This project has received funding from the European Union’s Seventh Framework Programme for research, technological development and demonstration under grant agreement no. 608998.
Hands on Manual for DSOs
December 2016
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TABLE OF CONTENTS
1 INTRODUCTION 4
2 THE INCREASE FIELD TRIALS OVERVIEW 5
2.1 THE EANDIS FIELD TRIAL IN BELGIUM 6
2.2 THE ELEKTRO GORENJSKA FIELD TRIAL IN SLOVENIA 7
2.3 THE LIANDER FIELD TRIAL IN THE NETHERLANDS 9
2.4 THE ENERGIENETZE STEIERMARK FIELD TRIAL IN AUSTRIA 12
3 THE INCREASE FIELD TRIALS‐IMPORTANT INSIGHTS 14
3.1 THE EANDIS FIELD TRIAL IN BELGIUM 14
Design & preparition phase 14 3.1.1
Implementation & installation phase 14 3.1.2
Operational phase 15 3.1.3
3.2 THE ELEKTRO GORENJSKA FIELD TRIAL IN SLOVENIA 15
Design & preparAtion phase 16 3.2.1
Implementation & installation phase 20 3.2.2
Operational phase 21 3.2.3
3.3 THE LIANDER FIELD TRIAL IN THE NETHERLANDS 22
Design & preparAtion phase 22 3.3.1
Implementation & installation phase 23 3.3.2
Operational phase 23 3.3.3
3.4 THE ENERGIENETZE STEIERMARK FIELD TRIAL IN AUSTRIA 23
Design & preparAtion phase 23 3.4.1
Implementation phase 24 3.4.2
Operational phase 24 3.4.3
4 SYNTHESIS OF INSIGHTS 25
5 RECOMMENDATIONS AND GUIDANCE FOR DSOS 26
3
List of figures Figure 2.1. INCREASE field trials: location and description 5
Figure 2.2 Comparison of different OLTC control strategies 6
Figure 2.3 Statistical analysis of average phase voltages 8
Figure 2.4 The effect of EDC on voltage profile 10
Figure 2.5 Operation of EDC and FPS 10
Figure 2.6 Comparison of PV injection after different controls 10
Figure 2.7 Congestion management ‐ total loading of transformer 11
Figure 2.8 Congestion management – relative curtailment per inverter 11
Figure 2.9 Reduction of the neutral current in case of unbalance mitigation control activation 12
Figure 2.10 Impact of the unbalance control on PVUR and neutral current 12
Figure 3.1 EG wired network 19
Figure 3.2 EG optical network 19
Figure 3.3 LVN topology 20
Glossary
OLTC On‐Load tap changer
PVUR Phase voltage unbalance rate
DSO Distribution system operator
DRES Distributed renewable energy sources
LDC Line drop compensation
RTU Remote terminal unit
xWDM Wavelength division multiplexer
FPS Functionalities of fair power sharing
LVN Low‐voltage network
P/V control Voltage droop characteristic
RTU Remote terminal unit
NG‐SDH Next generation synchronous digital hierarchy
Acknowledgments
This document was prepared by Bart Meersman (Ghent University); Andreas Tuerk and Veronika Kulmer
(Joanneum Research); Marjan Jerele (Elektro Gorenjska); Gregor Podbregar (KORONA); Ruth Van Caenegem
(Eeandis); Gregor Taljan (Energienetze Steiermark) and Jan Bozelie (LIANDER).
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1 INTRODUCTION Future decentralized electricity systems will pose additional challenges for existing market actors, including
distribution system operators (DSOs). New technologies, innovations and business models are being tested in a
variety of EU funded projects. First insights report numerous challenges, risks as well as opportunities ranging
from technical constraints to real‐life barriers when implementing new solutions. Moreover these new
solutions impose challenges to the regulatory framework. In this context, INCREASE has gained additional
insights in these issues, which will be shared and discussed with DSOs, market actors and others who will play a
central role in the future electricity market. Therefore, the aim of this hands‐on manual is to provide lessons
learned from INCREASE with a focus on the experiences gained in the field trials from the design,
implementation and operation phase. Furthermore, the manual aims to support DSOs to better plan and
implement smart grid solutions in different environments, such as in the industry or at the household level.
The document is structured as follows: Section 2 gives an overview of the aim and result of each INCREASE field
trial, while the following section reports the insights of the various INCREASE field trials, followed by a synthesis
of barriers related to the design, implementation and operation of the demos we encountered and solutions
we found (Section 4). Finally in Section 5, the document gives practical recommendations on how to improve
the design and implementation of the new solutions such as the ones successfully developed in INCREASE.
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Dutch field trial
DSO: Liander
Location: Holiday park Bronsbergen
Pilot network: Low‐voltage (LV) network of
the first micro‐grid in the Netherlands with a
high share of PV (installed in approx. 50 % of
210 cottages).
Austrian field trial
DSO: ENERGIENETZE STEIERMARK
Location: Main administration building of
ENERGIENETZE STEIERMARK in Graz
Pilot network: Roof‐mounted part of a PV
installation, which consists of several single‐
phase PV inverters with a total installed
capacity of 47 kWp.
Belgian field trial
DSO: Eandis
Location: Koningshooikt, a rural region near
Mechelen
Pilot network: Cable type LV network with a
significant share of DRES on the LV level as
well as on medium‐voltage (MV) level. Main
types of DRES are PV and combined heat and
power (CHP).
Slovenian field trial
DSO: Elektro Gorenjska
Location: Village Suha near Kranj
Network demonstration: Rural cable type
network with a high penetration of PV. The
total installed capacity of the PV is 210 kW.
2 THE INCREASE FIELD TRIALS OVERVIEW Within the INCREASE field trials, the developed local and overlaying control strategies were tested in real
network environments of different European DSOs. Figure 2.1 illustrates the location of each field trial and
provides a description of key technical characteristics of the applied tests.
Figure 2.1. INCREASE field trials: location and description
KEY FACTS
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2.1 THE EANDIS FIELD TRIAL IN BELGIUM
In the scope of the Belgian field trial, carried out by Eandis, extensive tests of the OLTC performance have been
employed (starting at the end of 2014 until the end of 2015). During these tests valuable information and
experience regarding tackling voltage variations without using controllable inverters were obtained. The
Belgian field trial served as an initial trial for overlaying control functionalities, since on‐load tap changer (OLTC)
control is one of its main building blocks. The following different OLTC control strategies were tested and
evaluated:
Basic local OLTC control, with a fixed voltage set‐point, where the OLTC adjusts the tap to obtain a
pre‐defined voltage set‐point at the LV bus of the transformer.
Line drop compensation (LDC) OLTC control, which is the basic local OLTC control with the adjusted
voltage set‐point, based on the active power flow through the transformer.
o The voltage set‐point is increased in case of power flows into the network, to compensate
potential voltage drops.
o The voltage set‐point is reduced in case of reverse power flows from the network, to
compensate potential voltage rises.
Centralised (remote) OLTC control.
The first and second OLTC control strategy are of the classical type, which operate based on the local
parameters (voltage at the LV bus of the transformer). The third strategy operates on a central location (DMS
in the control centre of Eandis) based on measurements from multiple points of the network. Thus adequate
communication and measurement infrastructure is required.
Figure 2.2 provides a statistical comparison of the voltage measurements at key nodes of the pilot network. For
the evaluation, the results are compared to a business as usual scenario without OLTC control.
Figure 2.2 Comparison of different OLTC control strategies
We conclude that the basic local OLTC control improves the voltage only locally at the LV bus of the
transformer and the shortest LV feeder. High voltage variations remain in case of the longest LV feeder, since
the basic local OLTC control does not consider voltage conditions of other nodes in the network. In case of LDC
and centralised OLTC control, an overall improvement of the voltage was observed, since the voltage variations
are significantly reduced, also at the end of the longest LV feeder.
7
We find a similar performance of LDC and centralised OLTC control, especially considering the most critical
points at the end of the longest LV feeder. Based on these findings, EANDIS decided that the most suitable
OLTC control strategy for the future implementation would be LDC control, since there is no need to invest in
additional communication and measurement infrastructure (as in case of centralised control). There is also a
reduced risk in case of communication failure and hence no requirement of a back‐up for the local OLTC
control.
Note that in some cases the performance of LDC and centralised control will not be similar, therefore the
voltage conditions of the observed LV network have to be adequately considered in the selection of the
optimal OLTC control strategy.
2.2 THE ELEKTRO GORENJSKA FIELD TRIAL IN SLOVENIA
The Slovenian field trial implemented by Elektro Gorenjska was an upgrade of the Belgian field trial, since
besides OLTC control also the INCREASE local control for mitigation of over‐voltages was tested. For practical
reasons, the functionality of the local control (PV droop control) was realised using a controllable load instead
of a controllable PV inverter. That way potential issues which could arise from interactions with private owned
PV installations were avoided.
The following demonstration scenarios were evaluated in the scope of the Slovenian field trial:
Sc1: business as usual, no control measures applied.
Sc2: basic local OLTC control, with fixed voltage set‐point.
Sc3: INCREASE centralised OLTC control, using average phase voltages.
Sc4: INCREASE centralised OLTC control, using minimal and maximal phase voltages.
Sc5: INCREASE local control (using controllable load) only.
Sc6: coordinated control: basic local OLTC control and INCREASE local control.
Sc7: coordinated control: INCREASE centralised OLTC control (phase voltages) and INCREASE local
control.
The results, provided in Figure 2.3 are presented for four key nodes of the pilot network, namely:
The LV bus of transformer.
PV Urh, a 22 kW PV unit, where the highest voltages occur and the controllable load is deployed.
PV Bassol, a 22 kW PV unit.
Suha 56, a node where the lowest voltages are experienced.
Sc1 reveals significant voltage variations in the pilot network. There are voltage rises at PV units and voltage
drops at the end of the longest feeder without PV. Similar to the Belgian field trial, the basic local OLTC control
(Sc2) only improves the voltage locally at the LV bus of the transformer where voltages are concentrated
around a given set‐point of 235 V. High voltage variations remain, especially in case of PV Urh.
Centralised OLTC control, developed within INCREASE (Sc3 and Sc4) results in more variations at the LV bus of
the transformer, but improves the voltage at other critical nodes. Better results are obtained in case of Sc4,
where the OLTC control considers minimal and maximal phase voltages – the voltage at the node with highest
voltage drops is slightly increased, while significant voltage variations at PV Urh and PV Bassol are reduced.
8
Figure 2.3 Statistical analysis of average phase voltages
Sc5 aimed to evaluate the performance of the INCREASE local control for the mitigation of over‐voltages,
without the support of the OLTC. The load started to consume electricity generated by PV units, when the
voltage of PV Urh exceeded a value of 236 V. The controllable load (INCREASE local control) contributed to
reduced voltage rises at PV Urh.
In Sc6 there was a coordinated control of a basic local OLTC control and the INCREASE local control for the
mitigation of over‐voltages. Similar as in case of Sc2 (basic local OLTC control), the most significant voltage
improvement is achieved on the LV bus of the transformer. In addition, the voltage rises are reduced at PV Urh,
due to PV curtailment using a controllable load.
Compared to Sc6, an overall improvement of the voltage was achieved in Sc7, since both the lowest and
highest voltages were considered. The lowest voltages are mainly tackled by the centralised INCREASE OLTC
control (using phase voltages), which has a priority to solve the lowest voltages in the network by increasing
the tap position. The highest voltages on the contrary are reduced with the INCREASE local control, installed at
PV Urh, with the most significant voltage rises.
In the scope of the Slovenian field trial, all solutions were successfully validated; however a more significant
impact of the control strategies, especially the coordinated control, was expected before the trial. This is due to
several challenges, faced during the implementation and operation phase:
Due to the network configuration (high PV generation and long feeders without PV), there are nodes
with low voltages and other nodes with high voltages hampering the operation of the OLTC (tap
adjustment would improve voltage in some parts of the network, while the voltage in the other parts
of the network would be deteriorated).The coordinated control of the INCREASE centralised OLTC
control using phase voltages and INCREASE local control (PV curtailment) is a possible solution for this
challenge.
High voltage unbalances hinder the operation of OLTC control, especially controls based on average
phase voltages (Scenario 3).
Transformer PV Urh
PV Bassol Suha 56
9
To obtain an optimal OLTC control, extensive tests of different algorithms and control settings of OLTC must be
performed over a longer period, e.g. one year. This also applies to the INCREASE local control, where tests
should cover different seasons in order to identify the optimal settings, i.e. voltage thresholds where PV
curtailment is initiated and voltage thresholds where PV generation must be switched off.
In case that the LV network is experiencing low and high voltages at the same time, one solution (only OLTC)
might not be sufficient to cope with these issues. Therefore a combination of several measures (e.g.
coordinated control) is recommended.
2.3 THE LIANDER FIELD TRIAL IN THE NETHERLANDS
In the scope of the Dutch field trial implemented by Liander, the local control strategy to mitigate over‐voltages
as well as overlaying control functionalities “fair power sharing” (FPS) and “congestion management of the
distribution transformer” were tested. These strategies were implemented by means of new Mastervolt PV
inverters, which have the capability to remotely adjust the active power output.
Since the new Mastervolt inverters were not able to implement a P/V droop control on a hardware level, a
different approach was applied to incorporate the INCREASE control strategies. Liander decided to integrate
the P/V droop control into the ICT environment (middleware layer) of Mastervolt’s IntelliWeb cloud platform,
which implies the use of a web portal for the remote monitoring of the performance of the PV installation. The
platform was modified in order to enable the remote adjustment of PV generation (two‐way communication).
From a technical point of view active power limiting set‐points were used based on the inverters’ near real‐
time measurements of the voltage and active power. These set‐points are calculated by means of P/V droop
characteristics. In order to distinguish between physically integrated droop control and the approach taken in
the Dutch field trial, an emulated droop control (EDC) was used.
Three basic scenarios were conducted, namely the operation of emulated droop control (EDC), fair power
sharing (FPS) and congestion management. Figure 2.5 provides some results of the EDC and FPS operation on
the 25th October 2016. Measurements were acquired from inverters at 2 locations. Figure 2.4 illustrates voltage
measurements, while Figure 2.5 shows active power measurements and active power limiting set‐points
provided by EDC and FPS.
As illustrated in Figure 2.5 inverters were allowed to operate at 100 % available PV injection for approximately
two minutes. This corresponds to the initial procedure of the EDC. Later, the EDC initiated PV curtailment, since
the voltage of the inverter exceeded the threshold of 218.5 V (for activating the PV curtailment).
A slight reduction of the voltage was found subsequent to the PV curtailment. Active power measurements
illustrated in Figure 2.5 indicate that after the EDC was activated, PV generation (curtailment) was not equally
redistributed among the observed inverters. Therefore, around 15:39 FPS started and provided new active
power limiting set‐points for both inverters in order to ensure an equal distribution of the PV output. The
comparison of PV injection before and after activating the EDC as well as after activating FPS is illustrated in
Figure 2.6.
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Figure 2.4 The effect of EDC on voltage profile
Figure 2.5 Operation of EDC and FPS
Figure 2.6 Comparison of PV injection after different controls
In the following, an analysis of the congestion management is provided. Figure 2.7 provides measurements of
the total active power through the distribution transformer. Due to changing weather conditions (heavy cloud
passing), some fluctuations in power are visible. There was a continuous reverse power flow for more than 9
minutes and the congestion management was activated at approx. 11:40. We identified 16 inverters
participating in the control action. The number of inverters, activated during congestion management depends
227
228
229
230
231
232
233
15:28 15:31 15:34 15:37 15:40 15:43 15:46 15:48
Voltage (V)
Time
Upoc 49 Upoc 172
0
500
1000
1500
2000
2500
3000
15:28 15:31 15:34 15:37 15:40 15:43 15:46 15:48
Active pow
er (W
)
Time
Pinj 49 Pinj 172 Pset 49 Pset 172
0
500
1000
1500
2000
2500
3000
No control EDC FPS
Active power (W)
Pinj 49 Pinj 172
NO CONTROL EDC
EDC REDUCES VOLTAGE
FPS
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on the reliability of the Wi‐Fi communication. Due to communication issues, the amount of controllable PV
power within the congestion management was limited.
Analysing the total power flow through the transformer (Figure 2.7) we find that the reverse power flow was
reduced after the activation of the congestion management. In this specific case however the amount of
curtailed PV generation is extremely small, suggesting that the reduction could also be a consequence of
changed solar irradiation and/or load conditions in the network. An adequate response of the congestion
management is illustrated in Figure 2.8, which shows the response of the inverters. If communication would be
more reliable, more controllable power would be available and the impact on the transformers’ total loading
would be more significant.
Also in case of congestion management, the principle of fairness is considered. This is illustrated in Figure 2.8,
where all inverters show similar values of relative PV curtailment.
Figure 2.7 Congestion management ‐ total loading of transformer
Figure 2.8 Congestion management – relative curtailment per inverter
Within the Dutch field trial, all proposed control concepts were successfully validated, despite several
unpredicted technical challenges, related with real‐life implementation, for example:
Unreliable communication with inverters (Wi‐Fi).
Firmware issues of inverters, causing disconnection after new active power limiting set‐points were
set.
Small amount of controllable PV power (new inverters), compared to uncontrollable PV power (old
inverters).
‐20
‐15
‐10
‐5
0
5
10
11:05 11:10 11:15 11:20 11:25 11:30 11:35 11:40 11:45 11:50
Active pow
er (kW)
Time
Total loading Loading threshold
0,00
10,00
20,00
30,00
40,00
50,00
60,00
70,00
80,00
90,00
100,00
u1a u1b u3a u5b u6a 24a 28a 28b 46 49 111 116a 116b 125a 172 192
PV curtailment (%)
Inverter number
9‐min
Control reacts
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Challenges related with the modification of the cloud platform, originally meant for one‐way
communication.
Changing weather conditions.
2.4 THE ENERGIENETZE STEIERMARK FIELD TRIAL IN AUSTRIA
In the scope of the Austrian field trial implemented by Energienetze Steiermark, the performance of the
INCREASE local control functionality to mitigate voltage unbalances (in the following referred as the unbalance
mitigation control) was tested. For that purpose, two 15 kVA controllable three‐phase inverters were installed
in the pilot PV installation.
Two demonstration cases were applied. First, the basic scenario, where classical single‐phase inverters create
unbalances by injecting PV generation into the same phase L1, while the unbalance mitigation control of
controllable inverters is switched off. The controllable inverters thus inject a three‐phase symmetrical current
in the grid. In contrast, in the INCREASE scenario the unbalance control was switched on (instead of being
switched off as in case of the basic scenario) in order to tackle the unbalances created by the single‐phase
inverters.
The performance of the unbalance mitigation control is validated and evaluated using voltage and current
measurements, acquired from the main bus and the main line of the pilot PV installation. Figure 2.9 indicates
high current unbalances, generated by unsymmetrical PV generation. The highest current is obtained in phase
L1, since all single‐phase PV inverters injected their power. There is also a high neutral current, indicating high
unbalances of current and voltage. After the unbalance mitigation control is switched on (right chart on Figure
2.9), one clearly observes the reduction of the neutral current (compared to the basic scenario.)
Figure 2.9 Reduction of the neutral current in case of unbalance mitigation control activation
Figure 2.10 Impact of the unbalance mitigation control on PVUR and neutral current
Proper response of the unbalance mitigation control is further confirmed and illustrated in Figure 2.10, where a
statistical analysis is applied. On the left chart, the relationship between the phase voltage unbalance rate
(PVUR) indicating the voltage unbalance and total apparent power has been analysed. The results indicate that
in the INCREASE scenario, PVUR is reduced. For instance, in case of 15.000 VA, the PVUR is reduced for approx.
0
10
20
30
40
50
60
70
80
90
15.8.2016 16.8.2016 17.8.2016 18.8.2016
I (A)
I N I L1 I L2 I L3
0
10
20
30
40
50
60
70
80
90
26.8.2016 27.8.2016 28.8.2016 29.8.2016
I (A)
I N I L1 I L2 I L3
0
0,5
1
1,5
2
2,5
3
3,5
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5
0 5000 10000 15000 20000 25000
PVUR (%)
S (VA)
INCREASE scenario Basic scenario
0
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0 20 40 60 80 100 120
I N (A)
I 3‐phase (A)
INCREASE scenario Basic senario
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half a value. On the right graph of Figure 2.10, there is a relationship between the neutral current and the total
three phase current. Also in that case, it is clear that there is a proper operation of the unbalance mitigation
control. As an example, at a 3‐phase current of 80 A, the neutral current is reduced by about 20 A.
The Austrian field trial highlighted that the unbalance mitigation control performs according to the concept,
defined within INCREASE. By introducing the controllable inverters, a reduction of the voltage unbalances was
achieved after the unbalance mitigation control was activated. Using such controllable inverters hence is a
suitable solution for increasing the PV penetration in the networks which face voltage unbalances.
The field trial also confirmed that PV inverters with unbalance mitigation control do not further deteriorate
voltage unbalances. More significant improvements of the voltage unbalances are achieved with increasing the
share (total power capacity) of such controllable inverters. Regarding future research we are interested in
testing the unbalance mitigation control in other LV network configurations such as rural or highly urban
networks.
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3 THE INCREASE FIELD TRIALS‐IMPORTANT INSIGHTS
3.1 THE EANDIS FIELD TRIAL IN BELGIUM
DESIGN & PREPARITION PHASE 3.1.1
Coordinated purchase procedure
In many cases smart grid devices have to be purchased through tendering or an open procedure. This
procedure takes time, effort and coordination from different departments. It is important to define the process
(classical purchase / partnership with supplier/ consortium / … ) and to brief the different departments of the
goals of this field test and why this smart device is needed.
Define acceptance criteria / business cases
Since the selection of a smart device is not only a technical choice, but mainly an economic or techno‐economic
choice, it is wise to invest time in defining acceptance criteria / business cases for this technology. This
approach helps to define a clear goal for the project team (what do we need to measure/monitor and for what
reason) and helps to “translate” the technical aspects into your organization. Match these criteria with your
business strategy and find a mandate to perform the field test.
Choice of the test site and test criteria
Since smart grid technology generally focusses on solving emerging problems instead of widespread ones, the
choice of the test site and test criteria are of outmost importance. Eandis has withheld several criteria that the
test site needed to have: a combination of long and short feeders, high shares of renewable energy sources on
both LV and MV‐side, high consumption loads and voltage swings that violate the limits set by the European
PQ‐standard (EN 50160). After the criteria of the test site are made, try to find a match within the “portfolio” of
your distribution grids. At Eandis we have enquired possible test sites from both local as central experts; this
created involvement by different stakeholders and opened the door for follow‐up requests.
Take your time to thoroughly investigate the different suggested test sites and match the objectively
determined problems to the initially defined criteria. Some (if not most) of the test sites will have other
problems which makes them a less ideal candidate to evaluate the potential of the smart grid device. Based on
the experiences with the OLTC and theoretical analysis, EANDIS selected the grids for testing.
Understand behaviour of the consumers at test site
Since Eandis has no general roll‐out plan for Smart Meters, the data and behaviour of the consumers at the test
site is undeterminable. Find references / assumptions for this behaviour and their corresponding grid impact in
order to quantify the effects of the different grid users on the distribution grid / technology needs.
Stakeholder involvement
Find common ground for the different interests (purely academic, economic, practical, security of supply, …)
and determine the respective priority. Not only will this help to create focus (nice to have vs must haves) but –
if done properly – this will also ensure that all different actors in the field test are heard and that their worries
are captured and translated into the project planning / specifications.
IMPLEMENTATION & INSTALLATION PHASE 3.1.2
Importance of lab tests
Before implementing in the field, get some experience in a test environment. This will help to solve some bugs
but it also proves to be a right time for training / internal education purposes. Based on these test internal
procedures and manuals can also be developed.
15
Proper determination of measuring/monitoring period
Determine the right time to measure / monitor. If the Smart Grid device is designed to work with PV, it is
logical that you don’t want to test the device in the winter or at night‐time. Also, in many cases you want to
compare different options / algorithms with each other. Thus, choosing and creating a correct planning is
crucial.
Installation challenges
Make sure the device can be placed inside the (sub)station and that the (sub)station meets the device
specifications (e.g. temperature range, ventilation needs, …).
Communication structure
Ensure that all utilities are available in the substation. Intelligent devices do not only need a power supply, but
also have requirements regarding algorithms, communication interfaces, etc. Not only do these utilities have to
be available at the substation, but in many cases interfaces towards DMS‐systems and monitoring devices have
to be foreseen. In many cases, the required utilities will have a huge impact on the liability of the project
and/or business case. Ensure that also alternative utilities (for example GPRS/4G instead of fibre optic cables)
are tested in the project and evaluate their impact on the techno‐economic optimum of the smart grid device.
Make choices: what must/may the device decide locally and what must be done remotely? What will happen if
the remote communication with the device is lost for a longer period of time?
Define a contingency plan, what if the device does not work as foreseen. Who has the responsibility for which
case, who will intervene in which case. Who has the end responsibility to end the field test and revert to the
classical case? This plan was key to gain the involvement of Eandis’ local technical departments, since these
projects are mostly lead by central departments and local technical departments have a more operational
focus. The contingency plan made them feel that they still were in control in some (extreme) cases and could
revert back to their business as usual case.
OPERATIONAL PHASE 3.1.3
Regarding the operational phase the following aspects are of key importance:
Determine the responsibilities of the different staff / users.
Make interim reports and send them to the different stakeholders in order to prove the reliability and
added value of the device in the grid.
Communicate the timing of the different tests proactively to the different stakeholders.
3.2 THE ELEKTRO GORENJSKA FIELD TRIAL IN SLOVENIA
With the rapid emergence of distributed renewable energy sources (DRES) on different distribution network
voltage levels, DSOs are facing severe challenges in keeping the voltage levels within standard limits (EN 50
160) that enable safe, reliable and a high quality of supply. Low voltage networks were traditionally operated
as autonomous entities with not much insight or control. In this setting high penetration of DRES leads to
serious voltage quality problems and thus action is required.
Elektro Gorenjska d.d. (EG) has strongly contributed in the INCREASE project with the demonstration of
different research outcomes, which on the one hand mitigate the influence of DRES on voltage issues and on
the other hand, enable a higher penetration of DRES in existing networks.
As a result of the INCREASE project investigations, four different demonstration cases were implemented,
thoroughly measured and later evaluated for further exploitation:
Network with existing regular distribution transformer and no voltage control.
16
Introduction of an OLTC transformer utilizing incorporated algorithms for the transformer busbar
voltage control.
The implementation of the voltage droop characteristic (P/V control) and autonomous voltage control
on the location of a single PV installation by using controllable load.
The implementation of online coordinated voltage control based on the real‐time complete network
measurements, utilizing local SCADA for the OLTC control. For this purpose a special control algorithm
based on numerous real‐time network analysers’ measurements was developed in order to determine
the optimum OLTC tap position.
DESIGN & PREPARATION PHASE 3.2.1
As the demonstration of different control strategies was planned to be implemented under live distribution
network conditions, the following concerns were of key importance for EG:
Ensure safety of the operations (for people and equipment involved).
Complying with the voltage quality requirements (EN 50160 standard).
Ensure the reliability of operations and maintaining the quality level of supply.
Additional support for customers involved in the project.
Demonstration network
In order to assure a maximum response of the control strategies, choosing a suitable low voltage network is
mandatory. Therefore, a low voltage network with a relatively high number of photovoltaic power plants and
interesting feeder/customer distribution was selected. Voltage measurements were performed in advance in
order to analyse the voltage quality at the most representative low‐voltage network (LVN) points. Regarding
the temporal resolution of data the measurements were recorded in 5 minutes’ average period.
Some basic conclusions are as follows:
The voltages across the LVN differ significantly due to the individual load character of a single LVN point.
Higher voltages are observed at PV locations during the mid‐day production period. At “only consumer“ network points (only load, no production) voltage drops correspond to individual
load profile. During the mid‐day PV production the transformer energy flow is reversed as energy from the LVN is
exported backwards into the middle voltage network. The variety of voltage levels were registered at different network points at the same time.
OLTC transformer
The selection of the appropriate distribution OLTC transformer was crucial in order to provide an adequate
voltage control. A modern OLTC 400 kVA transformer was purchased specially for this demo.
Power quality system
The proper observability of distribution networks is one of the main professional DSO occupations. Without
knowing exact network statuses, no adequate network control is possible. Observation of low voltage networks
with an almost countless number of distribution transformer stations and an increasing number of distributed
generations nowadays represent a major challenge for DSO network control requirements.
Until DRES (mostly PV) significantly invaded DSO networks, there was no need for high level observability of the
low voltage network. For a long time low voltage bus bars of distribution transformers were the last network
points observed with different types of measurement equipment. Different analogue instruments with simple
peak load indicators were the first instruments. They were mainly applied to monitor peak transformer load
and the resulting data was used for network development purposes. The introduction of the electronic power
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meters lead to a significant change. With the meter performance development and remote reading
capabilities, additional need for data logging had risen.
EG followed the development of power network analysers from its beginning knowing the importance and
value of high quality network data. EG decided to replace older types and massive installation of new electronic
power analysers. In the course of performance tests and benchmarking activities the local vendor Iskra
electronic power analysers and Mismart data logging system were selected. Following the deployment plan,
more than 500 out of almost 1500 distribution transformer stations were equipped with modern analysers,
40% of total were already remotely monitored and data was logged.
Low voltage network measurements data is regularly used for the following purposes:
Network development
Network control
Network protection
In order to provide appropriate online network (almost real‐time) measurements for the INCREASE control
algorithm implementation and further analysis, a careful selection of network locations, suitable power
network analysers and power quality measurement system was first conducted. A measuring period interval
had to be chosen in a way that supports the voltage control algorithm and enables a relevant OLTC transformer
control. For the INCRAESE demo case, a one minute reading period was determined. EG regularly installs power
quality meters on the secondary side of MV/LV substations, but with the emerging distributed generation,
meters are also regularly installed at PV generation points to locally provide supervisory and control
measurements. Meters are used for measuring basic electric quantities, like voltage, current, active and
reactive current as well as harmonics. Newer meters are also able to measure power quality parameters like
harmonics and flicker. The data from these meters is used for monitoring the substation. The device is used for
monitoring, measuring and recording measurements of electric quantities. The evaluation of voltage quality in
compliance with EN 50160 was not available. The device was used for permanent analysis of electricity supply
quality in compliance with the EN 50160 standard. In most cases Ethernet communication was used for the
connection of a device to the Ethernet network for remote inspection. Each device had its own MAC code.
SCADA system
The remote control was based on an up‐to‐date SCADA system, which at the same time also served as a
common communication interface platform. SCADA as a main communication node interconnects all demo
systems and is additionally suitable for data collection and system visualisation. A separate test SCADA system
was built for demonstration purposes in order not to intervene or endanger the regular day‐to‐day control
system.
The MV control and monitoring system (SCADA) consisted of:
Remote Terminal Unit (RTU). The field sites were equipped with RTUs that collect data from on‐site
sensors, add data from off‐site sources, and use this aggregated data to make decisions regarding how
the process is operating. Changes to the local process may be made; messages may be initiated that
send data elsewhere to influence the operation of off‐site equipment.
Communications. The multiple system elements communicate among themselves by utilizing a variety
of communication choices.
Communication and concentrator server. Sipronika communication and concentrator server was used
at the central control site to provide a two‐way path to the communication system and the distant
RTUs.
Control algorithm
For the implementation of the main INCREASE OLTC control algorithm, a separate PC with remote access was
implemented mainly due to the reliability of operations. Being installed in the EG headquarters, no
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communication failures were expected. A remote access to the PC was installed in order to perform required
actions related with development and upgrade of the algorithm.
Local control
The local voltage control was decided to be autonomous on the PV point of common coupling. For that reason,
a decision for appropriate hardware and software solutions was mandatory. For the communication reliability
standardised ICT connections were foreseen.
ICT support and communication protocols
In the MV/LV power grid in most cases radio and PLC networks were used. Typically, transformers in rural areas
do not have fibre connections at the moment. In the medium term the investment into fibre connection to
rural transformers is economically not feasible. Thus, in the respective time‐span wireless connectivity is more
efficient. Wireless networks were used to manipulate remote reclosers on the MV grid. These systems are
based on closed, legacy protocols. UHF radio was used (the majority still operate today). At present
approximately 18% of all reclosers are remotely manipulated.
Since we decided to use open protocols (Ethernet and IP), we were searching for technologies that could
support systems involved in modern Smart Grids.
What were the technological alternatives based on ITU/ETSI/IEEE standards?
In medium‐term ‐ WIMAX IEEE 802.16e
In long‐term: LTE‐A
For rural areas not cowered with WiMAX narrow band digital radio (e.g. UHF frequency band)
The current 2G/3G mobile networks do not provide prioritization for different data traffic. Typically, all users
share the same media (first come first served) and hence critical smart grid data will be treated in the same
way as regular internet traffic. 4G network will overcome this problem, but mobile operators will invest in 4G in
regions where economically reasonable (similarly operators do not install 3G everywhere).
Fundamental issues worth mentioning
Mobile networks are designed for certain voice and data traffic models. This model is highly related to the
operators’ business model. In other words, operators invest in the network just enough to serve planned
number of subscribers and planned quality of services and not more.
A mass M2M (machine to machine) communication (Smart Grids) with thousands or even tens of thousands of
end point connections is usually not considered in network design nowadays. In catastrophic events, when
reliable communications are most needed, public operators usually have their own priorities, which in most
cases do not coincide with the priorities of certain power distribution companies. Based on above mentioned
considerations we decided to build a private network based on the WIMAX IEEE 802.16e standard. In 2011 we
acquired a license for 42MHz of 3.5GHz frequency band, the only one available in Slovenia. Consequently six
existing base stations were equipped with WiMAX
The EG communication network, Figure 3.1, is thus very heterogeneous as well as complex and supports all
distribution processes. Communication networks were planed very carefully having in mind the need for their
openness, flexibility, scalability and manageability. Recently Ethernet and IP are becoming basic protocols for
communications in our power grid but many older systems are still in use. Our communication network is
generally divided in two sections. All HV substations are connected to a fibre optical network, while in MV/LV
network in most cases radio and PLC networks are used. Fibre optical connections consisting of two NG‐SDH
(next generation synchronous digital hierarchy) rings build the backbone of existing ICT infrastructure. In some
rural locations fibre optic is connected to PDH radio links in order to assure some redundancy.
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Figure 3.1 EG wired network
All optical cables (fibres) are in accordance with the ITU‐T G.652 standard, thus supporting xWDM. There is
only one physical optical ring existing in the Kranj area, Figure 3.2. In all other parts of the Elektro Gorenjska
distribution network flat rings are used. To realize a flat ring, different pairs of optical fibres in the same cable
are used. Thus, greater reliability as in the system without rings is achieved. The existing infrastructure meets
current but will also meet future demands.
Figure 3.2 EG optical network.
Radio and PLC networks are normally used in the MV/LV power grid. For the first time wireless networks were
used to manipulate remote switchgear in the MV grid. Proprietary systems based on closed legacy protocols
and UHF radio were used. After thorough analysis, we decided to use a private network built on WIMAX IEEE
802.16e standard. Almost 80% of the Elektro Gorenjska area is already covered with a broadband signal.
Introducing a broadband wireless IP network enabled us to use single communication paths to our remote
sites. This enables us to share the same network resources for multiple applications. In MV/LV transformer
stations ‐ through a single communication path ‐ data from AMI concentrators, power quality meters, SCADA
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RTUs, industry electricity meters and other sensors is transferred. Standalone industry electricity meters and
SCADA RTUs are connected as well. Due to its support for standardized quality levels WiMAX enabled the
configuration of different profiles of different data flows.
In remote rural areas, out of sight of WiMAX base stations, we drew on VHF/UHF digital radio. Being flexible,
spectrally efficient and secure the VHF/UHF digital radio enables the transport of IP protocols. The VHF/UHF
frequency band on one hand assures good radio coverage but on the other hand is limited with its data
capabilities. A combination of both, WiMAX and digital radio is therefore an effective support. For the
INCREASE demo purposes the utilisation of Wimax broad band radio was planned from the beginning as it
represents the basic EG communication system platform. Only the utilisation of standardised protocols was
foreseen.
IMPLEMENTATION & INSTALLATION PHASE 3.2.2
During the implementation and installation, the following was experienced:
Demonstration network
TS Suha low voltage network with 7 active PV plants and challenging load as well as voltage profiles was
selected to most suitable for testing. The network topology is depicted in Figure 3.3.
Figure 3.3: LVN topology
OLTC transformer
A modern OLTC 400 kVA transformer was purchased for that demo. We experienced minor problems with
commissioning but those were quickly solved.
Power quality system
All 7 PV locations, distribution transformer station and additionally two residential (customer) points were
equipped with network power analysers. All measurements based on one minute readings were collected in
the power quality server.
SCADA system
A remote control test SCADA was implemented on a separate server and connected to all demo subsystems
utilizing predefined communication protocols. All necessary MMIs were defined and tested to ensure a
complete demo case implementation.
Control algorithm
The INCREASE coordinated control algorithm was implemented on a separate PC and remote access was
provided to the project partner TU/e. The execution of the algorithm was based on online network
measurement readings (by utilizing OPC UA protocol) and SCADA.
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Local control
The local voltage control basically represents a droop control for overvoltage mitigation on the PV location. The
voltage at the inverter ( ) point of connection is measured and when it crosses the constant power band
voltage ( ), it manipulates the PWM of the inverter reducing the active power injection.
Since we were not able to install new inverter with build in algorithm, the local voltage control was executed by
utilizing resistor heaters and the implementation of an integrated local control algorithm (adapting the output
power of resistors to the PV production and local voltage measurements). A broadband radio with the
utilization of IP enables resistor remote control.
ICT support
The WiMAX broad band radio was used for the communication purposes. Only standardised protocols (DNP3,
OPC UA) were utilized.
OPERATIONAL PHASE 3.2.3
Demonstration network
No problems regarding voltage quality and safety of operations were experienced during project
demonstrations due to careful planning.
OLTC transformer
A hardware failure of the OLTC control box was experienced during the demo period. During the normal
transformer operation, a short circuit within the OLTC control box resulted in a number of damaged contactors.
After the fault, the OLTC tap changer positioned itself in the middle tap position allowing the operation as a
normal non‐regulated distribution transformer. The fault was cleared by factory experts.
Power quality system
The power quality system with the utilization of network power analysers showed no major failures during the
operation phase although Ethernet port failures were occasionally detected. Analysers were however restored
by a reset of the power supply.
Failures in data transmission from an individual metering point were experienced occasionally, which caused
the abortion of the coordinated control algorithm and the activation of the local transformer PLC control. The
reason for the above mentioned switch is that the presence of measurements from all monitored network
points was one of the preconditions for the normal algorithm operation. In case of a single measurement
failure, the requirements for algorithm operation are no longer met and control is taken over by transformer
local PLC control. During the project, a number of measuring locations with normal voltage quality were
excluded from algorithm evaluation in order to increase the robustness of the algorithm.
SCADA system
The SCADA system was implemented separately and exclusively for demo purposes and as such some fine
tuning was required during the whole project. At the end, a stable operation was achieved.
Control algorithm
The newly developed INCREASE OLTC control algorithm required fine tuning at the beginning, but afterwards
operated with expected reliability. Based on this positive experience EG decided to implement the developed
algorithm in day‐to‐day operations.
Local control
The autonomous application highlighted the importance of control mechanisms being executed locally on site.
After proper commissioning, the operation itself showed no major failures. Due to unacceptable energy losses,
the control resistor will be dismantled after the project.
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ICT support
A good signal and WiMAX broad band radio coverage resulted in a smooth and reliable communication. The
amount of conveyed data never reached the system limitations. The utilization of standardised protocols was
highly reliable during the whole operational phase. WiMAX as the broad band communication solution has fully
supported the INCREASE demo case and proved to be a promising ICT solution (also for future large scale smart
grid applications).
3.3 THE LIANDER FIELD TRIAL IN THE NETHERLANDS
DESIGN & PREPARATION PHASE 3.3.1
As the demonstration of different control strategies was planned to be implemented in the live distribution
network, some aspects were of special concern:
Selection of sites
Choose your test site carefully. This is of utmost importance in guaranteeing a successful field trial.
Interaction with people
It is important to get people / customers on board for the test. This has proven to be intensive and time
consuming (i.e. 2.‐4 hours per customer was not unusual, a preparation time of at least a full year is needed).
As already discussed in the EN field trials, it is important to have at least one meeting on the location of the
field trial with all responsible partners where all details are discussed thoroughly. This is especially important
because different partners may have different expectations and opinions about the implementation of the pilot
phase. There are also interdependencies between components of the system which have to be clarified in an
early stage. Furthermore, it is also important to have all partners, who are related to the field trial, on the spot
during the commissioning phase. In particular the partners who have developed and produced the equipment
that is going to be tested in the pilot phase have to be present. The most important advantage is that the
knowledge of each equipment segment is on hand when needed during the commissioning phase. Moreover,
flyers, hand‐outs and letters will work partly, personal visit at homes will be needed, enhancing customers
understanding of the meaning of test is challenging.
Communication
The field trial showed that choosing a communication type that is available to all customers is of key
importance (in the case of the Liander field we use Wi‐Fi).
Matching new with existing hardware
The field trial highlighted the need to compare the voltage range and currents of the solar panels as well as to
check whether they are matching. In the Liander field trial the type/model was not known at the project
definition and this lack of matching with existing voltage range and currents caused problems later. Dimensions
should be checked for replacement, as users are using free space around inverters, making installation more
difficult and time consuming.
Simulations are showing that there are no real problems expected in overvoltage situations, because
controlling down the PV generation will lower the voltage. Adapting the communication, in particular rooting
PQ field measurement signals over the grid operators IOT domain, is costly (more than 10k€). In order to
successfully merge technological systems that were working independently control strategies are
recommended.
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Sufficient testing time
A testing time of at least 3 months at the location for the new equipment is recommended. This time span was
identified in the field trial, however even 3 months may be short to discover all issues involved. The challenges
depend on the type of technology used and are as follows:
By choosing the communication over the supplier of the inverter, lesser costs arise for later
implementation. However your test then depends on the willingness and capability of the supplier of
the inverter to solve problems.
Using a prototype that is not certified is not a successful strategy to minimize risks.
Clearly define the parameters to be tested.
Invest more time defining KPIs to evaluate performance of solutions; otherwise calculation is time
consuming as well as inefficient. Furthermore there is a lack in the common understanding on what
will be done during the demo.
IMPLEMENTATION & INSTALLATION PHASE 3.3.2
The involvement of end users combined with the installation and/or replacement of inverters at the end users’
premises require extra attention during the implementation and installation phase:
Be aware that each installation is unique and thus requires a (visual) inspection of the end users’
premises to ensure efficient installation. Otherwise the costs related to the
installation/implementation will be much higher than originally estimated. This affects both, the
material and the time to perform the modifications.
A frequently asked question (FAQ)‐website is recommended to tackle the main questions (most
efficient to solve main problems).
When replacing old inverters by new inverters, make sure that the new inverter has the necessary
specifications (e.g. isolation transformer vs. non‐isolated inverters).
People tend to be not at home during working hours which makes the coordination of the installation
challenging.
OPERATIONAL PHASE 3.3.3
The involvement of end users combined with the installation and/or replacement of inverters at the end users’
premises requires extra attention during the operational phase:
Minimize the active involvement of the end user as much as possible. Most people do not have the
necessary technical knowledge to e.g. adjust the Wi‐Fi connection themselves. A high degree of
automation and thus redundancy is required.
3.4 THE ENERGIENETZE STEIERMARK FIELD TRIAL IN AUSTRIA
DESIGN & PREPARATION PHASE 3.4.1
The test site was selected according to best simulation results from the Aristotle University of Thessaloniki. An
interaction with customers was not needed since the installation is in ownership of the mother company of
ENS.
From the Energienetze Steiermark, from here on ENS, point of view it is important to have at least one meeting
on the location of the field trial with all responsible partners in order to thoroughly discuss all details related to
design and preparation. This is especially important because different partners may have different expectations
and opinions about the implementation of the pilot phase. There are also interdependencies between
components of the system which have to be clarified as soon as possible. With this approach we could
efficiently adapt the installation scheme of the PV installation in the 10th floor of the main office building.
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IMPLEMENTATION PHASE 3.4.2
Furthermore, it is also important to have all partners, who are related to the field trial, on the spot during the
commissioning phase. More precisely, partners who have developed and produced the equipment that is going
to be tested have to be on site. The most important advantage is that the knowledge of each equipment
segment is on hand when needed during the commissioning phase. The implementation phase also highlighted
the importance of the remote access to the controller for the partner who is responsible for the control
algorithms. The reason is that the algorithms have to be updated weekly and thus the travel costs would be far
higher if the partners are not able to do that remotely.
OPERATIONAL PHASE 3.4.3
During the operation phase we frequently checked the communication, which was possible due to use of
GSM/GPRS based communication. A DSL option would be more suitable due to better availability.
Furthermore, ILPRA had to adapt frequently the algorithms and the parameters of the controllers/inverters,
which was easily carried out due to the remote access.
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4 SYNTHESIS OF INSIGHTS This chapter synthesizes insights that show common patterns across the demonstrations.
Planning and testing
The INCREASE field trials showed the need for a thorough planning and testing period, depending however on
the specific technology. For equipment not being officially certified, FAT and SAT tests are mandatory in order
to minimize expected risks. Any fault during exploitation is by default time consuming, usually complex and
costly. Moreover equipment faults endanger safety of operations and project time schedules.
Not only in the Liander field trials problems occurred that were not expected, also in the EG field trial there
were problems with the transformer and an adaptation was needed. In case of EG the ILPRA resistor was not
certified but this did not influence the network operation.
Communication systems
Communication seemed an issue in most cases. In the case of Liander the communication over internet
(Mastervolt) was not reliable. In particular, we suggest an internet platform designed for people to see energy
demand and which enables two way communications. In the case of EG the public supplier was not reliable
enough. In case of using WiFi as far as possible preparation for router adjustments have to be made. Using
customers WiFi also raises question about privacy. In case of Liander the MV inverter had WiFi capability,
inverters however needed to access the internet (some customers shut down their router). Another issue
related to communication is remote access. ENS learned the importance of the remote access to the controller
for the partner who is responsible for the control algorithms. We discovered that the algorithms had to be
updated weekly and thus travel costs would be far higher if the partners are not able to do that remotely.
Matching new with existing hardware – practical challenges
The field trial highlighted the need to compare the technical requirements of old and new systems as well as
assess whether they are matching. In the Liander field trial, the type/model of inverter was not known at the
project definition and this lack of matching with existing voltage range and currents caused problems later on.
In the EG field trials, the existing resistor had to be adapted, while ENS had to disconnect PV panels to comply
with the voltage band of the new inverter. It is also important to check the dimensions for replacement; users
are using free space around the inverters, making the installation more difficult and time consuming. In the EG
case, some of the panels were shadowed and communication antennas created noises in the measurement of
controllers. Besides the utilization of new equipment, demo cases should also be based on well proven and
reliable day‐to‐day technologies in order to minimize general demo risks. A thoughtful implementation of
upgraded day‐to‐day systems enables later an easier implementation of positive demo outcomes
Interaction with customers
Some of the field trials underlined the importance of getting people / customers on board for the test to avoid
problems at a later stage. This has proven to be intensive and time consuming. In particular, we find that it is of
key relevance to have at least one meeting on the location of the field trial with all responsible partners where
all details are discussed thoroughly. This is important because different partners may have different
expectations and opinions about what should be done and how it should be done during the pilot tests. There
are also interdependencies between components of the system which have to be clarified in an early stage.
Demo customers, being directly or indirectly involved should be devoted maximum care.
The sharing of information, clear project insight and fair play are mandatory. The quality of services should
never be reduced and demo goals achieved in order to attract customers’ future interest and engagement.
Necessary financial reimbursements should not be avoided
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5 RECOMMENDATIONS AND GUIDANCE FOR DSOS This chapter derives key recommendations (KR) for DSO based on the insights of the INCREASE field trials.
Design phase
Key recommendation 1: Proper definition of parameters and KPIs
The parameters of the measurement equipment which will be used in the field trials such as accuracy level or
sample rate need to be defined in detail. We recommend to invest a sufficient amount of time defining KPIs,
used to evaluate the performance of the solutions, otherwise it is not possible to calculate them, nor have a
good understanding on what will be available during the demo. KPIs should include not only technical issues
but also others, e.g. funding, market readiness levels, and business cases.
Key recommendation 2: Sufficient planning and testing
Quality planning and pre‐testing of new network equipment is of the utmost importance in all smart grid cases,
since the expected demo risk is additionally reduced that way. By utilizing different already proven and reliable
technologies, system failures should be minimised, building new control systems only as individual
demonstration cases not being interfered with regular day‐to‐day operations, bringing new solutions into
operations only if complying with safety, reliability and voltage quality provision. Problem grids should be
catalogued in order to facilitate the search of potential test sites and to quantify the full economic potential of
the technology within the working area. A process has to be created that clarifies how and when new field test
can be approved.
Key recommendation 3: Choosing a communication type available to all customers and enabling the remote
access to the network devices
Communication is key for a successful demo implementation. Choices need to be made on what must/may the
device decide locally and what must be done remotely. There has to be a solution for situations if the remote
communication with the device is lost for a longer period of time. Also there is a need for a remote access for
DESIGN
IMPLEMENTATION
OPERATION
KR1: Proper definition of parameters and KPIs
KR2: Sufficient planning and testing
KR3: Choosing a communication type available to all customers
KR4: Partners, who are related to the field trial, need to be closely involved during the commissioning and planning phase
KR5: Carefull interaction with people/ customers
KR6: Be sure that there is some redundancy in the implementation of the
solution and define fall‐back scenarios
KR7: Make interim reports on results and send them to the different stakeholders in order to prove the reliability and added value of the solution in the grid.
KR8: Use the interim reports on results to improve the solution
KR9: Embed "Smart control" into the daily business of the DSO
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the partner who is responsible for the control algorithms. The INCREASE field trials showed that private
communication is preferable over public networks. However a proper balance between technical
requirements, available infrastructure and costs must be identified.
Implementation phase
Key recommendation 4: All partners, who are related to the field trial, need to be closely involved during the
commissioning and planning phase
It is important to have all partners, who are related to the field trial, on the spot during the commissioning
phase. The partners who have developed and produced the equipment that is going to be tested in the pilot
have to be on site. The most important advantage is that the knowledge of each equipment segment is
available when needed during the commissioning phase.
Key recommendation 5: Careful interaction with people/ customers
It is of utmost importance to get people / customers on board for the test to avoid problems at a later stage.
The sharing of information and a detailed project insight as well as fair play are important. As demos may
interfere with the privacy of households more information may be needed than with industrial customers.
Customers’ demands should be always seriously considered and being reasonable and strictly respected.
Key recommendation 6: Be sure that there is some redundancy in the implementation of the solution and
define fall‐back scenarios.
Define a contingency plan, what if the device does not work as foreseen. Who has the responsibility for which
case, who will intervene in which case. Who has the end responsibility to end the field test and revert to the
classical case?
Operation phase
Key recommendation 7: Make interim reports on results and send them to the different stakeholders in
order to prove the reliability and added value of the solution in the grid.
Communicate the timing of the different tests proactively to the different stakeholders. Stakeholders need a
good understanding of timing and interrelationships between different tasks in order to avoid delays.
Key recommendation 8: Use the interim reports on results to improve the solution
Solutions have to be constantly improved (for example with fine‐tuning of the control settings) as new results
are available, to enable a smooth operational phase and to obtain maximal added value out of the solutions.
Key recommendation 9: Carefully embed smart control into the daily business of the DSO
Smart control applications should be very carefully introduced into daily operations taking the priority levels
(e.g. safety and reliability of operation) into account. New technologies and solutions should be approved by
qualified experts (incl. for example technology committees).
