A Method for Accurate Transmission Line Impedance Parameter Estimation

Real-time estimation of power transmission line impedance parameters has become possible with the availability of synchronized phasor (synchrophasor) measurements of voltage and current. If sufficiently accurate, the estimated parameter values are a powerful tool for improving the performance of a range of power system monitoring, protection, and control applications, including fault location and dynamic thermal line rating. The accuracy of the parameter estimates can be reduced by unknown errors in the synchrophasors that are introduced in the measurement process. In this paper, a method is proposed with the aim of obtaining accurate estimates of potentially variable impedance parameters, in the presence of systematic errors in voltage and current measurements. The method is based on optimization to identify correction constants for the phasors. A case study of a simulated transmission line is presented to demonstrate the effectiveness of the new method, which is better in comparison with a previously proposed method. The results, as well as limits, and the potential extensions of the new method are discussed

A Novel Approach to Noninvasive Measurement of Overhead Line Impedance Parameters

Transmission line impedance parameter estimation forms an essential part in modeling and monitoring of electricity networks. The accuracy of the estimated parameters has a direct impact on various functions of network operation, such as state estimation, fault location, and dynamic thermal line rating. Impedance parameters can be estimated from voltage and current measurements taken at the ends of the transmission line. Previous research has produced a range of methods with the purpose of maximizing the accuracy of the estimated values. However, the input measurements from the line ends can contain systematic errors that are introduced by the instrumentation channel and significantly reduce impedance parameter accuracy, which is not taken into account by most of the existing methods. In this paper, a novel method is presented that estimates correction factors for the systematic errors and, thus, increases the accuracy of impedance parameter values. The performance of the new method is compared with an existing one in a case study on laboratory measurements

An Assessment of PIER Electric Grid Research 2003-2014 White Paper

This white paper describes the circumstances in California around the turn of the 21st century that led the California Energy Commission (CEC) to direct additional Public Interest Energy Research funds to address critical electric grid issues, especially those arising from integrating high penetrations of variable renewable generation with the electric grid. It contains an assessment of the beneficial science and technology advances of the resultant portfolio of electric grid research projects administered under the direction of the CEC by a competitively selected contractor, the University of California’s California Institute for Energy and the Environment, from 2003-2014

Synchrophasor Based Islanding & Open phase fault Protection in Distribution Systems

With the rapid growth of renewable energy resources, energy efficiency initiatives, electric vehicles, energy storage, etc., distribution systems are becoming more complex such that conventional protection, control, and measurement infrastructure – typically concentrated at the main substation, with little to no access to information along the feeder – cannot maintain the reliability of the system without some sort of additional protection, control and measurement functionalities. As an example, a dedicated communication channel for carrying the transfer trip signal from the substation to the Point of Common Coupling (PCC) to prevent islanding operation of alternative resources, has been a requirement for many utilities. In the transformation of the distribution system from a simple radial system to a bidirectional energy flow network, integration of many intelligent devices and applications will also be required. Thus, this situation calls for investment in communication infrastructure, and augmentation of protection, control, and measurement functionalities. The value of power system communication technologies such as synchrophasor measurement technology – which includes the Phasor Measurement Unit (measuring and providing voltage and current phasors in the real time via communication), communication infrastructure, and Phasor Data Concentrator (PDC) – is being recognized through large-scale deployments around the world. However, these implementations are predominantly limited to some monitoring-type applications and are being realized primarily in transmission systems and bulk power systems (≥100 kV), where performance requirements are much more stringent compared to distribution systems. So contrary to transmission systems, the current status of synchrophasor measurement technology can be utilized to its full extent in distribution systems, as shown in current research for anti-islanding and open-phase faults in the distribution feeder protection application, where the number of PMUs and performance required is somewhat lower than the bulk of power energy. Thus, the opportunity to invest in the implementation of synchronized measurement technology in distribution system is timely as it can be coordinated with other investments in feeder modernization, distributed generation (DG) integration, and infrastructure enhancements that are underway, including “smart grid” initiatives. In the first use case of this research, the behavior of the major DG types during islanding is studied through accurate transient modeling of utility type distribution systems using PSCAD-EMTDC and MATLAB. The study proposes augmentation of PMU-based solutions to the current passive islanding protection elements, such as voltage and frequency, and improving the non-detection zone of the passive elements by adapting their settings based on normal loading conditions at closest known instant prior to the fault or islanding occurrence. The solution proposes a system architecture that requires one PMU at each PCC bus and in the main substation. The communication aspect is based on the IEC 6850-90-5 report, where the PMU can subscribe directly to the data stream of the remote PMUs such that the need for PDCs in this application is eliminated, yielding better performance. In the second use case, an open-phase fault – a major concern for distribution utilities from safety of public and equipment perspective – has been studied. Clearing the open-phase fault without identifying the type of fault could result in an attempt by the recloser to reenergize the downed wire; conversely, an undetected open-phase fault could initiate ferro-resonance, thereby stressing equipment and increasing the risk to public safety, both urban and rural. This work discusses comprehensive analysis of symmetrical components of various types of open-phase faults in the distribution feeder with the presence of distributed generators (DGs) and proposes the use of phasor measurement data located at substation and PCC to identify the open-phase fault. The proposed algorithm relies on the rate of change of the various current and voltage sequence components. In the study conducted, the utility type feeder and substation are modeled in PSCAD-EMTDC, and different types of open-phase fault and shunt faults are studied to verify the dependability and security of proposed algorithm

Transmission Line Parameter Estimation using Synchrophasor Data

abstract: Transmission line parameters play an important role in state estimation, dynamic line rating, and fault analysis. Because of this, several methods have been proposed in the literature for line parameter estimation, especially using synchrophasor data. However, success of most prior research has been demonstrated using purely synthetic data. A synthetic dataset does not have the problems encountered with real data, such as invariance of measurements and realistic field noise. Therefore, the algorithms developed using synthetic datasets may not be as effective when used in practice. On the other hand, the true values of the line parameters are unknown and therefore the algorithms cannot be directly implemented on real data. A multi-stage test procedure is developed in this work to circumvent this problem. In this thesis, two popular algorithms, namely, moving-window total least squares (MWTLS) and recursive Kalman filter (RKF) are applied on real data in multiple stages. In the first stage, the algorithms are tested on a purely synthetic dataset. This is followed by testing done on pseudo-synthetic datasets generated using real PMU data. In the final stage, the algorithms are implemented on the real PMU data obtained from a local utility. The results show that in the context of the given problem, RKF has better performance than MWTLS. Furthermore, to improve the performance of RKF on real data, ASPEN data are used to calculate the initial estimates. The estimation results show that the RKF algorithm can reliably estimate the sequence impedances, using ASPEN data as a starting condition. The estimation procedure is repeated over different time periods and the corresponding results are presented. Finally, the significance of data drop-outs and its impact on the use of parameter estimates for real-time power system applications, such as state estimation and dynamic line rating, is discussed. To address the problem (of data drop-outs), an auto regressive integrated moving average (ARIMA) model is implemented. The ability of this model to predict the variations in sequence impedances is demonstrated.Dissertation/ThesisMasters Thesis Electrical Engineering 201

Synchrophasor-based overhead line impedance monitoring

Thermal limits of overhead transmission lines create network constraints that can result in curtailment of renewable energy generation. Thermal limits are conventionally static and based on worst-case, non-cooling ambient weather conditions, leading to under-utilization of overhead lines. Utilization can be increased and network constraints reduced by rating overhead lines dynamically, based on actual conductor temperature. Installation and maintenance of temperature and weather sensors along an overhead line is expensive and laborious. A more cost-effective solution is to derive average conductor temperature from overhead line impedance parameters, which can be calculated from measurements of electrical signals at each line end. Synchronized phasor measurement technology is becoming increasingly available in substations to capture voltage and current signals with high accuracy and reporting rates. It is known that the substation instrumentation channel can introduce significant systematic errors to the phasor measurements, which in turn cause inaccurate line impedance parameter and temperature values. This thesis presents novel methods for accurate, real-time monitoring of overhead line impedance parameters using synchronized phasor measurements that have systematic errors. In contrast to previous research, the time-variance and temperature dependence of line resistance as well as compensation of systematic errors is taken into account in the system model to increase parameter estimation accuracy. In addition, an algorithm for the selection of the best parameter estimates from different measurement sets is given. The effectiveness of the novel methods is demonstrated in several case studies on measurement data from simulations and an actual overhead line. The results show that the identified correction factors compensate systematic measurement errors, leading to a reduction in impedance parameter estimation errors of at least one order of magnitude compared to existing methods. Furthermore, the accuracy of real-time estimation of average conductor temperature was increased by at least one order of magnitude relative to previously proposed methods

Online Non-iterative Estimation of Transmission Line and Transformer Parameters by SCADA Data

Utilization of various measurements provided by supervisory control and data acquisition (SCADA) system has recently attracted increasing attention. Real-time estimation of transmission line parameters, utilizing voltage and power flow measurements provided by remote terminal units (RTUs) located at line terminals, has been investigated. This paper significantly improves the existing approaches by introducing a novel linear formulation of the problem, which can be solved in a closed form. The distributed-parameter model of long transmission lines is considered and its parameters are estimated in a noniterative manner using traditional SCADA measurements. The new method is further extended to estimate transformer series impedance and tap position using SCADA measurements, linearly. As such, the shortcomings associated with the previously proposed iterative approach, e.g. concern over convergence, for transmission line parameters are avoided. Moreover, the novel technique for estimating transformer parameters allows to determine the tap position as well as updated transformer series impedance. Furthermore, a thorough analysis is presented to take the measurement accuracy into account. Simulation results for different transmission lines and transformers in the IEEE 118-bus test system are reported. The results obtained indicate successful performance of the proposed algorithms

Exploiting phasor measurement units for enhanced transmission network operation and control

This thesis was submitted for the degree of Doctor of Engineering and awarded by Brunel UniversityIn order to achieve binding Government targets towards the decarbonisation of the electricity network, the GB power system is undergoing an unprecedented amount of change. A series of new technologies designed to integrate massive volumes of renewable generation, predominantly in the form of offshore wind, asynchronously connecting to the periphery of the transmission system, are transforming the requirements of the network. This displacement of traditional thermal generation is leading to a significant reduction in system inertia, thus making the task of system operation more challenging. It is therefore deemed necessary to develop tools and technologies that provide far greater insight into the state of the power system in real-time and give rise to methods for improving offline modelling practices through an enhanced understanding of the systems performance. To that extent PMUs are seen as one of the key enablers of the Smart Grid, providing accurate time-synchronised measurements on the state of the power system, allowing the true dynamics of the power system to be captured and analysed. This thesis provides an analysis of the existing PMU deployment on the GB transmission system with a view to the future system monitoring requirements. A critical evaluation and comparison is also provided on the suitability of a University based Low Voltage PMU network to further enhance the visibility of the GB system. In addition a novel event detection algorithm based on Detrended Fluctuation Analysis is developed and demonstrated, designed to determine the exact start time of a transmission event, as well as the suitability of such an event for additional transmission system analysis, namely inertia estimation. Finally, a reliable method for the estimation of total system inertia is proposed that includes an estimate of the contribution from residual sources, of which there is currently no visibility. The proposed method identifies the importance of regional inertia and its impact to the operation of the GB transmission system.Engineering and Physical Sciences Research Council (EPSRC) and National Grid