Smart Distribution
Management.
The evolution of
regulatory tasks
and business
models
Manuel Sánchez, Ph.D
Team Leader Smart Grids
European Commission, DG ENER
Brussels, 13 May 2013
Energy
European Smart Grids Task Force 2012 - 2013
EG1: Standards





Mandate M/490 and validation of work programme
1st of standards by 2012 and 2nd set by 2014
Interoperability and Conformance Testing Map
Coordination with other mandates, e.g. M441 and M468
Cooperation with other regions, e.g. NIST
EG2: Data Protection and
Security
 DPIA template
 Cyber security assessment framework
 Consultation minimum security requirements
EG3: Regulation
 Identification of data handling options and actors
 Implications for regulatory framework
EG4: Infrastructure
 Identification process for "Project of Common Interest"
 Organisation of structures and procedures
EG5: Industrial Policy
 Identification of conditions for investment and speeding
up technology deployment
Dr. Manuel Sánchez Jiménez © European Commission
manuel.sanchez–jimenez@ec.europa.eu
2/11
1
Present regulation of electricity distribution activity
European legislation 2009/72/EC is the common understanding
Task of the DSO
Unbundling requirements of DSO in terms of legal
form, organization and decision-making for other
activities not related to distribution
DSO revenues and distribution grid tariffs (+ in EED)
Retail market: DSO is a neutral market facilitator carry on
the switch of supplier and roll-out of smart metering in
many MS
Dr. Manuel Sánchez Jiménez © European Commission
manuel.sanchez–jimenez@ec.europa.eu
3/11
Present organisation of EU distribution sector*
Dr. Manuel Sánchez Jiménez © European Commission
manuel.sanchez–jimenez@ec.europa.eu
4/11
2
Present organisation of distribution sector in the EU
Existing EU regulation leaves room for national implementation and countryspecific approaches to DSO regulation
> 3500 DSOs
> 1.500.00 km
Ref. Eurelectric
Dr. Manuel Sánchez Jiménez © European Commission
manuel.sanchez–jimenez@ec.europa.eu
5/11
Investments in Smart Grid projects (excl. metering)
Dr. Manuel Sánchez Jiménez © European Commission
manuel.sanchez–jimenez@ec.europa.eu
6/11
3
Smart Integration
Key messages from 1st Workshop, 17 October 2012
Key ‘Smart Integration' Messages
• There is the need for the right market conditions and cooperation with regulators
• Smart integration brings benefits for different stakeholders, but not always for grid operators.
There is a clear need to clarify the sharing cost and benefits among stakeholders and throughout
the value chain
• Third parties might build new peaks or load flows
• Demonstration and deployment means that we are discussing real projects
• DSOs need incentives to invest in other network solutions than 'iron and copper'
Dr. Manuel Sánchez Jiménez © European Commission
manuel.sanchez–jimenez@ec.europa.eu
7/11
Smart Customer
Key messages from 2nd Workshop, 22 January 2013
Key ‘Smart Customer’ Messages
• ‘Developing’ smart options for active customers requires efforts from several market players (DSO, retailer/aggregator, regulators
and policy makers) and thus also multi-dimensional incentive schemes
• Smart customer services will mainly be delivered by the retailer/aggregator based on the different markets; however the role of
the DSO as an independent facilitator neutral from the retailer/aggregators is crucial. Among the services that shall be facilitated
by the DSO electricity distribution with relevant power quality and providing meter values for settlement and extended services
• The most efficient smart customer services will evolve over time based on the customer values, it is therefore necessary to
continuously invest in pilots to identify what is attractive for the customer and at the same time financially and technically
feasible
• Customer information plays an important role. Evolution is not only there for smart grids, but also for active customers
• Multi-dimensional incentive schemes are important, but customer behaviour is not always rational; DSOs, together with
aggregators, must invest in pilots to:
- Prove that aggregation is technologically feasible
- Test which services can be delivered by aggregators to DSOs
• Finally, DSOs (as system operators) need active customers, but they are only one part of the puzzle. DSOs have to further
investigate possible features, carry out pilots and undertake actions that can be used as incubators for new business models.
Dr. Manuel Sánchez Jiménez © European Commission
manuel.sanchez–jimenez@ec.europa.eu
8/11
4
Evolution of data processing and business models
9
Dr. Manuel Sánchez Jiménez © European Commission
manuel.sanchez–jimenez@ec.europa.eu
9/11
Rethinking the regulation of European DSOs
Proposed topics for discussion
Revise the roles and responsibilities of DSOs (IEM,
incl. electro-mobility)
Define the minimum level of consumer data
availability
Define DSO-TSO interaction in compliance with
network codes
Guidelines for remuneration and network
charges for DSO
Guidelines on measures to reinforce Chinese walls
(or unbundling) between any DSO and DER-related
business under the same holding
Dr. Manuel Sánchez Jiménez © European Commission
manuel.sanchez–jimenez@ec.europa.eu
10/11
5
manuel.sanchez-jimenez@ec.europa.eu
http://ec.europa.eu/energy/index_en.htm
http://ec.europa.eu/energy/gas_electricity/smartgrids/taskforce_en.htm
Energy
6
ESB Networks Smart Automation
Ellen Diskin, ESB Networks
Eurelectric Smart Grid Academy
13 May 2013
Table of Contents
1. Smart Automation: What and why?
3
2. ESB Networks Smart Green Circuits
4
3. ESB Networks R&D for future automation
6
4. Developing the underlying infrastructures
5. Challenges and risks
2
12
Document Title
esb.ie
Smart Automation: What & why?
What & why?
● Sensing & control based operation
● Local automation and/or centralised control
● Improves
– power quality (voltage performance)
– continuity
● Automation & associated infrastructure can be used to
deliver new services (energy efficiency, variable DG
access, demand response systems)
● Improves operational efficiency
– improved information to aid fault location
– Remote switching rather than operator travelling to location to
operate switch manually
● Improves safety
– Quicker fault location
– less or no pole climbing
– Avoid full reclosing on faults
4
esb.ie
ESBN Smart Green Circuits
Continuity technology trials
Smart Networks: The Operations Jig Saw
Loop Automation
Tripsaver
ASC
FPI
6
esb.ie
Drivers for new solutions
Irish MV network characteristics
Fault Characteristics
● Total overhead line length 82,596 km (4
times EU average per capita)
● 70-80% of faults are transient
● 67% single-phase
● Earth faults account for 70-80% of all faults
● 55% 10kV, 45% 20kV (51% : 49% for OH
networks)
● ESBN measured results
● Continued 20kV conversion
● 80 earth faults per station per annum
● MV overhead rural outlets = 1086
● 83.5% of earth faults on MV
networks are transient
● Spurs over 30 subs = 879
● Spurs over 50 subs = 216
● Largest spur = 123 substations
● 10kV system has isolated neutral, patented
Faulty Phase Earthing system allows
continued supply in case of earth faults
● 20kV networks are low resistance earthed
with sensitive earth fault tripping
7
● Historically 20kV continuity far below that
of 10kV – aggressive tree cutting
programme adopted, but increases Opex.
Automation may be longer term solution
● 5 year regulated allowance of € 22.3m for
continuity improvement measures (MV
automation)
esb.ie
Single Phase reclosers
Initial Pilot
S&C Tripsaver
● Characteristics
– Vacuum recloser
– Self powered, no battery
– No settings or maintenance
– No communications or coordination
● Installation & operation
– Fit by live line crews
– Manual operation by “load buster” tool
– Blocker device available for work on spur
● Units installed on both 10kV and 20kV
networks
● Measured improvement of
– 18.59% reduction in customer interruptions
– 14.32% reduction in customer minutes lost
8
esb.ie
Single Phase reclosers – further development
Differentiating characteristics
Siemens Fusesaver
● First phase
– 2 shot reclosing then drop-out
– no fuse
– No data storage / memory
– No communications
● Second phase
– New supplier & device => new installation and
commissioning procedures to be developed,
new physical challenges
– Single shot reclosing, in series with fuse
– data storage / memory allows post-analysis
Current data
download via
short range
radio
– Short range radio link allows data download
near installation site
– GPRS & 4G communications modules being
developed
9
Document Title
esb.ie
Distribution automation
Rural automation schemes
ESBN remotely controlled devices
● 2.5 remotely controllable devices per outlet
● independent reclosing, clearing transient faults with
not outage
● pre-set coordination of time-current characteristics
● Remote network re-configuration for operational
purposes (planned load transfers, fault isolation)
● Transducers being developed to connect existing
downline switches without communications
● 1,950 devices by 2015
● Based on fault records, network stat, planning &
operational procedures
– 64% (20kV) 69% (10kV) reduction in customer
interruptions
– 43% (20kV) 39% (10kV) reduction in customer minutes
lost
10
esb.ie
Loop automation
F
Loop Automation Timers
No Voltage
CB
CB
F
Feeder Recloser
M1
Midpoint Recloser
T
Tie Recloser
F
No Voltage
A B
M1
Grading
Grading
M1
A B
Grading
M2
A B
No
NoCommunications!
Communications!
No Voltage
A B
No
NoOperator
OperatorIntervention!
Intervention!
M2
Grading
No Voltage
Grading
T
11
esb.ie
Loop automation
Feeder Recloser
F
CB
CB
F
M1
Midpoint Recloser
T
Tie Recloser
F
No Voltage
A B
M1
Grading
Grading
M1
A B
M2
Grading
Grading
M2
A B
No Voltage
A B
T
No Voltage
12
esb.ie
Advanced MV Arc Suppression
● ASC-C Arc
Suppression Coil
Controller
● PAW Power Auxiliary
Winding
● CIF Current Injection
by Frequencies
● DR Damping Resistor
● ER Earth Resistor
● PLC Pulsing Controller
● EOR-D Earth Fault
Detection
13
esb.ie
Advanced MV Arc Suppression
System features
Control Interface
● Dual tuning mechanisms movement of the coil across the
resonant point of the Network
avoided CIF Current Injection by
Frequencies
● Senses variation in neutral current
and varies inductive current to
suppress arcs, avoiding transient
fault occurrence
● during earth fault, system tunes to
resonant position to maximise
safety at the fault site
● In the event of a loss of Feeder,
during an earth fault, system tunes
by the measured quantity in [A] of
that Feeder to maximise safety at
the fault site.
14
Document Title
esb.ie
Advanced MV Arc Suppression
Results & Development
Result characteristics
● 74.73% reduction in CI
● 65.76% reduction in CML
● 70.26% reduction total outage cost/km
● 8 sites: 2 live, 2 almost fully
commissioned, 2 in construction & 2
more planned
● Developments
– Integration with embedded wind generation,
COMPLETE
– Integration with existing 10kV FPE systems,
ONGOING FIELD DEMO
– Active Current Injection, GOING LIVE MAY
2013
– Advanced fault location system, >75%
REDUCTION IN FAULT LOCATION TIME
15
Document Title
esb.ie
Smart Fault Passage Indicators
● Alert to network operator’s smart phone
● High resolution current traces in online
monitoring system
Fault location – hunting time reduced
from up to 8 hrs to average 1.5 hrs
when combined with ASC and
Pathfinder device!
16
esb.ie
ESBN R&D for future automation
Continuity technology trials
Automation required for energy efficiency
EU Energy Efficiency Directive:
“
ESBN smart energy efficiency measures
Each member state:
…may allow energy savings achieved
in the energy transformation,
distribution be counted towards the
energy savings required
shall ensure that national energy
regulatory authorities pay due regard
to energy efficiency
Low loss amorphous core
transformers
40,000 km 20kV
conversions,
reducing losses 75%
but smart
automation
required for
continuity at 20kV
shall ensure an assessment is
undertaken of the energy efficiency
potentials of electricity infrastructure
concrete measures & investments
are identified for the introduction of
cost-effective energy efficiency
improvements in the network
infrastructure
Conservation voltage reduction:
”
But rural implementation requires
remote control & automation of
downline voltage regulators
↓3% voltage
kW ↓3%
kVAr ↓>21%
esb.ie
Developing the underlying
infrastructures
Continuity technology trials
Telecoms
20
Footer
esb.ie
SCADA interfaces & control
Ongoing development
of SCADA interfaces
for MV Voltage
regulators
Bulk regulator control
facility to be
developed through
SCADA scripting
6 pilot deployments –
2 regulators deployed
under backfeed and
embedded generation
conditions revealed
need for updated
specifications
21
Document Title
esb.ie
Challenges and Lessons Learned
Revision of specifications
MV Downline Voltage regulators
Proposed application
● Several auto reverse power flow modes
● dedicated mode designed to respond in
presence of embedded generation
● DG developers want this as cost effective
alternative to reinforcement
● BUT
– Existing firmware allows only for
selection of automated or manual
tapping, not choice of which reverse
mode is in operation.
– Regulator’s sensing shown to lack
sensitivity to operate with embedded
generation
– Reliability of automation in question
23
Document Title
esb.ie
Difference between should and did…
24
Closed loop operation
What the system did do…
Voltage regulator operating in co-gen
mode, on change of feeding direction
should change sensing direction and
continue to regulate to the pre-set
level
6am on a Sunday morning, at a time of
low load and moderate generation,
voltage regulators cause circulating
current leading to sustained undervoltage. Generation customer tripped
off and could not reconnect.
Reverse power flow operation
What the system did do…
Voltage regulator has reverse
operational modes designed to cooperate with embedded generation
Due to regulators being near zero
current point under certain generation
conditions, the power flow was
outside their monitoring sensitivity,
leading to SCADA alarms as the
regulators could not determine the
appropriate power flow direction.
Document Title
esb.ie
Efficient development & delivery
Delivery considerations
Challenges encountered
● Automation installation works can be
delivered in conjunction with other required
work on same networks
● Some automation systems require network
improvements before installation – many
networks to be arc suppressed require
replacement of insulators
● Assets in need of replacement can be
replaced with new technologies
● New installation and commissioning
procedures should be developed with input
and feedback from local staff –
● practical considerations raised by
operational staff fed back to suppliers can
influence further product development
25
● Delays of weeks, months and seasons due
to technician scheduling – delivery
organisations may have other priorities
● A single bad experience can lead to
mistrust of local operators
● Multiple new systems may be resisted if the
first was not a success…
Document Title
esb.ie
Efficient system integration & protocols
Solutions
Complications
● SCADA and OMS links, and existing
devices and infrastructures can be used
collect increased monitoring data
● Device protocols do not match legacy
systems – many of the new IEDs use
DNP3, ESBN SCADA is IEC 101/104
● New devices can be integrated into
existing SCADA and OMS systems
● Cyber security
● Where possible use of existing SCADA
and OMS systems for new centralised
control operations avoids duplication of
infrastructures
● Use of existing systems ensures that
devices have a single master!
● Fear of over burdening underlying
SCADA infrastructure
● Too many interfaces for small number of
control room operators
● Monitoring without control
solutions….what actions can the CRO
take?!
● Delays in development of commissioning
procedure for latest firmware
26
Document Title
esb.ie
23/05/2013
EURELECTRIC Policy Recommendations
for Active Distribution System
Management
Per HALLBERG
Chairman of EURELECTRIC WG Smart Grids/ Network of the
Future, Vattenfall AB
EURELECTRIC Smart Grids Projects Academy
Brussels, 13th May 2013
Most RES to achieve 20% target by 2020 will be connected to
DSO networks
According to common assumptions,
distributed generation:
 reduces network peak load and
congestion
 And thereby also network investment
needs
 contributes to the security of supply
In reality, distributed generation represents
a huge network integration challenge:
 for grid planning (optimise investments in
distribution assets)
Source: Capacities announced in 2020 in the national RES action plans
 for distribution network operation (ensure
reliability and quality of supply)
1
23/05/2013
Active System Management would optimize the distribution
network by allowing greater interaction between the key
network processes
Network
Planning
Long term
How DER could
contribute to firmness
at the planning stage
reducing the need for
investments?
Connection
&
Access
Different levels of
connection firmness can
reduce investment needs
Operation
Real time
Real time flexibility
can improve the use
of existing assets
Connection & Access
 New types of network access could also help reduce network
investments and make the most of the existing one
 Variable network access contracts could be one such option
DER need to fulfil connection
requirements guaranteeing their
adequate performance towards
the system = capabilities to
ensure the operational security
standards
Source: EWE Netz
2
23/05/2013
Operation
 Flexibility platforms could play an important role, in particular for close to
real-time flexibility
 Basic system states should be defined to allow for this
‘Traffic lights
approach’
Society invests enormous amounts of money in the
restructuring of the energy landscape
Network infrastructures
Support schemes
€60 bn for
RES in Europe
in 2011
Distribution network investments share within overall
network investment is expected to rise from 2/3 by
2020 to 4/5 by 2050
*upper range values considered
3
23/05/2013
Distributed energy
resources create
pressure on DSO
business model
New
system
services at
DSO level
Rules and regulation
should be adapted to
steer
the most
cost-efficient system
solutions
Technical
tools for
DSO
Network
planning
and access
options
DER
connection
requirements
# 1 Properly implement existing EU legislation, namely the
EED and 2nd and 3rd Energy Packages
New system services at the
distribution level could
 be procured by DSOs as
ancillary services
(e.g. flexibility from DG and
consumers to solve grid
constraints)
OR
 be defined in grid codes
(DER contribution to voltage
control/reactive power
management and operational
information exchange)
Market and network operations including examples
of possible system services at distribution level
Source: EURELECTRIC
4
23/05/2013
# 2 Create an adequate regulatory framework that allows
network solutions beyond the traditional approach of
‘investing in copper’
 DSOs should be allowed to take into account DER and
conventional assets when planning their networks (as required
by Article 25.7 of Directive 2009/72/EC)
 DSOs could design and operate their networks more efficiently
if national regulation defines cost-efficiency more broadly
 They should be allowed to implement the most efficient
solutions (the traditional investment solution, the flexibility
service-based solution, or a combination of the two) and be
remunerated via appropriately designed grid fees
However, very few DSOs in Europe have strong and
appropriate incentives to invest in Smart Grids
Source: EURELECTRIC, Regulation for Smart Grids, 2011
5
23/05/2013
DSO should be able to collect the allowed revenue through
network tariffs
 Network costs are mainly capacity driven
 Current volumetric (€/kWh) network tariffs do not
provide right incentives to customers
 Network tariff structures should incentivise demand
response and energy-efficient behaviour while
providing a stable framework for both customers’
bills and DSO revenue
6
23/05/2013
DSO should be able to collect the allowed revenue through
network tariffs
Network Tariff Type
Intelligibility /
Complexity
Economic
efficiency
Cost
reflectiveness
Revenue
adequacy (for
DSOs with no ex
post adjustment)
Fixed volumetric (€/kWh)
Capacity based (€/kW)
Time-of-use volumetric
Two-part tariff (€/kW &
€/kWh), with flat or ToU
energy charge
# 3 Make the most of the relevant smart grid demonstration
projects and already implemented solutions
European
Smart Grids
Investments
(Source: EC
JRC 2012/13):
DSOs are
major
investors in
Smart Grids
€56
Billion to
be spent
by 2020
€5,8 Billion
spent by 2012
on smart grids
and smart
meters
7
23/05/2013
#3 Don not create additional unwanted barriers to Smart
Grids in the network codes instead of exploring synergies
Indicative EU-network codes drafting schedule (Source: ENTSO-E)
DSO diversity requires a flexible approach
# 4 Facilitate the procurement of flexibility from the
market. Unlock the potential of aggregation
 Roles and relationships between new and existing actors
should be defined.
 Existing agents will develop new roles and new agents such as
prosumers, aggregators and recharge managers will come into
scene.
 The network codes on system operation and balancing should
be designed with a view to facilitating such flexibility markets
without foreclosing any market design options.
8
23/05/2013
# 5 Revise access and connection criteria for DER
 Current priority grid access regimes prevent grid and market
operators from implementing cost-effective solutions to avoid
grid congestion.
Overview of level of priority
granted for RES-sourced electricity
plants when connecting & using
the grid (Source: CEER, 2012)
Thank you for your attention!
9
23.05.2013
To a new set of
distribution grid tariffs?
May 13, 2013
RWE Deutschland
SEITE 1
RWE Deutschland
SEITE 2
Agenda
• Distribution grids – new challenges
• Optimal capacity – a regulatory paradigm shift
• Smart tariffs – designing incentives
1
23.05.2013
The challenges for DSO are a reality already today
MITNETZ STROM: Solarpark Senftenberg, 166 MW
RWE Deutschland
SEITE 3
The focus is – and for the next decade will remain –
in rural distribution grids
Generation and demand in Bitburg-Prüm
> The distribution grid was
built to supply
demand.
> Distributed generation
is concentrated in areas
with low demand.
> Additional demand
(e.g. e-mobility) only
later.
Demand
Generation
> Higher degree of
simultaneous demand
(DSM) only later.
RWE Deutschland
SEITE 4
2
23.05.2013
Smart solutions address
both technical and regulatory issues
New challenges…
…require smart solutions.
> In certain regions decentralised
generation exceeding demand.
> Grid construction with smart
concepts and components.
> Increased volatility of generation.
> DSO Voltage control.
> Variable load flows.
> Provision of system services:
> Grid construction too slow.
> Mandatory use of underground
cables.
> Voltage control more difficult.
> Integration of smart meters.
– Frequency control.
– TSO Voltage control.
– Balancing power.
> Optimal grid capacity.:
– Decentralised generation.
– Demand Side Management.
– Decentralised storage.
– Complex solutions.
RWE Deutschland
SEITE 5
dena says that the use of smart technologies
has considerable cost reduction potential
Netzgetriebene Laststeuerung
Reduktion der Stromnachfrage
Marktgetriebene Laststeuerung
Marktgetriebener Einsatz von Speichern
Szenario NEP B 2012
Einsatz innovativer Netzbetriebsmittel
Anpassung der technischen Richtlinien
Abregelung von EE-Erzeugungsspitzen
Netzgetriebener Einsatz von Speichern
Vorausschauende Netzplanung
Potential for investment cost reduction
RWE Deutschland AG DF
SEITE 6
3
23.05.2013
Agenda
• Distribution grids – new challenges
• Optimal capacity – a regulatory paradigm shift
• Smart tariffs – designing incentives
RWE Deutschland
SEITE 7
Regulatory paradigm shift?
> Additional and increasingly simultaneous demand as well as a huge
increase in distributed generation will pose huge challenges for DSO.
> Providing unlimited capacity would result in unacceptably high costs. In
the near future this is in particular the case for rural distribution grids,
although urban areas will face the same problem in later years.
> This opens the possibility for the DSO to use available flexibility of both
decentralised generation and demand to limit grid extension.
Unlimited grid access
Unlimited grid extension
Maximum grid capacity
Smart grid access
vs.
Optimal grid extension
Optimal grid capacity
RWE Deutschland
SEITE 8
4
23.05.2013
The cost savings for generation are real:
restriction to 70 % of power loses only 2 % of energy
Standardised annual duration curve
RWE Deutschland
SEITE 9
The cost savings for demand are real:
up to 42 % less investment in heat pump areas
New heat pump areas
(100 % penetration)
optimized
for grid
purposes
measured
standard for domestic
customer with
electric heat pump
standard for domestic
customer with
electric heat pump
Upgraded heat pump areas
(100 % penetration)
optimized
for sales
purposes
optimized
for grid
purposes /
measured
optimized
for sales
purposes
standard for domestic
customer with
electric heat pump
standard for domestic
customer with
electric heat pump
standard for domestic
customer with
electric heat pump
? kVA*
3,5 kVA*
5,8 kVA*
3,5 kVA*
5,8 kVA*
investment costs
investment costs
investment costs
investment costs
investment costs
?%
100%
122%
100%
171%
1
2
3
2
4
* with EnEV-Standard 2009.
RWE Deutschland
SEITE 10
5
23.05.2013
Flexibility is the key:
Local and global demand meet supply
DSO: local
demand
for flexibility
Grid users
supply flexibility
TSO or market:
global demand
for flexibility
Voltage control
Reactive power
Thermal capacity
Decentralised generation
Decentralised storage
Complex domestic DSM
Balancing power
Wholesale market
Customers use flexibility themselves
RWE Deutschland
SEITE 11
RWE Deutschland
SEITE 12
Agenda
• Distribution grids – new challenges
• Optimal capacity – a regulatory paradigm shift
• Smart tariffs – designing incentives
6
23.05.2013
Determination of allowed revenue in smart grids
Costs
> Smart grid components with shortened life spans must be taken
into account.
> Introduction of new technologies leads to additional technical and
regulatory (!) risks, which have to be compensated for.
Benchmarking
> Efficiency benchmarks have to reconsider certain quantitative
parameters (e.g. line length) and substitute qualitative parameters
(e.g. smart interventions).
Optimale
Leistung
Quality
> The current measures for distribution grid quality have to be reevaluated as interruptions will to a large part be intentional.
> Regulatory micromanagement to determine the optimal grid
capacity must be avoided. Instead suitable incentive mechanisms
should be implemented.
RWE Deutschland
SEITE 13
New challenges to distribution grid tariffs
> Increase in demand will come later:
> Dramatic increase in decentralised generation:
– Restructuring and reinforcing the grid on all voltage levels.
– While alternating load flows lead to higher peak power levels,
energy transported is in steady decline on all voltage levels.
Enabling smart grids
> Energy efficiency does not help.
Higher costs
– Increased use of electricity (heating, mobility).
More power, less energy
– Higher peak power d/t DSM by suppliers.
> Use of flexibility limits grid costs:
– Suitable incentives must be designed.
RWE Deutschland
SEITE 14
7
23.05.2013
New opportunities for distribution grid tariffs
Two developments
All grid users
SLP
2
¼ LW
Selected
grid users
FC
1
FC = Fixed component
EC = Energy component
PC = Power component
PC
1
1
> Smart Grids lead to higher
acceptance for power-based
components.
2
> Smart meters enable power
metering even for domestic
customers.
EC
EC
Two alternatives for compensating for local flexibility:
> Incentive-based contracts vs.
> Dynamic grid pricing.
RWE Deutschland
SEITE 15
Is dynamic grid pricing really an option?
Incentive-based pricing
Dynamic grid pricing
> Small transaction costs.
> Huge transactions costs.
> Larger spread for innovative
flexibility products offered globally.
> Spread will in many cases be
siphoned off by grid pricing.
> Long-term commitment.
> No decision to avoid grid
construction possible.
> Guaranteed availability.
> Mandatory measures (red phase)
required.
> Stochastic approach increases
acceptability for suppliers.
RWE Deutschland
SEITE 16
8
23.05.2013
The traffic light system
The yellow phase
The red phase
> The DSO uses flexibility on the
basis of voluntary contracts with
suppliers.
> Most grid users are not affected.
> The DSO uses flexibility without a
contractual basis.
> Many grid users may still be
unaffected.
green
yellow
red
Market
Market operation in compliance
with the declared time tables and
the tolerable control deviation
Grid operator coordinates some market operators and actions
on a regional / local level
Market out of operation
Grid
No limitations –
100% market-led operation
possible, no bottlenecks
Voltage or thermal problems
•Grid operator uses voluntary agreements including (financial)
compensation with some network users to overcome
temporary network bottlenecks (i.e. mostly local)
•Some network users and their supply companies are unable
to fulfil their contracts as planned, but most users are
unaffected
Grid control to prevent a
total or partial black-out
Legislation
needed
Volume of network capacity that
is considered to be consistent
with a „green light“
Volume of possible bottlenecks that may be dealt with
Exact responsibilities,
duties and rights of parties
with a „red light“
RWE Deutschland
SEITE 17
A new set of distribution grid tariffs
> Higher focus on the power component (implies a lesser focus on a
fixed or an energy component):
– Especially for grid users connected to low voltage.
– For customers without smart meters (variable) capacity payments.
> In addition to the power component a capacity component is needed
on all voltage levels.
> Energy poverty must not increase d/t new grid tariffs.
> Incentive-based tariffs or direct payments better suited than dynamic
tariffs.
>
Keep a clear distinction between the grid and the market sectors.
RWE Deutschland
SEITE 18
9
23-05-2013
EURELECTRIC: Active Distribution System Management
Technical Control Strategy for Active System Management
Brussels, May 2013
Automation and Telecontrol Direction
Agenda
• EDP and EDP Distribuição in brief
• Distribution Generation
• Technical Control Strategy
• Key conclusions
Automation and Telecontrol Direction
2
1
23-05-2013
Agenda
• EDP and EDP Distribuição in brief
• Distribution Generation
• Technical Control Strategy
• Key conclusions
Automation and Telecontrol Direction
3
EDP … From a local electricity incumbent to a global energy player with a strong presence in
Europe, Brazil and considerable investments in USA…
#1 World leader
Electric Sector in Dow
Jones Sustainability
Indexes
#1 Europe
hydro project
(+3,5 GW under
development)
#3 World wind
energy
company
#1 Portugal industrial
group
United Kingdom
21
UK
Employees
France
Belgium
USA/ Canada
260
3422
9 330
100%
Employees
Installed Capacity (MW)
Net Generation (GWh)
Generation from renewable sources
Brazil
Employees
Electricity Customers
Installed Capacity (MW)
Net Generation (GWh)
Generation from renewable sources
Electricity Distribution (GWh)
China
中国
Spain
Angola
Portugal
7252
Employees
6 053 509 Electricity Customers
271 576 Gas Customers
10 992
Installed Capacity (MW)
34364
Net Generation (GWh)
51%
Generation from renewable sources
46 508
Electricity Distribution (GWh)
7 138
Gas Distribution (GWh)
Poland/ Romania
51
475
621
100%
Italy
Brazil
2 635
2 831 651
1 874
8 043
100%
24 544
Poland
Romania
Portugal
USA
Canada
France/ Belgium
34
363
705
100%
Employees
Installed Capacity (MW)
Net Generation (GWh)
Generation from renewable sources
Italy
14
Employees
Installed Capacity (MW)
Net Generation (GWh)
Generation from renewable sources
Spain
2 038
1 015 543
787 869
6 087
15 331
37%
9 517
48 447
Employees
Electricity Customers
Gas Customers
Installed Capacity (MW)
Net Generation (GWh)
Generation from renewable s.
Electricity Distribution (GWh)
Gas Distribution (GWh)
Employees
Automation and Telecontrol Direction
2
23-05-2013
The National Electricity System includes EDP Distribuição as the regulated electricity distribution
company acting under a public service concession. EDP is also present in the ordinary and special
regime generation market and in the regulated and liberalized retail markets
Generation
Transport
Distribution
Commercialization
comercial
DG
(RES)
HV network
Generation
Very HV/ HV
DG
(RES)
μG
(RES)
MV network
MV/ LV
HV/ MV
EV
Automation and Telecontrol Direction
LV network
EDP Box
Customer
EV
5
Agenda
• EDP and EDP Distribuição in brief
• Distribution Generation
• Technical Control Strategy
• Key conclusions
Automation and Telecontrol Direction
6
3
23-05-2013
Integrating a large share of decentralised generation capacities in the distribution network is key
for a low-carbon society …
Before
Now
Big Generation
Very
HV
TSO
DSO
HV
MV
LV
L
Big Generation
Very
HV
L
TSO
DSO
L
L
DG RES
L
MV
L
L
HV
DG RES (μG)
L
LV
L
L
L
L
L
L
L
L
In order to smoothly integrate distributed energy resources (DERs) a fundamental change in network
design is needed
L Loads
Automation and Telecontrol Direction
7
… and will be essential to deliver on the EU 20/20/20 objectives (Directive 2009\28\EC). Portugal
have already achieved 20,5% in 2005 and aims for 31% of share of renewable generation in 2020
Share of Renewables Energy in Gross Final Energy Consumption
Automation and Telecontrol Direction
8
4
23-05-2013
In Portugal the total installed capacity is 18,5 GW (2012) where 10,7 GW (58%) is from renewable
sources and 6,6 GW (36%) is from a special regime generation (SRG), that is, from distributed
resources (DER)
Portugal, 2012: Installed Capacity (MW)
18.546
SRG: 6.610 MW (36%)
1.756
All energy comes from SRG must be
acepted by TSO and DSO
4.739
Cogeneration
Distributed Resources
Cogeneration
1.363
5.656
Mini-Hydro
4.194
618
TOTAL
Coal
Natural Gas
Other Thermal
(Not RES)
Hydro
Wind
Renewable
(thermal)
Automation and Telecontrol Direction
220
Solar
9
Distributed generation represents 41% of total energy consumption in Portugal
Portugal, 2012: Special Regime Generation to TSO and DSO grids (GWh)
Automation and Telecontrol Direction
10
5
23-05-2013
The majority of Distributed Resources are connected to the DSO electrical grid, that is, 65% of
installed capacity and 97% of distributed units. Additionally, distributed generation is disperse
around the country
Portugal: Distributed resources connected to DSO electrical grid
More than 4.000 MVA
interconnected
5.000
500
4.000
400
+ 1.300 MVA
beyond 2007
Capacidade Interligada > 100 MVA
5 MVA ≤ Capacidade Interligada < 10 MVA
Capacidade Interligada < 5 MVA
3.000
300
2.000
200
1.000
100
Anual (MVA)
10 MVA ≤ Capacidade Interligada < 50 MVA
Acumulado (MVA)
50 MVA ≤ Capacidade Interligada < 100 MVA
Strong growth on
connection to DSO grid
0
0
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Ligados no ano
Acumulado
Automation and Telecontrol Direction
11
Distributed Generation has high impacts on electrical grid…
Impacts
Reliability
• Jitter: Voltage variations are related with
circuit impedance seen from the source;
• Voltage dips: The largest negative impact
is related with sudden unit exit for security
reasons;
• Losses: Potential loses reduction due to
higher proximity between generation and
consumption;
• Security of supply: DG may postpone grid
investment in reinforcement
• The reliability of electric grids is very good (close to the 4 "9's");
• The reliability of distributed energy could exceptionally approach 95%;
But ... with some kind of combination of network and DG can
improve the reliability of the whole system.
Automation and Telecontrol Direction
12
6
23-05-2013
Agenda
• EDP and EDP Distribuição in brief
• Distribution Generation
• Technical Control Strategy
• Key conclusions
Automation and Telecontrol Direction
13
Electrical grid and technical control strategy approach
Concepts
DMS
HV
• μGrid: All customers and μG that are connected to a
secondary substation;
• MGCC: μGrids connected to a MV feeder;
• CAMS: MGCC + DG connected to MV
MV
μGrid
CAMS
MGCC
LV
• DMS: Future DMS does not need to have direct access
to the data relative to the (possibly innumerous)
microsources in every microgrid connected to the MV
or LV network. Its purpose is to guarantee system
robustness by analyzing data received from network
elements positioned at the hierarchical level
immediately below (CAMS and MGCC);
Legend:
Primary Substation
DG
Secondary Substation
Customer (μG)
μG (RES)
DMS – Distributed Management System;
CAMC – Central Autonomous Management System;
MGCC – MicroGrid Central Controller;
Automation and Telecontrol Direction
14
7
23-05-2013
From technical operation point of view there are 2 major control levels, besides DMS, in the
distribution network: i) MGCC – MicroGrid Central Controller and ii) CAMC – Central Autonomous
Management System
DSO
Setpoint
DG RES
DMS
State
State
HV
Setpoint State
Setpoint
CAMS
State
State
MV
Setpoint State
DG RES (μG)
Setpoint
MGCC
State
State
LV
• A set-point control strategy is need in order to
management the grid at different levels: (LV – MGCC; MV
– CAMC)
• The MV structure needs to have a updated information
regarding MGCC portfolio;
• Monitoring phase will allow and effective control/
balance action, even in emergency situations (more
demanding);
• Communications should ensure data exchange among all
elements in the MMG (Multi-microgrids): Monitoring and
data acquisition from all elements; Real time generation
control; Real-time load shedding; Voltage and frequency
control coordination;
• DSOs should perform load management measures and
direct DSM only when grid stability and power quality
are at risk, avoiding that system security is jeopardized.
DMS – Distributed Management System;
CAMC – Central Autonomous Management System;
MGCC – MicroGrid Central Controller;
DSM – Demand Side Management;
An Active Management Network is possible by sending set-points based on data collect from the grids
(MV and LV) allowing an optimal balance and guarantying system robustness
Automation and Telecontrol Direction
15
CAMS controls and monitorizes MV network connected to a common primary substation. It is
responsible for the fine tune of MV grid operation ensuring grid stability and reliability
DSO
DG RES
Setpoint
State
DMS
State
HV
Setpoint State
Setpoint
State
CAMS
State
MV
Setpoint
State
MGCC
• At this level it’s essential to have an overall schedule formed
and the decision-making process includes the management
of DG. CAMS is responsible for:
• (i) Critical but not so time-sensitive decisions;
Setpoint State
DG RES (μG)
• Each primary substation HV/MV is a CAMS network element,
that is responsible for controlling and monitoring the
running operations of each feeder from the primary
substation and to report the overall status to the DMS and
others CAMS network elements.
• (ii) Handle a large amount of data communication;
State
LV
• (iii) Coordinate with secondary substation level
(MGCC) to achieve specific functions for a common
goal;
• (iv) Coordinate with DMS in order to control the
amount of DG DER injected that can is necessary to
maintain grid stability;
• The decisions taken in CAMS level can give rise to a series of
effects to sub-level (MGCC).
Automation and Telecontrol Direction
16
8
23-05-2013
1,6 GW of Distributed Generation connected do MV network is dispersed around Portugal… (1/2)
Automation and Telecontrol Direction
17
1,6 GW of Distributed Generation connected do MV network is dispersed around Portugal… (2/2)
Automation and Telecontrol Direction
18
9
23-05-2013
Integration of photovoltaic generation into MV network
(Portugal: Porteirinhos 60/30/15 kV, 20 MVA; 28/07/2012)
Automation and Telecontrol Direction
19
Generation mix between Wind and Hydro (Generation > Consumption)
(Portugal: Varosa 60/30 kV, 50 MVA; Dez. 2012)
Note:
• 37 MVA Eolic;
• 12 MVA Hydro;
Automation and Telecontrol Direction
20
10
23-05-2013
A passive network model of unidirectional flows from HV to MV gives place to a network model
with bidirectional energy flows of HV to MV or MV to HV depending on energy consumption and
generation
No or Low DG
High DG
Components
Consumption
Generation and Consumption
Load forecast
Based on the history and
seasonality
More complexity
Load diagrams
Load curves stabilized
Load variations according to the
generation
Configuration optimized for long
term
Increased complexity in the
definition of optimized
configuration
Network configuration
Automation and Telecontrol Direction
21
MGCC controls and monitorizes all the microgrids (LV feeder) connected to a common secondary
substation. It is responsible for the fine tune of LV grid operation ensuring grid stability and
reliability
DSO
DG RES
Setpoint
State
DMS
State
HV
Setpoint State
Setpoint
State
CAMS
State
MV
Setpoint State
DG RES (μG)
Setpoint
State
MGCC
State
LV
• A centralized control (MGCC) is a MGCC network element that
is responsible for evaluating the data received from enddevices (such as smart meters);
• MGCC analyze the current status of microgrids and take
actions in order to guarantee grid connection;
• There are two major smart meters type/ features for
monitoring and controlling:
• (i) DG smart meters: Collects information, as well as
monitoring and controlling DG DER power levels and its
connect/disconnect status;
• (ii) Load smart meters: Aggregates all the resistive and
inductive loads. It can also act over specific loads.
• For example, a MGCC network element monitors the
operation state of secondary substation and sends control
instructions to open or close secondary substation breakers
for switching between island-mode and grid-connected mode.
• The decisions taken in MGCC level need the most timesensitive operations to achieve real time control of the
microgrids and enhance the robustness of the power supply.
Automation and Telecontrol Direction
22
11
23-05-2013
In the end of 2012, Portugal has 97 MVA of installed capacity in Micro and Mini Generation and
these sources have generated 133 GWh
Only 0,3% of energy consumption is from
micro and mini generation
Portugal:
MicroGeneration
(<3,68 kW)
Enough to ensure public lighting in 3 major
municipalities of Portugal
Portugal:
MiniGeneration
(<250 kW)
Automation and Telecontrol Direction
23
81,3 MW from microgeneration are connected to 14k secondary substation (22% of total). For
operation and security reasons it’s not allowed to connect over 20% of installed capacity per
transformer
Portugal: Micro and Mini Generation (<3,68 kW) - LV
Portugal: MiniGeneration (<250 kW) - MV
206 minigenerators
conected to MV grid
(15,7 MW)
Secondary Substation
(%P uG/transformer)
21.823 micro and
minigenerators conected
to LV grid (81,3 MW).
Note: 238 minigenerators
with 4,1 MW
Automation and Telecontrol Direction
24
12
23-05-2013
EDPD needs to invest 1,5 M€ per year in network reinforcement to be able to accept 81k
microgeneration units predicted for 2020
Challenge
• The increasing availability of microgeneration can have an impact in LV grids if these units
impose voltage levels above regulation levels (±10% at connection point).
Study approach
• Regarding reference networks, microgenerators were connected at different points to
assess the network behavior in the presence of these charges. This analysis aimed to
determine the average cost per microgenerator;
• The values obtained per reference network were aggregated in order to obtain the
weighted average cost of connecting a microgenerator with the LV network.
Result
• In this scenario, it may be considered a constant investment associated with a constant
microgeneration growth, with a value of about 1.5 M€ per year.
LV grid (kVA)
# Secondary Substations
# Clients
# Microgeneration units (2020)
Average cost per unit (€)
Investment in grid reinforcement (M€)
Automation and Telecontrol Direction
25
KEMA study request by ERSE focus on the impact of DG on MV and LV grids. 3 scenarios were
analyzed in order to show the investment necessary to accommodate DG that strongly depends on
several factor as DG penetration, location and concentration as well as operating regimes
MV: <16%
MV: <8%
LV: < 25%
LV: =75%
• The results shows that a very significant investment
costs can be avoided if the allocation of DG is realized
under tighter criteria, thus empowering the DSOs and
limiting the option of promoters;
• Under a more liberal regime for DG allocation, the
investment is significantly higher, unless the operator
adopts an Active Network Management (ANM) regime
based on monitoring/ control/ communications
systems;
• The implementation of an ANM solution for voltage
control allowed total Capex (total investment in 10
years horizon) savings above 100 M€ for the most
critical situations;
Without grid constrains (i.e. maximum of µG per SS) an active management strategy is needed
in order to avoid high investments (10 M€/ year)
Note:
•
•
•
Reference/ BAU:
• MV: i) Location: the ratio between the rated power of each MV DG unit and the minimum short-circuit power at Point of Common Coupling
(PCC) is lower or equal to 8%; ii) Concentration: one unit per MV feeder;
• LV: i) Location: at the customer; ii) Concentration: total microgeneration capacity installed in each LV network is lower or equal to 25%;
There is no guarantee under the massive presence of DG and therefore other very relevant costs need to be taken in consideration (beyond scope);
These costs relate to conventional generation necessary to maintain system security or transmission infrastructure reinforcement;
Automation and Telecontrol Direction
26
13
23-05-2013
KEMA study request by ERSE focus on the impact of DG on MV and LV grids
3 scenarios description for 2020 horizon
Study of the Impact of Distributed Generation on the National Electrical System
Request by ERSE (Portuguese Regulator)
Description of the 3 scenarios for 2020 horizon
Reference/
BAU
• The presence of DG on the MV and LV is moderate much like nowadays;
• Load: 72,189 GWh (41% SRG; 29% SRG renewables);
• Power: 10,5 GW (28% on MV and LV grid);
Scenario 1
• Suppose a very significant presence of DG on MV grid;
• Load: 68.154 GWh (52% SRG; 40% SRG renewables);
• Power: 12,2 GW (34% on MV and LV grid);
Scenario 2
• Suppose a very significant presence of DG on LV grid;
• Load: 68.154 GWh (52% SRG; 40% SRG renewables);
• Power: 13,7 GW (41% on MV and LV grid);
(MV focus)
(LV focus)
Automation and Telecontrol Direction
27
InovGrid project is a solution that connects all levels: i) Client - EDP Box (EB), ii) SS Distribution Transformer Controller (DTC), iii) PS - Smart Substation Controller (SSC)
and iv) Central Control Systems
HV Dispatch (Oporto)
CPD Data
(Ermesinde)
Center
(Ermesinde)
MV Dispatch (0porto)
DTC
Automation
(Primary Substations)
Automation and Telecontrol Direction
Displays
EV
Home Automation
28
14
23-05-2013
LV Monitor is a national project between EDPD, EFACEC and INESC, financed by QREN, to develop
solution for monitoring and control LV networks. Project main goals are to develop solution for
dynamic control of microgeneration and detect and locate faults in LV grid
• Development and implementation of advanced algorithms to calculate the
optimal set-points to send to the coordinated control of microgeneration units;
• Development of a photovoltaic controller that interface with the secondary
substation. It will allow the fine tune and dynamic power set points to
microgeneration unit;
• Development of a communication protocol between: i) electrical grid elements
and photovoltaic controller and ii) photovoltaic controller and inverter;
• Development of algorithms for photovoltaic controller for effective dynamic
control of micro-inverters;
Automation and Telecontrol Direction
29
Agenda
• EDP and EDP Distribuição in brief
• Distribution Generation
• Technical Control Strategy
• KEMA study (Portugal)
• Key conclusions
Automation and Telecontrol Direction
30
15
23-05-2013
DSOs have to decide on the most efficient investments in order to cope with the forecasted future
demand and the connection requirements of new distributed generators
Macro conclusions
• ANM implementation that uses monitoring and control systems to deal with voltage variations
is compulsory;
Active
• Hierarchical system based on a set-point control strategy is need in order to management the
Network
grid at different levels and allowing grid fine tune;
Management
• Strong communication infrastructure is needed to ensure communication with all grid
elements, namely on micro grids;
DG
integration
(Portugal)
• To integrate the number of microgeneration units predicted for 2020 (81.500) it may be
considered a constant investment associated with a constant microgeneration growth, with a
value of about 1.5 M€ per year;
• Research projects and pilots like “LV Monitor” allow EDPD to develop solution for dynamic
control of microgeneration and faults detection in LV grid;
• MV and LV grids may require more or less significant investments depending on several factors
such as DG location and centration;
• There are efficient ways to adapt them and enable DG integration with minimized cost though
the employment of active management strategies (possibility to avoid 100 M€ investment);
• The relaxation of DG interconnection requirements should be made dependent on the degree of
IT and distributed sensors implementation (i.e. smart grid)
Automation and Telecontrol Direction
31
Thank you for your attention
Francisco Melo
EDP Distribuição
francisco.melo@edp.pt
Automation and Telecontrol Direction
32
16
EURELECTRIC SMART GRID PROJECTS ACADEMY
Dynamic Optimization Of
Medium Voltage Grid
(ZUQDE- industrial research project)
Albana ILO
3rd Workshop: Smart Distribution Management
Monday, 13 May 2013
Smart Grid Overall Model
ZUQDE
Zentrale Spannungs- (U) und Blindleistungs- (Q) Regelung Dezentraler Erzeuger
Central Volt/Var Control in presence of DG’s
Brussels, 13 May 2013
The Energy Supply Chain Net
An “Energy Supply Chain Net” is a set of automated power grids, intended for
links, which fit into one another to establish a flexible and reliable electrical
connection.
Each individual link or a link-bundle operates independently and have
contractual arrangements with other relevant boundary links, link-bundles, and
suppliers which inject directly to their own grid.
Under specific conditions each automated power grid or a couple of them can
split, thus creating a “Microgrid” and vice versa.
Brussels, 13 May 2013
Voltage Control
The Energy Supply Chain Net
Actually
Transmission
HVG
HVG
Distribution
~
High voltage
allowed limits
~
HVG
HVG
~
~
MVG
MVG
~
~
Medium voltage
allowed limits
MVG
MVG
LVG
LVG
LVG
LVG
Brussels, 13 May 2013
Low voltage
allowed limits
ZUQDE – project control scheme imbedded in
the „Energy Supply Chain net“
net model
Primary
control
Transformer
Tap
Normal operation
HVG
HVG
~
High voltage allowed
limits
static constraints
ZUQDE Server
+
Ubus
~
MVG
MVG
-
~
~
G
MV-Limits
cos-Limits
DSSE
Primary
Control
Reactive power
+-
VVC
Closed Loop
Control
Uset point
Qset point
cos TR
.
.
.
Primary
Control
Reactive
power
LVG
LVG
P, Q, U, …
Control Center
Brussels, 13 May 2013
Medium voltage
allowed limits
G
Lwo voltage
allowed limits
ZUQDE
Zentrale Spannungs- (U) und Blindleistungs- (Q) Regelung Dezentraler Erzeuger
Central Volt/Var Control in presence of DG’s
Brussels, 13 May 2013
ZUQDE  Zentrale Spanungs (U) – Blindleistungs (Q) Regelung Dezentraler Erzeuger
Project data
•Start:
01.07.2010
•End:
30.04.2012
•Funded by:
New Energy 2020, Austria
•Total budget:
~0.55 Mio. Euro
•Partners:
Salzburg Netz, Austria
Siemens, Austria
Brussels, 13 May 2013
Demonstration region Lungau
 Voltage level 110kV; 30 kV; 10 kV
 Maximal Load ~ 23 MW
- Winter
 Decentralised generation ~ 5.6 MW
- Hydro power plant
- Spring & Summer
 Line length
- Cable structure
MOTIVATION
 Further decentralised generation is required
 Challenge to keep the voltage with in the limits
Brussels, 13 May 2013
389 km
38 %
Voltage/var control based on
distribution systems state estimator
Un ± 7%
+
DSSE
Ucal (1) ... Ucal(n)
Voltage / var control
U 138 kV
 4 DGs are participating in
controlling process
P, Q
LTC
13.8 kV
 installed power  3.67 MW
I
I
I
P, Q
Fuse
 upgraded with var controller
∼
P1, Q1
∼
 P, Q, U measurements
Pi, Qi
Cabel
∼
Pm, Qm
Brussels, 13 May 2013
0. 4kV
Distribution System State Estimator
Minimum data needed to realise
closed loop
 R, X, … of lines, transformers, …
 Load profiles
 Real time measurements
-U in HV bus bar
-P, Q in feeder level
-P, Q in controlled DGs
 Usage of data validation tool
Results
 Very accurate voltage calculation
 P, Q, U, … calculated for every
element
 Execution time 49 ms
Brussels, 13 May 2013
Project control scheme
Primary
control
Transformer
Tap
ZUQDE Server
+
Ubus
-
G
MV-Limits
cos-Limits
DSSE
Primary
Control
Reactive power
+-
VVC
Closed Loop
Control
Uset point
Qset point
cosTR
.
.
.
Primary
Control
Reactive
power
P, Q, U, …
Control Center
Brussels, 13 May 2013
G
Features of MV- controlling schemas
Secondary control
Uset point
VVC
Closed Loop
Control
Qset point
Primary control
Uset point
Uset point
Qset point
 Different optimization objectives:
- violation alleviation
- loss minimization
- load reduction (Conservative Voltage Redaction)
 cos() constraints in HV/MV crossing




Tap’s coordination in different voltage levels
Master/Slave principle
Coordination with primary control
Elaborated order proposal to move the system from
one status to the other one without violations
 Calculation time ~7.5 sec
 Cyclic time 1 – 15 min
Brussels, 13 May 2013
+
Qset point
_
+
_
G
 Keep the voltage/ reactive
power to the set point
 Work independently in
absence of secondary
control
 Appropriate reaction for
very fast voltage changes
(LTC’s)
 Maximal reaction time 4
sec
 Time constants 2-4 min
Voltage profile
Generator is participating in
secondary control process
Generator is not participating in
secondary control process
Q = 0 kvar
Brussels, 13 May 2013
Q = 1070 kvar
capacitive
Dynamic controlling area
Brussels, 13 May 2013
Closed-Loop operation results
Load drop compensation
32,5
[kV]
32
Operation limits
31,5
Limits
2
1
3
31
Operation limits
Limits
31,5
1
31
4
30,5
Only violation alleviaton
32,5
[kV]
32
Limits
29,5
Operation limits
29
0
10
20
30
40
[km]50
Nominal
Limits
29,5
Operation limits
29
0
10
20
Limits
31,5
1
2
30,5
3
4
30
30
Operation limits
31
2
30,5
Nominal
Conservation voltage reduction
32,5
[kV]
32
30
Brussels, 13 May 2013
40
[km] 50
Nominal
30
4
3
Limits
29,5
Operation limits
29
0
10
20
30
40
[km]
50
Conservative voltage reduction
Identification of voltage reduction potential
Time
Load
Voltage
reduction [%]
Load
reduction
[%]
Energy saving potential
07:03.2012; 15:38
Maximal load
4,33
6,53
07:03.2012; 16:00
Normal load
4,67
7,06
From literature* "1% reduction in
voltage results in , on average, a
0.4 - 1 % reduction in energy
consumption"
08:03.2012; 21:37
Minimal load
4,33
4,67
08:03.2012; 22:13
Night current
4,33
6,57
expected circa 2% energy saving
* MEASURING THE EFFICIENCY OF VOLTAGE REDUCTION AT HYDRO-QUÉBEC DISTRIBUTION, IEEE 2008
Brussels, 13 May 2013
Conclusion
Dogma „garbage in, garbage out“ is cleared out
Presence of DGs is increasing the distribution network flexibility and makes
possible the realisation of different controlling schemas
Dynamic optimization of distribution networks with a minimum of real time
measurements is realistic
The conservation voltage reduction can be applied smoothly
Using DGs to control the system voltage can lead to operation at poor
power factor
Brussels, 13 May 2013
Since January 2012, the medium voltage network in
region Lungau in Salzburg, Austria is continuously
operated in closed loop.
Brussels, 13 May 2013