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Reliability Technology Issues and Needs Assessment

Publications with Abstracts

Reliable Integration of Variable Renewable Generation
2010
Main Report
Use of Frequency Response Metrics to Assess the Planning and Operating Requirements for Reliable Integration of Variable Renewable Generation
Eto, J.H., J. Undrill, P. Mackin, R. Daschmans, B. Williams, B. Haney, R. Hunt, J. Ellis, H. Illian, C. Martinez, M. O'Malley, K. Coughlin, K.H. LaCommare. LBNL-4142E. December 2010
1.6 MB PDF, 141 pp

An interconnected electric power system is a complex system that must be operated within a safe frequency range in order to reliably maintain the instantaneous balance between generation and load. This is accomplished by ensuring that adequate resources are available to respond to expected and unexpected imbalances and restoring frequency to its scheduled value in order to ensure uninterrupted electric service to customers. Electrical systems must be flexible enough to reliably operate under a variety of "change" scenarios. System planners and operators must understand how other parts of the system change in response to the initial change, and need tools to manage such changes to ensure reliable operation within the scheduled frequency range.

This report presents a systematic approach to identifying metrics that are useful for operating and planning a reliable system with increased amounts of variable renewable generation which builds on existing industry practices for frequency control after unexpected loss of a large amount of generation. The report introduces a set of metrics or tools for measuring the adequacy of frequency response within an interconnection. Based on the concept of the frequency nadir, these metrics take advantage of new information gathering and processing capabilities that system operators are developing for wide-area situational awareness. Primary frequency response is the leading metric that will be used by this report to assess the adequacy of primary frequency control reserves necessary to ensure reliable operation. It measures what is needed to arrest frequency decline (i.e., to establish a frequency nadir) at a frequency higher than the highest set point for under-frequency load shedding within an interconnection. These metrics can be used to guide the reliable operation of an interconnection under changing circumstances.

Supporting Technical Reports
Power and Frequency Control as it Relates to Wind-Powered Generation
Undrill, J.M. LBNL-4143E. December 2010
2.2 MB PDF, 94 pp

This report is a part of an investigation of the ability of the U.S. power system to accommodate large scale additions of wind generation. The objectives of this report are to describe principles by which large multi-area power systems are controlled and to anticipate how the introduction of large amounts of wind power production might require control protocols to be changed.

The operation of a power system is described in terms of primary and secondary control actions. Primary control is fast, autonomous, and provides the first-line corrective action in disturbances; secondary control takes place on a follow-up time scale and manages the deployment of resources to ensure reliable and economic operation.

This report anticipates that the present fundamental primary and secondary control protocols will be satisfactory as wind power provides an increasing fraction of the total production, provided that appropriate attention is paid to the timing of primary control response, to short term wind forecasting, and to management of reserves for control action.

Review of the Recent Frequency Performance of the Eastern, Western and ERCOT Interconnections
Martinez, C. S. Xue, and M. Martinez. LBNL-4144E. December 2010
4.0 MB PDF, 63 pp

The reliable operation of an electric power system depends on careful management of the balance between generation and load to ensure that system frequency is maintained within narrow bounds around a scheduled value. Yet, maintaining frequency at the scheduled value is challenging because the load served is continuously changing, and occasionally, events such as the sudden loss of a large generation plant or large amount of load, cause frequency to deviate abruptly. This report reviews the recent history of frequency performance for all three U.S. interconnections: Eastern, Western, and the Electric Reliability Council of Texas (ERCOT). The review is based on data collected by the North American Electric Reliability Corporation (NERC). The review focuses on frequency response, which measures the performance of the interconnections immediately following sudden, large imbalances between load and generation. Trends in frequency response are presented and preliminary efforts are made to relate frequency response to other aspects of frequency performance and to examine aspects of the methods used to calculate frequency response.

Frequency Control Performance Measurement and Requirements
Illian, H.F. LBNL-4145E. December 2010
249 KB PDF, 46 pp

Frequency control is an essential requirement of reliable electric power system operations. Determination of frequency control depends on frequency measurement and the practices based on these measurements that dictate acceptable frequency management. This report chronicles the evolution of these measurements and practices. As technology progresses from analog to digital for calculation, communication, and control, the technical basis for frequency control measurement and practices to determine acceptable performance continues to improve. Before the introduction of digital computing, practices were determined largely by prior experience. In anticipation of mandatory reliability rules, practices evolved from a focus primarily on commercial and equity issues to an increased focus on reliability. This evolution is expected to continue and place increased requirements for more precise measurements and a stronger scientific basis for future frequency management practices in support of reliability.

Dynamic Simulations Studies of the Frequency Response of the Three U.S. Interconnections with Increased Wind Generation
Mackin, P., R. Daschmans, B. Williams, B. Haney, R. Hunt, and J. Ellis. LBNL-4146E. December 2010
335 KB PDF, 42 pp

Utility Systems Efficiencies, Inc. was tasked by Lawrence Berkeley National Laboratory (LBNL) to conduct dynamic simulation studies of the three U.S. interconnections (Eastern, Western, and Texas). The simulations were prepared in support of LBNL's project for the Federal Energy Regulatory Commission to study frequency-response-related issues that must be addressed to operate the power system reliably with large amounts of variable renewable generation.

The objective of the simulation studies of each interconnection was to assess the effects of different amounts of wind generation on frequency behavior of each interconnection following a sudden loss of generation. The scenarios created to study these effects considered an operating circumstance in which system load is at or close to its minimum. The event studied was the sudden loss of the largest amount of generation recorded within each interconnection. The simulations calculated the impact of this event on interconnection frequency for three levels of wind generation. In addition to varying the amount of wind generation, the simulations varied the amount of operating reserves between a high level representative of current operating practices and a low level representative of the minimum required by present operating rules.

Analysis of Wind Power and Load Data at Multiple Time Scales
Coughlin, K.C. and J.H. Eto. LBNL-4147E. December 2010
236 KB PDF, 50 pp

In this study we develop and apply new methods of data analysis for high resolution wind power and system load time series, to improve our understanding of how to characterize highly variable wind power output and the correlations between wind power and load. These methods are applied to wind and load data from the ERCOT region, and wind power output from the PJM and NYISO areas. We use a wavelet transform to apply mathematically well-defined operations of smoothing and differencing to the time series data. This approach produces a set of time series of the changes in wind power and load (or "deltas"), over a range of times scales from a few seconds to approximately one hour. A number of statistical measures of these time series are calculated. We present sample distributions, and devise a method for fitting the empirical distribution shape in the tails. We also evaluate the degree of serial correlation, and linear correlation between wind and load. Our examination of the data shows clearly that the deltas do not follow a Gaussian shape; the distribution is exponential near the center and appears to follow a power law for larger fluctuations. Gaussian distributions are frequently used in modeling studies. These are likely to over-estimate the probability of small to moderate deviations. This in turn may lead to an over-estimation of the additional reserve requirement (hence the cost) for high penetration of wind. The Gaussian assumption provides no meaningful information about the real likelihood of large fluctuations. The possibility of a power law distribution is interesting because it suggests that the distribution shape for of wind power fluctuations may become independent of system size for large enough systems.

Electricity Reliability and Power Quality
2010
How to Estimate the Value of Service Reliability Improvements
Sullivan, M., M. Mercurio, J. Schellenberg and J. Eto. June 2010
347 KB PDF, 5 pp

A robust methodology for estimating the value of service reliability improvements is presented. Although econometric models for estimating value of service (interruption costs) have been established and widely accepted, analysts often resort to applying relatively crude interruption cost estimation techniques in assessing the economic impacts of transmission and distribution investments. This paper first shows how the use of these techniques can substantially impact the estimated value of service improvements. A simple yet robust methodology that does not rely heavily on simplifying assumptions is presented. When a smart grid investment is proposed, reliability improvement is one of the most frequently cited benefits. Using the best methodology for estimating the value of this benefit is imperative. By providing directions on how to implement this methodology, this paper sends a practical, usable message to the industry.

2009
Estimated Value of Service Reliability for Electric Utility Customers in the United States
Sullivan, M., M. Mercurio, J. Schellenberg, Freeman, Sullivan & Co. June 2009
534 KB PDF, 130 pp

Information on the value of reliable electricity service can be used to assess the economic efficiency of investments in generation, transmission and distribution systems, to strategically target investments to customer segments that receive the most benefit from system improvements, and to numerically quantify the risk associated with different operating, planning and investment strategies. This paper summarizes research designed to provide estimates of the value of service reliability for electricity customers in the US. These estimates were obtained by analyzing the results from 28 customer value of service reliability studies conducted by 10 major US electric utilities over the 16 year period from 1989 to 2005. Because these studies used nearly identical interruption cost estimation or willingness-to-pay/accept methods it was possible to integrate their results into a single meta-database describing the value of electric service reliability observed in all of them. Once the datasets from the various studies were combined, a two-part regression model was used to estimate customer damage functions that can be generally applied to calculate customer interruption costs per event by season, time of day, day of week, and geographical regions within the US for industrial, commercial, and residential customers. Estimated interruption costs for different types of customers and of different duration are provided. Finally, additional research and development designed to expand the usefulness of this powerful database and analysis are suggested.

2008
Tracking the Reliability of the U.S. Electric Power System: An Assessment of Publicly Available Information Reported to State Public Utility Commissions
Eto, J. and K. Hamachi LaCommare. October 2008
244 KB PDF, 52 pp

Large blackouts, such as the August 14-15, 2003 blackout in the northeastern United States and Canada, focus attention on the importance of reliable electric service. As public and private efforts are undertaken to improve reliability and prevent power interruptions, it is appropriate to assess their effectiveness. Measures of reliability, such as the frequency and duration of power interruptions, have been reported by electric utilities to state public utility commissions for many years. This study examines current state and utility practices for collecting and reporting electricity reliability information and discusses challenges that arise in assessing reliability because of differences among these practices. The study is based primarily on reliability information for 2006 reported by 123 utilities to 37 state public utility commissions.

2004
Understanding the Cost of Power Interruptions to U.S. Electricity Consumers
Hamachi LaCommare, K., and J. Eto. September 2004
375 KB PDF, 70 pp

The massive electric power blackout in the northeastern United States and Canada on August 14-15, 2003 resulted in the U.S. electricity system being called "antiquated" and catalyzed discussions about modernizing the grid. Industry sources suggested that investments of $50 to $100 billion would be needed. This report seeks to quantify an important piece of information that has been missing from these discussions: how much do power interruptions and fluctuations in power quality (power-quality events) cost U.S. electricity consumers? Accurately estimating this cost will help assess the potential benefits of investments in improving the reliability of the grid.

Pilot Evaluation of Electricity-Reliability and Power-Quality Monitoring in California's Silicon Valley with the I-Grid® System
Eto, J., Lawrence Berkeley National Laboratory; D. Divan and W. Brumsickle, SoftSwitching Technologies. February 2004
599 KB PDF, 49 pp

Power-quality events are of increasing concern for the economy because today's equipment, particularly computers and automated manufacturing devices, is susceptible to these imperceptible voltage changes. A small variation in voltage can cause this equipment to shut down for long periods, resulting in significant business losses. Tiny variations in power quality are difficult to detect except with expensive monitoring equipment used by trained technicians, so many electricity customers are unaware of the role of power-quality events in equipment malfunctioning.

This report describes the findings from a pilot study coordinated through the Silicon Valley Manufacturers Group in California to explore the capabilities of I-Grid®, a new power-quality monitoring system. This system is designed to improve the accessibility of power-quality information and to increase understanding of the growing importance of electricity reliability and power quality to the economy.

The study used data collected by I-Grid sensors at seven Silicon Valley firms to investigate the impacts of power quality on individual study participants as well as to explore the capabilities of the I-Grid system to detect events on the larger electricity grid by means of correlation of data from the sensors at the different sites. In addition, study participants were interviewed about the value they place on power quality, and their efforts to address electricity-reliability and power quality problems. Issues were identified that should be taken into consideration in developing a larger, potentially nationwide, network of power-quality sensors.

2003
A Framework and Review of Customer Outage Costs: Integration and Analysis of Electric Utility Outage Cost Surveys
Lawton, L., M. Sullivan, K. Van Liere, A. Katz, PRS; and J. Eto, Lawrence Berkeley National Laboratory. November 2003
608 KB PDF, 86 pp

A clear understanding of the monetary value that customers place on reliability and the factors that give rise to higher and lower values is an essential tool in determining investment in the grid. The recent National Transmission Grid Study recognizes the need for this information as one of growing importance for both public and private decision makers. In response, the U.S. Department of Energy has undertaken this study, as a first step toward addressing the current absence of consistent data needed to support better estimates of the economic value of electricity reliability. Twenty-four studies, conducted by eight electric utilities between 1989 and 2002 representing residential and commercial/industrial (small, medium and large) customer groups, were chosen for analysis. The studies cover virtually all of the Southeast, most of the western United States, including California, rural Washington and Oregon, and the Midwest south and east of Chicago. All variables were standardized to a consistent metric and dollar amounts were adjusted to the 2002 CPI. The data were then incorporated into a meta-database in which each outage scenario (e.g., the loss of electric service for one hour on a weekday summer afternoon) is treated as an independent case or record both to permit comparisons between outage characteristics and to increase the statistical power of analysis results.

Unadjusted average outage costs and Tobit models that estimate customer damage functions are presented. The customer damage functions express customer outage costs for a given outage scenario and customer class as a function of location, time of day, consumption, and business type. One can use the damage functions to calculate outage costs for specific customer types. For example, using the customer damage functions, the cost experienced by an "average" customer resulting from a 1 hour summer afternoon outage is estimated to be approximately $3 for a residential customer, $1,200 for small-medium commercial and industrial customer, and $82,000 for large commercial and industrial customer. Future work to improve the quality and coverage of information on the value of electricity reliability to customers is described.

A New Approach to Power Quality and Electricity Reliability Monitoring - Case Study Illustrations of the Capabilities of the I-Grid® System
Divan, D., and W. Brumsickle, SoftSwitching Technologies Corp.; and J. Eto, Lawrence Berkeley National Laboratory. April 2003
821 KB PDF, 32 pp

This report describes a new approach for collecting information on power quality and reliability and making it available in the public domain. Making this information readily available in a form that is meaningful to electricity consumers is necessary for enabling more informed private and public decisions regarding electricity reliability. The system dramatically reduces the cost (and expertise) needed for customers to obtain information on the most significant power quality events, called voltage sags and interruptions. The system also offers widespread access to information on power quality collected from multiple sites and the potential for capturing information on the impacts of power quality problems, together enabling a wide variety of analysis and benchmarking to improve system reliability. Six case studies demonstrate selected functionality and capabilities of the system, including:

  • Linking measured power quality events to process interruption and downtime;
  • Demonstrating the ability to correlate events recorded by multiple monitors to narrow and confirm the causes of power quality events; and
  • Benchmarking power quality and reliability on a firm and regional basis.
2001
A Scoping Study on Trends in the Economic Value of Electricity Reliability to the U.S. Economy
Eto, J., J. Koomey, B. Lehman, N. Martin, E. Mills, C. Webber, and E. Worrell. June 2001
581 KB PDF, 148 pp

During the past three years, working with more than 150 organizations representing public and private stakeholders, EPRI has developed the Electricity Technology Roadmap. The Roadmap identifies several major strategic challenges that must be successfully addressed to ensure a sustainable future in which electricity continues to play an important role in economic growth. Articulation of these anticipated trends and challenges requires a detailed understanding of the role and importance of reliable electricity in different sectors of the economy. This report is intended to contribute to that understanding by analyzing key aspects of trends in the economic value of electricity reliability in the U.S. economy.

We first present a review of recent literature on electricity reliability costs. Next, we describe three distinct end-use approaches for tracking trends in reliability needs: 1) an analysis of the electricity-use requirements of office equipment in different commercial sectors; 2) an examination of the use of aggregate statistical indicators of industrial electricity use and economic activity to identify high reliability-requirement customer market segments; and 3) a case study of cleanrooms, which is a cross-cutting market segment known to have high reliability requirements. Finally, we present insurance industry perspectives on electricity reliability as an example of a financial tool for addressing customers reliability needs.

Transmission Planning and Policy
2009
Transmission Benefit Quantification, Cost Allocation and Cost Recovery
Budhraja, V., J. Ballance, J. Dyer, and F. Mobasheri, Electric Power Group, LLC. 2009
1.9 MB PDF, 216 pp

This project was commissioned to perform a scoping study to understand transmission benefit quantification, cost allocation, cost recovery, and project approval processes with a particular focus on recommending new methods for improved benefit quantification and cost allocation that better fits the new electric industry structure and planning environment. Research goals and objectives included:

  1. Review methodologies currently being used for transmission project quantification.
  2. Review and summarize benefit analysis that have been carried out for some recent transmission projects in California.
  3. Present and summarize research results to improve benefit quantification methods for new transmission projects.
  4. Outline approaches to apply improved benefit quantification method to: evaluate project cost effectiveness, allocate project costs among participants, and develop framework for cost recovery.

Key conclusions and research recommendations are:

  • Use a social rate of discount to calculate the present worth of benefits of a new major regional transmission projects rather than utility cost of capital to recognize the public good and long life attributes of transmission.
  • Calculate explicitly the fuel diversity benefit from integration of large renewable resources.
  • Utilize a stakeholder consensus approach, such as Delphi method, to assign value to some of the strategic benefits such as risk mitigation against extreme reliability and market volatility events.
  • Initiate research into (a) dynamic analysis to evaluate the impact on generation expansion in exporting regions (b) resource portfolios analysis to assess performance of different combination of demand response, renewables and fuel based generation, transmission and energy conservation programs, and (c) quantification of extreme event benefits (Insurance Value) in terms of reliability and reduced market volatility to estimate the benefits from the low probability/high impact events.
2008
Renewable Resource Integration Project — Scoping Study of Strategic Transmission Operations, and Reliability Issues
Budhraja, V., J. Ballance, J. Dyer, F. Mobasheri, Electric Power Group; and J. Eto, Lawrence Berkeley National Laboratory. December 2008
1.1 MB PDF, 49 pp

California is on a path to increase usage of renewable resources. The renewable capacity additions that will be needed are 20,000 megawatts (MW) to achieve 33 percent renewables by 2030 and 40,000 MW to achieve 50 percent renewables by 2030. For this scoping study, a mid-range estimate of 30,000 MW is assumed to be needed over the next 20 years.

Renewable resources are typically located in remote locations, not near the load centers. Nearly two-thirds or 20,000 MW of new renewable resources needed are likely to be delivered to Los Angeles Basin transmission gateways. Integration of renewable resources requires interconnection to the power grid, expansion of the transmission system capability between the backbone power grid and transmission gateways, and increase in delivery capacity from transmission gateways to the local load centers.

To scope the transmission, operations, and reliability issues for renewables integration, this research focused on the Los Angeles Basin Area transmission gateways where most of new renewables are likely. Necessary actions for successful renewables integration include:

  • Expand Los Angeles Basin Area transmission gateway and nomogram (a graph depicting three curves representing different variables so that a line intersecting all three curves intersects the related values of each variable) limits by 10,000 to 20,000 MW.
  • Upgrade local transmission network for deliverability to load centers.
  • Secure additional storage, demand management, automatic load control, dynamic pricing, and other resources that meet regulation and ramping needed in real-time operations.
  • Enhance local voltage support.
  • Expand deliverability from Los Angeles to San Diego and Northern California.
2005
A Review of Recent RTO Benefit-Cost Studies: Toward More Comprehensive Restructuring Policies
Eto, J., B. Lesieutre, and D. Hale. LBNL-58027. December 2005
196 KB PDF, 61 pp

During the past three years, government and private organizations have issued more than a dozen studies of the benefits and costs of Regional Transmission Organizations (RTOs). Most of these studies have focused on benefits that can be readily estimated using traditional production-cost simulation techniques, which compare the cost of centralized dispatch under an RTO to dispatch in the absence of an RTO, and on costs associated with RTO start-up and operation. Taken as a whole, it is difficult to draw definitive conclusions from these studies because they have not examined potentially much larger benefits (and costs) resulting from the impacts of RTOs on reliability management, generation and transmission investment and operation, and wholesale electricity market operation.

This report: 1) Describes the history of benefit-cost analysis of FERC electricity restructuring policies; 2) Reviews current practice by analyzing 11 RTO benefit-cost studies that were published between 2002 and 2004 and makes recommendations to improve the documentation of data and methods and the presentation of findings in future studies that focus primarily on estimating short-run economic impacts; and 3) Reviews important impacts of FERC policies that have been overlooked or incompletely treated by recent RTO benefit-cost studies and the challenges to crafting more comprehensive assessments of these impacts based on actual performance, including impacts on reliability management, generation and transmission investment and operation, and wholesale electricity market operation.

Improving Dynamic Load and Generator Response Performance Tools
Lesieutre, B. LBNL-59192. November 2005
485 KB PDF, 74 pp

This report is a scoping study to examine research opportunities to improve the accuracy of the system dynamic load and generator models, data and performance assessment tools used by CAISO operations engineers and planning engineers, as well as those used by their counterparts at the California utilities, to establish safe operating margins. Model-based simulations are commonly used to assess the impact of credible contingencies in order to determine system operating limits (path ratings, etc.) to ensure compliance with NERC and WECC reliability requirements. Improved models and a better understanding of the impact of uncertainties in these models will increase the reliability of grid operations by allowing operators to more accurately study system voltage problems and the dynamic stability response of the system to disturbances.

2004
The Potential Impacts of a Competitive Wholesale Market in the Midwest: A Preliminary Examination of Centralized Dispatch
Lesieutre, B., E. Bartholomew, and J. Eto. LBNL-56503. October 2004
574 KB PDF, 75 pp

In March 2005, the Midwest Independent System Operator (MISO) will begin operating the first ever, formal wholesale market for electricity in the central and upper Midwestern portion of the United States. Region-wide, centralized, security-constrained, bid-based dispatch will replace the current system of decentralized dispatch by individual utilities and control areas.

This report focuses on how the operation of generators may change under centralized dispatch. We analyze a stylized example of these changes by comparing a base case dispatch based on a "snapshot" taken from MISO's state estimator for an actual, historical dispatch (4 p.m., July 7, 2003) to a hypothetical, centralized dispatch that seeks to minimize the total system cost of production, using estimated cost data collected by the EIA. Based on these changes in dispatch, we calculate locational marginal prices, which in turn reveals the location of congestion within MISO's footprint, as well as the distribution of congestion revenues. We also consider two sensitivity scenarios that examine 1) the effect of changes in MISO membership (2003 vs. 2004 membership lists), and 2) different load and electrical data, based on a snapshot from a different date and time (1 p.m., Feb. 18, 2004).

Although our analysis offers important insights into how the MISO market could operate when it opens, we do not address the question of the total benefits or costs of creating a wholesale market in the Midwest.

Transmission-Planning Research and Development Scoping Project
Eto, J., B. Lesieutre and S. Widergren. July 2004
630 KB PDF, 82 pp

The objective of this Public Interest Energy Research (PIER) scoping project is to identify options for public-interest research and development (R&D) to improve transmission-planning tools, techniques, and methods. The information presented was gathered through a review of current California utility, California Independent System Operator (ISO), and related western states electricity transmission-planning activities and emerging needs. This report presents the project team's findings organized under six topic areas and identifies 17 distinct R&D activities to improve transmission-planning in California and the West. The findings in this report are intended for use, along with other materials, by PIER staff, to facilitate discussions with stakeholders that will ultimately lead to development of a portfolio of transmission-planning R&D activities for the PIER program.

Economic Evaluation of Transmission Interconnection in a Restructured Market
Mobasheri, F., M. Cheng, and J. Medina. June 2004
91 KB PDF, 48 pp

California's high voltage interconnections to neighboring states have played a vital role in meeting the state's electricity needs reliably and at great savings to the customers. However, due to changing industry structure and financial uncertainties, construction of transmission capacity has not kept up with the increase in load or with the addition of generation capacity. There is a need for the development of an evaluation methodology that will include strategic benefits from transmission lines.

This report addresses the need to capture the long-term benefits of transmission lines, including a perspective that transmission lines are a "public good" and therefore, should be evaluated using a social discount rate. This report provides recommendations to adapt and modify the CA ISO proposed evaluation methodology to capture the long-term benefits that transmission projects may provide.

2003
California's Electricity Generation and Transmission Interconnection Needs Under Alternative Scenarios: Assessment of Resources, Demand, Need For Transmission Interconnections, Policy Issues and Recommendations For Long Term Transmission Planning
Budhraja, V., F. Mobasheri, M. Cheng, J. Dyer, E. Castaño, and S. Hess. November 2003
306 KB PDF, 42 pp

This report is designed to help policymakers focus on the long term and take steps now to plan for a robust and secure electricity infrastructure. Ultimately, a balanced and diversified resource strategy would utilize conservation, load management, renewables, distributed generation, and new interconnections and power plants. California also needs to plan for its future electricity needs by addressing other issues, e.g., fuel mix, energy efficiency, siting, transmission, and gas transportation. This report does not advocate any particular fuel source. It attempts to paint the situation in 2030 and concludes that new interconnections to resource-rich regions and new market hubs will be a part of California's future, and therefore California needs to take steps now to meet its future electricity needs.

Planning for California's Future Transmission Grid: Review of Transmission System, Strategic Benefits, Planning Issues and Policy Recommendations
Budhraja, V., J. Dyer, and S. Hess. October 2003
438 KB PDF, 30 pp

California's investments in its transmission grid and interconnections to neighboring states have produced substantial reliability, economic, environmental, and fuel diversity benefits. Since the late 1960s, the investments in interconnections have totaled approximately $4.1 billion. These investments have produced substantial benefits.

The California Independent System Operator's (CAISO) authorized Transmission Access Charge (TAC) for 2003 is approximately $390 million and equates to a cost of approximately 0.2/kWh or $2/MWh. If the State of California took a proactive role and invested $3 billion in strategic transmission interconnections over the next two decades, the rate impact would be equivalent to the current CAISO transmission access charge and represent approximately a 0.2/kWh or $2/MWh increase, or less than 2% increase in residential rates. The issue for policy makers is whether or not the benefits associated with strategic transmission assets justify the minor rate impact over time. The benefits associated with California's strategic transmission assets.

California needs to resume its leadership in the Western Interconnection to develop strategic interconnections, invest in technologies to improve utilization of existing transmission infrastructure, and develop new approaches to planning and valuing transmission investments. This report provides a summary of the specific recommendations for California transmission.

Electricity Transmission Congestion Costs: A Review of Recent Reports
Lesieutre, B., and J. Eto. October 2003
233 KB PDF, 53 pp

This report reviews reports of congestion costs and begins to assess their implications for the current national discussion on the importance of the U.S. electricity transmission system for enabling competitive wholesale electricity markets. We draw the following conclusions: 1) Information about the operation of congestion revenue rights markets is needed to assess the impacts of congestion revenue charges on consumers; 2) Information on generators' offers is needed to assess system redispatch payments; 3) Many studies presume that generator offers reflect competitive market conditions; 4) Customer costs may rise as a result of reducing congestion; 5) Minimizing consumer costs may not increase aggregate social wealth; and 6) There is no standardized conceptual framework for studies of congestion costs.

A Survey of National Transmission Grid Modeling Capabilities at DOE Laboratories
Thomas, S., P. Boggs and V. Howle, Sandia National Laboratories. July 2003
298 KB PDF, 53 pp

This report catalogs the results of a brief survey, conducted in early 2003, designed to answer the question "What DOE Laboratories electric power grid modeling and analysis software tools are available today that might be of value in carrying out a next-generation National Transmission Grid Study?" Software tool capabilities are described as answers by respondents to a standardized questionnaire, and are summarized by a datasheet for each tool. This survey does not address the significantly broader universe of tools and capabilities actively under research and development within the Laboratories, but not ready for use.

Analysis and Selection of Analytical Tools to Assess National-Interest Transmission Bottlenecks Final Report
KEMA Consulting: KEMA-ECC & Macro Corporation. March 2003
1.4 MB PDF, 122 pp

KEMA Consulting has assessed existing commercial tools in the U.S. market that might be used to help support future DOE assessments of national interest transmission bottlenecks, consistent with recommendations in the DOE National Transmission Grid Study. The tool or tools must be capable of supporting studies of power systems transmission, energy, and ancillary services and markets as well as trading behavior.

U.S. Department of Energy Transmission Bottleneck Project Report
Dyer, J., Electric Power Group. March 2003
1.8 MB PDF, 100 pp

This report describes the study findings, which are based on interviews and discussions with the nation's six established ISO/RTOs - the California ISO, the New York ISO, the Midwest ISO, ISO New England, the Electric Reliability Council of Texas, and the PJM Interconnection. In addition, this report summarizes information on bottlenecks gathered from other sources, including the Federal Energy Regulatory Commission, the Western Governors' Association, the North American Electric Reliability Council, and the Edison Electric Institute.

Computational Needs for the Next Generation Electric Grid
2011
Computational Needs for the Next Generation Electric Grid. April 2011 9.3 MB PDF, 375 pp

Background

The US electric power system has undergone substantial change since the late 1980's and promises to continue to change into the foreseeable future. The changes began in 1989 with the restructuring of the way industry procured electric supply. The restructuring sought to replace centralized decision–making by the traditional vertically integrated utility with decentralized decision–making by market participants that establish prices through market forces, not regulation. Today, that transformation is still in progress. Vertically integrated firms continue to serve customers in regions of the country. A sustainable means for ensuring adequate transmission has not been demonstrated. And the demand side of the equation is not able to compete fully in an open market environment.

In the midst of this restructuring, advances in electric transportation, a greater awareness of the environmental effects of electricity production, and a desire on the part of the US to eliminate its dependence on foreign oil has prompted a movement to again re–invent the electric system. The new objectives include better accommodation of planning and operational uncertainty, especially that associated with variable renewable generation sources such as wind and solar, accommodation of major reductions in CO2 and other pollutants harmful to air quality, and economic and reliable operation of existing assets with less margin than in the past. It is now agreed that the "smart grid" that will be needed to achieve these objectives will involve the confluence of new sensing, communication, control, and computing as a unique blend of technologies that must be designed specifically to manage the requirements for a future electric power system based on competitive markets. Fundamental to this agreement is the idea that significant advances are needed in the areas of large-scale computation, modeling, and data handling.

Approach

To begin to address the large–scale computation, modeling, and data handling challenges of the future grid, seven survey papers were commissioned in 2010 from eminently qualified authorities conducting research activities in problem areas of interest. Each paper was to define a problem area, concisely review industry practice in this area up to the present time, and provide an objective, critical, and comparative assessment of research needed during the next 5 to 10 years. Authors were asked to identify seminal papers or reports that had motivated later, generic, related work.

Electric power system computational needs appropriate for discussion in the survey papers were to include:

  1. New algorithms that are scalable and robust for solving large nonlinear mixedinteger optimization problems and methods for efficiently solving (in real–time) large sets of ordinary differential equations with algebraic constraints, including delays, parameter uncertainties, and monitored data as inputs. These new algorithms should accommodate randomness for capturing appropriate notions of security and incorporate recent results on improving deterministic and randomized algorithms for computationally hard problems.
  2. A new mathematics for characterizing uncertainty in information created from large volumes of data as well as for characterizing uncertainty in models used for prediction.
  3. New methods to enable efficient use of high–bandwidth networks by dynamically identifying only the data relevant to the current information need and discarding the rest. This would be especially useful for wide-area dynamic control where data volume and latency are barriers.
  4. New software architectures and new rapid development tools for merging legacy and new code without disrupting operation. Software should be open source, modular, and transparent. Security is a high priority.

We assume that designing and building larger and faster computers and faster communications will not be sufficient to solve the electric grid computational problems, although these improvements might ultimately be helpful. Instead, our expectation is that fundamental advances are needed in the areas of algorithms, computer networking and architecture, databases and data overwhelm, simulation and modeling, and computational security; perhaps most importantly, these advances must be achievable in a time frame that will be useful to the industry.

On April 19 – 20, 2011, a two–day workshop was held on the campus of Cornell University to explore critical computational needs for future electric power systems. Workshop participants provided input based on the presentation of the seven papers. The seven papers were not expected to be exhaustive, but acted as a framework within which to explore a rich range of topics associated with the overall issue. The collection of materials in this volume is intended to provide as complete a record as possible of the workshop proceedings. The volume contains the final versions of the seven papers that were presented, along with discussions of the papers' focus that were prepared ahead of time to stimulate discussion at the workshop, and the reports of the discussions that took place among workshop participants. The authors of the seven papers reviewed and approved the reports of the workshop discussions, which include the reporters' interpretations.

Summary of the Papers

In developing the workshop our focus has been on a class of problems that have been neglected but will have to be solved if we are to move in a timely way to a new smart architecture capable of accommodating our vision for the grid of the future. We summarize below the contributions each of the seven papers makes to the discussion of this class of problems.

The first paper by Kenneth P. Birman, Lakshmi Ganesh, and Robbert van Renesse explores the relatively new paradigm of cloud computing in relation to future electric power system needs. The authors note that future needs will demand scalability of a kind that only cloud computing can offer. Their thesis is that there will be power system requirements (real-time, consistency, privacy, security, etc.) that cloud computing cannot currently support and that many of these needs, which are specific to the expected future electric power paradigm, will not soon be filled by the cloud industry.

The second paper by Michael Ferris is about modeling. This paper argues that decision processes are predominantly hierarchical and that, as a result, models to support such decision processes should also be layered or hierarchical. Ferris contends that, although advice can be provided from the perspective of mathematical optimization on managing complex systems, that advice must be integrated into an interactive debate with informed decision makers. He also agrees that treating uncertainties in large scale planning projects will become even more critical as the smart grid evolves because of the increase in volatility of both supply and demand. Optimization models with flexible systems design can help address these uncertainties not only during the planning and construction phases, but also during the operational phase of an installed system.

The third paper by Andreas G. Hofmann and Brian C. Williams focuses on the twin problems of: 1) increasing the level of automation in the analysis and planning for contingencies in response to unexpected events, and 2) the problem of incorporating considerations of optimality into contingency planning and the overall energy management process. With regard to the first problem, the authors note that, although the level of anticipated automation is still advisory and humans remain in the loop, use of automation would reduce the drudgery and error prone nature of the current laborintensive approach. Automation would also guarantee the completeness of an analysis and validity of the contingency plans. With regard to the second problem, the optimization would include establishing risk bounds on actions taken to achieve optimal performance.

The fourth paper by Janos Sztipanovits, Graham Hemingway, Anjan Bose, and Anurag Srivastava is also about modeling. The thesis is that the future electric system will require "the efficient integration of digital information, communication systems, real time-data delivery, embedded software and real-time control decision-making." The authors posit that no high-fidelity models are capable of simulating electric grid interactions with communication and control infrastructure elements for large systems.

They also conclude that it is a challenge to model infrastructure interdependencies related to the power grid, including the networks and software for sensors, controls, and communication. The fifth paper by Santiago Grijalva argues that future electric system problems are multi-scale and that there is a need to develop multi-scale simulation models and methods to the level that exists in other engineering disciplines. The paper discusses 18 areas of multi-scale, multi-dimensional power system research that are needed to provide a framework for addressing emerging power system problems.

The sixth paper by Sarah M. Ryan, James D. McCalley, and David L. Woodruff describes computational tools that are needed in the area of optimization for large-scale planning models that account for uncertainty. The authors present, as an example, a proposed model for electric system planning that includes linkages with transportation systems. The paper addresses multi-objective planning in the presence of uncertainty where decision makers must balance, for example, sustainability, costs (investment and operational), long-term system resiliency, and solution robustness.

The seventh and final paper, by Jinjun Xiong and his associates, explores computational challenges in the context of security-constrained unit commitment and economic dispatch with stochastic analysis, management of massive data sets, and concepts related to large-scale grid simulation. Although other papers address simulation and optimization, this paper is unique in its exploration of emerging substantive data management issues.

Conclusions

The April 2011 workshop touched on important research and development needs for the future electric power system, but was not exhaustive. We hope that it has created the basis for the formation of a community of researchers who will focus on these very substantial and interesting needs. We wish to thank the authors of the papers for their outstanding contributions and for providing important food for thought. In addition to the authors of the papers, we wish to acknowledge the contributions of the Paper Discussants: James Nutaro, Ali Pinar, Bernard Lesieutre, Henry Huang, Roman Samulyak, Jason Stamp, and Loren Toole; and the Session Recorders: Ghaleb Abdulla, Alejandro Dominguez-Garcia, Hyung-Seon Oh, Victor Zavala, Sven Leyffer Chao Yang, and Jeff Dagle. Finally, we are grateful for the active contributions of the industry participants and invited guests. Everyone's participation led to a very successful enterprise.

Grid of the Future
2003
California's Electricity System of the Future Scenario Analysis in Support of Public-Interest Transmission System R&D Planning
Eto, J., Lawrence Berkeley National Laboratory; J.P. Stovall, Oak Ridge National Laboratory; V. Budhraja and J. Dyer, Electric Power Group; C. Goldman and C. Marnay, Lawrence Berkeley National Laboratory; G. Gross, Power Systems Engineering Research Center, University of Illinois; and S. Oren, Power Systems Engineering Research Center, University of California. April 2003
224 KB PDF, 61 pp

The California Energy Commission directed the Consortium for Electric Reliability Technology Solutions to analyze possible future scenarios for the California electricity system and assess transmission research and development (R&D) needs, with special emphasis on prioritizing public-interest R&D needs, using criteria developed by the Energy Commission. The scenarios analyzed in this report are not predictions, nor do they express policy preferences of the project participants or the Energy Commission. The public-interest R&D needs that are identified as a result of the analysis are one input that will be considered by the Energy Commission's Public Interest Energy Research staff in preparing a transmission R&D plan.

1999
Executive Summary for the Grid of the Future Project
Eto, J., Lawrence Berkeley National Laboratory. December 1999
45 KB PDF, 20 pp

In 1999, the Department of Energy (DOE) Transmission Reliability Program commissioned the preparation of six White Papers to establish the foundation for a multi-year program of federally funded research, development, and demonstration (RD&D) projects to maintain and enhance the reliability of the U.S. electric power system as the electricity industry undergoes restructuring.

  • "The Federal Role in Electric System Reliability RD&D During a Time of Industry Transition: An Application of Scenario Analysis," by J. Eto
  • "Review of Recent Reliability Issues and System Events," by J. Hauer and J. Dagle
  • "Review of the Structure of Bulk Power Markets," by B. Kirby and J. Kueck
  • "Accommodating Uncertainty in Planning and Operations," by M. Ivey, A. Akhil, D. Robinson, K. Stamber, J. Stamp, and K. Chu
  • "Real Time Security Monitoring and Control of Power Systems," by G. Gross, A. Bose, C. Demarco, M. Pai, J. Thorp, and P. Varaiya
  • "Interconnection and Controls for Reliable, Large Scale Integration of Distributed Energy Resources" by V. Budhraja, C. Martinez, J. Dyer, and M. Kondragunta

This document is a compilation and synthesis of the executive summaries from each of the white papers. It has been prepared as summary of the key findings from the project and is intended to complement the individual white papers.

The Federal Role in Electric System Reliability RD&D During a Time of Industry Transition: An Application of Scenario Analysis
Eto, J., Lawrence Berkeley National Laboratory. December 1999
92 KB PDF, 55 pp

This white paper is one of six commissioned by the Department of Energy (DOE) Transmission Reliability Program to establish a foundation for a multi-year program of federally funded research, development, and demonstration (RD&D) projects to maintain and enhance the reliability of the U.S. electric power system as the electricity industry undergoes restructuring. In this white paper, we develop scenarios that represent four possible states of the industry during the next three to 10 years. We outline the RD&D they require and describe appropriate federal roles in making these investments.

We conclude that the federal government has special responsibilities for ensuring adequate investments in electric system reliability RD&D during industry restructuring. Once a stable industry structure with vibrant private-sector RD&D is established, the federal government should assume its historic role of supporting very long-range RD&D activities to complement the private-sector's RD&D investments. During a time of industry transition, however, the private sector faces significant uncertainties that dramatically reduce and narrow the scope of its willingness to invest in RD&D. Thus, without federal support, significant RD&D gaps are likely to emerge. Equally importantly, unbiased federal RD&D is needed to help inform decision makers whose actions will have lasting consequences for the future reliability of the electricity industry. Federal RD&D should be market enabling, not market determining. In view of the importance of electricity grid reliability to national welfare, these factors now call for an increased federal role in electric system reliability RD&D.

Review of Recent Reliability Issues and System Events
Hauer, J., and J. Dagle, Pacific Northwest National Laboratory. December 1999
253 KB PDF, 65 pp

This white paper is one of six commissioned by the Department of Energy (DOE) Transmission Reliability Program to establish a foundation for a multi-year program of federally funded research, development, and demonstration (RD&D) projects to maintain and enhance the reliability of the U.S. electric power system as the electricity industry undergoes restructuring. In this white paper, we review, analyze, and evaluate critical reliability issues as demonstrated by recent disturbance events in the North America power system. Eleven major disturbances are examined. Most of them occurred in this decade. Two earlier ones—in 1965 and 1977—are included as early indictors of technical problems that persist to the present day. The system events are assessed for both their technological and their institutional implications. Policy issues are noted in passing, in so much as policy and policy changes define the most important forces that shape power system reliability on this continent.

The strategic challenge is that the pattern of technical need has persisted for so long. Anticipation of market deregulation has, for more than a decade, been a major disincentive to new investments in system capacity. It has also inspired reduced maintenance of existing assets. A massive infusion of better technology is emerging as the final option for continued reliability of electrical services. If that technology investment will not be made in a timely manner, then that fact should be recognized and North America should plan its adjustments to a very different level of electrical service.

It is also apparent that technical operations staff among the utilities can be very effective at marshaling their forces in the immediate aftermath of a system emergency, and that serious disturbances often lead to improved mechanisms for coordinated operation. It is not at all apparent that such efforts can be sustained through voluntary reliability organizations in which utility personnel external to those organizations do most of the technical work.

Review of the Structure of Bulk Power Markets
Kirby, B., and J. Kueck, Oak Ridge National Laboratory. December 1999
212 KB PDF, 62 pp

This white paper is one of six commissioned by the Department of Energy (DOE) Transmission Reliability Program to establish a foundation for a multi-year program of federally funded research, development, and demonstration (RD&D) projects to maintain and enhance the reliability of the U.S. electric power system as the electricity industry undergoes restructuring. In this white paper, we review six restructured market systems: California; Pennsylvania, New Jersey, Maryland (PJM); New England; United Kingdom; Alberta; and Australia.

Restructuring is not changing the physical needs of the power system. However, the functions previously performed by the vertically integrated utility must be accommodated by the new market structure. A basic feature of the restructured industry is that the system operator must be isolated from commercial market pressures. At a minimum, a "code of conduct" is required that prevents the system operator from providing preferential treatment for generation or transactions that are owned or sponsored by the system operators company. At a maximum, the system operator can be an independent, non-profit, commercial organization, an Independent System Operator (ISO).

Real Time Security Monitoring and Control of Power Systems
Gross, G., A. Bose, C. Demarco, M. Pai, J. Thorp, and P. Varaiya, Power Systems Engineering Research Center. December 1999
99 KB PDF, 48 pp

This white paper is one of six commissioned by the Department of Energy (DOE) Transmission Reliability Program to establish a foundation for a multi-year program of federally funded research, development, and demonstration (RD&D) projects to maintain and enhance the reliability of the U.S. electric power system as the electricity industry undergoes restructuring. In this white paper, we outline the scope of issues, challenges and opportunities in the area of real-time security monitoring and control (RTSMC) of power systems in the restructured electricity industry. The counterpart of power system reliability in real-time operations is security—the ability of the power system to withstand contingencies.

The White Paper starts out with an introductory section to explain the framework for RTSMC. The following sections are devoted to (1) the multitude of challenges and opportunities in RTSMC under the unbundled regime; (2) a reexamination of control laws in light of the changing environment and to take advantage of the opportunities from incorporating new technology advances; and (3) possible strategies in the area of analytical and software tools to deal with the many aspects of RTSMC in the restructured environment.

Interconnection and Controls for Large Scale Integration of Distributed Energy Resources
Budhraja, V., C. Martinez, J. Dyer, and M. Kondragunta, Edison Technology Solutions. December 1999
104 KB PDF, 40 pp

This white paper is one of six commissioned by the Department of Energy (DOE) Transmission Reliability Program to establish a foundation for a multi-year program of federally funded research, development, and demonstration (RD&D) projects to maintain and enhance the reliability of the U.S. electric power system as the electricity industry undergoes restructuring. In this white paper, we define the five most likely scenarios through which distributed energy resources (DER) will gain market acceptance, identify current barriers to development of these markets, and identify the areas of research needed to overcome these barriers.

The White Paper identifies the following areas of research as high priorities to facilitate greater market adoption of DER:

  1. Inexpensive, standardized power electronics converters and controls;
  2. Islanded (i.e., isolated from the grid) and integrated protection and control schemes;
  3. Islanded and integrated real-time MW and voltage regulation for DERs;
  4. Islanded and integrated real-time dispatch and control;
  5. High-quality power for both islanded and integrated operations;
  6. Wide area real-time data communication protocols and infrastructures;
  7. Integration of demand-side resources in electricity markets;
  8. Independent identification of DER operational requirements; and
  9. Field testing of all the above technologies and processes.
Accommodating Uncertainty in Planning and Operations
Ivey, M., A. Akhil, D. Robinson, J. Stamp, and K. Stamber, Sandia National Laboratories; and K. Chu, Pacific Northwest National Laboratory. December 1999
129 KB PDF, 46 pp

This white paper is one of six commissioned by the Department of Energy (DOE) Transmission Reliability Program to establish a foundation for a multi-year program of federally funded research, development, and demonstration (RD&D) projects to maintain and enhance the reliability of the U.S. electric power system as the electricity industry undergoes restructuring. In this white paper, we discuss uncertainties that are not captured in current planning process used by utilities in a regulated environment as well as emerging uncertainties that result uniquely from the restructuring of the electric industry. In latter sections, we identify technologies/methodologies that can be developed and employed to accommodate or manage these uncertainties to ensure reliable electric power. Finally, we briefly discuss market-supplied solutions to planning, operations, and reliability issues.

Power Outage Study Team
2000
Report of the U.S. Department of Energy's Power Outage Study Team: Findings and Recommendations to Enhance Reliability from the Summer of 1999
Carrier, P., Chairman. March 2000
216 KB PDF, 65 pp

In its interim report, POST found that the reliability events of the summer of 1999 demonstrated that the necessary operating practices, regulatory policies, and technological tools for assuring an acceptable level of reliability were not yet in place. This report outlines some of the changes needed to address the causes of these events.

Many of the recommendations presented in this report address reforms required to enable restructured markets to fulfill their potential to provide improved reliability. Markets should reflect the value of reliability to energy providers and their customers, and to the broader public interest. Both providers and customers should have opportunities to participate in markets for energy and ancillary services—and to profit from that participation. Modified (or new) institutions are needed to monitor and enforce compliance with reliability standards.

Interim Report of the U.S. Department of Energy's Power Outage Study Team
Carrier, P., Chairman. January 2000
1.5 MB PDF, 98 pp

The electric power industry is in the midst of evolutionary change. The reliability events during the summer of 1999 (i.e., outages in New York City, Long Island, New Jersey, the Delmarva [Delaware-Maryland-Virginia] Peninsula, the South-Central States, and Chicago and nonoutage power disturbances in New England and the Mid-Atlantic area) demonstrate that the necessary operating practices, regulatory policies, and technological tools for dealing with the changes are not yet in place to assure an acceptable level of reliability. In a restructured environment, generation technologies and prices are a matter of private choice, yet the reliability of the delivery system benefits everyone. The operation of the electric system is more difficult to coordinate in a competitive environment, where a much larger number of parties are participating.

IEEE-CERTS Reliability Symposium
2000
Summary Proceedings of IEEE-USA's 2000 Energy Policy Symposium
May 24, 2000
Summary Proceedings

The Institute of Electrical and Electronics Engineers—United States of America (IEEE-USA) Energy Policy Committee and the Consortium for Electric Reliability Technology Solutions (CERTS) organized a one-day symposium on 24 May 2000 at the Hyatt Regency Hotel in Washington, D.C. with co-sponsorship by Electric Power Research Institute (EPRI) and the U.S. Department of Energy. The Symposium examined the challenges that lie ahead for ensuring reliability as the U.S. electric power system undergoes the most fundamental transformation in its operation since its creation more than 100 years ago.
It explored the perspectives of market participants, system operators, government, and academics on various aspects of reliability—including market operations, system management, industry oversight, and research and development. Held to promote a dialogue between industry stakeholders on issues related to reliability management, the symposium provided the factual backdrop to policymakers for the upcoming debates on reliability and the restructuring of the electric power industry.

http://certs.lbl.gov