Protection of Power Systems with Distributed

Generation: State of the Art

Martin GeidlPower Systems Laboratory

Swiss Federal Institute of Technology (ETH) Zurichgeidl@eeh.ee.ethz.ch

20th July 2005

Abstract

The integration of distributed sources into existing networks brings up sev-eral technical, economical and regulatory questions. In terms of physicalintegration, protection is one of the major issues. Therefore new protec-tion schemes for both distributed generators (DG) and utility distributionnetworks have been developed in the recent years, but there are still openquestions.

This document is the result of a literature study and intends to givean overview of issues and current state concerning protection of DG. Thefirst part gives a basic introduction to distributed generation and powersystem protection. In section 2 protection issues concerning DG are outlined,then the current practice is described in section 3. In section 4 some newapproaches in this field are reported and finally section 5 concludes with anoutlook.

Contents

List of Acronyms 2

1 Introduction 31.1 Distributed Generation . . . . . . . . . . . . . . . . . . . . . . 31.2 Power System Protection . . . . . . . . . . . . . . . . . . . . 31.3 Generation and Interconnection Systems . . . . . . . . . . . . 5

1.3.1 Machines . . . . . . . . . . . . . . . . . . . . . . . . . 51.3.2 Transformers . . . . . . . . . . . . . . . . . . . . . . . 61.3.3 Power Electronic Interfaces . . . . . . . . . . . . . . . 61.3.4 Interconnection System View . . . . . . . . . . . . . . 7

2 Protection Issues with DG 72.1 Short Circuit Power and Fault Current Level . . . . . . . . . 82.2 Reduced Reach of Impedance Relays . . . . . . . . . . . . . . 102.3 Reverse Power Flow and Voltage Profile . . . . . . . . . . . . 102.4 Islanding and Auto Reclosure . . . . . . . . . . . . . . . . . . 122.5 Other Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

2.5.1 Ferroresonance . . . . . . . . . . . . . . . . . . . . . . 132.5.2 Grounding . . . . . . . . . . . . . . . . . . . . . . . . 13

3 Current Practice 143.1 Island Detection . . . . . . . . . . . . . . . . . . . . . . . . . 14

3.1.1 Passive Methods . . . . . . . . . . . . . . . . . . . . . 143.1.2 Active Methods . . . . . . . . . . . . . . . . . . . . . . 17

3.2 Interconnect vs. Generator Protection . . . . . . . . . . . . . 193.3 Examples of State-of-the-Art Relays . . . . . . . . . . . . . . 19

3.3.1 Integrated Generator Protection . . . . . . . . . . . . 213.3.2 Loss of Mains Relay . . . . . . . . . . . . . . . . . . . 213.3.3 Integrated Genset Control Device . . . . . . . . . . . . 223.3.4 General Electric Universal Interconnection Device . . 22

3.4 International Recommendations, Guidelines and Standards . 23

4 New Approaches 234.1 Adaptive Protection Systems . . . . . . . . . . . . . . . . . . 234.2 Synchronized Phasor Measurement . . . . . . . . . . . . . . . 254.3 Intelligent Systems . . . . . . . . . . . . . . . . . . . . . . . . 25

5 Conclusion and Future Work 26

References 27

1

List of Acronyms

AC Alternating CurrentAEPS Area Electric Power SystemAM Asynchronous MachineAPS Adaptive Protection SystemCHP Combined Heat and PowerDC Direct CurrentDER Distributed Energy RessourceDG Distributed, Decentralized, or Dispersed GenerationEG Embedded GenerationGPS Global Positioning SystemHV High VoltageIED Intelligent Electronic DeviceIM Induction MachineLOE Loss Of EarthLOG Loss Of GridLOM Loss Of MainsLV Low VoltageMV Medium VoltageNDZ Non-Detection ZonePCC Point of Common CouplingPFC Power Factor CorrectionPMU Phasor Measurement UnitPV PhotoVoltaicsROCOF Rate Of Change Of FrequencySCADA Supervisory Control And Data AcquisitionSM Synchronous MachineSPS Special Protection SchemesUI Universal InterconnectionVVS Voltage Vector Shift

2

1 Introduction

1.1 Distributed Generation

Distributed, dispersed, decentralized or embedded generation (DG, EG) arekeywords for an upcoming probable paradigm shift in electric power gener-ation.1 As mentioned in [1], there is no standing international definition forthese terms, but there are a number of legal definitions in several countries.A proposal for a definition of distributed generation is given in [4]. However,many distributed power sources have some characteristics in common:

Their rating is small compared to conventional power plants,

they are often privately owned,

they are not centrally dispatched,

they are connected to MV or LV distribution networks,

they do not contribute to frequency or voltage control,

and usually they were not considered when the local grid was planed.Hence, there are infrastructural needs as, for example, means of com-munication.

Two major reasons for an increased utilization of DG are liberalized mar-kets which are now opened for various kinds of participants, and the globaltrend of reducing greenhouse gas emissions, which leads to more renewable,CO2-neutral sources which are normally small-scaled. Further reasons arediscussed in [1] and others.

Besides a number of benefits, there are some technical, economical andregulatory issues with DG. In terms of market regulation, licensing, gov-ernment aid and privacy are typical concerns. Economical considerationsdisplay a possible cost increase not only for generation but also for trans-mission and distribution. Finally, there is the technical point of view, andprotection turned out to be one of the most problematical technical issuessince its malfunction could cause serious risk for people and components.

1.2 Power System Protection

Basic power system protection principles are outlined in standard literature[13, 14]. The primary purpose of power system protection is to ensure safeoperation of power systems, thus to care for the safety of people, personnel

1Surveys about DG are given in [1, 2, 3].

3

and equipment. Furthermore, the task is to minimize the impact of un-avoidable faults in the system.2 From an electrical point of view, dangeroussituations can occur from

overcurrents and

overvoltages.

For example, an asynchronous coupling of networks results in high currents.Earth faults can cause high touch voltages and therefore endanger people.The general problem is always voltage and/or current out of limit. Hence,the aim is to avoid overcurrents and overvoltages to guarantee secure oper-ation of power systems.

For the safety of the components it is also necessary to regard device-specific concerns, for example oil temperature in transformers, gas pressurein gas insulated components etc. These points are not directly related toelectrical values, but, as mentioned, they always come from or lead to unal-lowed high voltages or currents.

Another issue is mechanical stress. Whenever power is converted elec-tromechanically, one has to consider not only the electrical but also the me-chanical equipment. An example is mechanical resonance of steam turbinesdue to underfrequency.

Nowadays, electromechanical protection devices are replaced by micro-processor based relays with a number of integrated features. Currents andvoltages are suitably transformed and isolated from the line quantities byinstrument transformers and converted into digital form. These values areinputs for several algorithms which then reach tripping decisions. Furtherinformation about computer relaying can be found in [13, 14].

For the design and coordination of protective relays in a network, someoverall rules have become widely accepted:

Selectivity: A protection system should disconnect only the faulted part(or the smallest possible part containing the fault) of the system inorder to minimize fault consequences.

Redundancy: A protection system has to care for redundant function ofrelays in order to improve reliability. Redundant functionalities areplaned and referred to as backup protection. Moreover, redundancyis reached by combining different protection principles, for exampledistance and differential protection for transmission lines.

Grading: For the purpose of clear selectivity and redundancy, relay char-acteristics are graded. This measure helps to achieve high redundancywhereas selectivity is not disabled.

2Avoidable problems such as system instabilities are subjected to Special ProtectionSchemes (SPS) as reported in [15].

4

Security: The security of a relay protection system is the ability to rejectall power system events and transients that are not faults so thathealthy parts of the power system are not unnecessarily disconnected[16].

Dependability: The dependability of a relay protection system is the abil-ity to detect and disconnect all faults within the protected zone [16].

Different network topologies require different protection schemes. In thefollowing paragraphs some typical systems should be described shortly. Thesimplest network structure to protect are radial systems, therefore simple re-lays are used [13]. Normally, time-dependent, graded overcurrent protectionis installed regarding redundancy (backup protection). More sophisticatedrelays are used for the protection of rings and meshed grids. Impedancerelays trip due to a low voltage-current quotient. Since these relays allowto determine the position of the fault on the line, they are also called dis-tance relays. Detailed descriptions are given in [1, 13, 14]. A very commonprinciple for the protection of generators, transformers, busbars and lines isdifferential protection. The trigger criteria is, simply speaking, a certain dif-ference between input and output current. Furthermore, a number of othertechniques are used, also device-specific ones.

1.3 Generation and Interconnection Systems

Common distributed generators and network interfaces should be outlinedin the following paragraphs. Overviews are given in [1, 17, 18, 19, 20].

1.3.1 Machines

Synchronous Machines (SM) are widely used for larger water, steam andcombustion engine driven plants, for instance Combined Heat and Power(CHP) plants. By varying the excitation current, it is possible to controlthe reactive behavior of the SM, i.e. to regulate the voltage. The possibilityof voltage control is a major benefit and makes island operation possible.

Asynchronous or Induction Machines (AM, IM) are primarily used forwind and smaller hydro plants. Since these machines derive their excitationfrom the network, they always consume an inductive current and thereforebehave as reactive loads even if they are providing active power. Hence,voltage control and island operation is normally not possible with AM. Anadditional fact to consider is that these machines normally run with a lowpower factor. The fault behavior of AM is determined by a low positive andnegative sequence impedance. With AM in the network, the fault currentlevel3 is normally increased.

3The fault current level is defined in section 2.1.

5

In order to increase the power factor, AM are sometimes equipped withPower Factor Correction (PFC) [17, 21, 22]. So-called PFC-AM are able tocontinue operation if the main supply is lost, but voltage and frequency willnot be stable.

For modern wind power stations double-fed induction machines are used.The relation between the network frequency fn, the rotor current frequencyfr and the mechanical frequency of the shaft fm in such machines is

k2pifm + fr = fn (1)

where k is an integer constant due to the machine design. This equation ex-plains how the machine can operate with various mechanical speed whereasthe network frequency fn is constant: The rotor circuit has to be fed witha corresponding frequency fr. This method enables wind turbines to run ina wider range of speed and therefore to optimize efficiency.4

DC Machines are rarely used as generators because they need to beconnected to the AC system via an expensive inverter. Another disadvantageis that the brushes have to be serviced frequently.

1.3.2 Transformers

Whenever machines or inverters are connected to networks of different nom-inal voltage, transformers are needed. The high voltage winding of thetransformer is usually used to meet the grounding requirements of the utility.Delta-wye configurations are commonly installed for isolated generators. Interms of protection, the transformer connection is important since the zerosequence impedance depends very much on the winding type (delta/wye)and also on the earth connection. Reference [19] compares five commontransformer connections outlining their problems and benefits.

1.3.3 Power Electronic Interfaces

Whenever primary power is not transformed via a rotating AC machine,power electronic devices are used as a utility connection. Also wind powerstations are often connected via converters. In large wind parks a commonDC busbar collects the power and delivers it to the utility grid via onerectifier and one transformer [23].

Microturbines usually drive a synchronous machine at very high speed(due to efficiency). The high frequency has to be converted to the nominalutility frequency. Photovoltaic panels and fuel cells directly produce DCpower which has to be converted.

An advantage of power electronic converters is their controllability. Any-way, a converter has to be equipped with a controller that can be used to

4This method is also used for pump storage hydro stations because the most efficientspeed of Pelton turbines varies with the head.

6

achieve a number of functionalities. Voltage or reactive power control couldbe integrated in converters as an additional feature [20].

In terms of protection, it is a clear disadvantage of semiconductor de-vices that their valves are almost not overloadable, i.e. overload can notbe accepted for a longer time. Therefore converter controls are designedto prohibit high currents what leads to a lack of short circuit power whichis necessary to trip protection. In section 2.1 the fault level is discussed.This fault level may be low in networks with a large contingent of converter-connected power sources.

1.3.4 Interconnection System View

Reference [24] gives a review of DG interconnection systems and states sometrends and research needs. Also the commercial status of interconnectionequipment (list of manufacturers, cost and pricing, etc.) is outlined. In-terconnection systems are defined as the means by which the DER unitelectrically connects to the outside electrical power system and providesprotection, monitoring, control, metering and dispatch of the DER unit,where DER are Distributed Energy Resources [24]. Network interfaces aredescribed from a system point of view using functional schemes as shown infigure 1. Several typical schemes and configurations are outlined accordingto:

1. Does the system use an inverter?

2. Does the system have a parallel connection to the local grid?

3. Can the system export power to the local grid?

4. Is the system remotely dispatchable?

A test report of a Universal Interconnection (UI) device is given in [25].The device that was designed by General Electrics connects the DG withthe local load as well as with the grid. The UI device is further described insection 3.3.4.

2 Protection Issues with DG

The overall problem when integrating DG in existing networks is that distri-bution systems are planned as passive networks, carrying the power unidi-rectionally from the central generation (HV level) downstream to the loadsat MV/LV level. The protection system design in common MV and LV dis-tribution networks is determined by a passive paradigm, i.e. no generationis expected in the network [20].

With distributed sources, the networks get active and conventional pro-tection turns out to be unsuitable. The following sections will outline themost important issues.

7

conversionconditioning

localprotection

transfer switchparall. switchgear

DERmonitoringmetering

DER control dispatch andcontrol

Meter

interconnection system

local loads,distribution

DERPCC

AEPS

power flowinformation flow

Figure 1: Interconnection system functional scheme [24]; AEPS. . . Area Elec-tric Power System; DER. . . Distributed Energy Resource; PCC. . . Point ofCommon Coupling.

2.1 Short Circuit Power and Fault Current Level

The fault current level describes the effect of faults in terms of current orpower. It gives an indication of the short circuit current or (apparent) powerboost. In [1] the fault level in p.u. is defined as

fl = i =1

|zth|(2)

whereas i is the fault current related to the nominal current and zth isthe inner impedance of the Thevenin representation of the network in p.u.Examples for this value are given in [1], typical fault levels in distributionnetworks are in a range of 1015 p.u., where 1 p.u. corresponds to the ratedcurrent.

This is, phase-phase or phase-earth faults normaly result in an overcur-rent which is significantly higher than the operational or nominal current.5

This is a very basic precondition for the function of (instantaneous) overcur-rent protection. The fault current has to be distinguishable from the normaloperational current. To fulfill that, there has to be a powerful source pro-viding a high fault current until the relay triggers. This is not the case forall kinds of generation devices (see section 1.3). Especially power electronicconverters are often equipped with controllers that prevent high currents. If,for example, a remote part of a distribution network is equipped with largePV installations, it could happen that in case of a failure there is almost nosignificant rise of the phase current and the fault is therefore not detectedfrom the overcurrent protection system. The question arises, why one needsto care about a fault if there is no fault current. The answer is that dan-

5The amplitude of the fault current is dependent on the fault impedance, for phase-earth faults it is also highly dependent on the grounding.

8

PSfrag replacements

Idg

U

IfInw

L1 L2 L3

b1 b2 b3 b4

G

TR a

Figure 2: Short circuit at a. Current from transmission network Inw, currentfrom embedded generator Idg.

gerous touch voltages may occur even if the current is low. Furthermorepermanent faults may spread out and destroy more equipment.

With DG in the network, the fault impedance zth can also decreasedue to parallel circuits, therefore the fault level increases and there couldbe unexpected high fault currents in case of a failure. This situation putscomponents at risk since they were not designed to operate under that cir-cumstances.

For correct operation it is also important that the relay measures the realfault current which was expected and taken under consideration when therelay was configured. Figure 2 shows a distribution feeder with an embeddedgenerator that supplies part of the local loads. Assuming a short circuit atpoint a, the generator will also contribute to the total fault current

If = Inw + Idg (3)

but the relay R will only measure the current coming from the network infeedInw. This is, the relay detects only a part of the real fault current and maytherefore not trigger properly. As mentioned in [26, 27] there is an increasedrisk especially for high impedance faults that overcurrent protection withinverse time-current characteristic may not trigger in sufficient time.

One can find another influence of DG on fault currents when assuminga short circuit at the busbar b2. In this case, the fault current contributionfrom the generator passes the relay in reverse direction what could causeproblems if directional relays are used. DG can also affect the current di-rection during normal operation, this issue is explained in section 2.3.

Concluding the issues concerning short circuit faults it can be stated thatdispersed generation affects the

amplitude,

direction and

duration (indirectly)

9

of fault currents. The last point is a result of inverse time-current charac-teristics (or grading respectively).

2.2 Reduced Reach of Impedance Relays

The phenomena of reduced reach of distance relays due to embedded powerinfeed is mentioned in [26, 27, 29] and other references. In [14] this problemis considered for conventional power systems.

The reach of an impedance relay is the maximum fault distance thattriggers the relay in a certain impedance zone, or in a certain time due toits configuration. This maximum distance corresponds to a maximum faultimpedance or a minimum fault current that is detected.

Considering figure 2, one can calculate the voltage measured by the relayR in case of a short circuit at a6

Ur = InwZ23 + (Inw + Idg)Z3a (4)

where Z23 is the line impedance from bus b2 to bus b3 and Z3a is theimpedance between bus b3 and the fault location a. This voltage is increaseddue to the additional infeed at bus b3. Hence, the impedance measured bythe relay R

Zr =UrInw

= Z23 + Z3a +IdgInw

Z3a disturbance

(5)

is higher than the real fault impedance (as seen from R) what corresponds toan apparently increased fault distance. Consequently, the relay may triggerin higher grading time resp. in another distance zone.

For certain relay settings which were determined during planning studies,the fault has to be closer to the relay to operate it within the originallyintended distance zone. The active area of the relay is therefore shortened,its reach is reduced. Note that the apparent impedance varies with Idg/Inw.A possible solution to this problem is outlined in section 4.1.

2.3 Reverse Power Flow and Voltage Profile

Radial distribution networks are usually designed for unidirectional powerflow, from the infeed downstream to the loads. This assumption is reflectedin standard protection schemes with directional overcurrent relays. With agenerator on the distribution feeder, the load flow situation may change. Ifthe local production exceeds the local consumption, power flow changes itsdirection [30]. Reverse power flow is problematic if it is not considered inthe protection system design. Moreover, reverse power flow implies a reversevoltage gradient along a radial feeder.

6Load currents are neglected for this consideration.

10

PSfrag replacements

Idg

U

Ux

x

x

I23 I34

Inw

Il1 Il2 Il3

b1 b2 b3 b4

G

T

Figure 3: Voltage profile and gradient on a distribution feeder with andwithout contribution of generator G. Solid line: Idg = 0, downstream powerflow; dahsed line: Idg > Il2 + Il3, reverse power flow between b2 and b3.

Dispersed generation always affects the voltage profile along a distri-bution line. Beside power quality issues, this could cause a violation ofvoltage limits and cause additional voltage stress for the equipment. Thevoltage increase/drop U due to power in-/outfeed can be approximatedwith [1, 29, 31]

U PdgRth +QdgXth

Un(6)

where Un is the nominal voltage of the system, Rth + j Xth is the lineimpedance (Thevenin equivalent respectively) and Pdg + j Qdg is the powerinfeed of the DG.

An analytical method of calculating the influence of DG on the voltageprofile of distribution feeders is presented in [32, 33, 34].

Figure 3 pictures the voltage gradient along a distribution feeder withand without embedded generation. The power flow direction corresponds tothe sign of the voltage gradient. In this situation the power flow directionbetween bus b2 and b3 is changed due to the infeed at bus b3.

Especially in highly loaded or weak networks dispersed generation canalso influence the voltage profile in a positive way and turn into a powerquality benefit.

Reference [35] describes another issue concerning the voltage profile ondistribution feeders. Usually tap-changing transformers are used for thevoltage regulation in distribution networks which change the taps, i.e. their

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turns ratio, due to the load current. If the DG is located near the networkinfeed (e.g. at bus b2 in figure 3), it influences tap-changing because the DGinfeed decreases the resulting load for the transformer. Hence tap-changingcharacteristics will be shifted, the infeed voltage will not be regulated cor-rectly.

2.4 Islanding and Auto Reclosure

Critical situations can occur if a part of the utility network is islanded andan integrated DG unit is connected. This situation is commonly referredto as Loss Of Mains (LOM) or Loss Of Grid (LOG). When LOM occurs,neither the voltage nor the frequency are controlled by the utility supply.

Normally, islanding is the consequence of a fault in the network. Ifan embedded generator continues its operation after the utility supply wasdisconnected, faults may not clear since the arc is still charged.

Small embedded generators (or grid interfaces respectively) are oftennot equipped with voltage control, therefore the voltage magnitude of anislanded network is not kept between desired limits, and undefined voltagemagnitudes may occur during island operation.

Another result of missing control might be frequency instability. Sincereal systems are never balanced exactly, the frequency will change due toactive power unbalance. Uncontrolled frequency represents a high risk formachines and drives.

Since arc faults normally clear after a short interruption of the supply,automatic (instantaneous) reclosure is a common relay feature. With a con-tinuously operating generator in the network, two problems may arise whenthe utility network is automatically reconnected after a short interruption:

The fault may not have cleared since the arc was fed from the DGunit, therefore instantaneous reclosure may not succeed.

In the islanded part of the grid, the frequency may have changed dueto active power unbalance.7 Reclosing the switch would couple twoasynchronously operating systems.

Extended dead time (ti in figure 4) has to be regarded between theseparation of the DG unit and the reconnection of the utility supply tomake fault clearing possible. Common off-time settings of auto reclosurerelays are between 100 ms and 1000 ms. With DG in the network, the totaloff-time has to be prolonged. Reference [27] recommends a reclosure intervalof 1 s or more for distribution feeders with embedded generators.

A linear approximation for the frequency change during island operationis given in [1, 36]. The rate of change of frequency is expressed as a function

7Even if there is active power control, the island will not run synchronously with theutility system.

12

of the active power unbalance

P =

Pdg

Pl (7)

the inertia constant of the machine H, the machines rated power Sn andthe frequency before LOM fs:

df

dt=

Pfs2SnH

(8)

It is straight forward to calculate the frequency change

f =Pfs2SnH

ti (9)

This approach does only consider the frequency change due to islanding, thefault is not regarded.

Figure 4 shows an example for an auto reclosure procedure where anembedded generator is not disconnecting although it is islanded with thelocal grid. Here it is assumed that there is a lack of active power afterislanding, i.e.

Pdg