DOMA Narrative

This application is based on a real-time
unbalanced distribution power flow for dynamically changing
distribution operating conditions. It analyzes the results of the
power flow simulations and provides the operator with the summary
of this analysis. It further provides other applications with
pseudo-measurements for each distribution system element from
within substations down to load centers in the secondaries. The
model is kept up-to-date by real-time updates of topology,
facilities parameters, load, and relevant components of the
transmission system.

The Distribution Operation Modeling and Analysis
supports three modes of operation:

1.     
 Real-time mode, which reflects present conditions in the power
system.

2.     
 Look-ahead mode, which reflects conditions expected in the
near future (from one hour to one week ahead)

3.     
 Study mode, which provides the capability of performing the
“what if” studies.

The key sub-functions performed by the
application are as follows:

Modeling Transmission/Sub-Transmission System Immediately Adjacent
to Distribution Circuits

This sub-function provides topology and
electrical characteristics of those substation transformers and
transmission/sub-transmission portions of the system, where loading
and voltage levels significantly depend on the operating conditions of
the particular portion of the distribution system.  The model also
includes substation transformers and transmission/sub-transmission
lines with load and voltage limits that should be respected by the
application.  

Modeling Distribution Circuit Connectivity

This sub-function provides a topological model
of distribution circuits, starting from the distribution side of the
substation transformer and ending at the equivalent load center on the
secondary of each distribution transformer. A topological consistency
check is performed every time connectivity changes. The model input
comes from SCADA/EMS, Distribution SCADA, from field crews, from DISCO
operator, from AM/FM/GIS, WMS, and OMS databases, and engineers. 

Data Management Issues between AM/FM/GIS and ADA Distribution
Connectivity Database

Standard interfaces between different AM/FM/GIS
databases, data converters, and ADA database are not developed yet for
practical use. The AM/FM/GIS databases were not designed for real-time
operational use. They lack many objects and attributes needed for ADA.
The population of the databases is not supported by an interactive
consistency check. The existing extractors of data and the converters
into ADA databases do not determine all data errors. The ADA
applications must conduct additional data consistency checking and
data corrections before recommendations and controls are issued.
Typically utility do not have established procedures for regular
update of the AM/FM/GIS databases by the operation and maintenance
personnel. Therefore many changes implemented in the field remain
unnoticed by the databases. Synchronization of the field state with
the ADA database is a challenge in modern utilities.

Data Management Issues
between CIS and AM/FM/GIS and ADA Distribution Connectivity Database

For the ADA applications, the AM/FM/GIS data
must be associated with the corresponding customer information data
from the CIS database. This data include billing data and description
of the customer specifics, such as rate schedule, customer code, meter
number, address, etc. The critical information is the billing data.
This data is updated based on metering cycles (typically one month)
and is not well synchronized. In order to synchronize billing data an
automated meter reading system should be implemented. In order to
update the ADA databases more frequently, which would increase the
resolution of ADA functions to individual distribution transformers
and even customers, a high capacity communication system should be
introduced to gather the data from hundreds of thousands of meters at
the same time. Some of the modern procedures enabled by AMR conflict
with the needs of ADA model.An example is the consolidated bills,
where the individual load data of distribution transformers located in
different sites of the consolidated company becomes unavailable for
the external to CIS world.       

Modeling Distribution Nodal Loads

This sub-function provides characteristics of
real and reactive load connected to secondary side of distribution
transformer or to primary distribution circuit in case of primary
meter customers. These characteristics are sufficient to estimate kW
and kvars at a distribution node at any given time and day and include
the load shapes and load-to-voltage sensitivities (for real and
reactive power) of various load categories. In real-time mode, the
nodal loads are balanced with real-time measurements obtained from
corresponding primary circuits. A validity check is applied to
real-time measurements.  The load model input comes from Distribution
SCADA, from CIS supported by AMR and linked with AM/FM/GIS, and
weather forecast systems.

Modeling Distribution Circuit Facilities

This sub-function models the following
distribution circuit facilities:

1.     
Overhead and underground line segments

2.     
Switching devices

3.     
 Substation and distribution transformers, including step-down
transformers

4.     
 Station and feeder capacitors and their controllers

5.     
 Feeder series reactors

6.     
 Voltage regulators (single- and three-phase) and their
controllers

7.     
 LTC’s and their controllers

8.     
 Distribution generators and synchronous motors

9.     
Load equivalents for higher frequency models

All facilities should be modeled with sufficient
details to support the required accuracy of Distribution Operation
Modeling and Analysis application.

Distribution Power Flow

The sub-function models the power flow including
the impact of automatically controlled devices (i.e., LTCs, capacitor
controllers, voltage regulators), and solves both radial and meshed
networks, including those with multiple supply busses (i.e. having
Distributed Energy Resources (DER) interconnected to the power
system).            

Evaluation of Transfer Capacity

This sub-function estimates the available
bi-directional transfer capacity for each designated tie switch. The
determined transfer capacity is such that the loading of a tie switch
does not lead to any voltage or current violations along the
interconnected feeders.

Power Quality Analysis

This sub-function performs the power quality
analysis by:

1.     
Comparing (actual) measured and calculated voltages against the limits

2.     
Determining the portion of time the voltage or imbalance are outside
the limits

3.     
Determining the amount of energy consumed during various voltage
deviations and imbalance

4.     
Recording the time when voltage violations occur

5.     
Performing modeling of higher harmonics propagation and resonant
conditions based on information available from the sources of harmonic
distortion

6.     
Performing modeling of rapid voltage changes based on information
available from the sources of voltage distortion

The sub-function provides the ability to estimate
the expected voltage quality parameters during the planned changes in
connectivity and reactive power compensation. 

Loss Analysis

This sub-function bases its analysis on technical
losses (e.g., conductor I²R losses, transformer load and
no-load losses, and dielectric losses) calculated for different
elements of the distribution system (e.g., per feeder or substation
transformer). For the defined area, these losses are accumulated for a
given time interval (month, quarter, year, etc.). They are further
compared with the difference between the energy input (based on
measurements) into the defined area and the total of relevant billed
kWh (obtained from the database), normalized to the same time
interval. The result of the comparison is an estimate of commercial
losses (e.g., metering errors and theft).

Fault Analysis

This sub-function calculates three-phase,
line-to-line-to-ground and line-to-ground fault currents for each
protection zone associated with feeder circuit breakers and field
reclosers. The minimum fault current is compared with protection
settings while the maximum fault current is compared with interrupting
ratings of breakers and reclosers. If the requirements are not met, a
message is generated for the operator.

Evaluation of Operating Conditions

This sub-function determines the difference
between the existing substation bus voltage and the substation bus
voltages limits. 

The sub-function also estimates the available
dispatchable real and reactive load obtainable via volt/var control.  
The operator or other applications can use this information for
selective load reduction. The sub-function provides aggregated
operational parameters for the transmission buses to be used in
transmission operation models.

DOMA Steps

The DOMA Steps include:

• DOMA Data Conversion
• DOMA without Events
• DOMA with Events Causing
  It to Run
• DOMA Runs Based on a Schedule
• DOMA Used in Study
  Mode or Look-Ahead Mode

DOMA Data Conversion

Introduction to Advanced Distribution Automation (ADA)

Objective: 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 operations.

Scope: The ADA Function performs a) data
gathering, along with data consistency checking and correcting; b)
integrity checking of the distribution power system model; c) periodic
and event-driven system modeling and analysis; d) current and
predictive alarming; e) contingency analysis; f) coordinated volt/var
optimization: g) fault location, isolation, and service restoration;
h) multi-level feeder reconfiguration; i) pre-arming of RAS and
coordination of emergency actions in distribution; j) pre-arming of
restoration schemes and coordination of restorative actions in
distribution, and k) logging and reporting. These processes are
performed through direct interfaces with different databases and
systems, (EMS, OMS, CIS, MOS, SCADA, AM/FM/GIS, AMS and WMS),
comprehensive near real-time simulations of operating conditions, near
real-time predictive optimization, and actual real-time control of
distribution operations.

Rationale: By meeting its objectives in
near-real time, the Function makes a significant contribution to
improving the power system operations through automation, which cannot
be achieved using existing operational methods.  

Status: The methodology and specification
of the Function for current power system conditions have been
developed, and prototype (pilot) and system-wide project in several
North-American utilities have been implemented by Utility Consulting
International and its client utilities prior to IntelliGrid Architecture project.  

Figure 1: Coordination of ADA applications is accomplished through
internal interfaces within the ADA function and through the feedback
from the power system

Figure 2: Real-Time Distribution Operations showing Interactions
and Information Flows

Figure 3: What Do We Need to Know to Optimally Control
Distribution?

Figure 4: Information Flows within Advanced Distribution Automation
(ADA)

Source:EPRI

Contents

• Narrative
• Normal Sequence Steps
• Steps – Alternative / Exception Sequences

Narrative

Transmission Automated Control (Baseline) describes a set of functions that are typically automated within a substation, but are not directly associated with protection, fault handling, or equipment maintenance.  In general, they serve to optimize the operation of the power system and ensure its safe operation by preventing manually generated faults.  These functions include:

• Changing transformer taps to regulate system voltage
• Switching capacitor banks or shunts in and out of the system to control voltage and reactive load
• Interlocking of controls to prevent unsafe operation
• Sequencing controls to ensure safe operation
• Load balancing of feeders and transmission lines to reduce system wear and resistive losses
• Restoring service quickly in the event of a fault, with or without operator confirmation

The functions described in this use case were traditionally performed by individual devices acting alone.  When implemented this way, they did not have any effect on the communications system.  However, in the last five to seven years, these functions have been distributed across the substation.  That is, the software logic controlling the function now often resides on a different device than the one which provides the inputs or outputs to the process.

This change has taken place because the use of substation LANs has made it economical to place Intelligent Electronic Devices (IEDs) close to the equipment they are monitoring and controlling.  Logic has therefore either been centralized, with a single Substation Computer using the IEDs as remote controllers, or it has been distributed among the IEDs themselves.  In either case, the communications system has now become part of the automation functions.

Voltage Regulation using Tap Changers

In voltage regulation, the automation system ensures a constant voltage on the substation bus by adjusting the tap of one or more transformers.  A monitoring IED provides a voltage value to the Substation Computer, which has been programmed with threshold and hysteresis logic. The IED is usually monitoring the bus side of a transformer.  In more complex situations, IEDs may monitor multiple voltages throughout the station and pass them all to the Substation Computer as input to the logic. When the logic indicates that the bus voltage must be adjusted, the Substation Computer issues a control operation to the IED connected to the transformer tap.  This will change the monitored voltage, which will be fed back through the logic.

The voltage control logic typically has a pre-programmed qualification delay in the tens of seconds – adjusting the tap causes wear on the equipment, so adjustments should not be made lightly.  Therefore, an appropriate update time for the monitored voltage is on the order of one-half second to one second.  Because of the wear on the transformer and tap, and the impact on the rest of the system if adjusted wildly, tap raise/lower operations are typically performed with select-before-operate logic.  Redundancy and reliability of the communications path is important.

Volt/VAR Regulation using Capacitor or Shunt Control

In capacitor bank control, the automation system optimizes the voltage and inductive load on a line or bus by connecting or disconnecting one or more capacitor banks.  It prevents the imaginary part of the load from becoming too large, reducing voltage and the efficiency of the system.  The banks may be widely located across the power system, or within the substation.  There are many different logic algorithms for performing capacitor bank control.  The simplest is calendar or time of day control, in which the load on the power system is not even monitored.  The logic simply assumes that the inductive load will be higher at certain times of the day or year.  In areas where inductive load is largely caused by air conditioning, logic may switch based on ambient temperature.  Some algorithms monitor voltage only and switch when it passes certain thresholds.  More sophisticated algorithms monitor both current and voltage and switch based on either the calculated power factor or directly on the calculated inductive load (VARs).  There are typically hysteresis settings on such logic to prevent frequent switching.  Shunt control occurs under similar conditions, but with the addition or removal of inductive loads.

In distributed Volt/VAR control, one IED controls one capacitor bank on a given line, and each IED makes switching decisions individually.  In centralized Volt/VAR control, each IED reports monitored values back to a Substation Computer.  The Substation Computer may make switching decisions based on averages or groupings of voltages.  When it decides a switch is necessary, it sends a control message to the appropriate IED, which may or may not be the device reporting the controlled measurements.

The hysteresis in some Volt/VAR algorithms may often be in hours, so communication delays in tens of seconds are easily acceptable.  It is fairly common to broadcast capacitor bank control messages, without any select-before-operate logic, since the effect of any given control is usually small.  When capacitor banks are located remotely, pagers have sometimes been used as a communications media – one number to switch the bank in, one to disconnect it.

Interlocking

Interlocking prevents unsafe operation of the various switches and breakers within a substation.  When an Operator or software application attempts to operate a control, the automation system evaluates the state of the entire system and may reject the control request based on pre-programmed logic.  This logic corresponds directly to the topology and interconnection of the substation.  Simpler substations may have little or no interlocking.  The most complex logic is associated with complex transformer and bus redundancy systems. 

For instance, an operator will close an earthing switch on a section of the bus to ground it prior to permitting maintenance on the equipment.  However, the operator may not be aware that the bus section is still live due to an interconnection with another bus section or a feeder fed by another bus section.  The automation system must prevent a fault by rejecting the Operator’s request.

Interlocking is most reliably and efficiently performed by the device that must perform the requested operation.  In the past, it may have been performed by the substation GUI or SCADA master station, when those were the only locations that could perform switching.  It is still often performed by a Substation Computer or Data Concentrator which serves as a clearinghouse for all control operations to the substation.  This centralized logic mechanism is still used, especially because deregulation has increased the number of master stations that require access to the substation.

However, more and more frequently, interlocking is performed by logic on the IEDs themselves, operating on data distributed by peer-to-peer communications between the devices.  This peer-to-peer communications has been made possible by the introduction of the substation LAN.  Performing interlocking at the IED permits the same logic and performance to be in effect regardless of whether the control request originates at a remote site, at a substation GUI, at the control panel of the IED, or even a manual panel switch.

In an ideal system, the state information required to perform interlocking would be updated simultaneously throughout the system.  Any delay provides a window in which a control could be mis-operated.  However, in practice, it is sufficient to update the state of the system in less than a second or two.  This interval represents the typical time between the moment an Operator checks the state of the system on a GUI or display panel, and the moment the Operator makes the control request.  As more automation applications are deployed in the substation, human reaction time will become less of a factor, and the demands on interlocking will increase.  Today, a challenging interlocking requirement for an advanced substation is less than 200 milliseconds between updates.

The control itself is typically issued with select-before-operate logic.  The distribution of state information for interlocking may be broadcast or multicast.  Redundancy and reliability is extremely important.

Sequenced Controls

While interlocking is intended to prevent Operator-initiated faults by rejecting invalid controls, sequenced controls automate some portion of the Operator’s tasks to eliminate the possibility of an invalid control ever being issued.

For example, consider a substation with two transformers and a normally open switch between the two bus sections connected to each transformer.  There are two different philosophies that an Operator may employ to take one of the transformers out of service.  In “make before break”, the Operator should (1) connect the two buses, (2) disconnect the transformer from the bus, and (3) disconnect the transformer from the upstream transmission line.  This method ensures there will be no outage of service.  In “break before make”, however, the Operator should (A) disconnect the transformer, then (B) quickly connect the bus and then (C) disconnect the transmission line.  This results in an outage, but prevents side effects resulting from mis-matched transformers sharing the same bus.

In a sequenced control, the Operator simply requests the isolation of the transformer, and the automation system performs the controls in the sequence required by the utility.  The Operator is not permitted to perform any other sequence.  In the “break before make” case above, it also ensures that the resulting outage is as small as possible, because the automation system can perform the sequence faster than a human.

The speed of a sequenced control is related to the components involved in the sequence.  For instance, the logic may need to wait for motorized switches to connect or disconnect before proceeding with the next control in the sequence.  In a “break before make” sequence as described above, however, the length of the outage must be minimized and a value of less than half a second is typically desired.  All sequenced controls are typically service-affecting and are therefore executed with select-before-operate logic.

Load Balancing

Load balancing is typically a distribution operation, performed between two transformers within a substation, but may also be performed in transmission systems between substations.  In the distribution case, two feeders serviced by separate transformers are connected at their remote ends by a normally open switch.  A pole-top IED controls the switch.  Other IEDs monitor load on the line.  The IEDs report the state and load of the system to a Substation Computer.  The Substation Computer detects the condition when one transformer is heavily loaded and the other has excess capacity, and sends a message to the pole-top IED to close the switch.  Now, instead of one line loaded at 90% and the other at 25%, both may be loaded at 50%.  Since resistive losses vary with the square of the current, this action improves the efficiency of the power system and reduces wear on equipment.  In transmission systems, two substations having lines feeding the same third substation may share load.  This type of logic is typically centralized, not distributed.

As with tap changing, load balancing is not an action that is typically performed lightly.   Qualification times for the logic may be measured in minutes or even hours.  Therefore, update times and control transmission times may be measured in seconds.  In distribution operations, this is fortunate because IEDs controlling the switches may be remote and only reached via slow links.  Some utilities may prefer that the process not be completely automated, and that the automation system request confirmation from the Operator before taking action.  Reliability of the data is important and redundant links may be used.

Automated Service Restoration

Automated Service Restoration is typically a distribution operation, but may be performed in transmission systems when “loops” are possible between substations.  In the distribution case, two feeders are connected at their remote ends by a normally open switch.  Several other switch / breaker combinations are located at other points along the feeders.  All the switches and breakers are monitored by IEDs.  When a fault occurs, the IEDs on the upstream side of the fault trips its breaker.  It notifies the Substation Computer of its action.  The IED on the downstream side of the fault notifies the Substation Computer of the loss of current and estimates the direction of the fault.  Based on that information and pre-configured logic, the Substation Computer recommends to the Operator that the breaker of the downstream IED should be opened and the normally open switch should be closed.  The Operator typically directs the Substation Computer to do so, and the Substation Computer forwards the decision to the IEDs.  When the IEDs perform the operations, power is restored to all portions of the feeders except the section in which the fault occurred.  The more break points there are in the feeders, the fewer customers will be affected by a given fault.

Time is of the essence in service restoration, but utilities typically require an Operator approve the decision of the system, so the human Operator is usually the slowest link in the system.  Communications times may be measured in seconds.  The breaker tripping is done by an individual IED without need for communications.

An alternative scenario occurs if the fault is not on the main feeder but on a lateral.  In this case, the fault causes the protection IED at the substation to trip and attempt reclosure.  While the current is zero between reclosure attempts, the IED nearest the fault opens its switch to clear the fault.  This is called “auto-sectionalization”.  Then, when the next reclosure occurs, service is restored to all subscribers except those on the lateral.  In this case, there is no effect on the communications system other than to monitor that the events occurred.

Normal Sequence Steps

Steps – Alternative / Exception Sequences

Source:EPRI

Table of Contents

• Sampling, Sensing, and Control: e.g. PT and CT Sampling, Fault indicator sensing, LTC Raise/Lower controls, and Protection Trip Signal
• Protection IED Interactions: e.g. interactions among protection IED to determine whether to trip, and which equipment to trip
• Substation Master System: e.g. Substation system that manages the IEDs within the substation, ranging from simple data concentrators, RTUs, to sophisticated master stations for managing substation automation functions
• DER Management Systems Monitoring and Control of DER Devices: e.g. managing Distributed Energy Resources in a substation or at an industrial customer site
• SCADA Systems within Control Centers for Monitoring and Control of Field Equipment: e.g. Control center SCADA system used to monitor substation data, and issue controls to substation equipment

Overview

Scope: The Data Acquisition and Control (DAC) functions of Substation Automation, used in transmission and distribution operations, comprise multiple types of mechanisms for data retrieval from field equipment and the issuing of control commands to power system equipment in the field, including among field devices, between field devices and systems located in substations, and between field devices and various systems (including, but not limited to, SCADA systems) located in DER and utility control centers and engineering/planning centers.

Objectives: The DAC function provides real-time data, statistical data, and other calculated and informational data from the power system to systems and applications that use the data. The DAC function also supports the issuing of control commands to power system equipment and the setting of parameters in IEDs and other field systems.

Rationale: Power system real-time data is source of most information required for power system operations. Control over the power system equipment can be achieved by issuing control commands and setting parameters.

The Data Acquisition and Control (DAC) function, used in transmission and distribution operations, comprises multiple types of mechanisms for data retrieval and issuing of control commands to power system equipment. These mechanisms are often used in conjunction with each other to provide the full range of DAC interactions. The DAC function, in turn, is used by other functions, such as Supervisory Control and Data Acquisition (SCADA) systems, Energy Management Systems (EMS), Protection Engineering systems, and Advanced Distribution Automation (ADA), as the means for their interactions with the power system equipment.

Substation Environments

The following drawing illustrates the two main IntelliGrid Environments in a Substation, the Environment between a substation and the control center, and the Environment within a control center. Click on each Environment to see a complete description of the Environment, the requirements that define the Environment, and the recommended standards, technologies, and best practices for that Environment.

The following figure shows some of the key information flows of data acquired in substations and other field locations (click on picture to enlarge it).

Sampling, Sensing, and Control of Power System Equipment

Narrative

Sampling and Sensing of Power System Equipment is performed by CTs, PTs, sensors, Intelligent Electronic Devices (IEDs), Remote Terminal Units (RTUs), or other microprocessor-based controllers. Control of Power System Equipment is performed by controllers, IEDs, or RTUs. These control commands are sometimes the result of applications within the IED or controller, and sometimes are passed through from external systems, such as a Substation Master System or a Control Center SCADA system.

The communications links are often very short (a few meters) but can also entail multi-mile links. The communications media typically are copper wires or optical fibers, but can include power line carrier, radio-based media, and possibly other media. Typically, the timing of the sampling, sensing, and control must meet very stringent requirements for rapid response (about 4 milliseconds), high availability, and high security.

They either use internal applications or are instructed by other entities to issue control signals to associated power system equipment. For example:

• Digital CTs sample the current on a substation bus
• Sensors monitor the status of a circuit breaker
• A Protection IED issues a trip signal to a circuit breaker
• Load Tap Changer IED raises and lowers the transformer tap position according to pre-set algorithms, based on voltage levels sensed by Potential Transformers (PTs).
• A circuit breaker IED issues an electro-mechanical or solid-state-based trip signal to a circuit breaker.
• A DER IED controller senses status and measurements of a DER generator and its prime mover, and then issues start and stop signals.

Diagram

Steps for Sampling, Sensing, and Control of Power System Equipment

An IED receives sensor data from a Potential Transformer (PT), or a circuit breaker IED issues a trip signal to a circuit breaker device.

Protection IED Interactions

Narrative

Protection IED Interactions are undertaken to respond to a relatively local situation within a substation or on a feeder that requires the exchange of information among two or more IEDs, specifically to determine whether to issue a trip signal, and which equipment should be tripped.

The communications media are normally point-to-point cables, LANs (in automated substations), and point-to-multi-point radio channels (on feeders). Transmission protection actions require very high speed communication channels, with response timeframes of 1 to 4 milliseconds, while distribution protection actions involving automated switches could tolerate longer response times. For example:

• A protection IED issues a trip command over a Process Bus LAN to a circuit breaker IED within a substation, based on its detection of different power system measurements, such as low frequency, current overload, etc.
• Multiple automated switch IEDs, using point-to-multi-point spread spectrum radio communications media, respond to a fault condition on a feeder segment by opening and closing switches to isolate the fault and restore power to unaffected feeder segments.

Diagram

Steps for Protection IED Interactions

A protection IED issues a trip command over a Deterministic Rapid Response LAN to a circuit breaker IED within a substation, based on its detection of different power system measurements, such as low frequency, current overload, etc.

Substation Master Systems

Narrative

A Substation Master System is a system within a substation that can:

• Acquire data from the substation IEDs
• Pass selected data to a control center
• Receive control commands from the control center
• Issue control commands to IEDs and controllers for them to take action

Substation Master Systems can be relatively simple or can include sophisticated capabilities. They include data concentrators, Remote Terminal Units (RTUs), as well as more sophisticated Substation Control and Data Acquisition Systems. These are generalized systems, as opposed to IEDs or controllers, and usually monitor and/or control more than one power system device. Data concentrators and RTUs just pass data through them, acting primarily as communication nodes, although they may include a local database. Basic Substation Master Systems may include applications to perform some local interactions, or may help coordinate IED actions. Highly capable Substation Master Systems may include applications that can perform closed loop control (e.g. does not interact with the human operator before issuing a control command).

The communications media can be LANs, copper wire, optical cables, microwave radio, leased telephone lines, cellphones, and many other types. Data exchanges range from a few 10’s of milliseconds up to 1 second. Examples include:

• Data concentrator in a substation monitors data from IEDs that are located on feeders connected to the substation. It passes some of this data to a SCADA system and passes control commands from the SCADA to the IEDs. It may collect sequence of events data and some statistical information in a database.
• Substation master coordinates the protection settings of substation IEDs based on requests from the SCADA system for different response patterns. For instance, different protection trigger levels are set for recloser responses if a storm is pending, or if reconfiguration of a feeder impacts the expected fault current level, or if DER generation levels could cause fuses to blow unnecessarily.
• Substation master provides information to automated switch IEDs on a feeder as to the actual configuration of a neighboring feeder. This information will permit the automated switch IEDs to take more appropriate action if a fault occurs.
• Substation master performs advanced substation automation functions, by responding to field conditions reported by IEDs and issuing control commands for volt/var optimization, fault location, isolation, and restoration, multi-feeder reconfiguration, etc.

Diagram

Steps for Substation Master Systems

Substation master systems coordinate the protection settings of substation IEDs based on requests from the SCADA system for different response patterns. For instance, different protection trigger levels are set for zone 3 protection or for recloser responses if a storm is pending, or if reconfiguration of a feeder impacts the expected fault current level, or if DER generation levels could cause fuses to blow unnecessarily.

DER Management Systems Monitoring and Control of DER Devices

Narrative

DER management systems perform monitoring and control of a DER device, either at a customer site or within a substation or from a utility’s distribution control center (see Figure 1‑1). The DER management system could be a DER owner’s SCADA system, a customer’s Building Automation System (BAS), an energy aggregator’s system, or a distribution operations SCADA system. Communications media can include virtually any type, so long as response times of a few seconds can be accommodated. Examples include:

• Loss of power is detected at a customer site. The backup diesel generator starts up, the automatic transfer switch connecting the customer to the utility EPS opens, and the generator is connected to the customer’s local EPS (or just the critical equipment).
• The owner of the DER device decides to reduce his load on the utility EPS by increasing generation. The DER operator implements this decision by setting new parameters in the DER management system. (These are manual actions by persons.) As an automated result, another generator is started by the DER management system, synchronized with the local EPS, and interconnected.
• An energy aggregator sets groups of DER devices to cycle on and off over the next day, taking into account pollution limits, the real-time price of energy, and contractual arrangements with the owners of the DER devices.
• While a DER device is interconnected with the utility EPS, a fault occurs on the feeder. The DER management system ensures that the DER device either trips off or the interconnection circuit breaker opens.
• The DER management system collects sequence-of-events, performance data, and statistical information from DER devices in a substation.

Diagram

Figure DER Management Systems Monitoring and Control of DER Devices

Steps for DER Management System Monitoring and Control of DER Devices

The owner of the DER device decides to reduce his load on the utility EPS by increasing generation. The DER operator implements this decision by setting new parameters in the DER management system. (These are manual actions by persons.) As an automated result, another generator is started by the DER management system, synchronized with the local EPS, and interconnected.

Control Center SCADA Systems Monitoring and Control of Field Equipment and IEDs

Narrative

SCADA systems perform remote monitoring and control of field equipment and IEDs. The term “SCADA” is used here to imply any centralized system which retrieves data from remote sites and may issue control commands when authorized. These SCADA systems are typically located in a utility control center, but may include an engineering “SCADA” system which retrieves protection data or disturbance data, or a maintenance “SCADA” system which monitors the health of both power system and communications equipment.

SCADA system monitoring can use communication channels directly to IEDs, via Remote Terminal Units (RTUs), through a data concentrator, through a substation master, or through a DER management system. The communications media can include virtually any type, so long as response times of 1 second can be accommodated. Although typically seen as used only for real-time distribution operations, the data acquired by the SCADA system can be used by many different systems, applications, and personnel in the control center. This Use Case is limited to the monitoring and control function by SCADA systems; other Use Cases (e.g. ADA Use Case) describe their interactions with the SCADA systems.

SCADA system monitoring and control examples include:

• Power system operations SCADA system receives real-time data from power system equipment via:

–    RTUs

–    IEDs inside substations

–    IEDs along feeders

–    Substation masters

–    DER (or other generation) management systems

–    Other control centers

–    Manual entry

• Power system operations SCADA system issues control commands to power system equipment in real-time via:

–    RTUs

–    IEDs inside substations

–    IEDs along feeders

–    Substation masters

–    DER (or other generation) management systems

–    Other control centers (if authorized)

• Power system operations SCADA system receives metering information
• Data management “SCADA” system receives power equipment configuration data from devices. It may have its own communication channels to the remote sites, or it may acquire this data through the distribution operations SCADA system
• Engineering “SCADA” system receives sequence of events data, oscillographic data (special handling required), historical data, and statistical data. It may have its own communication channels to the remote sites, or it may acquire this data through the distribution operations SCADA system
• Maintenance “SCADA” system receives data related to the health of power system equipment and communications equipment. It may have its own communication channels to the remote sites, or it may acquire this data through the distribution operations SCADA system.
• Planning “SCADA” system receives data that can be used for statistical analysis of power system measurements: maximums, minimums, averages, trends, profiles, power quality metrics, etc, needed for short and long term planning.

Diagram

Steps for Monitoring and Control by SCADA System

Distribution operations SCADA system monitors and controls power system equipment via a multitude of mechanisms.

 Source: EPRI

Trends in electric utility automation, specifically substation automation, have converged upon a common communications architecture with the goal of having interoperability between a variety of intelligent electronic devices (IEDs) found in the substation. This initiative was begun back in the late 1980s driven by the major North American utilities under the technical auspices of EPRI (Electric Power Research Institute). The resulting standard that emerged is known as the Utility Communications Architecture 2.0 (UCA2.0) and is becoming an international standard as IEC61850. This architecture, which is now being adopted worldwide by utilities and IED vendors alike, has as its underlying network technology – Ethernet.

The legacy substation

Prior to this initiative, inter-IED communications (signalling and exchange of information) was typically achieved via a combination of rigid wiring between devices and low speed serial communications. Signalling was often accomplished by having outputs from one IED connected to the inputs of another. This system was by its very nature inflexible and limited in its scope of control. Most sophisticated inter-IED control schemes would require a large number of wiring interconnections between multiple IEDs and thus were not practical. Low-speed serial communications was often limited to master/slave half-duplex arrangements and thus true peer-to-peer communications between IEDs was not feasible.

Typical legacy substation

The substation LAN

The emergence of the Ethernet-based substation LAN (local area network) has been steadily gaining momentum worldwide. The main benefits of the substation LAN are:

* High-speed, peer-to-peer communications between IEDs.

* Reduced inter-IED wiring.

* Coexisting multiple protocols (eg, DNP, Modbus, IEC61850) on the same physical network.

* Enables ‘Data over IP’ for easy access to substation data.

Substation LAN

The family of substation hardened Ethernet switches from RuggedSwitch has been designed to implement the substation LAN and to meet the same EMI immunity, performance and reliability requirements and standards as mission-critical protective relaying devices.

The IEC 61850 substation

The IEC 61850 standard view of the substation has two application domains: Station Bus and Process Bus. Station Bus refers to an application domain where relays and RTUs attach to the LAN. Process Bus refers to the domain where devices such as CT/VT Merging Units (MU) provide sampled measured values of current and voltage via the LAN.

IEC 61850 substation

Brendan Swart of H3iSquared says: “The RuggedSwitch family of substation hardened Ethernet switches has been created to meet the requirements of IEC 61850 and to implement Station Bus or Process Bus LANs. Specifically, these devices exceed the IEC 61850-3 EMI immunity requirements and the fibre optical network interfaces help provide zero packet loss performance under EMI stress. This is a must if the Station Bus LAN is to be used for tripping or blocking of breakers or if sampled measured values of current and voltage are to be distributed over the Process Bus LAN.

For more information contact H3iSquared, +27 (0)11 454 6025, brendan@h3isquared.com, www.H3iSquared.com

KSGL family of protocol hardware are field proven and secure solutions for protocol communication integration and translation requirements for the Power Generation, Transmission & Distribution, Oil & Gas, Industrial Automaton, Utilities, AMR, Remote Monitoring applications. Our products enable you to deploy standards based field-proven utility communication solutions with secure communication options quickly and cost-effectively.

Automation Systems currently need to support new and high speed standards like IEC 61850, IEEE C37.118, DNP3, IEC 104, ICCP and integrate in a secure manner with central control centers, local control centers, remote monitoring stations, data concentration centers, local and national grids and at the same time be able to talk within the local sub-system on standards like IEC 60870-5-103, DNP3, Modbus, SPA, Courier, DLMS/IEC 62056, Ethernet IP, DH+, SEL Protocol, SRTP, GSM, CANOpen and various other proprietary and standard protocols. Kalki Protocol Converters and Gateways provide you with a unique and cost effective solution to achieve your sub-station modernization requirements and utility communication security requirements in a standards based manner.

The KSGL and KPG Platforms support the following functions:

• CANOpen IO Gateway – Connect to CANOpen IO’s and make them available on any standard protocol such as DNP3, IEC 60870-5-101/103/104, IEC 61850 (UCA 2.0), Courier, SPA, Modbus, ICCP and proprietary interfaces.
• Protocol Converter – Convert standard or proprietary device protocols to control center protocols such as DNP3, IEC 60870-5-101/103/104, IEC 61850 (UCA 2.0), Courier, SPA, Modbus etc.,: one-to-one, one-to-many or many-to-many options supported
• Data Concentrator – Collect data from all substation devices, using standard and proprietary protocol, and make it available to control centers and the local HMI, using LAN, WAN, serial connections and GSM/GPRS/PSTN modems on one or two standard protocols. KSGL support’s up-to 50000 points and the KPG family supports upwards of 250000 points.
• Serial Port Pass-Through – Use the KSGL  to connect to any substation device for settings, remote maintenance, monitoring and control using the IED’s Proprietary Software. Have native support for Areva S1 and ABB CAP 501 and SMS.
• GPRS/GSM/PSTN/RF – KSGL supports communication over GPRS, GSM, PSTN and Radio for Distribution Automation requirements, including interfacing RMU, Feeder RTU, Transformer Monitoring and similar applications.
• Security Adapter – KSGL product act as a security adapter that support AES, 3DES and SSL Support. This enables two KSGL units to communicate in a secured manner over standard protocols over a public communication networks or similar technologies. KSGL/S can support FIPS 140-2 specifications.
• Device Server – KSGL family of products can also be configured to act as a device server, thereby providing multiple serial ports over its Ethernet. This enables multi-mastering or redundancy configurations across a distributed network with less number of serial ports and also the possibility of connecting proprietary configuration software on these Device Server Ports.

Protocol Gateway Models

The gateway comes with a EasyConnect Configuration and Diagnostic’s software. The same can be downloaded from our download site for evaluation. These tools are easy to use and offer both local and remote access to the gateway configuration, security settings, log files, communication traces, and system statistics.

KSGL is an integration platform that can be deployed in your existing sub-stations to connect your existing sub-station IED’s and relays to newer sub-station control systems, for RMU automation and pole top communications, as data concentration equipment in distribution automation applications, as data concentrators in industrial automation applications, for pipe-line monitoring applications and so on. The KSGL/KPG supports protocols like IEC 61850, IEEE C37.118, IEC 60870-5-101, IEC 60870-5-104, DLMS, IEC 62056, IEC 60870-5-103, UCA 2.0, Modbus RTU, Modbus TCP/IP etc., and also can be configured to support proprietary interfaces like ABB SPA, Alstom Courier and other vendor specific protocols. The sub-station gateway supports expandable serial and Ethernet interfaces to support a multitude of devices to your latest control systems in substation. 

If you would like to know more about this product or any other of Kalki’s products, solutions or services, please e-mail at sales@kalkitech.com or submit our Quotation Request Form

KSGL Mobile Gateways comes with support for GSM/GPRS/EDGE/CDMA support, Analog and Digital I/O’s and upto 6 Serial and 1 Ethernet port all sub-station / EMI/EMC hardened for high availability and high EMI/EMC rugged requirements. Ideal for Smart Grid, APDRP applications with OpenVPN Support and Dynamic IP Support.

Remote monitoring and smart grid applications require extensive remote monitoring on standards based protocols. Kalkitech Mobile Gateways are ideal for this requirement. With a huge array of power system and metering protocols, together with substation hardened design, they are ideal for AMR/AMI and smart grid applications as well as distribution automation applications.  

The KSGL Mobile Platforms consists of the KSGL/S2/R1 product range which have the following features:

• Protocol Converter – Convert standard or proprietary device protocols to control center protocols such as DNP3, IEC 101/103/104, IEC 61850, Modbus, DLMS, ANSI and many others
• Data Concentrator – Collect data from all local devices, using standard and proprietary protocol, and make it available to control centers and the local HMI, using LAN, WAN, serial connections and GSM/GPRS/PSTN modems on one or two standard protocols.
• Serial Port Pass-Through – Use the KSGL  to connect to any substation device for settings, remote maintenance, monitoring and control using the devices Proprietary Software.
• GPRS/GSM/CDMA – KSGL supports communication over GPRS, GSM, PSTN and Radio for Distribution Automation requirements, including interfacing Meters, RMU, Feeder RTU, Transformer Monitoring and similar applications.
• Security Adapter – KSGL product act as a security adapter that support AES, 3DES and SSL Support. This enables two KSGL units to communicate in a secured manner over standard protocols over a public communication networks or similar technologies. KSGL/S can support FIPS 140-2 specifications.

Gateway Models

The gateway comes with a EasyConnect Configuration and Diagnostic’s software. The same can be downloaded from our download site for evaluation. These tools are easy to use and offer both local and remote access to the gateway configuration, security settings, log files, communication traces, and system statistics.

If you would like to know more about this product or any other of Kalki’s products, solutions or services, please e-mail at sales@kalkitech.com or submit our Quotation Request Form

Manufacturing Message Specification (MMS) is an international standard (ISO 9506) dealing with messaging system for transferring real time process data and supervisory control information between networked devices and/or computer applications. The standard is developed and maintained by the ISO Technical Committee 184 (TC184). MMS defines the following

• A set of standard objects which must exist in every device, on which operations like read, write, event signaling etc can be executed. Virtual manufacturing device (VMD) is the main object and all other objects like variables, domains, journals, files etc comes under VMD.

• A set of standard messages exchanged between a client and a server stations for the purpose of monitoring and/or controlling these objects.

• A set of encoding rules for mapping these messages to bits and bytes when transmitted.

MMS original communication stack

MMS was standardized in 1990 under two separate standards as

• 1. ISO/IEC 9506-1 (2003): Industrial Automation systems – Manufacturing Message Specification – Part 1: Service Definition
• 2. ISO/IEC 9506-2 (2003): Industrial Automation systems – Manufacturing Message Specification – Part 2: Protocol Specification

This version of MMS used seven layers of OSI network protocols as its communication stack:

MMS stack over TCP/IP

Because the Open Systems Interconnection protocols are challenging to implement, the original MMS stack never became popular. In 1999, Boeing created a new version of MMS using Internet protocols instead of the bottom four layers of the original stack plus RFC 1006 (“ISO Transport over TCP”) in the Transport layer. The top three layers use the same OSI protocols as before.

In terms of the seven-layer OSI model, the new MMS stack looks like this:

With the new stack, MMS has become a globally accepted standard.^{[citation needed]}

External links

• MMS Overview
• MMS Protocol Stack and test tools
• Protocol gateways for MMS based protocols

IEC 61850^[1] is a standard for the design of electrical substation automation. IEC 61850 is a part of the International Electrotechnical Commission’s (IEC) Technical Committee 57 (TC57)^[2] reference architecture for electric power systems. The abstract data models defined in IEC 61850 can be mapped to a number of protocols. Current mappings in the standard are to MMS (Manufacturing Message Specification), GOOSE, SMV, and soon to Web Services. These protocols can run over TCP/IP networks and/or substation LANs using high speed switched Ethernet to obtain the necessary response times of < 4 ms for protective relaying.

Standard Documents

IEC 61850 consists of the following parts detailed in separate IEC 61850 standard documents

• IEC 61850-1: Introduction and overview
• IEC 61850-2: Glossary
• IEC 61850-3: General requirements
• IEC 61850-4: System and project management
• IEC 61850-5: Communication requirements for functions and device models
• IEC 61850-6: Configuration description language for communication in electrical substations related to IEDs
• IEC 61850-7: Basic communication structure for substation and feeder equipment
  • IEC 61850-7-1: Principles and models
  • IEC 61850-7-2: Abstract communication service interface (ACSI)
  • IEC 61850-7-3: Common Data Classes
  • IEC 61850-7-4: Compatible logical node classes and data classes
• IEC 61850-8: Specific communication service mapping (SCSM)
  • IEC 61850-8-1: Mappings to MMS (ISO/IEC9506-1 and ISO/IEC 9506-2)
• IEC 61850-9: Specific communication service mapping (SCSM)
  • IEC 61850-9-1: Sampled values over serial unidirectional multidrop point to point link
  • IEC 61850-9-2: Sampled values over ISO/IEC 8802-3
• IEC 61850-10: Conformance testing

History

Multiple protocols exist for substation automation, which include many proprietary protocols with custom communication links. Interoperation of devices from different vendors would be an advantage to users of substation automation devices. An IEC project group of about 60 members from different countries worked in three IEC working groups from 1995. They responded to all the concerns and objectives and created IEC 61850. The objectives set for the standard were:

1. A single protocol for complete substation considering modeling of different data required for substation.
2. Definition of basic services required to transfer data so that the entire mapping to communication protocol can be made future proof.
3. Promotion of high interoperability between systems from different vendors.
4. A common method/format for storing complete data.
5. Define complete testing required for the equipments which confirms to the standard.

IEC 61850 Features

IEC 61850 features include:

1. Data Modeling — Primary process objects as well as protection and control functionality in the substation is modelled into different standard logical nodes which can be grouped under different logical devices. There are logical nodes for data/functions related to the logical device (LLN0) and physical device (LPHD).
2. Reporting Schemes — There are various reporting schemes (BRCB & URCB) for reporting data from server through a server-client relationship which can be triggered based on pre-defined trigger conditions.
3. Fast Transfer of events — Generic Substation Event (GSE) are defined for fast transfer of event data for a peer-to-peer communication mode. This is again subdivided into GOOSE & GSSE.
4. Setting Groups — The setting group control Blocks (SGCB) are defined to handle the setting groups so that user can switch to any active group according to the requirement.
5. Sampled Data Transfer — Schemes are also defined to handle transfer of sampled values using Sampled Value Control blocks (SVCB)
6. Commands — Various command types are also supported by IEC 61850 which include direct & select before operate (SBO) commands with normal and enhanced securities.
7. Data Storage– SCL(Substation Configuration Language) is defined for complete storage of configured data of the substation in a specific format.

IEC 61850 – Related Developments

• IEC 61850-7-410 — IEC 61850-7-410 Ed.1 Communication networks and systems for power utility automation – Part 7-410: Hydroelectric Power Plants – Communication for monitoring and control. [Published]
• IEC 61850-7-420 — Communications systems for Distributed Energy Resources (DER) – Logical nodes [Draft]
• IEC 62445
  • IEC 62445-1 — Use of IEC 61850 for the communication between substations [Approved New Work]
  • IEC 62445-2 — Use of IEC 61850 for the communication between control centers and substations [Approved New Work]
  • IEC 62445-3 — Mapping of IEC 61850 based Common Data Classes (CDC’s), information addressing, services onto IEC 60870-5-104/101 [Approved New Work]
• IEC 61400-25 — IEC 61850 Adaptation for Wind Turbines
  • IEC 61400-25-1 — Wind turbines – Part 25-1: Communications for monitoring and control of wind power plants – Overall description of principles and models [Published]
  • IEC 61400-25-2 — Wind turbines – Part 25-2: Communications for monitoring and control of wind power plants – Information models [Published]
  • IEC 61400-25-3 — Wind turbines – Part 25-3: Communications for monitoring and control of wind power plants – Information exchange models [Published]
  • IEC 61400-25-4 — Wind turbines – Part 25-4: Communications for monitoring and control of wind power plants – Mapping to communication profile
    • Mapping to Web services [Work under progress]
    • Mapping to MMS [Refer to IEC 61850-8-1 (published)]
    • Mapping to OPC XML DA [Work under progress]
    • Mapping to IEC 60870-5-104 [Refer to IEC 62445-3 (Work under progress)]
    • Mapping to DNP3 [Work under progress]
  • IEC 61400-25-5 — Wind turbines – Part 25-5: Communications for monitoring and control of wind power plants – Conformance testing [Published]
  • IEC 61400-25-6 — Wind Turbines – Part 25-6: Communications for monitoring and control of wind power plants – Logical node classes and data classes for condition monitoring [Work under progress]
• IEC 62271-3 — Communications for monitoring and control of high-voltage switchgear (published)

See also

• GSE (Generic Substation Events)
• Substation Configuration Language (IEC)
• IEC 60870-5
• IEC 60870-5-101
• IEC 60870-5-103
• IEC 60870-5-104
• DNP3

References

1. ^ IEC 61850 overview.
2. ^ Technical Committee 57 (TC57)

External links

General Information

• Detailed Introduction to IEC 61850
• IEC Website for IEC 61850 standards
• IEC 61850 Technical Issues Website
• UCA International Users Group
• IEC 61850-3 standard and requirement
• PRAXIS PROFILINE Special edition: IEC 61850 – Generating Tomorrow’s Electricity