CHALLENGE IN THE CONTROL CENTRE (EMS) DUE TO DISTRIBUTED GENERATION AND RENEWABLES

700
CHALLENGE IN THE CONTROL CENTRE (EMS)
DUE TO DISTRIBUTED GENERATION
AND RENEWABLES
WORKING GROUP
C2.16
SEPTEMBER 2017

Members
M. POWER, Convenor IE N. SINGH, Secretary CH
E. GARRIGAN IE M. CREMENESCU RO
R. BESSELINK NL V. PANDEY IN
H. TONG AU M. SANCHEZ ES
C. ROGGATZ DE A. STOLTE DE
F. BASSI IT T. KROGH DK
J. OTTAVI FR S. PASQUINI IT
R. PHILBRICK US B.C. CHIU US
G. IVKOVIC AU T. CAROLAN ZA
I. ARONOVICH IL X. WANG US
H. ILIAN US G. FAN CN
C. NORLANDER SE L. DU PLESSIS ZA
B. MALFLIET BE L. JONES US
M. MILLER AU T. BÖHMER DE
WG C2.16
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CHALLENGE IN THE CONTROL
CENTRE (EMS) DUE TO
DISTRIBUTED GENERATION AND
RENEWABLES
ISBN : 978-2-85873-498-6

CHALLENGES IN THE CONTROL CENTRE (EMS) DUE TO DISTRIBUTED GENERATION AND RENEWABLES
3
EXECUTIVE SUMMARY
The penetration of intermittent and distributed generation has influenced all facets of power system
planning and operation. From the perspective of system operation these generation sources bring
uncertainty and require another level of preparedness for the control room. The aim of this work is to
analyse, survey and propose what types of organizational tools and process changes will take place in
the control centre environment. Previously, CIGRE Study committee C6 released a Technical
Brochure (450) on Grid Integration of Wind Generation in 2011.
The traditional system with predictable flows and loads based on a large number of synchronous
generators with predictable outputs will be replaced by a system with unplanned flows. Power will be
generated from a mix of variable output, asynchronous generators (connected to the network through
power electronics) and a reduced number of synchronous generators. Load patterns will also vary
considerably as electricity becomes the major conduit for energy delivery to transport, homes and
businesses. The impact of electricity storage, which can provide multiple benefits to the grid, including
the provision of ancillary services and the provision of firm capacity, must also be considered. The
impact of Microgrids, which are physical or virtual areas where the average electrical energy
production is equal to consumption, also have to be considered. Microgrids allow for the balancing of
energy at low levels where most of the distributed energy resources are connected. They provide a
new challenge and new business opportunities e.g. for municipal utilities. On a completely different
scale the significant impact of HVDC interconnections, both externally and internally to existing
networks, must also be considered.
The power system will become much more dynamic and this will require additional analysis, both in
real-time and in the operational planning phase. New tools such as stochastic security constrained unit
commitment and security constrained optimal power flow may be required for normal daily operations.
Fundamental operational procedures such as power system restoration will also be subject to change.
The level of communications to all parties on the system will need to be of extremely high quality and
be capable of high throughput at all times. The quality of the control centre and ICT (Information and
Communication Technologies) infrastructure will be central in this new power system design. Although
the ICT infrastructure does not appear to present any insurmountable obstacles to the implementation
of the new power system, a poor or substandard ICT infrastructure will inhibit its deployment and long
term development.
Challenges for the system operator include:
 The impact of inaccurate forecasting e.g. for demand, wind and solar production
 Guaranteeing the appropriate response from manageable resources
 Dispatch, observability and control of a large number of small intermittent generators across
both the transmission and the distribution networks
 New transmission operations criteria to cater for intermittent and distributed energy sources
 Managing risks to system security and stress situations due to the uncertainties of intermittent
energy sources
 Operating the system with changing flow patterns due to significant amounts of distribution
connected generation.
 Fault or disturbance management – for example :
 the influence of PV during frequency disturbances (similar to the PV 50.2 Hz problem in
the Continental European power system)
 Stability of the system due to a significant loss of wind power due to a short circuit fault

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 The impact of voltage control in transmission and sub-transmission networks– in
particular where renewables resulted in the closure of older thermal plant which
provided voltage control services
 Developing new EMS and DMS architectures that will accommodate additional functions
necessary for the dispatch and control of renewable generators
 Deciding whether to integrate these additional functions within existing EMS/DMS systems or to
build separate control centres for renewable generators
 More specific technical requirements e.g. thresholds for disconnection of renewables at off-
nominal frequency and voltages
The technical brochure is structured as follows:
a. The first chapter provides an overview of the current and future challenges faced by the system
operator due the new generation paradigm.
b. The second chapter discusses in detail these and other technical challenges currently faced by
the system operator. Countries surveyed include Ireland, Spain, Germany, Israel, India and
Australia. Case studies from Ireland, Spain, India and Australia are described in detail.
c. The third chapter explores what the working group sees as the major future challenges for the
system operator.
d. The fourth chapter discusses two sets of vendor tools and how these might be used to deal with
current and future operational challenges.
In conclusion, contributions to this brochure have highlighted both, the physical changes to, and the
impacts on control of, power systems resulting from the advent of dispersed and intermittent
generation. The need for extensive telemetry and control has been highlighted by a number of
contributors including the need to control and operate across the transmission/distribution network
boundary. New applications including advanced forecasting tools, the use of synchrophasor
measurements and upgraded control centres are also a necessity for certain power systems while
smaller systems such as Ireland and Tasmania, in Australia, will face challenges due to reduced
inertia and stability constraints resulting from displaced synchronous generation.

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CONTENTS
EXECUTIVE SUMMARY ............................................................................................................................... 3
1. TECHNICAL BROCHURE OVERVIEW .................................................................................................. 7
1.1 INTRODUCTION ........................................................................................................................................................................ 7
1.2 EXISTING CHALLENGES .......................................................................................................................................................... 7
1.3 FUTURE CHALLENGES.............................................................................................................................................................. 8
1.3.1 Organizational .................................................................................................................................................................. 8
1.3.2 Operations ......................................................................................................................................................................... 8
1.3.3 Observability and Controllability ................................................................................................................................. 8
1.3.4 Technical Capabilities ...................................................................................................................................................... 9
1.3.5 Regulation and Commercial............................................................................................................................................ 9
2. EXISTING OPERATIONAL CHALLENGES..........................................................................................11
2.1 SPAIN.........................................................................................................................................................................................11
2.2 IRELAND.....................................................................................................................................................................................12
2.2.1 WSAT – Wind Secure Level Assessment Tool...........................................................................................................12
2.2.2 Energy Management Systems Wind Dispatch Tool (EMS Wind Dispatch Tool) ................................................13
2.3 GERMANY ................................................................................................................................................................................13
2.3.1 Boundary conditions .......................................................................................................................................................13
2.3.2 Observability and controllability (Status quo) .........................................................................................................14
2.3.3 Curtailment .......................................................................................................................................................................14
2.3.4 50.2 Hz effect .................................................................................................................................................................15
2.4 INDIA..........................................................................................................................................................................................15
2.4.1 Control system architecture and control room ..........................................................................................................15
2.4.2 Management of Unscheduled Flows (Deviations) due to variability of Renewables .......................................16
2.4.3 Future Challenges............................................................................................................................................................16
2.5 ISRAEL........................................................................................................................................................................................16
2.6 AUSTRALIA - TASMANIA .......................................................................................................................................................17
2.6.1 Special Protection Schemes...........................................................................................................................................17
2.6.2 Future Challenges............................................................................................................................................................18
2.7 AUSTRALIA - SOUTH AUSTRALIAN (SA) POWER SYSTEM............................................................................................18
2.7.1 System Inertia ..................................................................................................................................................................19
2.7.2 System Strength...............................................................................................................................................................19
2.7.3 Voltage Dips ....................................................................................................................................................................19
2.7.4 Frequency Control Services...........................................................................................................................................19
2.7.5 Load Following Capability ...........................................................................................................................................19
2.7.6 Example of Event of 28 September 2016................................................................................................................19
3. FUTURE OPERATIONAL CHALLENGES .............................................................................................23
3.1 ORGANIZATIONAL.................................................................................................................................................................23
3.1.1 State of the Art................................................................................................................................................................23
3.1.2 Future Trends....................................................................................................................................................................23
3.2 OPERATIONS ...........................................................................................................................................................................24
3.2.1 Congestion Handling in TSO Grids .............................................................................................................................24
3.2.2 Voltage Control – TSO/DNO Cooperation..............................................................................................................25
3.3 OBSERVABILITY AND CONTROLLABILITY..........................................................................................................................25
3.4 TECHNICAL CAPABILITIES......................................................................................................................................................26

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3.4.1 Active Power - Ramping and Frequency Control.....................................................................................................26
3.4.2 Reactive Power Control.................................................................................................................................................27
3.4.3 Other Considerations .....................................................................................................................................................27
3.4.4 Future Energy Management System (EMS)................................................................................................................27
3.5 REGULATION AND COMMERCIAL......................................................................................................................................27
3.5.1 Regulation.........................................................................................................................................................................27
3.5.2 Commercial.......................................................................................................................................................................28
4. OPERATIONAL TOOLS........................................................................................................................29
4.1 INTRODUCTION ......................................................................................................................................................................29
4.2 PSI...............................................................................................................................................................................................29
4.2.1 Contingency Analysis......................................................................................................................................................29
4.2.2 Congestion Forecast .......................................................................................................................................................30
4.2.3 Congestion Management ..............................................................................................................................................30
4.2.4 Overhead Line Monitoring............................................................................................................................................30
4.2.5 Renewable Generation Management........................................................................................................................30
4.2.6 Voltage Reactive Power Management ......................................................................................................................30
4.3 SIEMENS....................................................................................................................................................................................31
4.3.1 Transition from static to dynamic grid status analysis for next generation EMS ..............................................31
4.3.2 Totally integrated IT/OT framework for next generation DMS ..........................................................................31
4.3.3 Information exchange between TSOs or TSO and DSOs ......................................................................................32
4.3.4 Visualization must not confuse but enlighten the operator.....................................................................................32
4.3.5 Future integration requirements between control centre and energy markets .................................................33
4.3.6 Digitalization will be key to improve electrification and automation .................................................................33
5. CONCLUSIONS ....................................................................................................................................35
APPENDIX A. DEFINITIONS, ABREVIATIONS AND SYMBOLS ..........................................................37
GENERAL TERMS.............................................................................................................................................................................37
SPECIFIC TERMS..............................................................................................................................................................................38
APPENDIX B. LINKS AND REFERENCES.................................................................................................39
APPENDIX C. TERMS OF REFERENCE.....................................................................................................41
Figures and Illustrations
Figure 2.1 WSAT: Composed of VSAT and TSAT............................................................................ 12
Figure 2.2 WSAT transfer with wind increasing and conventional generation decreasing .................. 13
Figure 4.3.1: Architecture for totally integrated OT/IT framework (Source: Siemens AG) ................. 31
Figure 4.3.2: Highlighting severity by means of 2D bubbles and 3D cones (Source: Siemens AG)..... 33
Tables
Table 2.1 Intermittent Generation Resources in Spain.................................................................... 11
App Table A.1 Definition of general terms used in this TB .............................................................. 37
App Table A.2 Definition of technical terms used in this TB ............................................................ 38

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1. TECHNICAL BROCHURE OVERVIEW
1.1 INTRODUCTION
This technical brochure, written by working group C2.16 (Terms of Reference – Appendix C),
discusses challenges, both current and future which have to be faced by the system operator when
controlling the system in the presence of distributed (DG) and intermittent generation. Two papers
were published by the working group in 2013 [B1] and 2015 [B2].
The traditional system with predictable flows and loads based on a large number of synchronous
generators with predictable outputs will be replaced by a system with unplanned flows. Power will be
generated from a mix of variable output, asynchronous generators (connected to the network through
power electronics) and a reduced number of synchronous generators. Load patterns will also vary
considerably as electricity becomes the major conduit for energy delivery to transport, homes and
businesses. The impact of electricity storage, which can provide multiple benefits to the grid, including
the provision of ancillary services and the provision of firm capacity must also be considered. The
impact of Microgrids, which are physical or virtual areas where the average electrical energy
production is equal to consumption also have to be considered. Microgrids allow for the balancing of
energy at low levels where the most of the distributed energy resources are connected. They provide
a new challenge and new business opportunities e.g. for municipal utilities. On a completely different
scale the significant impact of HVDC interconnections, both externally and internally on existing
networks cannot be overlooked.
The power system will obviously become much more dynamic and this will require additional analysis,
both in real-time and in the operational planning phases. New tools such as stochastic security
constrained unit commitment and security constrained optimal power flow may be required for normal
daily operations. Fundamental operational procedures such as power system restoration will also be
subject to change.
The level of communications to all parties on the system will need to be of extremely high quality and
be capable of high throughput at all times. The quality of the control centre and ICT (Information and
Communication Technologies) infrastructure will be central in this new power system design. Although
the ICT infrastructure does not appear to present any insurmountable obstacles to the implementation
of the new power system, a poor or substandard ICT infrastructure will inhibit its deployment and long
term development.
1.2 EXISTING CHALLENGES
The penetration of renewable and distributed generation has influenced all facets of power system
planning and operation. From the perspective of system operation these generation sources bring
uncertainty and the need for another level of preparedness in the control room. Challenges for the
system operators include:
 The impacts of inaccurate forecasting e.g. for demand, wind and solar production
 Guaranteeing the appropriate response from manageable resources
 Dispatch, observability and control of a large number of small renewable generators across
both the transmission and the distribution networks
 New transmission operations criteria to cater for renewable and distributed energy sources
 Managing risks to system security and stress situations due to the uncertainties of renewable
energy
 Operating the system with changing flow patterns due to significant amounts of distribution
connected generation
 Fault or disturbance management – for example :

8
 the influence of PV during frequency disturbances (similar to the PV 50.2 Hz problem
[B3])
 Stability of the system due to a significant loss of wind power due to a short circuit
fault. The South Australia fault, which occurred in September 2016 is an example of
this where a large portion of the system generation being provided by wind was lost
due to faults on the transmission system. We could also consider the impact of a
similar fault on voltage stability
 The impact of voltage control on transmission and sub-transmission networks – in
particular where renewables resulted in the closure of older thermal plant which
provided voltage control services
 Developing new EMS and DMS architectures that will accommodate additional functions
necessary for the dispatch and control of renewable generators
 Deciding whether to integrate these additional functions within existing EMS/DMS systems or
to build separate control centres for renewable generators
 More significant technical requirements e.g. thresholds for disconnection of renewables at off-
nominal frequency and voltages
These issues are discussed in detail in Chapter 2.
1.3 FUTURE CHALLENGES
The future DG/RES operational challenges, which are discussed below are categorized under five
headings. These are organizational, operations, observability and controllability, technical capabilities
and regulation and commercial. These are discussed in more detail in Chapter 3. A number of new
control center tools and operator approaches to cope with these issues are discussed in Chapter 4.
1.3.1 Organizational
Organizational issues in the integration and control of RES and DG have been handled in different
ways in various countries depending on the voltage level and the size of installations, the impact on
the management of the power system and the novelty of the phenomenon. Small DG is connected to
DNOs’ (Distribution Network Operator) or regional providers’ networks and TSOs normally have no
direct control of this generation. Different approaches and agreements between TSOs and DNOs for
integrated control have been developed. In the case of large installations, TSOs have very often direct
control on the power plants. In countries with a high level of renewables and/or high growth trends,
TSOs and DNOs have realized or are implementing dedicated tools and sometimes dedicated
structures to control the RES/DG.
1.3.2 Operations
A number of operational challenges exist, many of which are related to the accuracy and availability of
forecast information. Changes in bulk power flow and subsequent network congestion is materialising
and new management techniques need to be applied. These may include local dispatch and
curtailment opportunities. System balancing is becoming more difficult as renewable penetration
increases, particularly in off-peak hours. Within the DNO, higher levels of monitoring and control are
required compared to previous operations and significant additional resources are required. Particular
attention needs to be paid to voltage regulation and control and the determination of appropriate set
points.
1.3.3 Observability and Controllability
Since renewable energy has significantly increased its contribution to system generation, real-time
production telemetry has become essential to ensure system security. Intermittent generation involves
new challenges since its management is different from conventional plants. Their variability and
uncertainty, their geographical spread, the way they participate in demand coverage, their low

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participation in voltage control and their behaviour during disturbances, make observability a
necessity. Controllability is also required to adapt generation to the demand profile, to avoid
generation reserve exhaustion, to maintain balance feasibility, and in general to increase renewable
energy sources penetration while maintaining the required level of system security.
1.3.4 Technical Capabilities
There are several key technical capabilities required in the future as renewable energy increases as a
percentage of system demand. As the proportion of the system renewable generation increases this
may affect the security criteria and the frequency and inertial responses of the system. Current
solutions involve controlling renewable generation but there are also new system-wide impacts
indirectly caused by renewables that may need to be considered. In this section we will identify future
technical challenges caused by increased renewable generation on the system.
1.3.5 Regulation and Commercial
The design and implementation of grid codes and energy markets are critical for system operators,
when operating and controlling grids with high penetrations of DG/RES. This section will identify a
number of the critical issues, in these two areas, for system operators to monitor.

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2. EXISTING OPERATIONAL CHALLENGES
Integration of significant amounts of renewable energies in electrical systems represents a challenge
for TSOs. Its behaviour is different from conventional plants due to variability, uncertainty, demand
coverage, dispersion and low participation in voltage control. These characteristics could represent a
threat for system security if new tools and regulations are not developed. The following sections
outline how TSOs in Spain, Ireland, Germany, Israel, India and Australia have solved existing
problems.
2.1 SPAIN
During the last years intermittent energy sources have increased significantly in the Spanish
peninsular system. The following statistics summarise the installed capacities as of January 2017:
Table 2.1 Intermittent Generation Resources in Spain
Generation Source Installed Capacity
(MW)
% of Total Installed
Capacity
% Connected to
Transmission
System
% Observability
Wind 22,864 22.8 64.6 99
PV 4,425 4.4 1.26 70
CSP 2,300 2.3 75.9 100
Such large penetration levels in an electrical system with very low interconnection capacity, as is the
case with Spain, constitute a challenge for integration without incurring large volumes of curtailment to
maintain system balance and the appropriate levels of operational reserves.
In order to achieve the goal of maximization of renewable energy sources in secure conditions, a
dedicated control center for renewable energies and other special producers (CECRE) has been
commissioned in June 2006 by Red Electrica de España, the Spanish TSO.
It is composed of an operational desk where an operator continuously supervises renewable energy
production and CHP. As required by the current regulation, all single production facilities or clusters
sharing the same connection point with a total installed power greater than 1 MW send every 12
seconds real-time telemetry of the active power produced. Plants or clusters with a total installed
capacity greater than 10 MW send additional tele-measurements of the reactive power and voltage at
the connection point. Additionally, each of the wind or solar photovoltaic renewable energy plants or
clusters, larger than 10 MW, receives from the CECRE an active power set-point to which they must
comply within 15 minutes.
This real-time information is collected from the plants by the specific Renewable Energy Sources
Control Centres (RESCC) and it is channelled via the ICCP links connecting these control centres to
the CECRE. These RESCC belong generally to generation companies or to third parties that offer this
control center service to smaller producers. To minimize the number of points of contact dealing with
the TSO, the RESCC acts as the only real-time contact with the TSO. They also manage the
limitations established by the set-points and are responsible for assuring that the plants with no direct
control comply with them.
This control and supervision scheme leads to improved security and effectiveness in system operation
and allows the substitution of permanent or long-lasting production hypothesis and preventive criteria
for real-time production control, thus allowing higher energy productions for the same installed
capacity and a more efficient real-time operation of the plants.
The main tool used inside CECRE is the application GEMAS. This application checks whether the
scenario involving the loss of all or part of the renewable generation portfolio, not under the control of
the control center, is admissible due to the low-voltage ride-through capabilities of wind and solar
photovoltaic generation. GEMAS makes real-time simulations possible and therefore adapts
preventive criteria to more permissive limitations depending on the real-time scenario. At the same
time GEMAS simplifies the operator’s task, of reducing simultaneously an important number or
renewable generation facilities, by the provision of extensive remote control and automation.

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The CECRE and the tool GEMAS have been proven to be very efficient in the task of managing the
supervision and control of non-manageable energy technologies.
Additional to these tools, Spanish grid codes (which are in line with European network codes) are
incorporating new specifications for renewable technologies, such as voltage control, and new
demand management strategies which are being (or have been) studied to be incorporated in control
centres in order to balance the system, maximize renewable production and maintain system security.
2.2 IRELAND
2.2.1 WSAT – Wind Secure Level Assessment Tool
Ireland is in the process of integrating unprecedented levels of wind generation (relative to the system
demand) onto a weakly interconnected, island power system. To continue operating the transmission
system in a safe and secure manner (in light of a rapidly changing generation profile) it has become
necessary to launch new, online, power system analysis tools in the control center– one of these tools
is WSAT.
The objective of WSAT (Wind Secure Level Assessment Tool) is to provide the TSO with guidance on
how to continue to operate the power system in a safe and secure manner.
WSAT is a combination of VSAT (Voltage Security Assessment Tool) and TSAT (Transient Security
Assessment Tool), two power system analysis tools developed by a Vancouver based company called
Powertech.
 VSAT concentrates on power system voltage security under steady state conditions (i.e. >
20 seconds following an event, after transient oscillations have been damped out)
 TSAT looks at the transient stability of the system immediately following a change in
system conditions using a time-domain simulation (i.e. < 20 seconds following an event,
when transient oscillations are present).
VSAT
TSAT
WSAT
Figure 2.1 WSAT: Composed of VSAT and TSAT
WSAT will monitor the quasi steady-state1 voltage stability (using VSAT) and rotor angle transient
stability (using TSAT) of the transmission network. WSAT studies will be automatically carried out
approximately every 5 minutes and will be based on real-time snapshots of data from the EMS
(Energy Management System)
WSAT also has the ability to take the base case and scale up wind generation in defined steps
(currently 50 MW is the major step; 20 MW is the minor step to hone in on the stable limit of wind on
the system) whilst consequently decreasing conventional generation (according to a static merit order
which occasionally differs from the market merit order – currently this doesn’t cause any problems
since similarly fuelled units tend not to change prices dramatically (the adoption of a dynamic merit
order list by WSAT is under consideration). This process of ramping up one variable (wind generation)
against another (conventional generation) is called a generation transfer.
1 Quasi steady state, i.e. the period after the transient oscillations have damped out, including the
operation of automatic measures (automatic re-dispatch, under voltage tripping, remedial action or
special protection schemes), but before the TSO can take manual actions (typically up to 5 minutes).

13
The same process can be applied to scaling the load which is useful in areas that are weakly
connected to the system and are prone to voltage collapse.
The stability of the transfer case is measured, at each transfer step, against the voltage criterion for
both N and N-1 conditions. If a criterion is breached at a particular transfer step, then the secure level
of wind that can be accommodated on the system will be reported as that transfer step.
The TSO assesses the reported problem from the output of WSAT and will decide an appropriate
response and action based on the reported scenario.
Wind Generation
(Independent Variable)
Conventional Generation
(Dependent Variable)
Figure 2.2 WSAT transfer with wind increasing and conventional generation decreasing
2.2.2 Energy Management Systems Wind Dispatch Tool (EMS Wind Dispatch Tool)
Due to the high percentage of wind penetration in Ireland it was necessary to develop a tool that can
control the wind farms in real-time. A tool was developed as part of the EMS in order to control groups
of wind farms quickly and efficiently when a contingency or system security scenario arises.
The control being executed on the wind farms can be a MW constraint or a MW curtailment or both.
Constraint refers to reducing the MW output of wind farms in a specific area of the network in order to
reduce a contingency overload on a transmission line or transmission plant in that area.
Curtailment refers to reducing the global MW output of all wind farms by a percentage of their MW
availability in order to maintain the frequency.
Due to priority dispatch policy, some wind farms are given higher priority than others when curtailment
is required. The tool can be used to group similarly classified wind farms together so their output can
be reduced first according to the policy. The wind farms are also defined by geographical region which
helps when applying constraints.
The benefits of the tool are that it automatically calculates the new MW set point for wind farms based
on their current availability and the amount of curtailment the TSO requires on the system. This means
that the wind farms are sent MW set points to reduce their output by an equal percentage.
The tool can also handle curtailment and constraint at the same time as this scenario can often arise
in real-time. Releasing the curtailment or constraint can be executed in steps using the tool in order to
avoid step changes in the frequency.
2.3 GERMANY
The share of installed decentralised generation units (DG) in Germany is significant. The amount of
installed PV is ~41 GW, the wind turbine capacity is about ~50 GW as well, and the amount rises
constantly. Additionally, to these heavily fluctuating renewable energy sources there are more
constant types, like biomass units or small hydro installations (~7 GW). The peak load in Germany is
85 GW approximately. All of these system figures are valid for 2017.
2.3.1 Boundary conditions
The German Renewable Energy Act guarantees a payment scheme for different renewable sources.
The grid companies are obliged to pay for the delivered power. Additionally, they are obliged to
connect all decentralised production units. This led to an extreme diversity of companies running DG-
units.

14
As usual, almost all the DG units are connected to the regional systems at the 110 kV voltage level
(wind farms) or at the medium voltage (MV) (smaller wind farms, single wind units and PV farms) or
even at low voltage (LV) level (PV single units). Only large wind farms are directly connected to the
TSO systems, especially the planned offshore wind farms.
According to the Energy Act the grid companies, where these units are connected, are obliged to take
all delivered power. So all decentralised generation units always run with maximum power output.
Although the amount of DG directly connected to the TSO system is not large, the German TSOs are
strongly involved in managing DG in Germany. The four German TSOs are each responsible for
balancing in their control area and they also forecast the wind and PV for their control area. Deviations
have to be handled online by each TSO as an imbalance. Tools are necessary, for example, for power
exchange scheduling or activating control power (secondary and tertiary reserve).
2.3.2 Observability and controllability (Status quo)
About 90% of the (over 1.5 million) PV units in Germany are connected to the low voltage (LV) level.
Since the low voltage networks are usually not modelled within the DMS, these generators are
allocated to the corresponding secondary substations in the network model. The majority of the
generators connected to the LV and MV networks are not telemetered. The generated power is
estimated in the control centre using reference values or characteristic curves. Necessary control
signals are sent out to these generators using (radio) ripple control.
Some wind farms are directly connected to dedicated bays in medium voltage (MV) substations. The
medium voltage grid operator can observe and control these installations, which, at the most basic
level is remote control of the circuit breaker.
The same situation pertains in the Regional grids, usually 110 kV in Germany. Here, bigger wind
farms are connected. From regional grid control centres these in-feeds can be measured and
switched remotely. The same applies in TSO grids, especially big offshore farms are well observed.
In Germany, the number of different control centres at the MV level as well as in the Regional grids
(110 kV) is large. Additionally, the TSO system is operated by four different companies. The amount of
wind and PV injection is forecast per control area by each TSO. These values are then summated to
provide total values for Germany. This requires well-coordinated communication between the control
centres involved.
2.3.3 Curtailment
A high DG-production can lead to local overloads, (N-1) congestions or critical voltages at various
voltage levels. A curtailment of the power output is possible, if the grids run into technical problems,
caused by the decentralised generation units. This is regulated in the German Energy Act and the
German Renewable Energy Act. Depending on the situation grid companies even have to pay for
curtailed production. As a consequence, a curtailment is usually the last option in grid operation.
Depending on the voltage level, different procedures have to be applied for curtailment of DG-
production.
Congestion in the TSO grid caused by too much DG in-feed cannot be solved by the TSO itself,
because from the TSO control centres DG can neither be observed nor controlled.
 The TSO staff has to contact the appropriate Regional system control centre and ask for a
reduction of exchange power on dedicated transformers
 The Regional control centre staff can then reduce the production of (wind) units connected to
their grid. It is possible to completely switch on/off units or to reduce production in predefined
wind areas. Therefore, a DG management system has to be installed. Via a remote
connection to each DG-unit in the grid, the production can be ramped up or down in defined
steps
 If this measure is not sufficient, the Regional control centre staff has to contact the Medium
voltage control centre staff, which will reduce the in-feed at defined transformers in a similar
way
The required DG management system is not available in all control centres. PV generation cannot
(yet) be controlled in the same manner, mainly because of the high number of installations -
approximately 1.5 million.
Congestions in the Regional Grids are solved in the same manner, here an interaction between the
Regional grid control centre (RCC) and the MV control centre is required. Here, the congestion

15
management is under development to be highly automated, because DG units can be operated
directly via remote control (switch on/off, stepwise ramping of power output).
2.3.4 50.2 Hz effect
Due to the German Renewable Energy act providing high subsidies for PV, the amount of installed PV
exploded in a three year period up to 2011. The old connection rules for PV have created present day
operational challenges [B3].
For PV, the connection rules for low voltage generators are relevant. In contrast to the rules that
pertain for medium or high voltage generators, measures for e.g. dynamic ride-through capability,
frequency stabilization or frequency-dependent power reduction are not taken into account here. As a
result, all installations up to May 2011 (~15 GW) trip at a frequency of 50.2 Hz immediately. The loss
of 15 GW production may cause a large frequency deviation, even in large systems such as the
ENTSO-E system (Continental Europe). The tripped PV unit will reconnect automatically, as soon as
the frequency is below the limit of 50.2 Hz. This may lead to heavily oscillating frequencies, the so
called “yo-yo-effect”.
In May 2011 a temporary arrangement for PV systems changed the requirements for the frequency
protection performance. The over frequency protection should react at fixed values between 50.3 Hz
and 51.5 Hz.
New connection rules for PV units require improved frequency behaviour. As frequencies are above
50.2 Hz, the PV unit decreases its actual power output automatically down to zero at a frequency of
51.5 Hz. At 51.5 Hz the unit is automatically disconnected. The frequency dependent power output will
smooth the frequency in over-frequency situations (similar to conventional units running in primary
control mode).
New installations have to follow these rules (from 2012 onwards). Older installations (before 2012)
have to be retrofitted, if possible, but a certain number of PV units cannot be retrofitted. So the 50.2
Hz effect will still remain to a certain degree.
2.4 INDIA
The installed generation capacity in India as of 31st July 2016 is 305 GW out of which nearly 44 GW is
from Renewable Energy Sources (RES) comprising wind (27.4 GW), solar (8.0 GW), small hydro (4.3
GW) and Biomass (4.8 GW). The existing capacity in wind energy generation is primarily concentrated
in Southern India (Tamil Nadu, Karnataka, Andhra Pradesh) and Western India (Maharashtra, Gujarat,
Rajasthan). The All India gross energy generation during 2015-16 was more than 1107 TWh out of
which more than 51 TWh was contributed by wind and solar generation (mainly from wind energy).
Thus, at the all India level, the present renewable energy penetration is about 5.7% and capacity
penetration is about 14.5 %. The target of renewable energy capacity has been up scaled to 175 GW
by the year 2022 which includes 100 GW from solar, 60 GW from wind, 10 GW from bio-power and 5
GW from small hydro-power.
2.4.1 Control system architecture and control room
The power system in India is demarcated into five regional grids, comprising several control areas of
States/Inter State Generating Stations/Regional Entities. The real-time coordination of power system
and market operation is done by the State Load Despatch Centre (SLDC) in a State, by the Regional
Load Despatch Centre (RLDC) in a Region and by the National Load Despatch Centre at the national
level. The SCADA/EMS is a unified scheme with hierarchical structure and common database for a
region.
The integration of the renewable generation with the grid is predominantly at 11 kV, 22 kV, 33 kV or 66
kV. The transmission system beyond pooling point is either at 110 kV, 132 kV, 220 kV or 400 kV
depending on the quantum of power being pooled. Thus, the renewable generation generally lies
within the State control area which falls under the jurisdiction of the State Load Despatch Centre
(SLDC) of the host State where such renewable generation are interconnected. The RLDC supervises
the interchange at the inter-State boundary. 33 solar parks in 21 states with aggregate capacity of
19,900 MW have been approved. These parks may be connected to inter-state transmission system
and hence, may come under direct jurisdiction of respective RLDCs.
The peak generation from wind is during June to August (monsoon season). In a typical day the
generation from wind farms in most of the States is higher in other than peak hours (1100 – 1800 hrs)
except in Rajasthan where generation peaks at around 1800 hrs. Solar output is generally from 0700

16
hrs to 1900 hrs with peak during 1200-1500 hrs. Occasional congestion in the sub-transmission
system is experienced particularly in states where the renewable generation capacity penetration is
high (Tamil Nadu ~ 37%, Rajasthan ~ 30%, Karnataka ~ 30%, Gujarat ~ 17%, Maharashtra ~ 16%).
Transmission augmentation and dedicated control centres are being envisaged for renewable energy
management in such States. Placement of Phasor Measurement Units at strategic locations along
with creation of a robust infrastructure for high speed communication has been done for Wide Area
Monitoring (WAM) and congestion management.
The utilities in India are mandated to fulfil their Renewable Purchase Obligations (RPOs).
Sale/purchase of Renewable energy is either at regulator determined preferential tariff or at non-
preferential rates. One MWh of renewable energy injected in the grid at non-preferential tariff is
entitled for a Renewable Energy Certificate which is tradable on the Power Exchange within the pre-
defined validity period.
2.4.2 Management of Unscheduled Flows (Deviations) due to variability of Renewables
In the Indian electricity market the physical delivery of capacity/energy contracts is coordinated by the
SLDC/RLDC. The scheduling and settlement period for all contracts is 15-minutes. The Deviation
settlement Mechanism (DSM) rate (frequency-linked rate predefined by the Central Electricity
Regulatory Commission) is used for settlement of the deviations from schedule at the Inter State
boundary. Recently in November 2015, the DSM rate applicable for renewable generators has been
delinked from frequency at the inter-state level. As per this new framework provided by the Central
Regulator, the DSM rate for renewable generators has been linked to the error from scheduled
generation thereby giving signals for better and more accurate forecasting. Forecasting has been
mandated for both the renewable generators and the load despatch centres. The Indian Electricity
Grid Code allows wind and solar generators to revise their injection schedule by giving advance notice
to SLDC/RLDC. There may be maximum 16 revisions in a day starting from 00:00 hours
Reserve Regulation Ancillary Services (RRAS) have been implemented in April 2016 harnessing un-
requisitioned surplus in Inter State Generating Stations (ISGS). At present, ancillary services are being
harnessed from over 50 RRAS Providers. Renewable Energy Management Centres (REMCs) at
State, Regional and National level are being established which are co-located with respective Load
dispatch centres (LDC). REMCs are being integrated with real-time measurement and information flow
from renewable generation sources for forecasting, geo-spatial visualization of RE generation and
control for smooth grid operation.
2.4.3 Future Challenges
The major challenges with respect to large scale integration of renewable energy in the Indian grid are
listed below:
 Real-time situational awareness of renewable generation in Load Despatch Centres
 Adequacy planning and congestion management with high penetration of renewables
 Creating facilities/mechanisms for renewable generation forecast at farm level, at grid pooling
point, at State level, at regional level and at country level
 Creation of standards/mechanisms for encouraging grid-friendly controls in renewable energy
systems
 Creation of facilities for flexible generation/energy storage and creating mechanisms for
demand response for addressing the ramping and variability related needs at high penetration
of renewable energy
 Interconnection of renewable energy rich areas for exploiting geographical diversity
 Reactive power management
 Strengthening the Renewable Energy Certificate Mechanism
2.5 ISRAEL
Israel has currently close to 900 MW of installed PV capacity. A large proportion, 47% (420 MW), are
installed on the LV grid while 260 MW are installed at MV and the remainder at HV. Israel Electric
Corporation (IEC) doesn't have any metering information in real-time (2014). The metering is done
only for commercial purposes. The DNO and TSO don't have any information about real-time
production at LV. This PV capacity – daily generation is not included in the forecast. One 3.5 MW PV
installed on the MV grid has real-time measurements. The information, which is coming to the

17
Distribution Management System (DMS), is: oneline diagram CBs, MW, Mvar and the ability to switch
off PV in an emergency. This information is also going to the EMS.
In the future 4*45 MW PVs will be installed on the 161 kV Grid. So currently we are dealing with an
information basket that has to be transferred to the TSO.
One of the current (2014) ICT projects aims to assemble data from MV grid installations and to bring it
to the DMS and to send summary data, for installations greater than 5 MW, to the TSO. If one PV on
MV has a capacity more than 3 MW the information should be also given to the TSO.
The future challenges are to:
 Connect PV at 161 kV
 To bring data about MV PVs to the system operator
 Start to build PV forecast for the whole grid
 Install smart metering in SMART CITY pilot which will bring information form LV PVs to the
DMS. The objective is to build the model of accumulation of this data for operational purposes
 Build a new operational grid policy based on PV penetration
 Learn from systems with PV experience about disturbances that happened – like 50.2 Hz
problem in the Continental European power system
2.6 AUSTRALIA - TASMANIA
Tasmania is an island system that is connected to mainland Australia by a single HVDC link, Basslink.
The installed generation in Tasmania is predominantly hydro (2270 MW), with some Gas (390 MW)
and Wind (308 MW). Average Tasmanian demand is about 1200 MW, with a minimum over summer
months of around 900 MW. Generation within the distribution network, such as PV, mini-hydro and
wind is considered insignificant/negligible.
Since the connection of Basslink, Tasmania has the capability to import up to 480 MW and export up
to 630 MW to and from Victoria. Being a predominately hydro system has made Tasmania reasonable
robust in terms of non-synchronous generation connection up until this point. This has allowed for
innovative solutions to be made to cater for such a connection to operate in an otherwise small
islanded system. To facilitate these levels of import and export, special protection schemes trip load
and generation should Basslink be lost due to a contingency.
2.6.1 Special Protection Schemes
These schemes operate on the SCADA system and through dedicated redundant (duplicate) relays at
each of the shedding points and control centres. The algorithms for tripping load and generation run
every four seconds, arming sufficient load and generation to trip depending on Basslink import/export
level, Tasmanian demand and the contingent event that is considered.
2.6.1.1 FCSPS
The Frequency Control System Protection Scheme (FCSPS) works on both import and export. This
scheme is required as Tasmania does not have the Frequency Control Ancillary Service (FCAS) raise
and lower capability locally to cope with the loss of the interconnector at both high levels of import and
export. This protection scheme arms generation and load to trip after loss of link signal has been
received from Basslink to maintain frequency within the Tasmanian frequency standard. This standard
is much wider than that of the Australian mainland. Currently the wind farms are not utilised for the
FCSPS.
2.6.1.2 NCSPS
To utilise the existing Tasmanian transmission network, at high Basslink export transmission lines are
run “non-firm”. This is done through a combination of generator shedding and dynamic line ratings
should a contingent loss of a transmission element occur. This allows for lines to be temporarily run
above continuous rating for a small period of time. The Network Control System Protection Scheme
(NCSPS) either slow or fast trips pre-selected generation to return the lines back to continuous rating.
The Fast FCAS response of during export Basslink is utilised to maintain system frequency within
standards. Currently, the wind farms are not utilised for the NCSPS.

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2.6.2 Future Challenges
Further integration of non-synchronous wind generation into Tasmania will start to create additional
challenges that have not been faced operationally until now. Recent studies have shown that beyond
2013, with the additional connection of non-synchronous wind generation, the decreasing system fault
level and inertia conditions will start to have operational impact under high Basslink import conditions.
The combined TSO and DNO, TasNetworks, has already identified potential issues with frequency
control, oscillatory stability and also fault ride through. As an example, with the connection of the
additional wind generation in 2013 it has already been seen that there are changes in the required
FCAS on some contingencies when compared to current system conditions with increased wind
penetration.
Topics currently being explored in Tasmania include:
 Frequency Control Ancillary Service dispatch reflecting fault ride through (real power deficit)
characteristics of wind farms and Basslink
 Inertia constraints for df/dt (RoCoF) following loss of Generation/Load
 Oscillatory stability constraints due to displaced synchronous generation
 Power quality issues arising due to increased power electronics and decreased system fault
levels
 Future regulating reserve with additional wind connections
 Impact of reduced inertia and fault levels on the ability of Basslink to ride through certain faults
on the Tasmanian transmission system
2.7 AUSTRALIA - SOUTH AUSTRALIAN (SA) POWER SYSTEM
The overall penetration of RES in the Australian NEM as a whole is not exceptional having grown over
the last ten years to about 7% for the NEM as a whole [B4]. However the NEM, whilst a medium size
system in generating capacity (45 GW), covers a large area stretching 5,000 km from northern
Queensland to western South Australia and via undersea cable to Tasmania. The NEM was created
by integrating state based power systems and thus the interconnections between some of the regions
of the NEM are quite limited.
South Australia (SA) with a peak demand of about 3.2 GW, for instance, is interconnected to the rest
of the NEM via a double circuit 275kV transmission line of about 600 MW capacity and an HVDC link
of about 200 MW capacity. Thus, the operating issues are almost all on a regional2 basis.
The penetration of RES is also unevenly distributed across the regions of the NEM with wind
generation predominantly in the southern regions and penetration of roof top solar significantly higher
in Queensland and South Australia.
This trend is particularly pronounced in South Australia. Percentage of households with rooftop PV
has reached about 25% [B5]. This growth has occurred rapidly over a six-year period due to:
 Government incentives through high feed in tariffs
 Falling costs of PV Systems
 Rising costs of domestic tariffs due largely to increased spending on distribution systems to
replacing aging assets and improve reliability of supply at the distribution level.
At the same time, there has been a rapid growth in wind generation in the form of large windfarms
connected on the transmission network. Wind generation capacity has grown from virtually nothing to
about 1.6 GW over the past decade. It has reached a point where wind generation has exceeded
demand in South Australia for short periods [B6]. This growth was due to a number of factors:
 South Australia has a large number of sites very suitable for wind generation
 Incentives for renewable energy provided by the Australian government
 Falling capital costs of wind generation.
These developments have totally changed the nature of the South Australian power system. When
South Australia is connected to the rest of the NEM these differences are not particularly evident in
2 The NEM has five pricing regions – New South Wales, Queensland, South Australia, Tasmania and
Victoria

19
terms of power system operations. However, on the rare occasions when it is islanded (on an AC
basis) then very significant issues can arise.
From a market perspective however, these differences are evident even when interconnected since
during periods of high wind generation regional electricity spot prices are depressed. This has
threatened the viability of traditional thermal plant. About 1 GW of thermal plant has withdrawn from
the market with most closed permanently [B7].This situation has been exacerbated by sudden
increases in the price of natural gas due to the commencement of large scale export of LNG [B8].
The impact on power system resilience in South Australia is across a number of areas each of which
interacts with the other to increase the problem.
2.7.1 System Inertia
The changed market conditions have meant a considerable reduction in the conventional generation
being normally synchronised in South Australia. The average system inertia has declined from above
10,000 MW-secs to about 7,000 MW-secs over the last 4 years [B9]. This is only an average figure
and at times the system inertia can be much lower even below 3,000 MW-secs [B10].
This means that following an islanding event the rate of change of frequency can be very high. This
RoCoF may be so high that the traditional under frequency load shedding scheme will be ineffective
leading to the collapse of the South Australian AC island as occurred on 28 September 2016 [B11].
2.7.2 System Strength
There has also been a corresponding decline in system strength (fault level) in South Australia. This of
course has implications for the stable connection of wind farms, SVCs and HVDC links.
2.7.3 Voltage Dips
This decline in system strength also means that the impacts of a network fault are increasing in terms
of depth, spread and duration [B12]. This means that at single fault could trigger the fault ride through
mode for a large number of wind farms resulting in simultaneous drops in output for 500 msecs
creating possible transient stability risks and increasing the consequences of single faults on the
system3.
2.7.4 Frequency Control Services
In the NEM traditional thermal generator and hydro generation has been the supplier of these
services. For the NEM, as a whole, the supply of these services is not at present a problem. However,
the availability of these services has become very limited in South Australia and so frequency control
is a major issue when, on rare occasions this region is required to operate as an island [B13].
2.7.5 Load Following Capability
The variability of solar and wind generation creates greater demand on the load following capability of
dispatch generation. Again, this is not yet an issue for the NEM as a whole but is certainly an issue for
South Australia particularly if the region is required to operate as an island. The high intra-day
variability in South Australia presents a particular problem as
 A significant ramping capacity is required to meet the ramp rate encountered on the evening
peak (as demand increases but PV output falls rapidly) meaning that a larger number of
scheduled generating units must be synchronised but
 Such generation would be required to operate at lower minimum levels in the middle of the
day [B14]
2.7.6 Example of Event of 28 September 2016
These factors have reduced the resilience of the South Australia system to unusual events. The most
significant example of this occurred on 28 September 2016. The event developed as follows.
Just prior to the incident South Australian demand was being met by 330 MW of thermal generation,
613 MW of import from the rest of the NEM and 883 MW of wind generation. System inertia within
South Australia was of the order of 3,000 MW-seconds.
3 For instance, a single fault has the potential to directly disconnect 260 MW of generation but the
associated voltage dip may also lead to the temporary loss of additional supply from wind farms not
directly affected.

20
A severe weather storm passed over the northern part of South Australia where there is a large
concentration of wind farms. This storm unexpectedly generated a number of tornadoes which badly
damaged three 275 kV transmission lines. There were 6 voltage disturbances over a two-minute
period. All wind farms in the area responded by going into their low voltage through mode on three or
six occasions4.
Unknown to AEMO at the time, some of these windfarms have a protective feature by which wind
turbines are shut down if the number of low voltage ride through modes exceeds a set limit in a two-
minute period5. The mechanism resulted in the effective shutdown of eight windfarms. There was also
some temporary reduction in output of other windfarms due to their normal operation during low
voltage ride through. The total reduction in output over period of a six second period was about 500
MW.
This resulted in a rapid increase in the power flow on the 275 kV double circuit line which was the sole
ac interconnection with the rest of the NEM. The flow reached the stability limit and loss of
synchronism protection operated tripping the interconnector.
The South Australian then separated with a very large supply deficiency of the order of 1,000 MW.
Due to low level of inertia there was a very high RoCoF of the order of 6.25 Hz/sec. At this rate the
under-frequency load shedding was unable to operate effectively to rebalance supply and demand.
The frequency fell to 47 Hz in 0.4 seconds and the remaining generating units then tripped. The island
collapsed totally interrupting supply to South Australia.
Restoration commenced once the situation was assessed and action was taken to make equipment
safe6. Restoration was delayed to some extent by the failure of two local system restart sources. This
required supply to be restored from the remainder of the NEM. Within about four hours of the event
40% of the load available for restoration was restored. Within 7.5 hours of the event 80 to 90 % of the
load available to be restored had been restored. Due to the damage to the transmission system in the
north and weather conditions preventing inspections, load in that area could not be immediately
restored. Restoration of much of this load was achieved within 36 hours but some load was unable to
be restored for some days until emergency repairs on some transmission lines had been completed.
Subsequent operation of some of the windfarms was restricted until their limits on successive low
voltage ride through operations had been increased. AEMO also introduced new limits on system
operation to ensure that at least three major thermal units were always synchronised. The South
Jurisdiction also issued a direction that the system be operated such that, following loss of the ac
interconnector, RoCoF would not exceed 3 Hz/sec to ensure that the under-frequency load system
could operate effectively.
Subsequent investigations have indicated that the power system would most likely survived the failure
of the transmission lines provided that the wind farms had remained in operation7.
The initial investigation into this event made a number of preliminary recommendations for practical
actions to
 Reduce the risk of islanding of the SA region
 Increase the likelihood that, in the event of islanding, a stable electrical island can be
sustained at least in part of SA
 Improve performance of the system restart process
 Improve market and system operation processes required during periods of Market
suspension
 Address other technical issues highlighted by this investigation
The final report into this incident has been issued [B15]. It addresses the following issues:
 Where changes to generator access standards are desirable in the light of risks highlighted by
this event
 Performance requirements for possible special protection schemes to prevent islanding of the
SA region or to improve the likelihood of such islanding being successful
4 The voltage trigger setting for the low voltage ride through mode differed between windfarms.
5 For some turbines, the limit was two in 2 minutes and for others it was five. For most of the others,
that did not shut down, the limit was ten.
6 There were number of high voltage circuits down across roads in northern South Australia.
7 There would likely still have been significant interruptions to local loads.

21
 Level of potential risk due to transient reduction of output from multiple wind farms
 Level of potential risk from high winds or rapidly changing winds in in areas of high wind farm
concentration
 The remaining level of risk of loss of multiple wind farms due to multiple faults on the
transmission system
 The possibility of over voltages in the SA transmission system due to UFLS load shedding
following separation from the rest of the NEM
 The possibility of low system strength in the SA transmission system following separation from
the rest of the NEM

22

23
3. FUTURE OPERATIONAL CHALLENGES
The future operational challenges outlined in Chapter 1 are now discussed in more detail in this
chapter.
3.1 ORGANIZATIONAL
3.1.1 State of the Art
Organizational issues in the integration and control of RES and DG have been handled in recent years
in different ways in various countries. These differences are caused by many factors. First of all the
different approach in the management of the RES and DG depends on the voltage level and on the
ownership of the connection grid.
In some countries the electrical system is still fully integrated, in others there has been a complete
unbundling and there are different operators for production, transmission and distribution of electricity.
Often the transmission network is owned by a TSO, in other cases the grid is owned by one or more
companies but the network control and dispatching activities are performed by an ISO.
At a European level, in order to deal with the voltage and frequency control challenges presented by
such a significant level of generation, which can jeopardize the security of the whole interconnected
grid in the case of severe network events, new standards for connection, protection and control have
been defined [B16]. These standards are being implemented at country level by national electrical
committees and sometimes also with the intervention of national Regulators.
Small DG units (typically less than 10 MW) are always connected to the distribution grid or regional
providers’ networks, usually on MV or LV grid and TSOs/ISOs normally don’t have direct control of this
generation. On the other hand large installations are usually on the HV grid and TSOs/ISOs normally
have direct monitoring and control of these power plants.
Nevertheless, in countries where the penetration level of DG is so high as to have a strong influence
on the behaviour of the transmission network, TSOs/ISOs have signed ad hoc agreements with the
distribution companies and local grid owners in order to exchange information about these producers.
Dedicated tools and sometimes even structures to control RES/DG have been realized, with a
particular focus on forecasts and real-time aggregated production monitoring. For example, Spain has
implemented a separate renewable control centre, CECRE. The decision to establish a separate
renewables control centre is a complex one in which the following issues, at least, should be
considered:
 Capabilities and architecture of existing EMS/DMS
 Number of renewable generation sites the TSO/DSO/ISO controls or will control in the future
 Methods employed to control and dispatch renewable generators
 Characteristics of the renewable generators connected to the grid
 Grid characteristics e.g. will the advent of widespread renewable generation lower the fault
level of the grid and alter reactive power management strategies
 Resulting from the foregoing considerations, what new control functionality will be required
and where is the optimum location to site it
3.1.2 Future Trends
The growth trends regarding RES/DG installed power suggest that the same issues already present in
countries with a high presence of these types of production will ultimately spread worldwide.
One of the main problems to tackle, not only from a technical but also from an organizational point of
view, will be the production deviation from schedules and frequency control. Such a high penetration
level of RES/DG can also have an adverse impact on large interconnected systems.
Different approaches can be adopted to resolve this problem. These include:
 Initiatives for improved forecasting of windfarm and PV production
 New rules for imbalances: some penalties could be introduced to RES and DG producers in
order to induce them to provide improved production forecasts and to respect the schedules
declared to markets (e.g. in Italy, where traditional plants are already penalized for
imbalances, the Regulator intends to introduce a similar treatment for RES, but is meeting
strong resistance from producers)

24
 New requirements for frequency primary control of DG and RES: Plants should provide the
primary frequency control alone or in pre-defined clusters as outlined in the TWENTIES
project [B17]
 A de-centralized frequency/imbalance control performed in an area with load and production
in order to guarantee adherence to a scheduled exchange in the matching points with
transmission grid. This solution implies a completely new organization and tools able to
perform this task
 New hierarchical control performed by TSO/ISOs which coordinate actions to be taken by
DNOs or generation control centres in order to guarantee power balance. This solution may
require a new type of organization in distribution companies and a strong data exchange
between them and the grid operators
Each of the above-mentioned solutions implies a significant effort in terms of organizational
improvements, new data exchange systems and in the training of operators at every level of the
system, from producer to DNOs and System Operators, so that they cater for new scenarios and new
types of behaviour.
3.2 OPERATIONS
3.2.1 Congestion Handling in TSO Grids
European transmission systems are highly loaded. The transportation of power from areas with high
infeed, both from controllable conventional and stochastic decentralised production, to areas with high
demand may lead to congestion problems, especially where the tie lines between different control
areas are affected.
These instance of congestion (in real-time operation as well as in the (N-1) contingency case) have to
be handled by the operators in the TSO control centres, until the systems have been reinforced via
grid development or solutions such as demand side response or coordination of remedial actions
between TSOs have been implemented.
In highly meshed systems such as Continental Europe the bulk power flows across many different
countries so congestion cannot be handled by a single TSO. Many TSOs are involved in removing
bottlenecks, so coordinated countermeasures are needed. Depending on the grid regions, different
tools are available. These include:
 Topological measures to reconfigure the network
 Phase Shifting Transformers (PST) are used to shift the flows from highly loaded devices to
less loaded devices. These actions have to be coordinated carefully, especially when several
TSOs are affected
 The redispatch of generation. This has to comply with countries’ individual rules
In many European countries, under undisturbed conditions (Germany/Italy), it is not permitted to
resolve congestion by curtailment of DG/RES, due to RES dispatch priority. As a result, the re-
dispatch of conventional generation is the countermeasure employed.
As soon as there is no conventional production left, an alternative is needed, e.g. re-dispatch of
DG/RES. It has to be decided for each operational situation which form of curtailment of DG/RES is
the most appropriate. In Spain, DG/RES curtailment is an appropriate measure to ensure (N-1)
security on the transmission system.
All re-dispatch measures have to be coordinated: e.g. a chain of several bilateral re-dispatch
measures between neighbouring TSOs can be replaced by one re-dispatch between two partners,
which are not directly connected. To realize these measures, stronger coordination and cooperation is
needed, both operational and contractual.
Critical situations have to be recognized in advance in order to take action i.e. before congestion
occurs. Therefore, the tasks of operational planning and real-time operation will further grow together
in future. One major task is to realize and solve congestion before it leads to a critical situation.
Therefore, in Continental Europe several Security Initiatives were started. In the future TSO control
centres, both colleagues from the real-time world as well as from operational planning will take care of
the systems.
In the Australian NEM large RES are treated as “semi-scheduled” i.e. it can be given a target to
reduce output but not increase output – thus both large RES and conventional generation share in

25
congestion management though generally conventional generation backs down first because of its
higher marginal cost.
3.2.2 Voltage Control – TSO/DNO Cooperation
With the rising share of DG/RES the number of synchronised conventional synchronous generators
decreases, so major possibilities for voltage control are missing. TSOs cannot control the voltage
profiles in their systems by just giving set points for the generators voltage controllers any more.
Voltages are changing much faster, depending on the system load. In high load cases voltages drop
significantly, especially in the absence of voltage control devices. In low load cases voltages are often
critically high. In continental Europe this is often the case on sunny “holiday-days”.
In the future control centre, new approaches for voltage control are required. It is important to state,
that reactive power is always a local challenge. These approaches may include:
 Existing devices have to be used more extensively: extend available reactive power band
of synchronous generators
 Allow switching out of lines in high voltage situations. Here the TSO has to ensure, that
these measures won't endanger the system security
 Make use of control capabilities of the DG/RES. Technically modern wind and PV
converters can control voltage. When these converters are connected at the DNO level,
the reactive power has to be transported to the TSO grid. This requires intensive
cooperation between DNO and TSO. In areas with high/low voltages on the TSO level, the
DNO has to give set points to a large number of DGs on the system, simultaneously
coordinated with tap changer control on transformers from TSO to DNO. This can’t be
managed without technical support by the SCADA systems
 New conventional compensation devices are needed: condenser banks and reactors
 New power electronic based compensation devices are needed, such as Static Var
Compensators (SVC). As these devices replace conventional Q-sources, the provision of
short circuit power in case of faults has to be considered
 A mixture of automatically controlled devices like SVC and manually switchable devices
like reactors is needed, to control extreme changes in the voltage profile
 Synchronous condensers since they can be operated like synchronous generators. They
can also provide short circuit current during faults and inertia
HVDC connections are proposed in long term planning to connect big offshore wind parks to the
power systems. In Germany, for example, the overlaying super-grid is planned to transport active
power directly from high production areas to high load areas. New converter stations have an impact
on voltage control.
 Conventional thyristor based converters (line commutated) always need reactive power,
dependant on the active power. Therefore, automatically switched condenser and filter banks
are employed to keep voltages within the allowed range
 The transistor based converters such as VSC converters can be used for voltage control like
SVCs, independent of the active power
Here, the system wide control of active power flows over the HVDC connections is directly connected
to the local control of reactive power. With the increasing numbers of DG/RES the voltage control
mechanisms will change. Operators should know about possibilities and limits of new Q-regulating
devices. One major task facing future TSO and DNO control centres is the coordination of the diverse
Q-Control-Devices.
3.3 OBSERVABILITY AND CONTROLLABILITY
Since renewable energy has significantly increased its contribution to the demand supply,
observability has become essential to ensure system security. Having real-time information about the
production of all renewable facilities above a certain installed capacity lets the System Operator
distinguish between generation and demand, and it means that it is possible to make reliable and
accurate renewable production forecasts and to avoid demand forecast errors. Observability also
enables modelling of power flow scenarios in order to evaluate the state of the grid under certain
constraints.

26
But that is not enough; controllability is also required to adapt generation to demand profile, to avoid
generation reserve exhaustion, to maintain balance feasibility, and in general to increase renewable
energy sources penetration while retaining the required level of system security.
The challenge for the TSOs and DNOs is to decide which data are essential to perform their
necessary tasks to assure system security within their area of responsibility. These data can include
the following:
 Status of every generator or group of generators connected at transmission or distribution
levels
 Active power generation for every generator or group of generators
 Reactive power generation i.e. leading of lagging for every generator or group of generators
 Characteristics of all generators e.g. are they squirrel cage or DFIG wind generators
 Generator present and forecast availability (up to 72 hours ahead) as dictated by weather
conditions e.g. wind speed and direction at every wind farm on the transmission and
distribution grids. This requirement could also apply to solar farms
 Data and forecasts from aggregators e.g. for active power from PV installed at the low voltage
level
The large amount of information that can be received in the control room has to be well filtered and
concentrated in order to help the operator. This forces TSOs and DNOs to correctly size their control
systems and to invest in new tools and infrastructures.
Depending on the regulatory framework, quick control of the RES production may also be essential.
As an example, in a weakly interconnected system such as Spain, based on the current legislation,
the system operator receives, through the CECRE (the specific control centre for renewable
generation) telemetry for 94.7% of the wind and solar generation installed. 84.2% of this telemetered
capacity is controllable and is able to adapt its production to a given set point within 15 minutes. The
telecommunications deployment to over 2000 renewable facilities, spread all around Spain, has been
achieved as a result of the aggregation of all the distributed resources of more than 10 MW in
renewable energy sources control centres (RESCCs) and the connection of them with CECRE. These
RESCC will work as the intermediary with the TSO - sending information in real-time and executing
orders from TSO, guaranteeing system reliability at all times. This hierarchical structure, together with
the applications developed by Red Electrica de España (REE), is used to analyse the maximum wind
generation supported by the system.
In Australia, the NEM has centralised forecasting systems for large Wind and Solar Farms – thus there
is a need to gather a new class of data for this forecasting (e.g. wind speed measurements and cloud
cover).
3.4 TECHNICAL CAPABILITIES
As the penetration of renewable generation technologies, such as wind and PV increases, the
technical complexity of the control centre will also increase. The control of both active and reactive
power will have to evolve in order to cater for significantly more generators and reactive support
devices such as synchronous condensers. The withdrawal of synchronous generators from traditional
AC systems may lead to problems, depending on system size, in the areas of inertia and
synchronizing torque and fault ride through due to low fault levels. The increasing number of power
electronic devices may also lead to harmonics problems. Additionally, many systems will have to
manage both international and internal HVDC links.
3.4.1 Active Power - Ramping and Frequency Control
The adoption of renewable generation will lead to significantly more ramping, especially in smaller
systems, than has been the case heretofore. This will ultimately affect larger systems as the
penetration of renewables grow. In order to manage these ramps, systems will obviously need a more
flexible portfolio of plant, but from the point of view of this brochure, this also implies an increased
onus on the control centre to balance supply and demand. Control centres will need new tools such
as the next generation of AGC which will be able to concurrently take account of renewable generation
forecasts, demand forecasts, storage facilities, market schedules and internal and external HVDC
exchanges, in order to automate the physical dispatch process.
The replacement of traditional synchronous generators may lead to problems in the areas of rate of
change of frequency (RoCoF) due to a lack of inertia, and synchronous torque. EirGrid in Ireland and
Transend in Australia (Tasmania), both of which are small systems, are addressing the inertia
problem. Both companies limit the total amount of non-synchronous generation on their systems which

27
includes power imported on HVDC links. EirGrid are specifying a new fast reserve [B18] which they
will ask generators to provide so they can increase the amount of non-synchronous generation on
their system from the current limit of 55% while Transend already operate with a non-synchronous
MW limit [B19] in their commitment algorithms, which ensures their system can be safely operated
under any contingency. The examples cited demonstrate that dispatch and commitment facilities will
have to be configurable to take account of new and as yet unforeseen constraints.
3.4.2 Reactive Power Control
The reduction of synchronous generation on power systems will also impact on reactive power
management. In Denmark, the reactive power traditionally provided by synchronous generators will
now, in part, be provided by synchronous condensers. Incidentally, consideration is also being given
to the fitting of flywheels to synchronous condensers so that they can also contribute to the inertia
problem. The addition of reactive power facilities such as these will alter the way reactive power is
dispatched in the control centre. It is envisaged that control centres will need new tools such as
Volt/Var dispatch or security constrained optimal power flow which calculate and issue set points
directly to reactive devices.
3.4.3 Other Considerations
Much work is being undertaken in the areas of load management, smart meters and load response.
This may alter traditional load patterns and system reserve requirements. From the viewpoint of the
control centre, this will affect demand forecasting and consequently power flow, contingency analysis
and fault level studies. New and highly accurate load forecasting tools will be required as load
management and response develop.
The replacement of synchronous generators by non-synchronous units will also affect system fault
levels [B20] while the adoption of new technologies such as dynamic line ratings will also have
implications for power flow and contingency analysis.
3.4.4 Future Energy Management System (EMS)
It can be seen from all of the above that the change in generation technology will have a profound
effect on the control centre and specifically on the Energy Management System. It will be required to
manage many new facilities and a more dynamic power system. The EMS database will obviously
have to expand to cater for the plethora of new devices which will be connected to the system. There
must be a major question as to whether that traditional EMS paradigm of a RTU (Remote Terminal
Unit) device sending /receiving data to/from a central server will have the capabilities to control a
power system with so many diverse devices connected to it. The power system model will become
extremely complex both to establish and maintain.
The use of phasor measurement units (PMU) may solve this problem. PMUs will initially complement
RTUs and ultimately replace them. Bose [B21] has proposed that the results of mini state estimators
(SE), using PMU data, run at the sub-station level, be combined into one overall SE result. All of the
EMS applications such as power flow, contingency analysis, voltage stability and dynamic stability
analysis will then execute using the results of this new SE.
3.5 REGULATION AND COMMERCIAL
The ability of the System Operator to facilitate the mandatory RES/DG infeed connections will be a
requirement for almost all power systems. In the short term, the onus falls on the System Operator to
facilitate this change in infeed but in the longer term the strengthening of the grid structure will be of
importance in order to cater for the paradigm shift in generation. Besides the grid investments
necessary to facilitate the increasing RES/DG infeed, regulation standards have to be developed. The
design and implementation of grid codes and energy markets are critical for operating the system. In
this sense, in Europe some policies are now under development in the European Network Codes to
improve certain aspects of RES integration, such as voltage control or requirements for generators,
with the goal of reaching an internal power market.
3.5.1 Regulation
Connection and operational rules are defined by National Authorities, Electrical Committees and
owners of connection grid respecting the peculiarities of each country. The applied solutions e.g. the
terms of control structures depend obviously on the level of impact of RES/DG.
The applied solutions in terms of control structures and legislation obviously depend on the level of
impact of RES/DG. In some countries their penetration is still marginal so politicians and grid experts

28
are not yet fully focused on the problem. In contrast, in Germany the installed RES/DG capacity is
over 40% of the installed capacity while in Spain it is greater than 30%. In 2015 over 42% of
Denmark’s electricity production was from wind. In those cases, all the stakeholders have been
obliged to find urgently concrete and stable solutions to deal with RES/DG integration.
The management structures and rules sometimes depend also on the novelty and the growth-rate of
this phenomenon. In some cases the growth rate of RES/DG penetration, for example boosted by the
incentive of policies (e.g. Italy), has been very high so that the power system management structure
has had to be completely redesigned.
Incentives and subsidies have a large impact on the development of renewables. The necessary grid
investments to meet the integration of new RES/DG do not match. The operational issues which will
be faced by the System Operators have to be addressed in national policies. Spain is an example of
how TSO operational procedures reflect national policies. Spanish operational procedures have to be
approved by the Ministry and some of them develop essential aspects of present day RES integration,
such as voltage control, curtailment management or requirements for generators.
3.5.2 Commercial
The current power markets are typically not designed to incorporate large scale penetration of
RES/DG generation. Nevertheless, a range of objectives has led to the implementation of policies
which are driving the growth of RES/DG. Power systems are challenged by this development.
RES/DG reduction, during real-time operation, is currently permitted in certain countries but only in
case of security of supply issues (e.g. Germany, Spain and Italy).
In almost all the markets RES/DG has a dispatching priority and this fact has drastically changed the
market outcomes in recent years. Market prices have gone negative e.g. in Germany and Denmark
with high penetrations of RES/DG and in Australia depressed wholesale prices are putting pressure on
thermal generators with the consequent risk of a disorderly exit from the electricity market.
New rules have been recently applied in Denmark considering possible market limitations to wind
generation, if a negative market price occurs.
The markets should be allowed to develop and use all competitive sources of flexibility such as
storage and demand response and exchange flexibility over a large area. Flexibility should be used,
where possible, for national balancing but also for capacity management and voltage control in lower
voltage grids in close TSO-DNO cooperation. Possible new market arrangements could be
implemented to connect RES/DG while safeguarding system security. Working group 11 of Study
Committee C5 discusses market design for large scale integration of intermittent RES in their technical
brochure 557 [B22].

29
4. OPERATIONAL TOOLS
4.1 INTRODUCTION
This chapter discusses how the system operator can operate and manage their network with a high
penetration of variable generation. The remaining paragraphs of this section outline a number of
straightforward steps for controlling an evolving system while the last two sections of the chapter
discuss control centre offerings from two established vendors, PSI and Siemens. These products are
typical of those developed by the control centre industry to address future challenges.
System operators must always have online (real-time) information from significant renewable
resources on both the transmission and distribution networks. Currently, the vast majority of
renewable resources connected to the low voltage level are not visible to the distribution system
operator or transmission system operator. If the penetration of low voltage generation is high then a
significant amount of generation may not be visible to the operators so this adversely affects system
security and stability.
One of the proposed solutions is to make remote monitoring mandatory for generators above an
agreed threshold. This will give a direct monitoring capability to the TSO/DSO so they can intervene in
case system security is compromised. The other solution in the case of large numbers of small
generators feeding into an area, is to define the role of an aggregator who collects the total generation
for a specific domain and sends it as aggregated values to TSO/DSO. This could be a commercial
service provided by one of the generating parties. Aggregation should also be promoted to reduce
errors due to poor forecasting and abnormal local weather conditions. Additionally, aggregators can be
used to manage/operate load response as an ancillary service.
The large penetration of distributed generation and the increasing number of cross border transactions
poses system control challenges for the TSOs. Large meshed synchronous networks such as the
continental European network may have frequency excursions and unexpected changes in flow
patterns. This may also affect the transit countries even if they do not have significant volume of
distributed generation. Switzerland is such an example. Even though the share of wind and solar
generation is less than 5%, the transits over the Swiss transmission network may reach up to 50% of
the typical load demand. To ensure system security, a coordinated approach and awareness of the
injected renewable generation in neighbouring systems is a necessity. Switzerland is part of TSO
Security Cooperation (TSC), an initiative of 11 TSOs, which caters for such a need [B23]. Each TSO
member of the TSC provides a generation forecast for renewables, in their own control area, which
they exchange together with feeder flows and system status values with their neighbours.
All new renewable generation parks should have direct monitoring and/or control possibilities. The
network operator should not allow new generators to be connected without clear, direct monitoring and
control possibilities. The legal instruments could be anchored in the Grid Code together with the
prerequisites for grid connection. The network operator should be authorized to refuse connections of
generation if control and monitoring facilities are not provided.
In order to address issues which may arise in the operation of the system at the DSO/TSO interface,
CIGRÉ established JWG C2/C6.36 to define a catalogue of procedures so that the TSO and DSO can
interact in order to maximise the benefits of renewable / distributed generation and demand-side
response while maintaining overall system adequacy and security. Additionally, the group will also
define how best to optimise and deliver the ancillary services which are available from DSO connected
resources. This group is due to report in 2017.
4.2 PSI
To cope with this rising complexity of grid operations, PSI has developed helpful and useful
functionalities in its control system to assist grid operators in this complex task. A number of these are
outlined below.
4.2.1 Contingency Analysis
Contingency Analysis (CA) checks how the network will react to the loss of one or more elements.
Such elements are, for example, power lines, cables, transformers or busbars. The PSI system
provides an easy-to-use online definition dialog, which uses drag & drop operations to de-energize the
“static CA cases”. In addition to the static cases, so-called “dynamic cases” are automatically derived
from a screening process. All objects with a load larger than a certain user-defined value will be

CHALLENGE IN THE CONTROL CENTRE (EMS) DUE TO DISTRIBUTED GENERATION AND RENEWABLES

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