Least-cost overvoltage control in PV-rich distribution networks via Unbalanced Optimal Power Flow

The rapid increase of distributed energy resources (DERs) installation at residential and commercial levels can pose significant technical issues on the voltage levels and capacity of the network assets in distribution networks. Most of these issues occur in low-voltage distribution networks (LVDNs) or near customer premises. A lack of understanding of the networks and advanced planning approaches by distribution network providers (DNSPs) has led to rough estimations for maximum DERs penetration levels that LVDNs can accommodate. These issues might under- or over-estimate the actual hosting capacity of the LVDNs. Limited available data on LVDNs' capacity to host DERs makes planning, installing, and connecting new DERs problematic and complex. In addition, the lack of transparency in LVDN data and information leads to model simplifications, such as ignoring the phase imbalance. This can lead to grossly inaccurate results. The main aim of this paper is to enable the understanding of the true extent of local voltage excursions to allow more targeted investment, improve the network's reliability, enhance solar performance distribution, and increase photovoltaic (PV) penetration levels in LVDNs. Therefore, this paper reviews the state-of-the-art best practices in modeling unbalanced LVDNs as accurately as possible to avoid under- or over-estimation of the network's hosting capacity. In addition, several PV system modeling variations are reviewed, showing their limitations and merits as a trade-off between accuracy, computational burden, and data availability. Moreover, the unbalanced power flow representations, solving algorithms, and available tools are explained extensively by providing a comparative study between these tools and the ones most commonly used in Australia. This paper also presents an overview of unbalanced optimal power flow representations with their related objectives, solving algorithms, and tools.

The role of distribution system operators (DSOs) has been changed due to deregulation in the distribution sector of the power systems. In this paper, a bi-level optimization problem is proposed to manage the day-ahead scheduling in an unbalanced distribution system with several micro-grids (MGs) in a decentralized manner. In the proposed framework, at the first level, the micro-grid operators (MGOs) solve their optimization problem to minimize their cost for the next 24 hours independently and send their aggregated demand to the DSO. Then, in the next level of optimization, DSO adjusts the main transformer and capacitor banks' tap position through an optimal power flow (OPF) problem to minimize the power loss with the minimum tap changing. To increase accuracy, the effect of earth is considered in unbalanced optimal power flow equations. To check the effectiveness of the proposed method, a modified unbalanced 13-bus IEEE test system is used as a case study. The results show that with the proposed framework, the MGOs and DSO can cooperate mutually. Also, by adjusting the main transformer and capacitor banks' tap position, the daily power loss is reduced by 30%.

Unbalanced three-phase distribution networks are undergoing significant changes with the advent of modern distributed energy resources (DER). These DER come in the form of both load and generation, such as electric vehicles, heat pumps, photovoltaics and micro wind turbines, and have the potential to drastically modify customers' behaviours and needs. Consequently, as distribution networks continue to develop, network management systems will become a crucial element of future distribution system architecture. This work introduces a multi-period, three-phase, unbalanced optimal power flow (TOPF) method, which has the capability to provide optimal solutions for distribution system control variables, for a chosen objective function, subject to required constraints. The method is validated with the IEEE 123-node test feeder, and a practical test feeder with the addition of photovoltaic systems is utilised to demonstrate the multi-period TOPF capabilities. The results show the benefits of adding storage to PV systems when combined with the TOPF formulation described here.

Robust Design of Distributed Energy Systems Within Unbalanced Power Networks

Voltage rise beyond statuary limits in low voltage (LV) ac networks due to high photovoltaic (PV) penetration and its mitigation using multiple techniques was assessed. Investigations using a real rural domestic overhead LV network were done through load flow simulations. A three-phase four wire medium length LV network with a fixed tap transformer and PV inverters operating at unity power factor was able to host PV between 79%–98% of transformer ratings for five different PV configurations. For the case studied at this penetration level three, limiting factors (voltage, thermal loading limits of lines, and transformer) come together. Three techniques were utilized to control the voltage across the LV network. On load tap changer (OLTC) control was found more robust than reactive power control (RPC). Hybrid control (OLTC and RPC) was found beneficial only for extra high PV penetration scenarios. Replacement of a few critical line spans and the existing transformer with higher capacity conductors and an OLTC equipped transformer (higher size) enabled the network to host an additional 50%–90% PV. The unequal distribution of single-phase PV systems among three phases has negative effects on penetration. Consideration of PV integration while planning new LV networks and retrofitting of OLTCs with existing transformers, could make the LV system more PV friendly. The RPC option, though less effective than OLTC due to increased current, can be beneficial at medium penetrations where OLTC may become a costly solution.

Mathematical models representing the behavior of electrical loads are an important part of any optimal power flow problem. The current state-of-the-art in unbalanced optimal power flow mostly considers wye-connected, constant power loads. However, for applications such as conservation voltage reduction, it is crucial to model how the consumption of the loads depends on the voltage of the network. This article develops a unified framework to handle a wide variety of load types: delta- or wye-connected, constant power, constant current and exponential load models. Furthermore, it proposes a novel convex relaxation for the exponential model, using power cones, that is intersected next with a well-known semi-definite relaxation of unbalanced OPF. Finally, numerical results on the LVTestCase feeder are included for both the exact, non-linear equations and the convex relaxation, which show how considering the voltage sensitivity and connection type can lead to different objective values and voltage profiles. Additional results for 128 low-voltage networks, examine the quality of the solutions obtained with the proposed relaxation.

This study proposes a model for multi‐phase, multi‐winding, lossy transformers. A methodology is developed to decompose such transformers into a sub‐network of multi‐conductor ‐sections, shunts and idealised (lossless) two‐winding transformers. The approach, therefore, can be used to include three‐phase transformer models in any unbalanced power flow or optimal power flow tool that is able to represent these three basic components. The study derives the mathematical formulation and an implementation is provided in Julia/JuMP/PowerModelsDistribution.jl. The obtained voltage profile for several distribution test cases deviates from OpenDSS by at most . A case study applies this model to optimise the tap settings in the context of conservative voltage reduction. This illustrates that the optimised tap settings can vary by as much as 30% depending on the vector group of the transformer.

In this paper a methodology is proposed to calculate the load demand flexibility that could be activated within the next 24-hours for solving the technical impacts of contingencies that may come up in an unbalanced low voltage distribution networks with high penetration of intermittent DG sources. The methodology is formulated within a Demand Response program environment via load shifting as flexibility enabler mechanism. To achieve that, a non-linear optimisation problem is formulated based on an unbalanced optimal power flow, which allows the determination of the load flexibility that each Demand Response customer could provide at the request of the Distribution System Operator. The demand as well as weather conditions are forecasted for the day ahead. The optimisation problem is solved in a sequence fashion, within a daily framework, splitting the whole problem in optimisation blocks. In each block, the flexible load demand is obtained and the load demand forecasting its updated for the upcoming blocks based on the changes in the scheduled load demand. The methodology is applied to a real distribution network with the load data received from the smart metering infrastructure. The results obtained show the strength of the methodology in solving the technical problems of the network under high unbalanced operation.

The growing adoption of residential photovoltaic (PV) systems around the world is presenting distribution network operators (DNOs) with technical challenges, particularly on low voltage (LV) networks. The need to mitigate these issues with simple yet effective measures in countries with high PV penetrations is likely to drive the adoption of limits on the very exports that affect this infrastructure. Defining the most adequate limit, however, requires understanding the tradeoffs between the technical benefits and the effects on PV owners. This paper proposes two methodologies: an optimal power flow (OPF) based technique to define the export limit that solves technical problems with minimal curtailment, and a Monte Carlo based analysis to investigate the spectrum of such tradeoffs considering different PV penetrations and export limits. A real U.K. residential LV network with 180 customers is analyzed using realistic 1-min resolution daily load and PV generation profiles across seasons. Results demonstrate that, for DNOs, the OPF-based approach is effective in determining the most technically adequate export limit. However, for policy makers, the spectrum of tradeoffs provided by the Monte Carlo approach can help defining export limits that reduce curtailment at the expense of partially mitigating technical issues.

The use of battery energy storage systems (BESS) is one of the methods employed in solving the major challenge of overvoltage, experienced on low voltage (LV) distribution networks with high penetration of photovoltaics (PV). The overvoltage problem limits the penetration levels of PV into the LV network, and the benefits that could be gained. This paper presents a smart scheme for the coordination of multiple battery energy storage systems (BESS) in such networks. An approximate method was adopted for the evaluation of network voltage sensitivity, and the coordination algorithm was developed based upon this. Through the efficient selection, coordination and timing of charge and discharge operations of the BESS, the scheme maintains bus voltages within statutory ranges during both periods of high PV power generation and high network load demand. The scheme also prevents sudden voltage rise, which usually occurs in such networks immediately a BESS gets fully charged. Simulations were carried out on a real LV distribution network and results demonstrate the effectiveness of this approach.

Low-voltage distribution network is a three-phase unbalanced system due to the integration of single-phase loads and single-phase distributed PV arrays. In this paper, three-phase unbalanced interval power flow calculation model of three-phase four-wire low voltage distribution network with distributed PV power generation is established. In the model, intensity of illumination and battery temperature which influence the power output of distributed PV power generation is described as intervals. Then, through the affine interval algorithm, the interval power flow problem is transformed into a deterministic power flow problem and two linear optimization problems. By solving the above problems, the interval power flow solution can be obtained. Finally, the proposed algorithm is applied to an actual 22-bus low-voltage distribution network, and the solution of the affine interval algorithm is compared to the solution of the Monte Carlo sampling method, which verifies the correctness and effectiveness of the proposed algorithm.

This paper proposes an extended three-phase converter model for unbalanced power flow studies [Stoicescu, R et al., 2002]. The actual three-phase converters presented in this paper consist of a thyristor rectifier, a dc system, and a pulse-width-modulated (PWM) voltage source inverter. The converter is modeled with three single-phase, grounded, Y-connected converters. It is equivalent to the actual converters with respect to the average dc current on the dc link. The converter model is integrated into an unbalanced sequential power flow solver. The solution algorithm is tested in a 16-bus test system. Simulation results are presented.

The impact of harmonics compensation ancillary services of photovoltaic microgeneration in low voltage distribution networks

Nonconvex lifted unbalanced branch flow model: Derivation, implementation and experiments

ABSTRACTThe voltage rise caused by photovoltaic (PV) power feed‐in is one of the main network constraints limiting the PV penetration in distribution networks. In this paper, a local voltage control approach for PV inverters based on reactive power management is proposed and investigated into detail. Through a parametric study, various inverter settings are considered and compared for a real medium voltage network with a high PV penetration level and for which a demonstration is planned within the project MetaPV. The purpose of this work is to investigate the suitability of such control concepts to compensate the voltage rise caused by the PV power feed‐in and to provide some guidance on the adjustment of the settings of such control mechanisms. For the assessment of the performance of the control concept with different settings, extensive load flow simulations have been performed for a voltage‐dependent reactive power control (Q(V) characteristics) on the basis of 15‐minute profiles. As a result, voltage time‐series over a period of 1 year are obtained for each case and analysed into details. Apart from the voltage profiles, other features such as network losses and reactive energy import have been quantified because they are also of noticeable importance for network operators. The simulation results show that suitable settings are necessary to maintain the voltage within the prescribed limits. A comparison between the considered cases shows that reactive power control Q(V) with a power factor down to 0.9 is necessary to achieve satisfying results. The use of a dead‐band is recommended for the voltage‐dependent reactive power control in order to limit the losses and reactive energy import. Copyright © 2011 John Wiley & Sons, Ltd.