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Hailuoto PSCAD simulations 1

Hannu Laaksonen (ABB, Distribution Automation) 28.03.2012

CLEEN OY Eteläranta 10, P.O. BOX 10, FI-00131 HELSINKI, FINLAND www.cleen.fi

Hailuoto PSCAD simulations

2FP – WP 5 and 6 (Tasks 5.1 and 6.13.2)

Research report

Privacy: Internal




Contents 1 Introduction .................................................................................................................................... 4

2 Protection and active management related functionalities required in future smart grids ................ 5

2.1 Centralized functionalities at HV/MV substation computer for realization of active

management and adaptive protection in smart grids .................................................................. 8

2.2 Case Hailuoto ...................................................................................................................... 9

3 Hailuoto PSCAD simulation model and backround information .................................................... 11

4 Simulation results ......................................................................................................................... 16

4.1 Fault simulations to determine protection settings for different topologies .......................... 16

Case 1: Protection during normal operation without DGs (balanced network) ...................... 18

Case 2: Protection during normal operation with new wind turbine (balanced network) ........ 20

Case 2b: Protection during normal operation with old 500 kW wind turbine (unbalanced

network) ............................................................................................................................... 22

Case 3: Protection during normal operation with diesel generator (balanced network) ......... 23

Effect of diesel generator control mode change (normal => island) time delay to stability after

islanding in different cases in case 3 .................................................................................... 25

Case 4: Protection during normal operation with diesel and wind (balanced network) .......... 26

Case 4b: Protection during normal operation with diesel and old 500 kW wind turbine

(unbalanced network) ........................................................................................................... 28

Case 5: Protection during island operation with diesel generator .......................................... 30

Case 5b: Protection during island operation with diesel generator and 500 kW wind turbine

(unbalanced network) ........................................................................................................... 32

4.2 Blackstart simulations ........................................................................................................ 34

4.3 Synchronized re-connection simulations ............................................................................ 36

5 Summary and conclusions ........................................................................................................... 39

5.1 Settings for Viinikantie recloser IED (IED_1) and diesel generator IED (IED_3) ................. 39

Over-current protection......................................................................................................... 39

Possible additional voltage protection in IED_1 (Viinikantie recloser) ................................... 40

Earth-fault protection ............................................................................................................ 41




Admittance based earth-fault protection ............................................................................... 43

5.2 Blackstart and synchronized re-connection ........................................................................ 50

6 References .................................................................................................................................. 51




1 Introduction In subtask 6.13.2 of WP 6 (Management and Operation of Smart Grids) the general purpose is to

demonstrate a generic concept for island operation and islanding in Hailuoto. The aim is that the

results from this task can be applied also in other networks with small changes, so that the solution

would not be a special solution only for this case. This Hailuoto proof-of-concept (PoC) has been

started in the 1st funding period (FP), and it is continued during the 2nd and 3rd FPs.

The target is to operate part of Hailuoto island in island mode (see Fig. 1.1).

Figure 1.1. Part of Hailuoto island to be used for islanding proof of concept is the area indicated with

white line.

In Hailuoto island operation demo the purpose is to develop and demonstrate in reality some active

management and protection adaptivity schemes for future smart grid concepts by utilizing

centralized, co-ordinated functionalities in HV/MV substation computer (e.g. COM 600). Before

demonstration in the real network, PSCAD simulations are required e.g. to determine protection

settings for different topologies.

This document for tasks 5.1 (Distributed Generation) of WP 5 (Active Resources) and task 6.13.2

includes first very short summary from few protection and active management related functionalities

required in future smart grids and a brief description from the re-built PSCAD simulation model and

in the end represents preliminary simulation results from different fault cases, blackstart and

synchronized re-connection with some conclusions. Blackstart means that in this first stage island




construction is carried out through interruption. However, for the future and from concept point of

view also the seamless islanding should be kept in mind right from the beginning.

2 Protection and active management related functionalities required in

future smart grids In following some examples from possible protection and active management related functionalities

required in future smart grids are shortly described. These functionalities can include for example:

1) Protection adaptivity to topology and earthing method changes (distributed vs.

centralized protection approaches)

2) Island operation capability and reliable islanding detection

3) Utilization of distributed IEDs at MV/LV distribution substations or at MV connected DGs

in active network management, fault location calculation and power quality monitoring

It is worth mentioning that in all above mentioned functionalities as well as in smart grids overall

communication plays major role. One way to realize active management and protection adaptivity in

future smart grids is utilization of centralized functionalities within HV/MV substation computers (or

station automation devices).

1) From point of view of protection principles and settings adaptivity to topology method

changes following aspects need to be considered:

Changes in topology from radial meshed or from normal island operation,

Changes in earthing method e.g. from isolated compensated due to topology

changes or faults in centralized compensation units etc.,

Changes in number of distributed generation (DG) units connected to corresponding

network, like for example DG unit connected to MV feeder disconnected,

Changes in number of protection zones

The number of protection zones in future smart grids will be increased as

available measurements, high-speed communication and control becomes

reality further away in MV networks and also in LV networks

Communication availability and possible changes in speed of available

communication channel etc.

Distributed vs. centralized protection approaches has been presented and possibly

combination of distributed and centralized is probable in near future

Capabilities, flexibility and possible challenges of different protection schemes (e.g.

distance protection, line differential, directional over-current, directional earth-fault,

admittance protection) to implement adaptive smart grid protection which can handle




topology, earthing method and changes in number of connected DGs needs to be

known as well as their depence on communication

Central activation of pre-calculated settings for different topologies – usage

of different setting groups or

Real-time calculation of protection settings based on knowledge from

changes in e.g. topology or amount of connected DGs in nearest network

nodes

Back-up protection if communication fails and primary protection relies on

communication availability

2) Similarly as above, from point of view of island operation capability and reliable islanding

detection following aspects needs to be considered:

Utilization of DER (DGs, energy storages, including electric vehicles, and load

shedding) for island operation to improve reliability of electricity distribution

Realization of island operation possibility depends from the development of

grid codes, regulation, standards etc.

Knowledge about island operation capability (i.e. transition possibility to island

operation) based on real-time power unbalance knowledge

Power flow (active and reactive power, P and Q) in connection point of

island with knowledge about current P and Q production of DG units

together with knowledge about available control capacity in island grid (e.g.

from DG units, energy storages, controllable or low-priority loads)

Island operation capability from DG unit fault-ride-through (FRT) capability and critical

clearing time (CCT) point of view and their effect to needed protection schemes,

settings, speed of operation etc.

Reliable islanding detection i.e. loss-of-mains (LOM) protection

Local measurements based passive detection methods (like for example

frequency (f), rate-of-change-of-frequency (ROCOF / df/dt), vector shift

(VS) / phase jump or voltage (U) based methods)

Two major drawbacks are large non-detection zone (NDZ) near power

balance situation and sensitivity to unwanted DG trips due to other network

events (nuisance tripping)

Proposed local detection methods have also traditionally been dependent

from DG type

With high-speed communication based LOM schemes e.g. transfer trip

signal from MV feeder IED to DG interconnection IEDs (utilization of optical




fibre or WiMax/LTE for communication of IEC 61850 based GOOSE

signals) these drawbacks of traditional LOM methods don’t exist, but there

are still challenges like for example

Availability and cost of high-speed communication

Flexibility of communication based LOM schemes to

topology changes

o Adaptivity and flexibility could be improved

through pre-configured settings (activation

centrally with HV/MV substation computer) or

automatic re-engineering of GOOSE signals

o Also more centralized, communication based

islanding detection schemes has been proposed

based on status checking of CBs in certain area

without a predetermined logic where islanding

detection algorithm has been installed in a

central controller which has connections to all

IEDs with IEC 61850 based communication and

utilizes also transfer trip with GOOSE messages

to disconnect DGs from islanded part of the

network

=> But, if centralized solutions are not available and communication fails or

is not high-speed enough or available at all (e.g. due to economic reasons

in the near future) also reliable LOM method based local detection is still

required in future, but it has to overcome the major drawbacks of traditional

LOM methods

Reliable, local measurements based island detection algorithm without

NDZ and nuisance tripping of DG units is still needed and the new islanding

detection algorithm must also be such that it can adapt or be adapted to

interconnection of different types of DG units

3) From point of view of utilization of distributed IEDs at MV/LV distribution substations or at MV

connected DGs in active network management, fault location calculation and power quality

monitoring following aspects needs to be considered:

Usage of both reactive and active power for voltage control needs to be taken into

account because also active power affects on voltage in distribution networks

Depends on network stiffness and R/X-ratio

Voltage control scheme during island operation may need adaptation of

voltage control logic




Hierarchical approach to voltage control of distribution networks

Voltage violations in distribution networks (e.g. MV feeder) could be managed first

with distributed, local devices with voltage control capability which are connected near

the area with voltage problems

If local voltage control along the MV feeder cannot fix the problem, then signal to

HV/MV substation computer to e.g. control the on-load tap-changer (OLTC) so that

voltage levels in each of the MV feeders can be sustained within normal limits

Increasing number of measurements from MV/LV substations in future could be used

to improve e.g. network estimation towards “real-time estimation” (could be also utilized

in different voltage control schemes), earth-fault location calculation and power quality

monitoring

2.1 Centralized functionalities at HV/MV substation computer for realization of active

management and adaptive protection in smart grids

In reference [1] substation level functionality has been divided based on the location and criticality of

the functions to unit level functions (mandatory and optional) and station level functions (mandatory

and optional). In [1] it has been proposed that the most important and time critical protection

functions could in the future run on the unit level (in single IEDs) but all additional functionality would

be moved to the HV/MV substation computer. Primary protection and control functions on unit level

should not rely on external communication so that safety is guaranteed even if communication is

lost. If only most important functionality is located in unit level, then updating and maintenance

activities will not affect the primary protection on the unit level. On station level updating is easier

and less expensive and therefore functions which need or make use of data from several sources or

are updated more frequently due to new inventions or new legislation could be located at HV/MV

substation computers. [1]

One way to realize active management and protection adaptivity in future smart grids is utilization of

these centralized functionalities within station computer, because these functionalities which

combine data from several sources are continuously developing and therefore more frequent

updates may be necessary. In following some functionalities in which co-ordination by HV/MV

substation computer could be useful in future smart grids

Active, co-ordinated hierarchical voltage control management on all MV

feeders by utilizing information from different locations together with

currently available, controllable resources like DER units and OLTCs

With add-on features like minimizing losses with topology changes etc.

Protection settings changing (i.e. changing of IED setting groups) based on

topology / earthing method changes

Improved fault locating

Island operation co-ordination (voltage and frequency control with DER,

blackstart and synchronized re-connection back to utility grid




Power quality level monitoring, verification etc. for example on MV/LV

substation level for different needs and applications

Dedicated management and protection solutions for wind farms to e.g.

prevent disconnection of all wind turbines due to fault at one of many

feeders with multiple wind turbines

2.2 Case Hailuoto

In Hailuoto island operation demo the purpose is to develop and demonstrate in reality some active

management and protection adaptivity schemes for future smart grid concepts by utilizing

centralized, co-ordinated functionalities in station computer (e.g. COM 600) (Fig. 2.1).

Figure 2.1. Hailuoto island demonstration scheme with relying on communication between station

computer (COM 600), different IEDs and diesel unit control system.

These functionalities include for example

1) Protection settings changing based on topology changes (i.e. changing of pre-

determined IED setting groups with pre-determined settings)

Normal without DGs Normal with DG/DGs

Normal Island

2) Active management and island operation related functionalities like for example

Blackstart (island construction) and

Synchronized re-connection back to utility grid (connection back to the mains)




Before demonstration in the real network, PSCAD simulations are required

1) To determine protection settings for different topologies

Normal operation without DGs

Normal operation with wind turbine and/or diesel

Island operation with diesel

2) To develop blackstart logic

In island operation after disconnection from utility grid

3) To develop synchronized re-connection logic

From island operation to normal operation parallel with utility grid




3 Hailuoto PSCAD simulation model and backround information The PSCAD simulation model of Hailuoto network was totally re-built due to illogical results obtained

with the previous version (done by TUT) especially during earth-fault simulations. Also the speed

control of diesel engine model has been a bit modified to deal with steady state frequency error

during island operation. The structure of the new Hailuoto PSCAD model is presented in Fig. 3.1.

Figure 3.1. Overview of the new Hailuoto PSCAD simulation model.

In following shortly few facts about the planned island area shown in Fig. 1 and 2

One diesel aggregate in Huikku, 1.4 MW (directly connected synchronous generator)

The diesel aggregate has two operation modes in the model. In normal mode,

diesel is running in parallel with the utility grid. In normal mode, the automatic

voltage regulator (AVR) is in reactive power control mode and the speed

controller in active power control mode i.e. PQ-control. In island mode, the

AVR of diesel is operating in voltage control mode and the speed controller in

speed control mode.

One wind turbine in Huikku

Currently 500 kW (directly connected squirrel cage induction generator) which

probably will be replaced in future with larger wind turbine (1.5 – 2 MW) (Used

induction generator based wind turbine simulation models are originally done

by Tampere University of Technology, TUT)

Simulations done with current 500 kW and larger (new) wind turbine




In PSCAD simulations voltage source based DG unit model done by Vaasa

Energy Institute (VEI) is used to model 2 MW wind turbine

Earthing method of MV network: isolated

Minimum and maximum loads in Hailuoto are approximately as following

Minimum load (in June)

Whole Hailuoto feeder

P = 421 kW, Q = 130 kVAr

Planned island area in Hailuoto

P = 246 kW, Q = 77 kVAr

Maximum load (in January)

Whole Hailuoto feeder

P = 1883 kW, Q = 587 kVAr

Planned island area in Hailuoto

P = 1144 kW, Q = 357 kVAr

In case of low load (i.e. near minimum load) it may be necessary to disconnect

Huikku wind turbine before transition to island operation to avoid operation of under-

power / reverse-power protection of Huikku diesel generator and blackout of whole

island

This disconnection decision should be dependent on current load in corresponding

island area which can be calculated by HV/MV substation computer if power

production of diesel generator and wind turbine as well as power flow in connection

point (Viinikantie recloser) is known




In following some more or less accurate current and initially planned protection settings in Hailuoto

are also shortly listed.

Siikajoki Substation (at the beginning of Hailuoto feeder) in normal operation

(Settings from network information system of distribution network operator, DNO)

Over-current (non-directional)

High-stage I>> time delay 150 ms

Low-stage set value I> 250 A, time delay 600 ms

Directional earth-fault protection (to operate in earth-faults up to 5000 ohms)

Residual voltage, Uo = 10 %

Residual current, Io_dir = 3.0 A (forward)

Time delay 400 ms

Viinikantie recloser (in connection point of planned island i.e. in middle of

Hailuoto feeder) in normal operation (Settings initially calculated by DNO)

Over-current (directional)

I> 120 A, time delay 300 ms

Directional earth-fault protection (to operate in earth-faults up to 5000 ohms)

Residual voltage, Uo = 5 %

Residual current, Io_dir = 2.0 A (forward)

Time delay 150 ms




Diesel generator (Huikku) (Settings from commissioning test records)

Frequency protection

f> 54 Hz, with time delay 1.3 s

f< 47 Hz, with time delay 2.9 s

Frequency control range 49.8-51.6 Hz

Voltage protection

U> 1.1 pu, with time delay 2.7 s

U< 0.85 pu, with time delay 2.5 s

Voltage control range 0.9275-1.065 pu

Under-power / Reverse-power protection

P = 130 kW, with time delay 12 s

Wind turbine (Huikku 500 kW) (Settings from PSCAD model done by Tampere

university of technology, TUT)

Frequency protection

f> 51.5 Hz, with time delay 0.2 s

f< 48.5 Hz, with time delay 0.2 s

Voltage protection

U>> 1.1 pu, with time delay 0.05 s

U> 1.085 pu, with time delay 60 s

U<< 0.5 pu, with time delay 0.1 s

U< 0.855 pu, with time delay 10 s

Over-current protection (LV side currents)

I>> 3150 A, with time delay 0.1 s

I> 550 A, with time delay 0.6 s




Transmission system operator (TSO) Fingrid has recently in the end of year 2011 updated grid

interconnection requirements for wind turbines including fault-ride-through (FRT) requirements for

new wind turbines in Finland presented in Fig. 3.2.

Figure 3.2. FRT requirements for new wind turbines in Finland [2].




4 Simulation results Before demonstration in the real network, PSCAD simulations are done to determine protection

settings for different topologies and to develop blackstart and synchronized re-connection logic.

In following the simulation results are presented from fault, blackstart and synchronized re-

connection simulations. The simulation results e.g. the dynamic response of the network in

simulations may not fully correspond to the real network. But after the measurements in Hailuoto,

the network model can be updated to correspond to the reality more accurately.

4.1 Fault simulations to determine protection settings for different topologies

Fault simulations were done in different cases listed below:

Case 1: Protection during normal operation without DGs (balanced network)

Case 2: Protection during normal operation with new wind turbine (balanced network)

Case 2b: Protection during normal operation with old 500 kW wind turbine (unbalanced

network)

Case 3: Protection during normal operation with diesel generator (balanced network)

Case 4: Protection during normal operation with diesel and wind (balanced network)

Case 4b: Protection during normal operation with diesel and old 500 kW wind turbine

(unbalanced network)

Case 5: Protection during island operation with diesel generator




In Fig. 4.1 principle of Iosin() based directional earth-fault protection is also presented.

Figure 4.1. Iosin() based directional earth-fault protection in an isolated network. [3]




Case 1: Protection during normal operation without DGs (balanced network)

In Fig. 4.2 load currents and fault types, fault locations and fault resistances in case 1 are presented.

Figure 4.2. Load currents and fault types, fault locations and fault resistances in case 1.




In Fig. 4.3 simulation results from case 1 are shown.

Figure 4.3. Simulation results from case 1.




Case 2: Protection during normal operation with new wind turbine (balanced

network)






Case 2b: Protection during normal operation with old 500 kW wind turbine

(unbalanced network)

In Fig. 4.6 load currents and fault types, fault locations and fault resistances in case 2b are

presented and in Fig. 4.7 simulation results from case 2b are shown.

Figure 4.6. Load currents and fault types, fault locations and fault resistances in case 2b.

Figure 4.7. Simulation results from case 2b.




Case 3: Protection during normal operation with diesel generator (balanced

network)



In Fig. 4.9 simulation results from case 3 are shown. In case of F0 fault, transition to island operation

must be very rapid to be able to maintain stability in island after transition. Critical clearing time

(CCT) for diesel generator (if protection operates within this time stability of diesel can be

maintained) in case of three-phase short-circuit fault (F0) before islanding was found to be 175 ms.

This means that time delay for Viinikantie recloser (IED_1) over-current protection in reverse

direction must be under or equal to 100 ms (if circuit-breaker operation takes for example 50 ms).

Based on previous simulations start value for over-current protection could be e.g. 80 A. In reality

this can be realized so that if COM 600 detects diesel generator to be connected during normal

operation, it changes IED_1 to setting group 2 (SG 2) in which settings in reverse direction for

directional over-current protection are defined (I> 80 A, time delay 100 ms). Other possibility is to

define in setting group 1 (SG 1) already settings in reverse direction when change of setting group is

not required when diesel generator is connected.





In case of F0 earth-fault, CCT of diesel generator is not necessarily that critical issue (depending on

fault resistance) and magnitude of earth-fault current seen by IED_1 in reverse direction is not

dependent on diesel generator or any other DG unit. In case of F0 earth-fault with low fault

resistance under voltage protection of IED_1 could take care of rapid transition to island operation.

However, earth-fault protection setting in reverse direction in Viinikantie recloser is needed in case

of F0 earth-faults, especially if voltage protection is not included in IED_1 protection functions =>

Can be included in setting group 2 in IED_1 which is activated when diesel generator is connected

to network and seamless transition to island operation is therefore possible. In case of F0 fault,

transition speed to island operation i.e. operation time delay in reverse direction could be e.g.

dependent on magnitude of residual voltage (Uo), but most important is selectivity with other earth-

fault protection settings in upstream network and with diesel.




Effect of diesel generator control mode change (normal => island) time delay

to stability after islanding in different cases in case 3

In Fig. 4.10 simulation results from effect of diesel generator control mode change time delay to

stability after islanding in different cases with case 3 configuration are presented. It can be seen

from results of Fig. 4.10 that surplus of active power (cases 1a, 1b) is most critical in terms of

allowed time delay for diesel generator control mode change after islanding to maintain stability and

with F0 fault happens before islanding the time delay must be even shorter i.e. < 1.0 s. In addition, if

for example settings of frequency protection in Huikku 500 kW wind turbine are too sensitive, wind

turbine may be disconnected also during seamless transition to island operation e.g. if settings are

f> 51.5 Hz, with time delay 200 ms and f< 48.5 Hz, with time delay 200 ms. On the other hand, if for

example setting of over-voltage protection (or under-voltage) in Huikku wind turbine is too sensitive,

it may also be disconnected in certain power unbalance situations due to that during seamless

transition to island operation e.g. if setting is U>> 1.1 pu, with time delay 50 ms. In Fig. 4.11

simulation results from frequency and voltage behavior are presented as an example from case with

power unbalance in island area (measured at Viinikantie recloser) ∆P = + 30 kW and ∆Q = -336

kVAr before transition to island operation (islanding at t = 10.0 s) and time delay for diesel generator

control mode change is 250 ms.

Figure 4.10. Simulation results from effect of diesel generator control mode change

(normal=>island) time delay to stability after islanding in different cases with case 3 configuration.




Figure 4.11. Simulation results from frequency and voltage behavior with power unbalance ∆P = +

30 kW and ∆Q = -336 kVAr before islanding (t=10 s) and mode change delay is 250 ms.

Case 4: Protection during normal operation with diesel and wind (balanced

network)

In Fig. 4.12 load currents and fault types, fault locations and fault resistances in case 4 are

presented.




Case 4b: Protection during normal operation with diesel and old 500 kW wind

turbine (unbalanced network)

In Fig. 4.14 load currents and fault types, fault locations and fault resistances in case 4b are

presented and in Fig. 4.15 simulation results from case 4b are shown.

Figure 4.14. Load currents and fault types, fault locations and fault resistances in case 4b.




Case 5: Protection during island operation with diesel generator

In Fig. 4.16 load currents and fault types, fault locations and fault resistances in case 5 are

presented.





Case 5b: Protection during island operation with diesel generator and 500 kW

wind turbine (unbalanced network)

In Fig. 4.18 fault types, fault locations and fault resistances in case 5b are presented.

Figure 4.18. Fault types, fault locations and fault resistances in case 5b.




In Fig. 4.19 simulation results from case 5b are shown.





4.2 Blackstart simulations

In following simulation results from blackstart simulations are presented to study frequency and

voltage transient magnitudes and durations due to connection or disconnection of approximately half

of the load during opening or closing the Potti disconnector. The simulations were done with almost

maximum load situation.

In general, the control mode of diesel generator (normal or island mode) is dependent on the status

of CB in Viinikantie. If Viinikantie recloser is opened by IED_1 (Fig. 4.20) diesel generator

automatically changes based on COM 600 command (after time delay due to communication speed

etc.) from normal mode PQ-control to in island mode speed + voltage control. All load in the island

cannot be connected simultaneously during diesel generator start-up and therefore load is

connected in two steps.

Figure 4.20. Blackstart sequence used in simulation (unbalanced network).

In Fig. 4.21 simulation results from blackstart simulation are shown. Correspondingly, in Fig. 4.22

simulation results from the effect of large load disconnection by opening Potti disconnector during

island operation with max. load at t= 20.0 s are presented.




Figure 4.21. Simulation results from blackstart (Potti disconnector is closed at t=35.0 s).

Figure 4.22. Simulation results from load disconnection (Potti disconnector opened at t=20.0 s).




4.3 Synchronized re-connection simulations

Synchronized re-connection is needed especially with directly connected synchronous generators

based DG units (diesel generator) in this case, because severe damage to the generator may occur

due to re-connection with e.g. large voltage phase angle difference across circuit breaker at the

connection point of island operated network. Transient power oscillations after switching events will

cause torsional effort in the turbine-generator set and cumulatively these fatigue effects will reduce

its expected life time. The severity of the torsional effort can be evaluated through the behavior of

electric power i.e. after switching, the maximum acceptable change in the electric power is about ≤

±50% of the generator MVA capacity and if transient stays under that limit after re-connection it will

not reduce the generators expected life time.

Re-connection logic could be built-in station computer COM 600. Re-connection is allowed when

following conditions are fulfilled (Fig. 4.23):

Diesel generator is in island mode control (speed control & voltage control), because

CB/recloser in Viinikantie is open

Voltage at both sides of CB in Viinikantie can be detected

Synchronized re-connection logic is activated in COM 600 is activated and

synchronizing function at Viinikantie CB is activated

When the conditions determined by settings of synchronization function in Viinikantie

IED are fulfilled, CB at Viinikantie is closed by IED_1. Synchronized connection is

possible if

Voltage phase angle difference (∆) across CB in Viinikantie is under the set

value

Voltage magnitudes difference (∆U) across CB in Viinikantie is under the set

value

Frequency difference (∆f) across CB in Viinikantie is under the set value

Voltage magnitudes difference (∆U) across CB in Viinikantie is communicated (e.g.

with COM 600) either directly to control system of diesel or first to IED_3 and through

it to diesel generator’s control system) as an additional variable/control loop to voltage

control system of diesel generator which the control system tries to minimize

Small frequency difference between utility grid and island grid may be needed to

achieve needed small (∆) across CB in Viinikantie at some point

Needed frequency difference (∆f) across CB in Viinikantie can be

communicated from COM 600 to speed control system of diesel generator

(increase or decrese speed in steps) or control of generator could be

modified during synchronized re-connection to speed up the fulfillment of

phase angle (∆) criterion as part of synchronized re-connection

logic/settings




After successful re-connection, based on signal from COM 600 or IED_1 or

alternatively based on local islanding ON/OFF detection of IED_3 (Fig. 4.23) either

Control mode of diesel generator is automatically changed back from island to

normal mode after time delay due to communication etc. (which in simulations is

dependent on the status of CB in Viinikantie) or

IED_3 shuts down and disconnects the diesel generator

Figure 4.23. Implementation of synchronized re-connection logic etc. in simulation (unbalanced

network).

In simulation settings needed to be fulfilled to allow synchronized re-connection (i.e. closing

Viinikantie recloser Fig. 4.23) were ∆=±7.5, ∆U=±0.03 pu, ∆f=±0.7 Hz. Following synchronized re-

connection logic was activated at t=50.0 s:

• Voltage magnitudes difference (∆U) across CB in Viinikantie was communicated to

voltage control system of diesel

• Speed control mode of diesel generator is modified to enable synchronized re-

connection i.e. not anymore to minimize steady state frequency error during island

operation




• When the conditions determined by settings are fulfilled, CB at Viinikantie is closed by

IED_1 at t = 50.725 s

• At t = 50.725 + 2.5 s diesel generator control mode change after synchronized re-

connection from island to normal mode (time delay included)

Simulation results from re-connection are presented in Fig. 4.24. Change in the electric power is

about 27 % of the generator MVA capacity (Fig. 4.24).

Figure 4.24. Simulation results from synchronized re-connection (synchronized re-connection logic

is activated at t=50.0 s and re-synchronization at t = 50.725 s).




5 Summary and conclusions In following discussion and conclusions from simulations as well as some proposal for possible

protection settings are presented based on previous simulation results.

5.1 Settings for Viinikantie recloser IED (IED_1) and diesel generator IED (IED_3)

Over-current protection

Preliminary proposed settings and setting groups for over-current protection are presented in Fig.

5.1. In case of F0 fault (Fig. 5.1), transition to island operation must be very rapid to be able to

maintain stability in island after transition. From case 3 simulation results it could be concluded that

if COM 600 detects diesel generator to be connected during normal operation, it changes IED_1 to

setting group 2 (SG 2) in which settings in reverse direction for directional over-current protection

are defined (Fig. 5.1). Same conclusions and settings discussed as well as presented in case 3 are

also valid in cases 4 and 4b with both diesel generator and wind turbine connected during normal

operation. Therefore, setting group change of IED_1 from SG 1 to SG 2 is only dependent on

presence of diesel generator.

Figure 5.1. Preliminary proposed settings and setting groups for over-current protection.




Possible additional voltage protection in IED_1 (Viinikantie recloser)

From general concept point of view other possibility to ensure stable island operation after islanding

(seamless islanding) due to F0 3-phase short-circuit fault or voltage dip (e.g. after autoreclosure in

upstream network) is usage of voltage protection in Viinikantie recloser (IED_1) in setting group

when seamless islanding is possible (in this Hailuoto case when diesel is running).

Settings of voltage protection (IED_1) with proper time delay must be such that critical-clearing-time

(CCT) of diesel generator is not exceeded (see Fig. 5.2):

U<< 0.75 pu, time delay 100 ms, U< 0.91 pu, time delay 300 ms

Also settings for over-voltage protection at connection point (IED_1) would be recommended to

ensure seamless transition and long duration over-voltages for island area customers:

U>> 1.25 pu, time delay 100 ms, U> 1.11 pu, time delay 300 ms

Figure 5.2. Possible additional voltage protection in IED_1 (Viinikantie recloser).




Earth-fault protection

Preliminary proposed settings and setting groups for earth-fault protection are presented in Fig. 5.3.

Figure 5.3. Preliminary proposed settings and setting groups for earth-fault protection.

In case of F0 earth-fault (Fig. 5.3), CCT of diesel generator is not necessarily that critical issue

(depending on fault resistance) and magnitude of earth-fault current seen by IED_1 in reverse

direction is not dependent on diesel generator or any other DG unit. In case of F0 earth-fault with

low fault resistance under voltage protection of IED_1 (see Fig. 5.2) could take care of rapid

transition to island operation. However, earth-fault protection setting in reverse direction in

Viinikantie recloser is needed in case of F0 earth-faults, especially if voltage protection (Fig. 5.2) is

not included in IED_1 protection functions. Voltage protection could be included in setting group 2

(SG 2) in IED_1 which is activated when diesel generator is connected to network and seamless

transition to island operation is therefore possible.

In following few remarks about proposed earth-fault settings in Fig. 5.2:

IED_3 (diesel)

In normal operation, SG 1, (parallel with utility grid) time delay depends also from the

time delay of residual voltage protection Uo of the whole Siikajoki 45/20 kV substation

In island operation, SG 2, time delay could be shorter (e.g. 500 ms), because no

other protection zones inside island exists and also setting could be higher during

island operation e.g. 15 % (based on simulations this setting is sensitive enough to

detect also faults with high fault-resistance) if larger unbalance and healthy state Uo

values are realised during islanding

IED_1 (Viinikantie recloser)

Time delay of IED_1 setting in reverse direction is quite long (600 ms) to ensure

selectivity with IED_feeder (400 ms) which could e.g. in F0 1-phase earth-faults with

low fault-resistance introduce large long duration (>400 ms in this case) over-voltages




to island area customers if IED_1 is not equipped with voltage protection as

presented before

Time delay of IED_1 earth-fault protection in reverse direction at Viinikantie

could also be shorter than 600 ms (e.g. 150 ms) if voltage protection with

short time delays does not exist at IED_1

However, then frequent ”unnecessary” seamless transitions (if islanding

conditions are fulfilled, diesel running etc.) to island operation may take

place in case of earth-faults on adjacent feeders or F0 fault in upstream of

the same Hailuoto MV feeder from Viinikantie recloser

If voltage protection with short time delays does not exist in IED_1 and

seamless islanding is possible (Diesel running) then, in case of F0 fault,

transition speed to island operation i.e. operation time delay in reverse

direction could also be e.g. dependent on magnitude of residual voltage

(Uo), => e.g. 150 ms when Uo is 90 % and 600 ms when Uo is 10 % etc.

However, time delay is not currently possible to be adjusted in this way.

In general, if proper communication link would be available then both directional over-

current and earth-fault protection could be made to operate faster without losing

selectivity by usage of high-speed GOOSE interlocking signals between IEDs

In simulations during 1-phase earth-faults magnitude of zero current (I0) was reduced and magnitude

of zero voltage (U0) was increased during island operation when compared to normal operation with

same fault resistance (e.g. Rf = 500 ohm). Although in normal operation U0 values increased in

every case from case 1 to case 4 due to increased amount of DG. On the other hand, in all cases 1-

5 regardless of the operation state (normal with DGs connected or not / island with diesel)

comparison of simultaneous U0 magnitudes in earth-faults, especially with high fault resistance Rf,

from different IEDs could be useful in fault locating if e.g. I0 (in isolated network I0sin() largest

closest to the fault) measurement is not available. Magnitude of U0 is lowest near the fault location in

simulations with totally symmetrical network. However, differences in magnitude of U0 especially

during island operation in case 5 are very small in different locations. Comparison of U0 values from

different IEDs could be done in a centralized way with COM 600 if precise, time-stamped,

comparable measurements (e.g. sensor based) are available. In simulations with unbalanced

network (unbalanced load and healthy state U0 1%) magnitude of U0 was not necessarily lowest

near the fault location especially with high-resistance faults.




Admittance based earth-fault protection

Instead of comparison of simultaneous U0 and/or I0 magnitudes and direction in a centralized way

with substation computer to locate earth-faults, also comparison of zero admittance Y0

measurements could be utilized for fault locating and also for directional earth-fault protection alone

instead of Iosin() or Iocos() based earth-fault protection. The major benefit of admittance based

protection on contrary e.g. to Iosin() based protection (Fig. 4.1) is the fact that fault resistance

magnitude (to certain extent e.g. few tens of kilo-ohms) does not have effect in earth-fault detection

capability of it. In Fig. 5.4 the basic principle of admittance based earth-fault protection is shortly

presented.

Figure 5.4. Admittance based directional earth-fault protection. [3]

The possible utilization of admittance based earth-fault protection is high-lighted with few

simulations from faults presented in Fig. 5.5.




Figure 5.5. Location of faults in simulations about utilization of admittance based directional earth-

fault protection.

In following figures Fig. 5.6, 5.7, 5.8, 5.9 and 5.10 simulation results from 1-phase earth-faults with

different fault resistances (Rf) is presented as an example to compare usage of admittance (Yo)

based detection and earth-fault locating in comparison to residual current (Io) and residual voltage

(Uo) based protection. From simulation results it can be clarly seen how the calculated admittance

values are not dependent of fault resistance values. However, network unbalance has some effect

on capability to utilize admittance harmonic components as part of the admittance based earth-fault

protection.

Comparison of simulation results in balanced and unbalanced cases also shows that in unbalanced

network with low residual voltage U0 value (due to high fault-resistance) (Fig. 5.9 in comparison to

Fig. 5.7 and 5.8) only B0 fundamental frequency components (or I0 magnitudes) should be compared

with each other in order to detect direction and location of fault correctly.




Figure 5.6. Simulation results of admittances and residual currents and residual voltages in Case 1

from 1-phase earth-faults (Rf = 0.0001 ohm, 750 ms) in different locations (F0, F1, F2, F3) (see Fig.

5.5) with balanced network.





from 1-phase earth-faults (Rf = 0.0001 ohm, 750 ms) in different locations (F0, F1, F2, F3) (see Fig.

5.5) with unbalanced network.





from 1-phase earth-faults (Rf = 5000 ohm, 750 ms) in different locations (F0, F1, F2, F3) (see Fig.







5.5) with unbalanced network.




5.2 Blackstart and synchronized re-connection

Blackstart simulations

o During blackstart sequence frequency (f<,f>) protection of Huikku wind turbine (if

connected) may need to be blocked (if possible and depending on the settings) or

alternatively the settings used in corresponding setting group during islanding could

be wider with longer time delays than during normal operation

Alternatively, wind turbine with island operation setting group activated could

be connected to island in the end of blackstart sequence (i.e. after load re-

connection) depending on current loading conditions (generator P and Q) etc.

In addition, LOM protection like df/dt could operate, but it should not be able to

operate during island operation

Synchronized re-connection simulations

The minimization of voltage magnitudes difference (∆U) across CB in Viinikantie with additional

voltage control loop in voltage control of diesel generator by communicating the ∆U to voltage

control system of diesel functioned well. However, constant ∆U minimization control with diesel unit

additional voltage control loop has potential threat to lead in unwanted voltage oscillations if the

controller parameters are not chosen properly. Therefore, also possible communication of only

required step change ∆U i.e. new set point value (Fig. 5.11) to voltage control (excitation) system of

diesel generator was simulated and it was found to function well and could be more relevant to be

implemented in reality.

Figure 5.11. Required step change ∆U i.e. new set point value to voltage control (excitation)

system of diesel generator was found to function well and could be more relevant to be

implemented in reality than constant ∆U minimization with modified diesel unit control like in

Fig. 4.23.

After switching the maximum change in the electric power was about 27% from nominal capacity

(should be about ≤ ±50% of the generator MVA capacity). From simulations it could be seen that the

allowed phase angle difference before re-connection (∆=±7.5) could lead to re-opening of CB in




Viinikantie if setting of ∆f is not large enough or if the re-synchronization logic does not block the re-

opening of CB with a certain time delay. This problem is even more probable with constant power or

voltage dependent load scenario. In general, also all possible setting group changes associated with

transition from island to normal operation or vice versa should be done with sufficient time delays so

that possible oscillations and transients after transtion have decayed. Other possibility is to block the

protection functions during transitions e.g. when re-synchronization logic from island to normal

operation is activated.

6 References [1] J. Valtari, T. Hakola, P. Verho, 2010, “Station Level Functionality in Future Smart

Substations”, Nordac 2010.

[2] http://www.fingrid.fi/portal/suomeksi/uutiset/ajankohtaista?bid=1404

[3] ABB Ltd, Relion, Protection and Control, 615 series Technical Manual, Version 3.0, 2010.

http://www.fingrid.fi/portal/suomeksi/uutiset/ajankohtaista?bid=1404

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