In this paper, we propose a measurement-based approach to the real-time economic dispatch (ED). The realtime ED is a widely used market scheduling problem seeking to economically balance electricity system supply and demand and provide locational marginal prices (LMPs) while respecting system reliability requirements. The ED is a convex optimization problem with a linear or quadratic objective, typically the minimization of generator costs or the maximization of social surplus. The constraints capture power balance and network flow capacity limits and are formulated using a linearized power flow model. Our approach utilizes power system sensitivities estimated from phasor measurement unit (PMU) measurements to reformulate the model-based power flow and network flow constraints. The resulting measurement-based real-time ED overcomes the vulnerabilities of the model-based real-time ED. The dispatch instructions and LMPs calculated with our measurement-based real-time ED accurately, and adaptively, reflect real-time system conditions. We illustrate the strengths of the proposed approach via several case studies.

%B 2015 IEEE Power & Energy Society General Meeting %I IEEE %C Denver, CO, USA %P 1 - 5 %8 07/2015 %R 10.1109/PESGM.2015.7286091 %0 Journal Article %J IEEE Transactions on Power Systems %D 2015 %T Measurement-Based Real-Time Security-Constrained Economic Dispatch %A Van Horn, Kai E. %A Alejandro D. Dominguez-Garcia %A Peter W. Sauer %K AA05-005 %XIn this paper, we propose a measurement-based approach to the real-time security-constrained economic dispatch (SCED). The real-time SCED is a widely used market scheduling tool that seeks to economically balance electricity supply and demand and provide locational marginal prices (LMPs), while ensuring system reliability standards are met. To capture network flows and security considerations, the conventional SCED formulation relies on sensitivities that are typically computed from a linearized power flow model, which is vulnerable to phenomena such as undetected topology changes, changes in the system operating point, and the existence of incorrect model data. Our approach to the formulation of the SCED problem utilizes power system sensitivities estimated from phasor measurement unit (PMU) measurements. The resulting measurement-based real-time SCED is robust against the aforementioned phenomena. Moreover, the dispatch instructions and LMPs calculated with the proposed measurement-based SCED accurately reflect real-time system conditions and security needs. We illustrate the strengths of the proposed approach via several case studies.

%B IEEE Transactions on Power Systems %V PP %P 1 - 13 %8 12/2015 %! IEEE Trans. Power Syst. %R 10.1109/TPWRS.2015.2493889 %0 Conference Paper %B 2015 North American Power Symposium (NAPS) %D 2015 %T Sensitivity-based line outage angle factors %A Van Horn, Kai E. %A Alejandro D. Dominguez-Garcia %A Peter W. Sauer %K AA05-005 %XIn this paper, we propose a model-based approach to the computation of line outage angle factors (LOAFs), which relies on the use of angle factors (AFs) and power transfer distribution factors (PTDFs). A LOAF provides the sensitivity of the voltage angle difference between the terminal buses of a transmission line in the event the line is outaged to the pre-outage active power flow on the line. Large angle differences between the terminal buses of an outaged line can prevent the successful reclosure of the line-such an event was a significant contributing factor to the 2011 San Diego blackout. The proposed model-based LOAFs, along with the AFs and injection shift factors (ISFs), enable the fast computation of the impact on the angle across lines of line outages and active power injections, and provide system operators a systematic mean by which to assess line outage angles and undertake the appropriate dispatch actions necessary to alleviate large phase angle differences. We demonstrate the effectiveness of the proposed LOAFs with a case study carried out on the IEEE 14-bus test system.

%B 2015 North American Power Symposium (NAPS) %I IEEE %C Charlotte, NC, USA %P 1 - 5 %8 10/2015 %R 10.1109/NAPS.2015.7335130 %0 Conference Paper %B 2014 North American Power Symposium (NAPS) %D 2014 %T Generalized injection shift factors and application to estimation of power flow transients %A Chen, Yu Christine %A Alejandro D. Dominguez-Garcia %A Peter W. Sauer %K AARD %K CERTS %X This paper proposes a method to estimate transmission line flows in a power system during the transient period following a loss of generation or increase in load contingency by using linear sensitivity injection shift factors (ISFs). Traditionally, ISFs are computed from an offline power flow model of the system with the slack bus defined. The proposed method, however, relies on generalized ISFs estimated via the solution of a system of linear equations that arise from high-frequency synchronized measurements obtained from phasor measurement units. Even though the generalized ISFs are obtained at the pre-disturbance steady-state operating point, by leveraging inertial and governor power flows during appropriate time-scales, they can be manipulated to predict active transmission line flows during the post-contingency transient period. %B 2014 North American Power Symposium (NAPS) %I IEEE %C Pullman, WA, USA %P 1 - 5 %8 09/2014 %R 10.1109/NAPS.2014.6965399 %0 Journal Article %J IEEE Transactions on Power Systems %D 2014 %T Measurement-Based Estimation of Linear Sensitivity Distribution Factors and Applications %A Chen, Yu Christine %A Alejandro D. Dominguez-Garcia %A Peter W. Sauer %K AARD %K Automatic Switchable Network (ASN) %K CERTS %K load modeling %K phasor measurement units (PMUs) %K power system monitoring %X In this paper, we propose a method to compute linear sensitivity distribution factors (DFs) in near real-time. The method does not rely on the system power flow model. Instead, it uses only high-frequency synchronized data collected from phasor measurement units to estimate the injection shift factors through linear least-squares estimation, after which other DFs can be easily computed. Such a measurement-based approach is desirable since it is adaptive to changes in system operating point and topology. We further improve the adaptability of the proposed approach to such changes by using weighted and recursive least-squares estimation. Through numerical examples, we illustrate the advantages of our proposed DF estimation approach over the conventional model-based one in the context of contingency analysis and generation re-dispatch. %B IEEE Transactions on Power Systems %V 29 %P 1372 - 1382 %8 5/2014 %N 3 %! IEEE Trans. Power Syst. %R 10.1109/TPWRS.2013.2292370 %0 Journal Article %J IEEE Transactions on Power Systems %D 2014 %T A Sparse Representation Approach to Online Estimation of Power System Distribution Factors %A Chen, Yu Christine %A Alejandro D. Dominguez-Garcia %A Peter W. Sauer %K AARD %X In this paper, we propose a method to compute linear sensitivity distribution factors (DFs) in near real time without relying on a power flow model of the system. Specifically, we compute the injection shift factors (ISFs) of a particular line of interest with respect to active power injections at all buses (all other DFs can be determined from ISFs). The proposed ISF estimation method relies on the solution of an underdetermined system of linear equations that arise from high-frequency synchronized measurements obtained from phasor measurement units. We exploit a sparse representation (i.e., one in which many elements are zero) of the vector of desired ISFs via rearrangement by electrical distance and an appropriately chosen linear transformation, and cast the estimation problem into a sparse vector recovery problem. As we illustrate through case studies, the proposed approach provides accurate DF estimates with fewer sets of synchronized measurements than earlier approaches that rely on the solution of an overdetermined system of equations via the least-squares errors estimation method. %B IEEE Transactions on Power Systems %P 1 - 12 %8 10/2014 %! IEEE Trans. Power Syst. %R 10.1109/TPWRS.2014.2356399 %0 Conference Paper %B 2013 North American Power Symposium (NAPS) %D 2013 %T Online estimation of power system distribution factors — A sparse representation approach %A Chen, Yu Christine %A Alejandro D. Dominguez-Garcia %A Peter W. Sauer %K AARD %K Automatic Switchable Network (ASN) %K CERTS %K distribution factors %K phasor measurement units (PMUs) %K power system reliability %XThis paper proposes a method to compute linear sensitivity distribution factors (DFs) in near real-time without relying on a power flow model of the system. Instead, the proposed method relies on the solution of an underdetermined system of linear equations that arise from high-frequency synchronized measurements obtained from phasor measurement units. In particular, we exploit a sparse representation (i.e., one in which many elements are zero) of the desired DFs obtained via a linear transformation, and cast the estimation problem as an IO-norm minimization. As we illustrate through examples, the proposed approach is able to provide accurate DF estimates with fewer sets of synchronized measurements than earlier approaches that rely on the solution of an overdetermined system of equations via the least-squares errors method.

%B 2013 North American Power Symposium (NAPS) %I IEEE %C Manhattan, KS, USA %P 1 - 5 %8 09/2013 %R 10.1109/NAPS.2013.6666886 %0 Generic %D 2012 %T Reliability Performance Monitoring (RPM) Prototype Preliminary Validation Results, User Interface, Deployment Plan, and Field Test %A Carlos A. Martinez %A Peter W. Sauer %A Alejandro Dominguez-Garcia %K MISO-GPM %K reliability metrics and monitoring %K reliability monitoring tools %8 03/2012 %0 Report %D 2004 %T Integrated Security Analysis Final Report %A Peter W. Sauer %A Kevin Tomsovic %A Jeffery E. Dagle %A Steven E. Widergren %A Tony B. Nguyen %A Lawrence Schienbein %K RTGRM %K System Security Tools %XThis report presents results on the identification of the current state of power system security analysis for operations and the potential integration of the various existing power system security analysis tools. Current security analysis consists of numerous software tools (some off-line and some on-line) that predict operator guidelines for transaction scheduling. A survey of selected operators in representative locations in both the East and Western US was conducted to determine the effectiveness of current tools and the need for future improvements.

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