SMART GRID, SMART CITY TECHNICAL CASE STUDIES
DISTRIBUTION MONITORING AND CONTROL (DM&C)
QUICK FACTS
What is DM&C?
DM&C refers to
technologies used
to remotely monitor
asset utilisation,
loading, faults and
power quality on the
distribution network
and to provide realtime information
to the network
operator.
What was trialled?
Over 4,000 DM&C
devices measuring
current, voltage
and power factor
at distribution
substations have
been installed as of
end of 2013.
Trial period
Ongoing program
started in 2008.
What were the
outcomes?
The installed
devices enable
real-time monitoring
of the low-voltage
network, for
example peak
demand, utilisation,
faults and power
quality, avoiding
manual collection of
data and minimising
fault patrols.
IN BRIEF
The distribution monitoring and control (DM&C) program involves technologies that
have the potential to deliver operational efficiencies and improve asset utilisation
through continuous remote monitoring of distribution substations and the lowvoltage (LV) network. From 2008 to the end of 2013, more than 4,000 monitoring
devices measuring current, voltage and power factor were installed as part of the
standalone program, which was further evaluated for Smart Grid, Smart City.
Traditionally, only a small number of high-value assets at the zone substation
level have been monitored, as the relative costs of the monitoring equipment and
associated communications did not make it economically feasible on the HV or LV
networks. Continuous remote monitoring of LV distribution assets could provide
valuable information on asset utilisation, faults and network state, which can be
used to optimise transformer and LV line loading, improve the planning and design
processes and improve network reliability by narrowing down the location of faults.
The DM&C solution deployed collects continuous measurements of voltage, current,
real and reactive power across all three phases in the distribution substation.
The deployment of the DM&C devices has provided the network operator with
the ability to obtain real-time measurement data from any substation fitted with
the equipment. A visualisation tool developed for the program allows the network
operator to access and analyse any collected data, giving greater insight into the
network state.
This case study also reports on the indicative business case for deploying DM&C in
Australia on a per feeder basis.
Page 1 of 6
SMART GRID, SMART CITY TECHNICAL CASE STUDIES
DISTRIBUTION MONITORING AND CONTROL (DM&C)
Kiosk
Kiosk
The AU$100
million Smart
Grid, Smart
City Program
ran between
2009 and
2013, testing
arguably one
of the widest
ranging
technology
assessments
of smart grid
products in
the world.
Incoming
Feeder
Maximum Demand Indicator:
Measures
SCADA
only 1Ø currentMeasures
to +/-20%.
Manually read
only 1Ø current;
Monthly
data
download
every 6 months
SCADA
Measures only 1Ø current;
Monthly data download
Maximum Demand Indicator
Measures only 1Ø current to
+/- 20% at Transformer,
manually read every 6 months
Maximum Demand Indicator
Measures
only 1Ø current
to
DISTRIBUTION
SUBSTATION
+/- 20% at Transformer,
manually read every 6 months
Figure 1: Legacy Equipment and Measurements
PolyLogger: Connected
to each of the LV feeders
every four years to
measure voltage and
current
PolyLogger / MaxiAmp
Measures 3Ø current and
voltage on each distributor;
manually read every 4 years
PolyLogger / MaxiAmp
Measures 3Ø current and
voltage on each distributor;
manually read every 4 years
CURRENT INDUSTRY APPROACH AND ITS LIMITATIONS
The monitoring of distribution network assets is generally limited to only a small
number of high-value assets at the zone substation level. Data from assets on the
LV distribution network is commonly collected through routine inspections by field
staff.
Maximum demand indicators (MDI) are installed in most distribution substations.
They record the maximum demand supplied by each substation since the last read
and reset of the device. Typically the MDIs are manually read twice a year to gather
information regarding the peak summer and winter demands for each substation.
The MDI readings form the basis for forecasting future demand and drive the
maintenance, upgrade and planning processes for distribution substations. The
readings inform network operators of what the maximum demand was during the
period since the last read, but provide no information regarding when the maximum
demand event occurred and its duration.
Load surveys are collected for a period of one week every four years to identify
overloads and phase imbalances on distribution transformers. These measurements
are assumed to be representative, but provide only a very limited view of the
operating conditions.
With limited real-time information available, the network design and planning
process is based on conservative assumptions regarding asset utilisation and
capacity. This can lead to higher capital investment costs and customer bills.
The management of network state is also affected by the limited availability of realtime data, with network state in many cases still managed using pin boards, where
the control room operators manually move pins to update their view of the network
state.
Page 2 of 6
Customer calls in combination with feeder patrols working their way along
the feeder are used to determine fault locations. If no fault is located through
this approach, a process of elimination is used to identify the faulty section by
sectionalising and re-energising different parts of the feeder through manual
switching. The main limitation with the current approach is that it subjects assets to
faults and can take considerable time for field staff to patrol the feeder once on site.
Remotely measures 3Ø
current and θ (bidirectional and no
Remotely measures 3Ø
saturation)
current and θ (bi-
Kiosk
directional and no
saturation)
Kiosk
SMART GRID, SMART CITY TECHNICAL CASE STUDIES
DISTRIBUTION MONITORING AND CONTROL (DM&C)
Remotely measures 3Ø
current and θ (biOtherand no
directional
saturation)
Kiosk
Optical Sensor: Measures 3Ø
current and phase angle (bidirectional and no saturation)
Kiosk
Other
Remotely measures 3Ø
current and θ (bidirectional and no
saturation)
Incoming
Feeder
Other
Remotely measures 3Ø
voltage to +/- 1% (i.e. LV
Voltage Sensor: Measures
3Ø voltage to +/-1%
Remotely measures 3Ø
voltage to +/- 1% (i.e. LV
Bus)
Smart
Device
DM&C Module: Collects
data and communicates
Smart
either viaDevice
3G or WiMAX
Smart
Device
Various communications
options including 3G and
WiMAX
Various communications
options including 3G and
WiMAX
Various communications
options including 3G and
WiMAX
Smart
Remotely measures 3ØBus)
Device
voltage to +/- 1% (i.e. LV
Bus)
Various communications
options including 3G and
WiMAX
Remotely measures 3Ø
voltage to +/- 1% (i.e. LV
Bus)
Other
Remotely measures 4 x 3Ø
current to +/- 5% (i.e. each
distributor)
Remotely measures 4 x 3Ø
current to +/- 5% (i.e. each
distributor)
Current Transformers:
DISTRIBUTION SUBSTATION
Remotely measures 4 x 3Ø
current to +/- 5% (i.e. each
distributor)
3Ø4current
RemotelyMeasures
measures
x 3Ø to
+/-5% on each LV feeder
current to
+/- 5% (i.e. each
distributor)
Figure 2: DM&C Equipment and Measurements
BEST PRACTICE APPROACH AND POTENTIAL BENEFITS
Continuous remote monitoring of the LV network can greatly improve a network
provider’s insight into network state, fault locations and asset utilisation.
In practice, the approach involves installing monitoring devices at several points
on the network, for example on distribution substations, capable of providing
measurements such as voltage, current and power factor. More advanced solutions
can also measure environmental factors such as air temperature, wind speed and
humidity to provide a more accurate view of asset condition. Fault indicators
installed on HV feeders can provide the network operator with information
regarding fault locations.
The data from the monitoring devices is transmitted to the control room to enable
real-time information sharing and stored for planning and design purposes.
This provides real-time information on asset utilisation, loading, power quality
and phase imbalances and delivers operational efficiencies by automating data
collection normally collected by field crews. The collected data may be used to
improve the network performance and provide data for the grid operators to
optimise the network planning and design process.
When a fault occurs information from line fault indicators can be used to narrow
down the search area for the field crew, enabling power to be restored to customers
more quickly.
Page 3 of 6
SMART GRID, SMART CITY TECHNICAL CASE STUDIES
DISTRIBUTION MONITORING AND CONTROL (DM&C)
You might
also be
interested
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of New York
– Smart Grid
Project
Figure 3: DM&C Device Installed in Kiosk Substation
Figure 4: Sensors Installed on LV Board
THE TRIAL
From 2008 to the end of 2013, more than 4,000 monitoring devices measuring
current, voltage and power factor were installed as part of the standalone DM&C
project, which was further evaluated for Smart Grid, Smart City. Its key objectives
were to:
• Deliver a visualisation capability to search, filter and view measurement data
• Improve accuracy and timing of LV network measurement data
• Enable continuous monitoring of distribution substation performance and utilisation
Sites were selected based on a number of criteria, including fault frequencies and
durations, high utilisation and the number of customers served. The rationale behind
this was to identify distribution substations where enabling remote monitoring
would be likely to deliver the greatest benefits.
Most distribution networks fundamentally have three design types for distribution
substations: kiosk, chamber and pole transformers. A number of different enclosure
designs to house the DM&C equipment were required, along with enclosure
modifications to ensure that devices installed outdoors could cope with adverse
weather conditions. Four enclosure designs were ultimately developed as part of the
program to fit almost 60% of kiosk substations.
The equipment was installed by two separate teams; one for the physical installation
of the equipment; and the other for calibrating and commissioning the equipment.
Where possible, installations coincided with other outages to reduce the impact on
customers.
The DM&C solution deployed for the program provides online real-time data and
collects continuous measurements of voltage, current, real and reactive power
across all three phases in the substation. In addition, it provides extra analogue
and digital inputs/outputs. This makes it possible to monitor or control additional
equipment in the distribution substations. Examples are sensors measuring
temperature, humidity, fire, water level and battery status.
Page 4 of 6
SMART GRID, SMART CITY TECHNICAL CASE STUDIES
DISTRIBUTION MONITORING AND CONTROL (DM&C)
The
visualisation
tool provides
a user
interface
for viewing
alarms and
events,
historical
analysis
Figure 5: Substation Load Measurements Aggregated for Each Phase
functions,
TRIAL OUTCOMES
LESSONS LEARNT
graphical
The deployment of the DM&C devices
The unique layout of substations in
information
has provided the distributor with the
most cases required new installation
of electrical
ability to obtain real-time measurement
designs for each substation type. The
networks,
data regarding utilisation, power
development of modular solutions
quality and phase imbalances from any
that could be adjusted to the different
detailed
substation fitted with the equipment.
designs was crucial to the success of the
device status,
project.
Remote readings provide an
and network
understanding of how long the
The complex and sensitive nature of
status.
substation had to maintain supply at
DM&C equipment requires a stringent
or near the maximum, giving far better
insight into the asset’s life expectancy.
Remote readings down to each phase
of each distributor makes it possible to
accurately estimate temperatures that
the equipment would have experienced,
which could be fed into the maintenance
schedules to help predict when the
asset should be upgraded, maintained
or replaced. This enables a much more
proactive regime, ultimately enabling
improvements in network reliability.
A key outcome of the DM&C program
was the development of a fit-forpurpose web-based visualisation
tool giving access to the DM&C
measurement data.
Figure 5 shows substation load
measurements aggregated for each
phase, with each phase represented by a
different colour. Phases are sized based
on their proportionate load, with larger
circles representing imbalanced phases.
A cluster of substations with phase
imbalances increase line losses and
asset wear-and-tear.
Page 5 of 6
quality assurance testing process to
ensure that the equipment works as
expected prior to it being installed in
the field. Appropriately skilled staff
need to provide ongoing testing of
the equipment. As part of the DM&C
program, a smart grid testing facility was
built for this specific purpose, where all
devices were tested prior to installation.
The need for two separate teams in
some cases to install the equipment
resulted in two site visits to complete
the installation. Ensuring that the
entire installation work is done in one
site visit would reduce cost and make
the deployment more efficient. The
incorporation of DM&C equipment into
new substations as part of the factory
assembly process would significantly
reduce costs.
SMART GRID, SMART CITY TECHNICAL CASE STUDIES
REFERENCES
Ausgrid, Substation
and Feeder
Monitoring,
Technical
Compendium, 2014
J Haumann,
GA1184 Distribution
Monitoring &
Control Trial Report,
SGSC Supporting
Document, 2014
Net Benefit (NPV 2014 AU$ Real '000)
DISTRIBUTION MONITORING AND CONTROL (DM&C)
$400
$15
$356
$350
$18
$160
$300
$250
$194
$200
$150
$100
$50
$0
$0.4
Search
Costs
VCR
Figure 6: Cost Benefit Analysis
Load
Surveys
Benefits
PQ Surveys
DM&C
Opex
Costs
DM&C
Capex
Net
Benefit
BUSINESS CASE
NEXT STEPS
Figure 6 shows the indicative costbenefit analysis of deploying DM&C per
feeder in Australia. It suggests a benefitto-cost ratio of approximately 2:1.
The Consortium undertaking the
independent analysis and reporting for
Smart Grid, Smart City assessed the
findings from the trial and has identified
the following key next steps and actions
for Australia:
The main benefit on a system level
is related to the Value of Customer
Reliability (VCR). This benefit is realised
from the monitoring devices enabling
faster location of faults, which results
in quicker restoration times. Benefits
related to eliminating the need for
manual data collection are limited.
The main cost element is the capital
cost for devices and installations, with
a small portion related to operating
costs associated with communications
infrastructure and fault management.
Figure 6 shows that without the benefit
from VCR, the investment would not
be cost-effective. An important step to
verify the VCR benefit is to confirm that
the current VCR accurately reflects the
value that customers place on reliability.
The work by the Australian Energy
Regulator to develop a methodology to
determine the national VCR is a key step
in this process.
Many DM&C benefits can also
be provided by alternative smart
grid technologies including Fault
Detection, Isolation and Restoration.
The technology deployed first can
undermine the business case for the
other.
Page 6 of 6
$0.3
• Further investigation into current network
reliability incentives need to be considered
to unlock full customer benefits
• As the retrofit cost of existing assets is
significant, monitoring capabilities should
be integrated into assets at vendor-level to
reduce implementation costs.
• Develop data management and
visualisation tools at an early stage to
optimise benefits.
• Consider the trade-offs and overlap when
evaluating FDIR and DM&C business cases.