Transmission Efficiency Technology Assessment
Transmission Efficiency Technology Assessment 1017895 Final Report, December 2009
EPRI Project Manager A. Del Rosso
ELECTRIC POWER RESEARCH INSTITUTE 3420 Hillview Avenue, Palo Alto, California 94304-1338 ▪ PO Box 10412, Palo Alto, California 94303-0813 ▪ USA 800.313.3774 ▪ 650.855.2121 ▪
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DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM: (A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I) WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUAL PROPERTY, OR (III) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER'S CIRCUMSTANCE; OR (B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER (INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOUR SELECTION OR USE OF THIS DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT. ORGANIZATION(S) THAT PREPARED THIS DOCUMENT Electric Power Research Institute Electranix Corporation Lone Wolf Engineering, LLC
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[email protected]. Electric Power Research Institute, EPRI, and TOGETHER…SHAPING THE FUTURE OF ELECTRICITY are registered service marks of the Electric Power Research Institute, Inc. Copyright © 2009 Electric Power Research Institute, Inc. All rights reserved.
CITATIONS This report was prepared by Electric Power Research Institute (EPRI) 942 Corridor Park Blvd. Knoxville, TN 37932 Principal Investigators A. Del Rosso J. Chan P. Zhan G. Sibilant F. Bologna B. Clairmont B. Brooks R. Lordan Electranix Corporation 12-75 Scurfield Blvd. Winnipeg, MB R3Y 1G4 Principal Investigator D. Woodford, P. Eng. Lone Wolf Engineering, LLC 10020 La Paz Drive N.W. Albuquerque, NM 87114-4921 Principal Investigator G. Wolf, P.E. This report describes research sponsored by EPRI. This report is a corporate document that should be cited in the literature in the following manner: Transmission Efficiency Technology Assessment. EPRI, Palo Alto, CA: 2009. 1017895.
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PRODUCT DESCRIPTION
Reducing our carbon footprint and increasing the role of renewable energy are important parts of the strategy for the greening of electric energy supply. Energy efficiency will be a major contributing factor to achieving a low-carbon future. Traditionally, energy-efficiency measures have focused on end-use efficiency. But if one considers the electricity consumed by auxiliary loads at power plants and lost in power delivery, the single largest industrial consumer of electricity is the electric power industry itself. Few utilities take a holistic view of reducing energy losses and improving the energy efficiency of their own facilities. Leading utilities, as well as other organizations in the electricity industry, have recognized the need to explore efficiency measures in each stage of the electricity value chain. This report is specifically aimed at investigating technological options to reduce losses in transmission systems. It develops a comprehensive evaluation methodology and strategic-planning framework to evaluate various available transmission loss-reduction options in a cost-effective manner. It also discusses the necessary measurement and verification procedures to confirm the achievement of the anticipated reductions. Results and Findings The loss-reduction strategies examined in this report include raising transmission-line nominal voltage; use of advanced or lower-loss conductors and bundling; bundle optimization; corona losses as impacted by line voltage, conductor size, and bundle configuration; shield-wire segmentation; insulation losses; low-loss transformers; redirecting power flow by power-flow controllers; selective conversion to dc, bipole, and tripole; and transmission voltage-profile optimization. Although some of these options have been applied in the industry for the main purpose of increasing capacity—with transmission losses a secondary consideration—the investigators found that, under certain conditions, the efficiency gains alone can justify an optimization project. Challenges and Objectives Utilities are under pressure to supply an ever-increasing customer demand for electricity. Electricity providers are studying techniques to upgrade their overhead ac transmission lines to increase capacity without adding additional facilities. Although they apply advanced technologies and materials to improve their capacity to move electric power from the generator to the customer, loss reduction is taking a lower priority. In a large network, these losses can be significant. Utilities understand this, and there is increased interest in technologies and methods for improving transmission losses as they try to improve the overall efficiency of their operations. The objective of this project is to provide utilities with the background and comprehensive tools to assess the application of available technological measures to improve transmission losses.
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Applications, Values, and Use The results of this project will provide utilities with a valuable proposition, from both a technical and an economical perspective, for implementing practical ways of reducing losses in transmission systems and equipment. Planning and design engineers and utility managers will find valuable tools to help them assess, choose, and implement the most cost-effective energyefficiency opportunities for transmission system loss-reduction and to measure and verify whether the expected goals are attained. It will also allow utilities to document those energy savings so they can be properly credited toward energy-efficiency savings goals. Some loss-reduction methods have dual effects: increased power transfer capability and reduced losses. This situation may cause a conflict between these two effects. EPRI’s evaluation framework provides guidelines to properly address loss-reduction techniques without conflicting with the objectives of expansion planning and incremental transmission upgrades. Additional rewards for implementing such measures will include a demonstration to regulators and the general public of a utility’s commitment to environmental issues; a reduction of its CO2 emissions and overall greenhouse gas footprint; and a reduction of its electrical losses, resulting in financial savings and improved equipment life expectancy. EPRI Perspective EPRI has found considerable interest within the power industry in methods to increase power flows across overhead ac transmission lines, which could in turn reduce transmission-line losses. But it appears that there is no industry-wide, comprehensive strategy for the reduction of transmission-line losses. Some utilities are studying line losses, whereas others are investigating lower losses in large power transformers, or focusing on more-efficient distribution transformers. Unlike programs to improve end-use energy-efficiency, programs to enhance the energyefficiency of transmission systems have not been extensively applied. Hence, there are no widely accepted savings guidelines for these types of projects. This report is a first effort to investigate known technologies and to develop consistent and comprehensive methodologies to reduce losses in transmission systems, without conflicting with the traditional objectives of sufficiency, security, and economy. Approach The project team surveyed EPRI members to investigate and gauge interest and activity in the reduction of transmission-line losses to improve the performance of ac overhead transmission lines. The survey responses established the objectives, scope, and approaches of the project. The EPRI team then conducted an analysis of the technologies available to utilities that could be implemented to reduce transmission losses. They measured cost-effectiveness according to the achievement of important societal benefits, comprising the monetary value of key savings in energy, capacity, and carbon emissions. Keywords Transmission losses Energy efficiency Societal benefits Evaluation framework FACTS Bundled conductor Low-loss transformers
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ABSTRACT Energy loss in the transmission lines, at both transmission and distribution voltages, is an area of concern as utilities struggle to supply the ever-increasing demand for electricity to their customers. Every megawatt that is dissipated through losses is a megawatt wasted, which in turn increases fuel consumption to replace those lost megawatts. Increasing fuel consumption increases the utility’s carbon footprint at a time when protecting the environment is critical. Typical losses for the transmission and distribution systems have been estimated at approximately 6–9%. When electricity is produced, it is moved from the generation plant, into the transmission system, through the distribution system, to the customer’s meter. Losses are introduced at each step along the way. When the amount of power injected into the system is compared to the amount sold (customer’s meter), it can be seen that the two figures do not match. Somewhere along the way, part of the electricity is lost. How much is lost, and how many megawatts make up the 6– 9%, can be found by comparing the information published by the US Department of Energy’s (DOE’s) Energy Information Agency (EIA). EIA reported the amount of electricity generated in 2006 (the last year for which this information is available) as 4065 million MWh. The amount of electricity sold (retail sales) in 2006 was 3670 million MWh. This simplistic calculation method shows that the order of magnitude for the 2006 energy losses was roughly 395 million MW. Reducing the energy that is lost in the transmission and distribution networks provides significant benefits to society as a whole. These benefits can be monetized by evaluating the value of energy, capacity, and carbon emissions savings. This report focuses on methods to improve the efficiency of the grid. Industry-accepted methods are applied to evaluate various loss-reduction methods for the operating grid. The report first describes the elements that motivate utilities to investigate options to improve the energy efficiency of their transmission networks. Then, the concept of the holistic view of energy efficiency across the entire value chain of an enterprise is introduced. A survey of EPRI members was made to investigate the current scope of interest and activity in the reduction of transmission-line losses to improve the performance of ac overhead transmission lines. It was found that this is a subject of great interest and of some activity. Various existing technologies available to utilities for reducing transmission losses are described in detail, including numerical examples and case studies. The effectiveness of these methods to accomplish the desired loss-reduction goals, their associated implementation challenges and limitations, and the issues that have prevented their wide spread utilization are addressed in this report. A framework for the evaluation of transmission loss-reduction options is developed. A complete case study is included to demonstrate the applicability of the proposed framework. A discussion of the principles and necessary considerations for the development of measurement and verification procedures is also included. Having a consistent and uniform methodology to vii
determine transmission-system losses would help utilities target cost-effective approaches for reducing these losses. It would also allow utilities to document the resulting energy savings so that they could be properly credited toward energy-efficiency savings goals. Finally, the main conclusions and suggestions for future research are presented.
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ACKNOWLEDGMENTS EPRI wishes to acknowledge the contributions of the many utility companies who responded to the industry survey found in this report. The authors would also like to acknowledge the guidance and assistance of the EPRI Advisory Committee: Mohamed Anmed (AEP) Jay Caspary (SPP) Jennifer Dering (NYPA) Dawe Fan (NYSO) Ray Ferraro (PSEG) Jeff Fleeman (AEP) Nick Koehler (AEP) Dejan Sobajic (NYSO) Harold Wyble (KCP&L) In addition, we wish to acknowledge the other participants and industry experts who provided helpful information and input, as well as constructive comments, to this document: Nick Abi-samra (EPRI) Kamran Ali (AEP) Dave Bryant (CTC) Jo Kutty (NYPA) Bernie Neenan (EPRI) Stephen Olinick (PPL) Craig Stiegemeier (ABB) Mile Taylor (CTC) Anthony Williams (Duke Energy) Abderrahmane R Zouaghi (ABB)
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ACRONYMS AND ABBREVIATIONS ACES : American Clean Energy and Security Act of 2009 ANSI : American National Standards Institute CCS: Core Cooling System EE: Energy Efficiency EERS: Energy Efficiency Resource Standard EIA: Energy Information Agency FACTS: Flexible AC Transmission Systems GHG: Greenhouse Gas IRR: Internal Rate of Return ISO: Independent System Operator LMP: Locational Marginal Pricing NEMA: National Electrical Manufacturers Association NEMS: National Energy Modeling System NERC: National Electric Reliability Council NESC: National Electrical Safety Code NPV: Net Present Value PST: Phase-Shifting Transformer RTO: Regional Transmission Organization RFI: Radio Frequency Interference SVC: Static Voltage Compensator TEE: Transmission Energy Efficiency
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CONTENTS
1 INTRODUCTION ....................................................................................................................1-1 Motivation for Evaluating and Reducing Transmission Losses .............................................1-1 Project Objective and Scope .................................................................................................1-4 References ............................................................................................................................1-6 2 INDUSTRY SURVEY OF TRANSMISSION-SYSTEM LOSS ACTIVITY ...............................2-1 Need for Understanding Industry Practice ............................................................................2-2 Loss-Reduction Strategies ....................................................................................................2-3 Survey Results ......................................................................................................................2-3 Loss Studies .....................................................................................................................2-4 Loss Calculations .............................................................................................................2-5 Reasons for Loss Studies.................................................................................................2-5 Peak and Energy Losses..................................................................................................2-6 Technologies to Reduce Transmission Losses ................................................................2-7 Transmission-Line Projects ..............................................................................................2-8 Transmission-Line Inspections .........................................................................................2-8 Transmission-Line Modifications ......................................................................................2-9 Transmission-Line Modifications ....................................................................................2-10 Survey Conclusions........................................................................................................2-10 3 BACKGROUND......................................................................................................................3-1 Summary of Measures for Reducing Transmission Losses ..................................................3-1 Applicability of Specific Measures to Reduce Transmission Losses.....................................3-8 The Value of Reducing Transmission Losses .......................................................................3-8 4 PRINCIPLES FOR THE EVALUATION OF TRANSMISSION ENERGY-EFFICIENCY OPTIONS...................................................................................................................................4-1 Introduction ...........................................................................................................................4-2 Establishing Objectives .........................................................................................................4-2
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Baseline Definition.................................................................................................................4-3 Baseline Forecast.............................................................................................................4-3 Identification of Baseline Conditions.................................................................................4-5 Quantification of Transmission Losses..................................................................................4-6 Economic Variables for Cost-Effective Analysis....................................................................4-7 Escalation Rates...............................................................................................................4-7 Discount Rate ...................................................................................................................4-7 Project Costs .........................................................................................................................4-8 Benefits Assessment.............................................................................................................4-8 Capacity Costs .................................................................................................................4-8 Least-Cost Planning Protocols.....................................................................................4-9 Market-Based Prices....................................................................................................4-9 Energy Costs ....................................................................................................................4-9 Transmission-Capacity Costs.........................................................................................4-10 Recommended Values for General TEE Evaluations ................................................4-11 Cost of Emissions...........................................................................................................4-11 References ..........................................................................................................................4-14 5 LOWERING TRANSMISSION LOSSES BY RAISING TRANSMISSION-LINE VOLTAGE..................................................................................................................................5-1 Introduction ...........................................................................................................................5-2 General Operational Issues...................................................................................................5-3 Voltage Control.................................................................................................................5-3 Unscheduled Power Flow.................................................................................................5-3 Feasibility of Upgrade.......................................................................................................5-4 Voltage-Upgrade Concepts ...................................................................................................5-4 Increasing Capacity Strategies..............................................................................................5-6 Upgrading an Overhead Transmission Line..........................................................................5-7 Overhead Transmission-Line Upgrading..........................................................................5-8 Considerations of the Existing Overhead Transmission Line................................................5-9 Physical Inspection...........................................................................................................5-9 Mechanical Design Criteria.............................................................................................5-10 Electrical Design Criteria ................................................................................................5-10 Environmental Data ........................................................................................................5-11 Standards .......................................................................................................................5-12
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Investigations and Studies ..................................................................................................5-12 What is Expected............................................................................................................5-12 System Studies...............................................................................................................5-13 Electrical Analysis...........................................................................................................5-14 Mechanical Analysis .......................................................................................................5-14 Detailed Engineering Design ..........................................................................................5-14 Results ................................................................................................................................5-14 References ..........................................................................................................................5-15 6 LOWERING TRANSMISSION LOSSES BY APPLICATION OF ADVANCED OR LOWER-LOSS CONDUCTORS AND BY BUNDLING .............................................................6-1 Background ...........................................................................................................................6-2 Conductor Thermal Rating ....................................................................................................6-2 Thermally Limited Lines....................................................................................................6-3 Design Considerations ..........................................................................................................6-3 Conductor Characteristics ................................................................................................6-3 Continuous Current Rating ...............................................................................................6-4 Power-flow Limitations ..........................................................................................................6-5 Interaction of Wind and Conductor Temperature .............................................................6-6 Increasing the Height of the Conductor ............................................................................6-6 Monitoring Sag in Real Time ............................................................................................6-7 Sagging-Line Mitigator......................................................................................................6-8 Bundling the Phase Conductor.........................................................................................6-9 Advanced Conductors ....................................................................................................6-10 Trapezoidal-Wire Conductors – ACSR/TW or AAC/TW......................................................6-12 Evaluation of Reconductoring Options for TEE Improvement.............................................6-13 Design Constraints on Structure Loads..........................................................................6-13 Reconductoring Options .................................................................................................6-14 Use of Larger Conductor or Bundling ........................................................................6-14 Reconductoring Without Significant Structure Modifications: ....................................6-14 Cost of Upgrading...........................................................................................................6-16 Structures and Foundation Modifications..............................................................6-16 Conductor-Replacement Costs .............................................................................6-17 Operation and Maintenance Costs........................................................................6-17 Examples of Reconductoring Alternatives...........................................................................6-18
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Approach ........................................................................................................................6-18 Case #1: ........................................................................................................................6-19 Case #2: .........................................................................................................................6-24 Case #3: .........................................................................................................................6-29 Case #4: .........................................................................................................................6-33 Nondisruptive Reconductoring ............................................................................................6-35 Summary .............................................................................................................................6-35 References ..........................................................................................................................6-36 7 LOWERING TRANSMISSION-GRID LOSSES BY DIVERTING POWER TO HIGHERVOLTAGE LINES ......................................................................................................................7-1 Introduction ...........................................................................................................................7-2 General Issues ......................................................................................................................7-2 Means for Diverting Power Flow ...........................................................................................7-4 Phase-Angle Regulators...................................................................................................7-4 Series Compensation .......................................................................................................7-5 FACTS Controllers ...........................................................................................................7-5 Thyristor-Controlled Series Capacitor (TCSC) .................................................................7-6 Static Synchronous Series Compensator (SSSC)............................................................7-7 Unified Power-flow Controller (UPFC)..............................................................................7-8 Interphase Power Controller (IPC) ...................................................................................7-9 Back-to-Back HVDC Converter ........................................................................................7-9 HVDC Transmission .......................................................................................................7-10 AC Transmission Line Converted to DC.........................................................................7-10 Evaluation of Potential Loss-Reduction...............................................................................7-12 Summary .............................................................................................................................7-12 References ..........................................................................................................................7-13 8 CORONA-LOSS REDUCTION...............................................................................................8-1 Introduction ...........................................................................................................................8-1 Reduction of Corona Loss in Existing Transmission Lines ...................................................8-2 230-kV Corona-Loss Example..........................................................................................8-4 345-kV Corona-Loss Example..........................................................................................8-6 Reduction of Corona Loss in New Transmission Lines.........................................................8-7 Summary ...............................................................................................................................8-8
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References ............................................................................................................................8-8 9 SHIELD WIRE LOSS-REDUCTION .......................................................................................9-1 Introduction ...........................................................................................................................9-1 Segmentation Method ...........................................................................................................9-2 Power Loss-Reduction ..........................................................................................................9-4 Case Study............................................................................................................................9-4 Phasing of Double-Circuit Lines to Minimize Shield-Wire Losses.........................................9-7 Summary ...............................................................................................................................9-9 References ............................................................................................................................9-9 10 INSULATION LOSSES ......................................................................................................10-1 Introduction .........................................................................................................................10-1 Insulator Leakage-Current Losses ......................................................................................10-5 Cleaning .........................................................................................................................10-6 Hand-Cleaning ...........................................................................................................10-7 Water Spray-Washing (De-energized).......................................................................10-7 Water Spray-Washing (Energized) ............................................................................10-7 Compressed Air and Dry-Cleaning Compound..........................................................10-7 Greasing .........................................................................................................................10-8 Coating with Silicone Rubber .........................................................................................10-8 Re-Insulation ..................................................................................................................10-8 Comparison of Insulator-Maintenance Procedures .............................................................10-8 Application to Reduce Losses .............................................................................................10-9 References ........................................................................................................................10-13 11 LOW-LOSS TRANSFORMERS .........................................................................................11-1 Introduction .........................................................................................................................11-1 Losses in Transformers.......................................................................................................11-2 No-Load Losses .............................................................................................................11-3 Load Losses ...................................................................................................................11-3 Losses in Auxiliary Equipment........................................................................................11-4 Losses Due to Harmonics ..............................................................................................11-4 Options to Improve Transformer Efficiency .........................................................................11-5 Savings Potentials...............................................................................................................11-7
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Conventional Evaluation of Loss Capitalization and Optimal Transformer Design ...........11-12 Transformer Loading ....................................................................................................11-13 Transformer Investment Cost and Efficiency................................................................11-14 Transformer-Replacement Options ...................................................................................11-15 References ........................................................................................................................11-20 12 HIERARCHICAL DYNAMIC VOLTAGE CONTROL TO HELP REDUCE TRANSMISSION LOSS...........................................................................................................12-1 Introduction .........................................................................................................................12-1 Methodology of Hierarchical Dynamic Voltage Control .......................................................12-2 Existing Solutions of Hierarchical Dynamic Voltage Control ...............................................12-4 Solution in Belgium.........................................................................................................12-4 Solution in France...........................................................................................................12-5 Solution in Italy ...............................................................................................................12-6 Solution in China ............................................................................................................12-8 Voltage Profile/Stability Improvement ...............................................................................12-11 Transmission Loss-Reduction ...........................................................................................12-12 Cost/Benefit Analysis ........................................................................................................12-14 References ........................................................................................................................12-16 13 FRAMEWORK FOR ASSESSING LOSS-REDUCTION OPTIONS...................................13-1 Introduction .........................................................................................................................13-1 Focus and Scope of the Framework ...................................................................................13-2 Categorizing Actions That Impact Transmission Losses.....................................................13-2 Framework Outline ..............................................................................................................13-5 Stage 1: Qualitative Screening .......................................................................................13-6 Stage 2: Definition of Baseline Scenarios ....................................................................13-13 Stage 3: Detailed Evaluation of the Selected Methods ................................................13-13 Methodology for Stage 3 – Group A ........................................................................13-13 Step 1: Quantify and Cost the Reference Loss Level. ........................................13-15 Step 2: Select Candidate Transmission Lines to Be Upgraded. .........................13-15 Step 3: Determine Optimal Set of Projects. ........................................................13-17 Step 4: Evaluate Costs Associated with Upgrade Implementation. ....................13-18 Step 6: Conduct Benefit/Cost Analysis of Line Upgrades Without Increasing System Utilization................................................................................................13-18 Step 7: Evaluate Transmission-Capability Increase............................................13-19
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Step 8: Evaluate Benefits Versus Costs of Increased Capacity Permitted by Upgrades.............................................................................................................13-20 Methodology for Stage 3 – Group B ........................................................................13-21 Step 1 and 1A: Prepare List of Existing Facilities. ..............................................13-24 Step 2: Off-line Optimizing Procedure with Optimal Power Flow ........................13-25 Step 3: Collection of Data for Off-line Optimal Power Flow ................................13-25 Step 4: Effectiveness of Each Facility in Reducing Losses.................................13-25 Step 5: Simultaneously Test All Facilities ...........................................................13-26 Step 6: Cost/Benefit Analysis..............................................................................13-26 Step 7: Analysis to Locate and Size New Facilities ............................................13-27 Methodology for Stage 3 – Group C ........................................................................13-27 Stage 4: Ranking of Methods .......................................................................................13-27 Case Study........................................................................................................................13-28 Stage 1: Qualitative Screening .....................................................................................13-28 Stage 2: Definition of Baseline Scenarios ....................................................................13-28 Stage 3: Detailed Evaluation of the Selected Methods ................................................13-31 Step 1: Quantify and Cost the Reference Loss Level. ........................................13-31 Step 2: Select Candidate Transmission Lines to Be Upgraded. .........................13-32 Step 3: Determine Optimal Set of Projects. ........................................................13-39 Step 4: Evaluate Costs Associated with Upgrade Implementation. ....................13-39 Step 5: Conduct Benefit/Cost Analysis of Line Upgrades Without Increasing System Utilization................................................................................................13-39 Step 7: Evaluate Transmission-Capability Increase............................................13-41 Step 8: Evaluate Benefits Versus Costs of Increased Capacity Permitted by Upgrades.............................................................................................................13-41 Stage 4: Ranking of Methods .......................................................................................13-44 References ........................................................................................................................13-45 14 PRINCIPLE OF MEASUREMENT AND VERIFICATION FOR TEE PROGRAMS............14-1 Introduction .........................................................................................................................14-1 Method for M&V Applied in End-Use EE Programs ............................................................14-2 M&V Considerations for Transmission Energy-Efficiency Projects .....................................14-4 References ..........................................................................................................................14-6 15 CONCLUDING REMARKS AND FUTURE RESEARCH ...................................................15-1 Summary .............................................................................................................................15-1
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Future Work.........................................................................................................................15-3 A APPENDIX – TEST-SYSTEM DATA .................................................................................... A-1
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LIST OF FIGURES Figure 1–1 Overview of Energy-Efficiency Resource Standards (EERS) by State....................1-2 Figure 1–2 Utilities Face Growing Concerns over Carbon Emissions from Generation Plants .................................................................................................................................1-3 Figure 1–3: Transmission System Efficiency-Improvement Process – Illustration of Project Scope.....................................................................................................................1-5 Figure 2–1 Transmission-Line Loss Studies..............................................................................2-4 Figure 2–2 Loss Calculations.....................................................................................................2-5 Figure 2–3 Reasons for Loss Studies and Verification with Test Data ......................................2-6 Figure 2–4 Determination of Peak Losses.................................................................................2-6 Figure 2–5 Determination of Energy Losses..............................................................................2-7 Figure 2–6 Frequency of Transmission-Line Inspections ..........................................................2-8 Figure 2–7 Role of Inspections in Transmission-Line Modifications ..........................................2-9 Figure 3–1: Pictorial View of Integral Value Proposition Associated with Transmission Loss-Reduction ................................................................................................................3-10 Figure 4–1 General Overview of a Transmission System Efficiency-Improvement Process ..............................................................................................................................4-2 Figure 4–2 Possible Approach to Define Baseline in Dual-Effect Projects When the Primary Objective Is Not Loss-Reduction ..........................................................................4-6 Figure 4–3 GHG Allowance-Prices Projection (EIA Report) ....................................................4-13 Figure 5–1 Multiple Transmission Lines Make up the Grid ........................................................5-3 Figure 5–2 Replacing Structures ...............................................................................................5-7 Figure 5–3 Inspection of Hardware, Conductor, and Insulators.................................................5-9 Figure 5–4 Weather Stations Installed Along the ROW Provide Valuable Data ......................5-11 Figure 6–1 Normal Ruling Span Sag-Variation Diagram ...........................................................6-4 Figure 6–2 Conductor Heating/Cooling......................................................................................6-5 Figure 6–3 Installing Bayoneting on a 115-kV Transmission Line .............................................6-6 Figure 6–4 Installing PhaseRaiser on a Transmission Line .......................................................6-7 Figure 6–5 Installing Sagometer Camera and Target on Line ...................................................6-8 Figure 6–6 SLiM Device.............................................................................................................6-9 Figure 6–7 Bundled Conductor ..................................................................................................6-9 Figure 6–8 Sensitivity Analysis of Option #1 with Respect to Several Parameters .................6-24 Figure 6–9 Variation of Current over Two 345-kV Lines of the Study System – Case #2 .......6-25 Figure 6–10 Variation of Losses for Two 345-kV Lines of the Study System – Case #2.........6-25
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Figure 6–11 Line-Loading Duration Curve – Case #3 .............................................................6-31 Figure 7–1 A Modified Hierarchical Control Structure for Network Loss-Minimization and Coordinated Regulation of Transmission Network Voltages with Optimal Power Flow (PF)............................................................................................................................7-3 Figure 7–2 345-kV Series Capacitors ........................................................................................7-4 Figure 7–3 345-kV Thyristor-Controlled Series Capacitors (Courtesy of WAPA) ......................7-6 Figure 7–4 Single-Line Diagram Depiction of a TCSC Module..................................................7-6 Figure 7–5 Single-Line Diagram Depiction of an SSSC ............................................................7-7 Figure 7–6 Inez Unified Power-Flow Controller (Courtesy of AEP) ...........................................7-8 Figure 7–7 Single-Line Diagram Depiction of a UPFC ..............................................................7-8 Figure 7–8 Single-Line Diagram Depiction of an IPC Configured as an APST with a Capacitor for Boosting Power Flow ....................................................................................7-9 Figure 7–9 Rapid City 200-MW Back-to-Back HVDC Converter Station ...................................7-9 Figure 7–10 Line Loss As a Function of Power Transfer for the AC to DC Example...............7-11 Figure 7–11 Line Losses as a Function of Line Length for the AC to DC Example .................7-12 Figure 8–1 Corona Loss Minus Ohmic Loss Increase for a 230-kV Transmission Line When AC Operating Voltage Is Reduced from 240 kV to 230 kV ......................................8-5 Figure 8–2 Corona Loss Minus Ohmic Loss Increase for a 345-kV Transmission Line When AC Operating Voltage Is Reduced from 345 kV to 327 kV ......................................8-7 Figure 9–1 Example of Sectionalized Segment (OPGW) [3] .....................................................9-3 Figure 9–2 Isolator and Related Components [3] ......................................................................9-3 Figure 9–3 500-kV Tower for Segmented Shield-Wire Analysis ................................................9-4 Figure 9–4 Loss-Reduction Benefit Derived from an Example of a 500-kV Transmission Line for a Range of Power-Transfer Levels. ......................................................................9-5 Figure 9–5 Phasing the Conductors on a Double-Circuit Tower to Minimize Shield-Wire Loss....................................................................................................................................9-8 Figure 10–1 Example of Dry-Band Arcing on Glass Insulators................................................10-2 Figure 10–2 Pollution Severity Based on ESDD and NSDD Levels [6] ...................................10-4 Figure 10–3 Example of On-Line Leakage-Current Monitoring Using EPRI’s Wireless Leakage-Current Sensor..................................................................................................10-5 Figure 10–4 Example of Insulator Leakage Current During a 24-Hour Period ........................10-6 Figure 11–1 Sources of Transformer Losses and the Physical Components That Affect Them [5] ...........................................................................................................................11-4 Figure 11–2 Percentage of Loss Versus Load Factor for Different Values of No-Load Loss (NLL)........................................................................................................................11-9 Figure 11–3 Percentage of Loss Versus Capacity Factor for Different Values of Load Loss (LL) ........................................................................................................................11-10 Figure 11–4 Percentage of Power Loss for Different Values of Load Loss (Ploss) ...............11-11 Figure 11–5 Percentage of Power Loss for Different Values of No-Load Loss (Po)..............11-11 Figure 12–1 Typical Structure for Hierarchical Dynamic Voltage Control ................................12-3 Figure 12–2 Typical Closed-Loop Hierarchical Dynamic Voltage-Control Strategy.................12-4
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Figure 12–3 Italian Hierarchical Voltage-Control System [11] .................................................12-6 Figure 12–4 Italian Control Areas for Secondary Voltage Regulation......................................12-8 Figure 12–5 Main Power Plants Controlled by Jiangsu Provincial Grid’s AVC Strategy..........12-9 Figure 12–6 Two Zone-Division Strategies Generated by the TVR of Jiangsu Provincial Grid ................................................................................................................................12-10 Figure 12–7 Main Power Plants Controlled by North China Regional Grid’s AVC Strategy ..12-10 Figure 12–8 Load Margins at Two Key Substations: Solid Line = PVRs Only; Dotted Line = PVRs and SVRs; Dashed Line = PVRs, SVRs, and the TVR .....................................12-11 Figure 12–9 Comparison of the Pilot Bus Voltages (Unit: kV), With and Without Hierarchical Dynamic Voltage Control, in Jiangsu Provincial Grid .................................12-12 Figure 12–10 Expected Transmission Loss-Reduction in Italian Power System ...................12-13 Figure 12–11 Transmission Loss-Reduction in Jiangsu Provincial Grid ................................12-13 Figure 12–12 Transmission Loss-Reductions in an Evaluation Study on the PJM System (Unit: MW) ......................................................................................................................12-14 Figure 13–1 Outline of the Framework for the Evaluation of Loss Reduction Measures .........13-6 Figure 13–2 Framework of Stage 3 for Measures in Group A (Except for Conversion of AC to DC).......................................................................................................................13-14 Figure 13–3 Framework for Determining Minimum-Loss Operation with Existing Facilities ..13-24 Figure 13–4 Outline of the Automated System Required for Transmission Network LossMinimization ...................................................................................................................13-26 Figure 13–5 One-Line Diagram of The Study System ...........................................................13-29 Figure 13–6 Annual Load-Duration Curve and Approximation Steps ....................................13-30
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LIST OF TABLES Table 2-1 Transmission-Line Voltage Levels Reported in the Survey ......................................2-4 Table 2-2 Technologies Being Studied to Reduce Transmission-Line Losses ..........................2-7 Table 2-3 Technologies Being Used to Reduce Transmission-Line Losses..............................2-9 Table 2-4 Operational Practices Used to Reduce Transmission-Line Losses .........................2-10 Table 4-1 Representative Values of Utility Cost Variables ......................................................4-11 Table 4-2 NERC Region Annual CO2 Output-Emission Rate (Ton/MWh)...............................4-14 Table 6-1 Comparison of Available Conductors .....................................................................6-11 Table 6-2 Characteristics of Equivalent Different Type Conductors ........................................6-15 Table 6-3 Conductor Data – Case #1 ......................................................................................6-20 Table 6-4 Project Cost – Case #1............................................................................................6-21 Table 6-5 Operational and Economic Parameters – Case #1 .................................................6-21 Table 6-6 Annual Energy and Emissions Savings – Case #1..................................................6-22 Table 6-7 Economic Analysis Results – Case #1 ....................................................................6-23 Table 6-8 Conductor Data – Case #2 ......................................................................................6-26 Table 6-9 Project Cost – Case #2............................................................................................6-27 Table 6-10 Annual Energy and Emissions Savings – Case #2................................................6-28 Table 6-11 Economic Analysis Results – Case #2 ..................................................................6-28 Table 6-12 Conductor Data – Case #3 ....................................................................................6-30 Table 6-13 Project Cost – Case #3..........................................................................................6-31 Table 6-14 Annual Energy and Emissions Savings – Case #3................................................6-32 Table 6-15 Economic Analysis Results – Case #3 ..................................................................6-33 Table 7-1 AC to CD Conversion Example ...............................................................................7-11 Table 9-1 Line Characteristics and Economic Parameters ........................................................9-6 Table 9-2 Savings and Economic Analysis Results...................................................................9-7 Table 10-1 Characteristics of Methods to Reduce Insulator Leakage Current ........................10-9 Table 10-2 Line Characteristics and Economic Parameters ..................................................10-11 Table 10-3 Economic Analysis Results – Silicone Coating of Insulators ...............................10-12 Table 11-1 Properties of Common Amorphous Metals and Electric Steels [10]. .....................11-6 Table 11-2 Description of Options for Transformer Replacement..........................................11-16 Table 11-3 Evaluation Process for “Repair-Now-And-Replace-Later” Option........................11-19 Table 12-1 Summary of Capital and Operational Costs (Currency: €)...................................12-15 Table 12-2 Cost/Benefit Data.................................................................................................12-16
xxv
Table 13-1 Characteristics of Loss-Reduction Methods ..........................................................13-4 Table 13-2 Main Characteristics and Attributes of Options to Reduce Transmission Losses..............................................................................................................................13-8 Table 13-3 Load-Duration Steps............................................................................................13-30 Table 13-4 Generation Dispatch for Each Approximation Step .............................................13-31 Table 13-5 Baseline Conditions .............................................................................................13-31 Table 13-6 Selection Metrics to Identify a Candidate Line for Reconductoring .....................13-32 Table 13-7 Economic parameters – Application of the Evaluation Framework......................13-33 Table 13-8 Conductor Data for Reconductoring Options – Application of Framework – Step 2.............................................................................................................................13-33 Table 13-9 Project Costs for Reconductoring Options – Application of Framework – Step 2 .....................................................................................................................................13-34 Table 13-10 Annual Energy and Emissions Savings – Reconductoring Options Application Of Framework – Step 2 ...............................................................................13-35 Table 13-11 Economic Analysis Results: 138-kV Line 153–3005: Preliminary Analysis at Step 2.............................................................................................................................13-35 Table 13-12 Conductor Data for Voltage Upgrade of Line 153–3005 – Application of Framework – Step 2.......................................................................................................13-37 Table 13-13 Demand-Loss Savings – Voltage Upgrade of Line 153–3005 – Application of Framework – Step 2...................................................................................................13-37 Table 13-14 Energy and Emissions Savings – Voltage Upgrade of Line 153–3005 – Application of Framework – Step 2 ................................................................................13-38 Table 13-15 Economic Analysis Results – Voltage Upgrade of Line 153–3005 – Application of Framework – Step 2 ................................................................................13-38 Table 13-16 Loss Savings – Complete Set of Projects – Application of Framework – Step 5.............................................................................................................................13-40 Table 13-17 Economic Analysis Results – Complete Set of Projects – Application of Framework – Step 5......................................................................................................13-41 Table 13-18 Generation Dispatch with Increased Transmission Capacity – Application of Framework – Step 8.......................................................................................................13-43 Table 13-19 Power Flow on Upgraded lines – Application of Framework – Step 8 ...............13-43 Table 13-20 Savings and Benefits Obtained with the Set of Upgrading Projects – Application of Framework – Step 8 ................................................................................13-44 Table 14-1 Characteristics and Typical Applications of Methods for M&V in End-Use EE Programs..........................................................................................................................14-3 Table A-1 Buses Data: Load, Generation, and B-Shunt at Peak Conditions ........................... A-1 Table A-2 Transmission Lines .................................................................................................. A-2 Table A-3 Transformer Data ..................................................................................................... A-3 Table A-4 Generators Power-Flow Data................................................................................... A-4 Table A-5 Generators Operation-Cost Parameters .................................................................. A-4
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1
INTRODUCTION
Motivation for Evaluating and Reducing Transmission Losses Electric utilities have always been conscious of delivery losses because they represent lost revenue. Recently, however, utilities have begun to consider delivery-system losses in an additional context. Energy efficiency has gained broad-based support as one of the main components of a clean and secure energy future. Rapid increases in energy price, constraints in energy supply and delivery, the need for improving reliability, and the increasing concerns of supply adequacy have all contributed to the recent increased focus on efficiency. As a result, along with renewable-energy legislation, a number of initiatives are now underway in the United States to improve efficiency in a variety of areas. The federal Energy Policy Act (EPAct) that was enacted in August 2005 includes some notable provisions for energy efficiency. These include tax incentives for advanced energy-saving products and buildings and updated authorizations for advanced energy research, including energy efficiency. The EPAct took modest steps to promote energy efficiency with these provisions. Emerging national and state legislative initiatives are driving energy efficiency and demand management. Indeed, the American Clean Energy and Security (ACES) Act, approved in June 2009, is a more comprehensive approach to promoting a clean-energy economy. The ACES Act amends the Public Utility Regulatory Policies Act (PURPA) of 1978 to establish a combined efficiency and renewable-electricity standard that requires utilities to supply an increasing percentage of their demand from a combination of energy-efficiency savings and renewable energy (6% in 2012, 9.5% in 2014, 13% in 2016, 16.5% in 2018, and 20% in 2021–2039). Moreover, a number of sections in the Act include elements for improved Transmission and Distribution Efficiency. Section 144, “Smart Grid Peak-Demand Reduction Goals,” provides requirements to establish a baseline and achieve demand-reduction targets. Section 216A, “Transmission Planning,” provides requirements to take into account all significant demand-side and supply-side options—including energy efficiency, smart grid, and electricity storage. In addition, state regulatory bodies are adopting aggressive energy-efficiency policies to increase investments in efficiency programs and improve efficiency in their own facilities and fleets. Although some states have been making commitments toward energy efficiency for decades, others are just getting started; still others fall far behind. Many states have adopted policies to encourage efficiency investments, such as public benefit funds (PBFs) and state tax credits. PBFs are small charges on electric bills used to fund energyefficiency programs and other programs deemed to be in the public interest (for example, assistance to low-income households). Energy-efficiency tax incentives encourage providers to reach energy-savings targets.
1-1
Introduction
Perhaps the most important regulatory instrument implemented by states to date is the EnergyEfficiency Resource Standard (EERS). An EERS aims to reduce or flatten electric-load growth through energy-efficiency (EE) measures. Goals may specify reductions in energy (megawatt hours, or MWh), demand (megawatts, or MW), or both. State regulators set electric and/or gas energy-savings targets for utilities, often with flexibility to achieve the target through a marketbased trading system [3]. An EERS requires utilities to meet quantitative targets for efficiency improvements. State regulators specify explicit numerical goals that regulated utilities and others are required to meet on an annual and cumulative basis. EERS-like laws and regulations are now in operation in many states. Twenty-three states have an EERS or goal; at least 15 include EE as part of a renewable standard or goal. The states that enacted significant energy-efficiency legislation in 2008 include: DC, FL, HI, IA, MA, MD, MI, NJ, NM, NY, PA, OH, OK, UT, and VT [1]. Figure 1–1 provides a pictorial overview of the EERS programs nationwide.
Figure 1–1 Overview of Energy-Efficiency Resource Standards (EERS) by State
EERS can be particularly effective because they allow utilities to save large amounts of energy by using a market-based system. This helps keep the cost down for each unit of savings achieved. An EERS implemented in a market-based trading system can offer energy providers flexibility in reaching energy-efficiency targets. Under such a system, a utility that exceeded its energy-efficiency targets in a given year would be able to sell its excess credits to other utilities that found it more expensive or difficult to comply with savings quotas. Indeed, Some EERS policies permit trading of efficiency credits, which allow savings to be achieved at the lowest cost but may give credit for more complex existing programs.
1-2
Introduction
All current EERS programs focus on end-use energy-savings improvements. In general, there are no specific provisions in these programs to include transmission and distribution improvements as a measure for increasing efficiency. Electric utilities, however, are themselves large consumers of electricity and, in some cases, the single largest consumer of electricity relative to their end-use customers. As such, many utilities have decided to take a leadership position through the implementation of various consumption- and delivery-system efficiency initiatives. The American Council for an Energy-Efficient Economy recommends including transmission and distribution improvements that improve efficiency in the EERS programs as one measure to accomplish their energy-saving goals. As a result, it is expected that utilities will be able to meet some portion of their EERS requirements through enterprise-wide system-efficiency efforts. Only recently, Minnesota has altered its EERS to allow energy savings resulting from improving system efficiency. The Minnesota energy policy mandates energy savings equal to 1.5% percent of annual retail-energy sales of electricity and natural gas, achievable directly through energyconservation improvement programs and rate design. The state of Minnesota has stated that up to 0.5% of the targeted 1.5% efficiency gains can come from system-efficiency improvements. [1].
Figure 1–2 Utilities Face Growing Concerns over Carbon Emissions from Generation Plants
Although many utilities implement end-use energy-efficiency programs, few take a holistic view of energy efficiency. Therefore, significant opportunities to reduce energy losses and improve energy efficiency across other utility functional areas are missed. Going forward, utilities will have to adopt a much broader view of energy efficiency and evaluate efficiency opportunities 1-3
Introduction
across the electric utility supply chain (generation, to transmission, to distribution, through enduse utilization). Within this overall approach, efficiency improvements in the transmission system play a very important role. According to Energy Information Agency (EIA) generation and consumption data, transmission losses account for approximately 2–4% of the total electricity generated in the United States. Although these percentages may appear relatively low, the total amount of energy involved is considerable. The percentages equate to about 83–166 million MWh lost each year (based on a total U.S. annual generation of 4157 million MWh). (EIA: Electric Power Industry 2007: Year in Review; report released January 21, 2009). The wasted MW caused by transmission losses are an untapped resource. Indeed, utilities have to generate more power to offset these losses—power that otherwise could be delivered to customers. Reducing system losses helps utilities to defer generation and transmission investments. In addition to utilities’ traditional efforts to reduce losses in order to maximize revenues, the evolving social, political, and regulatory environments promise additional rewards for a transmission utility that implements measures to improve transmission-system efficiency. Such a utility •
Demonstrates its commitment to environmental issues to regulators and the general public through more efficient use of transmission resources;
•
Reduces its CO2 emissions and its overall greenhouse-gas footprint;
•
Reduces electrical losses, resulting in financial savings and improved life expectancy of some equipment ;
•
Supports cost-effective compliance with emerging energy-efficiency mandates;
•
Provides the potential to relieve transmission constraints and defer capacity addition.
Project Objective and Scope The responses to the EPRI industry survey by participating utilities are summarized in Section 2. These responses confirm that implementing effective transmission loss-reduction methods is important to utilities, especially in the new context of generalized interest in and efforts toward energy-efficiency improvements. The implementation of technology-based solutions to improve transmission efficiency requires utilities to study and assess not only the technologies, but also their transmission systems. Utilities need a comprehensive evaluation methodology and strategic-planning framework to accomplish this task. EPRI has established this project in response to this industry-wide need. The realization of measures to reduce transmission losses within this context of holistic interpretation of energy efficiency should be consistent with the customary approach followed in the development of end-use EE programs. Indeed, it should be possible to assess, appraise, and compare prospective projects across operational sectors in a fair-basis comparison.
1-4
Introduction
The ultimate goal of this project is to develop a comprehensive strategic framework to assess and evaluate energy-efficiency opportunities from reduction of transmission system losses and to choose the most effective options. Figure 1–3, which illustrates the main sequential steps in the development of a transmission energy-efficiency (TEE) program, helps to clarify the scope of this project. This report focuses mainly on the first stages of a TEE program. That is, the evaluation framework includes provisions to properly define and establish the baseline for a prospective TEE program and provides guidelines to conduct the necessary feasibility and scoping studies. Industry-wide deployment of transmission energy-efficiency programs very much needs to establish measurement and verification (M&V) protocols to demonstrate the realized savings and document the benefits. Although a detailed treatment of the M&V component was not included in the primary scope of this project, ideas for the development and implementation of M&V procedures and methodologies are provided in this report. However, detailed engineering design and implementation stages are not addressed here. It is worth emphasizing that programs to improve energy efficiency in transmission and distribution (T&D) systems have not yet been extensively implemented. Hence, they do not have the benefit of widely accepted savings guidelines, such as those available for end-use efficiency projects. For end-use projects, certain established measures— such as the replacement of incandescent bulbs with compact fluorescent lamps (CFLs)—have associated energy-savings guidelines. Therefore, this project should be considered a first attempt toward the development of consistent and comprehensive methodologies, procedures, and protocols for the assessment and implementation of a T&D energy-efficiency program.
Establishing Objectives
Baseline Definition
Evaluation Framework Scope
Measurement and Verification (M&V)
M&V Guidelines
Feasibility and Scoping Study Implementation and Monitoring Detailed Engineering Design
Figure 1–3: Transmission System Efficiency-Improvement Process – Illustration of Project Scope
1-5
Introduction
This report is structured as follows: Section 2 summarizes the results of the survey conducted for industry members. The survey was aimed at gaining knowledge about utility practices and approaches related to the computation and management of transmission losses. It was also developed to determine the interests and the needs of the industry related to transmission lossimprovement. Section 3 presents background material. A summary of technological options for reducing transmission losses is first presented in this section. Section 3 also includes a discussion of the value proposition of transmission energy-efficiency improvement. Section 4 presents the principles for the evaluation of transmission energy-efficiency options that are the basis for the analyses and case studies presented throughout this report. Sections 5 to 12 thoroughly describe the available technologies for reducing losses in transmission networks. Although many of these techniques are well known in the industry, they have not been extensively applied. The effectiveness of these methods to accomplish the desired loss-reduction goals, their associated implementation challenges and limitations, and the causes that have prevented their wide spread utilization are discussed in these sections. The proposed framework for the evaluation of transmission loss-reduction options is described in Section 13. A complete study case that illustrates the application of the framework is included in this section. Section 14 describes the basic considerations and requirements for the development of a comprehensive methodology for an M&V process in transmission energy-efficiency programs. Finally, a summary of conclusions and main findings, along with proposals for future research, is presented in Section 15.
References [1]. FERC, Electric Market Overview: Energy-Efficiency Map. http://www.ferc.gov/ [2]. American Council for an Energy-Efficient Economy, Energy-efficiency Resource Standards: Experience and Recommendations. ACEEE Report E063, March 2006. [3]. Minnesota Office of Reviser of Status, 2008 Minnesota Status: 216B.2401 Energy Conservation Policy Goal. https://webrh12.revisor.leg.state.mn.us/statutes/?id=216B.2401&year=2008 [4]. Minnesota Office of Reviser of Status, 2008 Minnesota Status: S.F. No. 100, 2nd Engrossment: 85th Legislative Session (2007–2008). https://www.revisor.leg.state.mn.us/bin/bldbill.php?bill=S0100.2.html&session=ls85 [5]. Energy-Efficiency Planning Guidebook: Energy-Efficiency Initiative. EPRI, Palo Alto, CA: 2008. 1016273.
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2
INDUSTRY SURVEY OF TRANSMISSION-SYSTEM LOSS ACTIVITY This section covers a survey that was sponsored by EPRI to compile information and lessons learned on transmission-system efficiency efforts at various member companies, which include investor-owned utilities (IOU), public power utilities, cooperatives, transmission providers, and federal utilities.
This section groups the responses from the various participants. Some of the areas covered in this survey are: •
The use of the eleven (11) candidate transmission loss-reduction strategies (which are further developed in the report): –
Six dealing with transmission lines: o Use of advanced or lower-loss phase conductors o Bundling of the phase conductors o Phase-conductor corona losses o Shield-wire–associated losses o Transmission-line insulation losses related to leakage current o Conversion from ac to dc
–
Two dealing with transmission voltages: o Raising transmission-line nominal voltage o Transmission voltage-profile optimization
–
Two system approaches: o Redirecting power flows o Switching out of equipment
– •
•
One dealing with high-efficiency transformers
Information about the loss studies, performed with an emphasis on –
Loss calculations
–
Reasons for loss studies
–
Peak and energy losses
Transmission-line projects that have been undertaken by a survey participant: 2-1
Industry Survey of Transmission-System Loss Activity
–
Transmission-line inspections
–
Transmission-line modifications
Need for Understanding Industry Practice EPRI understands that there is significant knowledge within the industry regarding the implementation of many of the loss-reduction technologies described in Section 1. These technologies might not be applied specifically for the purpose of reducing losses, but they are on the grid. This knowledge constitutes very valuable information for the industry. There is also a wealth of previous EPRI work related to technologies designed to increase transmission capacity, including voltage and current upgrades of transmission lines, advanced conductors, dynamic ratings, and application of flexible ac transmission system (FACTS) devices. In the majority of cases, these modifications have been implemented for reasons other than reducing transmission losses. Data can be extracted from such operational experience in terms of how the applied methods have affected losses in the system. Such data would be very relevant to this project. It is also important to collect industry knowledge related to the study and application of those schemes designed specifically for the improvement of loss-reduction. Understanding the strategies and methodologies that have been applied in the design of transmission lines, as well as the criteria the utility followed, is of great value to this project. Certainly, any information concerning the actual loss-reduction following the implementation of the strategy—and any discrepancies with respect to the projected energy savings—is of major importance. In addition, it is worthwhile to gather and analyze the procedures, techniques, and tools utilities have used to evaluate transmission losses. Assessing the effectiveness of the implemented methods in terms of loss-reduction will also be a valuable consideration for the project. Additionally, it is necessary to determine if there is any standardized approach to loss-reduction being applied by utilities, as well as whether there is real interest in methods for transmission loss-reduction. The study has also attempted to determine what considerations utilities use to determine which transmission lines are candidates for loss-improvement. It was determined that this rich knowledge needed to be recorded, properly compiled, and characterized in order to extract the information and lessons learned. These data are extremely valuable for the purposes of this project. To this end, EPRI conducted a survey of the participating members. A list of recipients for the survey was made from the list of EPRI member organizations. The survey results are presented in this section. In Phase 2 of this project, EPRI has used the survey responses to identify opportunities for direct consultation and interaction with the technical staffs of companies that have indicated experience that can be leveraged in formulating an understanding of what has been taking place in the industry: that is, what are the needs, concerns, and expectations regarding transmission-system loss activity. The loss-reduction strategies listed here serve as a reference for those companies contemplating such activities on their own transmission systems. The utilities responding to the survey, and the actual transmission lines, are not specifically identified (as a matter of confidentiality to the membership).
2-2
Industry Survey of Transmission-System Loss Activity
Loss-Reduction Strategies The loss-reduction strategies were: •
Raising transmission-line nominal voltage
•
Transmission voltage-profile optimization
•
Use of advanced or lower-loss conductors
•
Redirecting power flows
•
Bundling phase conductors
•
Improving corona losses, as impacted by line volts, conductor size, and bundling
•
Segmentation of shield wires
•
Improving insulation losses
•
Installing low-loss transformers
•
Selective use of, or conversion to, dc— including bipole and tripole configurations
•
Switching or cycling out-of-service equipment not needed for current operation
Survey Results Twenty-five member utilities responded to the survey. They were fairly representative of the industry as a whole: small-, medium-, and large-sized utilities took part. Participants included investor-owned utilities (IOU), public power utilities, cooperatives, transmission providers, and federal utilities. The responses included voltage levels from 765kV to 34.5kV. A breakdown of those levels is as follows:
2-3
Industry Survey of Transmission-System Loss Activity Table 2-1 Transmission-Line Voltage Levels Reported in the Survey Transmission Voltage Levels
Number
765kV
1
500kV
10
345kV
15
230kV
16
161kV
7
138kV
7
115kV
14
100kV
1
69kV
10
46kV
4
44kV
1
41.6kV
1
34.5kV
2
Loss Studies It is important to determine what type of database is available for transmission-line loss identification. Utilities were asked if they performed loss studies on their overhead ac transmission systems. Twenty-nine percent reported that they performed loss studies on their transmission lines. These respondents were also asked if any system components were included in the loss study. Of those responding, 50% included substation transformer load-loss figures in their studies. Substation transformer no-load losses were included in 21% of those including transformer losses in their calculations.
Figure 2–1 Transmission-Line Loss Studies
2-4
Industry Survey of Transmission-System Loss Activity
Loss Calculations Knowing how utilities calculated their losses is also important in establishing standardized methods when applying study results across the grid. Therefore, respondents were asked how they performed the loss calculations for their facilities. Fourteen percent of those answering the question reported performing field investigations to collect and verify data for transmission lines and substation transformers. Interestingly, 64% of those answering the question reported using office records and design criteria for the studies. Twenty-two percent did not answer the question of how their losses were calculated.
Figure 2–2 Loss Calculations
Reasons for Loss Studies Knowing the reason utilities are performing loss studies gives us some insights about the importance of the data. The survey asked an open question about why the loss studies had been performed. This allowed a variety of responses from the members. Fifty-two percent answered the question. Thirty-six percent reported needing the loss data for rate and/or regulatory filings to justify their cases. Thirty-six percent used the information for the billing of transmission services. The survey also asked if the studies were verified with actual test data from the system. Twenty-eight percent responded that they verified their transmission studies with test data.
2-5
Industry Survey of Transmission-System Loss Activity
Figure 2–3 Reasons for Loss Studies and Verification with Test Data
Peak and Energy Losses Another key element in the process of understanding the industry’s activity regarding loss evaluation is to understand how the utility determined peak losses for their system. Fifty-six percent answered “yes” to this question. Forty-four percent did not answer the question. The survey also asked how peak losses were calculated by the utilities. Seventy percent reported that they used computer simulations; 25% used supervisory control and data acquisition (SCADA) data, and 5% made estimates based on transmission studies.
Figure 2–4 Determination of Peak Losses
The survey also asked if utility systems determined their energy losses. Forty-four percent reported that they did. Twelve percent reported that they did not. Unfortunately, 34% did not answer the question. It is also interesting to know how energy losses were determined by these utilities. Of those answering the question, 56% reported using actual data from their transmission system, 33% used load-flow simulations, and 11% reported taking information from their energy-management systems.
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Industry Survey of Transmission-System Loss Activity
Figure 2–5 Determination of Energy Losses
The survey also asked about the types of load data that were used to generate loss studies. The answers showed no commonality. They covered a wide range of methods, including demand-loss factors, real-time system losses, empirical methods, and load modeling. Technologies to Reduce Transmission Losses The survey was also interested in a utility’s intent to apply loss-reducing technology on its transmission systems. Therefore, a question was developed to gage this movement. Eighty-four percent of the utilities responded to the question: 43% said they were investigating these technologies; 57% said they were not. The respondents who answered positively were asked to describe the technologies being studied, which are defined in Table 2–2 below. It is important to note that many utilities are investigating more than one technology. Table 2-2 Technologies Being Studied to Reduce Transmission-Line Losses Methods Under Consideration
Percent Responding
Raising Nominal Voltages
33%
Optimizing Voltage Profiles
22%
Using Lower-Loss Conductors
56%
Redirecting Power Flows
44%
Bundling Phase Conductors
11%
Improving Corona Losses
11%
Segmenting Shield-Wires
22%
Improving Insulation Losses
11%
Installing Low-Loss Transformers
56%
Converting to DC, Bipole, or Tripole
0%
Switching Off Equipment Not in Use
0%
2-7
Industry Survey of Transmission-System Loss Activity
Respondents were also asked if there were any methods not listed in the survey that were being considered to reduce transmission-line losses. Thirty-three percent responded that they were doing computer studies of the overall bulk-transmission system, but that nothing had been planned as a result of the computer studies. Transmission-Line Projects The respondents were asked to provide a description of the overhead ac transmission lines being studied for application of the advanced technology. Twenty-two percent responded, but the respondents did not include details of their projects. Transmission-Line Inspections A very important aspect of upgrading an existing transmission line is knowing the physical condition of the specific transmission line being considered. Maintenance records are an excellent source of data regarding the line. The survey asked the utilities about their inspection process: did they inspect their lines on a regular basis? Thirty-two percent answered the question; the other 68% skipped the question. Of those answering the question, 38% reported that they inspected their lines more than once a year. Thirty-eight percent reported that the lines were inspected annually. Twenty-four percent reported that their lines were inspected every two years.
Figure 2–6 Frequency of Transmission-Line Inspections
The survey also asked if the transmission-line inspections influenced the decision process to modify the line’s capacity rating (apply new technology). Forty-four percent of the respondents answered this question. Eighty-eight percent of those answering the question reported that neither schedule maintenance nor inspections were considered. Twelve percent reported that it was an influence in the decision process.
2-8
Industry Survey of Transmission-System Loss Activity
Figure 2–7 Role of Inspections in Transmission-Line Modifications
Transmission-Line Modifications The survey asked utilities if they were actually applying any loss-reduction technologies to their existing transmission lines. Sixty-eight percent answered the question. Twelve percent reported that some form of loss-reducing technology was being applied to their transmission system. Eighty-eight percent reported that no projects were being considered. Table 2-3 Technologies Being Used to Reduce Transmission-Line Losses Technologies Being Installed
Percent Responding
Raising Nominal Voltages
4%
Optimizing Voltage Profiles
0%
Using Lower-Loss Conductors
0%
Redirecting Power Flows
8%
Bundling Phase Conductors
0%
Improving Corona Losses
0%
Segmenting Shield Wires
0%
Improving Insulation Losses
0%
Installing Low-Loss Transformers
8%
Converting to DC, Bipole, or Tripole
0%
Switching Off Equipment Not in Use
0%
Respondents were also asked if there were any other methods being considered to reduce transmission-line losses. Everyone skipped this question.
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Industry Survey of Transmission-System Loss Activity
Transmission-Line Modifications The survey asked the respondents if their companies had undertaken any operational practices to reduce overall transmission-system losses. Sixty-eight percent answered the question; 31% reported that their companies were making operational changes, and 69% said that they were not. Table 2-4 Operational Practices Used to Reduce Transmission-Line Losses Item
Practice
1
Use of Load-Tap-Changer (LTC)
2
Use of Reactive Devices
3
Control of System Voltage
4
Tower Inspections
5
Sag Inspections
6
Insulator Inspections
7
Vegetation Management
8
Voltage Studies
Survey Conclusions After reviewing the data in the surveys returned by the EPRI members, the following determinations have been made: •
Utilities have a definite interest in developing methods to reduce transmission-line losses and improve the performance of transmission lines.
•
Utilities are studying various methods and technologies to reduce losses on the bulktransmission system.
•
There is a need to develop an industry-wide standard approach to transmission-line loss studies.
•
The majority of transmission-line loss data is empirically derived from design and office records rather than from real-time data from the field.
This survey has proven that the ability to increase power flow is a timely issue for the owners and operators of transmission facilities. There is no industry-wide strategy for approaching the reduction of transmission-line losses or performing the necessary system studies. To meet the increasing demands of the industry and our customers, it is vital that the owners of the facilities making up the transmission grid operate as efficiently as possible. To this end, a framework for calculation of transmission-system losses will be proposed as part of this project.
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3
BACKGROUND This section attempts to provide the reader with the required background and reasoning behind choosing the transmission loss-reduction measures included in this report. It is intended to serve a wide spectrum of stakeholders, from the power-systems experts to the financial analysts who would welcome some of the fundamental information included in this section. It introduces the need to look beyond reducing the losses in the components to examining the effects of increasing the energy efficiency of the transmission system as a whole.
Some of the areas covered in this section are: •
The dependence of line losses on the line's resistance and the square of the current flowing through the line. The section introduces measures to –
Reduce the line resistance, such as o Using different conductors (reconductoring) o Bundling conductors with additional conductors per phase
–
Reduce the line flow, such as o Transmission at higher voltages o Using a centralized coordinated control of bus voltages o Diverting the flows to lower-resistance lines
•
This section introduces some of the salient points of the other techniques for reducing corona and insulator losses, as well as the merits of lower-loss transformers.
Summary of Measures for Reducing Transmission Losses When electricity is transmitted over ac transmission lines, some portion of the energy is consumed by Joule heating losses (resistive or line losses) in the conductor. These line losses are a function of the line’s resistance and the square of the current flowing through the line. Therefore, reducing line losses requires either a reduction in the resistance of the line or in the current flowing through the line. A reduction of conductor resistance directly reduces Joule losses, for the same amount of transferred power. Conductor resistance can be reduced by either replacing the conductor with a larger-diameter conductor or by replacing the conductor with one of the new advanced conductors with lower resistance and of the same diameter. Another option is bundling conductors with additional conductors per phase, which also reduces the line’s impedance. Reducing the currents flowing in a given transmission line can significantly reduce losses, because the losses change with the square of the current flow. Transmitting electricity at higher 3-1
Background
voltages can also reduce transmission-system losses. For a given power flow, a higher voltage reduces the current and, consequently, the resistive losses. Hence, raising the voltage of existing transmission lines reduces losses. In an alternating current (ac) circuit, the inductance and capacitance of the phase conductors also significantly impact current magnitudes. The inductive and capacitance currents flowing in the circuit impedance constitute reactive power, which transmits no energy to the load, but increases losses as the magnitude of the current increases. Reactive power flow is influenced by the power factor of the loads, as well as by the bus voltage profile throughout the power network. Hence, a centralized coordinated control of bus voltages allows the user to obtain a flatter voltage profile that minimizes the reactive power losses over the transmission grid. Alternatively, if power flow is diverted from a lower-voltage line to a higher-voltage line, or a high-loss path to a low-loss path, a reduction of the overall transmission grid losses can also be accomplished. This fact suggests the idea of using special methods and control equipment to redirect the power flow over a selected transmission path to reduce losses. There are additional sources of transmission losses other than line losses, including corona and insulator losses. These losses are not influenced by the power flow over the lines (like resistance losses), but rather by the voltage level, the design characteristics of the transmission line, and the deposition of polluting substances over conductors and insulators. Reduction of these types of losses can contribute, in a minor way, to the overall loss-improvement of the transmission lines. But, in most cases, they can be easily addressed. Another source of no-load losses are transformer-core losses that are dependent upon voltage levels. These losses can be controlled primarily by installing high-efficiency transformers. Based on the nature of transmission losses, the characteristics of network components, the power system operation, and control practices, a number of different measures for reducing transmission losses can be implemented. The main measures considered here are: •
Raising transmission-line nominal voltage
•
Transmission voltage-profile optimization
•
Use of lower-loss conductors
•
Redirecting power flow
•
Bundle optimization
•
Corona losses
•
Shield-wire segmentation
•
Insulation losses
•
Low-loss transformers
•
Selective conversion to dc, bipole, or tripole.
•
Switching or cycling out-of-service equipment not needed for current operation.
This list includes measures or actions that have been considered within the industry specifically for increasing power transfer, but that can also be used for the reduction of losses. Many of these methods have been studied for loss-reduction to varying degrees, and a number of them actually 3-2
Background
have been implemented by utilities on varying scales. Other system-expansion projects that would impact losses, such as adding new lines and substations/transformers, are not listed here as loss-reducing measures because they represent major additions or expansions to the system. The measures listed above are briefly described in the following subsection. Detailed descriptions of these technologies are provided in the corresponding sections of this report. •
Raising transmission-line voltage:
The one goal of increasing the nominal voltage level of an existing ac transmission line is to reduce the transmission line’s losses while increasing the power-transfer capacity of that line. Changes of voltage level as a measure to increase transfer capacity consist of energizing a transmission line in a higher voltage class. This approach might require upgrading the transmission towers to meet safety standards regarding clearance levels or phase spacings. In addition, the switching stations and substations must also be upgraded with higher-voltage circuit breakers, switches, transformers, and other related equipment. Increasing the operating voltage of the transmission line can substantially boost the powertransfer capability, especially in long voltage-limited transmission lines. For short, thermallylimited lines, doubling the line voltage could double the thermal capacity of the line. (The maximum current remains the same if the conductor is not replaced.) This measure is a considerable improvement, which might avoid or delay the need for the construction of an additional line to achieve the necessary transmission capacity. Doubling the line voltage for longer lines could increase the power-handling capacity of the line by as much as the ratio of the line voltages squared. The extent of the loss-reduction that can be achieved depends on the way the line loading is changed after the voltage uprating. If the line loading remains the same, the current will be reduced proportionally, and loss-reduction will be significant. However, if the line load is increased to the maximum capacity of the line, the MWh losses will not be reduced. However, the percentage of loss with respect to the transmitted power will be less. •
Voltage-profile optimization:
Sufficient controllable reactive power resources are essential for the reliable operation of electric power systems. Inadequate reactive power support has led to voltage collapses and has been a cause of several recent major power outages worldwide. Reactive power/voltage-control service should fulfill the objectives of satisfying overall system and customer requirements for reactive energy on a continuous basis; maintaining system voltages within acceptable limits; providing a reserve to cover changed reactive requirements caused by contingencies; and reducing system losses. The profile of bus voltages strongly affects the reactive power flow throughout the power network, which in turn substantially impacts transmission losses. Hence, by adjusting bus voltages to minimize the transfer of reactive power over the grid, a significant reduction in transmission losses can be accomplished without jeopardizing system security. In other words, voltage control can be used as an effective method for reducing losses. Besides, appropriate voltage control and reactive-power management in the power grid allows maximizing the amount of real power that can be transferred across congested transmission lines. Indeed, reactive-power flows in the grid consume transmission and generation capacity, hence limiting a system’s ability to move real power. 3-3
Background
Two methods typically used to improve real power transfer are: •
Voltage control by optimizing the voltage profile to minimize losses, using all existing voltage-control equipment available in the power system
•
Reactive-power compensation by installing additional reactive-power support equipment
Reactive-power compensation and voltage control are intrinsically related. From the point of view of reactive-power management for loss-reduction, voltage control can be understood as an optimal way of setting up a voltage profile. It reduces reactive-power transfers through the transmission network by means of the existing control components—for example, generator excitation adjustment, switched reactors and capacitors, transformer tap changers, static voltampere-reactive, or VAR compensators (SVCs), and other FACTS devices. Reactive-power compensation is the action of planning and installing new reactive-power equipment to improve voltage control. It is clear that after installing additional reactive-power support equipment, optimal voltage control can be applied to maximize the benefits from the new equipment. Optimizing the voltage profile for loss-minimization requires adjusting voltage-control settings according to continuously changing system conditions. Clearly, for this approach to be effective, a centralized automatic process, like centralized secondary voltage/VAR control systems, is required. Such systems can be implemented in a hierarchical control fashion, with one of the control levels being a loss-minimization control. The loss-minimization control level would perform on-line adjustments of the overall network voltage and reactive-power plan based on the most recent system-state estimation. •
Reconductoring with larger cross-sectional conductors
By using a larger cross-sectional conductor, the thermal capacity of the transmission line can be increased significantly. Similar to raising the transmission voltage, the impact of this measure on transmission losses will depend on how the power system is operated after the installation of the new conductor. If the power flowing over the reconductored line remains the same, an important reduction in transmission losses can be achieved. The same current magnitude will flow through a lower-resistance conductor. Conversely, if the reconductored line is loaded to its updated maximum capacity, transmission losses will not be reduced. •
Reconductoring with lower-loss conductors
By replacing the original line conductors, it is possible to employ modern conductors of the same diameter, but with lower resistance. Trapezoidal wire (TW) conductors of “equal diameter” type have an overall diameter equal to their standard aluminum-core steel-reinforced (ACSR) counterparts, but they provide up to a 20% increase in aluminum area. This characteristic results in lower resistance and a moderately higher current-carrying capacity. Hence, replacing existing round-wire conductors with TW conductors of the same diameter allows utilities to reduce line losses up to 20% without increasing structure transverse loading. The cost of an ACSR trapezoidal conductor is about 5% higher than the cost of a conventional round-wire ACSR conductor of similar aluminum section. The higher cost is basically attributable to the premium feature of trapezoidal strands over circular strands, assuming the same amount of aluminum. The use of certain new conductors can yield an increase in thermal capacity of as much as 100%, at a cost of less than half that of a new line. “High-temperature, low-sag” (HTLS) conductors are capable of continuous operation at temperatures ranging from 150°C (302°F) to 250°C (482°F) without increasing sag at mid-span or reducing conductor-strength problems associated with 3-4
Background
ACSR conductors exposed to high temperatures. HTLS advanced-technology conductors are able to carry much higher currents continuously without exceeding sag clearances. Reconductoring with HTLS conductors can provide significant reduction in line losses if the new conductor is operated under the same parameters as the conventional ACSR conductors they are replacing. Line losses will be less, due to the reduced resistance of the conductor. On the other hand, if loading of HTLS conductors is increased (taking advantage of their higher temperature capability), electrical losses will be greatly increased. Indeed, operation of lines at high temperatures is a clear indication that electrical losses are significant. Reconductoring with HTLS conductors is attractive in particular situations in which extra capacity is required for short periods of time due to N–1 overload conditions. •
Redirecting power flows
Redirecting power flow through an ac transmission network consists of forcing power into lowloss paths that are obstructed by higher relative impedance. To achieve such a modification of the natural power-flow pattern on a transmission system, significant pieces of equipment have to be added. The devices for power-flow control allow alteration of the key parameters that affect the power transferred by a transmission line: that is, the voltage magnitude of end buses, line impedance, and the voltage angles of end buses. The control devices—(FACTS and high-voltage direct current (HVDC)— and the strategies that can be applied for diverting power flow are discussed in detail in Section 6. Such pieces of equipment are costly, and they are usually installed in transmission networks for other reasons than reducing transmission losses. FACTS controllers are typically installed to fulfill a specific role, such as increasing transmission capacity, reducing loop flows, confining power to a specific path, or improving system stability. Installation of power-controlling equipment with the sole objective of diverting power flow to achieve lower losses is normally not cost-effective. However, if FACTS devices already exist in the power network, they could be used with the second-priority objective of reducing losses. To do so, a centralized controller to optimally adjust settings on-line is implemented. Such a controller would operate as an additional control loop. And it should be carefully designed to avoid possible adverse interactions or conflicting control actions with the main controller of the devices being controlled. Depending on the system topology, the operating characteristics, and the manner in which the power-flow pattern is controlled, changes in losses can be expected from both directions (increasing or decreasing). For instance, if a particular FACTS controller is used to mitigate power-flow loops, and if in order to avoid these loop flows, power is forced through higher-impedance paths, a change in losses will result. In this case, a loss-minimization controller might not be feasible, because conflicting control actions would occur.
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Background
•
Low-loss transformers
Transformers can be designed to operate with lower losses and higher efficiencies than the standard efficiency designs. However, these features might result in an increase in the capital cost of the transformer. To reduce losses in transformers, two components can be improved: the core and the windings. The reduction in transformer-related losses over the years has come about by improving the materials and construction of the cores and coils of distribution and substation transformers. To understand the benefits of using high-efficiency transformers, it is worthwhile to identify the different losses found in power transformers and to understand how they are improved by high-efficiency designs. There are basically three types of losses in a power transformer: –
No-load losses
An unloaded transformer experiences loss because of the magnetizing current required to take the core through the alternating cycles of flux at a rate determined by system frequency. This loss is known as core loss, no-load loss, or iron loss. Core loss is present whenever the transformer is energized. No-load losses can be reduced by selecting a high-performance steel for the core and by improving the core design. Over the years, better steels for transformer cores have been developed. Various processing and coating techniques and a reduced silicon content led to the creation of high-permeability grain-oriented steels. During the 1980s, techniques were introduced to redirect the domains of the iron crystals by laser etching. More recently, the development of amorphous iron introduced a significant new evolution for reducing iron losses. Amorphous iron deserves special mention. Distribution transformers built with amorphous iron cores can have more than 70% lower no-load losses compared to the best conventional designs, and can achieve up to 99.7% efficiency for 1000 kilovoltampere (kVA) units. –
Load losses
The load loss of a transformer is that part of the losses generated by the load current and which varies with the square of the load current. This type of loss falls into two categories: •
Resistive loss within the winding conductors and leads
•
Eddy-current loss in the winding conductors
Lower load losses can be obtained by reducing the current densities of the conductors; more finely subdividing the conductors to reduce eddy-current losses; mowing the shape of the conductor to reduce skin effect; using structural materials that develop lower losses when penetrated by leakage flux; and using various shielding techniques to reduce the stray losses produced by leakage flux. –
Auxiliary losses:
These are losses caused by the use of cooling equipment such as fans and pumps to increase the loading capability of substation transformers. The energy consumption of auxiliary equipment depends on the horsepower of the fans and pumps and the length of time they are running. This loss is dependent on the transformer loading throughout the year. Some transformers are designed to run the fans and pumps continually. The auxiliary losses are very low compared to the other losses, and because the equipment is used to increase the loading capacity, the losses should be compared to the increased capacity to achieve a fair assessment of transformer
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efficiency. Auxiliary-equipment losses can be reduced by limiting the operating time of the auxiliary equipment. The replacement of existing low-efficiency transformers and the use of high-efficiency transformers have been focused mainly on the distribution side because the effect on system efficiency is more significant there. In fact, distribution transformers are one of the largest lossmaking components in electricity networks. Transformers in the distribution systems are relatively easy to replace, compared to transmission lines or conductors, and their efficiency can be fairly easily classified, labeled, and standardized. The loss-reduction in high-efficiency transformers is principally achieved in the no-load losses, because the major improvement is in the core. Hence, the effect on overall loss-reduction is more important in transformers with relatively low load factors, which is mainly the case in distribution systems. For large transformers, above a few megavolt amperes (MVA), the costs of losses are so important that transformers are custom-built. They are tailored to the loss-evaluation figures stipulated in the transformer specification defining the unit. Therefore, loss-reduction is not usually a reason for replacing existing large transformers. Nevertheless, the improvement in high-efficiency transformers based on amorphous metal technology allows their economical use in large transformers, resulting in a more significant effect on losses. •
Corona losses
Corona and insulator losses are normally low in comparison to the resistance losses in transmission lines. The mean annual corona losses of high-voltage transmission lines are usually an order of magnitude lower than the resistive losses. However, annual corona-energy loss, which depends on the various weather conditions occurring in a given year, has an impact on the economic choice of conductors. Corona losses are dependent on voltage levels, altitude, type of conductor, and bundle design. Corona loss for an existing transmission line will be present if the line voltage is operating near or above the critical corona-onset level. Transmission lines designed for higher voltages are generally more prone to corona. The degree of corona will vary with environmental conditions and with the voltage applied. A reduction in ac voltage will lower the corona and associated losses but will increase resistance losses because the line current has to increase to keep the transfer level. However, during conditions of light load and heavy corona loss, lowering the ac-line voltage may reduce corona loss more than the system losses increase. To realize such a reduction in practice, a centralized controller that modulates bus voltages according to power-flow levels and optimal weather conditions would be required. Practical implementation of this option poses technical challenges because it may impair system operation and reliability. More comprehensive investigations will be required to assess potential implementation of this strategy in actual systems. •
Insulator losses
Losses in the insulation of overhead transmission lines occur when there is resistive leakage current flowing across the surface of the line insulators. The resistive leakage current is negligible with clean insulators, but it increases when contaminants are deposited on the insulator surface. There are a number of technical options available to mitigate the effect of contamination of insulators. These techniques are usually applied to reduce the risk of flashover, and, consequently, improve failure rate. The main options include cleaning insulators, greasing, coating with silicone, and—as an ultimate alternative—replacing insulators. The application of 3-7
Background
these techniques might produce a significant reduction in insulator losses if the existing insulators were heavily contaminated.
Applicability of Specific Measures to Reduce Transmission Losses Most of the methods or initiatives previously described for reducing transmission losses have been applied by utilities with the main objective of increasing transmission capacity and/or reliability. Typically, loss-reduction takes a lower priority or is not considered at all. Moreover, projects implemented to increase transmission capacity may actually result in increases in transmission losses because lines are more heavily loaded. Under traditional market and regulatory conditions, many of the identified potential loss-reduction measures would not be economically justified solely for the purpose of loss-reduction. Evolution of regulatory requirements, such as the previously discussed ACES Act and the EERS, along with market conditions, may result in financial penalties for carbon emissions. The economics of reducing losses will likely result in changes to this process. Section 13 provides an analytical framework to evaluate and account for losses under these changing market and regulatory conditions.
The Value of Reducing Transmission Losses The results from the industry survey on transmission-loss activity actually undertaken, presented in Section 2, indicate that there is real interest among utilities in developing methods to reduce transmission losses. It is expected that such interest will significantly increase in the upcoming years, mainly because of the new policies and regulatory provisions for improvements in energyefficiency. Nevertheless, the extent to which new capital projects specifically designed to reduce losses will be adopted will most likely rely on economic decisions. Will the additional revenue from reduced losses justify the associated costs? As noted in Section 1, evolving environmental, political, and regulatory environments may very well alter the value proposition associated with reducing system losses. The overall economic impact of losses has two main components: the cost of energy losses and the cost of providing additional generation capacity to compensate for the losses. As system losses are reduced because of the implementation of specific technologies, generation energy and capacity cost will be reduced accordingly. However, identification of the net benefits from lossreduction for the different participants in an electrical system is not straightforward; economic responsibility for losses varies from one transmission-line owner to another, from one line to another, and from one regulatory entity to another. The beneficiaries of loss-reduction and its associated monetary benefits in an unbundled power system will depend on the transmission-pricing mechanism and on how losses are allocated among the market participants. Different variations of loss allocation—such as, pro-rata, Z-bus, flow-tracking, bilateral, last MW, first MW, and average MW—have been applied within the industry. In the pro-rata system, for example, the total losses of the system are estimated or measured and applied to every generator (and/or load) on a pro-rata basis. Under such a system, every customer pays the same loss rate, regardless of location, unit size, load level, or any other factor. This method basically distributes the actual losses evenly, both across the system and across time. In power systems in which the transmission tariff includes the cost of losses in a way that reflects the real cost of moving power (marginal-cost pricing), consumers and generators receive shortterm and long-term signals with regard to transmission. Indeed, as a result of marginal-loss 3-8
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pricing, generators placed closer to their load experience an advantage over generators farther away, which must transmit their power over greater distances to reach the load served. Large customers may also face higher energy prices depending on their location in the system, and, consequently, on their contribution to system losses. Another important aspect of the benefits of transmission loss-reductions is the allocation of losses due to wheel-through transactions. In some power systems, a portion of the system’s total loss is caused by wheeling power from external generating sources. The way losses due to wheel-through transactions are allocated also varies from one system to another. From the viewpoint of utilities and transmission owners in a deregulated environment, the cost of energy losses is a pass-through cost; therefore, it does not affect them financially. This consideration implies that there are no benefits that accrue to the utility if it decreases its system losses. Even though it can be argued that there is no energy cost of losses to utilities, costs associated with demand-losses can be identified. Indeed, losses do impose costs on a utility— such as the requirement to increase the size of assets on the network to transport energy that will be lost further into the network, and the cost to maintain assets with higher capacity. These costs, however, are a component of the capital-operation and maintenance budgets and are normally included in the rate base. More directly related to the transmission owners’ business incentive is the impact of demand-losses on MW-transfer capability and its value in gaining transmission rent. On the other hand, in vertically integrated utilities, losses are usually embedded in the cost of operation. Normally, a utility schedules generation to meet a specific demand, using economic dispatches that account for transmission losses. In general, there is no real commercial debate about how transmission losses are allocated among the generator and its customers. From the above discussion, it can be attested that transmission losses impact power-system participants in many different ways-----depending on system characteristics, ownerships, and regulatory frameworks. Thus the most appropriate and simplest way to assess loss-reduction benefits is based on the real total cost to society as a whole. From a societal resource-cost perspective, reductions in transmission losses decrease resource depletion and provide a benefit by reducing investment in generation and transmission infrastructure. Reduction in losses also plays an important role in reducing pollution and carbon emissions, which clearly represents a remarkable benefit for the entire society. Indeed, reduction of carbon emissions has emerged as a major driver for energy efficiency. The benefits to environmental externalities—especially carbon emissions—should be included in the assessment of any TEE program. The decision for the implementation of any particular project to enhance transmission energy efficiency should be based on a benefit/cost analysis from the point of view of overall societal sustainability. That is, the evaluation test should include all of the costs and benefits to the utility and its rate payers as a whole, including externalities. The cost-effectiveness of a program can be evaluated by applying one or more of the widely used economic tests, such as net present value (NPV), benefit-cost ratio, internal rate of return, and pay-back period. If the option proposed to reduce losses is cost-effective, it should be implemented because it is deemed to be beneficial for society. However, as explained above, under traditional ratemaking, utilities have not had incentives to invest in loss-reduction. Therefore, specific regulatory instruments need to be adopted, in order to allow utilities to recover investment costs and to provide incentives for the development of loss-reduction measures. Moreover, current regulatory frameworks should be revised and expanded to include specific provisions and mechanisms to motivate stakeholder 3-9
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support for reducing transmission losses. Such initiatives will allow utility managers to start thinking of TEE as a profit center, rather than as just another cost. The societal benefits to be derived from efficiency improvements and loss-reduction measures constitute a basis for developing the necessary regulatory instruments to provide positive incentives for utilities. Figure 3–1 is a pictorial description of the concepts expressed in this section. Aspects related to the technical feasibility and cost-effectiveness of various options for transmission loss-reduction are addressed in this project; however, analyses of utility business models for transmission energy efficiency are beyond the scope of this study.
Transmission Loss Reduction
Value Transformation
Reduced:
•Energy (MWh) •Capacity (MW)
Market/Utility Price and Investment
Externalities
Lower emissions, imports
Emission Cost
Who Benefits
All Electricity Consumers
Effects
Utility Business Model for System Efficiency
•Utility cost recovery mechanisms
•Incentives for improving transmission efficiency
Need to develop Regulatory Instruments
Figure 3–1: Pictorial View of Integral Value Proposition Associated with Transmission Loss-Reduction
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4
PRINCIPLES FOR THE EVALUATION OF TRANSMISSION ENERGY-EFFICIENCY OPTIONS This section establishes the principles that are used in the rest of the report for evaluating the energy-efficiency options. It is perhaps one of the most important sections in this report, because it lays the foundations upon which the various options are to be evaluated.
Some of the areas covered in this section are: •
Definition of a set of benchmarks to be used for the analyses, such as: –
A system baseline that will constitute the reference against which loss-reduction is assessed
–
A baseline forecast that will constitute the forecast needed to measure the benefits of loss-reduction over a range of future years
–
Modifications of baseline conditions, in which the future benefits of loss-reductions are to be evaluated, and in which various factors— such as additions or changes in transmission and generation or load growth—are defined
•
Quantification of transmission losses, in which the tools for evaluating the losses of the transmission system are introduced—basically, power-flow or security-constrained dispatch programs (The handling of the hourly cost of losses is also introduced here.)
•
A breakdown of the total project costs, including elements such as capacity costs, energy costs, transmission-capacity costs, and the cost of emissions (Also included here are some typical cost figures from some EPRI members)
•
Financial-appraisal methods for long-term projects, based on (NPV), payback period, or internal rate of return (IRR)–accepted methods
•
Valuation of savings achieved from the implementation of the various measures to improve transmission efficiency, factoring in the definition of future power-system scenarios (baseline) that describes year-by-year changes in the system (for example, transmission, generation, load, generation, energy costs, and carbon emissions)
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Principles for the Evaluation of Transmission Energy-Efficiency Options
Introduction Figure 4–1, first presented in Section 1 as Figure 1–3, is included again here for easy reference. It presents a flowchart that illustrates the main stages that should be followed in the development and implementation of a program to improve transmission energy efficiency. It was explained in Section 1 that this project deals specifically with the first stages of the TEE process: baseline definition and feasibility and scoping studies. It also briefly addresses M&V issues. This section describes the key elements for the assessment of transmission energy-efficiency options and the general approach that is followed in this study. The elements discussed here constitute the basis for the evaluation framework described in Section 13.
Establishing Objectives
Baseline Definition Evaluation Framework Scope
Measurement and Verification Feasibility and Scoping Study
M&V Guidelines
Implementation and Monitoring
Detailed Engineering
Figure 4–1 General Overview of a Transmission System Efficiency-Improvement Process
Establishing Objectives The first step of a TEE process is to clarify and establish the utility’s strategic objectives. The interest in implementing measures to reduce transmission losses arises as a result of increasing pressure from the public, state regulators, and federal policy makers to meet growing energy demands in a cost-effective and environmentally sustainable manner. At the same time, utilities have an obligation to serve the best interests of their shareholders. As described in the previous section, it can be said that the objective a utility might define in terms of transmission energy efficiency will greatly depend upon the cost recovery and/or incentive regulatory mechanism that will be implemented. This mechanism will most likely allow the utility to recover cost or provide incentives only on those TEE programs that are costeffective from a societal-benefit point of view. (The total benefits for the society, including externalities, outweigh the associated investment costs.) Therefore, under these conditions, there are no predefined targets for reducing transmission losses to a certain amount. A particular utility would implement measures to reduce losses to the
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Principles for the Evaluation of Transmission Energy-Efficiency Options
extent that they are technically feasible (that is, they do not adversely impact system reliability) and cost-effective.
Baseline Definition In end-use EE programs, the baseline forecast represents a projection of energy consumption and peak demand in the absence of EE. The baseline serves as a reference against which the impact of EE can be assessed. The EE baseline forecast is based on a utility’s load forecast, but typically it is much more detailed. Most frequently, the forecast is represented by single yearly values for a specific set of variables, such as annual energy consumption, summer peak demand, and winter peak demand for each year of the analysis. Some utilities use a range around the point forecast, using either probabilistic or scenario-generation methods. The EE-program baseline forecasts are generally derived from the utility’s official load forecast, which is used to project utility capacity needs and fuel costs as well as to evaluate supply-side options, against which EE options will compete. In programs for improving TEE, the baseline is the reference case or benchmark against which loss-reduction is assessed. It represents the normal transmission loss level the system has, which results from the application of the planning and operation criteria. Consequently, the baseline forecast is the projection of expected loss level (energy and demand losses) in the absence of any TEE measure. Baseline Forecast The benefits of implementing measures to reduce transmission losses are to be evaluated on an annual basis over a range of future years. The annual benefits in terms of energy, capacity, and emission-cost savings associated with loss-reduction measures are aggregated to evaluate the applicable economic metrics. Standard methods to appraise long-term projects—like NPV, payback period, or IRR— require that annualized benefits and cost evaluations be conducted up to a predefined horizon year. The number of years included in the NPV analysis can have a significant impact on the absolute NPV value, because benefits from loss-reduction are collected over the years. Indeed, the NPV is an indicator of the value or magnitude of an investment. The definition of horizon year (as well as that of other economic parameters) will depend upon the rules and customary approaches used within the organization for the appraisal of investment projects. It is generally related to the accepted repayment period. Thus, the valuation of savings achieved from the implementation of measures to improve TEE, as well as the assessment of their related economic metrics, require the definition of future power-system scenarios (baseline) that describes year-by-year changes in the following parameters: •
Additions or changes in the transmission network (transmission-expansion projects)
•
Load growth
•
New generation
•
Generation changes and changes in fuel costs or other parameters that may impact generation dispatch 4-3
Principles for the Evaluation of Transmission Energy-Efficiency Options
•
Anticipated changes in interregional flow patterns impacting the system
•
Generation retirements and other deactivations
•
Expected performance of demand response (if applicable)
Having defined power-system scenarios, annual economic benefits can then be calculated for a postulated set of loss-reduction measures. If a long-term transmission-expansion plan is available, the future system conditions envisaged in the plan can be used as a reference for defining baseline scenarios. Transmission-expansion plans define the transmission reinforcements that are to be implemented in order to ensure that the electric system will be able to supply electricity to customers from the available generation in a reliable and economic manner. As load forecasts predict demand to exceed available capacity, T&D planners identify necessary system upgrades and expansions. Projects that are needed to maintain reliability while accommodating the ongoing needs of existing transmission customers are identified as necessary. Transmission-reinforcement decisions are usually made to ensure that the total investment cost is minimized while reliability constraints are met. The criteria and procedures to perform transmission-expansion plans may differ considerably from one system to another, depending on the system characteristics and, especially, on the regulatory framework. Transmission plans in vertical integrated utilities have traditionally been justified from a technical, rather than from an economic, point of view. Typically, the expansion philosophy was to expand the transmission system to satisfy a set of predefined service-quality and reliability standards at minimum cost. In this way, transmission expansion will allow the utility to accomplish the target level of reliability with which its load will be served. The level of system losses will result from the application of these planning and design criteria. On the other hand, in market-based power systems, transmission-expansion projects are usually justified or based on either or both of the following criteria: •
Reliability: These projects are network upgrades that ensure that the transmission system complies with applicable reliability requirements, such as the National Electric Reliability Council (NERC) or regional reliability councils.
•
Economic: These projects are proposed network upgrades that are beneficial to some market participants but that are not required for reliability. Economic projects may benefit market participants by supporting competition in bulk power markets, by expanding trading opportunities, or by alleviating congestion beyond that achieved by reliability projects.
Transmission-system reinforcements needed to maintain reliability are usually built by transmission owners and paid for by customers. The responsibility for construction and the allocation of costs among the customers differs from system to system. On the other hand, in economic planning, the market participants proposing the economic projects are responsible for the investment expenditures and costs, and they normally receive transmission rights for the transmission capability that their upgrade yields. Projects based on both reliability and economic plans should be considered for baseline definition in TEE-program evaluations.
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Principles for the Evaluation of Transmission Energy-Efficiency Options
Identification of Baseline Conditions As opposed to end-use efficiency projects, for which certain established measures (such as the replacement of incandescent bulbs with CFLs) have associated energy-savings guidelines, efficiency projects in transmission systems do not have the benefit of widely accepted savings guidelines. Currently, there is no industry-standardized method to account for electrical lossreduction in the transmission or distribution system—or, for that matter, for the loss-reduction opportunities associated with transmission-upgrade projects. There are a number of analytical subtleties involved in quantifying the loss-reduction impacts of transmission projects. For example, the extent to which loss-reduction can be evaluated depends upon the primary purpose of the improvement—efficiency versus capacity expansion—because loss-reduction options such as voltage uprating, reconductoring, or bundling conductors have a dual effect. If regulatory instruments for TEE cost recovery or incentives are implemented, it is necessary to identify the benefits of reducing losses and the associated implementation costs. In projects with dual effects, the identification of benefits solely due to loss-reduction and cost allocation poses a challenge. Consider, for instance, a project consisting of reconductoring a transmission line for increasing the transmission capacity of a certain corridor. Assume that losses in the entire system are reduced by this project. In this case, loss-reduction is a by-product of an investment that was chosen for other purposes. However, it could be argued that savings from loss-reduction should be credited to such a project, because a reduction in losses is in fact achieved. But even if it were acceptable to credit loss savings to the project, the specific benefits solely due to loss-reduction are in most cases very difficult, if not impossible, to identify; they are embedded in the total benefit of the project. For example, if the reinforcement is needed to supply the load, it is not possible to determine a baseline for a loss-reduction evaluation without such reinforcement. One option for evaluation of dual-effect projects could be to identify additional improvements to the base design that would allow a further reduction in losses, and to associate this extra energyefficiency benefit with the marginal investment. For example, consider the case of an existing 50-mile-long 230-kV transmission line with a simple-bundled ACSR 795-kcmil conductor. It is necessary to expand the transmission capacity of the line, so it has been decided to replace the existing conductor with a larger one. The conductor chosen is an ACSR Lapwing 1590-kcmil conductor. This conductor will allow the utility to meet the project objectives at a minimum investment cost. An option to further improve transmission energy efficiency would be to choose a trapezoidalwire conductor. The ACSR Lapwing 1950 ATHABASKA/TW kcmil would be a good option. The diameter is the same as the ACSR Lapwing, so wind and ice loading would not increase. But the resistance is 18% less than for the Lapwing. In this case, the benefits would be the total losses associated with the ATHABASKA/TW conductor, minus the total losses associated with the ACSR Lapwing. And the cost associated with the loss-reduction measure would be the price difference between these two conductors. Note that if the TEE project is decided upon, the most practical implementation would be to replace the existing conductor with the ATHABASKA/TW conductor. The consideration of the intermediate case(the ACSR Lapwing conductor) is a means to enable the utility to evaluate the costs and benefits associated with the energy-efficiency option. This concept is illustrated in Figure 4–2.
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Principles for the Evaluation of Transmission Energy-Efficiency Options
Figure 4–2 Possible Approach to Define Baseline in Dual-Effect Projects When the Primary Objective Is Not Loss-Reduction
As another example of marginal investment to further reduce losses, suppose that FACTS devices are chosen to be installed in a given power system, with the objective of diverting power flows to improve some congested paths and/or to improve system security. Assume that a reduction of transmission losses is actually achieved to some extent as a result of the power-flow control. As in the previous example, this reduction in losses is a by-product of the strategy that was implemented for another purpose. Suppose, however, that the addition of a centralized controller is evaluated in order to further redirect power flows to obtain additional reduction of losses, without affecting the primary objective of the power-flow control. For the cost/benefit analysis of the TEE (the supplemental centralized controller), the incremental cost due to the installation of the centralized controller is considered as the cost. The benefits will be the extra loss-reduction that is achieved because of the implementation of such a controller. However, in this case, unlike in the previous reconductoring example, the additional investment to reduce losses can be chosen and implemented at any time after the primary installation is in place and operating. In summary, any such marginal reduction of losses that can be obtained by augmenting other projects that are undertaken for other purposes should be considered in the TEE evaluation at the marginal cost incurred. In cases in which the loss-reduction measure is being considered for the sole purpose of TEE, the baseline definition is more straightforward, because it is defined “without” the upgrade project.
Quantification of Transmission Losses Quantification of transmission losses is a key component of the evaluation of options for improving TEE. Losses need to be accurately determined for two conditions: “without” and “with” the loss-reduction projects being investigated. Different methodologies can be applied for transmission loss-evaluation. The approach to be adopted will depend upon the operation characteristics of the system being studied, as well as the available data and simulation tools. 4-6
Principles for the Evaluation of Transmission Energy-Efficiency Options
Regardless of the methodology adopted, the same methodology must be followed in all the different stages of the evaluation process so that the benefit appraisal will be consistent. Transmission losses can be evaluated as a byproduct of the economic operating-cost analysis obtained from a security-constrained dispatch program. If an ac network model is used to evaluate savings in energy costs resulting from upgrades, the loss impacts are implicit in the overall economic results. Such models exist, but they may be time-consuming to use when hourly resolution over a number of years is required. If linear dc load-flow representations are used in the constrained dispatch program, losses are estimated approximately. Even though such approximations provide reasonable precision for operation and expansion planning purposes, they should not be used in such cases, because the analysis here is focused on loss-optimization; a more precise approach is required. As an alternative, statistics of hourly circuit loadings and marginal costs can be summarized for postprocessing to obtain annual transmission losses. Transmission losses can also be determined by power-flow analyses or by applying the securityconstrained dispatch program to a limited number of load levels. Hourly costs of losses obtained at each load level can then be multiplied by the number of hours of exposure to this load level, as derived from a load-duration curve. Alternatively, curve-fitting techniques can be used to determine losses as a function of system load; total energy losses are then determined by integration of this function over the annual load-duration curve. Procedures for transmission-loss evaluation are described in Section 13 and the references therein.
Economic Variables for Cost-Effective Analysis Computing the NPV, the benefit-cost ratio, or the other economic metrics of a TEE requires estimating the present value of the stream of costs and benefits of the program over its lifetime. This computation requires estimates of both escalation (or inflation) rates and discount rates. Escalation Rates To estimate the future annual costs and benefits of a TEE program, the value of each component of the cost-effectiveness test must be appropriately escalated over time. In general, escalation rates reflect the expected inflation for each of the cost and benefit components. However, different inflation indexes may be appropriate for different cost categories. For example, a materials index and labor index may be appropriate for determining the investment cost of projects considered in future years. The cost of energy, as well as of capacity and carbon dioxide (CO2) emissions have to be scaled to determine savings during the horizon time considered in the evaluation. Discount Rate Because of the nature of the technological options proposed for TEE, the utility’s allowed rate of return for capital investments is the appropriate rate to consider for the evaluation.
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Principles for the Evaluation of Transmission Energy-Efficiency Options
Project Costs The cost-effectiveness evaluation of prospective TEE projects requires a consideration of all the costs and expenses that the utility has to incur to develop and implement the project. The costs include: •
Capital cost of upgrades
•
Increased or decreased maintenance costs associated with upgrades
•
Operating costs caused by operating constraints during construction
Capital cost varies significantly with the nature and characteristics of the project. Sections 0 to 0 describe in detail the capital and maintenance costs for each of the different technologies. As explained in the previous section, the capital cost allocated to TEE in dual-effects projects will depend on the project’s main driver. The marginal investment cost to further improve efficiency is to be considered in dual-effects projects driven by transmission-capacity expansion or reliability. For instance, if a centralized control- system loop is evaluated to control existing or new FACTS installations for loss-reduction, the investment cost to consider on the evaluation of TEE is basically the cost of deploying such a control system. Other costs, like increments in operations and maintenance (O&M) costs associated with the new installations, need to be included. (For example, the work burden in the control room may increase, and more personnel may be required to handle it.) Operating constraints caused by outages during upgrade construction may have a significant impact on operating costs. Operating constraints may result in operating-cost penalties, necessitate temporary operations that do not meet reliability criteria, or require temporary interruption of supply to customers. These adverse impacts will vary dependent on the outages required, the duration of the outages, and the flexibility of the system to accommodate the required outages. Operating-cost penalties during the implementation of upgrades can be evaluated by operation-simulation software.
Benefits Assessment The benefits associated with a TEE project are determined based on the avoided cost for the utility to supply electricity with a reduced level of losses. Indeed, reductions in line losses reduce the kWh required to serve end-use loads and also reduce peak demand. These costs include capacity cost, energy cost, and T&D costs. The savings must be monetized to compare the benefits with the costs and to ascertain whether the investment is justified. How kilowatt (kW) and kWh savings are monetized depends on how the electricity market is organized, which determines the monetary impact the utility realizes. Capacity Costs Generation-capacity costs are a measure of the cost of building and maintaining new generation plants to serve peak demand. Capacity cost is determined differently for a restructured market than for a vertically integrated utility.
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Principles for the Evaluation of Transmission Energy-Efficiency Options
Least-Cost Planning Protocols In a vertically integrated utility, the utility will typically identify the type of plant that will be added to its planned capacity additions. Avoided cost ($/kW-yr or $/kWh) reflects the cost savings that the utility realizes from reduced kW and kWh delivery requirements. In principle, avoided capacity costs ($/kW) are set equal to the annualized cost of a gas-turbine peaking unit, under the assumption that reduced kW have a corresponding impact on the need for such units. Because the standard of comparison is a peaking turbine, one would expect that the cost would be quite uniform across the country, with differences reflecting local variance in land costs, taxes, and other non-machinery-based costs. Moreover, they should vary only a small amount from year to year, reflecting turbine-parts costs. However, posted avoided-capacity costs have varied quite substantially across utilities, and over time for a utility; from as low as $30/kW to over $100/kW avoided. Engineering studies that are normalized for localized exceptional conditions typically report peaking capacity costs in the range of $60–75/kW. Market-Based Prices Independent System Operator/Regional Transmission Organization (ISO/RTO) markets that impose capacity requirements on load-serving entities (utilities and competitive retailers of electricity) operate capacity markets so that buyers and sellers (generators and demand-response providers) can resolve imbalances. In some markets, such as the New York Independent System Operator (NYISO), the market is used primarily to resolve short-term imbalances (for a sixmonth period or a single month). Most of the capacity need is met through bilateral contracts. Others, like Independent System Operator–New England (ISO–NE) and the Pennsylvania–New Jersey–Maryland Interconnection (PJM), operate central procurements in which the entire capacity requirement is procured through a centralized auction. Each auction procures the capacity requirement for three years out (for example, ISO-NE), but some (especially demandresponse suppliers) can make offers for up to five years and receive that clearing price throughout that contract term. All buyers pay the market-clearing price, and all sellers receive that price. This practice provides transparency to capacity prices, at least for the auction term. The NYISO auction prices have historically been highly volatile, sometimes ranging in a year from as low as $.10/ kW-month to $5/ kW-month. A new auction mechanism has stabilized prices, but they still vary considerably across the state’s capacity zones, most recently in the $40–60/kW-yr range. PJM and ISO-NE auctions have imposed a floor on the price for the initial auctions at the assumed price of a peaker turbine, which is about $65/ kW-yr. Energy Costs Avoided energy costs ($/kWh) are typically set by predicting marginal supply costs for each year through some forecasting methodology. However, utility protocols for determining the avoided costs vary, and as a result, so do the avoided costs—even among utilities with quite similar generation resources. Some utilities set the avoided costs based on estimates of marginal generation costs, whereas others use average supply costs, which are lower (in some cases, considerably lower). Posted avoided-energy costs range from as low as $.030/kWh to over $.20/kWh. In restructured markets with ISOs, some jurisdictions (such as PJM and NYISO) use locational marginal pricing (LMP). LMPs are determined based on the prices offered by generators, the prices bid by dispatchable loads (if any), and the transmission constraints. LMPs vary by location 4-9
Principles for the Evaluation of Transmission Energy-Efficiency Options
(or bus) on the grid and represent the marginal cost to supply one more megawatt (MW) of load at a given location. In systems under an LMP dispatch regime, the marginal cost of transmission losses is considered for transmission pricing. Loss-penalty factor are incorporated into dispatch and pricing calculations. By including the penalty factor, losses are paid on the margin instead of on the average, as a consequence an over-collection occurs because the marginal-loss cost is much higher than the real cost of replacing losses. Penalty factors are usually determined from the incremental losses calculated in an optimal power flow. For systems under this transmission pricing regime, the cost of losses to be considered for determining benefit from loss-reduction measures has to be calculated based on LMP values. Midwest ISO (MISO), for instance, determines the economic benefit of loss decreases due to system reinforcement by pricing losses at an hourly load-weighted LMP. The simulation software PROMOD® is used by MISO for economic evaluations. To obtain the economic benefits of select projects, two PROMOD® cases are run: one case without the projects, and one case with the projects. Then the results from these two cases are compared to obtain the economic benefit. In some power systems, losses are priced at average value instead of marginal cost, so the cost of transmission is based on the cost of replacing the losses rather than at a competitive transmission price. In these cases, the average cost of losses is considered for a benefit-evaluation of the lossreduction methods. Regardless of the way losses are priced, the cost-effectiveness evaluation of a TEE requires a future stream of energy prices. Average energy prices or LMPs need to be forecasted on an hourly basis, using a production-costing model that simulates the day-to-day operations of a utility system or a larger system (if the market is restructured)—including projected fuel costs, variable expenses, maintenance schedules, and other factors. Because the baseline should be based on a transmission- expansion plan, the energy-cost forecast needs to consider all the projects and future system characteristics foreseen in the expansion plan. In some cases, however, it is difficult or unfeasible to forecast energy costs by using a cost-production model or a similar simulation tool. In such cases, the estimated value of energy costs can be used to evaluate TEE projects. An escalation rate is used to estimate increments of energy in future years. Transmission-Capacity Costs Reduction of transmission losses unloads some transmission circuits, somewhat reducing to some extent the cost of transmitting power across the transmission network. Capital costs go down to the extent that peak-load growth is averted, and the costs of transmission upgrades are avoided. These values are typically calculated based on historical transmission-investment data and are very system-specific. Transmission investments occur for a variety of reasons; only a portion of them are related to growth in peak demand. The marginal transmission cost should be based on investments related to growth in system peak. In some cases, states that consider avoided generation capacity and energy costs attribute the associated cost savings to avoided transmission costs. However, because these savings are determined somewhat subjectively, it is difficult to generalize the methodological approach. Moreover, some states do not recognize T&D avoided costs.
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Principles for the Evaluation of Transmission Energy-Efficiency Options
Transmission-capacity costs are only relevant for vertically integrated utilities, and they are typically small compared to generation-capacity and energy costs. Avoided transmission costs are generally under $0.10/kWh, and often less than five mills ($0.005/kWh). Utilities use the approved jurisdictional procedure to determine the transmission-capacity cost. Recommended Values for General TEE Evaluations In cases in which utility cost variables (capacity, energy and transmission costs) are difficult to determine (or to expedite screening analyses), estimated values should be used for these parameters. Table 4–1 provides a representative value of the utility cost variables needed to conduct a cost/benefit analysis of TEE. It can be observed in this table that the variation range of these values is significantly great. So if there is not enough information available to make a good estimate of the values for a particular study; a more complete sensitivity analysis should be conducted to assess the impact of data uncertainty on the study results. Table 4-1 Representative Values of Utility Cost Variables Representative Value
Low
High
$70
$50
$100
Transmission Capacity ($/kWh)
$0.002
0
$0.005
Energy Cost ($/kWh)
$0.10
$0.05
$0.20
Cost Variable Generation Capacity ($/kW-yr)
Cost of Emissions Externalities are costs that are associated with economic activity apart from the costs included in and recovered from the price consumers pay for the good or service. The addition of the externality cost raises the level of the allowable incentive for implementing measures to improve efficiency. Reducing transmission losses generates environmental benefits from reduced emissions associated with supplying electricity. Pollution is a negative externality (unaccountedfor costs) because the damage caused by pollutants emitted from power plants is not entirely captured by the cost of production or reflected in the prices paid by consumers. Therefore, society would benefit from clean air and reduced climate change to the extent that conservation measures reduce negative externalities. The environmental costs of sulfur dioxide (SO2) and nitrogen oxide (NOx) are included in the calculations of avoided costs of generation—implicitly, because generator owners pay penalties for excessive emissions, and explicitly—because they can purchase rights to increase emissions above their allowance and must add that cost to the price they charge. Until the very recent enactment of the American Clean Energy and Security (ACES) Act of 2009, carbon dioxide (CO2) emissions were not restricted. The ACES Act is a complex bill that regulates emissions of greenhouse gases through market-based mechanisms, efficiency programs, and economic incentives. The Title III cap-and-trade program for greenhouse gas (GHG) emissions addresses the provisions for cumulative GHG emissions. The program subjects 4-11
Principles for the Evaluation of Transmission Energy-Efficiency Options
covered emissions to a cap that declines steadily between 2012 and 2050. The cap requires a 17% reduction in covered emissions by 2020 and an 83% reduction by 2050 (both relative to a 2005 baseline), with targets that decline steadily for intermediate years. Compliance is enforced through a requirement for entities subject to the cap to submit allowances (which are bankable) sufficient to cover their emissions. Allowance obligations may also be offset by reductions in domestic emissions of exempted sources, by international offsets, or by emission allowances from other countries with comparable laws limiting emissions. The very recently issued report by the EIA, “Energy Market and Economic Impacts of H.R. 2454, the American Clean Energy and Security Act of 2009,” analyzes the impact of the ACES Act proposals on energy choices made by consumers in all sectors and the implications of those decisions for the economy. The report studies the impacts of the provisions in the ACES Act by means of the EIA’s National Energy Modeling System (NEMS). The reference case used as the starting point for the analysis in this report is an updated version of the Annual Energy Outlook 2009 (AEO2009). One of the outputs and key findings of this study is a projection of GHG allowances for different scenarios. The scenarios and analysis cases, which are described in detail in this report, are briefly summarized below: •
ACES Act Basic Case: This case represents an environment in which key low-emissions technologies—including nuclear, fossil with core cooling system (CCS), and various renewables—are developed and deployed on a large scale in a timeframe consistent with the emissions-reduction requirements of the ACES Act without encountering any major obstacles.
•
ACES Act Zero-Bank Case: This case is similar to the Basic Case, except that no banked allowances are held in 2030, reflecting the assumed availability of a broad array of reasonably priced low- and no-carbon technologies that can provide an alternative path to compliance, with tighter emissions caps after 2030 through reductions across all energy uses, including transportation.
•
ACES Act High-Offsets Case: This case is similar to the Basic Case, except that it assumes the nearly immediate use of international offsets at levels at (or close to) the specified aggregate ceiling, without regard for possible institutional or market impediments.
•
ACES Act High-Cost Case: This case is similar to the Basic Case, except that the costs of nuclear, coal with CCS, and dedicated biomass generating technologies are assumed to be 50% higher.
•
ACES Act No-International Case: This case is similar to the Basic Case, but it represents an environment in which the use of international offsets is severely limited by cost, regulation, and/or slow progress in reaching international agreements or arrangements covering offsets in key countries and sectors.
•
ACES Act No-International/Limited Case: This case combines the treatment of offsets in the ACES Act No-International Case with an assumption that deployment of key technologies— including nuclear, fossil with CCS, and dedicated biomass—cannot expand beyond their reference case levels through 2030.
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Principles for the Evaluation of Transmission Energy-Efficiency Options
The report states that under the ACES Act’s cap-and-trade provisions, the market price of allowances will establish an incremental cost to emitting GHGs. That cost provides an incentive to reduce emissions, whether or not some allowances are received for free, because operating costs can be reduced by reducing emissions. Allowance prices and levels of emissions are estimated in this report so that covered emissions, less offsets, meet the emissions caps over a time period. The allowance-price path is estimated by assuming a constant rate of growth matching the cost of capital, or discount rate, assumed in financing the investment in allowance banking. The report indicates that the projected allowance prices represent idealized paths, because in reality, allowance prices would tend to fluctuate as markets respond to new information and as unanticipated events unfold. The projected GHG allowances are presented in Figure 4–3, which has been taken from the EIA report. It is observed in this graph that GHG allowance prices are sensitive to the cost and availability of emissions offsets and of low- and no-carbon generating technologies. Allowance prices in the ACES Act Basic Case are projected at $32 per metric ton in 2020 and $65 per metric ton in 2030. Note that the initial value of the Basic Case ($20 per metric ton) is very similar to the initial value used throughout this report for the various case studies.
Figure 4–3 GHG Allowance-Prices Projection (EIA Report)
Emission Intensity The carbon-emission rate, or emission intensity, expresses the amount of CO2 emissions per MWh of electricity generated. For a given power system, this measurement clearly depends upon 4-13
Principles for the Evaluation of Transmission Energy-Efficiency Options
the physical and operating characteristics (efficiency, type of fuel, vintage) of the generation fleet. However, for an evaluation of the performance of an energy-efficiency program, average values for a particular region are commonly used. Values of emission intensity specified by NERC regions, sub-regions, or states are published in the EPA Emissions & Generation Resource Integrated Database [5]. For quick reference, Table 4–2 presents emission-rate values for various NERC regions based on this database. Table 4-2 NERC Region Annual CO2 Output-Emission Rate (Ton/MWh) NERC Region Acronym
Region Name
CO2 OutputEmission Rate (Ton/MWh)
ASCC
Alaska Systems Coordinating Council
0.55
ERCOT
Electric Reliability Council of Texas
0.71
FRCC
Florida Reliability Coordinating Council
0.66
HICC
Hawaiian Islands Coordinating Council
0.83
MRO
Midwest Reliability Organization
0.91
NPCC
Northeast Power Coordinating Council
0.45
RFC
Reliability First Corporation
0.72
SERC
SERC Reliability Corporation
0.69
SPP
Southwest Power Pool
0.91
WECC
Western Electricity Coordinating Council
0.55
References [1] Energy-Efficiency Planning Guidebook: Energy-Efficiency Initiative. EPRI, Palo Alto, CA: 2008. 1016273. [2] IEEE Power Engineering Society, Optimal Power Flow: Solution Techniques, Requirements, and Challenges, IEEE Tutorial Course, 1996. [3] Characterizing and Quantifying the Societal Benefits Attributable to Smart Metering Investments. EPRI, Palo Alto, CA: 2008. 1017006. [4] Energy Information Administration, Energy Market and Economic Impacts of H.R. 2454, the American Clean Energy and Security Act of 2009, August 2009. [5] eGRID2006 Version 2.1, U.S. EPA, Emissions & Generation Resource Integrated Database, Released April 30, 2007.
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5
LOWERING TRANSMISSION LOSSES BY RAISING TRANSMISSION-LINE VOLTAGE This section addresses the merits of voltage upgrades of transmission lines. The goal of increasing the nominal voltage level of an existing ac transmission line is to reduce the transmission-line losses while increasing the power-transfer capacity of that line. Regulatory bodies look favorably on more-efficient use of resources by the utilities. Such projects can also be more acceptable to the general public than alternative projects, such as adding a new line.
This section covers issues such as: •
The forms of voltage upgrades: –
No line modification (increasing the voltage a few percentage points at select times of the year)
–
Minor modifications to the transmission structures
–
Major modifications to the transmission structures
–
Reconstruction of the line (foundations unchanged)
This section also covers some general issues regarding •
Capacity-increase benefits of upgrading a line to a higher voltage
•
System voltage control, such as the use of shunt elements
•
Considerations needed for assessing the feasibility of the voltage upgrade of a transmission line
•
A detailed punch list of some of the studies that need to be completed for the voltage upgrade, such as:
•
–
Electrical studies (such as electrical clearances for phase-to-ground, phase-phase, corona, radio frequency interference (RFI), and electromagnetic interference (EMI)
–
Mechanical studies (such as structural loading, foundations, wind loadings, and lightning protection)
–
Safety and code-compliance studies
–
Economic studies (such as capacity, cost-per-mile, losses, and maintenance costs)
–
Environmental studies (such as visual impact and rights-of-way)
This section also provides some examples from across the United States of lines that have been upgraded to higher voltages. 5-1
Lowering Transmission Losses by Raising Transmission-Line Voltage
Introduction With the demand for electricity steadily increasing, the delivery system is being severely challenged throughout the world. Megawatts are no longer sufficient; the transmission system is being asked to supply electricity in gigawatt proportions. The bulk-power transmission system infrastructure has not kept up with this growth, and it has aged beyond all normal expectations. Utilities are now faced with the challenge of meeting this ever-increasing power demand from their customers, with some experts estimating a 40% growth in demand by 2030. Overhead ac transmission lines represent a significant investment and source of revenue for their owners and operators. We have witnessed an increase in the numbers of new generation units coming on line, but the overhead transmission infrastructure has lagged behind. We have seen loadings of overhead transmission lines becoming heavier and heavier. At the same time, economic and regulatory conditions have made many utilities very reluctant to make additional investments in the overhead-transmission infrastructure. Without additional transmission-system investment, grid congestion will increase, making it more difficult for the available electricity supply to meet demands and facilitate full use of capacity diversity. In some situations, this problem can lead to supply shortages and involuntary customer interruptions. However, building new transmission lines takes time. It takes seven years or longer for engineering design, licensing, and construction of the average transmission line. If the project runs into any opposition, the time will lengthen and the cost will climb. Therefore, the owners and operators are looking for ways to operate their existing transmission lines more efficiently by squeezing every possible megawatt out of the existing infrastructure. What can be done to the existing ac overhead-transmission line to improve its performance, reduce losses, and increase its power-transfer capabilities? Series capacitors and other advanced technologies, such as flexible ac transmission systems (FACTS) devices have been employed to increase power transfer. FACTS devices (also known as FACTS controllers) are power electronics-based systems that control one or more of the ac transmission system’s parameters— which include dynamic control of voltage, current, impedance, and phase angle. They allow the utility to overcome any constraints or limitations on the system brought about by poor voltage performance. There are, however, simpler approaches to solving the problem. It is possible to increase the nominal voltage level of an existing transmission line and increase its power transfer. This voltage increase or upgrade can range from •
No line modification (increasing the voltage occasionally)
•
Minor modifications to the transmission structures
•
Major modifications to the transmission structures
•
Reconstruction of the line (tower below the waist and foundations unchanged)
Voltage upgrades with minimal modifications to the existing transmission structures or the conductor are a desirable alternative to new construction. Typically, they cost less. Regulatory bodies look favorably on more efficient use of resources by the utilities. These projects are also more acceptable to the general public, making them more achievable. Once approved, modifications can be accomplished in less time than the construction of new transmission lines.
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Lowering Transmission Losses by Raising Transmission-Line Voltage
General Operational Issues
Figure 5–1 Multiple Transmission Lines Make up the Grid
Overhead transmission systems are composed of transmission lines (conductors, hardware, insulators, and towers) substations (power transformers, circuit breakers, switches, and bus work), and some form of compensation (capacitors and reactors), all interconnected and forming a grid reaching from the generator to the customer. It is a sophisticated system to deliver electricity (power). The transmission lines interact with the system, and this interaction defines how the line performs and the amounts of power it can transfer [1]. Voltage Control Load growth stresses the transmission system when new facilities lag behind that growth. Voltage control (voltage drop) becomes a major concern faced by the owners and operators of overhead ac transmission systems trying to force the maximum power flow over that system. When a transmission line is lightly loaded, it produces VAR, and the voltage goes up. If the transmission line is heavily loaded, it consumes VAR, and the voltage drops. Extremes in either direction cause problems. Certainly, VAR can be supplied or consumed by adjusting the generator’s field excitation. Taps on a transformer can also produce some voltage control by raising or lowering the voltage. But these measures only provide transitory relief. The real assistance to voltage control comes in the form of shunt reactors and series/shunt capacitors. Shunt reactors are utilized to consume VAR, whereas capacitors can also be used to produce VAR. It is a balancing act. FACTS devices such as SVC can provide a real-time control of transmission-line power flow. Unscheduled Power Flow Overhead transmission lines operating in parallel with each other from what is generally referred to as a path. Grids are made up of multiple paths, which do not share well. Transmission lines have a resistance to the flow of electricity. In a grid configuration, transmission lines with lower resistance will carry more electricity than those with higher resistance, which is described as interaction. The interaction between the overhead transmission lines in this path can be significant enough to require the limiting of the path’s rating. A transmission-path rating is determined by the maximum reliable power-transfer capability under any and all conditions. This rating is normally established by the mutual agreement of regional transmission organizations, made up of the owners of the interconnected systems. 5-3
Lowering Transmission Losses by Raising Transmission-Line Voltage
The limiting factors are thermal overload, instability, and poor voltage performance. The thermal rating of a line is defined by the conductor’s ability to dissipate heat. The stability rating of a line is defined by the power transfer within the voltage-angle limits. Exacerbating this situation are the multiple paths, which can cause bottlenecks, congestion, and loop flows. These operating conditions may limit the path’s rating below its maximum design rating. Loop flow is a phenomenon also referred to as unscheduled power flow. Power flows through all the parallel paths of the grid, but not equally. A power transaction may call for power to go directly from— say—Arizona to Utah, but because of loop flow it goes to California, Oregon, and Idaho before reaching Utah. This is unscheduled flow, and it causes utilities to curtail power transactions to avoid overloading the system. Feasibility of Upgrade When upgrading the voltage level of an overhead ac transmission line, the insulation to ground and between phases has to be increased. To prevent audible noise and interference with radio and television signals, the surface gradient of the conductor has to be kept below certain levels. Each transmission line will be different, due to the numerous existing line designs, with almost infinite possibilities for modifications. Consequently, it is important to understand the physical properties of the transmission line. How will the proposed voltage upgrade interact with the transmission system? Each proposed line modification will affect the transmission system it is interconnected with in some manner. This phenomenon requires detailed investigations of the transmission line and detailed studies of both the transmission system and the proposed line upgrades [2]. Documentation for the original design and construction can be challenging, both in accessibility and in completeness. But once it has been assembled, the decision process can take place. This process becomes a risk assessment of all the available options and alternatives. The final selection will involve a balance of performance, reliability, and costs.
Voltage-Upgrade Concepts The goal of increasing the nominal voltage level of an existing ac transmission line is to reduce the transmission line’s losses while increasing the power-transfer capacity of that line. Exactly how much this capacity increases is dependent upon many variables. Some “back-of-theenvelope” calculations can be made to determine if the selected line will provide the expected capacity. The first step is to select the target voltage level for the upgrades. It would be best to select a voltage level that is a standard within the utility’s transmission system. Such a selection would assure that the utility would have experience with this voltage level, the spare parts, and the facilities to connect it to without additional expense. Normally, this level will be two or three times the existing line’s nominal voltage rating. Consider that an 115-kV line would be in a 115/230/345-kV system. Following this logic, the 115-kV line would be increased to 230kV or to 345kV. A few simple calculations can be performed using the following equations, which are very well known and can be found in any number of texts on power flow over a transmission line. They are, however, included here because they are germane to the decision process under discussion. Simply put, power flowing through a transmission line (neglecting the resistance of the line) is defined by Equation 5–1. It is measured in watts (W). The maximum power that a transmission
5-4
Lowering Transmission Losses by Raising Transmission-Line Voltage
line can transmit is directly proportional to the product of the sending-end and receiving-end voltages.
P =
VS • VR X
W
Eq. 5–1
Where: P = Real power transfer on the transmission line VS = Magnitude of sending end-bus voltage VR = Magnitude of receiving end-bus voltage X = Series reactance of the line Given that utilities work hard at keeping the sending- and receiving-end voltages at relatively the same value, the power limit is roughly the square of the system voltage. As the voltage is increased, so is the power flow. If the line reactance (X) can be reduced, more power flows on the transmission line. Because X is a function of the relationship between conductor size and phase spacing (defined in detail in many power system texts), when the voltage is increased, X remains about the same, and power flow increases. Doubling the voltage of the transmission line will quadruple the power limit of the line. Of course, there is no “free lunch.” Traditionally, increasing the voltage requires greater phase spacing, more insulation, and wider rights-of-way (ROW), but a lot of work has been done over the years with compact line design [1]. The public opposition to higher voltages is because of the increased visual impact. Taking advantage of the new computer programs, designers have been able to reduce the margins in line designs, making them smaller. This development has led others to look at lower-voltage transmission lines and ask: why not apply compact theory to these lines and raise their voltage levels? The compact designs may allow the structures to use longer insulator strings in closer proximity. ROW might be able to handle the increased voltage without requiring additional width. The existing conductor might have sufficient surface area in this geometry. The utility would be able to increase its power transmission without building additional lines. A quick method to calculate a rough approximation of the existing transmission line’s loading limitation would be to use the surge impedance loading (SIL) of the line. SIL is the power delivered by a lossless line to a load resistance equal to the surge impedance of the line (see Equation 5–2). SIL =
V2 ZS
Eq. 5–2
Where: V is the line voltage and ZS is the surge impedance of the transmission line. Zs is defined by Equation 5–3 and is measured in ohms (Ω). ZS = L
C
Ω
Eq. 5–3
Where ZS = Surge impedance L = Positive sequence inductance C = Positive sequence capacitance
5-5
Lowering Transmission Losses by Raising Transmission-Line Voltage
Using these three equations, the engineer can develop a very rough approximation of how much the power can be increased by changing the nominal voltage level of the ac transmission line. If this upgrade seems attractive, the next step is to conduct a more rigorous study to determine the inherent nature of the specific ac transmission line. It is really a feasibility study to establish and identify all the constraints affecting this particular transmission line as part of the transmission grid.
Increasing Capacity Strategies Increasing the power-transfer capabilities of the existing ac transmission lines is a very attractive alternative to new construction, especially if it can be accomplished without substantially modifying the line or affecting the reliability of the system. The costs associated with upgrading an existing line are much less than those for constructing a new line (industry studies place it between 30–70% savings), and public opposition is lessened because the utility is not building a new transmission line that visually impacts the area. The public is used to seeing the existing line. As a rule, they don’t distinguish the difference between the old transmission line and the new, modified line. Examples of savings are: •
No additional ROW costs are incurred.
•
Access roads are in place.
•
Conductors, towers, and foundations are in place.
•
Much of the hardware can be reused.
•
Permitting time is reduced.
Upgrading an existing ac transmission line to transfer more power can be accomplished by two basic methods: increasing the voltage or increasing the current (thermal). But it might be a little more complicated than that. Voltage, current, and phase shift along the transmission line, limiting the power flow over the ac transmission line. Power-flow limitations can be relatively simple, such as in short transmission lines in which the maximum current flow is determined by the thermal limits of the line’s conductor (a function of that current). They can also be a complex issue. This report will focus on increasing the voltage aspects of the transmission line. Increasing line current is discussed in other EPRI publications and technical literature [7].
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Lowering Transmission Losses by Raising Transmission-Line Voltage
Upgrading an Overhead Transmission Line
Figure 5–2 Replacing Structures
Planning, Engineering, and Operating Departments must work together to assess transmissionline upgrades. Each brings its own area of expertise to decide if the line can operate at a higher voltage level safely, reliably, and effectively. Together, they will develop a detailed evaluation of the line. Some redefinition/redesign of the project might be required (physical modifications or reduced electrical performance) as this evaluation progresses [2]. Overhead ac transmission-line upgrades will evaluate the following factors: •
•
Electrical –
Electrical clearances
–
Corona fields
–
Radio/TV interference
–
Electromagnetic fields (EMF)
Mechanical –
Structural loading
–
Foundations
–
Wind loadings
–
Lightning protection 5-7
Lowering Transmission Losses by Raising Transmission-Line Voltage
•
•
•
Safety –
Public
–
Construction
–
Operation and maintenance
Economic –
Cost per mile
–
Losses per mile
–
Maintenance
–
Capacity
Environmental –
Visual impact (aesthetics)
–
Property value
–
Health
–
Safety
–
Physical size of rights-of-way
–
NIMBY (not in my backyard)
Any project that increases the nominal voltage level of a transmission line will have to address issues such as these. Overhead Transmission-Line Upgrading For the most part, raising the ac transmission line’s voltage is well understood [2]. An individual transmission line can have its operating voltage raised temporarily by use of transformer load tap changers, or permanently by new transformers or reterminations to higher-voltage busbars in the substations. If the overhead ac transmission line is constructed to facilitate operation at a higher voltage, it can be reterminated directly to the higher-voltage busbar, such as 115kV to 230kV. But what of the transmission line built to the utility’s standard ac transmission-line design criteria? It was designed and constructed to meet a specific set of design criteria (nominal voltage) for that project’s scope. Perhaps its designers included generous safety factors for tower loadings, phase spacing, and conductor heights. More likely, however, its designers did not anticipate future conditions changing sufficiently for a utility to consider modifying the operating voltage of the line in this manner. This section reviews the key issues that must be addressed when considering raising an ac line’s nominal operating voltage. These include but are not limited to: •
The impact of phase-to-phase spacing, spacing between conductors to the tower, and from conductor to ground at mid span
•
Limiting switching surge overvoltages if they tend to be a significant factor in operation at higher voltage
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Lowering Transmission Losses by Raising Transmission-Line Voltage
•
Insulation coordination—including re-insulation, the insulator arrangement at the tower, and its impact on spacing
•
Raising the towers
•
Terminal equipment upgrades or replacements
Considerations of the Existing Overhead Transmission Line The environmental, mechanical, and electrical characteristics of the selected existing ac overhead transmission line need to be investigated and studied to determine how the transmission line was designed, constructed, and operated. This information is also needed to determine whether or not the line is acceptable for voltage upgrading [3]. Physical Inspection
Figure 5–3 Inspection of Hardware, Conductor, and Insulators
A physical inspection of the line is necessary to establish the actual condition (poles, hardware, and conductor) of the components [4, 5]. Inspection is necessary to verify that the actual route of the transmission line agrees with the plan and profile (P&P). This inspection should look for and identify •
Encroachment of the ROW
•
Compromised clearances
•
Construction adjacent to ROW (built after line)
•
Construction within ROW (built after line)
•
Modified structures (not shown on P&P)
•
New highways, streets, and roads built after line (not shown on P&P) 5-9
Lowering Transmission Losses by Raising Transmission-Line Voltage
•
Reconductored sections of the transmission line
•
Obvious changes to the line and its surroundings
•
Damaged structures, insulators, hardware, or conductor
Mechanical Design Criteria The investigators should assemble all the physical data available for the existing overhead transmission line. Typical data that should be collected for the line: •
P&P of the line
•
Altitude of the ROW
•
Detailed structural tower drawings
•
Photos of structures
•
Conductor type (size, stranding, and name)
•
Shield-wire type and size
•
Insulator type and American National Standards Institute (ANSI) class number or transformer rectifier (TR) number (as appropriate)
•
Associated hardware
•
National Electrical Safety Code (NESC) edition used for line design
•
Electrical design criteria
•
Mechanical design criteria
•
Tower grounding configuration
•
Tower foundation resistance
•
Operation and maintenance records
•
Latest inspection records
Electrical Design Criteria The investigators need the original electrical design criteria for the existing overhead ac transmission line. It should include (but not be limited to): •
Maximum voltage (kV)
•
Nominal voltage (kV)
•
Number of phases
•
Frequency (Hz)
5-10
Lowering Transmission Losses by Raising Transmission-Line Voltage
•
Basic impulse level (BIL – kV)
•
Three-phase fault current (root-mean-square, or rms symmetrical amps)
•
Structure configuration
•
Structural material
•
Minimum insulator leakage distance (in/cm)
•
Minimum phase-to-ground clearance (in/cm)
•
Minimum horizontal phase-to-phase clearance (center-to-center) (in/cm)
•
Minimum vertical clearance from finish grade to energized conductor (in/cm)
Environmental Data
Figure 5–4 Weather Stations Installed Along the ROW Provide Valuable Data
The existing overhead ac transmission line was built in the real world, and many factors were considered in its design. They included: •
Elevation above mean sea level (MSL)
•
Maximum outside ambient air temperature (°F/°C)
•
Minimum outside ambient air temperature (°F/°C)
•
Maximum relative humidity (percent)
•
Minimum relative humidity (percent)
•
Atmospheric pollution level 5-11
Lowering Transmission Losses by Raising Transmission-Line Voltage
•
Maximum wind design speed (miles per hour/foot-pound-second, or mph/fps) no ice (define temperature)
•
Gust Factors
•
NESC loading criteria
•
Maximum design ice loading (define wind and temperature)
•
Soil resistivity (ohm-meters)
•
Soil criteria (net-bearing capability, dry density, buoyant density, frost penetration, and foundation stability)
Standards Investigators should be aware that existing transmission lines were designed and constructed in accordance with the existing industry standards in effect at the time of the design and construction. Standards such as Institute of Electrical and Electronics Engineers (IEEE), ANSI, National Electrical Manufacturers Association (NEMA), and the NESC are published with a date for the time of publication. The NESC is continually revised and upgraded, as are the other standard bodies. The latest NESC has provisions for compact overhead ac transmission lines that may be beneficial for voltage-upgrade projects. Investigators should obtain copies of the standards in effect when their transmission line was designed and constructed. These standards should be reviewed and compared with the current standards and all changes noted.
Investigations and Studies Gathering data about the existing transmission line is important, but that is only part of the decision-making process for this type of project. A physical inspection will determine if the transmission line is a good prospect for a voltage upgrade [3]. If a large percentage of the midspan ground clearances do not meet code, the structures are severely damaged, or if some other big-ticket item shows up, there isn’t much reason to go any further with this line. But if the line is found to be in good shape, the project can move to the next phase. The substation termination is another issue needing to be studied. To make the project economically justifiable, there must be a termination point for the new voltage level. Otherwise, it will require an expensive equipment replacement in the substation. The bus must also have sufficient capacity to accept the new transmission line. There are many references available from EPRI concerning the substation [8, 9], its voltage levels, and its equipment for the interested reader. What is Expected Once the transmission line has passed the initial selection process for a possible voltage upgrade, there are several questions that should be asked to define not only the upgrade, but what is expected from that upgrade. They are: •
What voltage level will be selected for the transmission line?
•
Is this upgrade to be a temporary or a long-term solution?
5-12
Lowering Transmission Losses by Raising Transmission-Line Voltage
•
What is the power-transfer rating of the existing transmission line?
•
What is the limiting factor of the existing transmission line? –
Thermal
–
Voltage drop
–
System stability
–
Other
•
What will be the limiting factor of the transmission line after the voltage upgrade?
•
What is the expected increase in power flow needed to meet project requirements?
•
What are the future load projections for the line (with and without the voltage upgrade)?
•
–
Baseline
–
Peaking
–
Emergency
Are these future loads reasonable with respect to voltage-upgrade modifications to the transmission line?
System Studies The next phase of the investigation process will examine how the modified transmission line will function electrically. The modified line must perform as required, and not adversely affect the operation of the overall transmission system, or there is no reason to continue. Interconnection studies should be performed at this point. These studies are used to establish the line’s operational constraints. They will establish: •
Stability limits
•
Switching surge
•
Lightning performance
•
Insulation coordination
•
Power-flow limits
•
Voltage drop
•
Voltage collapse
•
Corona-induced noise
System traits will also be identified. Such points as open lines, loop flows, or congestion points may place operating limitations on a transmission line based on geographical areas, and they may change daily due to changes in the system’s overall capacities.
5-13
Lowering Transmission Losses by Raising Transmission-Line Voltage
Electrical Analysis It is important to understand how the initial design criteria were used to develop the original transmission line, and how can they be applied to the voltage-upgrade project. In effect, the modified transmission line has become a “compacted” design. The clearances have been reduced, whereas loadings have increased. A detailed engineering analysis needs to take place in both realms (electrical and mechanical). Electrically, the points to consider are: •
Insulator leakage distance
•
Probability of flashover
•
Radio noise limits
•
Lightning trip-out rates
•
Ground-level EMF
Mechanical Analysis Mechanically, the engineering analysis determines: •
Adequate tower/foundation strength to support heavier insulators
•
Space to allow for longer insulators
•
Space for increased electrical clearance to ground
•
Mid-spans having sufficient ground clearance (sag)
•
Shield-wire spacing and clearance
•
Possible replacement of shield wire with optical ground wire (OPGW) (fiber optics)
•
Sufficient room to accommodate greater phase spacing
•
ROW clearance at its edge for any blowout under maximum expected wind conditions
Detailed Engineering Design The initial electrical and mechanical feasibility studies have proven that the selected transmission line is a suitable candidate for the voltage upgrade modification. At this point, the project should be released to the Engineering Department. A detailed engineering design of the project is begun. This phase may locate problems missed in the preliminary studies, which will have to be dealt with if and when they develop.
Results Transmission-line design is a complex subject—encompassing electrical, mechanical, and civil engineering factors balanced against regulatory processes, economics, and environmental concerns. There is always a tradeoff between the cost of the line and the energy to be transported. These concepts have been fine-tuned over the years for the design and construction of new overhead transmission lines. Recently, the theory for compact transmission-line design 5-14
Lowering Transmission Losses by Raising Transmission-Line Voltage
[1] has made possible the scheme of increasing the voltage level to increase the power limits of the transmission line. The process of increasing the voltage rating is a technology that is well-understood in the industry. It has been successfully applied by many utilities [3]. Both the Bonneville Power Administration (BPA) and Baltimore Gas & Electric have upgraded 115-kV transmission lines to 230 kV. Otter Tail Power Company has upgraded about 180 miles (290 km) of 41.6-kV transmission lines to 115 kV. PacifiCorp has upgraded some 46-kV lines in the Salt Lake City area to 138 kV. Also, PacifiCorp has upgraded 115 miles (185 km) of 230-kV transmission lines to 345 kV. The list of utilities upgrading existing transmission lines continues to grow. It is a modification that is very attractive to the utilities, the regulators, and the public. An example of the application of voltage upgrade for reducing transmission losses is presented in Section 13.
References [1]
Transmission Line Reference Book : 115–345 kV Compact Line Design. EPRI, Palo Alto, CA: 2008. 1016823.
[2]
Feasibility of Increasing Transmission Line Capacity by Voltage Upgrade. EPRI, Palo Alto, CA: 2007. 1013984.
[3]
Overhead Transmission Inspection and Assessment Guidelines – 2007. EPRI, Palo Alto, CA: 2007. 1013784.
[4]
Inspection and Assessment of Conductor Corrosion. EPRI, Palo Alto, CA: 2007. 1013892.
[5]
Phase Conductor and Shield Wire Corrosion. EPRI, Palo Alto, CA: 2007. 1013893,
[6]
Risk and Rewards of Incremental Transmission Upgrades. EPRI, Palo Alto, CA: 2006. 1010626.
[7]
AC Transmission Line Reference Book – 200 kV and Above, Third Edition. EPRI, Palo Alto, CA: 2005. 1011974.
[8]
Substation Voltage Upgrade. EPRI, Palo Alto, CA: 1989. EL-6474.
[9]
Substation Voltage Upgrade. Vol. 2. EPRI, Palo Alto, CA: 1992. EL-6474.
5-15
6
LOWERING TRANSMISSION LOSSES BY APPLICATION OF ADVANCED OR LOWER-LOSS CONDUCTORS AND BY BUNDLING This section discusses ways to improve the energy efficiency of transmission systems through a number of options, such as: •
Replacing an existing phase conductor with one of larger diameter of the same type
•
Replacing an existing phase conductor with one of the same diameter but with lower resistance
•
Replacing an existing phase conductor with advanced conductor designs
•
Bundling of existing phase conductor(s) with additional conductor(s) per phase
This section covers issues such as: •
Conductor thermal rating and the challenges to achieve the transfer of power up to the thermal limitation of the transmission line's design
•
The effects of conductor heating on long-term loss of tensile strength and sag (for safety reasons)
•
The definition of objectives, identification of baseline conditions, and evaluation of the benefits of reconductoring options for transmission loss-reduction
•
The choices of conductors, both from a loss perspective and from the perspective of the associated mechanical aspects of conductor options, such as structures and accessories; comparison of different conductor characteristics
•
The cost factors involved in reconductoring, segregated into those which could be readily estimated (such as structure reinforcement and conductor cost) and those which might be difficult to quantify (such as the levels of maintenance required)
•
The monetary value of energy savings from such efforts, including the monetary values of capacity savings and the monetary values of associated externalities (specifically, the reduction of carbon emissions)
•
A simplified economic analysis and methodology, based on loss factor, load factor, and— when available—operational (line-current or power-flow variation) and physical characteristics of the line
•
A number of cases using the above methodologies and economic analyses
6-1
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
Background
In simple terms, an ac overhead transmission line is a long flexible set of conductors forming three phases and, in most cases, a shield wire. The phase conductor can be one or more conductors per phase. The ground conductor is usually one or two wires above the phase conductor attached near the top of the structure. They are supported by structures (wood, steel, concrete, or composite) including insulators, dampers, and hardware. The section between two rigid support structures is referred to as a “span.” The conductor is described as being suspended in a catenary (sag curve) or parabolic curve. This curve defines clearance, which is usually established first. It is required by code requirements and utility standards. Physical factors play a key role in determining the curve, such as type of conductor (diameter and material), terrain, loadings, structures, and economics.
Conductor Thermal Rating The transmission engineer’s challenge has always been to achieve the transfer of power up to the thermal limitation of the transmission line’s design [3]. If that could be done, more power would reach the end user over the existing transmission line. The thermal rating of bare overhead conductors is determined by the maximum continuous current-carrying capacity of the conductor. The thermal rating is a function of the conductor’s characteristics, weather conditions, and the maximum operating conditions of the conductor. It is a major concern because of the effect conductor heating has on long-term loss of tensile strength and sag. The thermal rating is defined to protect the transmission line by avoiding conductor and hardware failures under maximum wind and/or ice loads and to maintain minimum ground clearances, as specified by regulatory bodies in standards around the world. In the United States, it is specified by the NESC. In Canada, the Canadian Standards Association (CSA) specifies the standards. The idea is to restrict both the sag (for safety reasons) and protect the conductor from stress and strain. In addition, transmission-line designers restrict the maximum allowable conductor temperature to an amount that limits the loss of strength to no more than 10% during the lifetime of the transmission line.
6-2
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
Thermally Limited Lines Only a relatively small percentage of transmission circuits are thermally limited, but these circuits limit the useful transfer capabilities of the whole network by roughly 10–20%. In other words, it would increase the efficiency of the system to full utilization of the existing infrastructure if it were possible to identify and overcome the thermal limitations of a relatively small portion of the total grid. It should also be kept in mind that transmission lines are located in networks, and networks interact, causing additional problems. Stability, voltage limits, and/or loop flows must be dealt with before ever reaching the thermal limits of the transmission line. Intelligent technology seeks to address these issues, as well as others. A successful, intelligent, bulk-power control scheme would make thermal limits and power disturbances a thing of the past. We are seeing the emergence of the next-generation of technology that will lead the industry on its way to a reliable and secure grid [8].
Design Considerations Designing an overhead ac transmission line is a complex process [1]. Initially, the utility decides the specific power-transfer and voltage level required for the transmission line. Routing of the line will also determine more design characteristics of the transmission line by defining the terrain and ambient conditions. There are also regulatory and environmental constraints to consider. Rating practices vary from utility to utility, but perhaps the most significant decision is the selection of the line’s conductor. The conductor makes up about 30% of the cost of a transmission line, and it establishes many of the utility’s conventions and assumptions for that line. Conductor Characteristics The conductor-selection process balances operational considerations against cost. The choice of conductor determines losses due to resistance, inductance, and reactance. It also establishes the structure heights, because the maximum sag of the phase conductor is a function of the physical characteristics of the conductor used. It also defines those structures in relationship to ice, wind, and the tension loads they must support; in effect, the structures are dependent on the size and type of conductors used. Characteristics to consider include, but are not limited to: •
Voltage rating
•
Current loading
•
Voltage stability
•
Losses
•
Weight and diameter of conductor
•
Tension loading
•
Thermal rating
•
Wind and ice loading
6-3
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
The engineer’s goal is to choose a conductor that demonstrates the best conductivity-to-weight ratio, along with the best strength-to-weight ratio, for the best possible cost, while meeting the requirements for the project. The designer has a wide variety of conductor types to choose from—with such features as tensile strength, high conductivity, corrosion resistance, or selfdamping—but there is always a tradeoff. Increasing conductor diameter to reduce electrical resistance will increase wind and ice loadings. Reducing conductor diameter (weight) will allow savings for structures and foundations, but at the expense of increased electrical losses over the line’s lifetime and increased corona-induced noise. Increasing conductor tension during stringing will reduce sag clearances, but it will increase the longitudinal forces that break conductor strands. It also requires stronger structures and foundations.
Figure 6–1 Normal Ruling Span Sag-Variation Diagram
Continuous Current Rating A steel core can withstand temperatures of around 200°C (392°F) without changing its physical properties. Aluminum, on the other hand, starts having problems when the temperature goes above 90°C (194°F). Therefore, the combination of aluminum and steel found in ACSR conductors can be operated at 100°C (212°F) for normal operation. For emergencies, it can be operated at temperatures of between 125°C (257°F) and 150°C (302°F), but these are short-time measures.
6-4
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
Figure 6–2 Conductor Heating/Cooling
When power (current) goes through a transmission line, it produces heat (I2R losses), which cause the temperature of the conductor to increase. Normal operating conditions (steady-state thermal rating) are based on calculations defining the maximum allowable continuous current that produces the maximum allowable continuous conductor temperature for a set of very specific weather conditions. It assumes the conductor is at thermal equilibrium for that maximum allowable conductor temperature. The specific weather conditions are very conservative. These calculations are defined in the IEEE Method for Calculations of Bare Overhead Conductor Temperatures and Ampacities Under Steady-State Conditions, IEEE Standard 738.
Power-flow Limitations If the power flow is limited by the transmission line’s thermal rating, it can be increased by: •
Operating the existing transmission line (conductors) at a higher temperature while monitoring the sag in real time
•
Raising the current limit of the conductor while monitoring the conductor temperature in real time
•
Raising the height of the transmission line’s phase conductor
•
Bundling (adding conductors to each phase) the conductors of the transmission line
•
Replacing the existing conductors with a larger diameter-conductor
•
Replacing the existing transmission line’s conductors with advanced conductors, which would have the same diameter, but would be able to operate at higher temperatures (higher current)
6-5
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
Interaction of Wind and Conductor Temperature Some utilities have been investigating the interaction of wind and conductor-temperature elevation, with interesting results. The accepted method of determining an overhead conductor’s rating has always been based on local weather conditions, conductor characteristics, and the utility’s design criteria. Transmission-line conductor ratings are generally calculated using a wind speed of 2 ft/sec (0.61 m/s) in the sun with a 40˚C (104°F) ambient temperature, a 25˚C (77°F) ambient temperature rise and a conductor temperature of 75˚C (167°F). This method is a conservative approach, but climates differ widely. The interested utilities gather weather data from the National Oceanographic and Atmospheric Administration (NOAA) and the National Weather Service and install weather stations along transmission corridors, with research-grade sonic anemometers to gather real-time data. If the wind conditions exist, this approach allows the utility to increase the power transfer over existing lines. Increasing the wind speeds to 4 ft/sec (1.219 m/sec) allows the line rating to be increased by 18.2% and 5 ft/sec (1.524 m/sec) and increases the rating by 25.1%. The utility has to do a lot of research first and know the condition of the line before applying higher criteria to increase the rating. It should be pointed out that, with increased ratings, O&M is very important to keep the reliability of the system intact. It doesn’t improve the transmission line’s losses, but it does allow the utility to utilize an installed asset more efficiently. System operators often prefer a fixed maximum rating for transmission lines because it is easy for them to manage, but today’s advanced computer systems are producing real-time dynamic ratings. With weather-dependent dynamic ratings applied, on-line tools that are easy to apply are also required to assist the operator to make use of the resulting loading benefits. Increasing the Height of the Conductor
Figure 6–3 Installing Bayoneting on a 115-kV Transmission Line
6-6
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
A simple approach aimed at increasing transmission-line capacities is to raise the height of the line. Utilities have found that, in many cases, transmission lines are limited by segments rather than by the entire line. sections might have limited ground clearance due to the occurrence of many unforeseen events since the line was constructed. One method of improving clearance is called bayoneting. The structures in question are inspected to determine their condition and whether they can support the additional weight, stress, and forces. Assuming the structure is sound, the shield wire and the conductor (or the shield wire alone) are raised on extensions attached to the top of the structure (typically, wood poles). The length of the extensions is determined by the clearance needed to meet code. If only the shield wire is installed on the bayonet, the phase conductor is then raised to the top of the existing wood pole. This task can be accomplished with the line energized or with minimum outage times.
Figure 6–4 Installing PhaseRaiser on a Transmission Line
Another method for improving ground clearance without replacing structures is called “PhaseRaiser.” This is a system that allows a transmission line’s ground-line clearance to be increased by cutting the pole, raising it hydraulically, and installing steel support units. This system has been installed at many voltage levels by utilities across North America. Being able to increase the transmission line’s ground-line clearance while keeping the line energized is a tremendous benefit to a utility. Again, these methods don’t improve the transmission line’s losses, but they do allow the utility to utilize an installed asset more efficiently. Monitoring Sag in Real Time Moving up the scale in technological complexity, sensors have been developed and combined with computer programs that provide intelligence about the transmission lines. Imagine being able to increase a transmission line’s power-transfer rating by 18% or more just by being able to monitor the sag of the line in real time! EPRI started a collaborative research project [9] several years ago to develop a system to monitor transmission-line sag in real time. As a result, a device has been developed called the “Sagometer.” It consists of a smart camera with a target, data6-7
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
logger, and communications system. The camera is located on the transmission structure of the segment in question. A target is placed in the mid-span of the phase conductor. The camera records the sag of the conductor and calculates the ground clearance in all light conditions. This recording is done inside the camera. The camera sends this information to the system operator, giving the actual condition of the line as more power is transferred across it. It can be set to alarm the operator only when the conductor reaches a preset sag dimension. Like the other methods, this technology doesn’t improve the transmission line’s losses, but—again—it allows the utility to utilize an installed asset more efficiently by increasing the line’s capacity.
Figure 6–5 Installing Sagometer Camera and Target on Line
In addition to the Sagometer, there are other monitoring devices available for installation on conductors to monitor their physical condition. Load cells, radiation monitors, and temperature monitors can be installed. Many utilities use computer programs to model what is taking place on the transmission line and help operators determine exactly how much power can be transferred over the line without impacting the system or the critical ground clearance. Sagging-Line Mitigator The Sagging-Line Mitigator (SLiM) is a new class of line hardware installed permanently on the transmission line. It was developed by Material Integrity Solution, Inc., with funding from the California Energy Commission. It has been field-tested as part of an EPRI Tailored Collaboration (TC) demonstration project [7] with San Diego Gas and Electric, Pacific Gas and Electric, Southern California Edison, Public Service Company of New Mexico, Consolidated Edison, British Columbia Hydro, National Grid Transco (UK), Northeast Utilities, and the California Energy Commission.
6-8
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
Figure 6–6 SLiM Device
The EPRI TC confirmed that the SLiM reduces the effective length of the conductor during hightemperature conductor conditions. As the conductor heats, its length increases, which increases sag. SLiM changes its geometry to decrease the line segment’s length. This eliminates the excess sag in the transmission line, allowing higher line-transfer capability when it is needed most. When the temperature returns to normal rating, the SLiM returns to its original geometer. It is ready for the next temperature excursion, and the conductor always remains within acceptable sag and tension limits. The passive design (no motors or electronic controls) of the SLiM device and its ruggedness encourage utilities to treat it like typical transmission-line hardware. In effect, it becomes a permanent part of the transmission line. Bundling the Phase Conductor An existing single conductor per phase can be combined with a new conductor. This is known as bundling. It is accomplished by stringing the new conductor below or parallel to the existing conductor. This procedure has the advantage of reducing the electrical characteristics (impedance, inductance, and admittance) of the transmission line, which reduces losses. Also, adding a second conductor of the same diameter can save money over removing and replacing the existing conductor with the installation of a single conductor of twice the diameter.
Figure 6–7 Bundled Conductor
6-9
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
Bundling the conductors increases the thermal capacity, which improves the sag limitations. There are, however, disadvantages. The structures on the transmission line need to be inspected to determine if they can support the additional loads of either the second conductor or the increased-diameter conductor. Bundling the conductor will increase the conductor weight (vertical loads), transverse (wind) loads, and ice loadings on the structures. The towers require lateral strength to withstand these forces placed on the line. Bundling conductors usually requires substantial reinforcement of the tower structures and possibly also the concrete footings of the towers. Advanced Conductors Copper was the material of choice for transmission lines at the beginning of the 20th Century, which didn’t give the engineer a lot of options. Stranded-aluminum bare conductor for overhead lines was introduced about 1895. Somewhere around 1908, a stranded-steel reinforced-aluminum conductor was introduced. But aluminum really didn’t gain wide acceptance until World War II made copper scarce and expensive. The addition of this stranded-steel core gave the aluminum conductor the tensile strength it needed, and the aluminum-core steel-reinforced (ACSR) conductor soon became the standard for transmission-line construction. Today it is estimated that over 80% of the existing transmission lines are constructed with ACSR conductor, but we are again seeing another transition taking place with the newer conductors coming onto the market. These are aluminum-based conductors combined with advanced materials, which make possible lighter-weight higher-capacity composition conductors. For many years, the engineer could select a variety of conductor sizes but had a limited choice in the materials or composition of the conductor. That situation has changed with the introduction of advanced materials and alloys. These high-temperature, low-sag (HTLS) advanced-technology conductors are able to carry much higher currents continuously without exceeding sag clearances. HTLS conductors are capable of continuous operation at temperatures ranging from 150°C (302°F) to 250°C (482°F), depending on the specific design of the conductor [4]. They do this without increasing sag at mid-span or reducing the conductor strength normally associated with ACSR conductors exposed to high temperatures. Aluminum conductors are very stable over time, as long as the temperature of the aluminum strands stays below 100°C (212°F). Temperatures above this point harden strands and lose tensile strength. The loss of strength increases with the temperature. Utilities have found that they can replace the ACSR conductor in an existing overhead ac transmission line with little or no modification to the transmission structures making up the transmission line.
6-10
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling Table 6-1 Comparison of Available Conductors Homogeneous Conductor
Nonhomogeneous Conductor
Advanced-Materials Conductor
Advanced Alloys
Copper
Aluminum-Core SteelReinforced (ACSR)
Aluminum Conductor Composite-Reinforced (ACCR)
Aluminum Conductor Fiber-Reinforced (ACFR)
All-Aluminum Conductor (AAC)
Aluminum Alloy Conductor SteelReinforced (AACSR)
Aluminum Conductor Composite-Reinforced/ Trapezoidal Wire (ACCR/TW)
Thermal-Resistant Aluminum Alloy Conductor FiberReinforced (TACFR)
All-Aluminum Alloy Conductor (AAAC)
Aluminum Conductor Steel-Supported (ACSS)
Aluminum Conductor Composite Core (ACCC)
Zirconium HighTemperature Aluminum Alloy Conductor Invar Steel– Reinforced (ZTACIR)
Aluminum Conductor Alloy-Reinforced (ACAR)
Aluminum Conductor Composite Core/ Trapezoidal Wire (ACCC/TW)
Gap-Type Ultra Thermal–Resistant Aluminum Alloy Conductor SteelReinforced (GTACSR)
With the introduction of composite materials to transmission conductors, the industry has the ability to tailor both the physical and the mechanical properties of these composite conductors to suit the specific purpose of the installation. •
Metal Matrix: 3M introduced the first metal-matrix conductor in 2005. This is an aluminumcore composite-reinforced (ACCR) conductor. It can carry 1.5 to 3 times the current of an ACSR conductor. It has the same sag characteristic at 210°C as ACSR has at 100°C. Seven utilities now have this conductor installed on their transmission systems.
•
Carbon-Fiber Conductor: Composite Technology Corporation introduced a composite-core conductor using carbon fiber, glass, and epoxy for the core. Twenty-one miles of this conductor are being installed and tested in Kansas. It sags about 10% as much as the samesize ACSR conductor. As a matter of fact, it gets stronger when heat is applied to it, allowing for 28% more aluminum conductor to be wrapped around the core for greater currentcarrying capability.
•
Aluminum conductor steel-supported (ACSS): It consists of fully annealed strands of aluminum (1350-H0) stranded around a stranded-steel core. The steel core wires may be aluminized, galvanized, or aluminum-clad and are normally “high strength,” having a tensile strength about 10% greater than standard-steel core wire. ACSS is capable of operating at very high temperatures (over 200°C). It also has a high capacity for damping aeolian vibration. In addition, Southwire has developed a Galfan coating for the ACSS, which improves the conductor’s ability to withstand corrosion.
•
Superconducting Conductor: High -temperature superconductor (HTSC) cables are also a reality, as these projects illustrate. American Electric Power installed a 200-m HTSC cable, designed and manufactured by Ultera (a joint venture of Southwire and NKT cables), at its 6-11
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
Bixby substation in August of 2007. The Triax cable is energized at 13.2 kV and rated 3.0 kA and 69 MVA, and it incorporates all three phases of a power line through a single cable. This design reduces space requirements and uses one half the quantity of superconducting materials. Sumitomo, SuperPower, Inc., the BOC Group, and National Grid have installed the world’s first “In-Grid” HTSC 350-m, 34.5-kV underground cable in Albany, NY this year. The venture is known as “the Albany project.” American Superconductor Corporation started production of HTSC cable in 2005. The cable is able to carry 150 times the current as copper cable of the same dimensions. DOE has been working with manufacturers to develop the next generation of HTSC 2G. Rockwell Automation and SuperPower, Inc. are both working on this technology. With all of these advanced conductors coming into the marketplace, utilities were facing a lot of decisions in a very short time. They knew they needed to install advanced conductors to increase their system’s ability to transfer power. The big problem was which one to use. Utilities are a conservative group, and they need to be convinced that they will not be affecting their reliability. To aid the utilities with these decisions, EPRI performed a TC demonstration project [4] with Center Point Energy, Hydro One, Arizona Public Service, and San Diego Gas & Electric. The goal was to evaluate the performance of a selection of advanced conductors over a number of years. The HTLS conductors selected for the project, together with their suppliers, were: •
Aluminum conductor, steel-supported/trapezoidal wire (ACSS/TW) (Southwire of Georgia, USA)
•
Aluminum conductor, composite-reinforced (ACCR) (3M of Minneapolis, USA)
•
Aluminum conductor, composite core (ACCC) (CTC of California, USA)
•
Gap-type aluminum conductor, steel-reinforced (GTACSR) (J-Power System, Japan)
•
Zirconium-type aluminum conductor, invar steel–reinforced (ZTACIR) (LS Cable, Korea; formerly LG Cable).
Trapezoidal-Wire Conductors – ACSR/TW or AAC/TW A trapezoidal wire (TW) cable is a concentric lay-stranded conductor, consisting of a strandedsteel central core with one or more layers of trapezoid-shaped aluminum wires. Usually, trapezoidal-wire conductors are available in two different designs: • Trapezoidal wire of equal area: In this design, the TW conductor has the same area as the standard ACSR round-wire conductor. This design provides a conductor with a smaller overall conductor diameter and results in lower wind and ice loads while maintaining the same ampacity. • Trapezoidal wire of equal diameter: In this design, the TW bare conductor has an overall diameter equal to the standard ACSR conductor. This design provides up to a 20% increase in aluminum area, which results in a higher current-carrying capacity and lower resistance. Although this conductor is limited to operation at moderate temperatures, the use of compact trapezoidal strands results in a resistance reduction of about 20% for the same diameter as the original conductor. Hence, replacing existing round-wire conductors with TW conductors of the same diameter allows utilities to reduce line losses of up to 20% without increasing structure 6-12
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
transverse loading. If some increase in conductor diameter over the original is possible, with limited structural reinforcement, the resistance reduction can be in excess of 20%, and the increase in rating can be 20% or more.
Evaluation of Reconductoring Options for TEE Improvement Transmission-line upgrades by reconductoring have been extensively applied in transmission systems, with the primary objective of increasing transmission capacity. Under certain conditions, reconductoring is a feasible option for reducing transmission-system losses in a costeffective manner. The options to improve transmission-system efficiency by reconductoring are: • Replace the existing conductor with a conductor of larger diameter but of the same type. • Replace the existing conductor with a conductor of the same diameter but with lower resistance (TW conductor). • Replace the existing conductor with an advanced conductor. • Bundle the existing conductor with an additional conductor per phase. In order for reconductoring options to effectively reduce losses, the current magnitude over the reconductored line has to be maintained as closely as possible to the current magnitude on the existing line. In this case, the reduction in line losses is proportional to the reduction in conductor resistance, implying that the additional transmission capacity provided by the new conductor/s should not be utilized. If so, losses might increase rather than decrease. Nevertheless, in reconductoring projects, it is worth evaluating the effect of taking advantage of the increased capacity achieved; in some cases, losses can still be reduced, and other additional benefits can be accomplished. This point is discussed in more detail in Section 13. There might be situations in a power system in which increasing the capacity of certain transmission lines would reduce overall system losses, even when losses on that particular line increase. For example, suppose that because of transmission limitation on a particular line, power flows over less-efficient paths. Releasing the line limit might cause a reduction in total system losses. Note, however, that reducing congestion by adding capacity to the congested line usually implies that more power is moved over a longer distance, with a consequent increase in losses. Selecting a line-upgrade method to either increase transmission capacity or reduce transmission losses is a complex matter. There are different ways to accomplish the same goal, and there are a number of technical and economic conditions to consider. Engineering judgment is often required in selecting the most appropriate method of upgrading existing lines. A comprehensive treatment of reconductoring technology, along with numerous case studies and application examples, are provided in previous EPRI reports [2, 8, 11, 13]. This section is not intended to replicate the detailed material presented in these reports, but rather to analyze the applicability of reconductoring technology as an option to reduce transmission losses. Some relevant aspects of thermal upgrade of transmission lines are summarized here for completeness. Design Constraints on Structure Loads Existing structures and foundations were designed for certain maximum transverse wind loads and—in the case of strain structures—for maximum tension loads. Unless the existing structures are to be replaced, retensioning the existing conductor, or reconductoring the line with a new 6-13
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
conductor, must be done without greatly exceeding the original design limits on structure loading. If many of the line structures must be replaced, the cost-effectiveness properties of the solution are lost. For tangent structures, the governing transverse loads are primarily a function of the conductor diameter. Therefore, the diameter of the replacement conductor must not exceed 10% of the existing conductor in order to avoid tangent structure modification. For angle and dead-end structures, the governing loads are primarily related to maximum conductor tension. The replacement conductor’s maximum tension should not exceed the original conductor’s tension unless these structures are to be reinforced. Before undertaking any upgrading project, a review of the existing structures and operating records of the line is required. If structural failures at angle or dead-end structures have occurred, any attempt at increasing everyday installed tension is unlikely to succeed. On the other hand, if a review of structure and foundation capacity indicates that the line was conservatively designed, and that it has operated for many years without any structural or foundation failures, it may be possible to replace the existing conductor with a new larger conductor without, or with, minor structure modifications. Reconductoring Options Use of Larger Conductor or Bundling By replacing the existing conductor with one of larger diameter, it is possible to reduce line resistance to a great extent. However, larger conductors significantly increase strain-structure tension loads and increase transverse wind/ice conductor loads on suspension structures. Such large load increases would typically require structure reinforcement or replacement. Bundling the existing conductor with a second conductor of the same diameter reduces line resistance by 50%, allowing a significant reduction in losses. However, as described above, substantial reinforcement of tower structures and footings is required. The high cost of reinforcing structures makes these options less likely to be cost-effective. Besides, the applicability of these techniques is more restricted, because it is not always practical to implement the required structure modifications. Reconductoring Without Significant Structure Modifications: By replacing the original line conductors, it is possible to employ modern conductors having lower resistance for the same diameter. The use of advanced conductors with the same diameter has the primary advantage of minimizing structure modifications. However, the reduction of line resistance is limited to 20–25%. Two different types of conductors can be applied: • ACSR/TW: Conventional ACSR conductors with trapezoidal aluminum strands • HTLS conductors: ACSS, ACSS/TW, ACCR, ACCR/TW, ACCC/TW, and others Table 6–1 compares the characteristics of different conductor types of the same diameter. The reference conductor is an ACSR 795-kcmil Drake.
6-14
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling Table 6-2 Characteristics of Equivalent Different Type Conductors
Consider, for example, an existing line with a 795-kcmil ACSR Drake conductor, operated continuously at 905 A, which is the current capacity for standard weather conditions (ambient temperature 25°C, cross wind at 2ft/sec., full sun). If this original conductor is replaced with a Suwanee ACSR/TW conductor (which has the same diameter) and operated at the same current level of 905 A, line losses will be reduced by 18%. For the same weather conditions, the conductor temperature will be lower, and so will the sag (the conductor will sag less). Hence, there are will not be issues with sag clearances. If, on the other hand, the Suwanee ACSR/TW conductor is operated at a temperature of 75°C, it would have approximately the same sag as the ACSR Drake, but its lower resistance would result in a rating that is on the order of 1000 A (9.5% higher). Hence, if the Suwanee conductor is operated at 1000 A, losses will be approximately the same as with the original Drake conductor operated at 905 A, and therefore the desired loss-reduction will not be achieved. It can be concluded from the values in Table 6–2 that if the objective of reconductoring is merely to reduce losses, the natural choice for a replacement conductor is an ACSR/TW. It allows almost the same amount of loss-reduction (for the same current) as the HTLS counterparts, at a much lower price. In fact, HTLS conductors are intended for upgrading lines that are thermallimited. In such cases, the use of an HTLS conductor having the same diameter as the existing one, and operated at a higher temperature (180°C), increases the line rating by 50% or more, without any significant change in structure loads. Operation of lines at high temperatures is a clear indication that electrical losses are significant during periods of high load and corresponding high conductor temperatures. If the line operates routinely at line currents that approach its thermal limit, the cost of the resulting electrical losses is likely to be significant. Reconductoring with HTLS conductors may result in a cost-effective option in particular cases in which extra capacity is needed to cope with N-1 contingency overloads. In such cases, the lower resistance of the HLTS conductor would result in significant loss savings under normal operating conditions. If a contingency occurs, the HLTS conductor will be operated at a high temperature, and the conductor losses will be high. However, because contingency conditions are occasional and last for a relatively short time, the impact on energy losses will be minor. The reconductoring option in such a case has a dual effect: it reduces losses and improves reliability. Hence, the evaluation of benefits should consider not only the savings from loss-reduction but also the avoided cost of implementing alternative options to handle overloads at N-1 conditions. An illustrative example of this reconductoring case is presented in Example #4 in the next section. 6-15
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
Cost of Upgrading In comparing alternative methods of line upgrading, the designer must consider all of the cost factors and evaluate the likelihood that each upgrading method can meet the power system’s needs and will be able to fulfill all the technical and reliability constraints. Line -upgrading costs are very dependent on the design details of the existing line. For example, if the structures were designed to withstand much larger transverse and/or longitudinal forces than are produced by the existing conductors (with high safety factors), reconductoring can be accomplished without the expense of structure modification. Similarly, if the original design allowed for ground clearances that greatly exceed the minimum requirement, it may be possible to use conductors with higher sags without any physical modification or expense. The major cost factors of a typical line upgrading include at least some of the following [8]: •
Replacement and/or reinforcement of tangent/suspension structures
•
Raising of suspension structures
•
Replacement and/or reinforcement of tension/strain structures
•
Purchase of new conductors
•
Stringing, sagging, and clipping of new or existing conductors
•
Replacement or addition of insulators and hardware.
•
Stocking of additional hardware and material
•
Addition of wind-motion control devices
•
Increased maintenance associated with higher operating temperatures
Some of these factors, such as structure reinforcement and conductor cost, can be quite readily estimated; others, such as increased levels of maintenance, can be difficult to quantify. This difficulty in estimating maintenance is particularly true for those upgrading methods with which the utility has little or no experience. Structures and Foundation Modifications
Modifications of existing structures should be considered as a two-part process. First, consider only the tangent structures, assuming that angle structures will have to be either rebuilt or replaced if the conductor diameter or tension levels are changed. Determine the cost of modifying the tangent structures on the line as a function of the conductor diameter, accounting for changes in code or loading since the line was built. Second, if the upgrading cost for tangent structures appears to be reasonable for the required increase in thermal rating or voltage, then consider the cost of modifying angle structures and dead-ends, and do a detailed clearance study of the line for the most economical conductor diameter. As a rough rule of thumb, if the study of tangent structures shows that necessary structure modifications can be accomplished for less than 50% of the cost of replacing the existing structures with new ones, a more detailed analysis is justified [8].
6-16
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
Conductor-Replacement Costs
The following options for reconductoring to improve TEE have been described: •
Replace the existing conductor with a conductor of larger diameter but of the same type.
•
Replace the existing conductor with a conductor of the same diameter but with lower resistance (TW conductor).
•
Replace the existing conductor with an advanced conductor.
•
Bundle the existing conductor with an additional conductor per phase.
Manufacturers normally issue price lists for their products that can be used for comparison and screening purposes. Unlike the case of ACSR conductors, some advanced conductors are manufactured by only one firm, so the price range is more limited. Table 6–2 provides cost ranges of various conductors relative to those of the ACSR conductor. For trapezoidal wires, the premium for trapezoidal strands over circular strands, assuming the same amount of aluminum, is approximately 5%. The labor cost of reconductoring with a larger conductor is roughly the same as the usual cost of stringing, sagging, and clipping a new conductor. Reconductoring with special conductors may cost somewhat more than using standard conductors, because the use of higher installation tensions and special handling may incur a contractor premium. Bundling of new and old conductors doubles loading on the structure. The cost of installing the second conductor in either a vertical of a horizontal bundle costs only slightly more than installing a new conductor on the same structure. The added cost is due to the possible need to pre-stress the new conductor and the need to work “around” the existing conductor. The following table provides some general estimates of the cost of replacing a conductor with another of the same diameter and similar price. 1 conductor per phase
$ 20,000/mile
2 bundled conductors
$ 30,000/mile
3 bundled conductors
$ 40,000/mile
The old conductor may have significant scrap value if it is all aluminum. In any event, if it can be reused, the cost of this operation would be reduced accordingly. Operation and Maintenance Costs
Upgrading an existing line with larger conductors increases the forces on structure components, and shorter inspection intervals may be needed. Reconductoring with advanced conductors may be very attractive, but the aggressive utilization of new materials and products can add to maintenance and repair activities. One important factor that should be considered is the cost and burden associated with stock managing of additional hardware and material that is different from what is commonly used in the utility. For instance, trapezoidal conductors need a different compression deadend than that used for standard round-wire conductors.
6-17
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
HTLS conductors normally require special hardware, such as connectors, support clamps, and terminations. In addition to the hardware accessories, special attention needs to be given to selecting an appropriate inhibitor for HTLS compression joints. The maximum temperature limit of 250°C for which some manufacturers are rating their HTLS conductors will cause connectors to experience internal temperatures in excess of those that traditional mineral-oil-based inhibitor compounds will tolerate. The mineral-oil base of such inhibitors begins to break down at 162°C. A synthetic base inhibitor has been developed that will perform in the temperature range in which the HTLS operates [3].
Examples of Reconductoring Alternatives In this section, some examples of reconductoring options are developed. These case studies are not intended to exhibit the detailed engineering process of reconductoring technology, but rather to illustrate the applicability of these technological options to improve the energy efficiency of transmission systems. It was stated in Section 4 that the benefits of loss-reduction technological measures are determined by three major components: the monetary value of energy savings, the monetary values of capacity savings, and the monetary values of associated externalities—specifically, the reduction of carbon emissions. In the following examples, these monetary benefits are used to determine some economic metrics that are used to assess the economic performance of different reconductoring options. The case studies are grouped into the following three categories: •
Category #1: Primary Objective: Reduce losses–full investment
•
Category #2: Primary Objective: Increase transmission capacity–marginal investment
•
Category #3: Dual Objective: Reduce losses and improve reliability
The first category represents cases in which the reconductoring is decided upon with the sole objective of reducing losses. In this category, the benefits of loss-reduction must completely offset the total cost of implementing the solution in order to be cost-effective. In the second category, it is assumed that the replacement of the existing conductor has already been decided upon for other purposes than reducing losses (for example, to increase transmission capacity), and that the option for further improving TEE is to select a conductor with less resistance than the conductor proposed in the original project design. Therefore, the cost to be considered in the economic evaluation should be the incremental cost over the original design. The third category represents special cases in which the use of advanced conductors may solve a reliability issue (overloads at N–1 conditions) while providing loss savings during normal operating conditions. Approach The following considerations and hypotheses are followed in the simplified economic analysis of case studies. •
The transmission line under study is evaluated in a stand-alone fashion. That is, losses of the transmission line under study are determined with the line-current magnitude alone, not with a power-flow model of the entire system.
•
The energy losses of the transmission line are evaluated on an annual basis by using loss factor:
6-18
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
Loss Factor - LFS = 0.15 ⋅ LD + 0.85 ⋅ LD 2
Eq. 6–1
Where LD is the line load factor, which is defined as: LD =
average current magnitude [A] maximum current magnitude [A]
Eq. 6–2
•
Some case studies are based on real installations for which information about line operations (line-current or power-flow variation) and physical characteristics are available. For those cases, line load factor is determined based on the available information.
•
Conductor costs are based on manufacturer price lists.
•
Costs of structure reinforcement are roughly estimated in some cases and just assumed in others.
•
It is assumed that the current on the replacement conductor is equal to the current on the existing one. This assumption is valid because in high-voltage (HV) transmission lines, variations of conductor resistance only minimally change transmission-line reactance. Hence, if everything in the system is kept unchanged, the current over the line will not change. In cases of reconductoring with larger conductors, the increased diameter may affect line impedance to some extent. For example, if a conductor of the same type with a diameter of 20% larger is used, line reactance is reduced by 3% and line impedance by 3.2%. A coefficient to account for this variation is considered in these cases.
Case #1: This case corresponds to Category #1. It is based on an actual study intended to increase the capacity of an existing transmission line. In this case, the basic results from the original study are used to evaluate options for reducing line losses. It is a 138-kV, 40-mile-long transmission line passing through mountainous terrain. The existing conductor is a 477-kcmil ACSR Hawk. The basic engineering analysis in the original study indicates that the line can be upgraded with a 795-kcmil ACSR Drake, but substantial changes in structure will be needed to support this larger conductor. Indeed, 70% of the towers will have to be replaced, and the remaining 30% will need minor modifications. The estimated cost of replacing the structures is $150k per tower, whereas the costs for modification range from $15k to $20k. The preliminary study also shows that the transverse load capability of the existing tangent structures is such that the diameter of the replacement conductor can be up to 10% higher than that of the existing conductor with minimal reinforcement of tangent structures. Two conductor-replacement options for loss-reduction are considered in this study: •
Option #1: Reconductoring with a 667-kcmil MYSTIC/TW ACSR trapezoidal conductor
•
Option # 2: Reconductoring with a 795-kcmil ACSR Drake conductor
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Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
Table 6–3 describes the characteristics of these two conductors. Table 6-3 Conductor Data – Case #1 Reconductoring Option Existing Conductor
Option #1
Option #2
Type
ACSR
ACSR/TW
ACSR
Code name
Hawk
MYSTIC/TW
Drake
Parameter
Unit
Aluminum area
[kcmil]
Diameter
[in]
Weight
[lbs/Kft]
AC resistance at 75°C
[ohm/kft]
Ampacity at conditions*
[A]
Resistance reduction w.r.t existing conductor
[%]
477
667
795
0.858
0.913
1.108
656
856
1097
0.0438
0.0139
0.0114
658
798
909
28.3%
40.0%
* Rating conditions: 2ft/sec., ambient air temperature 25°C, sun, conductor temperature 75°C
The ACSR Drake conductor is 67% larger in diameter and 29% heavier than the existing Hawk conductor. It allows the utility to reduce line resistance by 40%, and the line current is the same as in the existing line. On the other hand, the diameter of the ACSR trapezoidal Mystic/TW is only 6% larger, but the reduction in line resistance that can be achieved with this conductor is around 28%. It is 30% heavier than the existing Hawk. Because of the small increment in diameter, this conductor can be installed with minor modifications of structures. Table 6–4 provides an estimate of the investment cost for each option. This value has been estimated based on the results of the preliminary engineering study described above. Table 6–5 describes the economic and emission parameters considered in this example. It also shows the operational parameters of the line (load factor, peak coincident factor).
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Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
Table 6-4 Project Cost – Case #1 Reconductoring Option Existing Conductor
Option #1
Option #2
Type
ACSR
ACSR/TW
ACSR
Code name
Hawk
MYSTIC/TW
Drake
Item
Unit
Conductor cost
[$/ft]
1.9
3.1
Structure cost/upgrades
[$/mile]
20,000
245,000
Stringing cost
[$/mile]
20,000
20,000
Engineering and other costs
[$/mile]
Installation and hardware costs
[$/mile]
3,500
3,500
Scrap value of existing line
[$/ft]
0.5
0.5
Total investment
[K$]
2,627
12,247
Levelized investment cost
[K$/yr]
211.7
987.1
Table 6-5 Operational and Economic Parameters – Case #1 Parameter Load factor
Unit [p.u.]
Peak coincident factor
Value 0.5 0.8
Year of analysis
[yr]
30
Interest rate
[%]
7%
Energy cost
[$/kWh]
Energy cost escalation rate
[%/yr]
Capacity cost
[$/kW-yr]
75
CO2 emissions per kWh
[tn/MWh]
0.9
CO2 value
[$/tn]
20
CO2 value escalation rate
[%/yr]
2.0%
0.80 2.5%
The peak coincident factor considers the coincidence in time of line peak load with respect to system peak load. The year peak load of this line is 80% of its rated capacity at normal conditions: that is, 658 A*0.8 = 526 A. The variation of line power flow is not known in this case, so it is assumed that the line load factor is 0.5. This factor plays a crucial role in the costeffectiveness of reconductoring solutions, as will be demonstrated later in the sensitivity 6-21
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
analysis. It is also assumed that the line peak load increases at an annual load-growth rate of 2%, until the line rate is reached. Table 6–6 presents the analysis results in terms of energy, demand, and emissions savings. As expected, it is observed that the savings are of the same percentage as the reduction in conductor resistance. The economic performance of the proposed solutions is presented in Table 6–7. It can be observed that the total present value 1 of both solutions is less than that of the existing conductor. So in both cases, the monetary value of the total savings due to energy, capacity, and emissions reductions surpasses the investment cost of reconductoring. Nevertheless, economic performance metrics, pay-back period, and IRR show that only Option #1 may be economically sound. Indeed, the IRR is an indicator of the efficiency, quality, or yield of an investment; whereas the present value is an indicator of the value or magnitude of an investment. It is also observed that the monetary value of the CO2 savings of the considered parameter ($20/tnCO2) is marginal in this case. Table 6-6 Annual Energy and Emissions Savings – Case #1. Reconductoring Option Item
Unit
Existing Conductor
Option #1
Option #2
ACSR
ACSR/TW
ACSR
Hawk
MYSTIC/TW
Drake
27,813
19,939
16,701
7874
11,113
Average annual losses
[MWh/yr]
Annual energy-loss savings
[MWh/yr]
Average annual emissions
[tn/yr]
17,945
15,030
Annual emissions savings
[tn/yr]
7087
10,001
Annual energy and emissions savings
[%]
28.3%
40%
Average peak-demand reduction
[MW]
3.05
4.33
1
Note that it is the total present value of all the costs associated with an option: that is, the investment plus the present values of the yearly outflows due to energy, capacity, and emission costs in each option individually. Another way to compare these two mutually exclusive alternatives is to determine the NPV, in which the stream of inflows due to energy, capacity, and emission savings are discounted to yield the present value of the total savings and added to the investment (the investment is negative flow) to determine the NPV. The alternative yielding the higher NPV is the preferred one. However, the NPV evaluated in this case does not allow comparison of Options #1 and #2 with the base case.
6-22
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling Table 6-7 Economic Analysis Results – Case #1 Reconductoring Option Item
Unit
Existing Conductor
Option #1
Option #2
ACSR
ACSR
ACSR
Hawk
MYSTIC/TW
Drake
49,199
37,949
41,987
PV (energy+cap.+CO2+investment)
[K$]
Levelized savings (energy + capacity)
[K$/yr]
952.5
1345.6
Levelized CO2 savings
[K$/yr]
165.7
233.8
Levelized overall savings (energy+cap.+CO2)
[K$/yr]
1118.2
1579.4
Levelized savings per invested dollar
[$/$]
5.28
1.58
Pay-back period
[yr]
4.0
15
Internal rate of return
[%]
31%
11%
Average cost of demand reduction
[$/kW]
69
231
Levelized cost of energy lossreduction
[$/MWh-yr]
26.89
89.83
Levelized investment cost to save 1 tn of C02
[$/tn CO2]
29.87
99.81
Sensitivity Analysis In the economic analysis, it is useful to determine how sensitive the economic performance of the solution (expressed by means of the IRR) is to several parameters of concern, so that proper consideration may be given to them in the decision process. The parameters considered in the sensitivity analysis are: line load factor, energy cost, capacity cost, energy cost escalation rate, and cost of CO2. The base case for the sensitivity analysis is the solution presented in Table 6–7. The values of the considered parameters are varied one per turn around the value they have in the base case. For example, by changing the line load factor +30%, the IRR changes by +43%. The results of this analysis are presented in Figure 6–8. The relative degree of sensitivity of IRR to each component is indicated by the slope of the curves (the steeper the slope of a curve, the more sensitive the IRR is to the component). The results of the sensitivity analysis indicated that the economic performance of the reconductoring solution is most sensitive to line load factor. Indeed, as the load factor increases, so do the energy losses. (Energy losses vary with square load factor.) Another factor that has significant influence is the cost of energy. The influence of the other parameters is less significant.
6-23
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
60% 55% 50% 45% IRR [%]
40% 35% 30% 25% 20% 15% 10% -50%
-30%
-10%
10%
30%
50%
Parameter Variation [%] Load Factor
Energy Cost
Energy Cost Escalation Rate
Capacity Cost
CO2 cost
Figure 6–8 Sensitivity Analysis of Option #1 with Respect to Several Parameters
Case #2: This example also corresponds to Category #1. This case study is based on an actual transmission system of a mid-size utility that serves the northeast region of the United States. The transmission system is comprised of the following voltage levels: 765 kV, 500 kV, 345 kV, and 138 kV. The peak demand is about 5000 MW. The generation capacity is 6000 MW. At peak demand, losses in the transmission system are around 200 MW. Long transmission lines that are most heavily loaded during longer periods of time are good candidates for reconductoring. As described in the previous example, line load factor is the component that impacts economic results the most. Hence, the first selection of candidate lines for reconductoring is based on the identification of long lines with relatively high load factor. The best way to determine the real load factor of a transmission line is by means of hourly resolution time series of line power flows, which can be obtained from either historical data or the results of production-cost–simulation software. In this case, such time series of line power flows are not available. Instead, a set of six power-flow scenarios, or snapshots, are used to determine line load factor and to identify the best candidate lines. The representative scenarios are: summer peak, summer intermediate, summer base, winter peak, winter intermediate, and winter base. As a first screening, the lines with higher losses at peak conditions are identified. Then, line load factor and line energy losses over a one-year period are determined in order to select the best
6-24
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
candidate line for reconductoring. The following two lines have been selected from the first screening process: •
Line A: 345 kV, 45 miles long, 1431-kcmil ACSR Bobolink, 1 conductor per phase
•
Line B: 345 kV, 81 miles long, 1272-kcmil ACSR Bittern, 1 conductor per phase
Figure 6–9 shows the variation in current for these two lines for the six study scenarios; Figure 6–10 shows the variation in line losses for the same power-flow scenarios.
1200
Current [A]
1000 800 600 400 200 0 1
2
3
4
5
6
Scenario Line A
Line B
Figure 6–9 Variation of Current over Two 345-kV Lines of the Study System – Case #2
12
Losses [MW]
10 8 6 4 2 0 1
2
3
4
5
6
Scenario Line A
Line B
Figure 6–10 Variation of Losses for Two 345-kV Lines of the Study System – Case #2
6-25
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
It can be observed that, even though Line A is shorter, it is the one with higher demand and energy losses, as current magnitude on this line is higher in all the scenarios. Assuming typical duration for each of the six analysis periods, the load factor of each line is estimated. The load factor for Line A is about 0.85, whereas for Line B, it is 0.5. Therefore, the best candidate line for reconductoring is Line A. Two conductor-replacement options for loss-reduction are considered: •
Option #1: Reconductoring with a 1758.6-kcmil PEE DEE/TW ACSR trapezoidal conductor
•
Option # 2: Reconductoring with a 2154-kcmil POWDER/TW ACSR trapezoidal conductor
The characteristics of these conductors are presented in Table 6–8. Table 6-8 Conductor Data – Case #2 Reconductoring Option Parameter
Unit
Type Code name
Existing Conductor
Option #1
Option #2
ACSR
ACSR/TW
ACSR/TW
Bobolink
PEE DEE
POWDER
Aluminum area
[kcmil]
1431.0
1758.6
2154
Diameter
[in]
1.427
1.427
1.602
Weight
[lbs/Kft]
1610
1658
2498
AC resistance at 75°C
[ohm/kft]
0.0152
0.0125
0.0104
Ampacity at conditions*
[A]
1300
1416
1601
Resistance reduction w.r.t existing conductor
[%]
17.8%
31.6%
* Rating conditions: 2ft/sec., ambient air temperature 25°C, sun, conductor temperature 75°C
The diameter of the ACSR/TW PEE DEE conductor is the same as the existing conductor, and it is only 3% heavier. The resistance is almost 18% lower than that of the ACSR Bobolink. This conductor can be installed without modifications or reinforcements of structures or footings. On the other hand, the ACSR/TW Powder conductor is 12.3% larger in diameter and 26% heavier than the existing conductor. Hence, replacement with this conductor requires reinforcement of tangent towers. Table 6–9 provides an estimate of the investment cost for each option. The economic and emission parameters considered in this example are the same as those in Case #1 (Table 6–5), except for the load factor, which is 0.85 in this case.
6-26
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling Table 6-9 Project Cost – Case #2 Reconductoring Option Item
Unit
Type Code name
Existing Conductor
Option #1
Option #2
ACSR
ACSR/TW
ACSR/TW
Bobolink
PEE DEE
POWDER
4.62
5.25
Conductor cost
[$/ft]
Structure cost/upgrades
[$/mile]
0
220,000
Stringing cost
[$/mile]
20,000
20,000
Engineering and other costs
[$/mile]
Installation and hardware costs
[$/mile]
3500
3500
Scrap value of existing line
[$/ft]
0.5
0.5
Total investment
[K$]
3550
12,750
Levelized investment cost
[K$/yr]
286.1
1027.4
Table 6–10 presents energy, demand, and emissions savings for the two reconductoring options considered in this example. The economic performance of the proposed solutions is presented in Table 6–11. It can be observed that the total present value of both solutions is less than that of the existing conductor, so in both cases the monetary value of the total savings due to energy, capacity, and emissions reductions surpasses the investment cost of reconductoring. Option #2 has the minimum total present value (PV), so it can be considered as the most-efficient one in terms of total savings. Note, however, that the economic performance of Option #1 is superior, as can be inferred from the economic metrics, IRR and pay-back period. As in Case #1, the monetary value of CO2 savings for the considered emission parameter ($20/tnCO2) is of much less significance than the savings from energy losses.
6-27
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
Table 6-10 Annual Energy and Emissions Savings – Case #2 Reconductoring Option Item
Unit
Existing Conductor
Option #1
Option #2
ACSR
ACSR/TW
ACSR/TW
Bobolink
PEE DEE
POWDER
95,436
78,484
65,299
16,953
30,138
70,635
58,769
15,257
27,124
Average annual losses
[MWh/yr]
Annual energy-loss savings
[MWh/yr]
Average annual emissions
[tn/yr]
Annual emissions savings
[tn/yr]
Annual energy and emissions savings
[%]
18%
32%
Average peak-demand reduction
[MW]
2.59
4.34
85,893
Table 6-11 Economic Analysis Results – Case #2 Reconductoring Option Item
Unit
Existing Conductor
Option #1
Option #2
ACSR
ACSR/TW
ACSR/TW
Bobolink
PEE DEE
POWDER
151,519
128,166
116,627
PV (energy+cap.+CO2+investment)
[K$]
Levelized savings (energy + capacity)
[K$/yr]
1814.3
3210.4
Levelized CO2 savings
[K$/yr]
353.8
628.9
Levelized overall savings (energy+cap.+CO2)
[K$/yr]
2168.1
3839.3
Levelized savings per invested dollar
[$/$]
7.58
3.73
Pay-back period
[yr]
3
6
Internal rate of return
[%]
41%
23%
Average cost of demand reduction
[$/kW]
110
222
Levelized cost of energy lossreduction
[$/MWh-yr]
16.88
34.09
Levelized investment cost to save 1 tn of C02
[$/tn CO2] 18.75
37.88
6-28
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
It is important to note that, although the reconductoring options considered in this study case are economically sound (especially Option #1), the impact on total system losses is small. Indeed, total system losses at maximum peak load conditions (summer peak) sum up to 203 MW. Line A losses for that scenario are 9.5 MW. Option #1 reduces Line A losses at peak conditions by about 2 MW, which is 1% of total demand losses. Annual energy for the entire system is 1121.6 GWh, representing 4.6% of the total energy served. The energy loss-reduction achieved with Option #1 is 16.95 GWh, which is about 1.5% of the annual system losses. Therefore, in order to get a more-significant reduction in system total losses, a number of lines must be reconductored. Case #3: This example is of Category #3. It is based on a real reconductoring project of a utility in the Northeast region. A 230-kV, 40-mile-long transmission line is to be reconductored in order to increase transmission capacity to alleviate transmission bottlenecks and improve system reliability. The existing conductor is an ACSR 795-kcmil Drake. The original reconductoring project proposes to replace the Drake conductor with a larger ACSR conductor: a 1590-kcmil Lapwing. The existing line is very old, so in order to install the larger conductor, the utility is planning to tear down most of the existing towers and completely rebuild the line segment. The cost of rebuilding the line is around $1.5 million/mile. The objective in this example is to analyze the option of using a more energy-efficient conductor in the new line, instead of the conductor considered in the original design. Two options are considered in this case. The first option is to use a trapezoidal conductor of the same diameter as the ACSR Lapwing, so that modifications in tower design are avoided. The second options is to use a moderately larger TW conductor that allows for further reduction in losses with moderate changes in tower designs. The options analyzed in this case are: •
Option #1: A 1946.6-kcmil ATHABASKA/TW ACSR trapezoidal conductor
•
Option # 2: A 2154-kcmil POWDER/TW ACSR trapezoidal conductor
In new lines, more advanced conductors like ACCC/TW and ACSS can yield designs with shorter and fewer structures due to higher strength and lower sag variation. In this case however, we assume that the location and characteristics of the existing tower cannot be modified. The characteristics of these conductors are presented in Table 6–12.
6-29
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling Table 6-12 Conductor Data – Case #3 Reconductoring Option Parameter
Unit
Type Code name
Existing Conductor
Option #1
Option #2
ACSR
ACSR/TW
ACSR/TW
Lapwing
Athabaska
POWDER
Aluminum area
[kcmil]
1590
1949.6
2154
Diameter
[in]
1.504
1.504
1.602
Weight
[lbs/Kft]
1790
1838
2498
AC resistance at 75°C
[ohm/kft]
0.073
0.060
0.0550
Ampacity at conditions*
[A]
1358
1502
1601
Resistance reduction w.r.t existing conductor
[%]
18.0%
31.6%
* Rating conditions: 2ft/sec., ambient air temperature 25°C, sun, conductor temperature 75°C
The diameter of the ACSR/TW ATHABASKA conductor is the same as the proposed conductor, and it is only 3% heavier. The resistance is almost 18% lower than that of the ACSR Lapwing. This conductor can be installed without modifications of the original tower designs. On the other hand, the ACSR/TW Powder conductor is 6.5% larger in diameter and 40% heavier than the existing conductor. The increment in conductor diameter with respect to the Lapwing is small, so it is possible that the towers designed for the Lapwing conductor will be able to bear the increased ice and wind transverse loads. However, strain structures may require some modifications because of the increased weight. Table 6–13 provides an estimate of the investment cost for each option. The conductor cost in each case is the difference in cost with respect to the Lapwing conductor. The stringing cost and scrap value of the existing conductor are not considered in this analysis because they are taken into account in the original reconductoring project. Hence, only the incremental cost of selecting the TW conductor instead of the Lapwing conductor is considered.
6-30
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling Table 6-13 Project Cost – Case #3 Reconductoring Option Item
Unit
Existing Conductor
Type Code name Conductor cost
[$/ft]
Structure cost/upgrades
[$/mile]
Stringing cost
[$/mile]
Engineering and other costs
[$/mile]
Installation and hardware costs
[$/mile]
Scrap value of existing line
[$/ft]
Total investment Levelized investment cost
Option #1
Option #2
ACSR
ACSR/TW
ACSR/TW
Lapwing
Athabaska
POWDER
1.5
1.9 30,000
3500
3500
[K$]
1704
2520
[K$/yr]
86.5
203.1
An hourly resolution time series of historical line loading is available for this case. Figure 6–11 shows the line-loading duration curve in terms of current magnitude. It is observed in this graph that this line is heavily loaded for only a few hours. Indeed, the line-loading factor determined from this time series is very low: 0.26.
1000 900 800
Current [A]
700 600 500 400 300 200 100 0 0
1000
2000
3000
4000
5000
6000
7000
8000
Hours
Figure 6–11 Line-Loading Duration Curve – Case #3
6-31
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
The economic and emission parameters considered in this example are the same as those in Case #1 (Table 6–5), except for the load factor, which is 0.26 in this case. It is assumed that the maximum current for the new conductor will initially be 80% of the Lapwing conductor rating: that is, the rate current of the conductor considered in the original reconductoring design. Table 6–14 presents energy, demand, and emissions savings for the two reconductoring options considered in this example. The economic performance of the proposed solutions is presented in Table 6–15. It can be observed that the total present value of both solutions is less than the total present value of losses that would be obtained with the Lapwing conductor. Thus, the monetary value of the total savings due to energy, capacity, and emissions may justify the replacement of the existing conductor with a trapezoidal conductor instead of the conventional ACSR Lapwing. Option #2 has the minimum total PV, so it can be considered as the most efficient one in terms of total savings. Note, however, that the economic performance of Option #1 is superior, as can be inferred from the economic metrics, IRR and pay-back period. One would expect in this case a value of IRR much higher than in the previous cases, because the investment is relatively very small; however, the load factor of this line is very small, and consequently, so are the energy and emissions savings. As in the previous examples, the monetary value of CO2 savings for the considered emissions parameter ($20/tnCO2) is of much less significance than the savings from energy losses. Table 6-14 Annual Energy and Emissions Savings – Case #3 Reconductoring Option Item
Unit
Existing Conductor
Option #1
Option #2
ACSR
ACSR/TW
ACSR/TW
Lapwing
Athabaska
POWDER
12,614
10,345
9438
2269
3176
9311
8494
Average annual losses
[MWh/yr]
Annual energy-loss savings
[MWh/yr]
Average annual emissions
[tn/yr]
Annual emissions savings
[tn/yr]
2042
2859
Annual energy and emissions savings
[%]
18%
25%
Average peak-demand reduction
[MW]
2.66
3.73
6-32
11,352
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling Table 6-15 Economic Analysis Results – Case #3 Reconductoring Option Item
Unit
Existing Conductor
Option #1
Option #2
ACSR
ACSR/TW
ACSR/TW
Lapwing
Athabaska
POWDER
29,190
22,882
19,339
PV (energy+cap.+CO2+investment)
[K$]
Levelized savings (energy + capacity)
[K$/yr]
374.1
524.0
Levelized CO2 savings
[K$/yr]
47.7
66.8
Levelized overall savings (energy+cap.+CO2)
[K$/yr]
421.9
590.8
Levelized savings per invested dollar
[$/$]
4.87
2.91
Pay-back period
[yr]
4
7
Internal rate of return
[%]
30%
19%
Average cost of demand reduction
[$/kW]
33
54
38.15
63.94
42.39
71.05
Levelized cost of energy lossreduction Levelized investment cost to save 1 tn of C02
[$/MWhyr]
[$/tn CO2]
Case #4: This case corresponds to Category #3. Consider a single-circuit, 230-kV transmission line with a one-bundle 795-kcmil ACSR Drake conductor per phase. Assume that according to the utility reliability criteria and procedures, the emergency rating of the conductor is a thermal capacity at 100°C and normal weather conditions: that is, 1115 A (444 MVA). The system analysis indicates that this line needs to carry up to 700 MVA as a result of certain contingencies. Although the contingency is not likely to occur often (once in a few years), if it does occur, it is likely to persist for several days. The line needs to be thermal-updated in order to cope with this situation. The inspection and preliminary engineering analysis indicate that there are some restrictions for reconductoring: the maximum loading over the structure should not exceed that produced by the original conductor by more than 20%, and the replacement conductor will need to sag at the maximum required capacity (700 MVA) no more than the existing conductor does at 100°C. Nevertheless, the maximum tension cannot exceed that of the existing ACSR Drake conductor by more than 20%. One possible solution is to use an HTLS conductor. For example, a 1020-kcmil ACCC/TW Drake conductor would yield a rating of 704 MVA at a conductor temperature of 180°C, as a 6-33
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
result of its greater aluminum cross-section and its ability to operate at 200°C for an extended period of time. The low-sag characteristics of this conductor allow it to comply with sagclearance restrictions, as can be concluded from Table 6–16. Certainly, the sag of the original ACSR Drake at 100°C is 30.7 ft (9.3 m), whereas the sag of the ACCC/TW Drake at 180°C is 27.5 ft (8.4 m). The maximum tension is about 20% greater. The diameter of this conductor is the same as that of the existing ACSR Drake, so the constraints about maximum wind and ice load are also met. The resistance is 22.6% less than that of the ACSR Drake, so if the line is loaded at normal conditions in the same way as with the existing conductor, a reduction of 22.6% in line losses will be achieved. During the emergency conditions that the upgrading solution is designed for, the losses on the conductor will be high. However, because the occurrence of these conditions is of low probability, the effects of these short periods of high losses on the performance of the energy-efficiency solution can be neglected. Another possible option is the ACCR Suwanee conductor. The capacity of this conductor at 180°C is 692 MVA, so it would operate at a bit higher temperature to carry the required 700 MVA. However, it would comply with the sag and tension restrictions. Table 6–16 Sag-Tension Table for Four Different Conductor Types of the Same Diameter (Courtesy of CTC Cable Corporation).
Note that in this case the economic evaluation must consider the benefit of improving reliability, because this is a dual-effect solution. These benefits are the avoided cost of procuring other means of coping with overloads caused by contingency conditions. 6-34
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
One possible way to isolate the costs associated only with loss-reduction would be to determine the cost of a reconductoring option that would yield a similar reduction in losses but not be able to withstand the emergency conditions. For example, a Suwanee ACSR/TW conductor allows a similar reduction in losses, but it cannot handle higher current values as do the ACCC/TW Drake or ACCR Suwanee. The cost of the Suwanee is $2.8/ft, whereas the cost of the ACCC/TW Drake is $7.14/ft.
Nondisruptive Reconductoring There is a large cost to removing critical circuits from operation long enough to reconductor. A mechanism has been devised to replace conductors, one phase at a time, while sustaining service on the circuit being reconductored [5]. One such method can be summarized as follows: a. Over the section of line to be restrung, conductor clamps are replaced by conventional stringing travelers. This can be done live. b. Over that section, a temporary structure is built alongside each tower, from which a fourth phase conductor is strung. c. One phase of the transmission line is diverted to the temporary fourth conductor, and the phase conductor remaining in place is subsequently isolated for restringing. d. The de-energized fourth conductor is then used to pull in a new conductor over the travelers installed on that phase condition. e. Power is restored to the newly strung phase, and the temporary phase is disconnected and de-energized. f. The above process is repeated for the remaining two phases. g. When completed, the temporary structure and the fourth phase conductor are removed, and the travelers are again replaced by clamps. This process must be undertaken carefully, because there will be substantial coupled currents and voltages during restringing due to close proximity to energized, current-carrying conductors. Other methods for nondisruptive reconductoring are described in [6].
Summary Power loss in ac transmission lines is a huge concern for the owners and operators of transmission systems. The transmission of power through the line causes loss of electrical power in the form of heat because of the impedance of the conductor. In a large network, these losses can be significant. Electrical-power losses increase with the length of the transmission line and the square of the current. Losses can be reduced by decreasing the distance the power travels, decreasing the current, or decreasing the impedance of the line itself. The most viable option for reducing losses is to reduce the impedance. This can be accomplished by replacing the existing conductor with a larger-diameter conductor of the same type but with a lower resistance. It can also be accomplished by the application of one of the new HTLS advanced conductors or ACSR trapezoidal-wire conductors. These conductors have a reduced resistance characteristic, which lowers the transmission line’s losses. HTLS conductors also have lower thermal elongation properties, which also allow increased power flow. Advanced technologies can also be applied to 6-35
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
the transmission line in the form of sensors and monitors [10, 11]. Another option is bundling the existing conductor with additional conductors per phase. Bundling reduces the line’s impedance, which lowers the line’s losses. It also increases the thermal capacity of the transmission line, which raises the line’s power-transmission capability. The disadvantage of bundling is the added weight and loadings to the transmission line’s structures, which could require the reinforcement of those structures. It is only desirable if the reinforcement is economical. Traditionally, the main emphasis of line thermal upgrades by reconductoring is to increase the capacity, with loss-reduction having a lower priority. However, from the point of view of transmission energy-efficiency improvement, reconductoring options can be considered with the main objective of reducing losses. Simplified economic analyses show that in some cases such implementation is cost-effective and economically sound. Of course, when losses are reduced, there is always the temptation to increase the transfer loading, taking advantage of the increased capacity achieved—with the result that losses may also increase rather than decrease. There is a conflict between reducing losses and increasing transfer capability. Therefore, proper definition of objectives, identification of baseline or reference conditions, and evaluation of benefits is crucial to determining the cost-effectiveness of reconductoring options for transmission lossreduction. Three types of projects have been identified in this section to help analyze reconductoring options for loss-reductions: The first project category comprises projects that are evaluated with the sole objective of reducing losses. It is more difficult to analyze the cost-effectiveness of these types of projects, because the economic benefits from loss savings must fully offset the investment cost. The second project category corresponds to reconductoring projects that have been decided upon for purposes other than loss-reduction, but for which a more energy-efficient conductor can be selected to further reduce losses. In these cases, the benefits from lossreduction need only to compensate for the incremental cost in order for the solution to be costeffective. The third project category applies to very specific cases in which additional capacity is required to handle infrequent overload conditions—caused, for example, by N–1 contingencies. An HTLS conductor of the same diameter as that of the existing conductor can be used in such cases, because it is able to operate at a higher conductor temperature, carrying much higher currents. Under normal operating conditions, the HTLS conductor is operated at the same current as the existing conductor, whereas its lower resistance allows it to reduce losses.
References [1]
Transmission Line Reference Book : 115–345 kV Compact Line Design. EPRI, Palo Alto, CA: 2008. 1016823.
[2]
Feasibility of Increasing Transmission Line Capacity by Voltage Upgrade. EPRI, Palo Alto, CA: 2007. 1013984.
[3]
AC Transmission Line Reference Book – 200 kV and Above, Third Edition. EPRI, Palo Alto, CA: 2005. 1011974.
[4]
Demonstration of Advanced Conductors for Overhead Transmission Lines. EPRI, Palo Alto, CA: 2008. 1017448.
[5]
Improved Method for Live Line Reconductoring. EPRI, Palo Alto, CA: Opportunity Brochure. 1015488.
6-36
Lowering Transmission Losses by Application of Advanced or Lower-Loss Conductors and by Bundling
[6]
P. Reichmeider, D. O’Connell, S. Jacobson, D. Devine, and L. Barthold, Experience with New Methods for Live-Line Conductor Replacement. CIGRE B2-106, 2006.
[7]
Sagging Line Mitigator (SLiM) Full Scale Demonstration. EPRI, Palo Alto, CA: 2005. 1011530.
[8]
Increased Power-Flow Guidebook. EPRI, Palo Alto, CA: 2005. 1010627.
[9]
Video Sagometer Application Guide. EPRI, Palo Alto, CA: 2001. TR-100191.
[10]
Instrumentation for Increasing Power Flow: Needs, Concepts, Feasibility, and Benefits. EPRI, Palo Alto, CA: 2006. 1012534.
[11]
Increasing Power Flow Through Transmission Circuits: Overhead Line Case Studies and Quasi-Dynamic Rating. EPRI, Palo Alto, CA: 2006. 1012533.
[12]
D. Douglass, “Sag-tension Calculations Tutorial.” Paper presented to the IEEE TP&C Line Design Subcommittee (June 13, 2005).
[13]
Transmission Line Uprating Guide. EPRI, Palo Alto, CA: 2000. 1000717.
[14]
ALCAN, Aluminum Conductor Steel Reinforced Trapezoidal Wire (ACSR/TW) Catalog.
6-37
7
LOWERING TRANSMISSION-GRID LOSSES BY DIVERTING POWER TO HIGHER-VOLTAGE LINES This section discusses ways to improve the energy efficiency of transmission systems by diverting power flows to higher-voltage lines with lower impedance and higher transfer capacity. The same concepts can also be used to divert power to lower-loss paths of the same voltage.
This section covers issues such as: •
Some of the constraints that need to be satisfied before embarking on such projects as: generation limits, reactive power supports available, busbar voltage operating ranges, and line-transfer limits
•
Measures and new components needed to divert the power flows to lower-loss lines: –
Switching out of service the higher-loss lines or equipment to force the power flows to lower-loss paths (and the possible reliability impacts of such measures)
–
Changing the settings of transmission controllers and generator voltages and other operational steps (including daily and seasonal considerations), such as the possible use of optimal load-flow and state-estimator tools
–
Use of conventional and common measures and equipment, such as: o Phase-angle regulators (phase-shift transformers) to change the angle between transmission points o Series compensation of the lower-loss transmission lines to reduce the series reactance of the desired path
–
Application of less-frequently used measures and equipment, such as: o Series FACTS controllers o Conversion of ac line to dc, albeit considering the break-even distance (which includes the cost of the ac/dc converters and their associated losses)
•
Other possible benefits that can be obtained from these approaches, such as reduction of loop flows, better alignment with contract paths, and improved transient or voltage stability when diverting the power to higher-voltage lines.
7-1
Lowering Transmission-Grid Losses by Diverting Power to Higher-Voltage Lines
Introduction When power flows along a transmission line at a higher voltage, the current magnitude reduces at an inverse proportion to the increased level of voltage for the same power level. This was explained in Section 3 under the subsection entitled “Voltage-Upgrade Concepts,” in which line losses are dependent on the square of the current. In other words, if power is diverted from a lower-voltage line to a higher-voltage line, three loss-reduction benefits may be realized. For a given power-flow level: •
A larger current is removed from the low-voltage line, reducing losses on that line.
•
A smaller amount of current is superimposed on the high-voltage line, adding losses on that line. However, because the added current is smaller, the extra losses should be less than they were on the lower-voltage line, resulting in a net reduction of losses for the same power flow.
•
The resistance of higher-voltage lines is generally less than that of lower-voltage lines, which also contributes to an overall lower loss benefit if power can be so diverted.
In an ac electric grid, power flow is determined by transmission line and transformer impedance between the sources of generation and the loads. Higher-voltage transmission lines have lower apparent impedance than lower-voltage transmission lines, so it is usual that more power flows on the higher-voltage lines. This natural flow pattern based on impedance does not necessarily correspond to a minimum-loss condition on the transmission grid. In order to operate closer to a minimum-loss condition, there must be a way to control the power flow through the network.
General Issues Redirecting power flow through an ac transmission network to achieve a minimum -loss condition requires that extra facilities be added to the network to force power into low-loss paths that are obstructed by higher relative impedance. These extra facilities are significant pieces of equipment, which have a cost component. The justification for adding them to the transmission network would usually be dependent upon benefits other than loss-reduction, and it might include one or more of the following reasons: •
Increase in power-transfer capacity
•
Reduction of loop flows
•
Confinement of power flow to a specific contract path
•
Improved transient or voltage stability
In order to determine which power to divert to low-loss paths in a transmission network, an optimal power flow is applied—with minimization of transmission losses as the primary objective. At the same time, there are some constraints—such as generation limits, available reactive power support, busbar voltage operating ranges, and line-transfer limits—that need to be satisfied. Generation can be changed, and so can any transmission controller (such as a phaseangle regulator that can divert power flow to another path). In principle, a lossy transmission line could be switched out of service to force the power that was flowing on it into lower-loss paths. A simple power-flow assessment would determine if a system-loss benefit could actually be achieved by switching out a lossy line, but generally lower 7-2
Lowering Transmission-Grid Losses by Diverting Power to Higher-Voltage Lines
losses would not generally be achieved by such a drastic measure. A disadvantage of doing this is the lowering of transmission reliability as a consequence of removing a line from service. An advantage is to use the transmission line as a capacitor bank to support voltage at one of its terminating busbars by disconnecting it at the other end. In this way, the higher busbar voltage so generated will contribute to reducing system losses. Determining the settings to apply to transmission controllers, generators, and switches to achieve minimum-loss operation can be done repetitively as the power system progresses through the daily load cycle. Use of an optimal load flow that minimizes losses and is combined with a state estimator would provide the application of on-going settings changes. This situation would be a burden to operators if they were required to adjust settings manually throughout each day as load and generation changed. The options would be to •
Automate the process, so that the settings and switch conditions for minimum transmissionsystem losses would be repetitively adjusted without requiring the close involvement of the operator.
•
Fix the settings for a seasonal full-load condition. The highest losses occur at the highest loads, so fixed settings would be a compromising way to operate. However, if transmission controllers are also required to facilitate specific operating schedules, such as ones needed to minimize widely fluctuating loop flows, then fixed settings could not be used.
A process for the on-line determination of minimum system loss, using transmission controllers to divert power to lower-loss paths, has been developed from proposals by EPRI’s Green Transmission Group, as shown in Figure 7–1 [1]. The central optimization could include the optimal power flow for loss optimization that is based on the current system’s condition delivered from the state estimator. However, as the process in Figure 7–1 implies, the central optimization can also include voltage control and reactive power management, as well as network settings and switching for system-loss operation.
Figure 7–1 A Modified Hierarchical Control Structure for Network Loss-Minimization and Coordinated Regulation of Transmission Network Voltages with Optimal Power Flow (PF)
7-3
Lowering Transmission-Grid Losses by Diverting Power to Higher-Voltage Lines
Means for Diverting Power Flow
Figure 7–2 345-kV Series Capacitors
Diverting power to lower-loss transmission paths in the transmission network requires a means to do it. These might include: •
Reducing the series inductive reactance in the lower-loss path. If this path is a higher-voltage path, the apparent series reactance is naturally reduced. However, the series reactance of the transformers to the higher voltage will add to the line reactance, hence counteracting the benefit the higher voltage provides. If power can still be diverted or forced onto the highervoltage line, a benefit from lower losses may still be realized.
•
Increasing the phase angle of the ac voltage across the ends of the higher-voltage transmission line. This adjustment will force power down that line, so that the benefit of its lower losses will still be gained.
•
With the ac transmission line, for which lower losses are possible, converting to HVDC transmission. Lower line losses are inherently realized when operating as HVDC transmission using the same conductors. This benefit quickly disappears if the line is too short, so that converter station losses at each end dominate the losses.
The possible equipment and strategies that can be applied for diverting power are discussed under the assumption that such facilities are costly and that they are in-service on the transmission network for other reasons than for loss-reduction. However, if they are available, then there is opportunity to use them for transmission-line loss-reduction. Phase-Angle Regulators Phase-angle regulators—or phase-shift transformers, as they are alternatively called—are relatively common in electric networks. They increase or reduce the voltage phase angle applied across a transmission line in which it has been located. They usually have on-line tap changing to adjust the phase angle, and thereby regulate the power flow through the line it is controlling. The ° amount of on-line phase-angle adjustment is limited. An on-line range of ±30 is considered maximum. Any greater range requires a series connection of phase-angle regulators or off-line switching in 60° steps. If the off-line switching is applied when a 30° limit is reached, the transmission line has to be opened so that power flow through it is reduced to zero. The off-line ° 60 switching is applied, and then the phase-angle tap changer is run back to a position in which 7-4
Lowering Transmission-Grid Losses by Diverting Power to Higher-Voltage Lines
power flow through the transmission line is at a desired level when it is switched back in. Then the on-line phase-angle taps are run to the setting in which the required power flow through the line is reached. This is clearly not a convenient way to operate a power-system network, but it is how the phase-angle regulators of Manitoba Hydro are managed in order to control loop flow around the Great Lakes. Phase-angle regulators may also have a voltage-magnitude transformer to compensate for the voltage reduction that a phase-angle shift requires. Series Compensation Series compensation of high-voltage transmission lines is a common practice on relatively long lines. A series capacitor has a negative reactance that can subtract from the positive inductive reactance of a transmission line, thereby reducing the series reactance of this path. Having series capacitors located on a high-voltage transmission line means that the greater power flow that can be attracted to the line may provide the advantage of potentially lower losses. Series capacitors may have limited control. Some series-capacitor banks are configured as one single module, and they are either in service or out of service—resulting in a two-step condition. Other series-capacitor banks on a transmission line may be composed of several modules that can be switched in and out in a greater number of steps. If there are two switchable modules on a transmission line, there are three possible steps, resulting in three levels of reactance and three levels of power flow for that particular transmission line. It is not usual to switch series-capacitor modules for system loss-minimization. A significant challenge of applying series compensation on a transmission line is the risk of negative damping to shaft torsional modes of oscillation on thermal generators. Care needs to be taken in the system design with series capacitors so that subsynchronous resonance is not generated in any torsional mode of oscillation on a nearby thermal generator shaft for any combination of modules in service. FACTS Controllers For nearly two decades, the concept of FACTS controllers has drawn a significant amount of interest under EPRI’s leadership. FACTS controllers include both series controllers to control power and reactive power flow, and shunt controllers to control ac voltage (and combinations of both) [2]. It is the FACTS controller with series controllers that can significantly divert power flow, but unfortunately, there have not been very many installations of these controllers to date on electric transmission networks. It is believed that their relatively high cost is a major factor in limiting the number of installations. However, their potential still applies, and a few units are in service. So, for completeness, the FACTS controllers that can be used for diverting power flow are briefly summarized here.
7-5
Lowering Transmission-Grid Losses by Diverting Power to Higher-Voltage Lines
Thyristor-Controlled Series Capacitor (TCSC)
Figure 7–3 345-kV Thyristor-Controlled Series Capacitors (Courtesy of WAPA)
A thyristor-controlled series capacitor (TCSC) is a capacitor in series with the transmission line. A thyristor-controlled reactor (TCR) is in parallel with the series capacitor, and both are protected against transient and temporary overvoltages by a metal-oxide varistor, also in parallel with the capacitor (See Figure 7–4). Variable capacitive and inductive reactance is achieved with controlled operation of the TCR. A TCSC module is usually connected in series with a conventional series capacitor. Only a few TCSCs are in service (in the United States and Brazil). Their main purpose is to provide damping of electromechanical modes of oscillation [3].
Figure 7–4 Single-Line Diagram Depiction of a TCSC Module
7-6
Lowering Transmission-Grid Losses by Diverting Power to Higher-Voltage Lines
Static Synchronous Series Compensator (SSSC) A static synchronous series compensator is a voltage-sourced converter connected in series with the transmission line through a coupling transformer, as shown in Figure 7–5. The dc side of the voltage-sourced converter is connected to a capacitor that provides the voltage source. It can only inject a series ac voltage in the transmission line that is in quadrature with the line current, but which can be controlled independently to the line current. This allows a larger variation of the apparent series line reactance than is achieved with a series capacitor. It is not prone to causing subsynchronous resonance [4].
Figure 7–5 Single-Line Diagram Depiction of an SSSC
7-7
Lowering Transmission-Grid Losses by Diverting Power to Higher-Voltage Lines
Unified Power-flow Controller (UPFC)
Figure 7–6 Inez Unified Power-Flow Controller (Courtesy of AEP)
The unified power-flow controller (UPFC) injects a series voltage into the transmission line through a coupling transformer like the SSSC. But it couples a second voltage-source converter (VSC) to the dc-side capacitor, as shown in Figure 7–7. Consequently, real power—as well as reactive power—can be injected in series into the transmission line through the coupling transformer. In this way, it can act to change the apparent series impedance of the transmission line it is inserted into, as well as generate a voltage phase-angle shift with voltage control. It is an ideal controller for diverting power into or out of an ac transmission line. A 160-MVA UPFC is located at American Electric Power (AEP)’s Inez substation in Kentucky [5].
Figure 7–7 Single-Line Diagram Depiction of a UPFC
7-8
Lowering Transmission-Grid Losses by Diverting Power to Higher-Voltage Lines
Interphase Power Controller (IPC) The interphase power controller (IPC) is a conceptual design in several forms. One configuration is designated an assisted phase-shifting transformer (APST). This is a high reactance that is connected across a conventional phase-angle regulator, or phase-shift transformer. The phaseangle regulator remains a conventional configuration, and its controllability is maintained. To boost power flow through the transmission line, a capacitor is switched in parallel with the phase-angle regulator, as shown in Figure 7–8. To buck the power flow, a reactor is switched in. The parallel reactance shares a portion of the power flow with the phase-angle regulator, thereby increasing the overall power-flow capacity through the transmission line. An IPC of this configuration has been installed at the Plattsburgh substation in Vermont [6].
Figure 7–8 Single-Line Diagram Depiction of an IPC Configured as an APST with a Capacitor for Boosting Power Flow
Back-to-Back HVDC Converter
Figure 7–9 Rapid City 200-MW Back-to-Back HVDC Converter Station
The ultimate power-flow controller is a back-to-back HVDC converter. If the converters are voltage sourced, then they can independently control ac voltage on each side of the installation. If necessary, the power flow through the back-to-back converters can be controlled as a function of voltage phase angle on each side to contribute synchronizing power. The back-to-back HVDC converter has unlimited phase-angle regulation. If inserted at or near the center of impedance in an ac transmission line, and if rated large enough, the overall power-transfer capacity can be increased to a theoretical maximum of double, providing that a thermal limit is not encroached upon.
7-9
Lowering Transmission-Grid Losses by Diverting Power to Higher-Voltage Lines
HVDC Transmission There are a number of HVDC transmission systems installed in ac transmission networks. The Pacific HVDC Intertie, which is in parallel to the 500-kV ac series-compensated Pacific HVAC Intertie, is a prime candidate for loss-minimization. There is also the Intermountain Project, which could participate in what might extend to a Western Electricity Coordination Council (WECC) loss-minimization program. AC Transmission Line Converted to DC For a given power flow through an ac transmission line, the line losses are reduced if converted to HVDC. There are a number of different configurations that can be applied for a single-circuit conversion [7]. These include: •
Option A: Bipolar, with the third phase conductor used as a metallic return to avoid use of ground return.
•
Option B: Bipolar, with the third phase switched to be in parallel with one of the active phase conductors to lower line losses. With suitable controls and switches, this third phase conductor can be switched in as a metallic return if one of the other phase conductors is removed from service. This mode of operation will reduce losses by 25% and will again achieve redundancy on loss of either a bridge or line conductor.
•
Option C: Tripolar, in which all three phase conductors are active, resulting in lower line losses than those achieved with a bipolar configuration.
No commercial conversions of an ac line to dc have been implemented to date. The loss-saving potential following an ac to dc conversion can be visualized from the following example in [8]: Consider a single-circuit 230-k V line using a 1272-kcmil conductor. The circuit is converted to a bipolar configuration, with one conductor carrying full current, and the other two sharing the return current (Option B). DC voltage is 20% above the 230-kV line-to-ground crest voltage. Hence, dc voltage is 225 kV. For the same amount of transferred power, the current over the conductors will be less than in ac operation mode. Because in this configuration, current would flow down one conductor and return in parallel on the other two, the net resistance would be 1.5 times the resistance of one conductor. Losses at the converters are estimated at 0.85% of the transmitted power per terminal. Table 7–1 presents the amount of losses for each option, for a transfer level of 360 MW. Figure 7–10 compares loss in the transmission line for different power-transfer levels. It can be observed from these results that if the dc alternative is to supply the same maximum power as the ac circuit, with the same load-duration curve, a net reduction in losses is achieved. It should be noted, however, that terminal losses are not dependent upon transmission-line length, but only on the transferred power. Hence, for short transmission-line terminal losses, offset loss-reduction is gained in the dc circuit. Figure 7–11 shows the variation of losses as a function of the transmission line for the same level of transfer power (360 MW). It can be observed from this figure that conversion of ac to dc for reducing losses can be effective on relatively long transmission lines.
7-10
Lowering Transmission-Grid Losses by Diverting Power to Higher-Voltage Lines Table 7-1 AC to CD Conversion Example Voltage Current Resistance Power Power factor Real Power Loss/mile
AC - Circuit [kV] [A] [ohm/mile] [MVA] [MW] [kW/mile]
230 1005 0.08 400 0.9 360 242.5
DC - Circuit DC Voltage Real Power Current Loss/mile Terminal losses
[MW] [A] [kW/mile] [kW]
225 360 800 76.8 6,120
Line Losses - [kW/mile]
350 300 250 200 150 100 50 0 0
50
100
150
200
250
300
350
400
450
Power Transfer [MW] AC losses
DC losses
Figure 7–10 Line Loss As a Function of Power Transfer for the AC to DC Example
7-11
Lowering Transmission-Grid Losses by Diverting Power to Higher-Voltage Lines
50.0 45.0
Transfer level: 360 MW
Line Losses [MW]
40.0 35.0 30.0 25.0 20.0 15.0 10.0 5.0 0.0 0
20
40
60
80
100
120
140
Line Length [mile] AC losses
DC losses
Figure 7–11 Line Losses as a Function of Line Length for the AC to DC Example
Evaluation of Potential Loss-Reduction In order to determine how effective existing power-flow controllers are in diverting power to lower-loss paths—thereby reducing losses in the power-transmission network—a realistic power-system network model is required. It should contain power-flow controllers such as phase-angle regulators, switchable series capacitors, and dc links. An optimal power flow would need to be developed with system loss-minimization as its objective, with control of the powerflow controllers, and then applied to this system network model. This network model would initially be undertaken without generation rescheduling, so that only the benefits of the lossminimization achievable on the power-transmission network would be evaluated. However, voltage optimization could also be included, using available generation, tap changers, and reactive power sources. Once the optimal power-flow optimization function is developed and a mechanism to link to the settings of the power-flow controllers and voltage controllers has been worked out, then several different system network models should be studied to ensure that the loss-minimization is consistently achieved.
Summary There are loss savings for a power-transmission network if power can be diverted to lower-loss transmission lines. It requires power-controlling equipment to do this. Installation of powercontrolling equipment specifically to divert power flow to achieve a lower-loss state is normally not cost-effective. In some power-transmission networks, power-controlling equipment such as phase-angle regulators, series capacitors, HVDC transmission lines, and back-to-back links are installed for various reasons. However, little effort is undertaken to operate them in a coordinated minimum-loss condition. The owners of such controllers acquired them to fulfill a specific role, such as to increase power flows, reduce loop flows, confine power to a path, or improve system 7-12
Lowering Transmission-Grid Losses by Diverting Power to Higher-Voltage Lines
stability. A few series-connected FACTS controllers also exist in some networks, which can be used for network loss-reduction. To take advantage of existing power-flow controllers, an on-line optimal power-flow procedure and controller is needed to adjust settings frequently or continuously, so that a minimum transmission-network loss state is maintained. The electric power transmission network of the WECC is a prime candidate region for lossoptimization, because it has a large number of phase-angle regulators, series capacitors, and HVDC transmission systems. Other regions have a relatively large number of phase-angle regulators dispersed throughout their systems, which could be applied effectively for diverting power to lower-loss paths. The technical process for determining minimum-loss operation can be developed. However, the restraints of long- and short-term market contracts, and the rules under which they operate, might constitute an impediment to achieving a minimum-loss operation goal.
References [1]
IEEE, “Green Transmission Demonstration.” PowerPoint Presentation to EPRI Green Circuits Members Meeting (2008).
[2]
IEEE Working Group 15.05.13, Transmission System Application Requirements for FACTS Controllers. A Special Publication for System Planners (2006).
[3]
C. Gama, L. Angquist, G. Ingestrom, and M. Noroozian, “Commissioning and Operative Experience of TCSC for Damping Power Oscillation in the Brazilian North-South Interconnection,” CIGRE 37 Session, Paris (2000).
[4]
L. Gyugyi, C. D. Schauder, and K. K. Sen., “Static Synchronous Series Compensator: A Solid-State Approach to the Series Compensation of Transmission Lines,” Paper No. 96 WM 120–6 PWRD, IEEE PES Winter Power Meeting (1996).
[5]
S. Zelingher. B. Fardanesh, B. Shperling, S. Dave, L. Kovalsky, C. Schauder, and A. Edris, “Convertible Static Compensator: Project – Hardware Overview,” Proceedings of the IEEE PES Winter Meeting (2000): pp. 2511–2517.
[6]
J. Lemay, M. Gvozdanovic, M. I. Henderson, M. R. Graham, G. E. Smith, R. F. Hinners, L. R. Kirby, F. Beauregard, and J. Brochu, “The Plattsburgh Interphase Power Controller.” Paper presented at the 1999 IEEE T&D Conference and Exposition, New Orleans, LA (April 11–16, 1999).
[7]
DC Capability of AC Transmission Lines. EPRI, Palo Alto, CA: 2008. 1013979.
[8]
Power Electronics-Based Transmission Controllers Reference Book (“The Gold Book”): 2006 Progress Report. EPRI, Palo Alto, CA: 2006. 1012414.
7-13
8
CORONA-LOSS REDUCTION This section discusses the concept of improving energy efficiency by reducing the electrostatic discharge (corona) losses of the phase conductors.
This section covers issues such as: •
The fundamentals of corona and how it is affected by various factors: –
The “onset” voltage, under which no corona will occur
–
The atmospheric conditions, such as rain, snow, or sleet
–
The physical characteristics of the conductor (including bundling) and its hardware, such as dimensions, sharp corners, edges, and protrusions
•
The concepts that can be applied to reduce or eliminate the corona loss (such as voltage reduction), their practical limitations, and the need to coordinate with other drivers such as line/system loading and reactive power flow
•
Examples of different lines, which contrast corona losses against transmission losses. Such comparisons can be used to determine if the corona loss-reduction is desirable and if it merits the efforts to reduce it.
Introduction Corona, as it is applied here, is an electrostatic discharge that occurs on transmission-line conductors when the electric field intensity, at the conductor surface, is above a certain critical level. There are a number of resulting corona effects—of which power loss is an important one— discussed in this report. Other corona effects include the generation of audible noise, electromagnetic interference, gaseous effluents, and light. A transmission line—whether ac or dc—is designed so that, when operating at its maximum continuous operating voltage, it is below the critical corona-onset level. The critical corona-onset level, as it may occur on transmission-line conductors and on hardware that is connected to the conductor, is impacted by physical dimensions such as the diameter of the conductor, sharp corners, edges, and protrusions. Atmospheric conditions are also a factor, with the most severe corona occurring with higher air density, which is also a function of pressure and temperature. Air density tends to be proportional to atmospheric pressure, which reduces with increased altitude and is also inversely proportional to absolute temperature. As a consequence, the critical corona-onset level varies over a range defined by possible extremes in atmospheric conditions for the location of the transmission line.
8-1
Corona-Loss Reduction
Reduction of Corona Loss in Existing Transmission Lines Corona loss for an existing transmission line will be present if line voltage is operating near or above the critical corona-onset level. Transmission lines designed for higher voltages are generally more prone to corona. The degree of corona will vary with environmental conditions and the voltage applied. The most severe corona occurs when it is raining and the line voltage is high. Rain, snow, or sleet increases corona activity by one or two orders of magnitude [1, 4]. A reduction in ac voltage will lower the corona and associated losses. If lowered when the line is heavily loaded, the result may be counterproductive. The lowered voltage will cause increased system losses because load current must increase to transfer the desired power flow. However, during conditions of light load and heavy corona loss, lowering the ac line voltage may reduce corona loss more than system losses increase. We also know that reconductoring or adding conductors to form a bundle can reduce or eliminate corona and corona loss. This alone is not considered a sufficient reason for reducing losses, because the reconductoring or bundling lowers conduction losses. This subject is discussed separately in Section 6 of this report. With the assumption that conductors on the transmission lines remain unchanged, and that rated voltage stays the same (for example, 115 kV, 230 kV, 345 kV), then the only mechanism available to reduce corona loss is to lower ac voltage when it is effective to do so. One expression for corona loss PdB (in decibels), developed by the BPA for the most severe conditions with precipitation [3.4], is:
Eq. 8–1
Where: n
is the number of subconductors in the conductor bundle
d
is the diameter of the subconductor in cm
E
is the average bundle gradient in kVrms/cm
K1
= 13 for n < 4 = 19 for n > 4
K2
8-2
is a term that adjusts corona loss for rain rate (RR) mm/hr, and is given as
Corona-Loss Reduction
K2
= 10. log (RR/1.676), for RR < 3.6 mm/hr
K2
= 3.3 + 3.5.log (RR/3.6). for RR > 3.6 mm/hr
A
is altitude in meters (m)
Eq. 8–2 Eq. 8–3
The corona loss in watts per meter (W/m) is determined from the antilog expression: P = 10PdB/10
Eq. 8–4
The total loss for a line in W/m is the summation of the losses for all the conductor bundles. This expression is based on 60 Hz. For results at other frequencies, corona power loss is determined with this expression for 60 Hz. Then take into account that loss is proportional to frequency. From these expressions (Equations 8–1 to 8–4), we can determine when it is effective to lower voltage, to reduce corona loss, and to what voltage. Alternatively, corona loss can be determined with Applet CL-1 Transmission Line Corona Loss [1]. The lowering of voltage would not be undertaken for a single line if that line is part of a grid at a common voltage, but would be undertaken over the area across which the grid extends. Grid voltage at that level would be lowered in a coordinated manner. This process is accomplished through the operation of the on-line tap changers (OLTCs) on the transformers that support the grid transmission. Presumably, this would be the highest voltage transmission for the network in the area of concern. In its simplest form, there would be just a single transmission line with autotransformers at each end, and the OLTCs on those transformers would be adjusted to raise and lower line voltage for corona loss-minimization, if effective to do so. It cannot be expected that the operating voltage of the grid level or transmission line would be manually reduced or raised in a coordinated manner for corona loss-minimization by the system operators. Instead, it would have to be carefully computed and adjusted automatically through the OLTCs. Corona loss-minimization, line/system loading, and reactive power-flow issues would have to be part of the computational algorithm to determine the best operating voltage for the grid. To the best of our knowledge, this procedure has not been implemented in an actual power system. To practically operate an on-line corona loss-minimization scheme, transmission lines or areas whose voltage can be lowered under light-load conditions would need to be identified—along with the means by which the voltage adjustment could be made. On-line monitoring in the area would then be needed to determine whether corona-generation levels are high enough to warrant voltage reduction. The on-line monitoring could be done by weather stations or corona-sensing detectors that can pick up radio interference levels and forward the data to where the computational algorithm is located. Presumably, when lower voltage levels are ordered, the signal would have to be sent to the supervisory control and data acquisition (SCADA) to initiate the selective voltage reductions. This would be a central control, except for a case in which only one transmission line was to be regulated. If so, control could be local, providing automated access to its voltage-control mechanism was possible.
8-3
Corona-Loss Reduction
230-kV Corona-Loss Example To explore whether it might be practical to lower ac line voltage for corona loss-reduction, the above corona loss expressions are applied. As an example, the transmission line is a common 230-kV, H Frame configuration, with the following parameters: Conductor:
Pheasant, d = 3.04 cm (1.196 in), Resistance = 0.0963 ohm/mi Rated current = 1200 A
Bundle:
n=1
AC electric field gradient at the conductor at 242 kV: E = 15.8 kV/cm The parameters for Equations 8–1 to 8–4 are: E=
15.67 kV/cm at 240 kV, and = 15.02 kV/cm at 230 kV. Note; E must be determined by a separate calculation, such as use of Applet No. CC-1 in [1].
d=
3.04 cm
K1 = 13 n=
1
RR = 0.1 mm/hr (light rain or light snow), = 3.0 mm/hr (medium rain or heavy snow), 25.4 mm/hr (heavy rain) A=
300 m
At rated current and 230 kV, there is 478 MVA flowing through the line. This is designated as 1.0 per-unit line loading. To measure the impact of corona loss versus line ohmic loss, the difference between them is plotted as a function of per-unit line loading for light, medium, and heavy rain when operating at 240 kV and reduced 10 kV to 230 kV. This 10-kV reduction in line operating voltage reduces corona loss, but it increases ohmic loss for the same line loading. When corona loss minus ohmic loss is positive, the reduction in line voltage reduces overall transmission loss. This result is shown in Figure 8–1. The length of the three-phase, singlecircuit transmission line is 100 miles. The results presented in Figure 8–1 indicate that during rainy conditions and light load on the transmission line, there is a potential corona loss benefit if the operating voltage is reduced by an appropriate amount. On the other hand, during fair weather or very light rain conditions, there is minimal benefit in terms of corona loss-reduction, for the simple reason that corona loss is very slight under these conditions.
8-4
Corona Loss Decrease minus Ohmic Loss Increase in kW
Corona-Loss Reduction
Per unit line loading
Figure 8–1 Corona Loss Minus Ohmic Loss Increase for a 230-kV Transmission Line When AC Operating Voltage Is Reduced from 240 kV to 230 kV
However, it would seem that for a specific transmission line or transmission voltage level, the study—as outlined herein—should be conducted to determine if the corona loss benefits are more significant than this example indicates. The portions of time when there is no rain, light rain or snow, medium rain or snow, or heavy rain or snow should be estimated— along with the corresponding load durations on the transmission line or system. These figures can then be used to determine how much corona-loss energy savings could be achieved through ac voltage reduction over a specific time frame (such as a year, for example). If corona-loss energy savings are deemed to be significant, they must be evaluated against the cost of deploying the communication system, environmental data-collection system, transmission load-monitoring system, and controller to effect the desired benefit. Extending this example further, consider that the percentage of time the 230-kV transmission line used in the example is under foul-weather conditions for 10% of the time. In addition, assume that 50% of the time the transmission line is lightly loaded enough so that voltage reduction is effective in reducing corona loss. This would mean that the operational corona lossreduction would be effective for only half of the time that foul-weather conditions prevail. If the average corona loss-reduction, under these conditions, is 200 kW/100 mi, then the energy savings possible is 200*8760*0.05 = 87,600 kWh of a year for 100 miles of transmission line. If the energy is valued at 10 cents per kWh, this savings is $8760 /yr for 100 miles of transmission line. This benefit must be balanced against the cost of having the facilities in place to realize the savings. It may be possible for this single-line application to put in place a local controller that would take in power flow on the line and perform corona-level monitoring at several places along the line (such as weather information or a radio interference-level detector) and determine if voltage can be lowered and by how much. Then signals could be sent to the 8-5
Corona-Loss Reduction
line’s voltage controllers to implement the computed line reduction. It is worth commenting that at light load, an additional benefit could be derived with a reduction in line-charging currents— and hence, losses—when the line’s voltage is lowered. This would be a supplementary benefit that could be integrated into the corona-evaluation algorithm. The loss savings can be more significant in higher-voltage lines, as demonstrated in the following example: 345-kV Corona-Loss Example The same procedure is followed in this example to determine the energy savings from operating a 345-kV transmission line at a reduced voltage during different weather conditions. The reduced voltage considered is the lower voltage permitted by the applicable reliability criteria for normal operating conditions. In this case, it is 95% of the nominal voltage (327 kV). Conductor:
Rail, d = 2.959 cm, Resistance = 0.108 ohm/mi Rated current = 1000 A
Bundle:
n=2
Phase spacing: 25 ft (7.6 m) E=
16.4 kV/cm at 345 kV, and = 15.5 kV/cm at 327 kV
d=
2.959 cm
K1 = 13 n=
2
RR = 0.1 mm/hr (light rain or light snow), = 3.0 mm/hr (medium rain or heavy snow), 25.4 mm/hr (heavy rain) A=
300 m
Line loading (1 pu): 1196 MVA Figure 8–2 presents the results for this case. It can be seen from this graph that, for a 100-milelong line under heavy rain conditions, there is a benefit from reducing the line voltage by 5%, provided that the line loading is below 0.9 pu.. For medium rain conditions, there is a benefit if the line loading is lower than 0.6, whereas for light rain conditions, there is no benefit at all when reducing the line voltage by 5%.
8-6
Corona-Loss Reduction
Figure 8–2 Corona Loss Minus Ohmic Loss Increase for a 345-kV Transmission Line When AC Operating Voltage Is Reduced from 345 kV to 327 kV
It should be noted that it might not be raining over the entire length of the line, and therefore a benefit might only be obtained for the section of line where it is raining. Further analysis should be undertaken to determine the minimum allowable length of line exposed to heavy rain (for a given PU loading) that would still make it feasible to lower the voltage. In the above graph, it seems that you would need at least 50% of the line to be under heavy rain conditions for a PU loading of 0.65 (the point at which the ohmic loss increase on the section of the line in clear conditions is equal to the total loss improvement on the section of the line exposed to heavy rain). For a 0.9 PU Loading, it appears that 85% of the line should be exposed to heavy rain to at least break even. The longer the line length, the more difficult it will be to have 50% or more of the line exposed to heavy rain.
Reduction of Corona Loss in New Transmission Lines For new transmission lines, the design of the conductor and tower configurations is based on a complex procedure that has been well documented [1, 5]. The electric field gradient on the conductor surface is a design parameter that impacts the degree of corona that will be generated.
8-7
Corona-Loss Reduction
The selection of conductor for a new line is also based on a transmission loss-assessment. During the design process, an anticipated load-duration curve is used to determine line losses over time. The transmission tower design and conductor selected are determined by an optimization of the present value of the cost of losses and the capital cost of the transmission facilities. Often, corona loss is not included in the cost of loss-assessment for this line-design process. This cost is left out because corona loss is inherently taken into account through the separate selection of conductor surface gradient. Over the operating range of ac voltage for the transmission line, corona is maintained at levels that comply with acceptable levels of audible noise and electromagnetic interference. For new lines, corona loss may not enter into the design process at all. And if it does, it may be for fair-weather (minimum corona-loss) conditions only.
Summary For most ac transmission lines in service, fair-weather corona loss will be relatively small in comparison to ohmic loss. However, under precipitation conditions in the form of rain or snow, corona loss can increase by several orders of magnitude, and so become significant. The example cases presented in this section demonstrate that corona loss can be reduced more than ohmic loss is increased by incrementally lowering the operating voltage during conditions of precipitation. Depending on the specific transmission line and network under consideration, operational improvements in corona loss might be possible during foul-weather conditions, and little or no operational improvements might be possible during fair-weather conditions. This determination would have to be made on a case-by-case basis. Whether such operational improvements are cost-effective would depend upon the proportion of time the foul-weather conditions exist, the portion of the line exposed to heavy precipitation conditions, and the cost of equipment that must be judiciously put in place to adjust line voltage for minimizing corona losses. Note that this is a novel approach. It is being proposed in this report to reduce corona losses, but much more investigation would be needed to evaluate its potential implementation in actual systems.
References [1]
AC Transmission Line Reference Book – 200 kV and Above, Third Edition. EPRI, Palo Alto, CA: 2005. 1011974.
[2]
AC Transmission Line Reference Book – 200 kV and Above, Third Edition. Section 8, “Corona and Gap Discharge Phenomenon.” EPRI, Palo Alto, CA: 2005. 1011974.
[3]
AC Transmission Line Reference Book – 200 kV and Above, Third Edition. Section 11, “Corona Loss and Ozone.” EPRI, Palo Alto, CA: 2005. 1011974.
[4]
P. Sarma Maruvada. Corona Performance of High Voltage Transmission Lines. Research Studies Press Ltd. 2000.
[5]
Transmission Line Reference Book : 115–345 kV Compact Line Design. EPRI, Palo Alto, CA: 2008. 1016823.
8-8
9
SHIELD WIRE LOSS-REDUCTION This section discusses the concept of obtaining improvements in energy efficiency by reducing transmission shield-wire losses.
This section covers issues such as: •
The concept of shield-wire segmentation (electrically breaking the shield wire at the tower) to reduce losses in the tower footing due to circulating currents on the shield wires
•
The other benefits of shield-wire segmentation, such as reducing the “step and touch” potentials at the towers, and its use for ice melting, which reduces line and structural loading
•
Information on the typical lengths of each segment of conventional and optical ground wire (OPGW)
•
A methodology for calculating ohmic loss-reduction, as well as an economic assessment for the use of segmented shield wires and its use for a case study
•
The merits of double-circuit lines for lowering circulating currents in the shield wires
Introduction Power loss occurs in the shield wires of ac transmission lines through mutual coupling from the phase conductors of the transmission line. Shield wires are generally steel cables with relatively high resistance compared to the conventional phase conductors, such as ACSR. In addition, any induced currents in the shield wires can circulate through the towers to ground, with losses accumulating in the tower-footing resistance and ground. Reducing these losses can be achieved by breaking the conductive path in the shield wires or by reducing the mutual coupling with the phase conductors. Breaking the conductive path in the shield wires is known as shield-wire segmentation. The shield wires are also insulated from the tower to avoid loop paths. The reduction of mutual coupling with the phase conductors is physically possible with doublecircuit transmission lines, so that there is an improved choice by positioning the phase conductors on the tower such that the mutual coupling is minimized [1].
9-1
Shield Wire Loss-Reduction
The segmentation of a transmission-line ground wire has three benefits [3]. These are: •
Power loss-reduction. The power loss-reduction will be described in more detail later in this section.
•
Reduction in “step and touch” voltage. When a human or animal touches an energized transmission-line tower, the resulting effect depends on the potential difference between the hand and foot (humans) and hoof and mouth (animals). A general rule of thumb is that the “step and touch” potential is about 50% of the induced tower voltage, where the induced tower voltage is given by Equation 9–1:
VT = I gw × RTf
Eq. 9–1
Where: Vt = Induced tower voltage Igw = Induced ground-wire current RTf = Tower-footing resistance From Equation 9–1, it is clear that reducing the ground-wire current will reduce the induced tower voltage.
•
Ice melting, which reduces line and structural loading. In certain countries, large blocks of ice form around the ground wire during extreme weather conditions. Some power utilities in these countries apply a continuous current of between 50 – 100A to the ground wire in order to melt the ice. This current is applied for a few hours up to a few days, depending on the thickness of the ice. Of course, this technique is only possible if the ground wire is insulated/sectionalized.
Segmentation Method When shield-wire segmentation is applied, each segment may be 2 to 20 miles in length. Each segment of shield wire may be grounded at one tower only, usually at the center of the segment. It will be insulated from all other towers by using standoff insulators. However, if lightning should strike it, an arc would be formed in the air across the shield wire’s insulator at the tower, enabling the charge from the lightning to discharge to ground. Each segment is terminated by dead-end strain insulators. There is no circulating path for fundamental frequency current induced from the mutual coupling with phase conductors. Hence, there are little—if any—ohmic losses in the shield wire when it is segmented. Because the mutual coupling of the line currents in the phase conductors is the significant factor, losses in an unsegmented shield wire increase with line loading. If an OPGW is planned to be installed with a segmented shield wire, the maximum available continuous length, and hence the maximum distance between splices, is 2 to 3 miles. For a standard shield wire, the length of insulated segments will be 15 to 20 miles [2]. When an OPGW is used on a segmented shield wire, each fiber splice is accommodated with an optical isolator to an accessible splice box bonded to the tower. In this way, maintenance on the communication circuit is accomplished safely while the transmission circuit is in service and energized.
9-2
Shield Wire Loss-Reduction
Figure 9–1 Example of Sectionalized Segment (OPGW) [3]
Figure 9–2 Isolator and Related Components [3]
9-3
Shield Wire Loss-Reduction
Power Loss-Reduction Energy losses in the U.S. transmission and distribution systems were estimated at 7.2% in 1995 [4]. These losses were made up of 60% line losses and 40% transformer losses. (Most of the transformer losses occur in distribution.) So based on this information, it can be said that the conductor power losses in a transmission system are in the range of 4–5%. The shield-wire power losses can be 0.1–1% of the total power transmitted, because of the fact that the groundwire losses are a result of induced currents, which are generally much lower than phase currents. Studies done by BPA [5], based on a 100-mile, 765-kV line carrying 1325 MW (1000A/phase), showed conventional ground-wire losses of 29.2 kW/mile. Further studies to determine the effect of sectionalization, with each section measuring 5 miles in length, resulted in total ground-wire losses of 27.3 kW/mile. This is a 6.5% loss-reduction and a decrease in losses of 0.014% of the total power transmitted. Ground-wire losses can be calculated by knowing the resistance of the conductor and the induced current flowing in this conductor. The ac/dc line module of the EPRI TL Workstation can be used to determine the induced currents for specific conductor geometries and load currents.
Case Study Consider an example case for a 500-kV single-circuit transmission line. The phase conductors were horizontally separated by 35 ft (10.7 m), and two shield wires of ½-in (1.3-cm) steel overhead ground cable were horizontally separated by 52 ft (15.8 m) and located 33.5 ft (10.2 m)above the phase conductors at the tower, as shown in Figure 9–3.
Figure 9–3 500-kV Tower for Segmented Shield-Wire Analysis
An analysis was undertaken to determine the approximate loss-reductions achievable by comparing line losses with and without segmenting the shield wires. The difference is designated 9-4
Shield Wire Loss-Reduction
as “loss reduction” in kW/mi for various levels of power transfer. The results are shown in Figure 9–4.
Figure 9–4 Loss-Reduction Benefit Derived from an Example of a 500-kV Transmission Line for a Range of Power-Transfer Levels.
The method of study for determining these losses is to represent the line segment in detail, using an electromagnetic transients (EMT) model. The transmission line must be represented accurately with a frequency-dependent line model. The EMT study is run in steady state for various line flows, and both with and without shield-wire segmentation in place. Power flow is accurately measured at each end of the segment, and the difference between measurements is recorded for each case to obtain loss-reduction. This particular example is similar to a study undertaken by one of the authors for a proposed 500-kV transmission line that was not approved for construction. Although no published results of the study were ever released, the above results are indicative of the results obtained. A detailed assessment of energy losses would require an annual load-duration curve of line loading so that loss-reduction could be accurately integrated over the whole year. It can be inferred from the results presented in Figure 9–4 that loss-reduction varies as the square of the line power transfer (because shield wire losses are of ohmic type). Therefore, loss factor (as defined in Equation 6–1 in Section 6) can be used to determine annual energy losses. Costs In order to segment a ground wire, it has to be insulated at each tower along the route of the line. The segmentation would most likely need to be done while the phase conductors are energized. Assuming a crew cost of $600/hour, including four persons and machines, and an installation time of between 2–3 hours, it will be $1800 for labor for the installation at one structure. Hardware costs, which include insulators and spark gaps and other hardware required for the installation, are estimated at $500 per structure. Design time for each structure would cost about $500. Design, labor, and hardware would therefore total $2800 per structure. 9-5
Shield Wire Loss-Reduction
A line with six towers per mile would incur a cost of $16,800 /mile. In conducting a cost/benefit analysis study for ground-wire segmentation, the utility needs to consider the local costs of energy, labor, and materials. Cost/Benefit Analysis The cost/benefit analysis is realized with an approach similar to those followed in the evaluation of other loss-reduction options presented in this report. Table 9–1 presents the parameters assumed in this evaluation. Loss reductions at maximum line-transfer level are estimated from Figure 9–4. A polynomial function of order two is used to approximate the loss-savings curve as a function of line-transfer level. Annual energy losses are determined by means of the line loss factor, as explained above. The total investment cost is $ 1,680,000. Table 9–2 presents the results of this analysis in terms of loss savings and economic metrics. It should be noted that, in this case, the NPV is the sum of the present values of cash inflows due to energy, capacity, and emission savings minus the total investment cost. The NPV determined in this case reveals that the loss savings surpass the investment and add value to the investor. As in the case of reconductoring to reduce losses, the loss savings— and consequently the economic results—are very sensitive to line-loading factor and energy cost. Table 9-1 Line Characteristics and Economic Parameters Parameter
Unit
Value
Line length
[mile]
100
Line maximum transfer level
[MW]
2000
Line-loading factor
[p.u.]
0.5
Peak coincident factor
0.8
Year of analysis
[yr]
30
Interest rate
[%]
7%
Energy cost
[$/kWh]
Energy cost escalation rate
[%/yr]
Capacity cost
[$/kW-yr]
75
CO2 emissions per kWh
[tn/MWh]
0.9
CO2 value
[$/tn]
20
CO2 value escalation rate
[%/yr]
9-6
0.80 2.5%
2.0%
Shield Wire Loss-Reduction Table 9-2 Savings and Economic Analysis Results Item
Unit
Value
Annual energy-loss savings
[MWh/yr]
2911
Average annual emissions
[tn/yr]
2620
Average peak-demand reduction
[MW]
1.16
Net present value
[K$]
3617
Pay-back period (energy +cap +emissions savings)
[yr]
5.0
Internal rate of return (energy +cap +emissions savings)
[%]
23%
Levelized savings (energy + capacity)
[K$/yr]
355.4
Levelized CO2 savings
[K$/yr]
71.5
Levelized overall savings (energy + capacity + CO2)
[K$/yr]
426.9
Levelized savings per invested dollar
[$/$]
3.15
Average cost of demand reduction
[$/kW]
117
Levelized cost of energy loss-reduction
[$/MWh-yr]
46.51
Levelized investment cost to save 1 tn of C02
[$/tn CO2]
51.68
Phasing of Double-Circuit Lines to Minimize Shield-Wire Losses When there are two circuits on a single tower and a single shield wire, it is possible to reduce the coupling to the shield wire by phasing the circuit on one side of the tower in reverse order to the phasing on the other side of the tower, as shown in Figure 9–5.
9-7
Shield Wire Loss-Reduction
g
a
c’
b’
b c
a’
Figure 9–5 Phasing the Conductors on a Double-Circuit Tower to Minimize Shield-Wire Loss
The phasing arrangement shown in Figure 9–5 is sometimes referred to as “low reactance phasing,” because it generates a higher surge impedance loading than if the conductor phasing on one side of the tower is the mirror image of the phasing on the other side of the tower. Other benefits of this phasing arrangement include better-balanced line voltages and currents, lower ground-level electric and magnetic fields, lower ground-return currents, and slightly lower losses in the phase conductors [1]. The lower loss for the shield wire is the result of the significant cancelation of the induced currents from the top two phase conductors that the shield wire experiences because of the phasing. Although Figure 9–5 is for a single shield wire, there is also significant shield-wire lossreduction if there are two shield wires on the tower. This method of shield-wire loss-reduction is usually of lower cost to implement than segmentation. On the negative side, the low reactance phasing causes a slightly higher conductor surface gradient, which leads to increased corona and corona effects such as corona loss. The study undertaken in [1] concluded that the cost of corona-loss increase was found to be smaller compared to the savings in resistive losses when 345-kV and 138-kV lines are moderately loaded. The cost of rephasing an existing double-circuit transmission line is relatively modest, and therefore it could be considered a possibly effective method of transmission loss-reduction on in-service and existing double-circuit transmission lines.
9-8
Shield Wire Loss-Reduction
Summary Two methods of shield-wire loss-reduction are presented. Segmentation is effective, but it requires insulation hardware to be applied to a new or existing transmission line. This method needs to be carefully evaluated to determine if the savings in reduced shield-wire losses warrant the cost of retrofitting or installation. A careful EMT study could determine the magnitude of the expected loss-reduction. For double-circuit towers, low-reactance phasing can significantly reduce shield-wire losses with minimal cost by retrofitting existing circuits or installation on new circuits. However, the benefits of low-reactance phasing are partially offset by increased corona loss from a resulting high conductor surface gradient.
References [1]
A. Nourai, A.J.F. Keri, and C.H. Shih, “Shield Wire Loss Reduction for Double Circuit Transmission Lines,” IEEE Transactions on Power Delivery, Vol. 3, No. 4, , pp. 1854– 1864 (October 1988).
[2]
Bonneville Power Administration, Policy on Voltage Isolators for Optical Ground Wire Applications.
[3]
C. Militaru, Sectionalized OPGW on Extra High Voltage Transmission Lines. AFL Telecommunications.
[4]
Staff Report: PRICE MANIPULATION IN WESTERN MARKETS DOCKET NO. PA02-2000. United States Department of Energy Federal Energy Regulatory Commission. 200303-26. http://www.ferc.gov/industries/electric/indus-act/wec/enron/summaryfindings.pdf.
[5]
A. Keri, A. Nouri, and J. Schneider, “The Open Loop Scheme: An Effective Method of Ground wire Loss Reduction.” IEEE Transactions on Power Apparatus and Systems. Vol. PAS–103, No.12 (December 1984).
9-9
10
INSULATION LOSSES This section discusses the concept of obtaining improvements in energy efficiency by reducing losses associated with the line (and post) insulators.
This section covers issues such as:
•
The fundamentals of losses in the insulators of transmission lines attributed to the resistive leakage currents flowing across the surface of the line insulators, and how they are affected by factors such as: –
The presence and types of surface contaminants (such as salt, chemical emissions, and dust)
–
The effects of light rain, fog, sleet, or mist
–
The types of insulators (for example, glass, ceramic, and nonceramic)
•
A method for measuring contamination on de-energized and energized insulators
•
A method to estimate the insulator’s energy losses, based on the leakage current phase-toground voltage, which can be used to calculate the annual cost of insulator losses
•
Typical estimates of labor costs involved in cleaning insulators and applying silicone grease, which can be used for the cost/benefit analysis
•
A typical example using the above methods
This section also provides these insights:
•
Methods to clean the insulators from the ground, an aerial bucket, a tower (structure), a helicopter, or by means of a fixed spraying system
•
Merits and considerations of applying grease to the insulators
•
Comparison of insulator maintenance procedures
Introduction Losses in the insulation of overhead transmission lines occur when there is resistive leakage current flowing across the surface of the line insulators [1]. The resistive leakage current is negligible with clean insulators, but it increases when contaminants are deposited on the insulator surface. When there is light rain, fog, sleet, or mist, the contaminant layer increases in conductivity because it becomes a layer of soluble salts, dilute acids, or alkalis. This is particularly true for insulation made from ceramic, glass, ethylene propylene diene monomer (EPDM), or any other hydrophilic material. When wetted, the contaminant forms an electrolytic 10-1
Insulation Losses
film that covers the surface of the insulator, forming a continuous conductive layer. If the contamination layer is excessive, the leakage current that flows will heat the electrolyte, which (if it is not continually wetted) will dry out unevenly. This uneven drying will result in a large voltage buildup across the dry bands, which may arc and avalanche into a flashover, causing a line fault. An example of dry-band arcing on glass suspension insulators is shown in Figure 10–1.
Figure 10–1 Example of Dry-Band Arcing on Glass Insulators
Generally, the line insulation is adequate for the environment it is designed for, and it is acceptable except for rare events when a flashover occurs. However, the resistive leakage current will still flow if the contaminants and moisture are present.
10-2
Insulation Losses
Contamination Effects on Insulator Losses Typical sources of contamination that accumulate on the surface of an insulator are:
•
Salt and sand, if near the sea or ocean or in the desert
•
Chemical emissions and waste products, if near industrial sites
•
Fertilizers, soil dust, weed killers, and crop spraying, if in agricultural lands
•
Salt, if near salted roads
Weather conditions—and in particular, moisture and temperature—can affect the formation of the electrolyte on the surface of the insulator and allow resistive leakage currents to flow. Environmental conditions such as heavy dew or rain can also wash away the contaminants on the insulator surfaces and reduce the magnitudes of leakage currents. There are a number of ways that contamination deposits or leakage currents are measured on energized insulators. Instrumentation and techniques are available to perform measurements, which include:
•
Insulator surface conductivity under natural contamination and wetting
•
Equivalent salt deposit density (ESDD) and nonsoluble deposit density (NSDD) measurements (See Figure 10–2, which is used to characterize the environment based on ESDD and NSDD measurements.)
•
On-line measurement of leakage current
10-3
Insulation Losses
Figure 10–2 Pollution Severity Based on ESDD and NSDD Levels [6]
Of these measurements, on-line leakage-current measurements of in-service insulators provide a direct measurement. Leakage-current measurement transducers are connected (attached) to the dead-end side of the insulator. There are a number of commercially available insulator leakagecurrent measurement systems [2, 3, 4]. However, newer technologies (like EPRI’s wireless leakage-current sensors) allow the possibility of mass deployment [5]. A typical installation is shown in Figure 10–3.
10-4
Insulation Losses
Wireless leakage current monitor
Figure 10–3 Example of On-Line Leakage-Current Monitoring Using EPRI’s Wireless Leakage-Current Sensor
It is important to know that the on-line field measurements of surface conductivity or leakage current vary significantly on a daily basis. Review of leakage-current measurements for a given installation make it possible, over time, to determine the relationship between the contaminationseverity class and the leakage-current magnitudes of the monitored insulators. Depending on the type of instrumentation, it may not always be practical to install a leakagecurrent measurement device on every insulator on a transmission line; if not, an extrapolated value of total leakage-current magnitudes would need to be made. If the transmission line passes through different contamination zones along its route, the impact of different averaged leakagecurrent values would need to be estimated for the total insulator loss-assessment for the line. To determine a reasonable base for estimating total line insulator loss, it would be important to have several leakage-current monitoring sites along the line. Insulator Leakage-Current Losses The losses incurred because of insulator leakage currents are not constant. Leakage currents vary on an hourly, daily, monthly, and yearly basis, because they are affected by humidity and ambient conditions. As humidity varies throughout the day, so does leakage current. In order to properly determine the leakage current, it needs to be monitored using leakage-current monitoring instruments for a specific period of time (at least one year). Figure 10–4 shows the 10-5
Insulation Losses
leakage current measured for a 400-kV glass insulator string over a 24-hour period [7]. These leakage currents were measured in a low-to-medium contamination environment. Figure 10–4 also shows an association between leakage activity and relative humidity. The increase in humidity to a value above 75% (relative humidity) results in leakage-current activity. In other words, the presence and magnitude of the leakage current varies. It is not always present, and it will not be the same on every structure. Higher leakage currents can be expected if more contamination is present.
Figure 10–4 Example of Insulator Leakage Current During a 24-Hour Period
Mitigating Line Insulator Losses [8] There are a number of ways that the effects of contamination can be mitigated to reduce the probability of flashovers and the magnitude of leakage current. Insulator material has a significant impact on leakage-current activity. The surface-layer resistance is the main factor that determines the magnitude of the insulator leakage current. Various methods to increase the surface-layer resistance are described below: Cleaning Cleaning removes the contamination from the insulator surface. This process can take the form of hand-cleaning or spray-washing (live or de-energized). Spray-washing can be performed from 10-6
Insulation Losses
the ground, an aerial bucket, a tower (structure), a helicopter, or by a fixed spraying system. The washing medium can be water, vegetable oil (for example, corncob or walnut oil), dry ice, or solvent. All these methods are described in detail in the IEEE guide for cleaning Insulators (IEEE Std 957-1995). Ideally, insulator cleaning should take place at the end of a lengthy dry spell (that is, a period of very little or no rain), thus preventing wetting of a contaminant by natural increases in relative humidity, the first rains, or fog/mist. Washing of polymer insulators is generally not recommended. Hand-Cleaning Hand-cleaning is effective in removing accumulated contamination from insulators, but it is labor-intensive and requires an outage. Hand-cleaning can be done with rags, nylon scrubbing pads, or steel wool, which are often used in combination with solvents to aid the cleaning process. Care should be taken to rinse the insulators properly after cleaning to remove any steel wool or solvent residue. Hand-cleaning of polymer insulators is generally not recommended. Water Spray-Washing (De-energized) Spray-washing (de-energized) is an effective and less labor-intensive option than hand-washing. Under de-energized conditions, a pressurized spray-washing system is used to clean insulators with water. Details of procedures and equipment are provided in the IEEE Std 957. Spraywashing is effective for removing soluble salts from the insulator. It may not be as effective in certain industrially contaminated areas that contain such contaminants as gypsum, cement, or fly ash that have hardened on the insulator surface. Water Spray-Washing (Energized) Spray-washing under energized conditions is, in principle, the same as that done under deenergized conditions—except that a number of measures must be taken to ensure the safety of the operator and to prevent any flashovers during the cleaning event. The washing can be performed from the ground, an aerial bucket, or a tower (structure). Water spray-washing of polymer insulators is generally not recommended. Compressed Air and Dry-Cleaning Compound Insulator cleaning can also be done with a combination of compressed air and an abrasive drycleaning compound or dry ice. This method is applicable in situations where there is old hardened contamination on the insulators, or for the removal of deteriorated room-temperature vulcanizing (RTV) silicone rubber coatings from porcelain or glass insulators. It is, however, not suitable for use on polymer insulators or polymer-housed equipment because of the risk of damage.
10-7
Insulation Losses
Greasing Greasing generally provides a hydrophobic surface, and it also surrounds and encapsulates the contaminants. Two types of grease coatings are in general use: hydrocarbon and silicone grease. Hydrocarbon greases are used in mild to cold climates as an encapsulation agent. A high ambient temperature or warm insulator housings resulting from internal heating may cause the grease coating to slide off the insulator. As a result, hydrocarbon greases are generally not used in the United States, where high ambient temperatures prevail. Silicone greasing of the insulator changes the surface condition from hydrophilic (surface wets out into water films) to hydrophobic (water repellent). The application of silicone grease is normally done by hand or brush, but these methods often result in an uneven coating. A more even coating is possible with a spray application, but it is not possible to do this will all types of silicone grease. Greasing can only be applied to glass or porcelain insulators. This method is also labor-intensive, and it is not usually practiced on transmission lines. However, if grease is applied and is not replaced, the effectiveness is reduced. Over time, this situation can lead to insulator degradation and flashover. Coating with Silicone Rubber This coating has a hydrophobic and dirt-repellent surface. Hydrophobic surfaces reduce magnitudes of leakage currents caused by nonuniform wetting and, consequently, reduce contamination flashovers. Guidance for the selection and application of RTV silicone rubber coatings is provided in the IEEE standard 1523 – 2002. Material aging may cause loss in hydrophobicity and, in some cases, erosion damage to the thin coating after several years of operation. When damage occurs, surface cleaning and reapplication of the coating are required. Re-Insulation This measure consists of replacing existing insulation with different designs to reduce leakagecurrent activity. When replacing existing insulation with polymer insulators, the design and suitability of grading rings should be carefully considered.
Comparison of Insulator-Maintenance Procedures The aforementioned maintenance procedures are normally implemented to improve reliability by reducing the risk of a fault resulting from insulator flashover. The remediation method is chosen based on maintenance interval and cost. Maintenance intervals will depend on the characteristics of the insulators in service and the contamination severity of the operating environment. Maintenance intervals are typically shorter for heavily contaminated environments. The risk of flashover associated with each maintenance technique is also taken into account in the selection. Because of the wide variety of insulator types, applications, environments, maintenance intervals, geographical locations, and voltage levels, it is not practically possible to provide a precise cost comparison of the various maintenance procedures. Table 10–1 describes the characteristics of these methods that are relevant for their selection [8]. Typical costs have been obtained from EPRI member utilities. 10-8
Insulation Losses Table 10-1 Characteristics of Methods to Reduce Insulator Leakage Current Options
Risk
Maintenance interval
Cost
Cleaning
6 months
High
N/A
Silicone grease
1 year
Medium
N/A
Silicone coating
5–10 years
Low
$190 per insulator
Re-insulation
30 years
Negligible
$2500 per 3-phase single-circuit tower
Application to Reduce Losses The described insulator-maintenance methods can be applied with the objective of reducing transmission-system losses, because they reduce insulator leakage currents and, consequently, insulator dissipation losses. The choice of corrective action will be influenced by applicability, accessibility, and cost. If the incidence of contamination-related flashovers is a factor, the mitigating action applied will most likely reduce the leakage current as well. To undertake a mitigating action solely for the reduction of insulator losses will need to be seriously investigated. It is very difficult to determine the leakage current over the lifespan of insulators (especially glass and ceramic), because there are many contributing factors—including cleaning of the insulator (rain), weather conditions, type of insulator, and insulator design. Therefore, leakage-current monitors need to be installed to compare the improvement achieved. The energy losses dissipated in the transmission insulators are determined by integrating the leakage current measured for the time period in question and then multiplying this integrated value by the line phase-to-ground voltage. Loss savings that can be achieved by applying one of the described maintenance options can be determined by comparing the losses with the existing insulator conditions, minus the losses after the application of the leakage-current mitigation option. It should be noted that the application of these maintenance options may not completely eliminate the leakage currents. This factor needs to be taken into account in the evaluation of potential savings. Example Consider a 100-mile, 230-kV, single-circuit transmission line. Each tower has three insulator strings, and there are five towers per mile. The conductor is an ACSR 1272-kcmil Bittern. The resistance of the conductor is 0.09 ohm/mile at 75°C. Assume that 20% of the line runs through a contaminated environment (300 insulator strings), with an average measured leakage current per string of 2.5 mA for this 20%. The remaining 80% of the line is assumed to have no leakage current. The average current across the entire line (1500 strings) would then be
AverageCurrent = current ∗
300 no _ of _ Strings _ with _ Current = 2.5mA ⋅ = 0.5mA 1500 Total _ no _ of _ Strings _ in _ Line Eq. 10–1
10-9
Insulation Losses
Assume that leakage currents have been measured on a number of insulators along the route of the line and that, based on this measurement, the annual average of this current is 0.5 mA. The annual energy losses due to insulator dissipation will be as follows: ⎡ MWh ⎤ 230 insulator tower hr Iloss⎢ ⋅5 ⋅ 100 mile ⋅ 8760 ⋅ 1e − 06 = 1,745 MWh/yr Eq. 10–2 kV ⋅ 3 ⎥ = 1 mA ⋅ 1.73 tower mile yr ⎣ yr ⎦
Assuming that the maximum current per phase is 1000 A and the line loading factor is 0.5 (the corresponding loss factor is 0.29), the annual energy losses due to conductor resistance will be ⎡ MWh ⎤ hr 2 2 Rloss⎢ ⎥ = 3 ⋅ 100 A ⋅ 0.09 Ω ⋅ 8760 ⋅ 0.29 ⋅ 100 mile ⋅ 1e − 03 = 67,818 MWh/yr . yr ⎣ yr ⎦
Eq. 10–3
Thus, the insulator energy losses in these conditions are 1.3% of the conductor ohmic losses. Consider that silicone coating is applied to all line insulators, and that the coating lifespan is 10 years (they have to cleaned and recoated every 10 years). Assume also that when the insulators are coated with silicone, the leakage activity is as follows: (Note: This example should be used for illustrative purposes only because contamination and environment will impact the lifespan or effectiveness of the coating. In other words, the loss of effectiveness may not be linear over its lifespan.)
Year
Leakage current as a percentage of uncoated insulator
1
10%
2
20%
3
30%
4
40%
5
50%
6
60%
7
70%
8
80%
9
90%
10
100%
The energy and emissions savings, as well as their monetary value, can be determined by considering such variations of insulator leakage-current over time. The upfront cost/benefit analysis is conducted by taking into account the investment cost of the silicone coating applied and the annual savings produced by leakage-current reduction. The horizon of the analysis is 10 10-10
Insulation Losses
years because, after that time, the effect of the coating in reducing leakage-current activity is negligible, and a new coating needs to be applied. In other words, the stream of cash flow repeats every 10 years. The total investment cost is: Inv[$] = 190
$ insulator tower ⋅3 ⋅5 ⋅ 100 mile = $285,000 insulator tower mile
Eq. 10–4
Table 10–2 shows the economic parameters considered in this case. Table 10–3 presents the results of the analysis. It is observed that the present value of the silicone-coating option is less than the total present value of losses if nothing is done to the insulators. It should be noted that the impact on capacity cost has not been taken into account in this analysis, because the simultaneous maximum leakage current of all the line insulators and coincidence with system peak would be required to perform such an analysis. It should be cautioned that this is only a generic illustrative example. The results are highly sensitive to the average leakage current over the considered time period. Therefore, an appropriate method to estimate this current by measuring and sampling needs to be investigated and applied. Table 10-2 Line Characteristics and Economic Parameters Parameter
Unit
Value
Year of analysis
[yr]
10
Interest rate
[%]
7%
Energy cost
[$/kWh]
Energy cost escalation rate
[%/yr]
CO2 emissions per kWh
[tn/MWh]
0.9
CO2 value
[$/tn]
20
CO2 value escalation rate
[%/yr]
2.0%
0.80 2.5%
10-11
Insulation Losses Table 10-3 Economic Analysis Results – Silicone Coating of Insulators Unit
Existing Insulator Conditions
Average annual losses
[MWh/yr]
872
Annual energy loss-savings
[MWh/yr]
Average annual emissions
[tn/yr]
Annual emissions savings
[tn/yr]
Annual energy and emissions savings
[%]
PV (energy+cap.+CO2+investment)
[K$]
Levelized energy savings
[K$/yr]
37
Levelized CO2 savings
[K$/yr]
9.2
Levelized overall savings (energy+CO2)
[K$/yr]
46.2
Levelized savings per invested dollar
[$/$]
1.14
Pay-back period
[yr]
5
Internal rate of return
[%]
11%
Levelized cost of energy lossreduction
[$/MWh-yr]
Levelized investment cost to save 1 tn of C02
[$/tn CO2]
Item
With Silicone Coating 479.8 392.6
785
431.9 353.3 55%
664
624
103.6
114.86
Summary Contamination deposits on transmission-line insulators cause a leakage current that flows across the insulator’s surface between the tower and the energized conductor, causing line losses. This current is subject to wide variability over time, which is largely a function of the amount of contamination deposited and its moisture level. The only practical way to estimate the insulator losses is to measure the leakage current in a sample of insulators. Based on the average value of insulator losses measured and computed over time for the total transmission line, including changes in contamination severity along the line route, an estimate of total line insulator losses can be made. Once the total line losses resulting from insulation have been estimated, a decision can be made as to whether a mitigation strategy needs to be applied that is cost-effective.
10-12
Insulation Losses
References [1]
R.E. Macey, C. de Tourreil, and W.L. Vosloo. The Practical Guide to Outdoor High Voltage Insulators. Published by Crown Publications for ESKOM, September 2006.
[2]
CIGRE, The Measurement of Site Pollution Severity and its Application to Insulator Dimensioning for AC Systems. WG 33-04, Electra No. 64, 1979.
[3]
TransiNor. www.doble.com/content/products/IPMBrochure.pdf
[4]
http://www.ctlab.com/main leakage.htm
[5]
Future Inspection of Overhead Transmission Lines. EPRI, Palo Alto, CA: 2006. 1016921.
[6]
IEC-815
[7]
FF Bologna, JP Reynders, and AC Britten, “Corona Discharge Activity on a String of Glass Cap-and-Pin Insulators Under Conditions of Light Wetting, Light Non-Uniform Contamination.” IEEE Power Tech. Conference, Bologna, Ital y (2003).
[8]
Guide to Maintenance of Insulators in Contaminated Environments. EPRI, Palo Alto, CA: 2009. 1017726.
10-13
11
LOW-LOSS TRANSFORMERS This section discusses the concept of obtaining improvements in the energy efficiency of transmission systems with lower-loss transformers.
This section covers issues such as:
•
The DOE’s new rule specifying the minimum efficiency levels for distribution transformers manufactured for sale in the United States on or after January 1, 2010
•
A breakdown of the losses in transformers, and the importance of (the nearly constant) noload losses in achieving higher efficiencies
•
The significance of low load factor in the loss evaluation
•
The importance of other losses, such as auxiliary equipment losses(for example, fans), for larger transformers
•
The options involved in improving efficiency— such as core design/materials—and the more-advanced designs—such as amorphous metals and superconducting designs
•
The concept of the total owning cost (TOC) for assets such as transformers
In addition, this section proposes approaches for evaluating the feasibility and cost-effectiveness of using energy-efficient transformers. These approaches are based on common strategies for dealing with failed transformer-replacement options for substation-class transformers, such as repair, rewinding, complete replacement, and early replacement due to efficiency.
Introduction Losses in power transformers can be modified by adjusting design parameters (including core size and material), which affect the constant no-load losses, and winding conductor size and material, which affect the variable-load loss. Today, improved manufacturer techniques and new types of core materials make it possible to produce cost-effective and energy-efficient transformers. Manufacturers are able to provide a number of choices relative to transformer losses and efficiency. However, high-efficiency levels imply larger investment costs. Hence, the decision of whether to purchase a low-cost less-efficient transformer or a more-expensive energy-efficient transformer is primarily an economic one. As described before, the cost of energy losses is a pass-through cost for the utilities, and therefore it does not affect them financially. This consideration implies that there are no benefits that accrue to the utility if it decreases its system losses. If so, it may not be in the interest of a utility to invest in a transformer with low losses (higher purchase price).
11-1
Low-Loss Transformers
However, on a large scale, reduction of losses is beneficial for electricity users. Indeed, if the cost of losses is higher than the cost of investment for improving efficiency, the cost of electricity is reduced—resulting in a lower tariff to customers. There are also other externalities that benefit society as a whole, such as the reduction in carbon emissions and resources depletion. If, through appropriate regulatory instruments, utilities were allowed to earn a return on the capital investment made to reduce losses, there would then be an incentive to invest in highefficiency transformers. The replacement of existing low-efficiency transformers and the use of high-efficiency transformers have mainly been focused on the distribution side, because the effect on system efficiency is more significant there. The DOE’s new rule on the Energy Conservation Program for commercial distribution equipment adopts energy-conservation standards for liquidimmersed and medium-voltage, dry-type distribution transformers. These standards constitute minimum-efficiency levels for the transformers manufactured for sale in the United States, or imported into the United States, on or after January 1, 2010. The standards are intended to achieve the maximum improvement in energy efficiency that is technologically feasible and economically justified and that will result in significant energy savings and emissions reductions. The loss-reduction in a high-efficiency distribution transformer is principally achieved in the noload losses, because the major improvement is in the core. Therefore, the effect on overall lossreduction is more important in transformers with relatively low load factor, which is mainly the case in the distribution system. Transformers in the distribution system are relatively easy to replace, and their efficiency can be classified, labeled, and standardized fairly easily. For large transformers (above a few MVA), on the other hand, the costs of losses are so important that transformers are custom-built. Most units are designed to meet individual utility specifications that involve significant differences in design requirements, features, safety factors, and use of materials. Historically, there has been little standardization in the design and manufacture of power transformers [1]. They are tailored to the loss-evaluation figures specified in the transformer specification defining the unit. Therefore, loss-reduction is not usually a reason for replacing existing large transformers. However, if a transformer is replaced for other reasons, such as age or under-capacity, it may be cost-effective to install a transformer with higher efficiency than the existing one.
Losses in Transformers Transformer losses can be divided into two main components: no-load losses and load losses. The first type of losses occurs in the core of the transformer, regardless of load conditions. Load losses, on the other hand, occur in the transformer’s winding and vary with load current. These types of losses are common to all types of transformers, regardless of transformer application or power rating. In large transformers, other sources of losses can be identified, such as extra losses created by harmonics and the energy used for auxiliary equipment (mainly the cooling system).
11-2
Low-Loss Transformers
No-Load Losses An unloaded transformer experiences losses resulting from the magnetizing current required to take the core through the alternating cycles of flux at a rate determined by system frequency. This loss is known as the core loss, no-load loss, or iron loss. The core losses are present whenever the transformer is energized, and they are almost constant. Core losses are composed of:
• Hysteresis losses: These losses are caused by the frictional movement of the magnetic domains in the core laminations as they are magnetized and demagnetized by alternation of the magnetic field. These losses depend on the type of material used to build a core. Silicon steel has a much lower hysteresis than normal steel. Amorphous metal presents a random configuration of the molecules that causes significant reduction in hysteresis losses over silicon steel. Hysteresis losses are usually responsible for more than half of total no-load losses (50–80%). Hysteresis losses can be reduced by material-processing methods such as cold rolling, laser treatment, or grain orientation. • Eddy-current losses: These losses are caused by varying magnetic fields inducing eddy currents in the laminations and, hence, generating heat. The increased heat can result in increasing the resistance and, consequently, cause the losses. Eddy-current losses usually account for 30–50% of total no-load losses. Eddy-current losses can be reduced by building the core from thin laminated sheets, insulated from each other by a thin varnish layer to reduce eddy currents. Load Losses The load loss of a transformer is that part of the losses generated by the load current and which varies with the square of the load current. This loss falls into two categories:
• Resistive loss: This loss occurs in transformer windings and is caused by the resistance of the conductor. The magnitude of these losses increases with the square of the load current and is proportional to the resistance of the winding. Lower resistive losses can be obtained by reducing the current densities of the conductors (increasing conductor cross-sectional area) and by reducing winding length. The choice of winding material (copper or aluminum) affects resistance losses. Cooper conductors have lower losses, and they allow a proper balance among factors such as weight, size, cost, and resistance. • Conductor eddy-current loss: This loss is caused by eddy currents that are induced in the winding conductors by alternating magnetic fields. Eddy-current loss in winding conductors can be reduced by more finely subdividing the conductors, mowing the shape of the conductor to reduce skin effect, using structural materials that develop lower losses when penetrated by leakage flux, and using various shielding techniques to reduce the stray losses produced by leakage flux. • Stray eddy losses: These losses are caused by eddy currents that are induced in structure components such as clamps, bolts, tanks, and channels by leakage fluxes.
11-3
Low-Loss Transformers
Losses in Auxiliary Equipment These are losses caused by the use of cooling equipment such as fans and pumps to increase the loading capability of substation transformers. The energy consumption of auxiliary equipment depends on the horsepower of the fans and pumps and the length of time they are running. These factors are dependent upon the transformer loading throughout the year. Some transformers are designed to run the fans and pumps continually. The auxiliary losses are very low compared to the other losses. And because the equipment is used to increase the loading capacity, the losses should be referred to the increased capacity to achieve a fair assessment of the transformer’s efficiency. Auxiliary-equipment losses can be reduced by limiting the operating time of the auxiliary equipment. Losses Due to Harmonics Harmonic currents produced by nonlinear loads increase both load and no-load losses due to increased skin effect, eddy current, stray, and hysteresis losses because they depend on the square of frequency. In a transformer that is heavily loaded with harmonic currents, the excess loss can cause high temperatures at some locations in the windings. In these cases, special transformers can be designed to withstand additional losses and heating. These transformers are identified as “K-rated” or “K-factor” transformers. K-rated transformers may cost twice as much as standard transformers, and they are not necessarily more efficient. They are used for special cases in which harmonic components are significant. Figure 11–1 illustrates the different sources of losses in a transformer and the physical components that mainly affect them. This figure is reproduced from [5], with permission of ABB, Inc.’s Power Transformers Division.
Figure 11–1 Sources of Transformer Losses and the Physical Components That Affect Them [5]
11-4
Low-Loss Transformers
Options to Improve Transformer Efficiency There has been impressive progress in transformer technology in recent decades, which is fundamentally based on two main factors: improved material characteristics (especially of core material) and development of advanced design tools. Core Material The most important step toward low-loss and high-saturable material was the invention of coldroll grain-orientated transformer sheets. By continuous reduction of thickness, improved grain size and orientation, surface polish, scratching, and the application of controlled mechanical stress, the specific losses in the core have been drastically reduced [6]. The introduction of laser cutting for laminations has reduced burrs, improving insulation between laminations and reducing no-load losses. Oriented steels used in transformers have a crystal structure that allows for improved magnetic properties in a given direction. Some common oriented- steel grades are M–2, M–3, M–4, M–5 and M–6. The M–2 and M–3 grades have the highest efficiency, highest cost, and lowest availability. Also, M–2 and M–3 are very thin for electric steel laminations, having a nominal thickness of 0.007 in. (0.18 mm) and 0.009 in. (0.23 mm), respectively. M–2 through M–6 have a density of 7.65 gm/cm3, which is similar to the M–15 nonoriented steel [10]. The most significant innovation for reducing losses in the transformer core is the use of amorphous steel. Amorphous-core transformers have been researched extensively, and they have great promise for improving the efficiency of the distribution system by significantly decreasing no-load losses. For a typical standard-steel core transformer, no-load losses average about 0.15– 0.4% of the transformer rating, depending on the needs of the utility. No-load losses typically account for a majority of total distribution transformer losses in lightly loaded conditions. Operating conditions in which distribution transformers are lightly loaded for extended periods throughout the year may provide the optimal conditions for amorphous technologies to be introduced [10]. Because of the thin and brittle nature of the amorphous ribbon material, laminations are not cut or punched (as with traditional steel-core laminations). Instead, woundcore technology is applied, in which the ribbon is rolled up (not stacked) and wound, usually in a rectangular toroid shape. The application of amorphous steel is still limited to distribution transformers. Extreme brittleness, mechanical sensitivity, and cutting and stacking problems resulting from a thickness in the range of 20–30 microns seem to make its application in power transformers prohibitive [6]. However, recent advancements in the processing of the amorphous material has led to a wider ribbon, hence expanding the size of the transformers capable of being produced and improving the actual manufacturing process [10]. Table 11–1 provides data on the magnetic properties and application types for amorphous metals used in transformer applications and standard oriented silicon steels.
11-5
Low-Loss Transformers Table 11-1 Properties of Common Amorphous Metals and Electric Steels [10].
Material
Core Loss (W/lb) at 60 Hz
Eddy-Current Contribution to Core Loss @ 60 Hz and 1.5 T
Applications
Distribution and power transformers Metglas 2605SA1 (as cast)
0.09 W/lb at 1.4 T
Negligible eddycurrent contribution
Motors High-frequency inductors Current transformers
Oriented M–2
0.41 W/lb at 1.5 T
53%
Oriented M–4
0.51 W/lb at 1.5 T
71%
Oriented M–6
0.66 W/lb at 1.5 T
76%
Electrical distribution and power transformers Large-turbine generators
Conductor Material The introduction of continuously transposed conductors (a single conductor subdivided into several flat subconductors that are regularly transposed) influenced the windings design, essentially allowing a better packing density of the winding and reducing losses caused by eddy and circulating currents [6]. Also, winding design and insulation improvements, making the winding thinner, allowing operation at higher temperatures, and adding some dielectric strength also helped to reduce load losses by improving heat evacuation and increasing the conductor area. Superconducting Transformers High-temperature superconductors (HTSCs) are resistance-free conductors made of ceramics that have superconducting characteristics at much higher temperatures than low-temperature superconducting materials that exhibit superconducting properties at -450 F. HTSCs use liquid nitrogen as a cryogen to cool the transformer windings. The possibility of using liquid nitrogen allows utilities to reduce the expenditure for cooling plants by an order of magnitude. Besides, the substance is inert and nontoxic. The use of HTSC transformers on a large scale will become more attractive as cooling systems improve and the cost of liquid nitrogen production falls. Another important factor is progress in the processing of long lengths of HTSC s [10]. At present, conductors based on ceramic material embedded in silver can be manufactured at lengths of several hundred meters, which is a precondition for their use in transformers [6]. These transformers have smaller weight and volume and are more resistant to overload, which makes them especially attractive for applications in which weight is crucial (for example, high-speed trains) [10]. HTSC transformers may be suitable in cases in which load factor is very high; however, their large-scale commercial application will depend on further steps to reduce cost.
11-6
Low-Loss Transformers
Advanced Design Tools The use of powerful computer-simulation methods and mathematical models— such as 2D and 3D finite elements methods— allows more precise prediction of electrical and mechanical stress, including heat transfer and vibrations. With such advanced tools, manufacturers can optimize the design of insulation structure and check losses and vibrations in structural parts with complicated geometry. These tools can also precisely determine short-circuit effects and capabilities, as well as thermal performance. Voltage distribution under transient conditions can be determined by calculation of the frequency and time domain for different voltage shapes and winding arrangements. As more precise calculations and simulations of performance can be conducted, tolerance and security margins can be substantially reduced.
Savings Potentials No-load losses are practically constant (disregarding variations in voltage) during the entire time the transformer is energized. The effect of load losses is more complicated. The load variation in a transmission transformer generally has a daily variation, a weekly variation, and a seasonal variation. This variation is then further combined with a long-term trend of generally rising loading over a number of years, until the installation become fully loaded and has to be relieved or reinforced. Indeed, transformers in transmission and distribution systems usually have a power rating that is considerably higher than the load just after installation, in order to meet future needs. The loading may prevail for several years before the load current approaches the transformer’s nominal current. Clearly, during the first period after installation, load losses will be less significant. Hence, the energy savings that can be achieved by using more-efficient transformers will depend on the relative impact of no-load and load losses over the total losses during a specific period of time (usually expressed on a yearly basis). This, in turn, will depend upon the transformer loading pattern. In order to precisely evaluate transformer load losses over its life-cycle, a calculation needs to be conducted that takes into account detailed load variations, tap-changer settings, and ambient operating temperatures with variable ambient conditions. However, in view of the considerable uncertainties of future conditions, it would be more practical to apply a simplified computation to evaluate transformer losses by disregarding temperature variations and, consequently, considering load losses at rated conditions. Another important factor that influences transformer loading conditions is that transformer installations must provide sufficient power capacity for back-up services in case of disturbance. A certain overload for a limited period of time is permissible in case of a fault. However, the ratio of back-up loading over predisturbance or normal conditions is in many cases larger than the ratio of permissible overload over rated load. This means that the spare capacity, if considered, should restrict maximum predisturbance loading to below the rated power in many typical applications. This situation has to be taken into account when loading conditions are defined for the evaluation of loss evaluation and loss capitalization. In distribution systems, the loading conditions of the transformers connected to radial feeders mostly follow load pattern. Therefore, the evaluation of the potential energy savings can be conducted by straightforward calculations if the characterization of the fed load is available. In 11-7
Low-Loss Transformers
transmission systems, on the other hand, the loading of the different system components does not necessarily follow the load pattern; it also varies with network topology, generation dispatch, inter-area power flows, and wheeling. Hence, determining the loafing pattern of a transmission transformer in future years is challenging. One option is to use a production-simulation model with a detailed representation of the transmission grid to simulate system operation. Another option is to estimate transformer loading variation by a power-flow study, considering a number of representative scenarios and taking into account the expected evolution of the power system within the period of analysis (transmission reinforcement, new generation, load forecast, demand response programs). Alternatively, if these options are not feasible, the prospective transformer loading pattern could be estimated from historical data (assuming that future transformer loads will follow the same patterns) and scaling load values with a given escalation factor. Energy-Saving Potential A qualitative observation of how load patterns and percentages of no-load losses (NLL) and load losses (LL) affect total energy losses is presented below: The total energy loss over a year is:
[
]
E loss ( kWh yr ) = NLL ( kW ) + LL( kW ) ⋅ LFS ⋅ CF 2 ⋅ 8760 hr yr
Eq. 11–1
Where: NLL: No-load loss LL: Load loss LFS: Loss factor - LFS = 0.15 ⋅ LD + 0.85 ⋅ LD 2
Eq. 11–2
LD is the load factor, which is defined as LD =
average transform er demand maximum transform er demand
Eq. 11–3
Total energy losses can be expressed as a percentage of the total energy that flows through a system in a specific period of time, by means of the following equation:
%E loss
% NLL + %LL ⋅ CF 2 ⋅ LFS = CF ⋅ LD
Eq. 11–4
Where: %NLL: Percentage of no-load loss with respect to rated power %LL: Percentage of load loss with respect to rated power CF: Capacity Factor - CF =
transforme r peak load transforme r rated load
Eq. 11–5
Figure 11–2 shows the variation of total transformer loss with respect to the load factor for three different values of no-load loss percentage (%NLL). It can be observed that, as expected, the impact of the NLL-reduction on the total transformer loss is more significant for low-load factor.
11-8
Low-Loss Transformers
12 10
%Eloss
8 6 4 2 0 0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
Load Factor (p.u.) NLL=0.2%
NLL=0.1%
NLL=0.05%
Figure 11–2 Percentage of Loss Versus Load Factor for Different Values of No-Load Loss (NLL)
The loss-reduction that is achieved in high-efficiency transformers is mainly in NLL, because the principal improvement is in the core. The following table shows an example of NLL and LL for different transformers with different core materials [11]. It can be observed that the lossreduction in advanced-core transformers is much more important in the core losses than in the copper losses. The use of transformers with advanced cores is more efficient for reducing losses in cases in which the transformer is not fully loaded over time. Indeed, the lower the load factor, the greater the influence of core loss on the total losses of the transformer, and the more significant the impact of the high-efficiency core in the loss-reduction.
The equation of %Eloss (Figure 11–3) shows that the influence of LL on the total transformer loss is strongly dependant on the capacity factor (CF), and that total transformer loss varies linearly with respect to NLL and LL percentages. Figure 11–3 shows the variation of the percentage of total load with respect to the C F for the different values of load loss percentage. It is observed that the impact of reducing load losses is more noticeable if the transformer is loaded near to its maximum capacity.
11-9
Low-Loss Transformers
6 5
%Eloss
4 3 2 1 0 0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
Capacity Factor (p.u.) LL=0.8%
LL=0.6%
LL=0.4%
Figure 11–3 Percentage of Loss Versus Capacity Factor for Different Values of Load Loss (LL)
Thus, the optimal design of a substation transformer is a trade-off between improvements in core losses and in winding losses. A substation transformer that is lightly loaded for most of its life will have a larger no-load penalty. For such a transformer, the design may accept higher winding losses in favor of more exotic core materials to keep the NLL down. This is a huge driver in what makes every power transformer design unique. Peak-Demand Reduction Potential The demand losses of a power transformer expressed as a percentage of the maximum power flow through it can be evaluated as follows:
%Ploss =
%NLL + %LL * CF2 CF
Eq. 11–6
Where the variables and parameters are the ones defined previously. This equation shows that power loss varies linearly with NLL as well as with LL, and that the influence of the latter is significantly affected by the C F. Figure 11–4 depicts the variations of the transformer power loss (%Ploss) with respect to the variation of the CF, parameterized for three different values of LL percentage. It is observed that the effect of LL-reduction in the total transformer load is more noticeable when the CF is high, which is the typical case under peakdemand conditions.
11-10
Low-Loss Transformers
1.4 1.2
% Ploss
1 0.8 0.6 0.4 0.2 0 0.8
0.85
0.9
0.95
1
1.05
1.1
1.15
1.2
1.25
1.3
Capacity Factor (CF) LL=0.8%
LL=0.6%
LL=0.4%
Figure 11–4 Percentage of Power Loss for Different Values of Load Loss (Ploss)
On the contrary, the effect of reduction in the NLL on the total transformer loss is less important under high C F conditions, as illustrated in Figure 11–5. Therefore, improving NLL has less influence on reducing system peak demand than it does on reducing transformer LL.
1 0.9
% Ploss
0.8 0.7 0.6 0.5 0.4 0.8
0.85
0.9
0.95
1
1.05
1.1
1.15
1.2
1.25
1.3
Use Factor (FU) NLL=0.2%
NLL=0.1%
NLL=0.05%
Figure 11–5 Percentage of Power Loss for Different Values of No-Load Loss (Po)
11-11
Low-Loss Transformers
Conventional Evaluation of Loss Capitalization and Optimal Transformer Design In order to perform an economical analysis of a transformer, it is necessary to calculate the life cycle of the transformer over its life span: that is, the total capitalized cost of the transformer. The most widely used technique for economic evaluations of transformers is the so-called total owing cost (TOC) method. The TOC method consists of determining the capitalized cost of the transformer’s losses over its lifetime and weighing that cost against its purchase price. The TOC is evaluated using the following formula: TOC = TC + A ⋅ NLL + B ⋅ LL
Eq. 11–7
Where: TOC: stands for total owing cost NLL = no-load loss in kW A = capitalized cost per rated kW of NLL (A factor) LL = load loss in kW at the transformer’s rated load B = capitalized cost per rated kW of LL (B factor) TC = the initial cost of the transformer, including such factors as transportation and sales Utilities assign an equivalent present value for the LL- and NLL-evaluation factors (A and B). Usually, the loss-evaluation figures A and B are submitted to the transformer manufacturers in the request for a quotation. The manufacturer then starts the complex design process to obtain a transformer design that performs best, using the same formula. The transformer that meets the transformer purchaser’s technical specifications with the lowest TOC becomes the most costeffective transformer. Based on the transformer loss-evaluation guide developed by the Transformer Committee of the IEEE [8], the A and B factors can be determined as follows [9]:
A = PWF ⋅ (SC + EC ⋅ AF ⋅ 8760 )
(
B = PWF ⋅ SC + EC ⋅ LF ⋅ CF 2 ⋅ 8760
Eq. 11–8
)
Eq. 11–9
In these formulas,
PWF =
(i + 1)n − 1 i ⋅ (i + 1) n
: Present worth factor
n: useful life of the transformer in years SC: Levelized annual cost of system capacity in $/kW. In the case of substation transformers, it includes the capacity cost of generation and transmission. EC: Levelized annual cost of energy in $/kWh
11-12
Low-Loss Transformers
AF: Transformer availability factor (the portion of time that the transformer is predicted to be energized) LF: Annual loss factor, as determined by Equation 11–2 CF: Levelized capacity factor. This is the levelized peak load per year over the lifetime of the transformer, referred to the transformer rated power. 8760: hours per year For large transformers, the capitalized cost of transformer auxiliary losses can be added to the TOC formula. The value of auxiliary losses is the same as the calculation of the NLL, except that the actual or estimated operating time is taken into account [8]. The determination of coefficients A and B is difficult because it is subject to a number of uncertainties, the principal ones being cost of energy, transformer loading, and transformer lifetime. The uncertainty in the future price of the transformer in the future is important if the economical study reveals that the replacement should be made some years ahead. Factors A and B, used by utilities to evaluate transformer bids, are widely dispersed nationally. They range from a low of A = $2/watt to a high of $13/watt. Higher values correspond to users who have updated their numbers recently, based on their current outlook for energy and capacity costs [16]. Typically, factor B is one third to one fourth the value of factor A. For example, Central Hudson Gas & Electric Corporation uses the following values for A and B coefficients: A = $6.97/watt and B=$1.64/watt [18]. A sensitivity analysis of the previous equations shows that the interest rate and the A factor have a negative correlation. This means that a higher interest rate leads to a lower A factor. Energy price and lifetime present a direct correlation. Load and energy price have a direct correlation in factor B, whereas interest rate presents the same behavior as that for factor A. The parameter that impacts factor A the most is the energy price, whereas the most influencing parameter on the factor B is the load [15]. Transformer Loading If the load of the transformer is considered to grow at a constant growth rate (such as can be true in the case of a distribution transformer), a close equation could be used to evaluate the levelized CF. In substation transformers, the transmission loading over the years may not follow the load growth pattern. Transformer loading can change substantially with changes in network topology resulting from transmission-system reinforcement, with the incorporation of new generation facilities, and with changes in operating conditions resulting from congestion or transmission security constraints. Generally, a long-term period is assumed for transformer economic evaluation (20–30 years). In some cases, it may not be possible or practical to determine the peak load for each study year by means of power-flow studies. In such cases, the transformer peak load for the first years is determined by power-flow studies and it is then projected for the following years, considering that the loading pattern will not change substantially. Usually, transformer loading stabilizes after some years as loads approach transformer rated capacity. The levelized C F is then determined by a three-step process: 1) determine transformer peak load for each year, 2) project peak load into future years (if necessary), and 3) take the present worth of each peak load and levelize it into the transformer’s lifetime.
11-13
Low-Loss Transformers
Transformer Investment Cost and Efficiency A transformer’s final price is an outcome of the design process, in which the cost of losses is included. Indeed, the customer provides the values of A and B, and the manufacturer integrates them into the cost of transformer design, seeking to optimize losses. The designer works out the best compromise between the initial cost and the power-loss expenditure. There is clearly a relationship between transformer cost and the amount of transformer losses. Indeed, by increasing the cross section of the winding conductor and/or the core, a wide range of transformer designs with lower losses can be achieved. The quantity of material will be higher, and so will the transformer cost. 1 The use of advanced materials and manufacturing processes for the core and winding to reduce losses (for example, laser-scribed steel to reduce NLL and finely divided transposed cable to improve LL) also increases the transformer’s cost. The designer evaluates options to improve transformer efficiency to a level that makes economic sense. For feasibility studies of loss-reduction measures, the estimated transformer price is very difficult to obtain; large transformers have unique characteristics, and it is therefore difficult to establish typical transformer prices. Basic parameters like voltage ratio and impedance, the loss evaluation, and subsequent material selections make each case a one-of-a-kind design. Besides, the cost of the transformer is usually based on a competitive tendering process. Cost estimates are even more uncertain if the transformer replacement is evaluated for future years. A transformer’s efficiency is inversely proportional to its total losses. These losses are affected mainly by the material quality (core steel) and the design (magnetic flux control). In general terms, a more efficient transformer will be heavier and have a higher investment cost, because more material is needed to reduce NLL and LL. However, this variation is not linear. For lowerimpedance transformers, short-circuit forces will set the amount of copper needed to withstand those forces. Transportation is also a big issue for large power transformers. Increasing the weight of the transformer may significantly increase the transportation cost (up to 30% of the transformer price). Therefore, in the evaluation of options for more-efficient transformers, not only transformer cost should be included in the total investment cost, but also all other costs incurred in a transformer installation (such as transportation and foundations). Cost of Environmental Externalities The above expressions of A and B coefficient do not account for the environmental cost of losses. As was stated in Section 3, the decision for the implementation of any particular project to enhance transmission energy efficiency should be based on a benefit/cost analysis from the point of view of the overall interests of society, which include the benefits from reducing the cost of energy losses, the investment in generation and transmission infrastructure, and the reduction in pollution and carbon emissions. In the case of substation transformers, a very high-efficiency transformer can be economically justified while yielding great benefits in energy savings, deferred infrastructure, and reduced emissions. Therefore, for the integral evaluation of highefficiency transformers as an option to reduce transmission losses in a cost-effective manner, the cost of environmental externalities should be included, as discussed in Section 4. If the TOC is to be used to evaluate design alternatives, emission costs need to be included in the A and B factors. 1
There is a balance in the degree to which copper and steel quantity can be augmented—for example, by increasing the conductor size, thus reducing LL but requiring a larger core (and with corresponding increases in NLL, because flux density does not vary).
11-14
Low-Loss Transformers
Transformer-Replacement Options Because large transformers are expensive pieces of equipment, it can generally be said that replacement of existing transformers with higher-efficiency transformers is only economically feasible if the replacement decision has already been made for other reasons—such as failure (that cannot be repaired), age, or under-capacity. In some cases, however, replacing old transformers with high-loss steels before end-of-life may be economically sound. The older the transformer (iron losses have improved to one-fifth their value in the past 80 years), the easier will be the effort to justify the cost of the new transformer. Several reports suggest that if the unit is more than 35 –40 years old, the cost of NLL will be too high to consider keeping the unit, in comparison to the significantly lower losses of a modern unit [6]. Usually, the replacement decision and options are determined by a utility’s assets-management division. Assets management consists of decision-making processes that have the goal of deriving the most value from utility assets within the available budget. Assets managers have responsibility for valuable and technically complex assets such as transformers that are crucial to the operating and financial performance of a utility. The decision to replace or repair an important asset such as a large transformer is quite complex. It requires an intimate understanding of corporate risk tolerance, current investment strategy, and the prevailing business and regulatory environment. The risk-cost of continuing to operate the asset under the existing conditions is of major importance. Therefore, power transformers are a major concern, because each unit serves a large number of customers; its failure will result in a loss of service—including considerable expenses associated with lost revenue, replacement, or other collateral costs. A body of literature on asset-management theory and practice is available. The Cigre report [14] presents a guide to help transformer assets managers perform economic evaluations of proposed solutions. EPRI has conducted an intense investigation related to asset-management in the electricity industry. A significant focus of EPRI’s asset-management research in recent years has been on developing a rational basis for selecting repair or replacement options for specific classes of equipment by balancing the risks of equipment failure against the costs of continued maintenance or capital replacement. In a recent report [13], EPRI presents a decision framework that enables utilities to generate business cases for asset-management policies. The framework takes a life-cycle costing approach that enables corporate financial managers and regulators to assess the multi-year financial impacts of maintaining specific classes of power-delivery infrastructure assets, such as substation transformers. The analytical tools presented in the above report share a basic framework for decision-making that specifies the evolution of the condition of the asset population over time, the various decision alternatives that are available (including testing), and the basic data needed to support the decision model. It is clear from the above discussion that the economics of transformer management—and consequently transformer replacement— is a complex process, which will vary significantly from one utility to the other. Considerations about the use of higher-efficiency transformers as an option to replace existing units should be embedded into the utility’s asset-management procedure and practice. A simplified general approach for evaluating replacement with higher-efficiency transformers is presented below. Table 11–2 presents a situation in which the option of using a more-efficient transformer can be evaluated. 11-15
Low-Loss Transformers Table 11-2 Description of Options for Transformer Replacement
Situation • • •
Failure (no repair ) Age Under-capacity
• •
Failure Trouble unit
Transformer Replacement Decided?
Yes
No
•
Early replacement to improve efficiency
No
Decision to Take the Unit Out of Service
Yes
Yes
No
Options
Decision-Making Criterion
•
New lower-efficiency transformer • New higher-efficiency transformer
•
•
Repair (reinsulation, rewinding, refurbishment) • New lower-efficiency transformer • New higher-efficiency transformer
•
Replace with a new moreefficient transformer at a different point of life than the existing unit
•
Less life-cycle cost • Externalities: CO2 value Less life-cycle cost • Externalities: CO2 value
Less life-cycle cost • Break-even point • Externalities: CO2 value
A) Replacement Decided In this case, the unit replacement has already been decided upon for different reasons—such as completion of life, failure or damage that cannot be repaired, or the need for higher capacity. In this situation, the decision is whether to purchase a low-cost, less-efficient transformer or a more-expensive, energy-efficient transformer. The TOC procedure, as presented above, applies to this case. A more comprehensive evaluation, including not only price and loss capitalization, but also transportation risks, interchangeability, environmental considerations, maintenance, and spare optimization can be conducted. B) Failure or Trouble Unit The decision in this case is whether to replace the trouble transformer with a new unit, or to repair it now and replace it later. The options are:
•
•
Full repair: –
Reinsulation
–
Rewinding
–
Refurbishment
New transformer
Clearly, the possibility of applying different repair options will depend upon the damage to and conditions of the existing unit. Reinsulation can result in longer life and increased capacity if insulation with a higher temperature capability is used. Rewinding a transformer can result in increased life and reduced losses if the windings are replaced with a larger conductor or an 11-16
Low-Loss Transformers
advanced conductor design. The cost of rewinding can be significantly less than the cost of replacing an existing transformer with a new unit. Refurbishment involves minor replacement of transformer parts such as connectors, nuts, gaskets, and bushings. Refurbishment is intended to extend transformer life and is usually done on-site. The decision of whether to replace a transformer with a new unit or to repair it is an economic one. It involves weighing the increased life-span and reduced losses resulting from replacing the existing unit against the cost of replacing it. The economic analysis is performed by comparing the life-cycle cost (LCC) of each option. In the LCC analysis ,the present values for capital and energy are calculated by taking the present value of the capitalized TOC. Comparing transformer costs using present values or capitalized cost does not change the comparison, although the absolute values would be different. The LCC analysis in this case is based on the assumption that the transformer is taken out of service, either to repair it or replace it. Therefore, the costs of reinstalling the transformer is the same for both alternatives, and it is not included in the analysis. The TOC formula is used to determine which option is the most cost-effective. The cost of replacement is dependent on whether the unit is to be replaced with a new unit or to be repaired. If the unit is to be replaced rather than repaired, the scrap or residual value of the old unit needs to be included in the TOC formula. The scrap value is subtracted from the cost of a new unit. The scrap value is dependent upon the condition of the older unit and whether the unit can be sold and recycled. Note, however, that the remnants of a failed unit can have both positive and negative implications on the repair or replace decision. The unit may have a scrap value; however, this value may well be offset by the cost of disposing of the potentially contaminated parts and clean-up services. In the case of unit repair, there is no cost associated with salvage. However, if the option is to repair now and replace later, the salvage cost can be considered at the time the repaired transformer is replaced by a new unit. In this case, the extended lifetime of the repaired unit needs to be estimated to determine the timing of the later replacement. Therefore, the economic analysis consists of evaluating:
•
TOC of the replace-now option
•
TOC of the repair-now-and-replace-later option (more than one repair option can be considered)
•
Comparison of the TOCs of the different options
In order for the LCC comparison analysis to be consistent, the same analysis period should be considered for the different options. The analysis period can be considered as the lifetime of a new transformer (that is, if one chooses the replace-now option). The following formulas can be applied:
• Option 1:Replace now. In this case, the TOC formula (Equation 11–7) is modified to include the salvage value of the existing transformer. Thus, the TOC for the replace-now (RN) option is TOCRN = Cost of new transformer – salvage value + (Cost of NLL of replacement) + (Cost of LL of replacement) Eq. 11–10
11-17
Low-Loss Transformers
• Option 2: Repair now and replace later. TOC RL = RC + A RT ⋅ NLL RT + B RT ⋅ LL RT +
1 (1 + i) N
(K Nn ⋅ TC NT − SVRT ) +
Eq. 11–11
+ A NT ⋅ NLL NT + B NT ⋅ LL NT
Where: TOCRL: total owing cost of the replace-later option RC: cost of repair N: expected lifetime of the repaired transformer n: total analysis period (the useful lifetime of a new transformer NLLRT = no-load loss of the repaired transformer in kW LLRT = load loss of the repaired transformer in kW at the transformer’s rated load ART = capitalized cost per rated kW of NLL for the repaired transformer (A factor) BRT = capitalized cost per rated kW of LL for the repaired transformer (B factor) TCNT = cost of purchasing a new transformer in year N SVET = salvage value of the repaired unit in year N transformer K Nn =
n−N : multiplier to lower the investment cost of the new transformer in year N n
A RT = PWFRT ⋅ (SC + EC ⋅ AF ⋅ 8760 ) : no-load factor for the repaired transformer
(
)
B RT = PWF RT ⋅ SC + EC ⋅ LF ⋅ CF 2 ⋅ 8760 : load factor for the repaired transformer
A NT = PWF NT ⋅ (SC + EC ⋅ AF ⋅ 8760 ) : no-load factor for the new transformer installed in year N
(
)
B NT = PWF NT ⋅ SC + EC ⋅ LF ⋅ CF 2 ⋅ 8760 : load factor for the new transformer installed in year N In these formulas,
PWF RT = PWF NT =
(i + 1)N − 1 i ⋅ (i + 1) N
: present-worth factor for the lifetime of the repaired transformer
(i + 1)n − 1 (i + 1)N − 1 i ⋅ (i + 1) n
−
i ⋅ (i + 1) N
: present-worth value of the period (n–N) for the new
transformer installed in year N. SC: levelized annual cost of system capacity in $/kW. (In the case of substation transformers, it includes the capacity cost of generation and transmission.) 11-18
Low-Loss Transformers
EC: levelized annual cost of energy in $/kWh. AF: transformer-availability factor (the portion of time that the transformer is predicted to be energized) LF: annual loss factor, as determined by Equation 11–2 CF: levelized capacity factor. (This is the levelized peak load per year over the total analysis period (n years), referred to the transformer rated power. 8760: hours per year Table 11–3 describes the costs considered in Equations 11–10 and 11–11 for the calculation of TOC [9]. Table 11-3 Evaluation Process for “Repair-Now-And-Replace-Later” Option Costs to Consider Year
Option 1: Repair-Now AndReplace-Later
Option 2: Replace-Now
1
Repair cost plus levelized energy of repaired transformer
Levelized energy and capital cost of new transformer
2 to N
Levelized energy of repaired transformer
Levelized energy and capital cost of new transformer
N
Takedown and reinstall cost plus levelized energy and capital cost of new transformer
Levelized energy and capital cost of new transformer
N to n
Levelized energy and capital cost of new transformer
Levelized energy and capital cost of new transformer
The “replace-now” option eliminates the repair takedown and reinstalling cost in year N. Also, it allows the utility to reduce loss cost in years 2 through N if the new transformer is more efficient than the existing one. Losses from year N+1 to n are the same in both alternatives. In the “repairnow-and-replace-later” option, present value will be less than in the “replace-now” option when the capital cost of the new transformer can be sufficiently delayed. The cost-effectiveness of the two alternatives is a weighing of the value of energy efficiency against the remaining life of the repaired transformer. C) Early Replacement to Improve Efficiency The objective in this case is to evaluate whether it is cost-effective to replace an existing transformer with a more-efficient transformer. The basic assumption here is that the existing transformer does not need to be repaired or replaced, and that it can be in use as it is up to the end of its expected life. The calculation in this case involves determining if the present value (PV) of early replacement of the existing transformer is more than offset by the present-worth savings of installing a more-efficient transformer. The analysis is aimed at determining the break-even point, which is the point in time in the transformer’s remaining life when it becomes cost-effective to do the replacement. The breakeven point is determined by calculating the PV of the TOC of the replacement, assuming various times of replacement. The TOCs calculated for these various replacement times are then 11-19
Low-Loss Transformers
presented in a graph: TOC versus year of replacement. This exponential curve is compared with the straight-line TOC of replacing the existing transformer when it reaches its life expectancy. The point at which these two curves intersect one another is the break-even point. If the remaining life of the existing transformer is greater than the break-even point, then it is costeffective to replace the existing transformer with a more-efficient one. Equation 11–11 can be used in this case to determine the break-even point and compare alternatives. The repair cost (RC) is set to zero, because the basic assumption is that the transformer does not need to be replaced or repaired before its lifetime is over. The total period analysis (n) could be selected as the expected lifetime of a new transformer, so that the extreme option of replacing the transformer in year 1 (N=1) is covered. Reliability Consideration The simplified approach for evaluating transformer-replacement options described above does not include the costs associated with expected transformer failure. The impact of reliability on transformer economics can be accounted for by including the cost of failure in the TOC. TOC = initial cost + failure cost + no-load-loss cost + load-loss cost The cost of failure should reflect not only the cost of repairing or replacing the failed unit, but also the expenses resulting from the loss of service and other collateral costs. This cost is weighted by the transformer failure rate to take into account the probabilistic nature of transformer failure. Energy-efficient transformers tend to be more reliable. This is because energy-efficient transformers have less losses and internal heating. The lower heating reduces the deterioration of the insulation and extends the life of the transformer. Therefore, consideration of reliability cost may positively impact the decisions to replace aging transformers with energy-efficient transformers.
References [1].
DOE, Energy Conservation Program for Commercial Equipment: Distribution Transformers Energy Conservation Standards: Final Rule, 2007.
[2].
Oakridge National Laboratory, Determination Analysis of Energy Conservation Standards for Distribution Transformers. ORNL–6847, July 1996.
[3].
Intelligent Energy Europe, Selecting Energy Efficient Distribution Transformers – A Guide for Achieving Least-Cost Solutions. Project No. EIE/05/056/SI2.419632, June 2008.
[4].
ABB, Transformer Handbook, 2007.
[5].
Abderaahmane Zouaghi, “Power Transformer Efficiency.” EPRI’s Green Transmission Efficiency Initiative Regional Workshop Series, Dallas–Fort Worth, TX (May 20, 2009).
[6].
CIGRE, Transformer Technology State of the Art and Future Trends. Electra Nr. 198, Oct. 2001.
11-20
Low-Loss Transformers
[7].
CIGRE, Power Transformers Technology Review and Assessments. Report AG A2.4, Electra Nr. 236, 2008.
[8].
IEEE C57.120–1991 (R2000), IEEE Loss Evaluation Guide for Power Transformers and Reactors.
[9].
Barry W. Kennedy. Energy Efficient Transformers. McGraw Hill 1998.
[10].
Distribution System Loss Evaluation, Reduction, Technical and Economic Assessment. EPRI, Palo Alto, CA: 2008. 1016096.
[11].
Amorphous Steel Core Distribution Transformers. EPRI, Palo Alto, CA: 1992. TR100295.
[12].
NEMA Standards Publication, Guide for Determining Energy Efficiency for Distribution Transformers. TP 1–2002.
[13].
Substation Transformer Asset Management and Testing Methodology. EPRI, Palo Alto, CA: 2006. 1012505.
[14].
CIGRE, Guide on Economics of Transformer Management. WG A2.20, June 2004.
[15].
N.K. Haggerty, T.P. Malone, and J. Crouse, “Applying High-Efficiency Transformers,” Industry Applications Magazine. IEEE Vol. 4, Issue 6, pp.50–56 (Nov/Dec 1998).
[16].
Amorphous Metal Transformer: Next Steps. EPRI, Palo Alto, CA: 2009. 1017898.
[17].
Eleftherios I. Amoiralis, Marina A. Tsili, Pavlos S. Georgilakis, and Antonios G. Kladas, “Energy Efficient Transformer Selection Implementing Life Cycle Costs and Environmental Externalities.” 9th International Conference, Electrical Power Quality and Utilization, Barcelona (October 2007).
[18].
David Dittmann, Central Hudson Gas & Electric Corp., “Reducing Electric System Losses.” NYS DPS Technical Conference (July 17, 2008).
[19].
Manuel Silvestre, EFACEC Power Transformers Inc., “Potential for Improved Transformers Efficiency.” EPRI’s Green Transmission Efficiency Initiative Regional Workshop Series, Atlanta, GA (June 15, 2009).
11-21
12
HIERARCHICAL DYNAMIC VOLTAGE CONTROL TO HELP REDUCE TRANSMISSION LOSS This section discusses the concept of reducing transmission losses by controlling the voltage of certain predefined busses in the system. The main emphasis of this section is the reduction in transmission loss that can be achieved from the hierarchical dynamic voltage control based on the decrease of megavolt amperes reactive (MVAR) flows in the system.
This section covers issues such as:
•
The present methods of controlling transmission busses in the United States, which may not lead to minimum system efficiencies
•
The alternate approaches for voltage control and reactive power management: hierarchical dynamic voltage-control technologies that have been developed and deployed at control centers in France, Italy, Belgium, and China
•
The methodology of a typical hierarchical voltage control, the main elements of which are based on –
Primary (local) voltage regulation
–
Secondary (regional) voltage regulation
–
Tertiary (system-wide) voltage regulation
•
Simulation results from Italy quantifying the system loss-reduction
•
A cost/benefit analysis of the application of a hierarchical control system
•
Estimation of the possible savings for application in the United States
Introduction In North America, transmission-grid voltages and reactive powers are at present mainly controlled in a decentralized way, at the power plant/substation level. In the control center, system operators may manually dispatch the reactive powers of generating units, schedule the high-side voltages of power plants, switch the banks of shunt capacitors or reactors, and change the voltage set-points of on-load tap changers (OLTC) and FACTS controllers. However, it is difficult for system operators to optimally coordinate these control actions at the system level under ever-changing operating conditions. Without system-wide coordination and optimization, massive MVAR flows may frequently occur to maintain voltage reliability of weak-voltage areas using remote reactive power sources. As a result, transmission losses will be increased. Even worse, system loadability in terms of voltage stability may be degraded and increase the risk of voltage collapse. 12-1
Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss
Since the 1980s, aiming at more-efficient automatic voltage control and reactive power management, hierarchical dynamic voltage-control technologies have been developed and deployed at control centers in Europe and China [1–9]. These technologies can help to significantly reduce the risk of voltage insecurity and transmission loss by temporarily and spatially hierarchical optimization and coordination of reactive power resources. In Brazil, similar coordinated voltage-control concepts are also under consideration [10]. In North America, concepts about hierarchical dynamic voltage control have received academic attention, but only limited consideration by power companies. The purpose of this section is to give an overview of hierarchical dynamic voltage-control technologies (including the methodology of a representative three-level voltage-regulation strategy) and existing solutions and implementations in Europe and China, along with their advantages in improving voltage reliability and energy efficiency.
Methodology of Hierarchical Dynamic Voltage Control A typical hierarchical dynamic voltage-control strategy adopts three voltage-regulation levels, as shown in Figure 12–1:
•
Primary (Local) Voltage Regulation Primary voltage regulation is performed by dispersed primary voltage regulators (PVRs), which are local voltage-control devices installed at power plants or substations, which remotely receive commands from the upper-level control programs via communication channels (for example, generators or synchronous compensators fitted with automatic voltage regulators (AVR), static VAR compensators, the capacitors and reactors involved in automatic voltage control, and automatic load tap changers). The time scale of this regulation level ranges from 100 ms up to several seconds.
•
Secondary (Regional) Voltage Regulation The transmission grid is divided into voltage-control zones. A secondary (regional) voltage regulator (SVR) (that is, a voltage control program) performs the coordination of control resources within each voltage-control zone, aiming at improving voltage quality and reliability. In each zone, a number of pilot buses are chosen whose voltages can be used to represent the voltage profile of the entire zone. The SVR is responsible for adjusting the set-points of all the PVRs to minimize the differences between the pilot buses’ actual voltages and their optimal voltage references, as determined by tertiary voltage regulation. The setpoints are adjusted either automatically by the SVR (for automatic closed-loop voltage control) or manually by the operator, using the SVR’s outputs as references. The actual voltages of pilot buses are obtained either from the SCADA system or via special measurement devices and communication channels. Typically, each SVR is implemented every one to a few minutes.
•
Tertiary (System-Wide) Voltage Regulation At the top, system-wide optimization and coordination are performed by a tertiary (central) voltage regulator (TVR) (that is, a central control program). The TVR dynamically provides each SVR with the optimal voltage references at the pilot buses of that voltage-control zone. These optimal voltage references are determined by solving
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Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss
optimal reactive power flow (ORPF) according to the current state estimation result (and probably its future changes, foreseen over a certain period). The optimization objective could be to minimize the overall transmission loss. In order to preserve temporal independence from SVRs, the response time of the TVR is slower (typically, every 10 minutes to 1 hour for automatic closed-loop tertiary voltage regulation). Figure 12–2 presents the interactions between the three voltage-regulation levels. In each voltage-control zone, the TVR and SVRs can both be installed at the grid-control center (as indicated in Figure 12–1), or be installed at the grid-control center and subgrid-control centers of voltage-control zones, respectively.
Figure 12–1 Typical Structure for Hierarchical Dynamic Voltage Control
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Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss
Figure 12–2 Typical Closed-Loop Hierarchical Dynamic Voltage-Control Strategy
Existing Solutions of Hierarchical Dynamic Voltage Control Although hierarchical dynamic voltage control theoretically utilizes three levels to ensure both reliable and economic voltage regulation, utilities may customize their solutions. This section briefly introduces different hierarchical dynamic voltage-control solutions in Belgium, France, Italy, and China. Solution in Belgium Coordinated voltage control has been in operation since 1998 to support the Belgian grid. Every 15 minutes, or upon request (for example, following important disturbances), a tertiary voltage control (TVC) scheme is computed, using an optimal power flow with dedicated objective function. It optimizes generator reactive reserve geographic spread, transformer tap setting, and shunt capacitor bank switching under constraints of voltage limits and reactive power area balance. Conceptually, voltage control is considered as having a hierarchical structure, including a primary generator (AVR), a secondary, and a tertiary level. The SVR controls the voltage of a pilot bus in each zone by modifying the set-points of neighboring generators, typically at a 10second rate. As in normal operation, the discontinuous (discrete) measures (capacitors and tap changers) can be adjusted at a much slower rate. If interactions between neighboring zones occur, the SVR algorithm has to take them into account. The TVC optimizes the voltage over the whole control area, using an ORPF. The TVC automatically runs at regular time intervals (for example, 15 minutes) or at a dispatcher's request (for example, following a disturbance). It commands all voltage-control measures and provides 12-4
Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss
the SVR parameters (for example, pilot bus voltages).The voltage/reactive power policy must be translated in a mathematical form suited to the optimization tool that will be used. The main goal of the alignment objective function is to spread and maximize the reactive reserves of the different generators taking part in the voltage control of the system. The correct operation of this core objective requires that the global import-export balance of reactive power from the neighboring systems tends to zero MVAR. Different constraints are used for the reactive power delivered by the generating units, the voltages in the system, the import/export of reactive power globally, and on a line-by-line basis. These constraints can be hard or soft, depending on the case and the circumstances.
•
Hard Type: Generators must operate within their declared capabilities but could be modified transiently, taking into account particular situations at the generator level. These constraints are of the hard type.
•
Voltage limits: These are managed as soft constraints, imposed by penalties.
•
Optimization Process: The actual optimization is carried out by linear programming.
Experience from the Belgian System The TVC manages to realize a geographically flat voltage level within a 3% margin with respect to the maximum voltage level allowed by the equipment manufacturers. Standardization of the voltage drop of generator AVR to ± 10% HV voltage drop on rated MVAR scale yields a fairly robust automatic reaction to grid disturbances. This measure minimizes necessary TVC runs in between the regular quarter-hour calculations. The TVC manages to require only a limited number of transformer tap-changer actions (typically a 5–10% daily rise and fall of the transformer winding ratio). The introduction of a one-tap-wide dead band has proven to be sufficient to eliminate transformer tap oscillations. A 15-minute computation frequency of the TVC has proven sufficient, mainly because of a judicious standardization of AVR voltage drop.TVC closed-loop operation is the long-term goal. It will depend upon the amount of confidence that the TVC proves to deserve in reality. Solution in France The hierarchical dynamic voltage control on French extra-high-voltage (EHV) networks operates at three levels: primary voltage regulation, secondary voltage regulation, and tertiary voltage regulation. However, these levels are temporally and spatially independent and do not interact with each other, so as to avoid risking oscillation or instability [11]. The SVR system, which has been widely implemented since 1979, involves splitting the network up into theoretically noninteracting voltage-control zones, within which voltage is controlled individually. This level has a response time of a few minutes and compensates against slower voltage variations. A faster and more precise type of SVR system—coordinated secondary voltage regulation (CSVR)—has been in use in western France since 1998, and it is eventually expected to take over from the existing SVR system. At the top level, a TVR is applied to optimize the nationwide voltage profile. This measure involves determining optimal voltage references for the pilot nodes in order to achieve reliable and economic system operation. The TVR is designed to act around every 20 minutes, but at present it is not automated.
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Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss
Solution in Italy
Figure 12–3 Italian Hierarchical Voltage-Control System [11]
In Italy, 1 a hierarchical voltage control system (Figure 12–3) is being tested [11–14]. The system is an automatic voltage-regulation system with a distributed controller. This system is constituted of regional voltage regulators (RVR) that coordinate the operation of more local SVR controllers. The SVR controllers work through hardware called REPORT controllers to update the voltage set-points for the AVR on electric generators. If the system had static voltage compensators (SVC) and/or static synchronous compensators (STATCOMs), the REPORT controllers would also control their reference voltage settings. At the top level of the hierarchy is a slow controller (operating time in minutes) called a TVR that sends signals to switch capacitor and reactor banks and to block or unblock the operation of OLTC for distribution transformers. The TVR has to have a preferred voltage profile for the system. This situation is achieved by having an ORPF for losses-minimization control (LMC). This power-flow software computes—in short (the day ahead), or very short (minutes ahead), time intervals—the forecasted optimal voltages and reactive levels, starting from the foreseen/current state estimation. The basic concept for this system is that voltage control for a country can be achieved by regulating the voltage at a relatively small number of critical points called pilot nodes. Network busses that have a very high electrical coupling define a network area (NA). The NA pilot node is the bus that is able to strongly affect the voltage of the other busses in the NA. The selection of pilot nodes is critical to the success of the control scheme. Intuitively, these nodes must be strongly coupled to the surrounding nodes so that a change in voltage at the pilot node will be reflected throughout the area. However, there should be minimum coupling between adjacent pilot nodes to minimize their interaction and simplify the control. The pilot node also should remain a pilot node during reasonable contingencies that remove transmission lines or
1
Peak load about 55,000 MW.
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Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss
generating plants. Obviously, there are contradictions among these desired characteristics, and the selection of pilot nodes is somewhat of an art. The pilot nodes in the Italian system were chosen based on short-circuit capacities and on a concept called sensitivity-matrix couplings. The bus with the highest short-circuit capacity was chosen as the first pilot node. The sensitivity matrix expresses the dependence of the grid's bus voltages on reactive power injections with primary voltage regulation operating. It is likely formed by injecting a defined amount of reactive power at a prospective pilot node and computing the change in bus voltage at other busses in the network. Busses with the highest coupling coefficients are considered to be within the NA. Busses with low coupling coefficients are outside the area. After an area is defined, all busses in the area are eliminated from further consideration, and the process is repeated by selecting the bus outside the area with the highest short-circuit capacity as the next pilot node. To minimize interaction between control levels, the proportional and integral gains are generally chosen to provide the shortest time constant at the lowest control level and so that the time constants at the next higher level are about an order of magnitude longer. In the Italian system, the shortest time constant is the closed-loop control of generator voltage provided by the AVR. Including generator time constants, this control loop has a time constant of about 0.5 seconds. The integral gain for the REPORT control that changes the voltage reference for the AVR is set to provide a time constant of about 5 seconds. The next higher-level control in the SVR establishes the desired reactive power level for the REPORT controllers, and its gains are established to provide a time constant of about 50 seconds. The pilot-node voltage references are automatically set by a TVR that performs a real-time optimization analysis that may be updated approximately every 5 minutes. The Italian power system—with a peak load of 55,000 MW and a reactive capability of about 20,000 MVAR's—was subdivided into 18 regions, each with a pilot node and an SVR controller (see Figure 12–4 from [12]). The SVR directs REPORT controllers located at the major thermal and hydro generating stations. The REPORT controllers change voltage-reference settings for AVR's on individual generators.
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Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss
Figure 12–4 Italian Control Areas for Secondary Voltage Regulation
Solution in China In China, research and development activities on hierarchical dynamic voltage-control applications were started in the early 1990s. A three-level automatic voltage-control (AVC) strategy was developed by Tsinghua University [16–17] and implemented in Jiangsu Provincial Grid in 2002 [18]. So far, it has been deployed at three regional (North Cnina, South China, and East China) grids whose total capacity exceeds 300GW, 10 provincial grids, and more than 20 area grids. 2 An off-line evaluation study of the strategy’s potential profits to the PJM power system is ongoing, using recorded real system data [17]. China’s hierarchical AVC strategy adopts the typical system architecture in Figure 12–5 and has the following features: 2
China’s power grids are operated at multiple levels. The top three levels are following: 1) Regional grids, whose control centers monitor and control main substations/power plants and interprovince tie lines at 500kV 2) Provincial grids, whose control centers are responsible for provincial transmission systems at 500/220kV 3) Area grids, whose control centers are responsible for transmission systems at 110kV and below
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Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss
•
The TVR performs an online zone division algorithm to generate adaptive voltagecontrol zones adapting to system operating conditions, which is more suitable for the fast development of Chinese power grids than fixed-zone divisions. Once control zones are determined, SVRs will be reconfigured for those zones.
•
For each zone, the SVR optimizes the set-points of the high voltages of power plants and VAR compensators, based on measurement data and sensitivity analysis instead of stateestimation results.
•
The expectation is to implement the AVC strategy at each grid level. The AVC strategy for a power grid receives control actions from the AVC strategy at its highest level and is able to coordinate the AVC strategies for multiple lower-level power grids. For example, the AVC strategy at a regional power grid not only controls the set-points of its main power plants but also coordinates the AVC strategies at the provincial power grids in its region.
In November 2002, the AVC strategy was the first open loop implemented in Jiangsu Provincial Grid, which has the largest generating capacity (about 30GW) among all provincial grids. “Open loop” means that the strategy provided operators with suggestions of the PVRs’ set-points as references for voltage control. In December 2003, both secondary and tertiary voltage regulations were implemented in closed loops involving 17 main power plants (as shown in Figure 12–5 from [17]), whose total generating capacity is 13.6 GW. Figure 12–6 from [19] shows two control-zone division strategies, generated on-line by the TVR under two operating conditions: four zones and five zones, respectively. ORPF is solved on the network with 407 buses and 478 branches. The average CPU time is 0.2 second.
Figure 12–5 Main Power Plants Controlled by Jiangsu Provincial Grid’s AVC Strategy
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Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss
Figure 12–6 Two Zone-Division Strategies Generated by the TVR of Jiangsu Provincial Grid
Another larger-scale application of the AVC strategy is in the North China Regional Grid, which covers Beijing and has a total generating capacity of 119 GW [20]. The strategy was closed-loop implemented in February 2007 at the regional control center. The computer system adopted an Alpha DS25 Server with a 1-GHz CPU and 4G RAM. The following power plants and substations are controlled by the AVC strategy, whose locations are indicated in Figure 12–7 from [17]:
•
Ten main power plants (including 35 units), whose generating capacity is 16.6 GW (53.6% of the grid’s total capacity)
•
Fourteen 500-kV substations with 4.6 -GVAR capacitors, 3.3-GVAR reactors, and one condenser of -80MVAR~160MVAR
Figure 12–7 Main Power Plants Controlled by North China Regional Grid’s AVC Strategy
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Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss
North China Regional Grid’s AVC strategy generates around eight control zones controlled by the TVR. Every 15 minutes~1hour, TVR solves the ORPF of a backbone network with 622 buses and 994 branches. The computation can be finished within 0.05s and can reach a convergent solution at 90% probability. The SVR in each control zone is performed every 5 minutes, whose computation can be finished within 1 second. Voltage accuracy at pilot buses is <1.0kV. The AVC strategy is interfaced with a voltage stability assessment (VSA) program, which is run every 3 minutes to perform simulations for 755 critical contingencies. The VSA program helps examine the control effects of the AVC strategy and calculate the stability margin of each zone.
Voltage Profile/Stability Improvement
Figure 12–8 Load Margins at Two Key Substations: Solid Line = PVRs Only; Dotted Line = PVRs and SVRs; Dashed Line = PVRs, SVRs, and the TVR
In Italy, studies show that the hierarchical voltage-control system can help increase the overall loadability of the transmission system by secondary and tertiary voltage regulations. Some case studies are performed in [12]. The studies on power-voltage (P-V) curves reveal significant improvements in voltage stability. As shown in Figure 12–8 from [12], load margins of 200 MW and 300 MW, respectively, are increased at two key buses: Roma Nord and Roma Sud, in the Rome control area. A simulation study has been done at the overall Italian network, and it involves an increase in load ramps at all the nodes. Because of secondary and tertiary voltage regulations, the largest amount of load-margin increase achieves 1500 MW for the overall Italian grid. 12-11
Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss
In China, hierarchical voltage control helps improve voltage profiles in power grids of multiple levels. Figure 12–9 from [17] gives an example in Jiangsu Provincial Grid. The green dashed curve and red solid curve are real one-day voltage measurements at one pilot bus (the LI YUAN 220-kV substation), which are from the records of two dates—before and after the AVC strategy was implemented, respectively—under similar operating conditions in order to compare the performance of the AVC strategy. Without the AVC strategy, the voltage at this bus changed between 232.6 and 236.5 kV, and the voltage variation was up to 3.9 kV (1.7%). With the AVC strategy, the voltage was controlled to 233.6~235.6 kV, and the variation was reduced to 2.0 kV (0.8%).
Figure 12–9 Comparison of the Pilot Bus Voltages (Unit: kV), With and Without Hierarchical Dynamic Voltage Control, in Jiangsu Provincial Grid
Transmission Loss-Reduction Another benefit from implementation of hierarchical dynamic voltage control is the reduction of transmission loss thanks to the decrease of MVAR flows achieved by system-wide optimal reactive power management. For the Italian power system, the main objective of the planned hierarchical voltage control system is to minimize transmission loss in the grid. Recent statistical analyses conducted on the Italian power system show that application of the hierarchical voltage-control system (with secondary and national voltage regulations) allows a transmission loss-reduction of about 4~6%, as shown in Figure 12–10 from [12].
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Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss
Figure 12–10 Expected Transmission Loss-Reduction in Italian Power System
In the Jiangsu Provincial Grid, a reduction of about 5% in transmission loss is achieved by the AVC strategy, which leads to a cost savings of more than $5M/year for Jiangsu Electrical Power Company. Figure 12–10 from [17] shows the transmission loss curves on two dates before (the blue dashed curve) and after (the red solid curve) the AVC strategy was implemented. The operating conditions are close. For this case, the AVC strategy achieves an average transmission loss-reduction of 23.1 MW (9%).
Figure 12–11 Transmission Loss-Reduction in Jiangsu Provincial Grid
An evaluation study of China’s AVC strategy on the PJM system shows that the strategy can help reduce transmission loss. Figure 12–12 from [21] compares the transmission losses for eight power-flow profiles with and without the AVC strategy. The loss-reductions are from 12.6 MW to 21.3 MW. The average percentage reduction is around 1.1%. For the example of a 2-MW lossreduction, the energy savings would be 184 M kWh/year. If the electricity rate is $0.08/kWh, the expected cost savings would be $14.7 M/year for PJM.
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Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss
Figure 12–12 Transmission Loss-Reductions in an Evaluation Study on the PJM System (Unit: MW)
Cost/Benefit Analysis A cost/benefit analysis is performed in [11] and [12] for the Italian hierarchical voltage-control system, considering a reference application involving 35 large power plants, 20 controlled grid stations, 3 regional dispatchers, and 1 national control center. Assuming an application lifetime of 25 years and a discount rate (minus inflation) of 12%, the capital and operational costs related to 50 REPORTs and 3 RVRs for the SVR and 1 TVR are summarized in Table 12–1. The annual capital cost would be €2.58 M and the annual total cost would be around €4.4 M, including operational costs.
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Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss Table 12-1 Summary of Capital and Operational Costs (Currency: €)
Itemized Capital Costs
Capital Costs
Studies, design & software development
5.6 M
Apparatus manufacturing & testing
6.2 M
Installation, AVR modifications & tests
6.2 M
Total Capital Cost
18.0 M
Annual Capital Cost (for 25 years)
2.58 M
Operational Annual cost for maintenance and upgrading of tools, Costs control apparatuses, and telecommunication equipment Annual cost for voltage/reactive operations at regional dispatchers/national control center Annual Total Cost
0.775 M
1.045 M
4.4 M
A prudent value estimation of the achievable benefits is €14.25 M savings per year due to the following factors:
•
Reduction of up to 5% of the MW losses in the power system by containing MVAR flows through better coordination of reactive power resources
•
Reduction of about 3%~5% in the duration of partial lack of loads feeding (for operational security reasons), due to the increase in reactive power reserves made available for facing the network transients determined by large perturbations
•
Reduction of about 20% of the time when contractual voltage quality at the customers’ end is not guaranteed
•
Increase in MW-transfer capability, under suitable operational security constraints
•
Reduction of the risk of blackout due to voltage collapse.
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Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss Table 12-2 Cost/Benefit Data
A cost/benefit analysis based on the above data gives interesting results, as shown in Table 12–2. The payback period of the hierarchical voltage-control project for an application on a large network is shorter than the duration of the project itself. Each partial realization (REPORT or RVR) can also operate autonomously, regulating the local power plant or pilot node voltage as soon as it is put into operation. Another comparison of the hierarchical voltage-control solution with another ideal SVC-based solution for voltage control and reactive power management on the real Italian power system, under the same operating standards, can be found in [12]. The cost for the hierarchical voltagecontrol solution is 34.3% less.
References [1].
V. Arcidiacono, “Automatic Voltage Reactive Power Control in Transmission System,” in Proc. CIGRE-IFAC Survey Paper E, Florence, Italy (September 1983).
[2].
S. Corsi, “The Secondary Voltage Regulation in Italy.” In Panel Session–2000. IEEE PES Summer Meeting, Seattle, WA.
[3].
S. Corsi, M. Pozzi, U. Bazzi, M. Mocenigo, and P. Marannino, “A Simple Real-Time and On-Line Voltage Stability Index Under Test in Italian Secondary Voltage Regulation,” Proc. CIGRE, Paper 38–115 (2000).
[4].
J. P. Paul, J. Y. Leost, and J. M. Tesseron, “Survey of secondary voltage control in France: Present Realization And Investigation,” IEEE Trans. Power Syst. Vol. 2 (May 1987).
[5].
H. Lefebvre, D. Fragnier, J. Y. Boussion, P. Mallet, and M. Bulot, “Secondary Coordinated Voltage Control System: Feedback of EDF.” In Panel Session–2000. IEEE PES Summer Meeting, Seattle, WA.
[6].
J. P. Piret, J. P. Antoine, and M. Subbe et al., “The Study of a Centralized Voltage Control Method Applicable to the Belgian System,” in Proc. CIGRE, Paper 39–201, Paris, France (1992).
[7].
J. Van Hecke, N. Janssens, J. Deude, and F. Promel, “Coordinated Voltage Control Experience in Belgium,” in Proc. CIGRE, Paper 38–111, Paris, France (2000).
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Hierarchical Dynamic Voltage Control to Help Reduce Transmission Loss
[8].
J. L. Sancha, J. L. Fernandez, A. Cortes, and J. T. Abarca, “Secondary Voltage Control: Analysis, Solutions, Simulation Results for the Spanish Transmission System,” IEEE Trans. Power Syst. Vol. 11, pp. 630–638 (May 1996).
[9].
L. Layo, L. Martin, and M. Álvarez, “Final Implementation of a Multilevel Strategy for Voltage and Reactive Control in the Spanish Electrical Power System,” in Proc. PCI Conf., Glasgow, Scotland, U.K. (2000).
[10].
G. Taranto, N. Martins, A. C. B. Martins, D. M. Falcao, and M. G. Dos Santos, “Benefits of Applying Secondary Voltage Control Schemes to the Brazilian System,” in Proc. IEEE/PES SM, Seattle, WA (July 2000).
[11].
CIGRE Report Task Force, Coordinated Voltage Control in Transmission Networks. C4.602, February 2007.
[12].
S. Corsi, M. Pozzi, C. Sabelli et al., “The Coordinated Automatic Voltage Control of the Italian Transmission Grid –Part I: Reasons of the Choice and Overview of the Consolidated Hierarchical System,” IEEE Transactions on Power Systems. Vol.19, No.4, pp.1723–1732 (2004).
[13].
S. Corsi, M. Pozzi, M. Sforna et al., “The Coordinated Automatic Voltage Control of the Italian Transmission Grid - Part II: Control Apparatuses and Field Performance of the Consolidated Hierarchical System,” IEEE Transactions on Power Systems. Vol.19, No.4, pp.1733–1741 (2004).
[14].
S. Corsi, V. Arcidiacono, U. Bazzi, R. Chinnici, M. Mocenigo, and G. Moreschini, “The Regional Voltage Regulator for ENEL’s Dispatchers,” in Proc. CIGRE, Paris, France (1996).
[15].
S. Corsi et al., “General Application to the Main ENEL’s Power Plants of an Advanced Voltage and Reactive Power Regulator for EHV Network Support,” in Proc. CIGRE, Paris, France (1998).
[16].
H. Sun, Q. Guo, and B Zhang, “Research and Prospects for Automatic Voltage Control Techniques in Large-Scale Power Grids,” Journal of Electric Power Science and Technology. Vol.22, No.1, pp.7–12 (2007).
[17].
H. Sun, Q. Guo, B. Zhang, W. Wu, and J. Tong, “Development and Applications of System-wide Automatic Voltage Control System in China.” Submitted to IEEE PES General Meeting, Calgary, Alberta, Canada (2009).
[18].
Q. Guo, H. Sun, B. Zhang et al, “Research and Development of AVC System for Power Networks of Jiangsu Province,” Automation of Electric Power Systems. Vol.24 (2004).
[19].
H. Sun, “Automatic Voltage Control System (AVC) with Its Implementation in China.” Presented at EPRI Webcast on Hierarchical Dynamic Voltage Control ( September 2008).
[20].
Q. Guo, P. Wang, W. Ning, H. Sun, B. Zhang et al., “Applications on Automatic Voltage Control System for North China Power Grid,” Automation of Electric Power Systems. Vol. 35, No. 5 (2008).
[21].
J. Tong, “Optimal Dynamic Voltage Control for PJM Transmission System – Phase I: Evaluation.” Presented at EPRI PDU Advisor Council Meeting (Feb. 23–25, 2009).
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13
FRAMEWORK FOR ASSESSING LOSS-REDUCTION OPTIONS This section presents the final objective of this project, which is an integrated framework tool for use in focusing and guiding the actions toward transmission-energy improvements.
This section provides the user with some guiding principles, such as:
•
Characterization of loss-reduction methods
•
Qualitative screening of the various actions to reduce transmission losses
•
Defining baseline scenarios without improvements (business as usual, no transmission efficiency-improvement actions)
•
The mechanics and methodologies for the evaluation of the selected methods
•
Benefit/cost analysis of the various measures
•
Ranking of the loss-reduction methods
To accomplish the above, this section presents a methodical step-by-step procedure, delineating:
•
The assumptions made in the analyses (technical as well as economic) to facilitate what-if sensitivity investigations
•
The gathering and collection of the data required for the analyses
•
The scope and rationale for performing the various evaluations, especially for dual-effect measures such as for increased capacity or improvement of reliability as well as for reduction in losses resulting from the new components, facilities, control actions, and maintenance
•
Quantification of the loss-reductions and the costing reference for analyzing the monetary savings
Introduction It was stated in Section 1 of this report that the final objective of this project is to develop an integrated framework for the evaluation of transmission loss-reduction measures. Results from the industry survey on transmission-loss activity undertaken and presented in Section 2 indicate that there is real interest among utilities in developing methods to reduce transmission losses. Utilities are studying methods to reduce losses on the electric ac transmission network, but they recognize that there is a need to develop an industry-wide standard approach to transmission-line loss studies. Hence, the survey results are taken as a direction in which to proceed in addressing the transmission network loss-minimization framework. 13-1
Framework for Assessing Loss-Reduction Options
This section presents a general framework for evaluating various measures to reduce transmission losses. The evaluation framework is developed based on the concepts and descriptions provided by the various sections of the report. The integral view of the value proposition associated with transmission loss-reduction measures is provided in Section 3. A detailed description of the basic components comprising the assessment of TEE projects is provided in Section 4. The remaining sections describe the various technological options to reduce losses in transmission systems. Physical characteristics, implementation considerations, and the investment and savings potentials for each technology are addressed in these sections.
Focus and Scope of the Framework As explained in Section 4, the evaluation framework is focused on two parts of a typical TEE process: baseline definition and feasibility and scoping studies (Figure 4–1). The framework is intended to provide a tool to facilitate good decision-making when evaluating methods and strategies for reducing transmission losses. Obviously, any facilities or control changes implemented on the transmission system for reducing losses must also be studied to ensure that reliability and other system criteria are met. Therefore, the loss-evaluation framework must be followed by typical engineering planning studies and design and construction phases. The lossevaluation framework itself should be a guide for conducting the feasibility and scoping study for the potential loss-reduction measures. The result of the framework’s application will basically be a ranking of the measures that can be applied to a given system to reduce transmission losses, in which the ranking is based on some predefined selection criteria such cost/benefit, total losses reduced, and other monetary and nonmonetary aspects. However, the framework is not intended to provide guidelines for the detailed engineering and implementation processes needed.
Categorizing Actions That Impact Transmission Losses It was stated in Section 4 that some of the methods identified in the repertoire of loss-reduction options can be considered as dual-effect projects, because they are usually implemented for increased transmission capacity or improved reliability. Nevertheless, they can also be implemented with the primary objective of reducing losses, as has been illustrated in the various sections of this report. Although these measures could potentially be implemented specifically to reduce losses, the cost associated with implementation is in many cases likely to be higher than the value derived solely from the reduction in losses. Furthermore, some of the measures described in the preceding sections can be applied specifically for reducing losses without incurring a significant investment. These projects can be accomplished by taking advantage of existing facilities. Examples are optimal-voltage profiling and redirecting of power flow in transmission systems. The control devices (such as phase-angle regulators, series capacitors, generator excitation adjustors, mechanically switched shunt reactors and capacitors, tap changers, SVCs, and HVDC transmission) existing in the system can be set or adjusted for loss-reduction purposes. It is worth mentioning that the concept of “existing” facilities can be ambiguous in planning terms. The required equipment (FACTS, tap changers, phase-angle regulators) may not exist in the current system, but there may be plans to incorporate it for purposes other than loss-reduction in future years. If the timeframe for evaluating the reduction in losses is after the planned installation of the future facilities, these projected facilities can be considered in the analysis. Therefore, the existing facilities to be considered will
13-2
Framework for Assessing Loss-Reduction Options
depend upon the timeframe of the analysis, and they will include the existing facilities as well as the projected additions. For the development of the evaluation framework, it may be convenient to differentiate the methods based on those characteristics that influence the evaluation processes, because the methodology and tools that need to be applied for the evaluation differ for the various measures. For example, for a loss-reduction measure that requires the implementation of advanced controls, such as voltage-profile optimization, an optimal power flow needs to be used for the evaluation. Therefore, the described methods for loss-reduction considered in this report are grouped in Table 13–1 based on the approach that is required to evaluate the measure. Conversion of ac to dc can fit in either Group A or Group B. However, this option is not included in this evaluation framework because it is an incipient technology, and more experience is needed to be able to delineate an appropriate evaluation methodology for it.
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Framework for Assessing Loss-Reduction Options
Table 13-1 Characteristics of Loss-Reduction Methods Group
Methods
Characteristics
A
• Raising transmission-line nominal voltage • Reconductoring • Bundling phase conductor
• Dual-effect measures: o increase capacity or improve reliability o reduce losses • Usually implemented to increase transmission capacity • These methods change the impedance characteristics of the network and impact system operation to some extent.
B
• Diverting power flow • Voltage-profile optimization
• These methods can be applied to the existing* facilities in a centralized upper-level control fashion to optimally adjust settings for lossreduction. • Can be used for other purposes than reducing losses, like increasing transmission capacity, improving system security, and reducing congestion.
C
• • • • •
• Applied specifically for loss-reduction purposes. • The use of low-loss transformers may also have dual effects. • The characteristics of these methods differ greatly among themselves, so a specific evaluation methodology must be applied for each of them. • Usually, these methods do not imply changes in the operating characteristics of the transmission system.
Shield-wire segmentation Insulation losses Low-loss transformers Corona-losses reduction Switching or cycling out-ofservice equipment not needed for current operation
(*) The aforementioned concept of “existing facilities” applies.
It should be noted that this classification is not rigorous, and some overlap may exist. Clearly, other classifications based on other criteria can be applied for different purposes. The use of lowloss transformers may, in some cases, imply that an existing transformer will be replaced with a new energy-efficient transformer of higher capacity, in order to increase system-loading capability. For such a case, this option would fit in Group A; however the evaluation methodology for the low-loss transformer option differs greatly from the one used for the measures in Group A. For this reason, it is not included in Group A.
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Framework for Assessing Loss-Reduction Options
Framework Outline On the basis of the grouping of measures in the previous section, the evaluation-framework outline depicted in Figure 13–1 is proposed. The main stages depicted are described in the following subsections. The proposed evaluation framework is based on the following assumptions:
•
There is not a predefined target for the loss-reduction to be achieved (a specification of the percentage that the losses must be reduced with respect to a reference case). Implementation of the technologies for reducing losses is decided upon based on the benefit/cost characteristics of the various options.
•
Measures in Group A are selected and designed for the primary purpose of reducing losses. Nevertheless, the impact of the increased transmission capability that can be achieved with the implementation of these technologies is also analyzed.
•
The measures in Group B are considered to be applied utilizing existing facilities—including not only the current system, but also other installations (control devices) that are planned to be installed in the system for purposes other than loss-reduction.
•
The analysis for the measures in Group B also includes the evaluation of marginal reduction in losses achieved from marginal investments intended specifically for improving lossreduction. For instance, the addition of a new switched shunt capacitor could be conveniently located to improve the control capability and performance of the centralized high-level lossreduction control loop. It is clear that, in general, adding new facilities that have significant costs associated with their installation is not a cost-effective measure for loss-reduction. However, such options should be included in the evaluation framework that may apply in certain particular cases (for example, adding some devices with lower capital cost like switched shunt capacitors or tap changers).
•
The framework is not intended to provide a unique optimal solution for the implementation of loss-reduction measures. Rather, its objective is to provide a list of possible alternatives— complete with an evaluation of their relevant attributes (benefit/cost)—so that various decision-making approaches can be utilized and tailored to specific needs.
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Framework for Assessing Loss-Reduction Options
STAGE 1: QUALITATIVE SCREENING • Measures that are technically feasible for the system being considered • Screening process based on a list of attributes • Evaluation of previous studies • Consultation process • Output: List of possible measures
STAGE 2: BASELINE SCENARIOS • Definition of time frame and scenarios for the study
• • • •
STAGE 3: GROUP A Basic design Computing of losses Cost analysis Analysis of benefits
• • • •
STAGE 3: GROUP B • Basic design • Basic outline of the centralized control system • Computing of losses • Cost analysis • Analysis of benefits
• • • •
STAGE 3: GROUP C Basic design Computing of losses Cost analysis Analysis of benefits
STAGE 4: RANKING OF METHODS Define selection criteria Apply ranking procedure Methods ranked according to the applied criteria More than one rank list possible
Figure 13–1 Outline of the Framework for the Evaluation of Loss Reduction Measures
Stage 1: Qualitative Screening The first step in the evaluation study is to conduct a qualitative screening process. The purpose of the qualitative screening is to produce a list of measures that merit detailed analysis with a reasonable expenditure of analytic effort. The complete evaluation process for the various methods selected can consume significant time and resources. Therefore, it is convenient to filter or perform an expedited selection of the possible methods in order to reduce the engineering burden and associated costs to a reasonable level. The output of this step is a list of measures— separated by category—to be analyzed in detail in the subsequent stages. 13-6
Framework for Assessing Loss-Reduction Options
The qualitative screening criteria may vary by utility, depending on the characteristics of the power system under study and the experience the utility’s technical staff has in studying or applying these technologies. An inventory of previous studies and projects may provide very useful information to support the qualitative screening process. The selection of measures based on a qualitative assessment can be done based on the relevant attributes of each loss-reduction method that impact their attractiveness for a particular application. The main attributes to be considered are:
•
State of technology
•
Challenges and limitations
•
Implementation considerations
•
Energy-savings potential
•
Peak-demand reduction potential
•
Capital and O&M costs
•
Levelized investment cost per kWh of energy reduction
•
Levelized investment cost per kW of demand reduction
The characteristics and attributes of each of the identified technologies have been described in detail in the corresponding sections of this report. Table 13–2 summarizes the principal attributes to be considered in the qualitative screening process.
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Framework for Assessing Loss-Reduction Options
Table 13-2 Main Characteristics and Attributes of Options to Reduce Transmission Losses Option
State of Technology
Implementation Considerations
Energy and Demand Savings Potentials
Levelized Cost per Energy and Demand Savings
Raising transmissionline voltage
Mature technology It has been applied in several systems, mainly to increase power capacity.
Mainly implemented to increase capacity: Increasing the operating voltage of the transmission line boosts the powertransfer capability. It will require modifying the terminal equipment, as well as possibly upgrading the transmission towers. Implementation for the sole objective of reducing losses may not be cost-effective because of high capital requirements. It modifies the impedance characteristics of the network and the power-flow pattern change for the same generation dispatch.
Losses in upgraded line may reduce by more than 50%. Reduces system losses to a greater extent than reconductoring.
May vary to a great extent from one case to another Reference values on simplified case studies: $15–40 /kWh $50–100/kW
VAR/Voltageprofile optimization
It has been applied in some systems in Europe and China. •In Brazil, coordinated voltage-control concepts are also under consideration. •In North America, it has received limited consideration by power companies.
It can be implemented with existing facilities. A high-level centralized control loop for loss-minimization is to be implemented to adjust bus voltages on-line. Additional controllable reactive power compensators could be added to improve the loss-minimization function (if it is cost-effective). Implementation for the sole objective of reducing losses may be cost-effective because of relatively low capital requirements.
1– 5% of transmission losses
Reference values based on limited data: $15–40 /kWh $30–50 /kW
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Framework for Assessing Loss-Reduction Options Table 13 2 (continued) Main Characteristics and Attributes of Options to Reduce Transmission Losses Option
State of Technology
Implementation Considerations
Energy and Demand Savings Potentials
Levelized Cost per Energy and Demand Savings
Reconductoring Mature technology Bundling phase It has been applied in several conductors systems mainly to increase power capacity
ACSR trapezoidal conductors of the same or moderately higher diameters as those of the existing conductors can be used for replacement without significant tower reinforcement. This solution is usually implemented to increase transfer capability. May require that transmission-line towers be significantly altered to support a larger conductor. Implementation for the sole objective of reducing losses might not be economical, especially if transmission-line towers have to be significantly altered. Bundling conductors significantly increases structure loading; line towers need to be reinforced.
Loss-reduction depends on the way the reconductored line is operated. Reconductoring with TW conductors of equal diameter can reduce line losses up to 20%. Bundling with the same conductor can reduce line losses up to 50%. Impact on system energy efficiency depends upon the relative weight of the line losses on the overall system losses.
Reference values based on simplified case studies: $40–120/kWh $30–200/kW
FACTS devices, HVDC and phaseshifter transformer technology is mature and available. Phase-shifting transformers are widely used in some systems (Europe) to control power flow. There is little or no evidence on its use for reducing losses.
May be accomplished with existing facilities if FACTS devices or other devices with power-flow control capability are installed in the system. It requires the implementation of a centralized control that continuously or frequently adjusts the control settings. It may be cost-effective based on reduced losses if power-flow control devices are already installed for reasons other than loss-reduction.
It depends greatly on the number of controlled devices and the powerflow pattern of the system. No information is available on actual implementations.
N/A
Redirecting power flows
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Framework for Assessing Loss-Reduction Options Table 13 2 (continued) Main Characteristics and Attributes of Options to Reduce Transmission Losses Option
State of Technology
Implementation Considerations
Energy and Demand Savings Potentials
Levelized Cost per Energy and Demand Savings
Use of low-loss transformers
Technology to reduce transformer losses is available.
Large transformers are usually designed for an optimal trade-off between losses and investment cost. Hence, there are few opportunities to further improve efficiency. Replacement with higher-efficiency transformers may be feasible when the transformer replacement has already been decided upon for reasons other than to reduce losses.
Reducing load losses has a more significant impact on energy losses as load factor increases. Reduction of NLL is more effective in transformers with relatively low load factor.
N/A
Shield-wire segmentation
This technology has been applied in certain systems. It is not widely used in the United States.
Shield-wire segment length may vary from 2 to 20 miles. Each segment is grounded at one tower, and it is terminated by dead-end strain insulators. If OPGW implementation is done, each fiber splice is accommodated with an optical isolator to an accessible splice box bonded to the tower.
Loss-reduction varies with the square of linepower transfer. Energy loss-reduction is very sensitive to lineloading factor.
Reference values based on one case study: $30–60/kWh $100–130/kW
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Framework for Assessing Loss-Reduction Options
Table 13 2 (continued) Main Characteristics and Attributes of Options to Reduce Transmission Losses Option
State of Technology
Implementation Considerations
Energy and Demand Savings Potentials
Levelized Cost per Energy and Demand Savings
Corona lossreduction
Reducing corona losses by reducing voltage during foul weather is a new concept. Numerical experiments shows its potentiality to reduce losses under certain conditions. Further investigation is required to fully prove the principle.
Corona losses are normally low compared to line losses. Controlling voltages to reduce corona losses poses a challenge because of possible reliability issues. A centralized secondary voltage control needs to be implemented. If it is already in place, a function to reduce corona losses could be added to the existing control system.
N/A
N/A
Reduction of insulator losses
Techniques for reducing insulator pollution are well known. It is usually applied for improving reliability.
Insulator losses are generally small compared to conductor and transformer losses. Estimation of the average leakage current is needed to determine energy savings. This can be done by measuring a number of sample insulators, but it is costly. Application of techniques for cleaning or coating insulators with the sole objective of reducing losses may be cost-effective if the leakage current is relatively high. This measure is usually implemented to improve reliability ( dual effects). One could take advantage of its dual-effect feature (improve reliability and reduce losses) to leverage investment.
Energy savings greatly depend upon the leakage current, which, in turn, depends upon the pollution on the insulator surface, the moisture factor, and the ambient conditions. Insulator losses may be in the range of 2– 5% of line-resistance losses. Demand savings on peak conditions are very difficult to determine.
Reference values based on one generic case study: $25–100/kW-h
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Framework for Assessing Loss-Reduction Options Table 13 2 (continued) Main Characteristics and Attributes of Options to Reduce Transmission Losses Option Conversion of ac to dc
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State of Technology
Implementation Considerations
The principle and DC voltage is strongly influenced by the applicability of ac conductors currently in place. Larger to dc conversion conductors will generally permit higher voltages, which in turn increase the dc have been proven. circuit effectiveness. Demonstration of the technology has It is more economic to convert an ac line been carried out to the tripole dc equipment configuration under EPRI’s than the bipole configuration. program. No commercial conversions of ac to dc have been implemented to date.
Energy and Demand Savings Potentials
Levelized Cost per Energy and Demand Savings
If the dc line is operated N/A with the same maximum load and loading factor as that of the existing ac line, a net reduction in losses can be achieved. For short lines, converter losses offset the lossreduction gained in the dc circuit.
Framework for Assessing Loss-Reduction Options
Stage 2: Definition of Baseline Scenarios The general concept of “baseline” for energy-efficiency projects has been introduced in Section 4. It was stated that in programs for improving TEE, the baseline is the reference case or benchmark against which loss-reduction is assessed. It represents the normal transmission losslevel of the system that results from the application of the planning and operation criteria. If a long-term transmission-expansion plan is available, baseline scenarios should be determined based on the future system conditions foreseen in the plan. In some cases, the transmission-expansion plan may not contain all the detailed information required for conducting a loss-reduction evaluation. In such situations, the best possible estimation of the missing data will be considered. However, the estimation must be consistent with the features of the transmission expansion plan and the utility’s planning philosophy. The number and characteristics of the various scenarios to be defined for conducting the evaluation of loss-reduction options will basically depend upon the loss-evaluation methodology adopted. If the methodology is based on the use of security-constrained dispatch programs, there is no need to define a number of representative snapshots. On the other hand, if the losscalculation approach is based on power-flow evaluations at a series of load levels and loadduration curves, representative power-flow cases need to be defined. Usually, base-, intermediate- and peak-load conditions (on a seasonal or monthly basis) are required. Scenarios representing high and low import and export conditions may also be needed, depending on the operating characteristics of the system being studied. Note that the reference scenarios may vary depending on the loss-reduction measure to be evaluated. For example, for assessing the insulator losses on a given transmission line, it is not necessary to establish future conditions for the entire system; these losses will depend only on the pollution level of the line insulators and the weather conditions. Stage 3: Detailed Evaluation of the Selected Methods This stage is the core of the evaluation methodology. In this stage, a tailored methodology is applied to each group of measures, because each group has special characteristics that need to be addressed in a particular manner. The specific evaluation methodologies for each case are provided in the following subsections: Methodology for Stage 3 – Group A An outline of the methodology for conducting a detailed evaluation of the methods corresponding to Group A is presented in the block diagram of Figure 13–2.
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Framework for Assessing Loss-Reduction Options
REFERENCE SCENARIOS FROM STAGE 2
1. QUANTIFY AND COST THE REFERENCE LOSS LEVEL. • Transmission losses evaluation • Cost of losses: energy, capacity, and emission costs
2. SELECT CANDIDATE TRANSMISSION LINES TO BE UPGRADED. • Basic engineering • Line-loading factor and maximum losses • Simplified preliminary analysis
6. EVALUATE TRANSMISSION-CAPABILITY INCREASE • Incremental transfer limits • Interface limits • Area import/export limit • Steady-state and dynamic analysis • Linear transfer analysis possible for incremental transfer limits (Siemens-PTI MUST)
7. EVALUATE BENEFITS VERSUS COSTS OF INCREASED CAPACITY PERMITTED BY UPGRADES. • Economic benefits from relaxing transmission constraints • Possible approaches: Multi-area production-costing programs Security-constrained dispatch program Simplified analysis via power-flow studies • Including cost of VAR compensation required • If losses are greater than in the reference case, the implementation is not acceptable.
3. DETERMINE OPTIMAL SET OF PROJECTS. • Selection based on engineering judgments based on the results of Step 3. • Alternative: • OF = MIN (Inv. Cost + Loss Cost) • Multi-period combination problem (dynamic programming, benders decomposition)
4. EVALUATE COSTS. • Capital cost of upgrades • O&M cost associated with the upgrades • Cost due to operating constraints during construction
5. CONDUCT BENEFIT/COST ANALYSIS OF LINE UPGRADES WITHOUT INCREASING SYSTEM UTILIZATION. • Determine losses with line upgrades • Determine cost of losses • Evaluate benefits: cost of losses “with” upgrades minus cost of losses “without” upgrades • NPV analysis
END OF STAGE 3 FOR GROUP A
Figure 13–2 Framework of Stage 3 for Measures in Group A (Except for Conversion of AC to DC)
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Framework for Assessing Loss-Reduction Options
The basics for the proposed formulation are as follows:
• Candidate lines to be upgraded are selected according to their effectiveness in reducing transmission losses. Their impact on transmission capability is of secondary importance in the first selection. • Benefits are determined for two different conditions: A. The system is operated assuming the same transmission restriction as in the reference case (baseline). That is, the additional transmission capability that may be allowed by line upgrades is not taken into account for determining system operation conditions. B. The system is operated assuming the additional transmission capability permitted by the selected line upgrades. The rationale for performing these two different evaluations is that although upgrades are selected for the primary purpose of reducing losses, it is reasonable to determine whether the extra capacity can provide any additional benefit. Indeed, the increased transmission capability may reduce transmission constraints that limit the system’s economic operation. The main benefit in Case B will come from energy cost savings resulting from transmission-constraint relaxation. However, if transmission losses are increased because of greater transmission-line loading, the option of taking advantage of the increased transfer capability (Case B) must be disregarded (even when the net benefit is positive). The objective of implementing the line upgrade in this case is to reduce transmission losses, and the investment will only be justified if this objective is attained. Step 1: Quantify and Cost the Reference Loss Level.
In this step, loss magnitude and its associated cost are to be determined for the reference scenarios. Benefits from loss-reduction will then be accounted for as the difference between loss levels obtained with and without the implementation of the loss-reduction measures. The approach and consideration for the evaluation of transmission system losses and the cost components associated with such losses have been described in Section 4. Step 2: Select Candidate Transmission Lines to Be Upgraded.
Voltage Upgrade Selection of a project suited for voltage upgrade is a fairly complex decision process that involves a number of responsibility areas of a utility company—from planning through engineering, construction, and operation and maintenance. Section 5 and the references therein comprise comprehensive materials and documentation regarding the different aspects of voltageupgrade technology—from feasibility analyses to detailed design and implementation. However, most of the previous work focused on the application of voltage-upgrade technology to increase the transmission capability of an existing system (incremental transmission capacity). Therefore, the selection of candidate lines to be upgraded was aligned with that objective. The process begins by identifying a project need—typically, a path that requires increased power flow or voltage-stability improvement. In some cases, a sequence of several upgrades may be required to meet the objective. An engineering process in which the feasibility of upgrading the existing line or lines to meet planning requirements is then conducted. If the feasibility test 13-15
Framework for Assessing Loss-Reduction Options
indicates that the selected lines have potential for voltage upgrading, the process proceeds forward as a viable option. Advanced stages of planning and engineering are then conducted to refine the project and better estimate the costs, benefits, and risks associated with it. In the case of voltage upgrading to increase capacity, the identification of the line or lines that need to be upgraded is more straightforward, because the objective is to improve the capacity of a given transmission path. On the other hand, in the case of a voltage upgrade to reduce losses, the number of options is considerably higher; any line feasible for upgrading is a candidate, regardless of its location. Indeed, the objective is to reduce the overall system losses, not just those in a particular area. There is no direct procedure to identify those transmission lines for which a voltage upgrade will most impact transmission losses. However, as a first attempt, those lines that are most heavily loaded during most of the scenarios considered for the analysis can be identified as candidates for voltage upgrading. Because voltage upgrades significantly modify transmission-line impedance, power-flow patterns can change considerably. Hence, the impact of voltage upgrading on transmission losses can only be determined by a full load-flow analysis. At this stage, a cost/benefit analysis considering each project independently can be conducted to evaluate their performance. The considerations and guidelines for loss and benefits evaluations provided below for Step 5 can also be followed to conduct the cost/benefit analysis for this step. Once prospective transmission lines are selected according to this criterion, a basic engineering feasibility test can be conducted to assess the potential for upgrading the chosen lines. Alternative solutions can be evaluated, ranging from full replacement to a minimal upgrade of the existing configuration. However, because in this case the objective for voltage upgrading is to reduce losses, it is unlikely that benefits from loss-reduction can offset a high investment cost. Hence, a lower-cost solution should be prioritized. Only those line upgrades that pass the feasibility test will be considered as candidates for further analysis. Reconductoring with Lower-Loss Conductors and Bundling It has been demonstrated in Section 6 that reconductoring existing transmission lines with either larger cross-sectional standard conductors or with advanced conductors can provide a significant reduction in line losses if the new conductor is operated under parameters similar to those of the existing line. Line losses will be reduced because of the lower resistance of the conductor. Reconductoring does not change reactance to a significant degree, so it produces a minor impact on the power-flow pattern, provided that all other conditions remain the same (generation dispatch, network configuration, import/export). Therefore, an expedited evaluation of the various candidate lines can be performed with the simplified approach followed for the case studies presented in Section 6. The analysis consists of evaluating each candidate line individually for different reconductoring options. The power flows through the candidate lines for intermediate- and peak-demand periods, and the corresponding period durations, are determined from the reference scenarios. The line-loading factor and the maximum current can be estimated from these scenarios as well. The maximum power flow over a given line may not coincide in time with the maximum system load; so it is likely that maximum power-flow conditions will not be “caught” by the power-flow analysis. If available, historical data about line loading can be used to validate or improve values determined by power-flow analyses.
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Framework for Assessing Loss-Reduction Options
Transmission-line load factor, along with line losses at system peak conditions, can be used as metrics for the first selection of candidate lines. The lines can be sorted according to their loss at peak conditions and load factors. Clearly, the first lines in the list are the ones to be considered as the best candidates for upgrading. Short lines and lines with low load factor should be discarded as candidates because of their minor impact on total transmission losses. The bundling conductor option can also be analyzed in this manner. The investment cost should be carefully estimated, taking into account that bundling a conductor usually requires substantial reinforcement of the tower structures. Unlike reconductoring, adding a second conductor per phase modifies the impedance characteristics of the transmission line (both inductance and resistance), so that the power-flow pattern may be altered. Hence, analyzing each line individually implies that this effect is neglected and, consequently, the results are less accurate. Nevertheless, this kind of analysis is still valid at this step, because the objective is to screen and filter multiple alternatives. By means of this analysis, upgrade projects that are not economically attractive are discarded. As in voltage-upgrade evaluation, a basic engineering feasibility test is conducted to assess the potential for upgrading the selected lines. Those projects that are technically feasible and economically sound will comprise the candidate-project list. Note that lines for which thermal upgrades have already been decided upon or evaluated for transmission-capacity improvement can be selected as candidate projects for loss-reduction. Indeed, as explained in Section 4, the analysis in this case consists of determining the costeffectiveness of the incremental investment needed to further reduce losses beyond the lossreduction level obtainable with the original project design. The opportunity for additional lossreduction in this case is the selection of a larger or advanced conductor. Step 3: Determine Optimal Set of Projects.
The output of Step 3 is a list of transmission lines for which a voltage upgrade or reconductoring are both technically and economically feasible. Because our assumption for this framework is that there is no loss-reduction target to be attained, any number of projects could be implemented, as long as they are cost-effective and economically attractive. If the economic performance of each project in the candidate list is positive, any combination of these projects could yield a positive overall performance. However, some transmission-line upgrades—especially those that change line surge impedance— alter network impedance characteristics and, as a consequence, system operation conditions. Hence, the effectiveness of each individual project in reducing losses may be altered when other projects are in place. As the level of investment in loss-reduction measures increases, so does the capital cost, whereas the total cost of losses is reduced. The optimal investment level, then, is at the point of minimum total cost. A sophisticated methodology could be envisioned for determining the optimal set of projects. In general terms, the problem can be formulated as an optimization model as follows:
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Framework for Assessing Loss-Reduction Options
OF = Min (Total Investment Cost + Loss Cost) Subject to:
• Reliability and security constraints • Equipment technical limits • Components design criteria The control variables will be the various candidate projects selected in Step 3. The optimization problem needs to be solved for the entire analysis period. Such a complete optimization formulation is a multi-period combination problem that could be solved by means of techniques suitable for event-sequence optimization, such as dynamic programming or benders decomposition. The development and implementation of such an optimization methodology is far beyond the scope of this work, and it is left for future extensions of this project. Without the availability of such an optimization tool, the set of projects for further investigation can be determined by engineering judgments, taking into account the performance of each individual project and technical feasibility study conducted in Step 2. Step 4: Evaluate Costs Associated with Upgrade Implementation.
In Step 3, a gross estimation of costs is considered for estimating the economic performance of the prospective projects. At this step, a more comprehensive cost analysis is conducted for the select projects. The cost includes:
• Capital cost of upgrades • Increased or decreased maintenance cost associated with upgrades • Operating cost caused by operating constraints during construction Capital cost and maintenance considerations are described in Sections 5 and 6 and the references therein. Operating constraints caused by outages during upgrade construction need to be considered as well, because they may have a significant impact on operating costs. Step 6: Conduct Benefit/Cost Analysis of Line Upgrades Without Increasing System Utilization.
The analysis at this step is intended to determine the impact of line upgrades on transmission losses if transmission line loading is kept at the same level as that in the baseline scenarios. That is, the system is operated without taking advantage of the increased transmission capability. 1 A) Determine Losses with Line Upgrade. System losses in this step are determined using the same approach followed in Step 1 for calculating the losses of reference cases. Because transmission limits are considered to be unchanged with respect to reference cases, generation dispatch of each scenario is also maintained unchanged—except for the reduction resulting from the lessening system losses. If a security constraint economic dispatch program is utilized, the generation dispatch pattern is adjusted to match the reduced total demand (load + losses) in an economical manner. If, on the other hand, a conventional power-flow analysis is used to calculate losses, the generation 1
Benefits resulting from the improved transmission capability are determined in a later step of this evaluation process.
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Framework for Assessing Loss-Reduction Options
dispatch can be adjusted manually, considering the relative operating cost of the different generating units (order of merit list). B) Evaluate Benefits Versus Costs. Benefits less costs that can be quantified in dollar terms are expressed as NPVs as a series of annual costs over the NPV-evaluation horizon. All annual benefits and costs are assumed as endof-year values, are discounted by a present-worth factor (PWF) and are summed as an NPV referenced to the beginning of the first year. Other economic metrics, such as IRR and payback period, can be used as indicators of the project’s efficiency As explained in Section 4, the benefits of loss-reduction measures are determined as the avoided costs of losses, including the cost of energy, capacity cost, and emission cost. These benefits are determined as the difference in loss costs between the “reference case” and the “system with line upgrades” case. Costs of losses are determined with the approach and considerations described in Section 4. The methodology and the parameters for benefits evaluation may vary by institution and circumstances, so that this general procedure needs to be adapted for each particular situation. Step 7: Evaluate Transmission-Capability Increase.
When technologies in Group A are implemented to increase transmission capability, the transmission-utilization objective is identified beforehand. A progressive update sequence is then designed to achieve the transmission-capacity requirement in time. Examples of common transmission-capability objectives are: increase the capability of a transmission corridor, increase the transfer capability of a defined transmission interface, increase the import capability into a load pocket, and increase the export capability of an area with surplus generation. Conversely, if technologies in Group A are designed and implemented to reduce losses, lineupgrade projects are selected as those having major impact on system losses—regardless of how they may impact transmission-system capability. In fact, in such a case, improvement of transmission capability is a by-product or secondary effect, because the measures are designed with the primary objective of reducing losses. The identification of transmission-capacity improvements is more difficult in this case, as the selection of lines to be upgraded may not derive from the need to solve specific transmission constraints. Transmission capability is traditionally described as one of several types of MW limits, in which the definition of the limits depends on the objectives of transmission utilization. The limits may be defined either as a total flow limit or as an incremental MW limit on top of a defined operating condition [7]:
• Incremental-transfer limit is the maximum incremental power that can be transferred from one place in the network to another without violating reliability criteria. An incrementaltransfer limit is expressed as a maximum incremental power flow on top of a defined operating condition. • Interface limit is the maximum power that can flow across the interface (the sum of the MW flows across the parallel circuits constituting the interface) without violating reliability criteria.
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Framework for Assessing Loss-Reduction Options
• Import limit is the maximum power (incremental or total) that can be imported into an area without violating reliability criteria. This is of particular importance to a “load pocket,” in which an inadequate import limit may severely impact economic operation or—in the extreme—result in load curtailment. • Export limit is the maximum amount of power (incremental or total) that can be exported out of an area without violating reliability criteria. This is of particular importance to a “generation pocket,” in which an inadequate export limit may deprive the outside system of economic power or—in the extreme—cause load curtailment in the outside system. The transfer limits may be caused by thermal, voltage, or stability constraints. Transmission-line upgrades may allow utilities to increase some transfer limits. Transfer limits are determined according to the applied reliability criteria. To determine transfer limits, the system is first tested under normal operating conditions, by means of a full ac power-flow analysis to evaluate if all the performance criteria for such operating conditions are met. Then, steady-state and dynamic simulation of various kinds of faults are performed. The kind s of faults to be considered in the evaluation, as well as the acceptable system performance under each kind of fault, are normally specified in the applicable reliability standards. Linear-transfer analysis models, such as the Siemens PTI MUST program, can be used to determine incremental transfer limits when stability constraints are not of major concern. The MUST program determines the critical thermal transmission limits, recognizing the thermal ratings on all circuits and all contingencies, as specified by applicable reliability criteria. Step 8: Evaluate Benefits Versus Costs of Increased Capacity Permitted by Upgrades.
Even though line upgrades are selected for loss-reduction purposes on the assumption that no additional transmission capacity is required to comply with reliability standards, they still provide extra capability that can be beneficial for economic operation. The benefit of increased transmission capability can be estimated by evaluating the following aspects of system economics [7]:
• Reduced overall production cost • Economic benefits of reduced energy-price differentials across bottlenecks • Reduced need for peaking plants in load pockets or, more generally, savings in generation capital costs because of reserve-sharing benefits The incremental transmission capacity permitted by line upgrades will yield economic benefits to the total system, but may benefit different portions of the system to different degrees. Indeed, the economic benefits from incremental transmission capacity depend on the beneficiary considered. In order to define relevant measures of economic benefits of incremental upgrades, the beneficiary of the upgrades must be explicitly identified. Several possibilities include: the cost savings for a particular company in a power pool; the total cost of the supply of power in a region such as a state; the cost of power consumed in a load pocket such as a city. Energy-cost savings can be quantified by using existing tools that are capable of analyzing operating costs (recognizing transmission constraints). These tools are: 13-20
Framework for Assessing Loss-Reduction Options
• Multi-area production-costing programs, in which transmission constraints are limited to inter-area constraints between area pairs. Economic benefits from transmission-limits relaxation are determined by comparing simulations of economic operations between two cases—with and without line upgrades. • Security-constrained dispatch programs recognizing individual line ratings. Normal ratings will be applied to all-lines-in conditions, and emergency ratings will be applied to contingency conditions. Such programs calculate the minimum system generation cost obtainable within transmission constraints. This tool can therefore be used to explicitly model the economic impact of the selected line-upgrade projects. In cases in which a line upgrade allows the utility to relieve transmission constraints in a particular locale or for a particular time period, it may be possible to obtain adequate estimates of gains in operating economics without the use of formal simulation tools. Analysis of snapshots of relevant load conditions over the analysis period may be sufficient to obtain adequate estimates of economic gain. Impact on Transmission Losses As previously mentioned, increased utilization of a transmission system will generally lead to higher transmission losses, because lines become more heavily loaded. However, in the case of a voltage upgrade, losses may decrease or increase depending on system structure and the degree of increased system utilization experienced after the upgrade. If losses increase with respect to the baseline, the option of using the additional capacity permitted by that selected transmissionline upgrade is not acceptable. Methodology for Stage 3 – Group B The procedure described in this case is a general high-level approach intended for first evaluation of options for Group B. Unlike the technologies in Group A, for which a wealth of study and implementation experience is available, there is limited experience or no experience for these technologies. (Some experience is available for Volt/VAR optimization.) Therefore, it is not possible to develop a detailed evaluation methodology at this time. Each ac transmission network is unique, but it may have existing facilities that can be adjusted to effect some level of loss-reduction. From an operational standpoint, an inventory of facilities and equipment with which their operators are familiar (perhaps adjusted for specific reasons other than loss-minimization) can be prepared and evaluated. In considering these facilities for system loss-minimization, burdening operators with more manual activities during each day and shift is not a good strategy. Therefore, an automated process for adjusting the settings of facilities that impact system losses must be contemplated. There are a number of strategies that may be able to be provided to a network without significant capital expenditure for equipment purchase. If facilities (such as phase-angle regulators, series capacitors, generator-excitation adjustment, mechanically switched shunt reactors and capacitors, tap changers, SVCs, and HVDC transmission) exist and can be set or adjusted, then the following Group B loss-reduction measures may be applied without significant additional equipment cost:
13-21
Framework for Assessing Loss-Reduction Options
•
Transmission voltage-profile optimization. This measure could be achieved with generator-excitation adjustment, mechanically switched reactors and capacitors, tap changers, and SVCs.
•
Redirecting power to lower-loss paths. This measure could be achieved with phase-angle regulators, switched series capacitors, and HVDC power-flow settings.
•
Switching or cycling out-of-service equipment that is not needed for current operation. This measure could include shunt reactors and high-loss transmission lines.
Some expenditures of money will be required to design and set up the automated process. It will consist of the monitoring and telecommunication facilities needed to determine the settings, and of switchings that will achieve a minimum transmission network loss for a given operating state (see Section 7, Figure 7–1). This framework for achieving minimum-loss operation will emphasize the process to take full advantage of existing facilities within the transmission network, so that loss-reduction can be achieved with minimum expenditure and in a relatively short timeframe. Considerations of new facilities are included as an additional option. The first step is the evaluation of existing facilities; other options in which new equipment is added are then evaluated. The outline of the methodology is presented in block diagram form in Figure 13–3.
13-22
Framework for Assessing Loss-Reduction Options
1. Prepare List of Facilities Existing in the Transmission Network That Could Be Adjusted or Switched to Participate in Loss-Minimization of the Network 1A Allocate Facilities Best Considered for the Following Participation in Network LossMinimization: • • •
Transmission voltage-profile optimization Redirecting power flows to lower-loss paths Switching or cycling in and out of service 2. Develop or Acquire an Off-Line Optimizing
Yes
Is an Optimization Procedure Available to Adjust Settings?
Procedure with Optimal Power Flow That Can Adjust Settings for Network Loss-Minimization for: No
• • •
Transmission voltage-profile optimization Redirecting power flows Switching or cycling in and out of service
3. Assemble Network and Facilities Data for Input into the Off-Line Optimizing Procedure. Ensure That the Models of Each Listed Facility in Step 1 Have an Interface with the OffLine Optimizing Procedure So That Network Loss-Adjustment Is Possible.
4. Evaluate the Effectiveness of Each Facility Listed in Step 1 Above, Using the Off-Line Optimizing Procedure. Discard Any That Are Ineffective.
5. Select Facilities to Include in the Network LossMinimization Project. Simultaneously Test All Chosen Facilities Active in the Network, Using the Off-Line Optimizing Procedure to Determine Overall Effectiveness Continued next page
13-23
Framework for Assessing Loss-Reduction Options From previous page 6. Evaluate the Cost of Implementing Network LossMinimization. Include in the Cost the Design, Engineering, and Construction of the Automated Process, Monitoring, and Telecommunication Facilities. Undertake a Cost/ Benefit Analysis by Evaluating the Savings of LossReduction Against the Cost of Implementation.
Consider Adding New Facilities?
No
Stop
Yes 7. Conduct Analysis to Locate and Size New Facilities (Switched Shunt Capacitors, FACTS, Tap Changers).
GO TO STEP 2
Figure 13–3 Framework for Determining Minimum-Loss Operation with Existing Facilities
Step 1 and 1A: Prepare List of Existing Facilities.
The equipment and facilities already existing in the electric transmission network that could impact transmission losses would consist of the following, and would be allocated into these three categories, as described in Step 1A:
•
•
For transmission voltage-profile optimization –
Generator excitation set-points
–
Transformer on-line with adjustable tap changers
–
Static VAR Compensators and STATCOMs, if available
–
Mechanically switched shunt reactors and capacitors
For redirecting power to lower-loss paths –
Phase-angle regulators
–
Switched series capacitor modules
–
HVDC transmission power-flow settings
13-24
Framework for Assessing Loss-Reduction Options
–
•
Series configured FACTS controllers, such as TCSC, SSSC, UPFC, or IPC (as discussed in Section 6)
For switching or cycling out-of-service equipment –
Shunt reactors not in use
–
High-loss transmission circuits
–
Equipment on hot stand-by that is rarely used
Each facility so listed should have the capability of being remotely adjusted or switched. Step 2: Off-line Optimizing Procedure with Optimal Power Flow
An optimal power flow (OPF) is needed to properly assess the impact that each listed facility will have on reducing transmission-network losses. Optimal power-flow packages are readily obtainable, such as a licensed add-on package of PSS/E. However, it may not readily undertake the analysis needed for optimal adjustment of all the various listed facilities to be tested. There may be a limit to the number of facilities it can simultaneously adjust, or properly function within the limits and the network’s demands, such as maximum operating voltage, thermal limits on equipment, and transmission lines. An investigation should be undertaken to assess the optimal power-flow programs available. It can also be undertaken to decide how best to proceed in either having an OPF vendor update the program to what is needed, or to write a new OPF to properly accomplish the network lossminimization objective [4, 5] Step 3: Collection of Data for Off-line Optimal Power Flow
All the data and models are assembled in the format required for the OPF. These data should include the network data normally studied for the power system under investigation. Care should be taken to ensure that the models are accurate enough to represent losses for which there is confidence. This stipulation applies to the transmission lines and transformers of the network as they are represented. As part of the suitability tests for the OPF, the adjustment setting or switch that the OPF must regulate in each facility, in its search for the minimum network losses, must be properly interfaced between the optimization solution and the facility. Otherwise, the minimum-loss objective cannot be reached. Step 4: Effectiveness of Each Facility in Reducing Losses
It would be very useful to evaluate the effectiveness of each identified loss-reduction facility included in the list assembled in Steps 1 and 1A. For each facility listed in Steps 1 and 1A, an individual optimal power flow—with minimum transmission network losses as the objective—is run. This analysis is conducted for the various baseline scenarios, especially for peak conditions. It will determine how effective each single facility is in loss-minimization by comparing the system losses it achieves with the reference base case. If there are too many facilities to examine on an individual basis, then the assessment can be undertaken based on a sample. It may be that some facilities do not contribute anything to loss-reduction, and so they can be considered for discarding. However, an investigation could be undertaken as to why they are 13-25
Framework for Assessing Loss-Reduction Options
ineffective, which may be caused by a rating limit in a nearby transmission line, transformer, or busbar. Step 5: Simultaneously Test All Facilities
With the selected existing facilities in place and active in the network model for the OPF, undertake a minimum-loss case using the peak-load condition used in Step 4. Determine the amount of reduced losses achieved with all existing loss-adjustment facilities in place. It would also be possible to assess which of the three categories of loss-reduction defined in Steps 1 and 1A above is the most effective. From the results of these tests, a peak loss-reduction value and annual energy loss-reduction value are determined. The procedures to evaluate demand and energy losses are the same as those used in Stage 1 and Stage 3 for Group A. The monetary value of loss cost (energy, capacity, and emission cost) are determined as previously described. The present value of the stream of costs is then determined. Step 6: Cost/Benefit Analysis
In order to achieve the loss-minimization that these studies imply could be achieved, an automated process for adjusting the selected facilities needs to be designed, engineered, and costassigned. Figure 7–1 from Section 7 is reproduced here as Figure 13–4 to provide some appreciation of this automated process. The cost for installing such an automated system includes its monitoring and telecommunication systems and an allowance for maintenance. Economic metrics like NPV, IRR, and/or payback period are then evaluated with the stream of cost flow determined in Step 5.
Regional Controller References
REGIONAL CONTROL
Power Plant Controller References
Minimum Loss Settings
POWER PLANT CONTROL UNIT CONTROL
CENTRAL OPTIMIZATION (INCLUDING OPTIMAL PF)
Measurements
Measurements
STATE ESTIMATOR
Excitation Voltage
Generator Measurements
POWER
Figure 13–4 Outline of the Automated System Required for Transmission Network Loss-Minimization
13-26
Framework for Assessing Loss-Reduction Options
Step 7: Analysis to Locate and Size New Facilities
If the option of analyzing the addition of new facilities is selected, the next step is to conduct a study to optimally locate and size additional facilities or devices, such as switched shunt capacitors, SVCs, and FACTS. Because the objective of adding such devices is solely to further reduce losses, the approach should be specifically directed for such a purpose. An optimal power flow can be used as a main basic tool for this case. Methodology for Stage 3 – Group C The technologies in Group C have been excluded from Groups A and B and collected together in a different group because they do not have the distinguishing features that the technologies in groups A and B have. However, they also do not share common characteristics with each other. For that reason, it is not possible to delineate an evaluation procedure that is applicable to all the technologies in this group. The evaluation methodology for each of these technologies is described in detail in the corresponding sections of this report. Examples and case studies are included in those sections to illustrate the procedures. If the technologies in Group C are selected for further analysis as an outcome of Stage 1 (Qualitative Screening ), the detailed analysis to be conducted at this stage would follow the specific procedure for each technology. Stage 4: Ranking of Methods The final stage is a ranking of the analyzed methods based on various criteria that can be adapted and accommodated to the various needs. The outcome of Stage 3 is used for this purpose. The approach followed in Stage 3 for evaluating the costs and benefits of loss-reduction options is based only on economic metrics. In the final ranking of prospective projects, other nonmonetary impacts or risks should be considered. For instance, for a given system, the environmental implications could be of primary importance. So the ranking procedure should be available to assign a high priority to measures that have less environmental impact. Other elements that should be considered in the final project selection are the possible adverse impacts on system operation caused by the outages required during the implementation. Indeed, these impacts may significantly affect the attractiveness of various loss-reduction measures. Operating constraints may result in operating-cost penalties, necessitate temporary operations that do not meet reliability criteria, or require a temporary interruption of supply to customers. These adverse impacts will vary depending on the outages required, the duration of the outages, and the flexibility of the system to accommodate the required outages.
13-27
Framework for Assessing Loss-Reduction Options
Case Study A study case is conducted on a generic power-system model to illustrate the application of the proposed framework. In this case, the framework stages are followed in the order described in the previous section. However, note that ,in a real application, the order of the framework stages and the calculations and analysis procedures in each stage can be altered according to the specific situation and needs. The model is implemented in PSS/E. Figure 13–5 is a one-line diagram of the study system model. The system is composed of 11 generating units and 9 loads. The transmission system is composed of two voltage levels: 230 kV (red in the one-line diagram) and 138 kV (blue in the one-line diagram). System peak load is 3220 MW, and the maximum generation capacity is 4800 MW. The complete data set is provided in Appendix A. Stage 1: Qualitative Screening The test system is not a real power system, but rather a generic reduced electric-system model set-up for illustration purposes. Only loss-reduction options in Group A are considered for this case study: that is, voltage upgrade and reconductoring. Because of the topological and physical characteristics of the system, the only line that can be upgraded to an upper voltage level is the 138-kV line West (3005) – MID138 (153). Indeed, it is the only 138-kV transmission line in the system for which a 230-kV busbar is available at both end substations. This voltage-upgrade project is considered as a candidate project for detailed analysis. Another option to be considered as a candidate project for loss-reduction is reconductoring of one or more or the transmission lines. There is no other information about transmission lines that can be used for conducting a qualitative screening process. At this stage, all lines are equally considered as feasible for the project. Selection refinement is conducted in Stage 3. Stage 2: Definition of Baseline Scenarios The step-wise approximation for the load-duration curve approach is followed here to evaluate the annual energy losses of the transmission system. Figure 13–6 shows the annual load-duration curve and approximation step. As can be seen in this figure, seven approximation steps have been defined for loss evaluation.Table 13-13 presents the range and duration of the seven loadduration steps. The total system annual energy load is 15,069 GWh.Table 13-4 shows generation dispatch for each of the approximation steps. Generation dispatch represents the economic dispatch for each load scenario. Certainly, an OPF function that takes into account transmission capacity has been used to determine generating unit output. Generating-unit cost data are presented in Appendix A. For simplicity, no future operating conditions or physical changes have been defined for this system. Therefore, for purposes of the analysis, it is assumed that the reference conditions or baseline do not change over time. However, there is no loss of generality from using this simplification, because the general procedure is applicable to a real system (for which future operating conditions are to be defined in a similar manner).
13-28
Framework for Assessing Loss-Reduction Options
Voltage upgrade option
Figure 13–5 One-Line Diagram of The Study System
13-29
Framework for Assessing Loss-Reduction Options
Load Percentage [%]
1.00 0.90 0.80 0.70 0.60 0.50 0.40 0.30 0.20 0.10 0.00
0
2000
4000
6000
8000
Cum ulative hours
Load Duration Curve
Step Curve
Figure 13–6 Annual Load-Duration Curve and Approximation Steps
Table 13-3 Load-Duration Steps Step
Upper Range
Lower Range
Step Load
Step Load
Step Duration
Accumulated hours
[%]
[%]
[%]
[MW]
[hr]
1
100
90
95.0
3059
60
2
90
78
84.0
2705
120
180
3
78
66
72.0
2318
650
830
4
66
54
60.0
1932
2100
2930
5
54
49
51.5
1658
3050
5980
6
49
36
44.0
1417
2780
8760
13-30
[hr]
Framework for Assessing Loss-Reduction Options Table 13-4 Generation Dispatch for Each Approximation Step Generating Unit Bus #
Name
Generation Dispatch [MW] Peak
Step 1
Step 2
Step 3
Step 4
Step 5
Step 6
101
MAIN-A
599.6
599.6
466.3
454.6
240.2
300.1
300.0
206
URBGEN
599.9
599.0
598.2
485.0
596.3
497.6
240.0
211
NORTH_G
615.9
615.9
615.7
615.9
577.2
363.7
470.5
1530
MID_G
161.9
109.3
86.5
0.0
0.0
0.0
0.0
1530
MID_G
161.9
109.3
0.0
0.0
0.0
0.0
0.0
1540
DOWNTN_G
215.8
215.8
214.8
150.0
0.0
0.0
0.0
3009
RURAL_G
129.8
149.2
0.0
0.0
0.0
0.0
0.0
3009
RURAL_G
129.8
149.2
200.3
142.8
0.0
0.0
0.0
3011
MINE_G
581.9
571.2
569.8
500.9
538.8
499.0
396.9
3018
CATDOG_G
60.0
60.0
60.0
60.0
60.0
60.0
60.0
86.43
CATDOG_G
86.4
0.0
0.0
0.0
0.0
0.0
0.0
TOTAL [MW]
3342.8
3178.6
2811.7
2409.3
2012.4
1720.4
1467.5
Stage 3: Detailed Evaluation of the Selected Methods The detailed evaluation procedure for loss-reduction options in Group A is followed in this case study. Step 1: Quantify and Cost the Reference Loss Level.
The reference loss level is determined by applying the step-wise energy-loss evaluation procedure with the approximation steps defined above. The cost of energy considered in this case is the annual average production cost determined from the generation cost of each step weighted with the corresponding step duration. Baseline conditions are presented in Table13–5: Table 13-5 Baseline Conditions Item
Unit
Value
System maximum load P System maximum load Q Demand loss at maximum load Demand-loss percentage System annual energy Annual energy losses Energy-loss percentage Average production cost
[MW] [MVAR] [MW] [%] [GWh] [GWh] [%} [c$/kWh]
3220 1100 122.8 3.8% 15,069 579.2 3.84% 0.64
13-31
Framework for Assessing Loss-Reduction Options
Step 2: Select Candidate Transmission Lines to Be Upgraded.
Reconductoring Prospective candidate lines for reconductoring are identified by determining their contribution to system losses at peak-demand conditions and annual energy losses. Table 13-6 shows the lines that contribute to demand and energy losses the most. Line demand losses at system peak conditions along with energy losses are considered here as metrics for first selection of candidate lines. In principle, all of these lines could be considered for further evaluation. In this case, however, the first two lines are selected as candidates. Line 153–3005 is selected because of its contribution to system demand losses, whereas line 3001–3003 is selected because it contributes to energy losses the most. It is assumed here that thermal upgrade or reconductoring of this line is technically feasible. In a real system, a basic engineering feasibility test should be conducted at this stage to determine whether it is possible to reconductor the lines. Table 13-6 Selection Metrics to Identify a Candidate Line for Reconductoring Transmission Line
Ckt
Voltage
Demand Losses at Peak
Annual Energy Losses
Line Length
[kV]
[MW]
[GWh]
[mile]
Bus 1 #
Bus 2 #
153
3005
1
138
14.8
48.4
50
3001
3003
1
138
12.2
70.3
45
3002
3004
1
230
12.0
69.1
90
201
202
1
230
11.5
50.9
90
201
204
1
230
9.4
37.0
90
151
152
1
230
8.2
31.6
70
151
152
2
230
8.2
31.6
70
Individual Evaluation of Project At this step, each of the potential reconductoring projects identified at first screening are evaluated independently. An expedited economical evaluation procedure, as used in the case studies in Section 6, is used for this purpose.
• Evaluation of 138-kV Lines 153–3005 and 3001–3003 Line maximum power flow and line-loading factor are the factors needed to conduct the simplified evaluation. In real transmission systems, the maximum power flow on a transmission line might not coincide with system peak-load conditions. Hence, it might not be possible to determine maximum power flow on a given transmission line from only a limited number of power-flow scenarios. However, if no detailed data on transmission-line loading is available, the line power flow at system peak conditions can be considered as the line maximum power flow for the preliminary study at this stage. For the selected lines, maximum current and line-loading factor are determined from the seven power-flow scenarios described above: 13-32
Framework for Assessing Loss-Reduction Options
•
Line 153–3005: Maximum current: 708 A, Line-loading factor: 0.58
•
Line 3001–3003: Maximum current: 1140 A, Line-loading factor: 0.5
Table 13–7 contains the economic parameters used in this analysis. The system average production cost shown in Table 13-5 is used as the cost of energy ($64/MWh).Table 13-8 presents the characteristics of the existing conductors for both lines, along with the characteristics of the replacement conductor. For the sake of simplicity, only one conductorreplacement option for each line is considered here. Table 13-7 Economic parameters – Application of the Evaluation Framework Parameter
Unit
Peak coincident factor
Value 0.8
Year of analysis
[yr]
30
Interest rate
[%]
7%
Energy cost
[$/kWh]
0.64
Energy cost escalation rate
[%/yr]
2.0%
Capacity cost
[$/kW-yr]
75
CO2 emissions per kWh
[tn/MWh]
0.9
CO2 value
[$/tn]
20
CO2 value escalation rate
[%/yr]
2.0%
Table 13-8 Conductor Data for Reconductoring Options – Application of Framework – Step 2 Line 153–3005
Line 3001–3003
Existing Conductor
Recond.
Type Code name
Parameter
Unit
Recond.
Option
Existing Conductor
ACSR
ACSR/TW
ACSR
ACSR/TW
Dove
Maumee
Lapwing
Athabaska
Option
Aluminum area
kcmil
557
768
1590
1373
Diameter
[in]
0.927
0.977
1.504
1.504
Weight
[lbs/Kft]
765
722
1790
1838
AC resistance at 75°C
[ohm/kft]
0.0375
0.0275
0.072
0.060
Ampacity at conditions*
[A]
727
870
1384
1522
Resistance reduction w.r.t existing conductor
[%]
26.7%
16.7%
* Rating conditions: 2ft/sec., ambient air temperature 25°C, sun, conductor temperature 75°C
The trapezoidal wire conductor MAUMEE/TW is selected for replacing the ACSR/TW Dove conductor of line 153–3005. The MAUMEE/TW conductor is only 6% higher than the existing 13-33
Framework for Assessing Loss-Reduction Options
Dove conductor, so it is assumed that it can be installed in the existing tower with minor modifications. The resistance is 26.7% lower, which allows for a significant reduction in line losses. In the case of line 3001–3003, a trapezoidal wire conductor ATHABASKA/TW is considered for replacing the existing ACSR Lapwing conductor. This TW conductor is of the same diameter as the ACSR Lapwing. Hence, there is no need for significant tower reinforcement. The resistance is about 17%. Table 13–9 provides an estimate of the investment costs. Table 13-9 Project Costs for Reconductoring Options – Application of Framework – Step 2 Line 153–3005
Line 3001–3005
Existing Conductor
Recond. Option
Existing Conductor
Recond. Option
Conductor type
ACSR
ACSR/TW
ACSR
ACSR/TW
Conductor code name
Dove
Maumee
Lapwing
Athabaska
Item
Unit
Conductor cost
[$/ft]
2.2
Structure cost/upgrades
[$/mile]
15,000
Stringing cost
[$/mile]
20,000
20,000
Engineering and other costs
[$/mile]
Installation and hardware costs
[$/mile]
3500
5000
Scrap value of existing line
[$/ft]
0.5
0.5
Total investment
[K$]
3275
4912
Levelized investment cost
[K$/yr]
263.9
395.9
5.1
Table 13–10 presents energy, demand, and emissions savings for the reconductoring options considered for each of the selected lines. The economic performance of the proposed solutions is presented in Table 13–11. It can be observed that the total present value of both solutions is less than the total present value of the losses that would be incurred with the existing conductor. Therefore, the monetary savings in terms of energy, capacity, and emissions savings justify the investment in both cases. However, the efficiency of the investment is superior in the case of line 153–3005, as can be observed from the economic and savings metrics described in the table. The superior efficiency is because, in this case, the replacement conductor produces a more significant reduction in losses. In the case of line 3001–3003, other conductor-replacement options with a larger-diameter TW could be studied. However, in large conductors, the trapezoidal replacement wire with a larger diameter has a much higher weight, so the effect on structure forces should be carefully investigated. Moreover, in the case of a large conductor, the conductor cost is relatively high, and, as a consequence, it is more difficult to off-set the investment cost from the loss savings.
13-34
Framework for Assessing Loss-Reduction Options Table 13-10 Annual Energy and Emissions Savings – Reconductoring Options - Application Of Framework – Step 2 Line 153–3005 Unit
Item
Line 3001–3003
Existing Conductor
Recond. Option
Existing Conductor
Recond. Option
ACSR
ACSR/TW
ACSR
ACSR/TW
Dove
Maumee
Lapwing
Athabaska
48.64
35.85
70.53
59.03
Average annual line losses
[GWh/yr]
Annual energy line loss savings
[GWh/yr]
Average annual line emissions
[tn/yr]
Annual line emission savings
[tn/yr]
11,515
10,353
Annual energy-loss savings w.r.t. to line losses
[%]
26.3%
16.3%
Annual energy-loss savings w.r.t. to system losses
[%]
2.2%
1.98%
Average peak-demand reduction
[MW]
3.92
2.1
12.79 43,784
32,269
11.50 63,483
53,131
Table 13-11 Economic Analysis Results: 138-kV Line 153–3005: Preliminary Analysis at Step 2 Line 153–3005 Item
Unit
Line 3001–3003
Existing Conductor
Recond. Option
Existing Conductor
Recond. Option
ACSR
ACSR/TW
ACSR
ACSR/TW
Dove
Maumee
Lapwing
Athabaska
74,653
58,295
97,553
86,066
Total present value*
[K$]
Levelized savings (energy + capacity)
[K$/yr]
1299.4
1027.7
Levelized CO2 savings
[K$/yr]
282.8
254.3
Levelized overall savings (energy+cap.+CO2)
[K$/yr]
1582.2
1282.0
Levelized savings per invested dollar
[$/$]
5.99
3.60
Pay-back period
[yr]
2.0
4.0
Internal rate of return
[%]
43%
26%
Average cost of demand reduction
[$/kW]
836
2146
Levelized cost of energy lossreduction
[$/MWhyr]
20.6
30.9
Levelized investment cost to [$/tn CO2] 22.9 save 1 tn of C02 * Total present value includes energy, capacity, and emissions costs plus investment
34.4
13-35
Framework for Assessing Loss-Reduction Options
Voltage upgrade of Line 153–3005 (138 kV to 230 kV) As mentioned above, the only line that can be upgraded to an upper voltage level in this system is the 138-kV line 153–3005. This line has been considered for reconductoring, so these two potential options for the same transmission line are mutually exclusive. This voltage-upgrade project is based on a real case reported in 0. The original case is a 115kVto 230-kV line nominal voltage increase implemented by the BPA. In this case study, the physical characteristics of the West (3005) – MID138 (153) line are defined similar to those of the real line in the BPA system, so that the basic characteristics and considerations of the real voltage-upgrade project apply to this generic case. In this study-system model, line West (3005) – MID138 (153) is a 50-mile-long, 138-kV, singlecircuit transmission line. The line is an H-frame structure using wood poles and I-strings. The line is a rather old design with high security margins. The line can be upgraded to 230 kV by changing the 6-unit (53/4 x 10-in or 14.6 x 25.4-cm ceramic insulators) I-strings on the outside phases to 9 units. The center phase can be converted from a 6-unit I-string to a V-string, in which each leg of the V-string has 9 units. The V-string prevents conductor movement for the center phase, and strut insulators are added to the I-strings on the outside phases to constrain the conductors. New hardware can be used to mount the conductor to the V-string and to the strut insulator. The phase spacing on the original 138-kV structure is 12 ft (3.6 m). It is considered in this case that phase spacing needs to be increased to 15 ft (4.6 m) for the upgraded 230-kV structure. 2 Hence, structure modification is needed. The conductor is a 577-kcmil ACSR Dove. This conductor is somewhat small for 230-kV transmission lines, but in the original project, BPA has not received any electromagnetic interference (EMI) or audible noise (AN) complaints. This prospective project is also evaluated at this step in the process to determine whether it is economically attractive. Unlike reconductoring projects, loss savings in voltage-upgrade projects need to be evaluated with a power-flow analysis of the entire network, because network impedance characteristics and topology are altered. Table 13–12 presents the cost estimate for this project. It is considered that some line bays will need to be upgraded at both substations to connect the existing line to the 230-kV busbars. Table 13–13 shows the reduction in demand-loss savings achieved with this voltage-upgrade project. It can be observed in this table that, whereas the transmission line loss-reduction at peak conditions is 7.62 MW, the system loss-reduction is 15.3 MW. This reduction is caused by the changes in the power-flow pattern across the grid. In reconductoring options, on the other hand, the reduction in total system losses is of the same magnitude as the reduction in the reconductored line. Table 13–14 shows savings in terms of energy and CO2 emissions, and Table 13–15 presents the economic analysis results. Note that, in the evaluation of losses presented in these tables, the generation dispatch is not altered with respect to the existing system. The generator at the slack bus absorbs the difference in losses, so the selection of the slack bus impacts the results. In a small system like this, the marginal unit in each scenario can be chosen as the slack machine, so that the representation is somehow more realistic.
2
In the original BPA voltage-upgrade case, the phase distance of 12 ft (3.6 m) was retained, even though normal phase spacing for a 230-kV line in a horizontal configuration at BPA is 20 ft (6.1 m).
13-36
Framework for Assessing Loss-Reduction Options Table 13-12 Conductor Data for Voltage Upgrade of Line 153–3005 – Application of Framework – Step 2 Item
Unit
Conductor type Conductor code name Line nominal voltage
[kV]
Structure cost/upgrades Engineering and other costs Installation and hardware costs Substations upgrading costs Total investment Levelized investment cost
[$/mile] [$/mile] [$/mile]
Existing Line
VoltageUpgraded Line
ACSR Dove
ACSR Dove
138
230 220,000
3500
[k$] [K$] [K$/yr]
2000 12,058 917
Table 13-13 Demand-Loss Savings – Voltage Upgrade of Line 153–3005 – Application of Framework – Step 2 Item
Unit
System peak demand
[MW] [MVAR] [MW] [%] [MW] [%] [MW] [MW] [%] [MW] [MVAR] [A]
System demand losses Demand loss percentage System loss-reduction System loss-reduction Line losses Line loss-reduction Line loss-reduction Line power flow Line-current magnitude
Existing Line 3220.0 1100.0 122.8 3.8% --14.77 -157.5 49.0 708.4
VoltageUpgraded Line 3220.0 1100.0 107.5 3.3% 15.3 12.5% 7.62 7.2 48.5% 193.1 60.1 511.7
13-37
Framework for Assessing Loss-Reduction Options Table 13-14 Energy and Emissions Savings – Voltage Upgrade of Line 153–3005 – Application of Framework – Step 2 Existing Line
Item
Unit
Average system annual losses
[GWh/yr]
Annual system energy-loss savings
[GWh/yr]
Average system annual emissions
[tn/yr]
Annual system emissions savings
[tn/yr]
Annual energy-loss savings w.r.t. to system losses
[%]
Voltage Upgrade Line
579.21
534.22 44.9
521,297
480,805 40,491 7.8%
Table 13-15 Economic Analysis Results – Voltage Upgrade of Line 153–3005 – Application of Framework – Step 2 Existing Line
VoltageUpgraded Line
Item
Unit
Total present value
[K$]
Levelized savings (energy + capacity)
[K$/yr]
4466.5
Levelized CO2 savings
[K$/yr]
1105.2
Levelized overall savings (energy+cap.+CO2)
[K$/yr]
5571.7
Levelized savings per invested dollar
[$/$]
5.73
Pay-back period
[yr]
2.0
Internal rate of return
[%]
41%
Average cost of demand reduction
[$/kW]
63.0
Levelized cost of energy lossreduction
[$/MWhyr]
21.6
Levelized investment cost to save 1 tn of C02
[$/tn CO2]
13-38
820,515
763,433
24.1
Framework for Assessing Loss-Reduction Options
Step 3: Determine Optimal Set of Projects.
The preliminary analysis in Step 3 reveals that the three options considered are reasonable candidates for loss-reduction projects. Reconductoring of line 153–3005 and voltage upgrade of the same line are mutually exclusive projects. (One can consider, as an option, increasing the nominal voltage and changing the conductor; however, that option is not considered here because it increases investment costs.) The evaluation of individual projects in Step 3 shows that the economic efficiency of these two projects is similar—as can be observed from the economic metrics, IRR and payback period. The investment cost for the voltage upgrade of Line 153–3005 is much higher than for the reconductoring option ($12 million as compared to $3.3. million for conductor replacement). However, the savings for the voltage upgrade are much higher than for the reconductoring option. These savings result not only from the lower current flowing in the higher-voltage line, but also from the change in the power-flow pattern. Indeed, the reduction in demand losses at peak conditions in the reconductoring case is 3.9 MW, whereas in the voltage-upgrade case, it is 15.3 MW. The annual energy-loss savings in the former case are 2.2% of the total system energy losses, whereas in the voltage-upgrade case, they are about 7.8%. Based on these characteristics, and taking into account that the objective of these projects is to reduce transmission losses as much as technically and economically feasible, the voltage-upgrade option should be selected over the reconductoring option for this transmission line. Therefore, the set of projects selected for final evaluation comprises:
•
Reconductoring of 138-kV Line 3001–3003 with an Athabaska trapezoidal conductor
•
Raising the nominal voltage of Line 153–3005 from 138 kV to 230 kV and retaining the existing ACSR Dove conductor
It is clear that in evaluating options in real power systems, a number of other technical and economic components are taken into account for ranking and selecting investment projects. Step 4: Evaluate Costs Associated with Upgrade Implementation.
In applications of this framework for actual systems, a comprehensive cost-analysis should be conducted at this step. In this generic and illustrative case study, however, there are no further elements to perform a detailed cost analysis. Therefore, the investment costs assumed in previous stages are used in all the steps of the evaluation process. Step 5: Conduct Benefit/Cost Analysis of Line Upgrades Without Increasing System Utilization.
At this step, the benefit/cost/ analysis of the complete set of projects is conducted. The evaluation of loss-reduction is performed with power-flow analyses of the complete system for the seven power-flow scenarios. Generations dispatch is not altered with respect to the dispatch of the existing system, so no variation in the average production cost is produced. Table 13–16 presents the results of this analysis in terms of demand- and energy-loss savings. It can be inferred from this table and from the results of Step 2 that, in this case, the effect on loss savings of both projects implemented together is very close to the sum of the effects of both projects implemented individually. Certainly, the loss-reduction achieved with the reconductoring of Line 3001–3003 is 2.1 MW (Table 13–10), and the loss-reduction achieved with the voltage upgrade of Line 153–3005 is 15.3 MW. The sum of these two values (17.4 MW) is very close to the 17.1 13-39
Framework for Assessing Loss-Reduction Options
MW of loss-reduction achieved when both projects are considered together. The same observation applies to the energy loss-reduction. Table 13–17 shows the results of the economic analysis. It is observed that the economic efficiency of the investment is as good as that for the voltage-upgrade project considered alone. Some economic metrics—like the levelized savings per invested dollar, the levelized cost of energy loss-reduction, and the levelized investment cost to save 1 tn of C02—worsen to a certain degree with respect to the voltage-upgrade project implemented individually, because of the influence of the reconductoring project. (Compare values in Table 13–11, Table 13–15, and Table 13–17). Table 13-16 Loss Savings – Complete Set of Projects – Application of Framework – Step 5 Item
Unit
Existing System
With Set of Projects
System peak demand System demand losses Demand loss percentage System loss-reduction System loss-reduction
[MW] [MVAR] [MW] [%] [MW] [%]
3220.0 1100.0 122.8 3.8% ---
3220.0 1100.0 105.7 3.3% 17.1 13.9%
Average system annual losses
[GWh/yr]
579.21
524.07
Annual system energy loss-savings
[GWh/yr]
Average system annual emissions
[tn/yr]
Annual system emissions savings
[tn/yr]
55.146 521,297
49,632
Annual energy loss-savings w.r.t. to system losses System average production cost
13-40
471,665
9.5% [$/MWh]
63.5
63.5
Framework for Assessing Loss-Reduction Options Table 13-17 Economic Analysis Results – Complete Set of Projects – Application of Framework – Step 5 Item
Unit
Existing System
With Set of Projects
Total present value
[K$]
820,515
754,375
Levelized savings (energy + capacity)
[K$/yr]
5342.8
Levelized CO2 savings
[K$/yr]
1354.6
Levelized overall savings (energy+cap.+CO2)
[K$/yr]
6697.4
Levelized savings per invested dollar
[$/$]
4.90
Pay-back period
[yr]
2.0
Internal rate of return
[%]
49%
Average cost of demand reduction
[$/kW]
80.0
Levelized cost of energy lossreduction
[$/MWhyr]
24.8
Levelized investment cost to save 1 tn of C02
[$/tn CO2]
27.5
Step 7: Evaluate Transmission-Capability Increase.
When the selected set of projects for transmission loss-reduction is implemented in this system, the transmission capability is increased, especially in the case of the voltage upgrade of Line MID (3005) – West(153). Considering that the transmission capability of this line is determined by conductor thermal limits, the capacity when this line operates at 138 kV is 174 MVA, whereas the capacity increases to 289 MVA when this line operates at 230 kV. In addition, the capacity of the reconductored line 3001–3003 increases from 330 MVA to 363 MVA when the existing ACSR Lapwing conductor is replaced by an ATHABASKA/TW conductor. In real power systems, the transmission limits of important corridors are determined by considering all applicable reliability constraints. Steady-state and dynamic contingency analysis is usually conducted to determine secure transmission limits. Normally, the transport capacity of long transmission corridors is limited by the stability of voltage-control conditions, and it is normally considerably less than the thermal capability of the conductor. In this case study, however, it is assumed that the transmission limits of these lines at normal operating conditions are determined by the conductor thermal rating at standard conditions (wind 2ft/sec., ambient air temperature 25°C, sun, conductor temperature 75°C). Step 8: Evaluate Benefits Versus Costs of Increased Capacity Permitted by Upgrades.
The proposed framework includes measures in Group A for the assessment of other possible benefits that could be achieved if the system is operated so as to take advantage of the increased 13-41
Framework for Assessing Loss-Reduction Options
transmission capacity allowed by the upgrading projects. In this system, the transmission capacity of line MID (152) – West(3004) has an important impact on the system operating cost, because it restricts the dispatch of the most economic generating units. In order to evaluate the additional benefits of increasing the transmission capacity of these two lines, a security-constrained dispatch program (OPF) is used to determine the economic dispatch with the increased transmission limits. The OPF calculates the minimum system generation cost obtainable within the applied transmission constraints. Table 13–18 presents both the current transmission limits and the increased transmission limits permitted by the line upgrades. Table 13–19 shows the power flow over the two upgraded lines corresponding to these generationdispatch patterns. It is observed from this table that the capacity of Line MID 230 (152) – West (3004) effectively constrains the economic generation dispatch. Indeed, when the upgraded transmission limit is considered in the OPF, the power flow over this line reaches its new limit. The other upgraded transmission line, Mine (3001) – S. Mine (3003), has no effect on the economic dispatch, because its power flow is well below the limit in both cases. A similar analysis is conducted for all seven of the power-flow scenarios to evaluate annual energy losses and average production. The results are presented in Table 13–20. It is observed in this table that, if the extra transmission capacity allowed by line upgrades is utilized, the following effects are obtained:
•
Demand loss is reduced, but to a lesser degree than the reduction achieved when the system is operated with the same transmission limits as in the existing system.
•
Energy loss increases with respect to the existing system. This loss increase occurs because, with the increased transmission capacity, power is moved over longer distances. Indeed, the upgraded line MID 230 (152) – West (3004) is heavily loaded most of the time.
•
Average production cost is reduced by $2.2 /MWh
Because the energy losses increase rather than decrease, the option of operating the system by taking advantage of the increased limits permitted by the transmission line upgrades is not acceptable, because the primary objective for implementing these projects is to reduce losses.
13-42
Framework for Assessing Loss-Reduction Options Table 13-18 Generation Dispatch with Increased Transmission Capacity – Application of Framework – Step 8 Generator
Dispatch [MW]
Bus #
Name
With Original Transmission Limits
With Upgraded Transmission Limits
101
MAIN-A
599.6
599.6
206
URBGEN
599.9
598.9
211
NORTH_G
615.9
615.8
1530
MID_G
161.9
98.5
1530
MID_G
161.9
98.5
1540
DOWNTN_G
215.8
215.8
3009
RURAL_G
129.8
180.9
3009
RURAL_G
129.8
180.9
3011
MINE_G
581.9
599.9
3018
CATDOG_G
60.0
60.0
86.43
CATDOG_G
86.4
86.4
TOTAL [MW]
3342.8
3335.5
Table 13-19 Power Flow on Upgraded lines – Application of Framework – Step 8 Power Flow [MVA] Nominal Voltage
Original Dispatch
Updated Economic Dispatch
Updated Limit
MID 230 (152) – West (3004)
230 kV
203
289
289
Mine (3001) – S. Mine (3003)
138 kV
248
251
363
Transmission line
[MVA]
13-43
Framework for Assessing Loss-Reduction Options Table 13-20 Savings and Benefits Obtained with the Set of Upgrading Projects – Application of Framework – Step 8 Item
Unit
With original transmission limits
With upgraded transmission limits
System peak demand System demand losses Demand-loss percentage System loss-reduction System loss-reduction
[MW] [MVAR] [MW] [%] [MW] [%]
3220.0 1100.0 105.7 3.3% 17.1 13.9%
3220.0 1100.0 115.5 3.6% 7.3 5.9%
Average system annual losses
[GWh/yr]
524.07
597.5
Annual system energy loss-savings
[GWh/yr]
55.14
-18.3
9.5%
-1.9%
63.5
61.3
Annual energy loss-savings w.r.t. to system losses System average production cost
[$/MWh]
Stage 4: Ranking of Methods At this stage, the various loss-reduction options evaluated in detail at Stage 3 are ranked according to the adopted criteria and selected for the next steps in the TEE process. The selection criteria may vary greatly from one utility to another, and even for different circumstances within the same enterprise or institution. Hence, the ranking and selecting approach needs to be adapted to each particular situation. However, it is recommended that not only economic metrics be considered for this purpose, but also other less-direct monetary aspects and nonmonetary impacts. In this illustrative case study, only the loss-reduction options included in Group A have been studied; therefore, the ranking process is not applicable for this case.
13-44
Framework for Assessing Loss-Reduction Options
References [1]
Transmission Line Reference Book : 115–345 kV Compact Line Design. EPRI, Palo Alto, CA: 2008. 1016823.
[2]
L. Barthold, D. Douglas, and D. Woodford, “Maximizing The Capability of AC Transmission Lines.” CIGRE (2008).
[3]
Feasibility of Increasing Transmission Line Capacity by Voltage Upgrade. EPRI, Palo Alto, CA: 2007. 1013984.
[4]
IEEE Power Engineering Society, IEEE Tutorial Course, Optimal Power Flow: Solution Techniques, Requirements, and Challenges. 1996.
[5]
Narayan S. Rau, Optimization Principles. John Wiley & Sons, Inc. 2003.
[6]
Increased Power Flow by Incremental Transmission Upgrades: Impact on Planning and Operations. EPRI, Palo Alto, CA: 2006. 1012406.
[7]
Risk and Rewards of Incremental Transmission Upgrades. EPRI, Palo Alto, CA: 2006. 1010626.
13-45
14
PRINCIPLE OF MEASUREMENT AND VERIFICATION FOR TEE PROGRAMS This section defines the general requirements of an evaluation, measurement, and verification (EM&V) for energy efficiency in the power-delivery system.
This section covers issues such as: 1. The need for such an effort because of the lack of industry standards to account for electrical losses on the T&D systems 2. Comparison with end-use efficiency projects for which certain established EM&V exist, and from which lessons learned can be drawn to quantify and verify the energy savings on transmission systems 3. The need for “calibration” of the simulation-based M&V efforts because of the absence of baseline conditions after the loss-reduction options are applied 4. A five-step example of how a simulation-based M&V method for verification of transmission loss-reduction could be implemented 5. Some of the difficulties that may face EM&V and how they can be worked around
Introduction Evaluation, measurement and verification (EM&V) of an EE program is usually the final step in the process. Measurement and verification (M&V) is often mentioned within the context of energy-efficiency implementation as the process of measuring the savings resulting from the installation of a specific EE measure and verifying the accuracy of those savings. Within the broader context of EE programs, M&V activities can assist utilities to perform an impact evaluation of their programs. As compared to end-use efficiency projects, for which certain established measures (such as the replacement of incandescent bulbs with CFLs) have associated energy savings, efficiency projects in transmission and distribution systems do not have the benefit of widely accepted savings guidelines. Currently, there is no industry-wide standard method to account for either electrical losses on the transmission or distribution system or the loss-reduction opportunities for T&D upgrade projects. On the other hand, end-use EE programs have been implemented for more than three decades on both a national and a world-wide basis. Consolidated and well-established procedures, rules, and methodologies have been implemented during these years to effectively deploy EE programs and overcome the numerous obstacles and difficulties that this type of program entails. Clearly, the nature of the options for improving transmission efficiency, the participating parties, and those 14-1
Principle of Measurement and Verification for TEE programs
involved in the implementation decision-making process for potential transmission energyefficiency (TEE) programs may differ substantially from their end-use counterparts. The evaluation of the process in end-use EE programs is more complex than in TEE programs, because they involve many parties and participants and generally have broader objectives. Indeed, process evaluations in end-use EE programs usually address utility operations, including the efficiency of service delivery, the effectiveness of promotional strategies, and the coordination of programs with other EE activities and utility functions. End-use process evaluations also analyze customer satisfaction with program services and related issues dealing with market acceptance. TEE programs, on the other hand, would be implemented by the utility on its own assets and would be managed and controlled by the utility itself. Therefore, the M&V activities in TEE will mainly focus on quantifying savings and verifying the accuracy of those savings. Despite the inherent differences that may exist between end-use and TEE programs, the concepts, approaches, and terminology from the end-use energy-efficiency technology can be used as a reference for developing standards to measure and verify energy savings from TEE projects.
Method for M&V Applied in End-Use EE Programs M&V is the process of using measurements to reliably determine the actual savings created within an individual facility by an EE project. Savings cannot be directly measured, because they represent the absence of energy use. However, savings can be determined by comparing measured use before and after the implementation of a project. The comparison of before-and-after energy use or demand can be made on a consistent basis, using the following general equation:
Savings = [ Before( Energy, Demand) − After( Energy, Demand) ] ± Adjustments The “before” term in the above equation is more commonly known as the “baseline.” The “after” term is also more commonly called the “post-installation” or “post-implementation” term. The “adjustments” term in this general equation is used to re-state the energy use or demand of the baseline and post-installation periods under a common set of conditions, in the event that some operational parameters outside of those directly influenced by the project also change. An example is the determination of the savings resulting from a lighting retrofit in an entire department store when the store’s hours of operation also changed during the same timeframe. The facility’s energy savings (O&M or water) cannot be measured, because they represent the absence of energy use. Instead, savings are determined by comparing the energy use before and after the installation of conservation measure(s), making appropriate adjustments for changes in conditions [1]. There are four accepted methods for determining savings in end-use EE programs: retrofit isolation with key-parameter measurement, retrofit isolation with all-parameter measurement, whole-facility measurement, and calibrated simulation. The main characteristics of these methods are summarized in Table 14–1.
14-2
Principle of Measurement and Verification for TEE programs Table 14-1 Characteristics and Typical Applications of Methods for M&V in End-Use EE Programs M&V method Retrofit Isolation with Key-Parameter Measurement
Characteristics and Savings Calculation Based on a combination of measured and estimated factors when variations in factors are not expected. Savings are determined by means of engineering calculations of baseline and post-installation energy use, based on measured and estimated values. Engineering calculation of baseline and postinstallation-period energy use and demand are evaluated from: •
Typical Applications A lighting retrofit in which power draw is the key performance parameter that is measured periodically. Estimate operating hours of the lights based on building schedules and occupant behavior.
short-term or continuous measurements of key
operating parameter(s) •
estimated values
Adjustments are made as required. Retrofit Isolation with All-Parameter Measurement
This option is based on periodic or continuous measurements of energy use taken at the component or system level when variations in factors are expected. Energy or proxies of energy use are measured continuously. Periodic spot or short-term measurements may suffice when variations in factors are not expected. Savings are determined from analyses of baseline and reporting-period energy use or proxies of energy use.
Whole-Facility Measurement
Savings are determined by measuring energy use and demand at the whole-facility or sub-facility level. Savings are determined from analysis of baseline and reporting-period energy data. Typically, regression analysis is conducted to correlate with and adjust energy use to independent variables such as weather, but simple comparisons may also be used.
Calibrated Simulation
Computer-simulation software is used to model energy performance of a whole facility (or subfacility). Simulation routines are demonstrated to adequately model the actual energy performance measured in the facility. This method usually requires considerable skill in calibrated simulation. Baseline energy use, determined by using the calibrated simulation, is compared to a simulation of post-installation-period energy use.
Application of a variable-speed drive and controls to a motor to adjust pump flow. Measure electric power with a kW meter installed on the electrical supply to the motor, which reads the power every minute. In the baseline period, this meter is in place for a week to verify constant loading. The meter is in place throughout the post-installation period to track variations in power use. Multifaceted energymanagement program affecting many systems in a facility. Measure metered energy use for a twelve-month baseline period and throughout the postinstallation period.
Multifaceted energymanagement program affecting many systems in a facility, but in which no meter existed in the baseline period. Energy-use measurements, after installation of gas and electric meters, are used to calibrate a simulation.
14-3
Principle of Measurement and Verification for TEE programs
The last method—calibrated simulation—has characteristics that make it more suitable as a base for developing M&V methods for TEE programs. Computer simulation is a powerful tool that allows an experienced user to model a building’s electrical and mechanical systems in order to predict building energy use both before and after the installation of an energy-conservation measure. The accuracy of the models is ensured by using metered site data to describe baseline and/or performance-period conditions. Carefully constructed models can provide savings estimates for an individual energy-conservation project. Calibrated simulation is applicable in end-use EE projects with these characteristics (among others): complex equipment replacement and control projects for which the use of retrofit isolation methods (1st and 2nd methods) is not applicable; new construction projects are involved; baseline does not exist; or energy-savings values per individual measure are desired. Calibrated simulation analysis is an expensive M&V procedure. Even for the simplest projects, simulation modeling and calibration are time-intensive activities and should be performed by an accomplished building-simulation specialist. Calibrated Simulation methods follow five general steps:
•
Collect data
•
Input data and test baseline model
•
Calibrate the baseline model
•
Create and refine the performance-period model
•
Verify performance and calculate savings
The method used to determine savings will depend upon the phase of the project. During project development, proposed savings are determined by subtracting the results of the performanceperiod model from the results of the calibrated baseline model, both using the agreed-upon weather data and facility operating conditions. Impact evaluations often require data on energy consumption and related variables for a full year after the installation of efficiency measures. As a result, the evaluation of savings is typically performed during the second year of implementation at the earliest. In this method, after the first year of performance, there are two options for calculating verified savings: 1) calibrate the performance-period model and subtract the results of the baseline model using the same conditions; or 2) subtract the measured utility data for the performance period from the results of the baseline model that was updated to actual conditions. Individual energy conservationmeasure savings are determined by the difference in energy or demand use between two consecutive runs. The savings determined for the individual energy-conservation measures should total the savings determined from the baseline and performance-period runs [2].
M&V Considerations for Transmission Energy-Efficiency Projects An approach based on a calibrated simulation model could be formulated for the accountability of the savings actually achieved with TEE projects. The methodology is attractive for this application because the baseline conditions are no longer measurable after the loss-reduction option has been applied (except perhaps for voltage optimization or diverting power flow, for which control can be deactivated for some period of time). 14-4
Principle of Measurement and Verification for TEE programs
The following is an example of how a calibrated-simulation method for verification of transmission loss-reduction could be implemented. Suppose that the set of implemented loss-reduction measures is comprised of one transmission line reconductored with an advanced conductor and a transmission line uprated to a higher voltage level. Assume that both projects are built in year 1 and commissioned at the beginning of year 2. The procedure for an energy-loss savings calculation would be:
•
Step 1: Determine from the measurement record the actual transmission-system losses for year 2.
•
Step 2: Determine via simulation the total losses for year 2.
•
Step 3: Calibrate the model and procedure to match the simulation results with the actual losses to a reasonable level of accuracy.
•
Step 4: Determine via simulation the total losses for year 2 that would result if the line upgrades were not in service. Hence, the model with the original line configuration is used. All other elements in the simulation are retained to make the simulation results consistent. This will be the updated baseline or reference case against which the real impact of the measures will be assessed.
•
Step 5: Determine the loss achieved as the difference between the loss levels determined in Step 5 and Step 3.
The process is conducted in the same fashion for the following years of the analysis horizon. Steps 1 and 3 pose a challenge for the practical implementation of this methodology. The total energy loss for the entire system can be determined for an electric system because of system metering. However, a detailed evaluation is difficult for a number of reasons: Energy losses are calculated by taking the difference between all the known metered inputs to the electrical system and subtracting all the known outputs. Inputs and outputs at the control-area boundaries and generator outputs are normally recorded in increments of MW per hour. These values therefore encompass the total system energy-input on a year-end to year-end basis. Readings from most customer meters are recorded each month by meter-reading methods that can only record about a twentieth of the meters for each business day in the month. Hence, although each customer has an annual energy record, it is not based on a true calendar-year consumption period. This situation results in a meter-reading billing-cycle error. (The use of electronic meters allows a utility to minimize this error.) Moreover, there are loads that have no meters, so that the energy use has to be estimated. Substation power and light requirements are also not normally metered. All these factors have been identified for many utilities as part of their loss-accounting challenges. In the specific case of a transmission network, the measurement of annual energy losses would be determined by taking the difference between the inputs and the system output, and it would require coordinated measurements at all boundary substations. Therefore, a comprehensive investigation should be conducted to evaluate the possibility of accurately determining transmission losses from measurements. An IEEE report addresses the difficulties in the estimation of transmission losses on transmission networks and proposes a method for the calculation of transmission-loss coefficients when the only information available
14-5
Principle of Measurement and Verification for TEE programs
are active injection measurements and active balance sheets [3]. However, its applicability for the M&V of TEE programs needs to be carefully evaluated. The process of simulation-model calibration (Step 3) also presents difficulties and challenges. The representation of all the sources of losses in a transmission system is not completely included in the model. Power-flow simulation models usually include a representation of Joule losses in transmission lines and transformers. NLL such as transformer excitation losses, and losses of shunt compensators and controllers (reactors, SVC synchronous condensers) could be included in these models as well. However, corona losses and other NLL have to be determined separately. Despite this possible modeling shortage, the main difficulty may arise from the fact that energy losses are determined by considering a relatively small number of representative snapshots and integrating them along the load-duration curve. Each snapshot represents the average characteristics of a large number of system operating conditions. Hence, in order to calibrate the model to fit the simulation results with measurements, some model parameters could be changed. But those changes would not represent actual system characteristics. Note, however, that because the main objective is to compare losses for conditions “with” and “without” the considered loss-reduction measures, and not necessarily to determine the real amount of the losses, reasonable mismatches between the model and the measurement (assuming that loss-measurement can be done) could be accepted. (But simulations would need to be consistent.) Moreover, for some of the considered loss-reduction measures—such as shield-wire segmentation, insulation losses, and even reconductoring—it would not be necessary to model and measure losses on the entire system, because these measures only affect losses on the transmission line where they are implemented. Hence, simpler M&V approaches can be envisaged for these measures. The development of an integrated procedure for M&V of TEE programs requires as a first step a detailed investigation of the feasibility of the proposed approach—especially Steps 1 and 3. The specific protocols for determining actual losses based on measurements, model set-up and updates, and model calibration need to be developed.
References [1].
Energy-Efficiency Planning Guidebook: Energy-Efficiency Initiative. EPRI, Palo Alto, CA: 2008. 1016273.
[2].
M&V Guidelines: Measurement and Verification for Federal Energy Projects, Version 3.0, 2008. http://ateam.lbl.gov/mv/docs/MV 20Guidelines 20Version 3.0Final.pdf
[3].
S. Fliscounakis, F. Lafeuillade, and C. Limousin, “Estimation of Transmission Loss Coefficients from Measurements,” Power Tech, 2005 IEEE Russia (June 27–30, 2005).
[4].
M. W.Gustafson and J.S. Baylor, “The Equivalent Hours Loss Factor Revisited,” IEEE Trans. on Power Systems. Vol. 3, No. 4 (November 1988).
[5].
M. W.Gustafson and J.S. Baylor, “Transmission Loss Evaluation For Electric Systems,” IEEE Trans. on Power Systems. Vol. 3, No. 3 (August 1988).
14-6
15
CONCLUDING REMARKS AND FUTURE RESEARCH
Summary Loss reductions in transmission systems are an important consideration for utilities concerned with operating their transmission systems efficiently, especially in the new climate of generalized interest and efforts for energy-efficiency improvements. Programs to improve energy efficiency have been implemented by utilities and enterprises in the electricity industry for more than three decades. However, these programs have been focused mainly on end-use customers, and little or no attention has been paid to the improvement of energy efficiency in other segments of the utility value chain—including energy efficiency in the transmission and distribution networks. Improving efficiency in the transmission networks by reducing associated power losses plays a very important role in the effort to enhance overall system efficiency, because transmission losses account for approximately 2– 4% of the total electricity generated in the United States. This project is an effort to provide the electricity industry with an investigation of technological options to reduce losses in transmission networks. Although the measures considered here to reduce losses are well known to the industry, they have normally been applied in actual systems to increase transmission capacity and improve reliability (with consideration of the impact on losses a side effect or byproduct). In this report, the available technological options are evaluated with the reduction in transmission losses as the main objective. A comprehensive strategic framework is developed to assess and evaluate the energy-efficiency opportunities from transmission system loss- reduction and to choose the most effective options. The values associated with reducing transmission losses impact power-system participants in many different ways, depending on system characteristics, ownerships, regulatory frameworks, and other circumstances. Therefore, the most appropriate and simplest way to assess the benefits of reducing transmission losses is by evaluating the cost of these losses to society as a whole. From a societal point of view, reducing transmission losses provides a benefit by reducing investment in generation and transmission infrastructure. And it also plays an important role in reducing carbon emissions. A monetary value can be established for these three elements, as demonstrated in Section 4. Thus, cost-effective analyses of each loss-reduction option can consist of comparing, in economic terms, the required investment cost with the overall societal benefits. If the option proposed to reduce losses is cost-effective, it should be implemented because it is deemed to be beneficial for society. Specific regulatory instruments need to be adopted in order for the utilities to recover their investment costs and to provide incentives to promote the implementation of loss-reduction technologies. The main conclusions that can be drawn from the investigation conducted in this project, related to implementation issues and the cost-effectiveness of loss-reduction options, are summarized below:
15-1
Concluding Remarks and Future Research
•
At present, there is no industry-standardized method to account for either electrical losses on the transmission system or for the loss-reduction opportunities for T&D upgrade projects. There is a need to develop an industry-wide standard approach to transmission loss studies and to evaluate transmission loss-reduction options.
•
There are a number of analytical subtleties involved in quantifying the loss-reduction impact of transmission projects. Indeed, some of the available options to reduce losses have a dual effect: they both increase transmission capacity and reduce losses. The extent to which lossreduction methods can be evaluated depends upon the primary purpose of the improvement. For these cases, the proper definition of baseline conditions is crucial to correctly identifying and quantifying the benefits. Hence, a methodology to establish an appropriate baseline is key. An approach to define baseline conditions for different project types and options is provided in this report.
•
Raising transmission-line nominal voltage may allow reduction of losses in an upgraded transmission line by more than 50%, if the transmission-line usage is not significantly increased after the upgrading. The loss-reduction achieved in MW in the entire transmission network is greater than the reduction in MW achieved in the upgraded line because of the changes in the power-flow pattern.
•
Reconductoring with trapezoidal-wire conductors of equal diameter allows utilities to reduce transmission-line losses up to 20% without significant modifications in structures. In some cases, this strategy may result in a cost-effective solution, depending primarily on the line utilization (line loading) and the value of the cost items involved (energy, capacity, and emissions). The impact of the line loss-reduction on the system losses will depend on the relative weight of the line losses on the overall transmission-network losses. Hence, even though reconductoring a given transmission line may be cost-effective, the reduction achieved on total system losses may not be significant. As a result, it might be necessary to reconductor a number of transmission lines to achieve an appreciable reduction in the transmission-network losses.
•
Reconductoring with advanced low-sag conductors may, in some cases, allow utilities to meet reliability constraints at N–1 conditions, while achieving a net loss-reduction in the transmission-line losses at normal operating conditions. In such cases, the quantification of benefits is more cumbersome, due to the dual-effect feature of the solution.
•
Hierarchical dynamic voltage control to help reduce transmission loss seems to be the most effective way to reduce transmission losses. Experience from actual implementation of this technology in different power systems reveals that overall transmission losses can be reduced by 1–5%. Studies demonstrate that the solution is cost-effective and has a good economic performance.
•
Large transformers are usually designed for an optimal trade-off between losses and investment cost, and in general they are efficient. Besides, because of the high investment cost, there is little room to economically justify the replacement of an existing transformer with another more energy-efficient one. However, if the unit replacement is decided upon for reasons other than improving efficiency, there is an opportunity to select a more-efficient transformer than the one being replaced—thus achieving a reduction in transformer losses. In particular cases involving very old, large transformers with high losses, especially in the core, it may be possible to justify the replacement by taking advantage of a substantial dollarefficiency gain by purchasing a new high-efficiency transformer.
15-2
Concluding Remarks and Future Research
•
In some cases, a significant amount of loss can be reduced by converting an existing transmission line from ac to dc operation, if the converted dc circuit is loaded in a similar way to the existing ac line. The savings potential depends upon the line-loading pattern and on the length of the transmission line. Although the principles and applicability of ac to dc conversion have been proven, no commercial conversions of ac to dc have been implemented to date.
•
Other options, like shield-wire segmentation and insulation loss-reduction, may only contribute moderately to transmission network loss-reduction, but they may be cost-effective and relatively easier to implement.
•
Industry needs a comprehensive methodology to evaluate the application of different available options to reduce transmission losses. A framework for the assessment of energyefficiency opportunities to reduce losses in transmission grids is proposed in this report.
•
Industry-wide deployment of transmission energy-efficiency programs will need wellestablished measurement and verification (M&V) protocols to demonstrate the realized savings and document the benefits.
Future Work The work performed in this project is a first step toward the development of effective and strategic methodologies and approaches that will allow utilities to evaluate, monitor, and verify the implementation of options to improve the energy efficiency of transmission systems. The next steps foreseen for continuing this investigation are:
•
Investigate the technological options for reducing transmission losses in further detail. Specifically investigate diversion of power flow by power-flow controllers and the conversion of ac to dc.
•
Test the evaluation framework on a number of real systems in order to demonstrate its capacity to consistently quantify losses and assess effective solutions for transmission lossreduction.
•
Refine the evaluation framework to accommodate different power systems in terms of technical, regulatory, and business structures.
•
Expand the framework to include the next steps in the process of evaluation and implementation of measures to reduce losses (specifically, engineering design and implementation and M&V processes).
•
Develop and test an efficiency-accounting (M&V)methodology.
Investigate the development of models that adjust the value of line resistances for the expected temperatures and ambient conditions. Changes of transmission-line resistances due to temperature have a significant impact on losses. The accuracy of loss can be improved if the resistance of the power-transmission-grid model is corrected for particular weather and loading conditions. Practical implementation of the temperature/loading dependency may be possible. And it is justifiable because it allows a more accurate allocation of the transmission losses, and more accurately determines power flows and the network voltage profile. In terms of M&V, because transmission losses will need to be evaluated over a long period of time in the future, it would be very difficult to estimate all future weather conditions affecting the different parts of 15-3
Concluding Remarks and Future Research
the transmission systems. Hence, an approach to estimate the average or aggregate value of resistance variations should be investigated.
15-4
A
APPENDIX – TEST-SYSTEM DATA Table A-1 Buses Data: Load, Generation, and B-Shunt at Peak Conditions Bus #
Bus Name
Nominal Voltage [kV]
Load [MW]
Generation
[MVAr]
[MW]
B-shunt
[MVAr]
[MVAr]
101
MAIN-A
21.6
599.6
95.9
102
MAIN-B
21.6
0
0
151
MAINPANT
230
250
152
MID230
230
100
153
MID138
138
600
210
154
DOWNTN
138
400
150
201
NORTH
230
202
EAST230
230
203
EAST138
138
204
SUB230
230
205
SUB138
138
206
URBGEN
18
599.9
58.6
211
NORTH_G
20
615.9
61.8
1530
MID_G
19
323.9
265.5
1540
DOWNTN_G
19
215.6
0.2
3001
MINE
138
3002
E. MINE
230
3003
S. MINE
138
3004
WEST
230
3005
WEST
138
200
60
3007
RURAL
138
270
95
3008
CATDOG
138
200
75
3009
RURAL_G
19
259.6
133.9
3011
MINE_G
13.8
581.9
220
3018
CATDOG_G
13.8
146.5
174.8
350 100
550
150
300
900
320
300
120
A-1
Appendix – Test-System Data Table A-2 Transmission Lines From Bus #
A-2
To Bus #
Ckt
Nominal Voltage
R
X
B
Rate
Length
[kV]
[p.u.]
[p.u]
[p.u.]
[MVA]
[mi]
151
152
1
230
0.0106
0.0992
0.2148
474
70
151
152
2
230
0.0106
0.0992
0.2148
474
70
151
201
1
230
0.0106
0.0992
0.2148
474
70
152
202
1
230
0.0121
0.1134
0.2455
474
80
152
3004
1
230
0.0187
0.0737
0.146
289
50
201
202
1
230
0.0103
0.129
0.2792
474
91
201
204
1
230
0.0102
0.1276
0.2761
474
105
3002
3004
1
230
0.0119
0.1489
0.3222
474
105
153
154
1
138
0.0382
0.2117
0.0576
217
56
153
154
2
138
0.0382
0.2117
0.0576
217
56
153
3005
1
138
0.052
0.1969
0.0543
174
50
154
203
1
138
0.0382
0.2117
0.0576
217
56
154
205
1
138
0.0205
0.1134
0.0309
217
30
154
3008
1
138
0.0546
0.3025
0.0823
250
80
203
205
1
138
0.0239
0.1323
0.036
217
35
203
205
2
138
0.0239
0.1323
0.036
217
35
3001
3003
1
138
0.017
0.1588
0.0432
304
45
3003
3005
1
138
0.0334
0.1853
0.0504
217
49
3003
3005
2
138
0.0334
0.1853
0.0504
217
49
3005
3007
1
138
0.0287
0.1588
0.0432
217
42
3005
3008
1
138
0.0289
0.189
0.0514
240
50
Appendix – Test-System Data
Table A-3 Transformer Data From Bus #
To Bus #
Ckt
Nr. of taps
R
X
Rate
[kV]
[p.u.]
[p.u]
[MVA]
Tap position
101
151
1
21
0.0001
0.0136
900
1.021
102
151
1
5
0.0001
0.0136
900
1.0
152
153
1
33
0.0000
0.01857
700
0.97
153
1530
1
10
0.0001
0.022
538
1.057
154
1540
1
10
0.0001
0.044
269
1.0
201
211
1
5
0.0007
0.02125
800
1.0
202
203
1
33
0.0002
0.01625
800
1.0
204
205
1
21
0.0002
0.026
500
1.049
205
206
1
5
0.0001
0.019
700
1.0
3001
3002
1
33
0.0002
0.0325
400
1.0
3001
3011
1
5
0.0001
0.012
1000
1.0
3004
3005
1
33
0.0002
0.0325
400
1.0
3007
3009
1
10
0.0001
0.022
540
1.0
3008
3018
1
11
0.0001
0.021
580
1.059
A-3
Appendix – Test-System Data Table A-4 Generators Power-Flow Data Bus #
Machine ID
Pmax
Pmin
Qmax
Qmin
Rate
[MW]
[MW]
[MVAr]
[MVAr]
[MVA]
101
1
600
240
600
-100
750
206
1
600
240
350
0
625
211
1
616
246.5
400
-100
725
1530
1
216
86.4
135
0
269
1530
2
216
86.4
135
0
269
1540
1
216
86.4
135
0
269
3009
1
216
86.4
135
0
269
3009
2
216
86.4
135
0
269
3011
1
600
240
600
-300
750
3018
1
250
50
72
0
312
3018
2
250
50
72
0
312
Table A-5 Generators Operation-Cost Parameters Bus #
A-4
Machine ID
Cost Polynomial Coefficients CQ
CL
CC
[MBTU/MW2-h]
[MBTU/MW-h]
[MBTU/h]
Fuel Cost
O&M Cost
[$/MBTU]
[$/MWh]
101
1
0.001
7.03
547.34
8.85
4.5
206
1
0.001
7.438
758.97
6.91
4.5
211
1
0.001
7.499
526.21
6.91
4.5
1530
1
0.000
9.433
95.826
8.85
3.0
1530
2
0.000
9.433
95.826
8.85
3.0
1540
1
0.000
9.433
95.826
7.74
3.0
3009
1
0.003
8.249
202.9
6.91
4.0
3009
2
0.003
8.249
202.9
6.91
4.0
3011
1
0.001
7.438
758.97
2.34
6.0
3018
1
0.001
9.137
178.41
10.66
8.0
3018
2
0.001
9.137
256.9
10.66
8.0
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