SCADA As Heart Of Distribution Management System

SCADA – The Heart Of Distribution Management System (DMS) - On photo: Fima UAB - Dedicated control systems and SCADA (Supervisory Control and Data Acquisition) as well as DMS (Distribution Management System) type of systems are offered for electricity, water and gas supply companies, as well as telecommunication operators and manufacturing companies.

SCADA System Elements

At a high level, the elements of a distribution automation system can be divided into three main areas:

1. SCADA application and server(s)
2. DMS applications and server(s)
3. Trouble management applications and server(s)

 

Distribution SCADA

As was stated in the title, the Supervisory Control And Data Acquisition (SCADA) system is the heart of Distribution Management System (DMS) architecture.
A SCADA system should have all of the infrastructure elements to support the multifaceted nature of distribution automation and the higher level applications of a DMS. A Distribution SCADA system’s primary function is in support of distribution operations telemetry, alarming, event recording, and remote control of field equipment.

•  Historically, SCADA systems have been notorious for their lack of support for the import, and more importantly, the export of power system data values.

 
A modern SCADA system should support the engineering budgeting and planning functions by providing access to power system data without having to have possession of an operational workstation.
The main elements of a SCADA system are:

1. Host equipment
2. Communication infrastructure (network and serial communications)
3. Field devices (in sufficient quantity to support operations and telemetry requirements of a DMS platform)

Host Equipment

The essential elements of a distribution SCADA host are:

1. Host servers (redundant servers with backup/failover capability).
2. Communication front-end nodes (network based).
3. Full graphics user interfaces.
4. Relational database server (for archival of historical power system values) and data server/Web server (for access to near real time values and events).

The elements and components of the typical distribution automation system are illustrated in Figure 1 above.

Host Computer System

SCADA Servers

As SCADA has proven its value in operation during inclement weather conditions, service restoration, and daily operations, the dependency on SCADA has created a requirement for highly available and high performance systems. Redundant server hardware operating in a “live” backup/failover mode is required to meet the high availability criteria.

•  High-performance servers with abundant physical memory, RAID hard disk systems, and interconnected by 10/100 baseT switched Ethernet are typical of today’s SCADA servers.

Communication Front-End (CFE) Processors

The current state of host to field device communications still depends heavily on serial communications.

This requirement is filled by the CFE. The CFE can come in several forms based on bus architecture (e.g., VME or PCI) and operating system. Location of the CFE in relation to the SCADA server can vary based on requirement. In some configurations the CFE is located on the LAN with the SCADA server. In other cases, existing communications hubs may dictate that the CFE reside at the communication hub.

The incorporation of the WAN into the architecture requires a more robust CFE application to compensate for less reliable communications (in comparison to LAN).

In general the CFE will include three functional devices:

1. A network/CPU board,
2. Serial cards, and
3. Possibly a time code receiver.

Functionality should include the ability to download configuration and scan tables. The CFE should also support the ability to dead band values (i.e., report only those analog values that have changed by a user-defined amount).

CFE, network, and SCADA servers should be capable of supporting worst-case conditions (i.e., all points changing outside of the dead band limits), which typically occur during severe system disturbances.

Full Graphics User Interface

The current trend in the user interface (UI) is toward a full graphics (FG) user interface. While character graphics consoles are still in use by many utilities today, SCADA vendors are aggressively moving their platforms to a full graphics UI.

Quite often the SCADA vendors have implemented their new full graphics user interface on low-cost NT workstations using third-party applications to emulate the X11 window system.

SCADA - Full graphic display using Video Wall

Full graphic displays provide the ability to display power system data along with the electric distribution facilities in a geographical (or semigeographical) perspective.

The advantage of using a full graphics interface becomes evident (particularly for distribution utilities) as SCADA is deployed beyond the substation fence where feeder diagrams become critical to distribution operations.
 

Relational Databases, Data Servers, and Web Servers

The traditional SCADA systems were poor providers of data to anyone not connected to the SCADA system by an operational console.

This occurred due to the proprietary nature of the performance (in memory) database and its design optimization for putting scanned data in and pushing display values out. Power system quantities such as: bank and feeder loading (MW, MWH, MQH, and ampere loading), and bus volts provide valuable information to the distribution planning engineer.

• The availability of event (log) data is important in postmortem analysis. The use of relational databases, data servers, and Web servers by the corporate and engineering functions provides access to power system information and data while isolating the SCADA server from nonoperations personnel.

Host to Field Communications

Serial communications to field devices can occur over several mediums: copper wire, fiber, radio, and even satellite. Telephone circuits, fiber, and satellites have a relatively high cost. New radio technologies offer good communications value.

•  One such technology is the Multiple Address Radio System (MAS).

The MAS operates in the 900 MHz range and is omnidirectional, providing radio coverage in an area with radius up to 20–25 miles depending on terrain. A single MAS master radio can communicate with many remote sites. Protocol and bandwidth limit the number of remote terminal units that can be communicated with by a master radio. The protocol limit is simply the address range supported by the protocol.

Bandwidth limitations can be offset by the use of efficient protocols, or slowing down the scan rate to include more remote units. Spread-spectrum and point-to-point radio (in combination with MAS) offers an opportunity to address specific communication problems.

At the present time MAS radio is preferred to packet radio (another new radio technology); MAS radio communications tend to be more deterministic providing for smaller timeout values on communication noresponses and controls.

Field Devices

Distribution Automation (DA) field devices are multi-featured installations meeting a broad range of control, operations, planning, and system performance issues for the utility personnel.
Each device provides specific functionality, supports system operations, includes fault detection, captures planning data and records power quality information. These devices are found in the distribution substation and at selected locations along the distribution line. The multi-featured capability of the DA device increases its ability to be integrated into the electric distribution system.

•  The functionality and operations capabilities complement each other with regard to the control and operation of the electric distribution system.

 
The fault detection feature is the “eyes and ears” for the operating personnel. The fault detection capability becomes increasingly more useful with the penetration of DA devices on the distribution line.

The real-time data collected by the SCADA system is provided to the planning engineers for inclusion in the radial distribution line studies. As the distribution system continues to grow, the utility makes annual investments to improve the electric distribution system to maintain adequate facilities to meet the increasing load requirements.

The use of the real-time data permits the planning engineers to optimize the annual capital expenditures required to meet the growing needs of the electric distribution system.
The power quality information includes capturing harmonic content to the 15th harmonic and recording Percent Total Harmonic Distortion (%THD). This information is used to monitor the performance of the distribution electric system.

Modern RTU

Today’s modern RTU is modular in construction with advanced capabilities to support functions that heretofore were not included in the RTU design.
The modular design supports installation configurations ranging from the small point count required for the distribution line pole-mounted units to the very large point count required for large bulk-power substations and power plant switchyard installations.

Modern RTU Scada

The modern RTU modules include analog units with 9 points, control units with 4 control pair points, status units with 16 points, and communication units with power supply.

The RTU installation requirements are met by accumulating the necessary number of modern RTU modules to support the analog, control, status, and communication requirements for the site to be automated. Packaging of the minimum point count RTUs is available for the distribution line requirement.

•  The substation automation requirement has the option of installing the traditional RTU in one cabinet with connections to the substation devices or distributing the RTU modules at the devices within the substation with fiberoptic communications between the modules.

 
The distributed RTU modules are connected to a data concentrating unit which in turn communicates with the host SCADA computer system.

The modern RTU accepts direct AC inputs from a variety of measurement devices including line-post sensors, current transformers, potential transformers, station service transformers, and transducers. Direct AC inputs with the processing capability in the modern RTU supports fault current detection and harmonic content measurements. The modern RTU has the capability to report the magnitude, direction, and duration of fault current with time tagging of the fault event to 1-millisecond resolution. Monitoring and reporting of harmonic content in the distribution electric circuit are capabilities that are included in the modern RTU.

The digital signal processing capability of the modern RTU supports the necessary calculations to report %THD for each voltage and current measurement at the automated distribution line or substation site.
The modern RTU includes logic capability to support the creation of algorithms to meet specific operating needs.

•  Automatic transfer schemes have been built using automated switches and modern RTUs with the logic capability. This capability provides another option to the distribution line engineer when developing the method of service and addressing critical load concerns.

 
The logic capability in the modern RTU has been used to create the algorithm to control distribution line switched capacitors for operation on a per phase basis. The capacitors are switched on at zero voltage crossing and switched off at zero current crossing.

The algorithm can be designed to switch the capacitors for various system parameters, such as voltage, reactive load, time, etc. The remote control capability of the modern RTU then allows the system operator to take control of the capacitors to meet system reactive load needs.
The modern RTU has become a dynamic device with increased capabilities. The new logic and input capabilities are being exploited to expand the uses and applications of the modern RTU.

PLCs and IEDs

Programmable Logic Controller (PLC) and Intelligent Electronic Device (IED) are components of the distribution automation system, which meet specific operating and data gathering requirements.

 

PLC SCADA Panel

While there is some overlap in capability with the modern RTU, the authors are familiar with the use of PLCs for automatic isolation of the faulted power transformer in a two-bank substation and automatic transfer of load to the unfaulted power transformer to maintain an increased degree of reliability.

The PLC communicates with the modern RTU in the substation to facilitate the remote operation of the substation facility.

•  The typical PLC can support serial communications to a SCADA server. The modern RTU has the capability to communicate via an RS-232 interface with the PLC.

 
IEDs include electronic meters, electronic relays, and controls on specific substation equipment, such as breakers, regulators, LTC on power transformers, etc.

The IEDs also have the capability to support serial communications to a SCADA server. However, the authors’ experience indicates that the IEDs are typically reporting to the modern RTU via an RS-232 interface or via status output contact points.

As its communicating capability improves and achieves equal status with the functionality capability, the IED has the potential to become an equal player in the automation communication environment.
However, in the opinion of the authors, the limited processing capability for supporting the communication requirement, in addition to its functional requirements (i.e., relays, meters, etc.), hampers the widespread use of the IEDs in the distribution automation system.

Resource: Power System Operation and Control - George L. Clark and Simon W. Bowen

 

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Typical AC Power Supply system (Generation, Transmission and Distribution) scheme and Elements of Distribution System (a complete note With Diagrams)

Typical AC Power Supply system scheme

The lines network between Generating Station (Power Station) and consumer of electric power can be divided into two parts.

• Transmission System
• Distribution System

We can explore these systems in more categories such as Primary transmission and secondary transmission. Similarly primary distribution and secondary distribution. This is shown in the below image (One Line or Single Line diagram of Typical AC power System Scheme)

It is not necessary that the entire steps which are sown in the above image must be included in the other power schemes. There may be difference. For example, there is no secondary transmission in many schemes, in some (small) schemes there is no transmission, but only distribution.

The following parts are shown in figure 1.

 

 

 Figure 1: single line diagram of electrical power system

1. Generating Station
2. Primary transmission
3. Secondary transmission
4. Primary Distribution
5. Secondary Distribution

Following is detail of the above sections

 

Generating Station:

 

The place where electric power produced by parallel connected three phase alternators/generators is called Generating Station. The Ordinary generating voltage may be 11kV, 11.5 kV 12kV or 13kV. But economically, it is good to step up the produced voltage from (11kV, 11.5kV Or 12 kV) to 132kV, 220kV or 500kV or greater (in some countries, up to 1500kV) by Step up transformer (power Transformer).

 

Primary Transmission:

 

The electric supply (in 132kV, 220 kV, 500kV or greater) is transmit to load center by three phase three wire overhead transmission system.

 

Secondary transmission:

 

Area far from city (outskirts) which have connected with receiving station by line is called Secondary transmission. At receiving station, the level of voltage reduced by step-down transformers up to 132kV, 66 or 33 kV, and Electric power is transmit by three phase three wire overhead system to different sub stations. So this is a Secondary Transmission.

 

Primary Distribution:

 

At a sub station, the level of secondary transmission voltage (132kV, 66 or 33 kV) reduced to 11kV by step down transforms.

generally, electric supply is given to those  heavy consumer which demands is 11 kV, from these lines which caries 11 kV ( in three phase three wire overhead system) and they make a separate sub station to control and utilize this power.

in other cases, for heavier consumer (at large scale) their demand is about 132 kV or 33 kV.  they take electric supply from secondary transmission or primary distribution ( in 132 kV, 66kV or 33kV) and then step down the level of voltage by step-down transformers in their own sub station for utilization ( i.e. for electric traction etc).

 

Secondary Distribution:

 

Electric power is given by (from Primary distribution line i.e.11kV) to distribution sub station. This sub station is located near by consumers areas where the level of voltage reduced by step down transformers 440V by Step down transformers. These transformers called Distribution transformers, three phase four wire system). So there is 400 Volts (Three Phase Supply System) between any two phases and 230 Volts (Single Phase Supply) between a neutral and phase (live) wires. Residential load (i.e. Fans, Lights, and TV etc) may be connected between any one phase and neutral wires, while three phase load may be connected directly to the three phase lines.

 

Elements of Distribution System

 

Secondary distribution may be divided into three parts

1. Feeders
2. Distributors
3. Service Lines or Service Mains 

Feeders:

 

Those Electric lines which connect Generating station (power station) or Sub Station to distributors are called feeders.

Remember that current in feeders (in each point) is constant while the level of voltage may be different; the current flowing in the feeders depends on the size of conductor.

 

Distributors:

 

Those taping which extracted for supply of electric power to the consumers or those lines, from where consumers get electric supply is called distributors.

As shown in fig 2.Current is different in each section of the distributors while voltage may be same. The selection of distributors depends on voltage drop and may be design according voltage drop. It is because consumers get the rated voltage according rules.

NOTE: the main difference between Feeder and Distributor is that Current in Feeder is same (in each section) in the other hand, Voltage is same in each section of Distributor

 

Service Lines or Service Mains:

 

The Normal cable which is connected between Distributors and Consumer load terminal called Service Line or Service Mains.

 Here is a a complete Typical AC Power Supply system scheme, in other words, the above whole story in below image.

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Why the reactance of a system under fault condition is low and faults currents may raise dangerously high value. ? (With simple example)

 Because the total Power is same, and under fault condition (Short circuit)…There is no load (Impedance (Z), or Reactance ( X_L)= Resistance, and in case of no load, there will be no reactance or resistance, so current will be high) in this condition…So current will be too high, and when power is same, and current increases, voltage will be decrease.

Example,

Suppose, (In normal condition)

 P= 10 watt, V = 5 Volts, and Current = 2 Amp.

But in Short circuit Condition, (When current is too high)

Then,

P = 10 Watts,    I= 10 A, so

 V = P/I….. 10 Watts/10A=1 V.

In case of short circuit, there will be no load (load = may be inductive (X_L) or resistive) so when X_L (We can say it resistance or opposition of current) = Zero, then Current will be too high.

So we can see that, in case of short circuit, (Faults condition) XL (inductive Reactance) =0, so Current increase, voltage decreases.

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Primary and Secondary or Backup protection in a Power System

Primary Protection 
Below is the power system protection scheme which is designed to protect the power system parts and components. As shown in below fig, each line associated with over current relay that protect the lines from faults. So, if a fault happens on any line, it will be cleared by its relay and circuit breaker. This is called primary or main protection and acts as a first line defender. The service record of primary relaying is very high with well over 90% of all operations being correct. But this is not always the case, sometimes faults are not illuminated by the primary or main protection system i.e. circuit breaker and relay system because of trouble within the relays, circuit breakers or wiring system in different conditions. In those conditions, Secondary or backup protection system does the required job.

 

Primary protection may fail due to the following reasons

• Failure of DC supply to the tripping Circuit
• Failure in relay operating current or voltage
• Failure in circuit breaker tripping mechanism
• Failure of main protective relay operation
• Failure in the wiring of relaying system
• Failure of CTs or PTs operation

Secondary Protection

Back-up protection is very important for stable and reliable power system

As we know that, it is not possible to design a 100% secure and efficient system because there are possibilities of failure in the connected CTs, PTs, circuit breaker etc. in the system. If it happens, then it will destroy our whole switching system.

If the primary protection operation falls into trouble, then secondary protection disconnects the faulty part from the system. Moreover, when we disconnect primary protection for testing or maintenance purpose, then secondary or back-up protection will act as primary protection. In the above fig, relay “X” (1 Sec time setting) provides backup protection for each of the four connected lines to the main bus.

In addition, a larger part is disconnected then when primary relaying functions correctly. Therefore, greater emphasis should be placed on the better maintenance of primary relaying which is economical.

Types of Secondary or backup protection

• Relay Backup Protection
• Breaker Backup Protection
• Remote Backup Protection
• Centrally Co-ordinate Backup Protection

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