• Energy Research

In this paper, a new control method for a line-commutated converter-based (LCC) high-voltage direct current (HVDC) system to support the frequency and AC voltage was proposed. For coordinated control of the inverter and rectifier, droop-based controllers are adopted for the outer loop of conventional controllers, and DC voltage is used to transfer the frequency information so that communication is not required. A method to determine the droop constants of the proposed controller is presented to emulate the conventional $f$ / $P$ droop characteristic and suppress the AC voltage fluctuations. Furthermore, a small-signal state-space model of the LCC HVDC system with the proposed scheme is derived, and root locus analysis is carried out to evaluate its stability. The effects of the proposed method are verified based on case studies, using the well-known CIGRE BENCHMARK model. The advantages of the proposed method can be summarized as follows: 1) system reliability is enhanced because there is no risk of communication failure during frequency information transfer and 2) voltage stability at the inverter side is enhanced as AC voltage fluctuation during frequency support is minimized.

This paper proposes three-phase steady-state models for a distributed generator (DG) interfaced to a main system via a three-wire current-controlled voltage-source converter. In order to represent the DG in a realistic manner, the three major factors that determine the steady-state phase outputs under unbalanced operating conditions are considered: 1) the power control strategy; 2) output filter; and 3) voltage and current sensor positions. Based on these factors, the DGs are classified into various types. According to the position of the voltage sensor, two equivalent circuit models including an equivalent three-phase current source (ETCS) are proposed. For each type of DG, the output current of the ETCS is formulated as a function of the voltage of the ETCS-connected node, the filter impedances, and the active and reactive power references. To verify the accuracy of the proposed models, the results of the power flow incorporating them are compared with those obtained from the PSCAD simulation using detailed dynamic models of the DG.

The Korean energy management system (K-EMS) development project, which includes the development of the dispatcher training simulator (DTS), has been underway since 2005. The DTS provides a realistic environment for system dispatchers to practice operating tasks and experience emergency operating situations. In order to provide a realistic environment, the DTS includes many dynamic models of power plants, such as fossil fuel plant and hydro plants. In this paper, the fossil fuel power plant model for the DTS in K-EMS is introduced and verified through actual measurement data.

Because it is almost impossible to train the dispatchers with real power system, the dispatcher training simulator (DTS) is used for the training. Among various components of the DTS, the power system model (PSM) emulates the dynamic behavior of the power system to calculate the frequency and voltage. In the PSM, the power plants are modeled as differential equations, so the mechanical power of the power plants is calculated by the numerical methods. Conventionally, the fixed step-size algorithm has been used in the PSM, however it has some drawbacks. This paper develops the prototype PSM using the Matlab, and analyzes the problems of the fixed step-size algorithm by comparing the results with those of PSCAD simulation considered as a real system. In order to overcome the limitations, the adaptive step size method for the PSM is proposed by modifying the general adaptive step size method. From the simulation using the proposed method, it is verified that the accuracy of the PSM is increased.

This paper presents the results of a study of a voltage management technology called parameter determination of voltage regulator (PDVR) implemented in a 22.9 kV distribution network. Korea Electric Power Corporation has developed this PDVR technology for increasing the hosting capacity without causing any voltage problems in LV (220/380 V) networks. PDVR calculates and provides the operation settings of voltage regulators such as on load tap changer, pole mounted automatic voltage regulator, and distributed generation (DG). Subsequently, these settings are applied to the voltage regulators, which further optimize the 22.9 kV network voltage without the control of the distribution management system (DMS). A study of the operations and performance of PDVR through the analysis of test results is presented in this paper.

A new operation method for an energy storage system (ESS) was proposed to reduce the electricity charges of a customer paying the wholesale price and participating in the industrial conservation initiative (ICI) in the Ontario electricity market of Canada. Electricity charges were overviewed and classified into four components: fixed cost, electricity usage cost, peak demand cost, and Ontario peak contribution cost (OPCC). Additionally, the online market data provided by the independent electricity system operator (IESO), which operates the Ontario electricity market, were reviewed. From the reviews, it was identified that (1) the portion of the OPCC in the electricity charges increased continuously, and (2) large errors can sometimes exist in the forecasted data given by the IESO. In order to reflect these, a new schedule-based operation method for the ESS was proposed in this paper. In the proposed method, the operation schedule for the ESS is determined by solving an optimization problem to minimize the electricity charges, where the OPCC is considered and the online market data provided by the IESO is used. The active power reference for the ESS is then calculated from the scheduled output for the current time interval. To reflect the most recent market data, the operation schedule and the active power reference for the ESS are iteratively determined for every five minutes. In addition, in order to cope with the prediction errors, methods to correct the forecasted data for the current time interval and secure the energy reserve are presented. The results obtained from the case study and actual operation at the Penetanguishene microgrid test bed in Ontario are presented to validate the proposed method.

Indirect load control (ILC) is a method by which the customer determines load reduction of electricity by using a price signal. One of the ILCs is a time-of-use (TOU) tariff, which is the most commonly used time-varying retail pricing. Under the TOU tariff, the customer can reduce the energy cost through an energy storage system (ESS). However, because this tariff is fixed for several months, the ESS operation does not truly reflect the wholesale market price, which could widely fluctuate. To overcome this limitation, this paper proposes an incentive pricing method in which the load-serving entity (LSE) gives the incentive pricing signal to the customers with ESSs. Because the ESS charging schedule is determined by the customer through ILC, a bilevel optimization problem that includes the customer optimization problem is utilized to determine the incentive pricing signal. Further, the bilevel optimization problem is reformulated into a one-level problem to be solved by an interior point method. In the proposed incentive scheme: (1) the social welfare increases and (2) the increased social welfare can be equitably divided between the LSE and the customer; and (3) the proposed incentive scheme leads the customer to voluntarily follow the pricing signal.

This paper proposes a vector-controlled distributed generator (DG) model for a power flow based on a three-phase current injection method (TCIM). In order to represent the DG models in the power flow, steady-state phase current output equations are formulated. Using these equations, the TCIM power flow formulation is modified to include the DG models. In the proposed power flow, a DG-connected bus is modeled as either a load bus (PQ bus) or a voltage-controlled bus (PV bus), depending on the control mode of the reactive power. However, unlike conventional bus models, the values of the DG-connected bus models are represented by three-phase quantities: three-phase active and reactive power output for a PQ bus, and three-phase active power and positive-sequence voltage for a PV bus. In addition, a method is proposed for representing the reactive power limit of a voltage-control-mode DG by using the q-axis current limit. Utilizing a modified IEEE 13-bus test system, the accuracy of the proposed method is verified by comparison to the power systems computer aided design (PSCAD) model. Furthermore, the effect of the number of DGs on the convergence rate is analyzed, using the IEEE 123-bus test system.