Distribution Network
Automation & Control
Seminar
Jan 29/30, 2008
Tehran/Iran
Seminar
Substation Substation Substation
Outstation Outstation Outstation Outstation Outstation Outstation Outstation Outstation Control Center
Strategies for distribution automation
Control in substations and outstations
Communication
Process optimization in the Control
Seminar Contents (I)
Section 6: Distribution automation standards
Section 5: Selection criteria for hardware, software and communications
Section 4: Which parameters should be measured or controlled ? Section 3: Selection of substations to work under automation –
automation layout
Section 2: Impacts on planning of distribution automation Section 1: Goal, task and aspects of distribution automation
Seminar Contents (II)
Section 7: SCADA functionalities
Section 8: DMS functionalities
Section 9: Case study presentation
Section 11: Maintenance and support procedures
Section 10: Distribution system automation personnel skills
Seminar Contents (I)
Section 6: Distribution automation standards
Section 5: Selection criteria for hardware, software and communications
Section 4: Which parameters should be measured or controlled ? Section 3: Selection of substations to work under automation –
automation layout
Section 2: Impacts on planning of distribution automation
Section 1: Goal, task and aspects of distribution automation
Mission of the Electricity Supply System
The primary aim of an electricity supply system is to meet the
customer’s demands for energy (in sufficient quantity and quality, at the required time and at an acceptable price)
Similarity to other goods consumption processes, the Electricity Business comprises 4 basics components
Demand
Production (Generation)
(Sub-)Transmission
Requirements to the Distribution System
Supplier’s View
high efficiency with low losses
few assets
easy service
less maintenance
fast fault detection
Customer’s View
high availability
no faults
high power quality
low price
Customer Requirements and Supply Standards
Availability no interrupts i.e. continuity of supply
Power Quality
Voltage
Frequency
Harmonics
Transients
Definitions of supply reliability are quite different
therefore statistic values can not be compared exactly
most countries count outages longer than 3 minutes, some define a 1 minute limit (Great Britain, Portugal)
Continuity indicators are calculated in a different way
Weighted by the number of customer
Weighted by the power affected (Spain, Portugal)
Power Quality Standards
Voltage in EuropeAccording IEC 61000
Voltage in the USA : the American National Standard Institute (ANSI) defines "Voltage Range " as:
120/240V ±5% at the user's service entrance, and
120/240V ±8,33% at the point of utilisation.
Frequency
The vast majority of equipment appliances are not much sensitive to variation of frequency. Furthermore, in interconnected networks (e.g. UCPTE,..) the
frequency (50 Hz or 60 Hz) is generally very stable and secondly source of problems.
Quality
Power Interrupt Statistic in Europe
Length of power interrupts in minutes per year (1999) in some countries
15 25 57 63 152 180 191 157 364 0 50 100 150 200 250 300 350 400
GER NLD FRA GBR SWE NOR ITA SPA POR
Country T im e [m in ]
Customer-weighted indicators Power-weighted
Domestic $ 0.15 / kW + $ 0.30 / kWh Agricultur e $ 0.75 / kW + $ 2.50 / kW h Large Ind ustry $ 2.70 / kW + $ 3.00 / kWh Small Indu stry $ 1.35 / kW + $ 5 .25 / k Wh Trad e & Serv ices $ 1.9 5 / k W + $ 9 .60 / kW h Customer’s Cost for an Unexpected Outage [ $ per Interrupted kW ] Outage’s Duration
Swedish nationwide survey for unexpected outages, 1993
Social Cost for Unplanned Outage
1 2 3 4 5 6 7
Transmission 33 - 420 kV 27% Distribution 1-22 kV 73% Distribution 1-22 kV Transmission 33 - 420 kV
Energy not Supplied due to Fault Outages
Why to Improve the Distribution System
The transmission and the sub-transmission system have already high reliability
Therefore:
Distribution Automation has the best ratio Improvement to Invest
Strategies to optimize the distribution system
n-1 strategies are very expensive
structure of the system can not be changed easily
But even with rather cheap measures one can reduce the outage times dramatically
Maintenance Erection Commissioning Assembly Design Equipment 5% 10% 25% 10% 40% 10% 10kV Overhead Line Diminishing Returns ∆C1 = ∆C2 ∆Rel1 >> ∆Rel2 ∆C1 ∆Rel1 ∆C2 ∆Rel2 0 0.2 1.0 0.4 0.6 0.8 Investment [C] Re lia bility [ R e l]
Reliability vs Investment Cost
Costs
Supply Quality vs. Cost:
A Macro Economic Consideration
Cost for Interrupts
(Less Sold, Penalties)
Cost
for Invest and Maintenance
Macro Economic Costs
Limits
What is ‘Distribution Automation’
There is no fixed definition of the term.Definition from EPRI 2004: The objective of (Advanced) Distribution Automation Function is to enhance
the reliability of power system service,
power quality, and
power system efficiency,
by automating the following three processes of distribution operation control:
data preparation in near-real-time;
optimal decision-making; and
the control of distribution operations in coordination with transmission and generation systems (Note: Distributed Energy Resources !) operations
Others (e.g. CIRED AD HOC Working Group 2 ) add topics such as ‚establish closer and more responsive relationship with customers‘.
“ Improved automated workflow of the Operation and Planning Department ”
( North York Hydro )
“ Improved supply quality and minimising of not sold kWh “ (CIRED 1987)
“ Improved efficiency and quality of service, more rational use of energy “ (ENEL)
Customer Interface, Management
& Control
Loads and Meters Readings Control Customer Trouble Information Billing & Settlement
Distribution Automation
Main Function Sets
Network Operation Operational Planning, Optimization Data Management Operation Statistics and Reporting Fault Management Power Import Scheduling and Optimization Network Operation Monitoring Network Operation Simulation Technical Data Management Network Control Switching Actions Scheduling Dynamic Data Management
Source: CIRED Ad Hoc Working Group 2
Geographical Displays Management Information System Maintenance Management Operation Feedback Analysis Maintenance Works Scheduling and Control
Benefits in Network Operation (I)
Improving the quality of service
Data acquisition, monitoring and remote control also at remote sites allows responding to alert and emergency conditions quickly and confidently and with the correct action, e.g.
low voltage
unbalanced flows
low power factor
overload
Less and shorter outages lead to increased revenue
Better network supervision means less equipment failure
Equipment lifetime is lengthened
Increased safety and security
Operation of any electrically controllable device can be securely inhibited at the SCADA master station
Remote outstations can be monitored for intrusion
Reduction of staff in remote outstations
Power Quality Calculations (Power Auditing)
the open market imposes penalties for quality of service not compliant with minimum characteristics.
Energy and Power Balances
some utilities have high amount of energy losses. The first step for
correcting this problem is to determine where losses larger than normal are located, this includes both technical and non-technical losses
Improve Quality of Service
SPM: Operator always has a clear picture about the current status and further planned steps of each switching sequence – faster switching at lower risk
Floc / FISR: Shorten interruption time by automatically identifying candidate switching actions for
isolation of faults
restoration of supply
switching back to normal
DSPF: Detection of Limit Violations that would occur after planned
switching actions – avoiding overloads and accidental customer supply interruptions
Improve Efficiency of Network Operation
VVC/OFR: Keep the system at the minimum of technical losses thus reducing cost
Fichtner Consulting estimates reduction of losses gained from
Fichtner Consulting estimates reduction of losses gained from
Benefits in Network Operation (III)
Customer Interface, Management
& Control
Loads and Meters Readings Control Customer Trouble Information Billing & Settlement
Distribution Automation
Main Function Sets
Network Operation Operational Planning, Optimization Data Management Operation Statistics and Reporting Fault Management Power Import Scheduling and Optimization Network Operation Monitoring Network Operation Simulation Technical Data Management Network Control Switching Actions Scheduling Dynamic Data Management
Source: CIRED Ad Hoc Working Group 2
Geographical Displays Management Information System Maintenance Management Operation Feedback Analysis Maintenance Works Scheduling and Control
Benefits from Automatic Meter Reading (AMR) Systems
Loss identification Æ Loss reduction Æ Revenue enhancement Operational Efficiency and Asset Utilization
Monitor energy balance & peak demand reduction
Faster response time to customers
Earn from innovative services to consumers e.g.
Load profile via web access
Security services e.g. door control
By using the AMR infrastructure
Customer Interface, Management
& Control
Loads and Meters Readings Control Customer Trouble Information Billing & Settlement
Distribution Automation
Main Function Sets
Network Operation Operational Planning, Optimization Data Management Operation Statistics and Reporting Fault Management Power Import Scheduling and Optimization Network Operation Monitoring Network Operation Simulation Technical Data Management Network Control Switching Actions Scheduling Dynamic Data Management
Source: CIRED Ad Hoc Working Group 2
Geographical Displays Management Information System Maintenance Management Operation Feedback Analysis Maintenance Works Scheduling and Control
Benefits from Real Time Energy Management System
(RTEMS)
Integration of meter-to-bill processes and systems
¾Improve cash flow, and system reliability
Consolidation of customer data and meter data repositories
¾Improve trust and reduce cost
Allowing web-based display and usage of energy demand and consumption information at the consumer‘s site
¾Reduce cost, improve customer retention / satisfaction and quality
Enabling real time monitoring of power quality information and automated response to energy distribution events
Customer Interface, Management
& Control
Loads and Meters Readings Control Customer Trouble Information Billing & Settlement
Distribution Automation
Main Function Sets
Network Operation Operational Planning, Optimization Data Management Operation Statistics and Reporting Fault Management Power Import Scheduling and Optimization Network Operation Monitoring Network Operation Simulation Technical Data Management Network Control Switching Actions Scheduling Dynamic Data Management
Source: CIRED Ad Hoc Working Group 2
Geographical Displays Management Information System Maintenance Management Operation Feedback Analysis Maintenance Works Scheduling and Control
Obtain more information from the network for a safer, more reliable and more efficient operation
extremely useful for cost efficient network planning because information on real equipment loading avoids over-sizing e.g. for installed transformer capacity
planning of just-in-time maintenance based on actual equipment stress
generation of logs and reports for after-the-fact system analysis and
management information; everybody can create the reports he/she needs (no software or database knowledge required, only brief handling training)
Precise, on-time, and comprehensive information increases management awareness of actual situation and increases efficiency of department co-operation
Calculation of Quality of Service Indices for individual distribution
A distribution utility has reported a 100,000 US$/per year saving
because new distribution substations could be better planned - at the right time at the right place.
Minimization of non-in-time delivered energy
reduce by 20% the current values (conservative figure)
Network losses minimization
reduce by 5% the current values (conservative figure)
Improved Operation efficiency
10% of the Operation’s budget
Improved Image
equivalent or better market penetration with reduced marketing costs
Improved working conditions and environment
stable personnel, less recruitment costs (and related training)
Distribution Automation
Seminar Contents (I)
Section 6: Distribution automation standards
Section 5: Selection criteria for hardware, software and communications
Section 4: Which parameters should be measured or controlled ? Section 3: Selection of substations to work under automation –
automation layout
Section 2: Impacts on planning of distribution automation
Section 1: Goal, task and aspects of distribution automation
Impacts on planning of distribution automation (I)
The general benefits from distribution automation have been clarified in
Section 1. This has answered the WHY of distribution automation.
The utility‘s priority of goals defines WHAT shall be done i.e. what is
more important to achieve:
increasing supply reliability
increasing power quality
decreasing cost
decreasing loss of revenue
etc
This priority list will guide the selection of the most suitable program
for distribution automation i.e. what will be done first.
Impacts on planning of distribution automation (II)
After the utility has answered the strategic WHAT question the next
question is HOW the distribution automation solution shall be
implemented i.e. what are technical / environmental / legal / …
constraints. This concerns issues such as:
overhead vs. underground networks
availability of communication technology
available (inter-)national standards
already existing automation / communication infrastructure
accessibility of substations
current and future importance of substations
Impacts on planning of distribution automation (III)
Normally there will be several proposals for achieving the ‘WHAT
goals’ considering the ‘HOW constraints’.
Besides the achievement of the strategic WHAT criteria there are
general criteria for selecting the most suitable distribution automation
proposal:
flexibility of the distribution automation solution in case of changing
strategic goals of the utility
flexibility for adding more services/business in the future
expandability of the distribution automation solution in case of
growing system size e.g. due to mergers with other utilities
reliability of the distribution automation solution itself
investment cost & cost for operation and maintenance of the
Components of a distribution automation solution (I)
A properly selected distribution automation solution will comprise
answers to the following questions:
Which substations should be automated to what extent ?
¾
Remote metering/monitoring
¾
Remote switch control
Which data shall be collected from which substation ?
Which control centers shall be built/used (centralized/distributed) ?
Which redundancy concepts shall be implemented ?
Which communication media shall be built/used for which type of
link?
Which communication configuration shall be built (point-to-point,
Components of a distribution automation solution (II)
Which software packages are required ?
Which interfaces are required ?
¾
to external control centers
¾
to external applications, such as GIS, CRM, etc
Which metering, accounting, settlement and billing process shall be
applied ?
Components of a distribution automation solution (III)
What is the capital expenditure for such a system ?
Which achievements are expected with regard to the strategic WHAT
goals ?
¾
reduction of outage frequency
¾
reduction of outage duration
¾
cost reduction
¾
etc
How can such a system be implemented and maintained ?
How can databases be populated and maintained ?
How can the implementation be split in several phases for early
benefit achieving ?
Which training is needed at what time for operational staff and
Anticipated Problems with Distribution Automation
#1: Centralized Control System
Apprehension: „Due to the automation of distribution networks the
number of data points and RTU lines to be processed increases
dramatically and thus exceeds the processing capabilities of
centralized systems“
large amount of data is not any more limiting the processing
capabilities of modern SCADA/DMS
modern process interfaces can handle hundreds of RTU lines,
furthermore there are possibilities for
¾
running several RTU servers in parallel
¾
‚lean‘ RTU interfacing by means of TCP/IP based
protocols
¾
use of modem pools
¾
cascading of RTUs, i.e. small field RTUs talk ‚through‘
Anticipated Problems with Distribution Automation
#2: Communication
Apprehension: „The automation of distribution networks fails due to
insufficient communication lines.”
cascading of RTUs reduces the number of communication lines
needed
alternative communication media are available
power line carrier over distribution lines
mobile phone networks such as GSM, GPRS
Anticipated Problems with Distribution Automation
#3: Cost
Apprehension: „The automation of the entire distribution network is too
expensive.”
in the course of energy market liberalization the pressure for cost
reduction from regulation authorities on distribution companies will
constantly grow and justify ever more investment in distribution
automation
cost for energy automation equipment and communication
equipment is decreasing particularly for compact RTUs and dial-up
connections via mobile telephone systems
distribution automation does not come as ‚big bang‘; it rather grows
over time closely coordinated with investment / maintenance
programs for substations
Seminar Contents (I)
Section 6: Distribution automation standards
Section 5: Selection criteria for hardware, software and communications
Section 4: Which parameters should be measured or controlled ?
Section 3: Selection of substations to work under automation – automation layout
Section 2: Impacts on planning of distribution automation Section 1: Goal, task and aspects of distribution automation
The Last Meters: Low Voltage
115 V /125 V Systems
Mainly used in USA, Canada, Brasilia, Mexico, Saudi Arabia, Korea,
Philippines
typical 60 Hz and
requires transformer nearby the consumer
main distribution to the end consumer is done by the MV grid
230 V / 400 V Systems
Mainly used in Europe
typical 50 Hz
Ohmic power losses enable distance up to 2 km to the next MV / LV
transformer
Structure of the Power System in USA
115 V
Transmission National / International Subtransmission Regional Low Voltage Distribution SystemStructure of the Power System in Europe
230 / 400 V
Transmission National / International Subtransmission Regional Low Voltage Distribution SystemTypical sub-transmission/distribution configuration
220KV
220KV/33KV Rec. Stn
33KV
33KV/11KV Rec. Stn.
Compact Distribution Station – Ring Main Units
11KV
X X X
X X
X X X X
Urban underground MV networks
110/20kV 20/0,4kV 20/0,4kV A B C D S c d Circuit breaker Load-breaking switch Fuse S Isolation pointAt a suitable point on the network the loop is opened by a sectionalising device S. This may be a circuit breaker, switch, fuse or link. The system then effectively
Overhead rural MV networks
The figure shows schematically typical arrangements for a rural overhead radial feeder, with some of the manually operated disconnectors omitted for simplicity. It will be noted that each main trunk feeder has a number of lateral spurs.
Substations of type 1 establish permanent
communication between the control centre and the
distribution substation e.g. by means of optical fibres. Often the fibres of a
secondary communication network are interconnected with a node (receiving
station) of the primary fibre optic ring. Applications such as RTU and AMR use
TCP/IP. IEC 60870-5-104 is recommended for RTU
communication. Of course, other communication media / Battery 24/48V DC Battery charger RTU (IEC…104) Meter
Control & Monitor switch states, Short circuit indicators
CT, VT
motorized 11kV Switchgear Fibre panel 1 (2) *24
8 port Ethernet HUB
FO from R/S, S/S FO to next S/S
Fibre optic to UTP Media Converters
Substation type #1 with permanent data access
Battery 24/48V DC Battery charger RTU (IEC…101) Dial up Modem (WLL/Fixed wired) Energy Meter
Control & Monitor switch states, Short circuit indicators
CT, VT
motorized 11kV Switchgear
24/48 V DC
Substations of type 2 use switched telephone
communication facilities (fixed wired or mobile
communication) to transfer data on demand. The
demand for data exchange can be initiated by the
control centre or the
distribution substation itself. The control centre needs to control switchgears
remotely, to ask for data update or just to test the connection. The substation need to call in the control centre if there is some
urgent data to transfer, for example a fault indication
Substation type #2 with temporary data access
Steps of Distribution Automation
Step 0: Centralization of distribution system operation
centralized distribution system operation is less costly
centralized distribution system operation reduces time to restore
supply after disturbances
existing mixed structures of local and centralized operation often
have grown over time but do not have justification as of today
mixed structures in case of disturbances, i.e. local operation only
Steps of Distribution Automation
Step 1a: Automation of feeder heads in HV/MV substations
in case of a new HV/MV substation the whole scope of automation shall be built in:
remote signaling of all switching element statuses
remote control of circuit breakers
digital protection devices provide analog measurements in normal operation and fault operation
in case of retrofitting HV/MV substations the following priority applies
must: fault information from protection equipment per field
optional: remote control of circuit breakers
analog measurements of feeder currents
nice-to-have: more switching status information (isolator, earthing switch, ...)
Steps of Distribution Automation
Step 1b: Automation of major switching substations
Major switching substation:
three (3) outgoing feeders or more
circuit breaker and protection
In case of a new switching substation the whole scope of
automation shall be built in (see Step 1a)
In case of retrofitting switching substations the same priorities apply
as in Step 1a.
Steps of Distribution Automation
Step 1c: Remote signaling of selected fault current sensors
With this step the utility has reached the level of
automated centralized fault location:
evaluation of topology information
evaluation of fault impedances
evaluation of fault current sensor information
Steps of Distribution Automation
Step 2a: Automation of selected MV/LV substations
Selected MV/LV substations:
‘normally open’ section point
midway of long feeders
Remote control of load switches
Steps of Distribution Automation
Step 2b: Automation of selected customer substations
Selected customer substations:
high-volume consumer
high-sensitive consumer
remote signaling of fault information
remote switching
remote signaling of analog measurements
This enables new business opportunities for providing high-quality
power supply services to those customers.
Selection of distribution substations for automation
For the selection of distribution substations for automation two main
questions have to be answered:
(A) What is the most reasonable and beneficial
rate of automation for distribution substations?
(B) Which dedicated distribution substations shall be automated ?
The goal of distribution substation automation is basically to reduce the
average interruption time of energy supply in the distribution network.
In case of a feeder trip the SCADA/DMS operators get fault indication
from automated distribution substations.
Within a short time a part of the affected consumers can be re-supplied
by reconfiguring the distribution network by remote control actions from
the SCADA/DMS. DMS applications will support the operator in
Selection of distribution substations for automation
Question (A): Automation Rate (I)
A fault on a cable section causes the feeder to trip. Two
distribution substations will send fault
indications and fault-direction to the control centre. Based on this information the operator can re-supply ~ 50% of the affected consumers by performing switching actions 2 - 5. This can be done within a time period of 3 minutes.
Normally open point
1. trip 2. open 4. open 5. close 650 feeders 4099 distribution substations D6,5 substations / feeder 2,2 million consumers D537 consumers / substation R/S feeder R/S feeder Fault indicator Automated substation 3. close
About 50% of the affected customers re-supplied after 3 minutes.
Automation rate assumed to be 25%.
Selection of distribution substations for automation
Question (A): Automation Rate (II)
Compared to non-automation, the
restoration crew can work faster since the area of intervention is only a part of the feeder. Fault
isolation and service restoration are done by conventional methods. The crew on site can be supported by the
operators in the control centre. Average
conventional restoration time is estimated to be reduced by 50 % (40 minutes Î 20 minutes).
Remaining 50% of the affected customers re-supplied after 20 minutes.
R/S feeder R/S feeder
Fault indicator Automated substation
Selection of distribution substations for automation
Question (A): Automation Rate (III)
As result of this scenario the service restoration time will be reduced from approximately 40 minutes to approximately 11 Minutes.
50 % of consumers are re-supplied after 3 minutes 50 % of consumers are re-supplied after 20 minutes
=> average interruption time ~11 minutes
This kind of estimation of outage time reduction can be repeated for other values of the automation rate.
The diagram on the next page indicates the average interruption time as function of the number of automated substations (magenta) taken from a study case. Relevant study case data are given on the following page.
The blue curve is representing the Net Present Value (cost/benefit ratio). The costs are based on the substation adaptation investments, the benefits are calculated from more energy sold due to reduced average interruption time.
Detailed Case Study on
Cost-Benefit-Analysis of Distribution Automation with
different Automation Rates in Section 9.
Selection of distribution substations for automation
Question (A): Automation Rate (IV)
Selection of distribution substations for automation (VI)
Question (B): Selection of Substations
The selection of dedicated substations for automation does not follow a strict and simple algorithm. It is rather guided by fuzzy criteria on two levels:
Feeder level
Such feeders will be preferred that have
¾ higher load density
¾ higher fault density than others
Substation level
Obviously the substation with ‚normal open points‘ will be automated first on a selected feeder.
As regards other substations, the leading criterion is the load that can be affected i.e. those substations will be preferred that have
¾large industrial consumers connected
¾spur lines with high load connected
Finally, the time needed for manual switching plays a role i.e. those substations will be preferred that have
Seminar Contents (I)
Section 6: Distribution automation standards
Section 5: Selection criteria for hardware, software and communications
Section 4: Which parameters should be measured or controlled ?
Section 3: Selection of substations to work under automation – automation layout
Section 2: Impacts on planning of distribution automation Section 1: Goal, task and aspects of distribution automation
Data to be collected from HV/MV Substations
Active Power, Reactive Power, Voltages, Currents from all
¾
incoming feeders
¾
outgoing feeders
¾
capacitor banks
¾
etc
Switch Positions of the
¾
Isolators (Single Pole)
¾
Circuit Breakers (Double Pole)
Indications of other auxiliary devices such as UPS, Battery
system, Chargers, Communication Devices etc.
Status from the protection devices
Data to be collected from Distribution S/S
Alarm Charger failure
Alarm Power supply failure
Battery System
Alarm Fault current sensors
Alarm Phase-to-ground short circuit
Alarm Phase-to-phase short circuit
Protection (each feeder)
Measured Value I / P / Q / V Analogs (Command) Status Load switches Command Status Circuit breakers Switches
Output from SCADA Input to SCADA
Step 2:
Line/cable segment engineering data Typical load curves for
load transformers 220 kV bus 33 kV bus 33 kV bus 11 kV bus M M M M
Data to be collected for distribution automation
Step 0: SCADA data model Step 0: SCADA data model Receiving Substation Bulk supply Substation
1. Extend by SCADA data model of distribution feeders (topology, switches) Î enabling Operation Applications (Section 8)
2. Extend by engineering data of line/cable segments and load models Î enabling Distribution Network Applications (Section 8)
Step 1: Extended SCADA Data Model M M M M Step 3: Measurements from distribution automation
I> (t)
t dt
pick-up time dt
selectable: 40 oder 80 ms
enveloping of failure current
IS1 selected pick-up current
criterion Is1 and dt fullfilled -> indication is activated
Integrative measurement avoids erroneous indication!
Red signal curves must not activate the indicator
Short-circuits and earth-faults indicators
For effective failure detection and
location short-circuits and earth-faults must be observed. Combined short-circuit and earth-fault indicators are most economical. Indicators can be installed on outgoing feeders of RMUs. The fault detection facility generates alarms in case of high current peaks. However, the facility shall prevent faulty indications due to magnetizing-inrush currents, other transient and no-fault conditions.
Knotenpunktstation nodal point substation
I>> Ie RMU RMU I>> Ie RMU RMU RMU RMU RMU Umspannwerk Power substation I>> Ie I>> Ie I>> Ie I>> Ie I>> Ie I>> Ie I>>Ie
Fault detection in low resistance terminated
networks by means of short-circuit indicators
Typical Repairing of Permanent Faults
Protection has tripped circuit breaker CB
Transient fault? Automatic recovery?
Localize fault
¾
phone calls, relay data, Remote Terminal Units (RTU),
visually
Open isolator and ground equipment
Restore supply as much as possible
Do nessesary repair work
Fault removed, line repaired
Remove grounding and close isolator or replace fuse
Urban vs. Rural Regions
Urban
underground cables with less external faults
Rural
a lot of overhead lines
intermediate short circuits
birds
trees
wind
Distribution Automation
in Urban Areas
Example for
OC OC
FI
Typical open ring configuration
OC: over current protection FI: fault indicator
-Q0 1 -A5 1 3 -T1 -T5 -Q0 1 -A5 1 3 -T1 -T5 -Q0 1 -A5 1 -F1 Ring Unit 1 Ring Unit 2 Feeder to LV trans-M M M Double indications:
Ring unit 1 isolator On/OFF Earth switch 1 On/OFF Ring unit 2 isolator On/OFF Earth switch 2 On/OFF
Feeder On/OFF
Earth switch Feeder On/OFF
Single indications:
Short circuit indicator RK1 Short circuit indicator RK2 Fuse blown
Grouped Indication Auxiliary power failure Transformer temperature alarm
Remote control off UPS failure
Station open
Meters (optional):
Meter feeder
Double commands:
Ring unit 1 isolator On/OFF Ring unit 2 isolator On/OFF Feeder On/OFF
Analogs (optional):
Ring unit 1 Current Phase L2 Ring unit 1 Voltage L2-N Ring unit 2 Current Phase L2 Ring unit 2 Voltage L2-N
Typical mini RTU solutions
Ring main unit with one feeder
Automation in a MV Ring (1)
Example of network configuration. The network is divided into four sections. In the example is there a fault between SB21 and SB22.
A central control unit is placed with the circuit breakers (E1,E2). The circuit breakers could be taken in and out from the central control unit.
Decentral control units are placed with the line switches in each section (SB11,SB-R,SB21 and SB22) .These units get information from a voltage
sensing system and control each line switch. In a ring configuration it is a must to have a voltage sensing system on both sides of the line switch.
20 0 40 60 [sec] E1 E2 SB11 SB21 SB22 SB-R
Automation in a MV Ring (2)
With a fault in the network configuration, the protection relay will take the circuit breaker (E2) out. The central control unit will try to put the circuit breaker in, but in a faulty network configuration the protection relay will take out the circuit
breaker again. 20 0 40 60 [sec] E1 E2 SB11 SB21 SB22 SB-R
Automation in a MV Ring (3)
This procedure indicates to all units (SB21,SB22 and SB-R) that the network configuration is faulty, and the automatic sectioning starts.
All decentral control units (SB21 and SB22) take out the line switches .
20 0 40 60 [sec] E1 E2 SB11 SB21 SB22 SB-R
Automation in a MV Ring (4)
The central control unit closes the circuit breaker after 20 seconds, to test the first part of the network configuration .
20 0 40 60 [sec] E1 E2 SB11 SB21 SB22 SB-R
Automation in a MV Ring (5)
After 40 seconds the decentral control unit (SB21) closes the line switch.
20 0 40 60 [sec] E1 E2 SB11 SB21 SB22 SB-R
Automation in a MV Ring (6)
Because this part of the configuration (SB21 – SB22) is faulty, the central unit will take out the circuit breaker. The decentral control unit (SB21) discovers that the voltage only was in for a short time, and then takes out the line switch and locks it. 20 0 40 60 [sec] E1 E2 SB11 SB21 SB22 SB-R
Automation in a MV Ring (7)
The decentral control unit (SB22) discovers that the voltage was in only for a short time, and because of the voltage sensing system of both sides of the switch, the unit knows that the fault is between SB21 and SB22. The decentral control unit (SB22) will then lock the line switch.
20 0 40 60 [sec] E1 E2 SB11 SB21 SB22 SB-R
Automation in a MV Ring (8)
The decentral control unit (SB-R) have detect the start of the automatic sectioning.
The decentral control unit (SB-R) has not detected any voltage on the side SB-R – SB22. After a time (60 seconds) the unit knows that the fault is between SB21 and SB 22, and the line switch (SB-R) is closed.
Now at this time the part between SB21 and SB22 (the faulty) is disconnected
20 0 40 60 [sec] E1 E2 SB11 SB21 SB22 SB-R
Distribution Automation
in Rural Areas
Sectionalizing in Overhead Lines
Sectionalizer enable a system for automatic sectioning in a
network configuration. Automatic sectioning is based on
switching on and out line switches and circuit breaker in a
controlled sequence to find errors in the network. When the
errors are found, the system will take out the faulty part of the
configuration.
Sectionalizing in Overhead Lines
Example of network configuration.
The network is divided into six sections (S1 – S6)
Circuit breaker Load-breaking
switch Power Transformer Voltage sensing system E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (1)
With at fault in the network configuration, the protection relay will take out the circuit breaker. 20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (2)
The central control unit (E1) will try to put the circuit breaker in but in a faulty network configuration. 20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (3)
The protection relay will take out the circuit breaker again.
20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (4)
This procedure indicates to all units (E1 and L1 .. L5) that the network configuration is faulty, and the automatic sectioning starts.
The automatic sectioning starts at relative time 0 seconds.
All decentral control units (L1 .. L5) take out the line switches
.
20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (5)
The central control unit closes the circuit breaker after 20 seconds, to test the first part of the network configuration (S1).
20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (6)
After 40 seconds the decentral control unit (L1) closes the line switch.
20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (7)
Because this part of the configuration (S2) is faulty, the central unit (E1) will take out the circuit breaker.
20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (8)
The decentral control unit (L1) discovers that the voltage only was in for a short time, and then takes out the line switch and locks it. At this time the section S2 (the faulty) is disconnected from the healthy part of the network configuration.
20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (9)
After 60 seconds the central unit (E1) closes the circuit breaker.
20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (10)
The decentral control unit (L2) closes the line switch in due to the voltage sensing system. 20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (11)
After 80 seconds the decentral unit (L3) close the line switch in due to the voltage sensing system.
20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (12)
After 100 seconds the decentral unit (L4) close the line switch in due to the voltage sensing system.
20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (13)
Because this part of the configuration (S4) is faulty, the central unit (E1) will take out the circuit breaker.
20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (14)
The decentral control unit (L4) discovers that the voltage only was in for a short time, and then takes out the line switch and locks it. At this time the section S4 (the faulty) is disconnected from the healthy part of the network configuration.
20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (15)
After 120 seconds the central unit closes the circuit breaker and the automatic sectioning is finished. The decentral control unit (L5) could be designed to close the line switch after 120 seconds.
20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer (16)
The central control unit sets outputs (lamps) for each section (S1 – S6) which is faulty.
It is also possible to send this information to a network control system via IEC 6870-5-101 protocol, or/and send SMS messages.
See next page 20 40 0 60 80 100 120 140 [sec] E1 L1 L2 L4 L5 S2: 250 kW S3: 375 kW S5: 250 kW S6: 150 kW S1: 500 kW L3 S4: 250 kW e. g. 110/ 20kV
Sectionalizer: Switch and Control
Line Switch with voltage transformer
Electronic with storage battery, local control and
Seminar Contents (I)
Section 6: Distribution automation standards
Section 5: Selection criteria for hardware, software and communications
Section 4: Which parameters should be measured or controlled ?
Section 3: Selection of substations to work under automation – automation layout
Section 2: Impacts on planning of distribution automation Section 1: Goal, task and aspects of distribution automation
Business Services IT Integration ASP Administration Operation E-Commerce Maintenance Field data acquisition,
local control & automation Communication Network control & supervision
(single-or multi-utility)
Added value network management &
optimization
(applications and systems)
Integrated utility business operation xxxx x xxx xxx xx Meters Substation automation Protection Local automation RTUs Power Exchange
$
$
Trader Partner, market, etc. Multi-site SCADA etc. DB Network planning Network information Meter data management...
Advanced applications (EMS, DMS, EBM, Trading)Information gateway
...
Asset Management Energy Sales & CareEnterprise Integration Bus
Data Warehouse MIS
F&A
Gateway
Power Systems Control and Energy Management
Multi-Level Environment
Optical Fiber
Radio
Copper Cable
Power Line
Public Network
GSM/CDMA –
Network
Communication Media
Backbone
Network
RTU RTU RTU RTU MV - Line RTU MV - LineControl Center
TCINo. 1
No. Z
MV - Line RTU RTU MUXOptical Fibre
Aspects of Network Design
Costs
Reliability
Performance
Regulations
Communication Selection Criteria
Leased Public Line
The telephone company provides direct point-to-point connectivity between the RTU location and the control centre. On both end of the communication, a suitable modem appropriate to bandwidth (9600 bauds, 86 Kbps) is required.
The cost of the communication of this nature comprises the fixed cost to be paid as one-time charges (for Registration fees, Installation fees of the
equipment) and the operational charges (for periodical subscription as well as usage).
Though this type of communication facility seems to be economical, on a long term it may not turn up to be cost-effective, since one has to pay the
periodical operation charges.
The other disadvantage is due to frequent failures of the lines, dependence of third party state-owned service provider.
Communication Selection Criteria
Dial-up Public Line
Few telephones / modems are provided having dial-up facility at the control centre end, whereas at the RTU / mRTU ends the modems are to be
provided with answering facility.
For a real-time operation, this kind of communication is not preferred due to the time consuming dial-up and answering process. However, for Automated Meter Reading or for checking the status of reclosers after disturbances dial-up communication can be effectively utilized.
The cost of the communication of this nature comprise of the fixed cost to be paid as one time Registration fees, Installation fees of the equipment) and the periodical subscription as well as usage charges.
Disadvantages, however, are the same as indicated above for the ’Leased line communication’.
Communication Selection Criteria
GSM Mobile Communication
With the advent of mobile telephony, usage of GSM communication is
becoming quite popular and widely used for data communication. Using GSM modems at the RTU end and the Control Centre end the data exchange can be introduced using urban mobile (GSM) networks.
While considering the GSM network as a feasible solution one has to be sure that mobile connectivity is available at all the RTU locations.
GPRS is also an acceptable solution.
Disadvantages are similar as indicated above for leased line communication. Even more, GSM networks tend to be overloaded during peak hours and
Communication Selection Criteria
Digital Networks via Fiber Optic
It is required to lay extensive FO cables connecting primary stations, sub-divisions and the control centre. Such systems, though “The Best” technical option to establish a TCP/IP network, requires considerably high cost.
In addition to establishing of an extensive FO network, the associated
terminating equipment and multiplexers are required at all the location from where the data is to be collected or to be dropped in.
Though the solution does not look to be cost effective at first sight due to high initial costs, it may turn out to be cost effective, if the utility makes use of the extra fibers of the FO cable for other communication facility requirements such as voice, Fax, other IT applications.
With the establishment of an own FO network, the utility has the responsibility for operation and maintenance of the network, but at the same time it has full control of system expansion in case of increasing number of (field-) RTUs.
Fast wireless Ethernet modems are gradually becoming popular. The Ethernet modems are available in the rated range of 5 miles to 25 miles. Making use of such Ethernet modems together with FO based
communication network as backbone, makes an ideal communication
Communication Selection Criteria
Radio Communication
The communication system using radio requires considerably high costs associated with procurement of radio systems, installation of towers and masts for antennas etc.
However, once installed and put into operation, the communication system has low, annual costs for operations and maintenance. Thus it helps the utility to establish its own communication network.
It is necessary to obtain the frequency allotment / approval from the wireless agency or the prescribed authority as nominated by the state / govt. In
general, yearly subscription fees for utilizing the frequency are required to be paid.
Before implementing the solution, a detailed Sight of Line study is required to be carried out for the feasibility of the solution in a particular town / city.
Obstruction make occur due to high rise buildings (also by not yet existing ones !).
Costs
Hardware
Commissioning / Installation
Base fees
Connection fees
Excavation work
0% 200% 400% 600% 800% 1000% 1200% 1400% 1600% 1800% Radio (no t ower) Radio BTC GSM New pilot cable Leas ed lin e (loc al) Leas ed lin e (far ) Dial mode line DCS CDC DCS CDI Transmission method
Telecontrol service (RTU) and remote load profile reading Connection fee
Base fee Assembly/commisioning Hardware cable Hardware equipment 9 km MV line with 4 kiosks Over 5 years 12 polling per day
Invest for assembly and operation
PLC
PLC overoverMedium Medium VoltageVoltage
*) This calculation depends on the regional conditions, the example based on the European / African market.
Data Transmission with Distribution Line Carrier
(DLC)
The coupling transformer encloses the earthing strap of the MV cable
Conductor 1 Conductor 2 Conductor 3
Sealing end Earthing strap CDI (ferrite ring) Earthing bar BU
Data Transmission with Distribution Line Carrier
(DLC) - Inductive coupling device
CDC Conductor 1 Conductor 2 Conductor 3
Bracket or separate supporting bar for CDC Earthing bar
Connecting element
Data Transmission with Distribution Line Carrier
(DLC) - Capacitive coupling device
Communication
Multi carrier principle
Transmission in the frequency range of
CENELEC
Uniform hardware for Master & Slave
Transmission rates up to 28.8kbit/s
(depending on the line)
Bypass of MV switchgear
Simple & complex: MV line, tree or ring
networks
Interfaces
Telecontrol per IEC 60870-5-101 or DNP 3.0
Meters per IEC 61107
Medium-voltage line and telecontrol line
Data Transmission with Distribution Line Carrier
(DLC) – Basic Unit
Pole mounted switch 1 BU Control center Distribution point MV Line V.24 IEC 60870-5-101 MV Line
MV substation automation - field trail
DLC runs with microRTU and control center by using
IEC communication standard
Test with out-door CDC coupling units
Transmission rate 9.6kBd
Pole mounted repeater
BU Master-BU V.24 IEC 60870-5-101 BU V.24 IEC 60870-5-101
Pole mounted switch 2
Data Transmission with Distribution Line Carrier
(DLC) – Sample project: MEA Bangkok/Thailand
Mounting a BU cabinet on an overhead line pole
Pole mounted cabinet including DCS3000 BU
Fully-installed cabinet, with
DCS 3000 BU and SICAM microRTU
Data Transmission with Distribution Line Carrier
(DLC) – Sample project: MEA Bangkok/Thailand
Business Services IT Integration ASP Administration Operation E-Commerce Maintenance Field data acquisition,
local control & automation Communication Network control & supervision
(single-or multi-utility)
Added value network management &
optimization
(applications and systems)
Integrated utility business operation xxxx x xxx xxx xx Meters Substation automation Protection Local automation RTUs Power Exchange
$
$
Trader Partner, market, etc. Multi-site SCADA etc. DB Network planning Network information Meter data management...
Advanced applications (EMS, DMS, EBM, Trading)Information gateway
...
Asset Management Energy Sales & CareEnterprise Integration Bus
Data Warehouse MIS
F&A
Gateway
Power Systems Control and Energy Management
Multi-Level Environment
Basic SCADA/EMS/DMS System Architecture
DW Operational Database Transmission NA Distribution DMS DSM Generation PA SA RO DW EA ELCOM ICCP DTS DW ORACLE Interfaces Front End BASE SCADA HIS SDM Base InterfacesSample SCADA/EMS/DMS Modularity
SCADA SCADA UI UI FA FA DSM DSM PA PA Base Base IS&R IS&R Multi BCK Multi BCK OA OA TS TS CFE CFE GEI GEI Elcom Elcom Data Data DNA DNA GIS GIS LTOP LTOP GSA GSA TNA TNA EMM EMM SDT SDT IndC IndC ICCP ICCPMultiBck Multisite/Backup System
Base Base System
CFE Communication Front End
Data Data Engineering
DNA Distribution Network Applications
DSM Demand Side Management
ELCOM Electricity Utilities Communication
EMM Energy Market Management
FA Forecasting Applications
GEI General External Interface
GIS Interface to GIS
GSA Generation Scheduling Applications
ICCP Inter Control Center Protocol
IndC Industrial Communication
IS&R Information Storage & Retrieval
LTOP Long-Term Operation Planning
OA Operational Applications
PA Power Applications
SCADA Supervisory Control & Data Acquisition
SDT Software Development Tools
TNA Transmission Network Applications
TS Training System and Simulation
Transmission
Distribution Generation
