1

Modeling and Analysis of Synchronous Generator Based Distributed Energy Resources for Dynamic Impact Studies

Tim Chang, Member IEEE, and Farid Katiraei, Senior Member IEEE

IEEE Working Group on Distributed Resources - Modeling and Analysis

Keywords: Conventional DER, Modeling, Benchmark Distribution Network, Interconnection, Impact Study

Abstract

Although power electronic based generation sources such as solar photovoltaic plants and wind farms are gaining enormous popularity, conventional distributed energy resources (DERs) are commonly used and integrated onto distribution systems. The main reasons are the improving the economy of generation, controllability and maturity of the technology that simplifies operation and maintenance of the plant. Contrary to common belief, recent technological enhancements have brought about many engine driven generation types which are classified as clean (green) sources. This paper deals with the topic of modeling and benchmarking conventional synchronous generator based DERs for application in distribution systems. The DER model incorporates some new aspects of generation controls such as voltage regulation and reactive power compensation that are being asked for by some utilities to help accommodate integration onto existing distribution feeders while minimizing adverse effects. The introduced DER model is applied to and studied on a benchmark distribution network to demonstrate typical applications and impact investigations.

1. INTRODUCTION Increasing numbers and scale of Distributed Energy Resources (DERs) on distribution networks have changed the face of medium and low voltage power systems. Many utilities these days require dynamic (quasi steady-state) studies in addition to steady-state (power flow) types of impact studies prior to approving interconnection plans due to potential voltage and power quality issues and/or possibility of interactions with other DER units and/or commonly used automatic voltage regulating devices on the same feeder. New control capabilities and technological changes to make the generation units cleaner and more cost-

F. Katiraei (fkatiraei@quanta-technology.com) and T. Chang (tchang@quanta-technology.com) are with Quanta Technology-Canada.

effective also add to the importance of developing transient/dynamic models for impact studies.

One of the major challenges for distribution utility engineers nowadays is to obtain representative models and parameters of DERs to study the impact on the grid and assess the mitigation effects. To address this need, several IEEE working group and task forces have initiated the work on introducing DER models and documenting example impact study methodologies. Although the major effort is shifted toward investigation of power-electronic based DERs such as PV plants and wind farms, some modeling and operation analysis aspects of rotating machine based DERs remain debatable. This paper introduces modeling and analysis of a synchronous generator based DER by defining the main building blocks and typical case studies as part of system impact analysis. Two operating modes of grid connected and islanding formation/operations are discussed and simulated to show future advanced DER applications.

2. CONVENTIONAL DER TYPE AND MODEL Rotational machines driven by a reciprocating engine or turbine are typically called conventional generation sources. Figure 1 shows a single-shaft gen-set comprised of a prime mover and a generator. The prime mover is a reciprocating engine that converts the chemical energy of the fuel to the kinetic energy of the rotating shaft to drive a rotating electric machine. Normally, a synchronous machine is used as the generation source to convert the mechanical energy to electrical energy based on the interaction of two electromagnetic fields. Some legacy gen-set technologies have utilized direct current (DC) machines to serve specific load types; however, this structure is presently uncommon for many protection, safety and performance reasons. The use of induction machines as the electric conversion medium is typically unpractical for stand-alone operation, due simple to the requirement of an additional driving source for start-up as well as the need for a reactive power supply source during normal generation period.

978-1-4577-1002-5/11/$26.00 ©2011 IEEE

2

GenPrime Mover

Figure 1 - A single-shaft gen-set

2.1. Control and protection Both the reciprocating engine and the synchronous generator are equipped with several controllers and protection devices to perform the various tasks of engine start-up, generator voltage/speed adjustment, frequency stabilization, and/or automatic synchronization with a live mini-grid. In addition, a supervisory control unit is normally used to adjust real/reactive power generation of the gen-set for sound and proper operation in parallel with other units and during cycling period for load transfer from one unit to another. An overall block diagram of the control units and interconnection signals for a three-phase gen-set is shown in Figure 2.

+ fd

Gen. Con. Unit

3PH

Synchronous Gen.

DieselEngine AC

FieldE

ControlSynchronization

Protection

Governor Control Voltage

Regulator

Fuel

- CB

sVsI

gVgI

Engine GeneratorSupervisory Control

refV

refP

outP

outV

Genset

Figure 2 - Overall diagram of a diesel gen-set with governor and excitation systems and supervisory

controls

2.2. Frequency and speed control The principal objective of speed-governor control is to respond to load variations and ultimately adjust the power frequency of the generator. Any deviation in the system frequency and the generator speed is determined by interactions of the electrical torque (TL), due to the load demand, and the mechanical torque of the generator prime mover (Tm). The aggregate effect of the gen-set inertia and load inertia also determines the rate of change of the frequency.

Two types of speed control are normally used on conventional DERs: a) speed-droop control or power

sharing method, and b) fixed frequency or isochronous control [1]. In the speed-droop control, a DER does not attempt to set the system frequency and only delivers power at a given power frequency. However, the base power output of the unit can be specified through the real power set point and adjusted using a power dispatch scenario. As a result, the speed-droop control is typically used during the grid-connected operation or on grid following units of an island system.

The fixed frequency speed control combines the effect of speed-droop and frequency recover to set the power frequency at which real power output exchange with the system is achieved. This mode is typically applied for single DER island and/or applied to the master DER unit of a multiple DERs island.

2.3. Voltage and reactive power control A synchronous generator requires an excitation system to power the field winding and regulate the terminal voltage. The excitation system consists of a DC voltage supply source which is controlled by an Automatic Voltage Regulator (AVR) to adjust the generator field voltage and/or the field current according to the variations in the terminal voltage to achieve the desired generator internal voltage.

In general, two main excitation system structures have been introduced by generator manufacturers: a) a self-excitation system, and b) a separate excitation system. In both excitation types, the AVR control utilizes a voltage reference controller or a reactive power compensation (or power factor) controller to generate a voltage reference for the excitation system.

The modeled DER is shown in Figure 3. For the studies, the DER model is equipped with over and under voltage protection, as well as over and under frequency protection, as specified by IEEE 1547 [2].

Speed-droop Control (Grid-Connected)

Isochronous Control(Islanded)

Governor

Turbine

Q Controller

Exciter

(Grid-Connected)

(Islanded)

CB

SynchronizationControl

Figure 3 - Modeled DER

3

3. BENCHMARK SYSTEM A 12.47 kV distribution network benchmark introduced by CIGRE, shown in Figure 4, is used to study typical impact scenarios normally requested by utilities to investigate possible adverse impact on feeders [3]. Some of the cases are: effect of adding DER onto feeders, DER and system response to faults, and islanding subsequent to a fault or accidental switching, separating part of the system from the main grid. The system parameters can be found in [3].

Figure 4 – Power flow with no DER

3.1. DER operation in parallel with the grid Most DER installations are intended for operation in the grid connected mode only. The control mode of DER is typically referred to as constant real and reactive power. The real power set point is determined based on available energy resources and generation schedule, for instance, peak time generation. The reactive power set point is generally selected to provide unity power factor at the point of connection to the main grid.

A synchronous generator based DER plant requires means of synchronization and paralleling with the grid. As a dispatchable DER, the power ramp up and ramp down slope is settable and can be adjusted by DER owner as required. Example studies of a DER synchronization process and parallel operation with the is described in the following sections of the paper.

3.2. Fault, system switching and islanding With the advent of distribution automation and remote automated switching to re-configure feeders upon faults and

loss of main grid, it is beneficial to utilize DERs to supply loads in an island fashion until the main grid or connection to an alternative substation is restored. Accidental switching in the system may also happen that can potentially affect quality of supply.

Under these circumstances, intentional islanding is utilized as a new practice to help enhance customer-based supply reliability and reduce DER down time [4].

4. IMPACT CASE STUDIES In this study, the benchmark system and DER are modeled in PSCAD/EMTDC. The generator is a 4.7MVA, 4.16kV unit connected to Bus 3 in Figure 5, with parameters extracted from [5]. The DER can operate in grid-connected or islanded mode. In grid-connected mode, the governor functions in fixed-droop mode, shifting to fixed-frequency (isochronous) mode when operating as an island.

Three scenarios are studied: a) the DER behavior during interconnection and power ramp up, b) the system and DER response to a downstream fault from the DER, and c) the system and DER response to islanding due to an upstream fault leading to disconnection from the main grid.

4.1. DER Connection to System The DER is connected to Bus 3 of the benchmark system through an interconnection transformer with high side delta configuration (Figure 5). Synchronization is performed based on 3% voltage difference and 10° phase angle difference for all three phases, as specified by IEEE 1547 [2]. Upon synchronization (at about 1.2 seconds, shown in Figure 6), the real power setpoint of the DER was steadily increased from zero to 1.0pu over a 10 second period. The reactive power setpoint remained at zero to achieve unity power factor operation. The voltages of Bus 2, Bus 3, Bus 4, and Bus 5, real and reactive power flow through the substation transformer, generator output, and generator speed are shown in Figure 6.

The voltages at the indicated buses show a small transient as the DER is connected to the system. The real power through the substation transformer decreases by 1pu (defined with respect to the generator’s MVA rating), corresponding with the time the generator real power output increases. The reactive power flow remains effectively constant.

The generator real power output shows some oscillation as it is connected to the system, settling to a smooth and steady ramp to 1pu. The reactive power output shows a transient upon connection, and settles to a near-zero value. The generator speed shows a damped oscillation and returns to 60Hz.

4

Figure 5 – Power flow with DER operating at 1pu output

Figure 6 – System and generator response to DER synchronization and power ramp-up

4.2. Fault with DER in System With the DER connected to the system, a bolted fault is applied on Bus 5 at t = 1 second, as shown in Figure 7.

Figure 7 - Fault with DER connected to system

The system and generator response to a single-line-to-ground (SLG) fault is shown in Figure 8. The voltage at Bus 5 drops to zero, as the fault phase is the same as the measured phase. The other three buses are upstream, and also show a significant (larger than 20%) voltage drop. The generator aims to maintain its real power output and frequency, but is disconnected by undervoltage protection about one second after fault occurrence. It should be noted that the frequency stays almost constant through the SLG fault, and the generator only trips on the undervoltage protection.

The system and generator response to a three-phase (TPH) fault is shown in Figure 9. Similar to the SLG case, the voltages at all buses show a large drop. The generator is disconnected by undervoltage protection in less than half a second – less than half the time of the SLG case.

5

Figure 8 - SLG fault with DER connected

Figure 9 - TPH fault with DER connected

4.3. Islanding in Response to Fault An island of under 4MW load is defined downstream of the circuit breaker CB. The island was formed as follows: the generator real power output was set to 0.9pu and a fault was applied on Bus 1, upstream of the island. In response, circuit breaker CB opened 5 cycles after fault occurrence. A communication delay of 4 cycles was assumed prior to changing the turbine governor control mode from fixed-droop to fixed-frequency (isochronous) mode. In addition, the overfrequency protection for islanding condition was adjusted to one second for 61Hz (from the 0.16s for grid-connected mode). The island and fault location are shown in Figure 10.

Figure 10 – Island formation after upstream fault and BKR opening

The system and generator response to a SLG fault followed by islanding is shown in Figure 11. Upon fault occurrence, the voltages at Bus 2 drops by 80%, while the voltages at Bus 3, Bus 4, and Bus 5 drop by 50%. Upon islanding, the voltage climbs to about 95% of the pre-fault value. The real power flow through the generator drops significantly following islanding, as it is supplying a much smaller load. The generator output is able to stabilize without tripping the frequency or voltage protections.

The system and generator response to a TPH fault followed by islanding is shown in Figure 9. As can be seen in Figure 9, the speed variation of the generator is much larger than in the SLG case. Due to the lengthened tolerance time for overfrequency, the machine is able to stabilize its output

6

without tripping the protection, and ride through the transient.

Figure 11 - Islanding in response to SLG fault

5. CONCLUSION The paper outlined modeling and benchmarking of rotating machine based DER for the purpose of grid impact studies. An electromagnetic transient model of a synchronous generator with prime mover of a gas turbine was developed and utilized as part of the CIGRE distribution system benchmark to perform a series of selected impact case studies, as examples. The proposed DER was equipped with an advanced governor and speed control system as well as automatic voltage regulation and excitation control to operate in either grid-connected or islanded mode.

It was shown that, the DER’s grid connected operation has minor impact on the voltage profile and system operation, although the DER changed the upstream power flow direction. In response to upstream faults and isolation of part of the system, including DER, from the main grid, it was also shown that a properly sized DER (with respect to island load) equipped with suitable control capabilities (i.e. voltage and frequency regulation) can smoothly ride through islanding transients and sustain the island. However, changes in DER’s intertie protection settings may be required to tolerate wider ranges of voltage and frequency excursions during transition period.

Figure 12 - Islanding in response to TPH fault

6. REFERENCES [1] F. Katiraei, “Computer Simulation Modeling and Analysis of the Dynamic behavior of a Reciprocating Engine based Distributed Generation unit during Islanding Transition”, CANMET Energy Technology Centre (CETC)-Varennes, QC, Canada. Report # 2007-187 (TR), Natural Resources Canada, August 2007, [available online]: http://canmetenergy-canmetenergie.nrcan-rncan.gc.ca/fichier.php/codectec/En/2007-187/2007-187_TR_411-DGUTIL_Study_AD_AI_Katiraei_e.pdf

[2] IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems, IEEE Standards Coordinating Committee 21 Std. IEEE Std. 1547-2003, 2003.

[3] K. Strunz, “Developing Benchmark Models for Studying the Integration of Distributed Energy Resources,” IEEE Power Engineering Society General Meeting, 2006.

[4] F. Katiraei, C. Abbey, S. Tang, M. Gauthier, “Planned Islanding – Utility Perspective”, in the proceeding of the IEEE PES GM 2008, Pittsburgh-USA, July 20-24, 2008.

[5] T. Chang, “Impact of Distributed Generation on Distribution Feeder Protection,” MASc dissertation, Dept. of Electrical and Computer Engineering, University of Toronto, 2010.