412 research outputs found
On the Properties of the Compound Nodal Admittance Matrix of Polyphase Power Systems
Most techniques for power system analysis model the grid by exact electrical
circuits. For instance, in power flow study, state estimation, and voltage
stability assessment, the use of admittance parameters (i.e., the nodal
admittance matrix) and hybrid parameters is common. Moreover, network reduction
techniques (e.g., Kron reduction) are often applied to decrease the size of
large grid models (i.e., with hundreds or thousands of state variables),
thereby alleviating the computational burden. However, researchers normally
disregard the fact that the applicability of these methods is not generally
guaranteed. In reality, the nodal admittance must satisfy certain properties in
order for hybrid parameters to exist and Kron reduction to be feasible.
Recently, this problem was solved for the particular cases of monophase and
balanced triphase grids. This paper investigates the general case of unbalanced
polyphase grids. Firstly, conditions determining the rank of the so-called
compound nodal admittance matrix and its diagonal subblocks are deduced from
the characteristics of the electrical components and the network graph.
Secondly, the implications of these findings concerning the feasibility of Kron
reduction and the existence of hybrid parameters are discussed. In this regard,
this paper provides a rigorous theoretical foundation for various applications
in power system analysi
On the Properties of the Power Systems Nodal Admittance Matrix
This letter provides conditions determining the rank of the nodal admittance
matrix, and arbitrary block partitions of it, for connected AC power networks
with complex admittances. Furthermore, some implications of these properties
concerning Kron Reduction and Hybrid Network Parameters are outlined.Comment: Index Terms: Nodal Admittance Matrix, Rank, Block Form, Network
Partition, Kron Reduction, Hybrid Network Parameter
A Generalized Index for Static Voltage Stability of Unbalanced Polyphase Power Systems including Th\'evenin Equivalents and Polynomial Models
This paper proposes a Voltage Stability Index (VSI) suitable for unbalanced
polyphase power systems. To this end, the grid is represented by a polyphase
multiport network model (i.e., compound hybrid parameters), and the aggregate
behavior of the devices in each node by Th\'evenin Equivalents (TEs) and
Polynomial Models (PMs), respectively. The proposed VSI is a generalization of
the known L-index, which is achieved through the use of compound electrical
parameters, and the incorporation of TEs and PMs into its formal definition.
Notably, the proposed VSI can handle unbalanced polyphase power systems,
explicitly accounts for voltage-dependent behavior (represented by PMs), and is
computationally inexpensive. These features are valuable for the operation of
both transmission and distribution systems. Specifically, the ability to handle
the unbalanced polyphase case is of particular value for distribution systems.
In this context, it is proven that the compound hybrid parameters required for
the calculation of the VSI do exist under practical conditions (i.e., for lossy
grids). The proposed VSI is validated against state-of-the-art methods for
voltage stability assessment using a benchmark system which is based on the
IEEE 34-node feeder
Achieving the Dispatchability of Distribution Feeders through Prosumers Data Driven Forecasting and Model Predictive Control of Electrochemical Storage
We propose and experimentally validate a control strategy to dispatch the
operation of a distribution feeder interfacing heterogeneous prosumers by using
a grid-connected battery energy storage system (BESS) as a controllable element
coupled with a minimally invasive monitoring infrastructure. It consists in a
two-stage procedure: day-ahead dispatch planning, where the feeder 5-minute
average power consumption trajectory for the next day of operation (called
\emph{dispatch plan}) is determined, and intra-day/real-time operation, where
the mismatch with respect to the \emph{dispatch plan} is corrected by applying
receding horizon model predictive control (MPC) to decide the BESS
charging/discharging profile while accounting for operational constraints. The
consumption forecast necessary to compute the \emph{dispatch plan} and the
battery model for the MPC algorithm are built by applying adaptive data driven
methodologies. The discussed control framework currently operates on a daily
basis to dispatch the operation of a 20~kV feeder of the EPFL university campus
using a 750~kW/500~kWh lithium titanate BESS.Comment: Submitted for publication, 201
PMU-Based ROCOF Measurements: Uncertainty Limits and Metrological Significance in Power System Applications
In modern power systems, the Rate-of-Change-of-Frequency (ROCOF) may be
largely employed in Wide Area Monitoring, Protection and Control (WAMPAC)
applications. However, a standard approach towards ROCOF measurements is still
missing. In this paper, we investigate the feasibility of Phasor Measurement
Units (PMUs) deployment in ROCOF-based applications, with a specific focus on
Under-Frequency Load-Shedding (UFLS). For this analysis, we select three
state-of-the-art window-based synchrophasor estimation algorithms and compare
different signal models, ROCOF estimation techniques and window lengths in
datasets inspired by real-world acquisitions. In this sense, we are able to
carry out a sensitivity analysis of the behavior of a PMU-based UFLS control
scheme. Based on the proposed results, PMUs prove to be accurate ROCOF meters,
as long as the harmonic and inter-harmonic distortion within the measurement
pass-bandwidth is scarce. In the presence of transient events, the
synchrophasor model looses its appropriateness as the signal energy spreads
over the entire spectrum and cannot be approximated as a sequence of
narrow-band components. Finally, we validate the actual feasibility of
PMU-based UFLS in a real-time simulated scenario where we compare two different
ROCOF estimation techniques with a frequency-based control scheme and we show
their impact on the successful grid restoration.Comment: Manuscript IM-18-20133R. Accepted for publication on IEEE
Transactions on Instrumentation and Measurement (acceptance date: 9 March
2019
Experimental Validation of Model-less Robust Voltage Control using Measurement-based Estimated Voltage Sensitivity Coefficients
Increasing adoption of smart meters and phasor measurement units (PMUs) in
power distribution networks are enabling the adoption of data-driven/model-less
control schemes to mitigate grid issues such as over/under voltages and
power-flow congestions. However, such a scheme can lead to
infeasible/inaccurate control decisions due to measurement inaccuracies. In
this context, the authors' previous work proposed a robust measurement-based
control scheme accounting for the uncertainties of the estimated models. In
this scheme, a recursive least squares (RLS)-based method estimates the grid
model (in the form of voltage magnitude sensitivity coefficients). Then, a
robust control problem optimizes power set-points of distributed energy
resources (DERs) such that the nodal voltage limits are satisfied. The
estimated voltage sensitivity coefficients are used to model the nodal
voltages, and the control robustness is achieved by accounting for their
uncertainties. This work presents the first experimental validation of such a
robust model-less control scheme on a real power distribution grid. The scheme
is applied for voltage control by regulating two photovoltaic (PV) inverters
connected in a real microgrid which is a replica of the CIGRE benchmark
microgrid network at the EPFL Distributed Electrical Systems Laboratory
AC OPF in Radial Distribution Networks - Parts I,II
The optimal power-flow problem (OPF) has played a key role in the planning
and operation of power systems. Due to the non-linear nature of the AC
power-flow equations, the OPF problem is known to be non-convex, therefore hard
to solve. Most proposed methods for solving the OPF rely on approximations that
render the problem convex, but that may yield inexact solutions. Recently,
Farivar and Low proposed a method that is claimed to be exact for radial
distribution systems, despite no apparent approximations. In our work, we show
that it is, in fact, not exact. On one hand, there is a misinterpretation of
the physical network model related to the ampacity constraint of the lines'
current flows. On the other hand, the proof of the exactness of the proposed
relaxation requires unrealistic assumptions related to the unboundedness of
specific control variables. We also show that the extension of this approach to
account for exact line models might provide physically infeasible solutions.
Recently, several contributions have proposed OPF algorithms that rely on the
use of the alternating-direction method of multipliers (ADMM). However, as we
show in this work, there are cases for which the ADMM-based solution of the
non-relaxed OPF problem fails to converge. To overcome the aforementioned
limitations, we propose an algorithm for the solution of a non-approximated,
non-convex OPF problem in radial distribution systems that is based on the
method of multipliers, and on a primal decomposition of the OPF. This work is
divided in two parts. In Part I, we specifically discuss the limitations of BFM
and ADMM to solve the OPF problem. In Part II, we provide a centralized version
and a distributed asynchronous version of the proposed OPF algorithm and we
evaluate its performances using both small-scale electrical networks, as well
as a modified IEEE 13-node test feeder
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