electrical protection for the grid-interconnection of photovoltaic-distributed generation
TRANSCRIPT
R
Eg
Ja
b
a
ARR2AA
KPIETGS
C
0d
Electric Power Systems Research 89 (2012) 85– 99
Contents lists available at SciVerse ScienceDirect
Electric Power Systems Research
jou rn al h om epage: www.elsev ier .com/ locate /epsr
eview
lectrical protection for the grid-interconnection of photovoltaic-distributedeneration
.C. Hernándeza,∗, J. De la Cruzb, B. Ogayara
Grupo de Investigación IDEA, EPS, University of Jaén, Campus de las Lagunillas s/n, Edificio A3, Jaén 23071, SpainEndesa Distribución Eléctrica S.L.U., Escudo del Carmen 31, 18009 Granada, Spain
r t i c l e i n f o
rticle history:eceived 15 August 2011eceived in revised form3 December 2011ccepted 2 March 2012vailable online 29 March 2012
a b s t r a c t
Distribution network and transmission system operators (DNOs and TSOs) who are obliged to con-nect photovoltaic-distributed generation (PV-DG) to their respective distribution networks or powersystems need a coherent set of electrical protection requirements for safe operation. Nonetheless, thegrowing importance of PV-DG has prompted continuous reformulations of these requirements. Withinthis context, this paper gives a detailed overview of electrical protection requirements for PV-DG grid-interconnection from the LV to the HV-EHV level. For this purpose, we have analysed national and regional
eywords:hotovoltaic-distributed generationnterconnectionlectrical protectionechnical requirementsrid codes
codes that have been proposed and enacted in many countries where high PV penetration levels havebeen achieved or are expected to be achieved in the future. This survey focuses on protection relays andtheir settings. Also included are the ancillary services to be provided by PV-DG, specifically at the HV-EHVlevel.
© 2012 Elsevier B.V. All rights reserved.
tandards
ontents
1. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 862. Grid-interconnection schemes for PV-DG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 863. Interconnection system functions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 864. Interconnection versus generator protection. Distribution network protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 885. Electrical protection for PV-DG grid-interconnection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89
5.1. Detection of faults in the area EPS and the isolation of the PV-DG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 895.2. Islanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 905.3. Coordination between the DNO’s reclosing practices and PV-DG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 905.4. PV-DG reconnection to the utility EPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91
6. Synchronization of PV-DG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 917. PV-DG grid-interconnection at the LV level . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91
7.1. Secondary distribution network protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 917.2. Electrical protection for PV-DG grid-interconnection at the LV level . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
8. PV-DG grid-interconnection at the MV level . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 928.1. Distribution primary network protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 928.2. Electrical protection for PV-DG grid-interconnection at the MV level . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
9. PV-DG grid-interconnection at the HV-EHV level . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 939.1. Ancillary services to be provided by PV-DG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
9.1.1. Dynamic grid support . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9.1.2. Active power control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9.1.3. Reactive power control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
∗ Corresponding author. Tel.: +34 953 21 24 63; fax: +34 953 21 24 78.E-mail address: [email protected] (J.C. Hernández).
378-7796/$ – see front matter © 2012 Elsevier B.V. All rights reserved.oi:10.1016/j.epsr.2012.03.002
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95
86 J.C. Hernández et al. / Electric Power Systems Research 89 (2012) 85– 99
9.2. Transmission system protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 969.3. Electrical protection for PV-DG grid interconnection at the HV-EHV LV level . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
10. Centralized protection and control system for PV-DG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9711. Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
Acknowledgements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
1
wutictIoemoa
weeDuncuoprmtn
pctl[pagP
rPctdsAsiatpLmtd
. Introduction
A PV-DG interconnection system has different functions [1],hich include synchronization, metering and monitoring, PV-DGnit control, electrical protection, etc. The interconnection sys-em effectively fulfils all the above functions when appropriatenterconnection requirements are defined [1]. These requirementsan be categorized as follows: (i) general requirements; (ii) elec-rical protection requirements; (iii) power quality requirements.n regards to electrical protection for interconnection, this typef protection allows PV-DG to safely operate in parallel with thelectric power system (EPS) and is often viewed as the singleost important technical requirement affecting the development
f most PV-DG projects. Nonetheless, power quality requirementsre also an important issue in PV-DG projects [2].
Until recently, PV-DG units connected to distribution networksere installations of reduced size and with low penetration lev-
ls. At these voltage levels (LV, MV), each DNO developed his ownlectrical protection requirements for the grid-interconnection ofG [3–8] (10 MW output power or less). Very rarely were any reg-lations specifically established for PV-DG [9] since there was littleeed for such installations to meet a strictly defined set of inter-onnection specifications. National codes or standards were alsosed to regulate this type of grid-interconnection (e.g. DG [1,10–18]r PV-DG [19–25]). Nevertheless, the analysis of various electricalrotection requirements for DG and PV-DG grid-interconnectioneflects that they can be quite heterogeneous and often havearked differences. Worse yet, when DG specifications are applied
o PV-DG, many inconsistencies become evident, such as the sig-ificant technological differences between each DG class.
In recent years, the rapid development of PV technology and PVenetration has resulted in successive reformulations of the inter-onnection protection requirements, with a view to adapting themo larger PV-DG units [25]. Specifications have even been estab-ished for PV-DG at the subtransmission and transmission level26–29]. Transmission-level requirements include both electricalrotection requirements and requirements for the provision ofncillary services, i.e. active/reactive power control and dynamicrid support to maintain the grid stability with large amounts ofV-DG.
Within the context of interconnection protection, there is a wideange of literature on electrical protection requirements for singleV inverters, e.g. islanding [30–35] and fault-ride through (FRT)apability [36–38]. However, very little attention has been paid tohe conflicts stemming from the significant presence of PV-DG inistribution networks and their effect on existing protection mea-ures [30,39–43], which have mainly been devised for DG [44,45].lthough there are many publications that discuss these issues,olutions have rarely been proposed. Therefore, instead of focus-ng on the conflicts between PV-DG interconnection protectionnd distribution network protection or transmission system pro-ection, this paper highlights the need for a unified set of electricalrotection requirements for PV-DG grid-interconnection from the
V to the HV-EHV level, which are compatible with the previouslyentioned conflicts. It also underlines the importance of selectinghe proper electrical protection requirements, which would varyepending on the voltage level. Although there have been efforts
to develop guidelines [25] for PV-DG interconnection protection,there is still no generally accepted approach.
This paper begins by explaining the grid-interconnectionschemes used for PV-DG, as well as the differences betweeninterconnection protection, generator protection, and distributionnetwork protection. This is followed by an in-depth descriptionof general electrical protection requirements for PV-DG grid-interconnection. Finally, an in-depth review of current guidelines orcodes regarding previous requirements is provided with a view todefining a realistic application of requirements from the LV to theHV-EHV level. This survey focuses on protection relays and theirsettings. Also included are the ancillary services to be provided byPV-DG, specifically at the HV-EHV level.
2. Grid-interconnection schemes for PV-DG
Regarding protection requirements, PV-DG can be classified intwo categories [19]: (i) a PV farm (0.5–40 MW) consisting of numer-ous PV inverters (0.5 kW to 0.5 MW), connected and distributedover an area of up to 0.5–2 km2 with a single point of commoncoupling (PCC) to a primary distribution network (Fig. 2) or sub-transmission/transmission system (Fig. 3); (ii) one or various PVinverters directly connected to the secondary distribution network(Fig. 1).
PV-DG interconnection to the EPS is possible at the LV, MV,and HV-EHV level, depending on the output power (Table 1). Mostsmall PV-DGs are connected to LV networks (Fig. 1, Schemes 1and 2). Larger PV-DGs are connected to MV and HV-EHV networks(Figs. 2 and 3, Schemes 3–6). Sometimes, medium-size PV farms areconnected to a close HV-EHV network when distribution primarynetworks are far away.
A small PV farm (Fig. 2, Scheme 3) is an installation composed ofa cluster of PV inverters with its own LV/MV transformer/s (here-after a MV PV-DG unit), and is connected to a primary distributionnetwork.
A medium-size PV farm (Fig. 2, Scheme 4) is an installation com-posed of various MV PV-DG units, and is connected to a PV collectorfeeder to reduce the high losses in LV lines caused by the distancebetween the PV inverters and the PCC. This feeder may be of dif-ferent types: radial, bifurcated radial, feeder-subfeeder, or loopedfeeder. Each feeder type has its advantages and disadvantages.
A medium-large PV farm (Fig. 2, Scheme 5), composed of vari-ous MV PV-DG unit clusters, is directly connected to the main MVbusbar.
A large PV farm (Fig. 3, Scheme 6), composed of several MV PV-DG unit clusters, requires a separate primary substation to injectthe energy produced at a point where the electric transmission gridis strong enough to absorb it.
3. Interconnection system functions
The PV-DG interconnection system is defined as the meansby which PV-DG is electrically connected to the area EPS. The
functions that may be included in the interconnection systemare [1]: synchronization, power source transfer, metering andmonitoring, PV-DG unit control (e.g. functions that affect theon/off operations, and the voltage, frequency, output power of
J.C. Hernández et al. / Electric Power Systems Research 89 (2012) 85– 99 87
Table 1General rules for selecting the voltage level/network type for the PCC according to the rated PV-DG power.
Voltage level/type of network orsystem
Type of PV-DG Maximum DG capacity exportedthrough the PCC
Transmittable power
LV/distribution secondary network Small and medium PV generators 400 V: 100–500 kW [3,5,12,19,94]<50% LV feeder power [3,5,12]
up to ≈300 kW
MV/distribution primary network(MV ≤ 34.5 kV)
Small, medium and medium-large PVfarms
10 kV: 2–5 MVA [3,94]15–20 kV: 5 MVA [1,3,17]25 kV: 8.5 MVA [1]30–34.5 kV: 8–10 MVA [1,3,94]<50% MV feeder/transformer power[3,12]
up to ≈4–16 MVA
HV/subtransmission network (HVsystem or at transformer substationto HV system (45 kV ≤ HV ≤ 132 kV)
Large PV farms 66 kV: 15 MVA [3,5]63–90 kV: 100 MVA [79]132 kV: 40 [3] 50 [76] 260 [78] MVA
up to ≈10–40 MVA
te
D
EHV/transmission system(EHV ≥ 220 kV)
Large PV farms
he PV-DG unit), dispatch/communication of the PV-DG unit, and
lectrical protection (Fig. 3).Technical requirements and specifications pertaining to the PV-G interconnection system can be categorized in three groups [1]:
Fig. 1. Grid-interconnection schemes for PV-DG at the LV le
220 kV: 250 MW [79]; >40 MW [3]220, 400 kV: <5% grid short-circuitduty [76]
(i) general requirements; (ii) power quality requirements; and (iii)
electrical protection requirements. General requirements are thoserelated to synchronization, monitoring, earthing, and voltage reg-ulation. Power quality requirements are those related to the dc andvel (relay numbers are according to IEEE C37.2 [46]).
88 J.C. Hernández et al. / Electric Power Systems Research 89 (2012) 85– 99
chem
htoac
Fig. 2. Grid-interconnection s
armonic injection of the PV-DG unit and the flicker induced by
his unit. Power quality requirements for the grid-interconnectionf PV-DG are described in [2]. Electrical protection requirementsre those related to the PV-DG response in abnormal or islandingonditions, and are the focus of the review in this paper.Fig. 3. Grid-interconnection scheme for PV-DG at the HV-EHV level.
es for PV-DG at the MV level.
4. Interconnection versus generator protection.Distribution network protection
Interconnection protection provides the electrical protectionthat allows PV-DG to operate safely in parallel with the utility EPS.Its function is threefold: (i) loss of mains (LOM) detection [1]; (ii)protection of the utility EPS from damage caused by the fault cur-rent supplied by the PV-DG for utility EPS faults; (iii) protection ofthe utility EPS, especially in case of automatic reclosing. Therefore,interconnection protection must be activated for short circuits,overloads, low/high voltage, and frequency. It must also preventout-of-phase reclosing and the energization of a dead supply lineby the PV-DG.
The interconnection protection arrangement and the associ-ated settings vary widely, depending on factors such as DG typeand size, PCC to the area EPS (voltage level), interconnectiontransformer configuration, and the network protection scheme.Generally speaking, power level is possibly more important thanthe DG type [1].
Interconnection protection requirements for DG or particularlyfor small medium PV-DG are established by DNOs (e.g. DG [3–8] orPV-DG [9]), national codes and standards (e.g. DG [1,10,12–17] orPV-DG [19–25]). Larger generators (in the 5–20 MVA range) employinterconnection protection requirements that are integrated intothe utility’s transmission system protection (e.g. PV-DG [26–29] orDG [47–53]).
Interconnection protection requirements should be met at thePCC even though the devices used for this purpose can sometimes
be located elsewhere [1,20]. For example, in PV inverters, these pro-tective functions are often built into the control software/hardware.Most DNOs, however, require protective devices to be located at thePCC (Figs. 1–3).
J.C. Hernández et al. / Electric Power Systems Research 89 (2012) 85– 99 89
Table 2PV-DG response to abnormal voltage and frequency at the LV, MV, and HV-EHV level.
PoDDgp
a
5
pDrfEt
5P
ttmotiaotrpto
Generator protection is installed at the generator-side of theCC (Fig. 1) and protects the PV-DG from internal faults, abnormalperating conditions (e.g. unbalanced currents), and damage to PV-G from the utility EPS if reclosing coordination is not achieved.NOs leave the responsibility to the PV-DG owners to select theenerator protection [54] that they consider most appropriate torotect their assets.
Distribution network protection may be necessary for compli-nce with other codes and standards.
. Electrical protection for PV-DG grid-interconnection
Electrical protection requirements are primarily intended torotect the area EPS so that its equipment is not damaged by PV-G. They also protect utility workers from exposure to unnecessary
isks and hazards [1]. These requirements primarily focus on theollowing: (i) PV-DG performance when faults occur in the areaPS; (ii) coordination between the DNO’s reclosing practices andhe PV-DG; (iii) PV-DG reconnection to the area EPS.
.1. Detection of faults in the area EPS and the isolation of theV-DG
The PV-DG interconnection system must detect and respondo faults or potentially hazardous abnormal conditions (e.g. unin-entional islanding) in the area EPS. This system mainly has two
ethods of detecting previous conditions. Both methods are basedn the fact that a fault reduces or unbalances the apparent sys-em impedance. In the first method, the reduction in impedances indicated by an overcurrent at the PCC (local detection) ornywhere else (remote detection). The interconnection protectionbjective for this method is fault backfeed detection. However, inhe second method, the reduction in impedance is indicated by a
eduction in voltage at the PCC. In this case, the interconnectionrotection objective is LOM detection. Other options are methodshat combine voltage-restrained overcurrent or voltage-controlledvercurrent (e.g. overcurrent-time relay, voltage controlled –51 V–)or other methods based on similar combinations (e.g. distance relay–21– or directional overcurrent relay –67–).
Detection methods of area EPS faults using overcurrent princi-ples, however, are not effective for PV-DG because of its inabilityto produce or sustain significant fault-current contribution duringarea EPS fault conditions [25,30,31,36,39,42,45,55]. Only self-commutated inverters can supply a constant fault current for anextended time, but its level (1.2–1.5 times the rated current) isinsufficient to trip the overcurrent protection. Therefore, the pri-mary means of detecting area EPS faults, or abnormal conditions inthe case of PV-DG must be based on passive LOM detection meth-ods (voltage-based fault detection, i.e. under/overvoltage relay–27/59– and under/overfrequency relay –81U/O–). Consequently,most national codes and standards for PV-DG [9,19,20,22,24,25,29]state that when a fault or subsequent unintentional islanding con-dition occurs on the grid and causes excursions in the monitoredPV-DG parameters beyond acceptable limits (Table 2), the intercon-nection system must cease to energize the grid. This requirement isalso applicable to GD (Table 3) [1–7,10,12–17,47,50]. However, inthe case of faults that do not cause significant variation in the volt-age or frequency measured at the PCC, no isolation of the PV-DG isrequired.
The main objective of rapid undervoltage protection is todetect severe faults, whereas the main objective of rapidunder/overvoltage and frequency protection is to detect uninten-tional islanding. The purpose of the delayed protection is to ridethrough short-term disturbances so that unnecessary PV-DG dis-connection is avoided. This makes it possible to maintain EPSstability in certain areas with high PV-DG penetrations.
As shown in Tables 2 and 3, voltage and frequency set pointsand disconnection times, which permit the safe operation of the DG(PV-DG), differ considerably. This is because each DNO/TSO mustadjust to the specific characteristics of an area EPS. Nonetheless,for PV-DG connected to LV and MV networks, a strict 0.3 s set dis-
connection time (see Table 2) is suggested for effective islandingdetection as well as the rapid disconnection of MV PV-DG before aquick reclosing attempt (approximately 0.3 s after initiation of thefault). Moreover, the duration of voltage dips due to faults on close
90 J.C. Hernández et al. / Electric Power Systems Research 89 (2012) 85– 99
Table 3DG response to abnormal voltage and frequency at the LV, MV, and HV-EHV level.
f(maadtctt
tdtdppEeiIPe
5
ti
Lotbl
eeders (i.e. 0.15 s) with phase-instantaneous-overcurrent relays50), does not generate nuisance trips. Fast disconnection times
ay increase nuisance trips if phase-time-overcurrent relays (51)re used, thus putting EPS stability at risk. At the HV-EHV level,
less sensitive setting is preferable, in other words, a 2.5 (1.5) sisconnection time for interconnection (PV generating unit) pro-ection (Table 2, Fig. 8). This setting maintains PV-DG generationapacity in operation during critical disturbances (voltage dips dueo faults cleared by 51 relays) that do not threaten the stability ofhe area EPS.
For the specific detection of earth faults, the winding configura-ion of the transformer connecting the large PV-DG to the area EPSetermines the means to be used. Unearthed primary interconnec-ion transformers (e.g. delta-earthed wye and floating wye-delta)o not directly contribute to earth current and will require primaryotential transformers to detect an area EPS earth fault, for exam-le, a (neutral) zero-sequence under/overvoltage relay (27G/59G).arthed primary interconnection transformers (e.g. earthed wye-arthed wye) only contribute to earth current to the area EPS if theres an earth source connected to the PV-DG side of the transformer.n this case, fault backfeed detection at a low level is applicable toV-DG using an earth-time-overcurrent relay (51N) or directionalarth overcurrent relay (67N).
.2. Islanding
In almost all countries, the unintentional islanding operation ofhe DG is not allowed for safety and reliability reasons [44] despitets potential benefits [56].
The oldest methods for islanding detection, such as passiveOM detection methods [30–32,44], may fail in the surroundings
f the production-consumption equilibrium of a local EPS fed byhe PV-DG after a fault [19,57,58]. Accordingly, the probability ofalanced generation-load conditions for different PV penetrationevels was analysed in a local EPS, and was found to be maximum at
penetration levels between 1 and 2 [1,59]. However, this probabil-ity was insignificant for levels below 0.35–0.50 of the minimumload for long-lasting balanced conditions (five or more seconds).Because of this concern, islanding detection has been extensivelystudied for PV inverters connected to a secondary distributionnetwork. This has led to the proposal of more sensitive activePV inverter-resident methods and communication based methods[1,30–35,44,57].
Despite their weak points, passive LOM detection methods arethe most frequently used in the majority of countries [16,34,59,60]because they are inexpensive and not intrusive [44]. Recently, how-ever, certain countries have opted for active methods [5,13,16,17](e.g. frequency or voltage shifting, impedance measurement, appli-cable no-islanding test, etc.), which require a disconnection periodof 1.66 –5 s [1,10,13,19,21]. These new requirements are now beingharmonised insofar as possible in international standards [20,23].Communication-based methods for the external disconnection ofthe interconnection system are also being implemented, especiallyat the MV level [1,44,61,62].
5.3. Coordination between the DNO’s reclosing practices andPV-DG
The reliability of electricity supply in radial primary overheaddistribution networks is improved by reclosing the fault interrupt-ing device after faults of extremely short duration. Some DNOsalso employ reclosing on feeders with underground sections [8].A reclosing relay (79), used for reclosing, may control a primarysubstation breaker/recloser or line reclosers (Fig. 2). DNO reclosingpractices vary widely [63]. For instance, some DNOs use one-shotreclosing (0.3–15 s or more), whereas others use up to three sub-
sequent time-delayed attempts of varying intervals (periods ofroughly 1–3 min).Two problems may result from the automatic reclosing of theutility EPS circuit to which the PV-DG is connected [64–67]. The
J.C. Hernández et al. / Electric Power Systems Research 89 (2012) 85– 99 91
Table 4Voltage and frequency window and delay time for DG reconnection.
Spanish order 5/9/1985 [12] IEEE 1547-2 [1] Iberdrola code [5] Endesa code [3]
85% < V < 115% 88, 92%a < V < 106% 85% < V 85% < V
time
fiaimrcPi
soiwsrbT0baWipDDarti[
5
gmTiEd
ti
TV
LV/MV 98.8% < f < 100.8%Delay time >3 min Adjustable delay
a >600 V.
rst problem is that the automatic reclosing attempt may fail as result of feeding the fault from the PV-DG. The second problems that because of active power unbalance, a change in frequency
ay occur in the islanded part of the grid. In this scenario, anyeclose attempt by the interrupting device would couple two asyn-hronously operating systems with unacceptable stress to bothV-DG and the network equipment, caused by out-of-phase reclos-ng [1,68].
Various solutions can be applied. Generally speaking, it is neces-ary to disconnect the PV-DG from the utility EPS circuit by meansf LOM protection before the first reclosing attempt of the util-ty EPS circuit [1–5,10,12]. However, DNOs do not always comply
ith this requirement [8]. Because of reclosing activities, more sen-itive LOM protection settings are advised in [25,29,32]. As theeclosing speed increases, there is a proportionally higher proba-ility that the reclosing attempt will not be successful with PV-DG.hus, DNOs may delay the reclosing attempt for such feeders from.3 s to up to 1.0 min [1,17,30,32,66,67,69]. In fact, they may evenlock it altogether [5]. However, neither of these measures guar-ntees the correct operation of LOM protection in all cases [70].hen PV-DG disconnection cannot be obtained with local sens-
ng approaches, the use of a communication channel between therimary substation and the PV-DG to transfer trip (TT) to the PV-G unit can ensure fast reclosing [12] (0.3 s) [3–5]. However, manyNOs are not able to change their reclosing practices which require
synchronism-check relay (25) and an undervoltage-permissiveelay (27X) to supervise reclosing. Lastly, PV-DG could be con-rolled so as to reduce its current “close to zero” while the feeders disconnected, thus allowing the fault electric arc to extinguish64].
.4. PV-DG reconnection to the utility EPS
The interconnection protection of PV-DG must prevent the ener-ization of the utility EPS until its frequency and/or voltage isaintained in normal ranges during a delay time (Tables 4 and 5).
his is necessary for the following two reasons: (i) to protect util-ty EPS equipment during feeder restoration activities after a utilityPS disturbance or fault; (ii) to protect utility workers from risks
uring line maintenance.The PV-DG reconnection response needs to be coordinated withhe DNO’s reclosing strategy. Moreover, reclosing time may bencreased when PV-DG resynchronization is necessary before its
able 5oltage and frequency window and delay time for PV-DG reconnection.
IEC 61727 [22] EN 50438 [20] Endesa PV-Code [9] Ro
LV
90% < Va < 110% 85% < V < 115% 85% < V < 110% 8599% < fa < 101% 94% < f < 102% 98% < f < 102% 98Adjustable delay timebetween 30 s and 3 min
Delay time >20 s Delay time >3 min De
MV
a According to EN 50160.
<5 min Delay time >3 min Delay time >3 min
reconnection [22]. At the LV level, line reclosing activities areunusual, and a low 1-min delay setting is suggested (Table 5). At theMV level, however, the reclosing coordination of different feederdesigns (e.g. radial, bifurcated radial, loop, etc.) needs to be exam-ined [8]. In addition, PV-DG must remain isolated from the utilityEPS until the automatic reclosing on the breaker has reset. A 3-mindelay setting is thus advisable (Table 5) [1]. At the HV-EHV level,since PV-DG disconnection in area EPS fault conditions is not alwaysnecessary, PV-DG reconnection is not analysed.
6. Synchronization of PV-DG
Self-commutated inverters may operate as voltage or currentsources. Only voltage source inverters match the EPS voltage andphase angle in the same way as a synchronous machine [1].Nevertheless, the tolerances can be greater because there is nomechanical inertia involved. Since line-commutated inverters can-not operate without an external line voltage, synchronization is notnecessary.
7. PV-DG grid-interconnection at the LV level
7.1. Secondary distribution network protection
Although this section describes secondary distribution net-works in Spain (Fig. 1), this description is also valid for networks inmany other countries as well [1,30,71,72].
There are mainly two types of secondary distribution networks:spot networks and grid (area/street) networks. A spot network isfrequently set up for a single customer or multiple customers at onesite. An open/closed grid network is typically used in metropolitanareas to serve several customers.
In Spain, both types of secondary network are supplied by oneprimary feeder through 1–2 network transformers (most in the250–1000 kVA transformer size range) connected to a common buson the LV side. The network protector uses overcurrent devices suchas LV circuit breakers/fuses [73].
The philosophy in the USA for operating secondary networks isthat these are supplied by redundant primary feeders. Accordingly,
the network protector must have additional functions [1,11,30]: (i)backup fuses for forward-looking overcurrent protection; (ii) direc-tional power relays (32) for primary feeder clearance in primaryfeeder faults; (iii) phase-angle measuring relays (78) for reclosingyal Decree 1663/2000 [24] IEEE 929 [19] Recommended settings
% < V < 110% 110% < V < 85%% < f < 102%lay time =0 s 88% < V < 110% Delay time <1 min
98.8% < f < 100.8%Delay time >5 min 110% < V < 85%
101% < f < 99%Delay time >3 min
92 J.C. Hernández et al. / Electric Power S
Fl
tf
7L
PnpoTst[
o(ich[
ois[
seu
t(
able switch (89) that is accessible at any time to the DNO’s staff
ig. 4. Basic functions of the interconnection protection system for PV-DG at the LVevel.
he network breaker when the voltage and phase of the primaryeeder allow power flow into the distribution secondary network.
.2. Electrical protection for PV-DG grid-interconnection at theV level
DNOs require a single interconnection protection system at theCC for the whole PV-DG unit (Figs. 1 and 4). Most DNOs [3,5,6,9],ational codes [12,15–17,24], and standards [1,10,13,14,19,20,22]ropose under/overvoltage detection (27/59 relay) and under/verfrequency detection (81U/O relay) for this protection system.he settings of these relays are shown in Table 2. Some DNOs andtandards allow these protective functions to be built into the con-rol software/hardware of PV inverters, e.g. 27/59 relay function5,9,20,24] and 81U/O relay function [3,5,9,20,24].
In addition, most references [3,5,6,9,12,14,15,20,22,24] rec-mmend overcurrent protection by means of a circuit breaker52) which is triggered by the 50/51 relay. A time-delayed andnstantaneous earth overcurrent relay (50/51N) also trips this cir-uit breaker to control earth faults. Alternatively, an independentigh-sensitivity residual-current device is sometimes advisable3,5,9,24].
For safety reasons, interconnection protection must be capablef detecting the loss of the grid supply by means of the anti-slanding protection (AI relay). Different methods are suggested,uch as rate-of-frequency change relay (81R) and vector shift1,5,6,12,16,17,19,20,22,47].
PV-DG connection must be performed with a visible lockablewitch (89) [1,3,5,6,9,15,19,20,22,24]. PV-DG reconnection must benabled by means of the auxiliary undervoltage relay (27X) after atility EPS fault [1,3,5,9,12,19,20,22,24].
Only one DNO analysed required additional protection such ashe phase-balance current relay (46) [9] or power factor (PF) relay55) [3].
ystems Research 89 (2012) 85– 99
8. PV-DG grid-interconnection at the MV level
8.1. Distribution primary network protection
Although this section describes primary distribution networksin Spain (Fig. 2), in the same way as for secondary distribution net-works, this description is also valid for networks in many othercountries [1,44,72].
Spanish primary substations usually have two transformers(most in the 10–60 MVA transformer size range [63,72]) and twoMV bars in open tie. Consequently, most primary distribution net-works are either radial or operated according to radial schemesto improve their reliability, e.g. a ring-main feeder keeps the tiebreaker/switch open. In low customer-density areas (e.g. ruralareas), each MV bar of the primary substation supplies 3–5 over-head radial feeders [74]. These feeders are formed by a main feederand laterals. In contrast, in high customer-density areas, such asmetropolitan areas, there are 3–5 ring-main feeders per MV bar[74].
Overhead radial feeders are protected by means of overcur-rent devices based on the coordination of fuses, overcurrentrelays, reclosers, and sectionalizers installed in the substationand in appropriate switching nodes along the length of thesupply feeder (Fig. 2). Mainly, this signifies that 50/51 and50/51N overcurrent relays [8,63], reverse-phase current relays(46) [63] and reclosers (79) [8,63] are required. Parallel feedercircuits need 67/67N and 21/21N relays [63]. Ring cable feedersmay use cable thermal relays (49). Nevertheless, the protectionphilosophy varies from DNO to DNO, e.g. fuse saving/blowingschemes, instantaneous/delayed reclose, etc. Consequently, thereis currently no consensus as to the optimal solution for thisproblem.
8.2. Electrical protection for PV-DG grid-interconnection at theMV level
DNOs require a single interconnection protection system atthe PCC for the whole PV-DG unit (Figs. 2 and 5). This protec-tion system has to be equipped with under/overvoltage detection(27/59 relay) and under/overfrequency detection (81U/O relay)[1–5,7,12,17,19,25,47]. The recommended settings are shown inTable 2. Furthermore, overcurrent protection by means of acircuit breaker (52), triggered by the 50/51 relay, must guar-antee PV-DG disconnection from the utility EPS in the eventof utility EPS faults. Sometimes, however, overcurrent protec-tion is performed by means of distance protection (21 relay)at the DNO’s request [3,25]. To control earth faults, the pre-viously mentioned circuit breaker may be triggered by meanof the following: (i) 50/51N relay [1–5,7,12,25] or 67N relay[1,4,7] for earthed primary interconnection transformers; (ii)59G relay for unearthed primary interconnection transformers[3–5,7,12].
For secure network operation, it is necessary to include the PV-DG in the DNO’s remote control scheme. For example, the TT ofthe interconnection circuit breaker (52) is mandatory in differentreferences when output power is higher than a certain thresholdvalue (100 kVA [25,75], 1 MVA [3,4,12], and 5 MVA [5]). Addition-ally, to coordinate PV-DG reconnection with the DNO’s reclosingstrategy (79 relay), the auxiliary undervoltage relay (27X) is neces-sary [1–5,12,19].
PV-DG connection must be performed with a visible lock-
[1–4,19,25].Specific anti-islanding protection is not as necessary at the MV
level as at the LV level [5,19,47].
J.C. Hernández et al. / Electric Power Systems Research 89 (2012) 85– 99 93
on pro
9
c[vc
pDlHlfip
ne[ltmtt
ccEdsi
Fig. 5. Basic functions of the interconnecti
. PV-DG grid-interconnection at the HV-EHV level
Moderate levels of PV penetration in the EPS (≤10%) have non-ritical impacts, e.g. a moderate bus voltage rise close to the PV39,31]. However, high levels (>30% [8]) require new rules and ser-ices (e.g. dynamic grid support) since the impact of the PV-DG isritical to power delivery and its capacity to meet demands.
In the current context of increasing PV penetration, the mostroactive countries, who are establishing new services for PV-G, are obviously pioneers in achieving higher PV penetration
evels. Thus, at the transmission level, namely when EHV andV ≥ 110–132 kV, some TSOs [25–29,52,53] are demanding that
arge PV farms provide the same ancillary services as those speci-ed in transmission grid codes [52,76–79] for conventional powerlants, i.e. dynamic grid support and active/reactive power control.
At the distribution level (<110–132 kV), even though grid codeeeds differ insofar as maintenance of local voltage stability and thequilibrium of active/reactive power, many distribution grid codes80–82] are adaptations of transmission codes containing simi-ar requirements. Therefore certain DNOs [17,25–28] also requireransmission requirements, such as dynamic grid support, from
edium and medium-large PV farms. Finally, there are countrieshat are also in the process of extending some of these features tohe LV level [14].
Implementing dynamic grid support and active/reactive powerontrol for PV-DG is not technically challenging. In fact, mosthanges can be performed by modifying PV inverter software.
xamples of this include new control strategies that entail indepen-ent control of the active and reactive power of the inverter gridide [36,38,83–89]. Previous experience in wind turbine invertersndicates that there is no reason why the same approach cannottection system for PV-DG at the MV level.
be used in PV inverters to achieve the same functionality. More-over, for PV technology, an added advantage is that there are nomechanical issues involved. There is only the need for minor hard-ware changes, additional sensors, and new electrical protectionrequirements, with adapted protection relay settings.
9.1. Ancillary services to be provided by PV-DG
9.1.1. Dynamic grid supportDynamic grid support means voltage control in the event of volt-
age dips/rises during subtransmission/transmission system faultsto avoid an unintentional disconnection of large feed-in PV-DGpower, and to maintain system stability. A transmission systemfault is transmitted across large areas due to the low impedanceof its circuits. As a result, many large PV farms may discon-nect. In the same way, even though at distribution levels PV-DGunits are smaller, they are more widespread. Thus, the samedisturbance might propagate over a larger part of the territory,affecting many medium or medium-large PV farms on distributionnetworks.
Dynamic grid support means that PV-DG has to be able to do thefollowing: (i) stay connected during a fault, i.e. FRT capability; (ii)support the voltage by providing/absorbing reactive current duringthe fault; (iii) consume the same or less reactive power after thefault clearance.
FRT capability for PV-DG generally varies from one coun-try to another. Nevertheless, most new grid codes [25–29,52,53]
and standards [21,49], adapted to PV, have similar requirements(Fig. 6). For voltage dips/swells that are above/below the border-lines, PV-DG must stay connected. Below/above these borderlinesthe disconnection of PV-DG is permitted. More demanding appear
94 J.C. Hernández et al. / Electric Power Systems Research 89 (2012) 85– 99
rds to
t)urclvnrmitcvtnoar
ead
Fig. 6. FRT capability proposed by new grid codes and standa
o be the CAISO (Spanish) requirements, which stipulate that (PV-DG must remain connected during voltage dips down to 0% forp to 625 (150) ms. However, it should be underlined that theseequirements apply to the PCC (HV level). Taking into account typi-al impedance values for step-up transformers and interconnectionines, a relatively simple calculation shows that the correspondingoltage dip at lower voltage levels near the PV inverter termi-als are likely to be somewhat above 15%. The less severe Germanequirements may be attributed to the physical location of the Ger-an grid and its strong interconnection to the UCTE system. This is
n contrast to the weakly interconnected Spanish system, in whichhe need for active power restoration to the pre-fault values is morerucial for system stability. Additionally, the Spanish grid is moreulnerable than the grids of other countries because it has a rela-ively high PV penetration. After the clearance of the fault, the timeecessary to recover nominal values depends on the percentagef PV penetration related to the short-circuit power. New settingslso tend to cover unsymmetrical faults, i.e. single and two-faultide-through capability [27].
The implementation of FRT capability in wind turbine invert-rs has been successful even though that it is more difficult tochieve than in PV inverters. This experience has furthered theevelopment of this capability in PV inverters. In fact, according
0
20
40
60
80
100
47 48 49 50 51 52 53
Rel
ativ
e po
wer
P/P
n (%
)
Frequency (Hz)
Net
wor
k vo
ltage
(%
)
(a)
Fig. 7. Requirements regarding the feed-in power from PV-DG to the networ
be supported by PV-DG without disconnection from the grid.
to a recent European survey, most PV inverters meet new Germanrequirements [25]. Seven years ago a similar survey showed thatPV inverters were extremely sensitive [62].
Meeting the FRT capability can be achieved by PV inverterperformance [36–38], and/or by using supplementary plant equip-ment. Recently, new technologies such as custom power devices(e.g. static series compensator like the DVR, static shunt compen-sator like distribution static compensator, and static series andshunt compensator like unified power quality conditioner) havebeen developed to provide protection against voltage dips/rises.
During either symmetrical/asymmetrical faults or voltagerecovery periods after the fault clearance, PV-DG must supportthe network voltage by means of additional reactive current. Forexample, the absorption of a large amount of the reactive power insymmetrical faults may induce instability in the line, especially forlarge-scale PV-DG. Therefore, according to [25,26,29] the voltagecontrol in the PV inverter must be capable of providing/absorbinga reactive current of at least 1.8–2% of the rated current for eachpercentage of the voltage dip/rise within 20–40 ms. Since the
fault response of any PV inverter is dictated by its control strat-egy [36–38], the reactive current requirement may be includedin this strategy, e.g. estimation and control of inverse sequence[36,55].85
90
95
100
105
110
115
120
cos network1.0 0.975 0.95 0.9250.975 0.95 0.975
0.0 0.228 0.33 0.410.41 0.33 0.228
Q/Pn network (p.u.)
overexcitedunderexcited
(b)
k to be guaranteed as a function of the network frequency and voltage.
J.C. Hernández et al. / Electric Power Systems Research 89 (2012) 85– 99 95
Table 6Frequency limits for active power control in transmission grid codes.
Spanishtransmission gridcode [76]
Germantransmission gridcode [77]
Great Britaintransmission gridcode [52]
Italiantransmission gridcode [78]
Frenchtransmission gridcode [79]
Applicable voltage levels(HV and/or EHV)(HV level)
110-132, 220,400 kV(45 kV ≤ HV ≤ 132 kV)
110, 220, 380 kV(60 kV ≤ HV ≤ 110 kV)
132, 275, 400 kV(HV = 132 kV)
120-150, 220,380 kV(50 kV ≤ HV ≤ 132 kV)
150, 225, 400 kV(63 kV ≤ HV ≤ 90 kV)
Spanishtransmissiongrid code [76]
Germantransmissiongrid code [77]
Great Britaintransmissiongrid code [52]
Italiantransmissiongrid code [78]
Frenchtransmissiongrid code [79]
Threshold tDa (s) Threshold tD
a (s) Threshold tDa (s) Threshold tD
a (s) Threshold tDa (s)
Output powerlevel foractive powercontrol
>10 MVA >100 MW >10–100 MW >10 MVA >0 MVA
Active powercontrol
f < 96% <3.0 f < 95% 0 f < 94% <60102% < f <0.2 95% ≤ f < 96% ≥ 600 f < 93% 0 94% ≤ f < 95% <180
96% ≤ f < 97% ≥ 1200 f < 94% 0 93% ≤ f < 95% <4.0 95% ≤ f < 98% <30097% ≤ f < 98% ≥ 1800 94% ≤ f < 95% ≥20 103%<f < 104% <1.0 98% ≤ f < 99% <3600
104
rsfo
9
db[psPt
e[r2
TF
101% < f < 103% ≥ 1800
103% ≤ f 0
a Disconnection time.
Since commercial PV inverters currently do not include thisequirement, new standards are necessary to define how theyhould behave in term of fault current contribution during externalaults, not only for reactive currents [25,26,29] but also for activenes [26].
.1.2. Active power controlTS/DNOs should temporarily limit the feed-in active power or
isconnect the PV-DG if there is risk of unsafe system operation,ottlenecks or congestion, instability due to frequency increase25,26,29,53]. Although both operators provide output power setoints by means of a signal (e.g. 0%, 30%, 60%, 100% in the Germantandard [25]), they must not interfere with the inner control of theV farm. Furthermore, this control should be carried out withouthe disconnection of any inner PV unit.
Active power control depends on frequency (Fig. 7a) when-
ver this is included inside the set limits (Tables 6 and 7)25,26,52,53,76–79]. Thus, according to [25,26,29], PV-DG has toeduce its output power above a system frequency of 50.2 Hz with–20% static, depending on the grid code selected. It is necessaryable 7requency limits for active power control in technical guidelines adapted to PV.
CAISO interiminterconnectionrequirements [53]
Applicable voltagelevels(HV and/or EHV)(HV level)
115, 138, 220, 230, 287,500 kV(60 kV ≤ HV ≤ 138 kV)
CAISO interiminterconnectionrequirements [53]
Threshold tDa (s)
Output power level foractive power control
>20 MVA
Active powercontrol
f < 95% 095% ≤ f < 95.5% <0.7595.5% ≤ f < 96.3% <7.5
96.3% ≤ f < 97.3% <30
97.3% ≤ f < 99% <180
101% < f < 102.6 <180102.6% ≤ f < 102.8% <30102.8% ≤ f 0
a Disconnection time.
% < f 104% ≤ f 0 101% < f < 104% <900104% < f <60
to reach a 10% output power reduction in PV-DG capacity in a timeranging from 250 ms to 60 s [25,26,29]. These requirements can befulfilled fairly easily by new control strategies in the PV inverter,which control the operation point of the PV array.
A future trend for active power control is both under and over-frequency support [26,53]. Therefore, PV-DG will operate with acertain constant reserve capacity in relation to its momentary pos-sible power production capacity (e.g. 10% [26]). By doing so, if thefrequency starts to drop, the PV-DG would increase the power out-put to the maximum achievable power in an effort to sustain thefrequency. Furthermore, PV-DG could have the capability of inertiaemulation.
9.1.3. Reactive power controlReactive power is used under normal operating conditions
to control network voltage stability, i.e. static grid support[52,76–79,90]. In this way, slow changes in bus voltage can bekept within acceptable limits with an increase/decrease of feed-inreactive power from the PV-DG units [39,86–88,91].
German MV technicalguidelines [25]
Spanish draft technicalguidelines (wind andPV) [26]
MV(10 kV ≤ MV ≤ 30 kV)
HV, 220, 400 kV(45 kV ≤ HV ≤ 132 kV)
German MV technicalguidelines [25]
Spanish draft technicalguidelines (wind andPV) [26]
Threshold tDa (s) Threshold tD
a (s)
>0 MVA >1 MVA
f < 95% 0f < 95% <0.2 95% ≤ f < 96% <30103%<f <0.2 103%<f
96 J.C. Hernández et al. / Electric Power Systems Research 89 (2012) 85– 99
prote
tf[bHabpbvrgrps
aicht
Fig. 8. Basic functions of the interconnection
Local grid requirements for PV-DG connected directly to dis-ribution networks [25–27] or transmission system [26,27,29,53]orce participation in the static grid support (if PV-DG ≥ 0 [25,29], 126], 10 [27], 20 [53] MW). The reactive power set point is obtainedy a PF control (fixed PF or variable depending on active power).owever, there is a growing tendency towards operating in a volt-ge set point control mode, where reactive power changes areased on measured voltage (Fig. 7b) without limiting the activeower delivered. PV-DG must reach the agreed reactive power inoth control modes in 10–60 s [25,26,29]. In Fig. 7b, inside theoltage range (e.g. 0.925 ≤ V ≤ 1.075 in the Spanish proposal forenewable power plants), PV-DG must have a technical capacity forenerating and absorbing reactive power in a required minimumange and must change its production/consumption of reactiveower within these limits so as to maintain the voltage in theuitable range.
The reactive power control requirements are related to the char-cteristics of each network since the influence of the reactive power
njection into the voltage level is dependent on the network short-ircuit capacity and impedances. The lower the voltage level, theigher the influence of the reactive power injection is because ofhe lower/higher short-circuit capacity/impedance.ction system for PV-DG at the HV-EHV level.
Currently, PV inverters are designed to operate at quasi-unity PF.PF requirements are only fleetingly mentioned in some standardssuch as [19,22] (PF > 0.85 lagging) and [20] (PF between 0.95 laggingand 0.95 leading at 20% or above the rated MW output). There-fore, additional regulations are required for the setting of new PVinverter reactive power capabilities, e.g. full reactive power capa-bility between 20% and 100% of the rated active output power orfully independent reactive power available.
Custom power devices, e.g. shunt reactors and FACTS, offergreater flexibility for reactive power control, but PV-DG operatorsstill hesitate to use it because of its cost.
9.2. Transmission system protection
The HV-EHV system in Spain has a meshed topology of greateror lesser complexity. It can be operated with a meshed philosophy(closed loop) or a radial philosophy (open loop). This system is used
to feed the primary substations. The layout of the HV-EHV bus bar ofthese primary substations depends on the area where they are built.Most the HV-EHV networks comply with n − 1 security criterion(for transformers and lines).
wer S
9H
Pati
e[Tdvaa
mtap[dr
[e
serr
tbh[ltsaug
1
vgTtfca
ftecctvwtc
[
[
[
J.C. Hernández et al. / Electric Po
.3. Electrical protection for PV-DG grid interconnection at theV-EHV LV level
TSO requires a single interconnection protection system at theCC for the whole PV-DG unit, which has a widespread MV networkvailable and is connected to the transmission system through aransfer station (Figs. 3 and 8). Nevertheless, additional protections also required at the PV generating unit grid side [29].
The interconnection protection system has to bequipped with under/overvoltage detection, i.e. the 27 relay3,5,29,47,52,76–78,92] and 59 relay [3,5,29,47,52,76,77,92].he recommended setting for abnormal interconnection voltageetection is shown in Table 2. Abnormal frequency detection has aery limited use at this voltage level since the frequency variationsre rare. Overfrequency detection [3,5,47,52,76–78,92] is moredvisable than underfrequency detection [3,5,47,52,77].
PV-DG protection against EPS phase faults is carried out byeans of a circuit breaker (52), triggered by the 50 relay [3,5] and/or
he 51 relay [3,5,29,52,77,78,92]. However, this protection must bechieved by means of distance protection (21 relay) if PV-DG outputower is higher than a given threshold value (0 MVA [29], 100 MVA3,78,92]). Distance protection is used together with a transformerifferential relay (87T). EPS earth faults are controlled by the 51Nelay that triggers the circuit breaker [3,5,29,52,77,78,92].
Protection against reverse power flow (32 relay) is required in77,92] to separate the PV-DG from the EPS when it lacks its primarynergy.
Although the ANSI C50.13 specifies that all generating unitshould support, in permanent regime and without any damage, theffects of the circulation of an inverse current, references [3,77,92]equire the use of negative sequence protection (negative sequenceelay –46–).
The TSO remote control scheme for PV-DG goes even furtherhan the required control of the interconnection circuit breakery DNOs. This level requires mandatory control for output powerigher than a given threshold value, e.g. 100 kVA [29,75], 1 MVA3] and 5 MVA [5]. Thus, dynamic grid support and/or active powerimitation and/or the reactive power provision are also obliga-ory [26–29,52,53,76]. When these ancillary services are provided,econdary protective equipment is also needed for the PV gener-ting units [25,29]. This equipment offers under/overvoltage andnder/overfrequency detection. The recommended settings for PVenerating unit protection are shown in Table 2.
0. Centralized protection and control system for PV-DG
Large PV farms have many protection zones from the con-entional electrical protection perspective (Figs. 2 and 3). The PVenerating unit is protected by a separate set of protection relays.he step-up transformer normally has a fuse at the MV side (pro-ection relay for transformers larger than 1 MW). The PV collectoreeder is protected by a separate feeder protection relay. The PVollector bus uses a busbar protection relay. The HV transformer islways protected by a transformer protection relay.
The fact that the protection relays for medium and large PVarms are found at many locations along with a control cen-re for the whole PV farm signifies that it requires a centralizedlectrical protection and control system (Figs. 2 and 3). Thisentralized system may be based on the IEC 61850-9-2 pro-ess bus [93]. The architecture of this process bus is based onhe concept of distributed data acquisition units interfacing with
arious types of primary apparatus and exchanging informationith numerical relays and PV inverters over fibre communica-ion. Acquisition units collect current/potential transformer signals,ircuit breakers/PV inverters control and status signals. The IEC
[
[
ystems Research 89 (2012) 85– 99 97
61850-9-2 output sends appropriate signals to each relay and PVinverter.
11. Conclusion
This paper has presented the electrical protection require-ments for PV-DG grid-interconnection from the LV to the HV-EHVlevel. A comparative overview and analysis of these requirementshave been provided. Such requirements are found in national andregional codes that have been proposed and enacted in many coun-tries where high PV penetration levels have been achieved or areexpected to be achieved.
Interestingly, in Spain as well as in other countries, electricalprotection requirements for LV are clearly defined. However, thisis not the case for other voltage levels. At the MV level, electricalprotection requirements take into account the potential conflictswith the current scheme of distribution network protection. How-ever, at the transmission level, there is a clear need to take thisone step further. Thus, in the specification of the requirements forlarge PV-DG, the provision of ancillary services should be included,which are similar to those required for conventional power plants.
Current PV technology, particularly its development in the lastcouple of years, has been heavily influenced by these specifica-tions. Nevertheless, costly technical requirements should only beapplied if there is a true technical rationale for them and if they arenecessary for safe and stable EPS operation.
Acknowledgements
The work presented in this paper is part of the research projectSigmaSoles: innovation in PV concentration in Spain (PSE-440000-2009-8), funded by the Ministry of Science and Innovation in Spain.The authors would like to thank the Company Endesa for its con-tinued support.
References
[1] IEEE Std. 1547.2, Application Guide for IEEE 1547 Standard for InterconnectingDistributed Resources with Electric Power Systems, 2008.
[2] J.C. Hernández, M.J. Ortega, J. De la Cruz, D. Vera, Guidelines for the technicalassessment of harmonic, flicker and unbalance emission limits for PV-distributed generation, Electric Power Systems Research 81 (2011) 1247–1257.
[3] Basic Standard regarding Technical Conditions of Connection for Power Plantsin Special Regime, Endesa Distribution Company, Spain, 2000 (in Spanish).
[4] Draft Technical Guidelines regarding the Conditions for Connection to theEndesa Distribution Network for Power Plants in Special Regime, Endesa Dis-tribution Company, Spain, 2010 (in Spanish).
[5] Technical Conditions of the Installation of Self-Producers Plants (MT 3.53.01),Iberdrola Company, Spain, 2004 (in Spanish).
[6] Criterion of Connection for Production Installations of Enel LV DistributionNetwork (DK 5940), Enel Corporation, Italy, 2007 (in Italian).
[7] Criterion of Connection of Production Installations of Enel MV DistributionNetwork (DK 5750), Enel Corporation, Italy, 2005 (in Italian).
[8] K. Malmedal, P.K. Sen, Comparison of some randomly selected utilities inter-connection requirements and the compliance with the IEEE Std. 1547 –Interconnection guidelines, in: Proc. 2008 IEEE Rural Electric Power Conference,North Charleston, South Carolina, USA, 2008, pp. C3–C3-8.
[9] Draft Technique Guidelines regarding the Conditions for the Connectionto the Endesa LV Distribution Network of Photovoltaic Energy Resourcesof Rated Power Lower than 100 kVA, Endesa Distribution Company, Spain,2009 (in Spanish), http://blogs.ujaen.es/jcasa/wp-content/uploads/2011/12/NGL00100.pdf.
10] IEEE Std. 1547, Standard for Interconnecting Distributed Resources with Elec-tric Power Systems, 2003.
11] IEEE Std. P1547.6/Draft 8.0, Draft Recommended Practice for InterconnectingDistributed Resources with Electric Power Systems – Distribution SecondaryNetworks, 2011.
12] Order 5/9/1985, Administrative Technical Rules for the Operation and Intercon-nection to the Grid of Hydroelectric Power Plants up to 5 MVA and Self-Producer
Plants, Spain, 1985 (in Spanish).13] DIN VDE Std. 0126-1-1, Automatic Disconnection Device between a Generatorand the Public Low-Voltage Grid, 2006 (in German).
14] VDE-AR-N Std. 4105/Draft, Application Rule on Production Installations at theLow Voltage Network, Technical Least Requests for Connection and Parallel
9 wer S
[
[
[
[[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[
[[
8 J.C. Hernández et al. / Electric Po
Performance of Production Installations at the Low Voltage Network, 2011 (inGerman).
15] Generating Plants Connected Generating Plants Connected to the Low-VoltageNetwork, Bundesverband der Energieund Wasserwirtschaft e.V. (BDEW), 2005(in German).
16] UK ER G83/1, Recommendations for the Connection of Small-Scale Embed-ded Generators (up to 16 A per Phase) in Parallel with Public Low-VoltageDistribution Networks, 2003.
17] UK ER G59/2-1, Recommendations for the Connection of Embedded GeneratingPlant to the Regional Electricity Companies’ Distribution Systems, 2011.
18] IEC Std. 62103, Electronic Equipment for Use in Power Installations, 2003.19] IEEE Std. 929, Recommended Practice for Utility Interface of Photovoltaic Sys-
tems, 2000.20] EN Std. 50438, Requirements for the Connection of Micro-Generators in Parallel
with Public Low-voltage Distribution Networks, 2007.21] UL Std. 1741, Inverters, Converters, Controllers and Interconnection System
Equipment for Use with Distributed Energy Resources, 2005.22] IEC Std. 61727, Photovoltaic Systems – Characteristics of the Utility Interface,
2004.23] IEC Std. 62116, Test Procedure of Islanding Prevention Measures for Utility-
Interconnected Photovoltaic Inverters, 2008.24] Royal Decree 1663/2000, Dated September 29th, on the Connection of Photo-
voltaic Installations to the LV Network, 2000 (in Spanish).25] Generating Plants Connected to the Medium-Voltage Network, Bundesverband
der Energieund Wasserwirtschaft e.V. (BDEW), 2008.26] Draft Technical Guidelines for Wind and Photovoltaic Power Plants Connected
Directly to the Distribution and Transmission Network: Minimum Require-ments of Design, Equipment, Operation, Setting in Service and Security, RedEléctrica, Spain, 2009 (in Spanish).
27] Royal Decree 1565/2010, Dated November 19th, by Means of Which CertainAspects of the Production of Energy under the Special Regime are Modified,2010 (in Spanish).
28] Arrêté, Dated December 23th 2010, Technical Prescriptions for Conception andPerformance of the Connection to a Public Electricity Distribution Network ofan Electric Energy Production Installation, 2010 (in French).
29] Guidelines on Renewables-based Generating Plants Connected to the High andExtra-high Voltage Network, VDE, 2004 (in German).
30] M. Geidl, Protection of Power Systems with Distributed Generation–State of theArt, Power Systems Laboratory, Swiss Federal Institute of Technology (ETH),Zurich, 2005.
31] M.A. Eltawil, Z. Zhao, Grid-connected photovoltaic power systems: technicaland potential problems – a review, Renewable and Sustainable Energy Reviews14 (2010) 112–129.
32] O. Raipala, S. Repo, K. Mäki, P. Järventausta, Studying the effects of distributedgeneration on autoreclosing with a real time digital simulator and real protec-tion relays, in: Proc. 9th Nordic Electricity Distribution and Asset ManagementConference, Aalborg, Denmark, 2010, pp. 1–11.
33] V. Zolingen, Electrotechnical requirements for PV on buildings, Progess in Pho-tovoltaics: Research and Applications 12 (2004) 409–414.
34] Evaluation of Islanding Detection Methods for Photovoltaic Utility-InteractivePower Systems (IEA-PVPS T5-09), International Energy Agency (IEA) – Photo-voltaic Power Systems Programme, 2002.
35] W. Bower, M. Ropp, Evaluation of Islanding Detection Methods for Utility-Interactive Inverters in Photovoltaic Systems, Report SAND2002-3591, SandiaNational Laboratories, 2002.
36] G.M.S. Azevedo, et al., Photovoltaic inverters with fault ride-through capability,in: Proc. 2009 IEEE International Symposium on Industrial Electronics, Seoul,Korea, 2009, pp. 549–553.
37] C. Photong, C. Klumpner, P. Wheeler, A current source inverter with series con-nected AC capacitors for photovoltaic application with grid fault ride throughcapability, in: Proc. 35th Annual Conference of the IEEE Industrial ElectronicsSociety Oporto, Portugal, 2009, pp. 390–396.
38] J.C. Vazquez, et al., Voltage support provided by a droop-controlled multi-functional inverter, IEEE Transactions on Industrial Electronics 56 (11) (2009)4510–4519.
39] E. Caamano-Martín, et al., Interaction between photovoltaic distributed gen-eration and electricity networks, Progess in Photovoltaics: Research andApplications 16 (2008) 629–643.
40] R.M. Tumilty, M. Brucoli, G.M. Burt, T.C. Green, Approaches to network pro-tection for inverter dominated electrical distribution systems, in: Proc. 3rd IETInternational Conference on Power Electronics Machines and Drives, Nagasaki,Japan, 2006, pp. 622–626.
41] C. González, et al., Assess the impact of photovoltaic generation systems onlow-voltage network: software analysis tool development, in: Proc. 9th Inter-national Conference on Electrical Power Quality and Utilisation, Barcelona,Spain, 2007, pp. 1–6.
42] K.I. Jennett, C.D. Booth, Protection of converter dense power systems, in: Proc.45th International Universities’ Power Engineering Conference, Cardiff, Wales,UK, 2010, pp. 1–6.
43] M. Dewadasa, A. Ghosh, G. Ledwich, Line protection in inverter supplied net-works, in: Proc. 2008 Australasian Universities Power Engineering Conference,
Sydney, Australia, 2008, pp. 1–6.44] S. Conti, Analysis of distribution network protection issues in presence of dis-persed generation, Electric Power Systems Research 79 (2009) 49–56.
45] B. Hussain, S.M. Sharkht, S. Hussain, M.A. Abusara, Integration of distributedgeneration into the grid: protection challenges and solutions, in: Proc. 10th
[
ystems Research 89 (2012) 85– 99
International Conference on Developments in Power System Protection,Manchester, UK, 2010, pp. 1–5.
46] IEEE Std. C37.2, IEEE Standard Electrical Power System Device Function Num-bers and Contact Designations, 1996.
47] UK ER G75/1, Recommendations for the Connection of Embedded GeneratingPlant to Public Distribution Systems above 20 kV or with Outputs over 5 MW,2002.
48] IEEE Std. 1547-5/Draft, Draft Guidelines for Interconnection of Electric PowerSources Greater than 10 MVA to the Power Transmission Grid.
49] NERC Std. PRC-024-1/Draft 2, Draft on Generator Performance During Fre-quency and Voltage Excursions, 2007.
50] Criterion of Connection of Customer to HV Distribution Network (DK 5400),Enel Corporation, Italy, 2004 (in Italian).
51] IEC Std. 11-32, Systems of Conversion Connected to Public Network of III Cat-egory, 2008 (in Italian).
52] Great Britain National Grid Code (Issue 4 Revision 5), National Grid ElectricityTransmission plc, Great Britain, 2011.
53] Draft Final Straw Proposal: Interim Interconnection Requirements for LargeGenerator Facilities Review Initiative, California ISO, 2010.
54] N. Jenkins, et al., Embedded Generation, The Institution of Electrical Engineers,Cambridge, 2000.
55] C.A. Plet, M. Graovac, T.C. Green, R. Iravani, Fault response of grid-connectedinverter dominated networks, in: Proc. 2010 IEEE Power and Energy SocietyGeneral Meeting, Minneapolis, Minnesota, USA, 2010, pp. 1–8.
56] Y. Sun, M.H.J. Bollen, G. Ault, Improving distribution system reliability by meansof distributed generation, in: Proc. 19th International Conference on ElectricityDistribution, Vienna, Austria, 2007, pp. 1–4.
57] PVPS Report – Risk Analysis of Islanding of Photovoltaic Power Systems withinLow Voltage Distribution Networks, (IEA-PVPS T5-08), International EnergyAgency (IEA) – Photovoltaic Power Systems Programme, 2002.
58] H. Kobayashi, K. Takigawa, Statistical evaluation of optimum islanding prevent-ing method for utility interactive small scale dispersed PV systems, in: Proc. 1stIEEE World Conference on Photovoltaic Energy Conversion, Village Waikoloa,Hawaii, 1994, pp. 1085–1088.
59] R. Bruendlinger et al., State of the Art Solutions and New Concepts for IslandingProtection, DISPOWER Project 2006, European Commission, Contract No. ENK-CT-2001-522.
60] A. Woyte, et al., International harmonization of grid connection guidelines:adequate requirements for the prevention of unintentional islanding, Progessin Photovoltaics: Research and Applications 11 (2003) 407–424.
61] E. Caamano et al., Utilities Experience and Perception of PV Distributed Gener-ation, Final PV Up-Scale Report, http://www.pvupscale.org.
62] B. Bletterie, R. Bründlinger, H. Fechner, Sensitivity of photovoltaic invertersto voltage sags—test results for a set of commercial products, in: Proc. 18thInternational Conference on Electricity Distribution, Turin, Italy, 2005, pp. 1–4.
63] P.T. Carroll, Distribution line protection practices industry survey results, IEEEPower System Relaying Committee Report (2002).
64] S. Kwon, C. Shin, W. Jung, Evaluation of protection coordination with distributedgeneration in distribution networks, in: Proc. 10th IET International Conferenceon Developments in Power System Protection, Manchester, UK, 2010, pp. 1–5.
65] J. Morren, S.W.H. De Haan, Impact of distributed generation units with powerelectronic converters on distribution network protection, in: Proc. 9th IET Inter-national Conference on Developments in Power System Protection, Glasgow,UK, 2008, pp. 664–669.
66] Martin Geidl, Protection of Power Systems with Distributed Generation: Stateof the Art, Power Systems Laboratory, ETH Zurich, 2005.
67] The Impact of Distributed Resources on Distribution Relaying Protection, IEEEPES, Power System Relaying Committee, 2004.
68] L. Kumpulainen, K. Kauhaniemi, Analysis of the impact of distributed genera-tion on automatic reclosing, in: Proc. 2004 IEEE Power Systems Conference andExposition, New York, USA, 2004, pp. 10–13.
69] S.A. Papathanassiou, A technical evaluation framework for the connection ofDG to the distribution network, Electric Power Systems Research 77 (2007)24–34.
70] L. Kumpulainen, K. Kauhaniemi, P. Verho, 0. Vähämäki, New requirements forsystem protection caused by distributed generation, in: Proc. 18th InternationalConference on Electricity Distribution, Turin, Italy, 2005, pp. 1–4.
71] M. Coddington, et al., Technical Report on Photovoltaic Systems Interconnectedonto Secondary Network Distribution Systems – Success Stories (NREL/TP-550-45061), National Renewable Energy Laboratory, 2009.
72] Distributed Generation in Europe – Physical Infrastructure and DistributedGeneration Connection, KEMA, 2011.
73] Specific Standards for Technical and Safety Conditions, Sevillana Endesa Elec-trical Energy Distribution Company, Spain, 2005 (in Spanish).
74] J.C. Hernández, A. Medina, F. Jurado, Impact comparison of PV system inte-gration into rural and urban feeders, Energy Conversion and Management 49(2008) 1747–1765.
75] Second German Law on the Energy Industry, 2005.76] P.O. 12.1 Y 12.2 Operating Procedure (OP) 12.1 and 12.2 of REE, Published in the
Official Gazette 01/03/2005, OP 12.1 Access Applications for the Connection ofNew Facilities To the Transmission System, 0P 12.2 Installations Connected to
the Delivery Grid: Minimum Requirements for Design, Equipment, Function-ality, Reliability and Energization, Spain, 2005 (in Spanish).77] Transmission Code: Network and System Rules of the German TransmissionSystem Operators, Verband der Netzbetreiber VDN e.V. beim VDEW, Germany,2007.
wer S
[
[
[[[
[
[
[
[
[
[
[
[
[
[
[
J.C. Hernández et al. / Electric Po
78] Code for Transmission, Dispatching, Development and Security of the Grid,Terna, Italy, 2011.
79] Référentiel Technique de Réseau de Transport dÉlectricité, Réseau de TransportdÉlectricité, France, 2009.
80] Le Référentiel Technique, EDF Réseau Distribution, France, 2003.81] Regeln für den Zugang zu Verteilungsnetzen, VDN, 2003.82] Royal Decree 436/2004, Dated March 12th, on Production of Electric Energy by
Installations Fed by RES, Waste and Cogeneration, 2004 (in Spanish).83] T. Stetz, W. Yan, M. Braun, Voltage control in distribution systems with high
level PV-penetration -Improving absorption capacity for PV systems by reactivepower supply, in: Proc. 25th EU PVSEC, Valencia, Spain, 2010, pp. 1–7.
84] J.M.E. Huerta, et al., A synchronous reference frame robust predictive currentcontrol for three-phase grid-connected inverters, IEEE Transactions on Indus-trial Electronics 57 (3) (2010) 954–962.
85] F. Delfino, et al., Integration of large-size photovoltaic systems into the distri-
bution grids: a P–Q chart approach to assess reactive support capability, IETRenewable Power Generation 4 (4) (2010) 329–340.86] L. Hassaine, et al., Digital power factor control and reactive power regula-tion for grid-connected photovoltaic inverter, Renewable Energy 34 (1) (2009)315–321.
[
ystems Research 89 (2012) 85– 99 99
87] K. Turitsyn, et al., Options for control of reactive power by distributed photo-voltaic generators, Proceedings of the IEEE 99 (6) (2011) 1063–1073.
88] M. Oshiro, et al., Optimal voltage control in distribution systems using PV gen-erators, International Journal of Electrical Power and Energy Systems 33 (3)(2011) 485–492.
89] G. Tsengenes, G. Adamidis, Investigation of the behavior of a three phase grid-connected photovoltaic system to control active and reactive power, ElectricPower Systems Research 81 (1) (2011) 177–184.
90] Operating Procedure 7.4, Published in the Official Gazette 18/03/2000, AncillaryService of Voltage Control for Transmission Network, 2005 (in Spanish).
91] Cagnano, et al., Can PV plants provide a reactive power ancillary service? A treatoffered by an on-line controller, Renewable Energy 37 (3) (2011) 1047–1052.
92] General Protection Requirements of the Spanish Peninsular Electric System,Red Eléctrica, Spain, 1995 (in Spanish).
93] IEC 61850-9-2, Communication Networks and Systems in Substations – Part
9-2: Specific Communication Service Mapping – Sampled Values over ISO/IEC8802-3, 2004.94] Draft on Guidelines for Grid Interconnection of Small Power Projects in Tan-zania – Part A: Mandatory Requirements and Test Procedure, Government ofTanzania, Ministry of Energy and Minerals, 2011.