An Introduction To SCADA For Electrical

Engineers Beginners

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beginners

An Introduction To SCADA (Supervisory Control And Data Acquisition) For Beginners // On

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Control and Supervision

It is impossible to keep control and supervision on all industrial activities manually. Some

automated tool is required which can control, supervise, collect data, analyses data and generate

reports. A unique solution is introduced to meet all this demand is SCADA system.

SCADA stands for supervisory control and data acquisition. It is an industrial control system

where a computer system monitoring and controlling a process.

Another term is there, Distributed Control System (DCS). Usually there is a confusion between

the concept of these two.

A SCADA system usually refers to a system that coordinates, but does not control processes in real time,

but DCS do that. SCADA systems often have Distributed Control System (DCS) components.

Components of SCADA

1. Human Machine Interface (HMI)

It is an interface which presents process data to a human operator, and through this, the human

operator monitors and controls the process.

2. Supervisory (computer) system

It gathers data on the process and sending commands (or control) to the process.

3. Remote Terminal Units (RTUs)

It connect to sensors in the process, converting sensor signals to digital data and sending digital

data to the supervisory system.

4. Programmable Logic Controller (PLCs)

It is used as field devices because they are more economical, versatile, flexible, and configurable

than special-purpose RTUs.

5. Communication infrastructure

It provides connectivity to the supervisory system to the Remote Terminal Units.

SCADA System Concept

The term SCADA usually refers to centralized systems which monitor and control entire sites, or

complexes of systems spread out over large areas (anything between an industrial plant and a

country).

Most control actions are performed automatically by Remote Terminal Units (RTUs) or by

programmable logic controllers (PLCs).

Host control functions are usually restricted to basic overriding or supervisory level

intervention. For example, a PLC may control the flow of cooling water through part of an

industrial process, but the SCADA system may allow operators to change the set points for the

flow, and enable alarm conditions, such as loss of flow and high temperature, to be displayed and

recorded.

The feedback control loop passes through the RTU or PLC, while the SCADA system monitors

the overall performance of the loop.

A simple SCADA system with single computer

SCADA/PLC Video Introduction/Example

Waste Water Treatment SCADA System Raising your Plant IQ

https://www.youtube.com/watch?v=ZSFdOjxB-1I&feature=player_embedded

Cant see this video? Click here to watch it on Youtube.

Introducing students to Industrial Programmable Controllers

https://www.youtube.com/watch?v=lCYWuk034NI&feature=player_embedded

Cant see this video? Click here to watch it on Youtube.

Three generations of SCADA system

architectures

Generations

SCADA systems have evolved in parallel with the growth and sophistication of

modern computing technology.

The following sections will provide a description of the following three generations of SCADA

systems:

1. First Generation Monolithic 2. Second Generation Distributed 3. Third Generation Networked

- Waste Water Treatment Plant SCADA (VIDEO)

1. Monolithic SCADA Systems

When SCADA systems were first developed, the concept of computing in general centered on

mainframe systems. Networks were generally non-existent, and each centralized system stood alone.

As a result, SCADA systems were standalone systems with virtually no connectivity to other

systems.

The Wide Area Networks (WANs) that were implemented to communicate with remote terminal units

(RTUs) were designed with a single purpose in mindthat of communicating with RTUs in the field and

nothing else. In addition, WAN protocols in use today were largely unknown at the time.

The communication protocols in use on SCADA networks were developed by vendors of RTU

equipment and were often proprietary.

In addition, these protocols were generally very lean, supporting virtually no functionality beyond that required scanning and controlling points within the remote device. Also, it was

generally not feasible to intermingle other types of data traffic with RTU communications on the

network.

Connectivity to the SCADA master station itself was very limited by the system

vendor. Connections to the master typically were done at the bus level via a proprietary adapter

or controller plugged into the Central Processing Unit (CPU) backplane.

Redundancy in these first generation systems was accomplished by the use of two identically

equipped mainframe systems, a primary and a backup, connected at the bus level.

Figure 1 - First Generation SCADA Architecture

The standby systems primary function was to monitor the primary and take over in the event of a detected failure. This type of standby operation meant that little or no processing was done on

the standby system. Figure 1 shows a typical first generation SCADA architecture.

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2. Distributed SCADA Systems

The next generation of SCADA systems took advantage of developments and improvement in

system miniaturization and Local Area Networking (LAN) technology to distribute the

processing across multiple systems.

Multiple stations, each with a specific function, were connected to a LAN and shared

information with each other in real-time.

These stations were typically of the mini-computer class, smaller and less expensive than their first

generation processors.

Some of these distributed stations served as communications processors,

primarily communicating with field devices such as RTUs. Some served as operator

interfaces, providing the human-machine interface (HMI) for system operators. Still others

served as calculation processors or database servers.

Remote terminal unit (RTU)

The distribution of individual SCADA system functions across multiple systems provided more

processing power for the system as a whole than would have been available in a single

processor. The networks that connected these individual systems were generally based on LAN

protocols and were not capable of reaching beyond the limits of the local environment.

Some of the LAN protocols that were used were of a proprietary nature, where the

vendor created its own network protocolor version thereof rather than pulling an existing one

off the shelf. This allowed a vendor to optimize its LAN protocol for real-time traffic, but

it limited (or effectively eliminated) the connection of network from other vendors to

the SCADA LAN.

Figure 2 depicts typical second generation SCADA architecture.

Figure2 - Second Generation SCADA Architecture

Distribution of system functionality across network-connected systems served not only

to increase processing power, but also to improve the redundancy and reliability of the system

as a whole. Rather than the simple primary/standby fail over scheme that was utilized in many

first generation systems, the distributed architecture often kept all stations on the LAN in an

online state all of the time.

For example, if an HMI station were to fail, another HMI station could be used to operate the

system, without waiting for fail over from the primary system to the secondary.

The WAN used to communicate with devices in the field were largely unchanged by

the development of LAN connectivity between local stations at the SCADA master.

These external communications networks were still limited to RTU protocols and were

not available for other types of network traffic.

As was the case with the first generation of systems, the second generation of SCADA systems was also

limited to hardware, software, and peripheral devices that were provided or at least selected by the

vendor.

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3. Networked SCADA Systems

The current generation of SCADA master station architecture is closely related to that of the

second generation, with the primary difference being that of an open system architecture rather

than a vendor controlled, proprietary environment.

There are still multiple networked systems, sharing masterstation functions. There are still

RTUs utilizing protocols that are vendor-proprietary.

The major improvement in the third generation is that of opening the system architecture, utilizing

open standards and protocols and making it possible to distribute SCADA functionality across a WAN

and not just a LAN.

Open standards eliminate a number of the limitations of previous generations of

SCADA systems. The utilization of off-the-shelf systems makes it easier for the user to

connect third party peripheral devices (such as monitors, printers, disk drives, tape drives, etc.)

to the system and/or the network.

As they have moved to open or off-the-shelf systems, SCADA vendors have gradually gotten out of the hardware development business. These vendors have looked to system vendors

such as Compaq, Hewlett-Packard, and Sun Microsystems for their expertise in developing the

basic computer platforms and operating system software.

This allows SCADA vendors to concentrate their development in an area where they can

add specific value to the system that of SCADA master station software.

The major improvement in third generation SCADA systems comes from the use of WAN

protocols such as the Internet Protocol (IP) for Communication between the master station and

communications equipment. This allows the portion of the master station that is responsible for

communications with the field devices to be separated from the master station proper across a WAN.

Vendors are now producing RTUs that can communicate with the master station using an

Ethernet connection.

Figure 3 represents a networked SCADA system.

Figure 3 - Third Generation SCADA System

Another advantage brought about by the distribution of SCADA functionality over a WAN is

that of disaster survivability. The distribution of SCADA processing across a LAN in second-

generation systems improves reliability, but in the event of a total loss of the facility housing the

SCADA master, the entire system could be lost as well.

By distributing the processing across physically separate locations, it becomes possible to build a SCADA

system that can survive a total loss of any one location.

For some organizations that see SCADA as a super-critical function, this is a real benefit.

Waste Water Treatment Plant SCADA (VIDEO)

https://www.youtube.com/watch?v=ZSFdOjxB-1I&feature=player_embedded

Cant see this video? Click here to watch it on Youtube.

Resource: Supervisory Control and Data Acquisition (SCADA) Systems Communication Technologies, Inc.

Advantages Of IEC 61850

IEC 61850 - Advantages and Key Features

One of the significant challenges that substation engineers face is justifying substation

automation investments. The positive impacts that automation has on operating costs, increased

power quality, and reduced outage response are well known. But little attention is paid to how

the use of a communication standard impacts the cost to build and operate the substation.

Legacy communication protocols were typically developed with the dual objective of providing

the necessary functions required by electric power systems while minimizing the number of

bytes that were used by the protocol because of severe bandwidth limitations that were typical of

the serial link technology available 10-15 years ago when many of these protocols were initially

developed.

Later, as Ethernet and modern networking protocols like TCP/IP became widespread, these

legacy protocols were adapted to run over TCP/IP-Ethernet.

This approach provided the same basic electric power system capabilities as the serial link

version while bringing the advantages of modern networking technologies to the substation. But

this approach has a fundamental flaw: the protocols being used were still designed to minimize

the bytes on the wire and do not take advantage of the vast increase in bandwidth that modern

networking technologies deliver by providing a higher level of functionality that can

significantly reduce the implementation and operational costs of substation automation.

Top

Modern Networking Technologies IEC 61850 is unique. IEC 61850 is not a former serial link protocol recast onto TCP/IP-Ethernet. IEC 61850

was designed from the ground up to operate over modern networking technologies and delivers an

unprecedented amount of functionality that is simply not available from legacy communications

protocols.

These unique characteristics of IEC 61850 have a direct and positive impact on the cost to

design, build, install, commission, and operate power systems. While legacy protocols on

Ethernet enable the substation engineer to do exactly the same thing that was done 10-15 years

ago using Ethernet, IEC 61850 enables fundamental improvements in the substation automation

process that is simply not possible with a legacy approach, with or without TCP/IP-Ethernet.

To better understand the specific benefits we will first examine some of the key features and

capabilities of IEC 61850 and then explain how these result in significant benefits that cannot be

achieved with the legacy approach.

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Key Features

The features and characteristics of IEC 61850 that enable unique advantages are so numerous

that they cannot practically be listed here. Some of these characteristics are seemingly small but

yet can have a tremendous impact on substation automation systems.

For instance, the use of VLANs and priority flags for GOOSE and SMV enable much more

intelligent use of Ethernet switches that in and of itself can deliver significant benefits to users

that arent available with other approaches. For the sake of brevity, we will list here some of the more key features that provide significant benefits to users:

Use of a Virtualized Model The virtualized model of logical devices, logical nodes, ACSI, and CDCs enables definition of

the data, services, and behavior of devices to be defined in addition to the protocols that are used

to define how the data is transmitted over the network.

Use of Names for All Data Every element of IEC 61850 data is named using descriptive strings to describe the data. Legacy

protocols, on the other hand, tend to identify data by storage location and use index numbers,

register numbers and the like to describe data.

All Object Names are Standardized and Defined in a Power System Context The names of the data in the IEC 61850 device are not dictated by the device vendor or

configured by the user. All names are defined in the standard and provided in a power system

context that enables the engineer to immediately identify the meaning of data without having to

define mappings that relate index numbers and register numbers to power system data like

voltage and current.

Devices are Self-Describing Client applications that communicate with IEC 61850 devices are able to download the

description of all the data supported by the device from the device without any manual

configuration of data objects or names.

High-Level Services ACSI supports a wide variety of services that far exceeds what is available in the typical legacy

protocol. GOOSE, GSSE, SMV, and logs are just a few of the unique capabilities of IEC 61850.

Standardized Configuration Language SCL enables the configuration of a device and its role in the power system to be precisely

defined using XML files.

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Major Benefits

The features described above for IEC 61850 deliver substantial benefits to users that understand

and take advantage of them. Rather than simply approaching an IEC 61850 based system in the

same way as any other system, a user that understands and takes advantage of the unique

capabilities will realize significant benefits that are not available using legacy approaches.

Eliminate Procurement Ambiguity

Not only can SCL be used to configure devices and power systems, SCL can also be used to

precisely define user requirement for substations and devices. Using SCL a user can specify

exactly and unambiguously what is expected to be provided in each device that is not subject to

misinterpretation by suppliers.

Lower Installation Cost

IEC 61850 enables devices to quickly exchange data and status using GOOSE and GSSE over

the station LAN without having to wire separate links for each relay. This significantly reduces

wiring costs by more fully utilizing the station LAN bandwidth for these signals and construction

costs by reducing the need for trenching, ducts, conduit, etc.

Lower Transducer Costs

Rather than requiring separate transducers for each device needing a particular signal, a single

merging unit supporting SMV can deliver these signals to many devices using a single transducer

lowering transducer, wiring, calibration, and maintenance costs.

Lower Commissioning Costs

The cost to configure and commission devices is drastically reduced because IEC 61850 devices

dont require as much manual configuration as legacy devices. Client applications no longer need to manually configured for each point they need to access because they can retrieve the points

list directly from the device or import it via an SCL file.

Many applications require nothing more than setting up a network address in order to establish

communications. Most manual configuration is eliminated drastically reducing errors and

rework.

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Lower Equipment Migration Costs

Because IEC 61850 defines more of the externally visible aspects of the devices besides just the

encoding of data on the wire, the cost for equipment migrations is minimized. Behavioral

differences from one brand of device to another is minimized and, in some cases, completely

eliminated.

All devices share the same naming conventions minimizing the reconfiguration of client

applications when those devices are changed.

Lower Extension Costs

Because IEC 61850 devices dont have to be configured to expose data, new extensions are easily added into the substation without having to reconfigure devices to expose data that was

previously not accessed. Adding devices and applications into an existing IEC 61850 system can

be done with only a minimal impact, if any, on any of the existing equipment.

Lower Integration Costs

By utilizing the same networking technology that is being widely used across the utility

enterprise the cost to integrate substation data into the enterprise is substantially reduced. Rather

than installing costly RTUs that have to be manually configured and maintained for each point of

data needed in control center and engineering office application, IEC 61850 networks are

capable of delivering data without separate communications front-ends or reconfiguring devices.

Implement New Capabilities

The advanced services and unique features of IEC 61850 enables new capabilities that are simply

not possible with most legacy protocols. Wide area protection schemes that would normally be

cost prohibitive become much more feasible.

Because devices are already connected to the substation LAN, the incremental cost for accessing

or sharing more device data becomes insignificant enabling new and innovative applications that

would be too costly to produce otherwise.

Conclusions

IEC 61850 is now released to the industry. Ten parts of the standard are now International

Standards (part 10 is a draft international standard). This standard addresses most of the issues

that migration to the digital world entails, especially, standardization of data names, creation of a

comprehensive set of services, implementation over standard protocols and hardware, and

definition of a process bus.

Multi-vendor interoperability has been demonstrated and compliance certification processes are

being established. Discussions are underway to utilize IEC 61850 as the substation to control

center communication protocol. IEC 61850 will become the protocol of choice as utilities

migrate to network solutions for the substations and beyond.

SOURCE: Ralph Mackiewicz SISCO, Inc. Sterling Heights, MI USA

Do Your Substation Devices Speak IEC

61850? They Should, Its Time.

Do Your Substation Devices Speak IEC 61850? They Should, It's Time. (photo by Siemens A.. - Siemens Trkiye)

Overview of IEC 61850

Since being published in 2004, the IEC 61850 communication standard has gained more and

more relevance in the field of substation automation.

It provides an effective response to the needs of the open, deregulated energy market, which

requires both reliable networks and extremely flexible technology flexible enough to adapt to the substation challenges of the next twenty years.

IEC 61850 has not only taken over the drive of the communication technology of the office networking

sector, but it has also adopted the best possible protocols and configurations for high functionality and

reliable data transmission.

Industrial Ethernet, which has been hardened for substation purposes and provides a speed of

100 Mbit/s, offers bandwidth enough to ensure reliable information exchange between IEDs

(Intelligent Electronic Devices), as well as reliable communication from an IED to a substation

controller.

The definition of an effective process bus offers a standardized way to connect conventional as

well as intelligent CTs and VTs to relays digitally.

More than just a protocol, IEC 61850 also provides benefits in the areas of engineering and

maintenance, especially with respect to combining devices from different vendors.

Key features of IEC 61850

As in an actual project, the standard includes parts describing the requirements needed in

substation communication, as well as parts describing the specification itself.

SIPROTEC 5 - IEC 61850 is more than a substation automation protocol. It comprehensively

analyzes data types, functions, and communication in substation networks.

The specification is structured as follows:

An object-oriented and application-specific data model focused on substation automation. This model includes object types representing nearly all existing equipment and functions in a

substation circuit breakers, protection functions, current and voltage transformers, waveform recordings, and many more.

Communication services providing multiple methods for information exchange. These services cover reporting and logging of events, control of switches and functions, polling of data model information.

Peer-to-peer communication for fast data exchange between the feeder level devices (protection devices and bay controller) is supported with GOOSE (Generic Object Oriented Substation Event).

Support of sampled value exchange. File transfer for disturbance recordings. Communication services to connect primary equipment such as instrument transducers to

relays. Decoupling of data model and communication services from specific communication

technologies. This technology independence guarantees long-term stability for the data model and opens up

the possibility to switch over to successor communication technologies. Today, the standard uses Industrial Ethernet with the following significant features: 100 Mbit/s bandwidth Non-blocking switching technology Priority tagging for important messages Time synchronization

A common formal description code, which allows a standardized representation of a systems data model and its links to communication services.

This code, called SCL (Substation Configuration Description Language), covers all communication aspects according to IEC 61850. Based on XML, this code is an ideal electronic interchange format for configuration data.

A standardized conformance test that ensures interoperability between devices. Devices must pass multiple test cases: positive tests for correctly responding to stimulation telegrams, plus several negative tests for ignoring incorrect information

IEC 61850 offers a complete set of specifications covering all communication issues inside a substation

Support of both editions of IEC 61850 and all technical issues.

PLC Application For Speed Control of AC

Motors With Variable Speed (VS) Drive

PLC Application For Speed Control of AC Motors With VSD (on photo: Quadplex panel that

controls four total pumps, two 25HP and two 50HP pumps controlled by corresponding variable

frequency drives with filters. The 460V 3PH 4 wire 300A panel features a PLC based control

system with back up floats and intrinisically safe barriers for level sensors. by D&B Custom

Wiring)

AC Motor Drive Interface

A common PLC application is the speed control of AC motors with variable speed (VS) drives.

The diagram in Figure 1 shows an operator station used to manually control a VS drive.

The programmable controller implementation of this station will provide automatic motor speed

control through an analog interface by varying the analog output voltage (0 to 10 VDC) to the

drive.

The operator station consists of:

1. a speed potentiometer (speed regulator), 2. a forward/reverse direction selector, 3. a run/jog switch, and 4. start and stop push buttons.

The PLC program will contain all of these inputs except the potentiometer, which will be

replaced by an analog output.

The required input field devices (i.e., start push button, stop push button, jog/run, and forward/

reverse) will be added to the application and connected to input modules, rather than using the

operator stations components.

The PLC program will contain the logic to start, stop, and interlock the forward/reverse commands.

Figure 1 - Operator station for a variable speed drive

Table 1 shows the I/O address assignment table for this example, while Figure 2 illustrates the

connection diagram from the PLC to the VS drives terminal block (TB-1). The connection uses a contact output interface to switch the forward/reverse signal, since the common must be

switched.

To activate the drive, terminal TB-1-6 must receive 115 VAC to turn ON the internal relay CR1.

The drive terminal block TB-1-8 supplies power to the PLCs L1 connection to turn the drive ON. The output of the module (CR1) is connected to terminal TB-1-6. The drives 115 VAC signal is used to control the motor speed so that the signal is in the same circuit as the

drive, avoiding the possibility of having different commons (L2) in the drive (the start/stop

common is not the same as the controllers common).

In this configuration, the motors overload contacts are wired to terminals TB-1-9 and TB-1-10, which are the drives power (L1) connection and the output interfaces L1 connection. If an overload occurs, the drive will turn OFF because the drives CR1 contact will not receive power from the output module.

This configuration, however, does not provide low-voltage protection, since the drive and motor will

start immediately after the overloads cool off and reclose.

To have low-voltage protection, the auxiliary contact from the drive, CR1 in terminal TB-1-7,

must be used as an input in the PLC, so that it seals the start/stop circuit.

Table 1 - I/O address assignment

Figure 2 - Connection diagram from the PLC to the VS drives terminal block.

Figure 3 shows the PLC ladder program that will replace the manual operator station. The

forward and reverse inputs are interlocked, so only one of them can be ON at any given time

(i.e., they are mutually exclusive).

If the jog setting is selected, the motor will run at the speed set by the analog output when the

start push button is depressed. The analog output connection simply allows the output to be

enabled when the drive starts. Register 4000 holds the value in counts for the analog output to

the drive. Internal 1000, which is used in the block transfer, indicates the completion of the

instruction.

Sometimes, a VS drive requires the ability to run under automatic or manual control

(AUTO/MAN). Several additional hardwired connections must be made to implement this dual

control.

Figure 3 - PLC implementation of the VS drive

The simplest and least expensive way to do this is with a selector switch (e.g., a four-pole, single-throw,

single-break selector switch). With this switch, the user can select either the automatic or manual

option. Figure 4 illustrates this connection.

Note that the start, stop, run/jog, potentiometer, and forward/reverse field devices shown are

from the operator station. These devices are connected to the PLC interface under the same

names that are used in the control program (refer to Figure 3).

If the AUTO/MAN switch is set to automatic, the PLC will control the drive; if the switch is set

to manual, the manual station will control the drive.

Figure 4 - VS drive with AUTO/MAN capability

Resource: Introduction-to-PLC-Programming www.globalautomation.info

]

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 systems 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)

Figure 1 - DA system architecture

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 todays 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 2025 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

Todays 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

Basic Mechanical Terms used in Drives

Applications

Index

Terms below are the basic mechanical terms associated with the mechanics of DC drive

operation. Many of these terms are familiar to us in some other context.

1. Force 2. Net Force 3. Torque 4. Speed 5. Linear Speed 6. Angular (Rotational) Speed 7. Acceleration 8. Law of Inertia 9. Friction 10. Work 11. Power 12. Horsepower

Force

In simple terms, a force is a push or a pull. Force may be caused by electromagnetism, gravity,

or a combination of physical means. The English unit of measurement for force is pounds (lb).

Go to back to Index

Net Force

Net force is the vector sum of all forces that act on an object, including friction and gravity.

When forces are applied in the same direction they are added. For example, if two 10 lb forces

were applied in the same direction the net force would be 20 lb.

If 10 lb of force were applied in one direction and 5 lb of force applied in the opposite direction,

the net force would be 5 lb and the object would move in the direction of the greater force.

If 10 lb of force were applied equally in both directions, the net force would be zero and the

object would not move.

Go to back to Index

Torque

Torque is a twisting or turning force that tends to cause an object to rotate. A force applied to

the end of a lever, for example, causes a turning effect or torque at the pivot point.

Torque (tau) is the product of force and radius (lever distance).

Torque (tau) = Force x Radius

In the English system torque is measured in pound-feet (lb-ft) or pound-inches (lb-in). If 10 lbs

of force were applied to a lever 1 foot long, for example, there would be 10 lb-ft of torque.

An increase in force or radius would result in a corresponding increase in torque. Increasing the

radius to 2 feet, for example, results in 20 lb-ft of torque.

Go to back to Index

Speed

An object in motion travels a given distance in a given time. Speed is the ratio of the distance

traveled to the time it takes to travel the distance.

Speed = Distance / Time

Linear Speed

The linear speed of an object is a measure of how long it takes the object to get from point A to

point B. Linear speed is usually given in a form such as feet per second (f/s).

For example, if the distance between point A and point B were 10 feet, and it took 2 seconds to

travel the distance, the speed would be 5 f/s.

Go to back to Index

Angular (Rotational) Speed

The angular speed of a rotating object is a measurement of how long it takes a given point on the

object to make one complete revolution from its starting point. Angular speed is generally given

in revolutions per minute (RPM).

An object that makes ten complete revolutions in one minute, for example, has a speed of 10

RPM.

Go to back to Index

Acceleration

An object can change speed. An increase in speed is called acceleration. Acceleration occurs

when there is a change in the force acting upon the object. An object can also change from a

higher to a lower speed.

This is known as deceleration (negative acceleration).

A rotating object, for example, can accelerate from 10 RPM to 20 RPM, or decelerate from 20

RPM to 10 RPM.

Go to back to Index

Law of Inertia

Mechanical systems are subject to the law of inertia. The law of inertia states that an object will

tend to remain in its current state of rest or motion unless acted upon by an external force. This

property of resistance to acceleration /deceleration is referred to as the moment of inertia.

The English system of measurement is pound-feet squared (Ib-ft2).

If we look at a continuous roll of paper, as it unwinds, we know that when the roll is stopped, it

would take a certain amount of force to overcome the inertia of the roll to get it rolling. The force

required to overcome this inertia can come from a source of energy such as a motor.

Once rolling, the paper will continue unwinding until another force acts on it to bring it to a stop.

Go to back to Index

Friction

A large amount of force is applied to overcome the inertia of the system at rest to start it moving.

Because friction removes energy from a mechanical system, a continual force must be applied to

keep an object in motion. The law of inertia is still valid, however, since the force applied is

needed only to compensate for the energy lost.

Once the system is in motion, only the energy required to compensate for various losses need be

applied to keep it in motion.

In the previous illustration, for example: these losses include:

Friction within motor and driven equipment bearings Windage losses in the motor and driven equipment Friction between material on winder and rollers

Go to back to Index

Work

Whenever a force of any kind causes motion, work is accomplished. For example, work is

accomplished when an object on a conveyor is moved from one point to another.

Work is defined by the product of the net force (F) applied and the distance (d) moved. If twice

the force is applied, twice the work is done. If an object moves twice the distance, twice the work

is done.

W = F x d

Go to back to Index

Power

Power is the rate of doing work, or work divided by time.

Power = (Force x Distance) / Time

Power = Work / Time

In other words, power is the amount of work it takes to move the package from one point to

another point, divided by the time.

Go to back to Index

Horsepower

Power can be expressed in foot-pounds per second, but is often expressed in horsepower (HP).

This unit was defined in the 18th century by James Watt. Watt sold steam engines and was asked

how many horses one steam engine would replace.

He had horses walk around a wheel that would lift a weight. He found that each horse would

average about 550 foot-pounds of work per second.

One horsepower is equivalent to 500 foot-pounds per second or 33,000 foot-pounds per

minute.

The following formula can be used to calculate horsepower when torque (lb-ft) and speed (RPM)

are known.

It can be seen from the formula that an increase of torque, speed, or both will cause a

corresponding increase in horsepower.

HP = (Torque x RPM) / 5250

Power in an electrical circuit is measured in watts (W) or kilowatts (kW).

Variable speed drives and motors manufactured in the United States are generally rated in

horsepower (HP); however, it is becoming common practice to rate equipment using the

International System of Units (SI units) of watts and kilowatts.

Go to back to Index

Resource: Basics of DC Drives SIEMENS

Few Words About Frequency Converters

Introduction

Since the late 1960s, frequency converters have undergone extremely rapid changes, largely as a result of the development of microprocessor and semi-conductor technologies and their reduction

in prices. However, the basic principles of frequency converters remains the same.

Frequency converters can be divided into four main components:

Figure 1 - Simplified frequency converter

1. Rectifier

The rectifier, which is connected to a single/three-phase AC mains supply and generates a

pulsating DC voltage. There are two basic types of rectifiers controlled and uncontrolled.

2. Intermediate circuit

The intermediate circuit. There are three types:

1. One, which converts the rectifier voltage into a direct current. 2. One, which stabilises or smoothes the pulsating DC voltage and places it at the disposal of the

inverter. 3. One, which converts the constant DC voltage of the rectifier to a variable AC voltage.

3. Inverter

The inverter which generates the frequency of the motor voltage. Alternatively, some inverters

may also convert the constant DC voltage into a variable AC voltage.

Control circuit

The control circuit electronics, which transmit signals to- and receive signals from the rectifier,

the intermediate circuit and the inverter. The parts that are controlled in detail depends on the

design of the individual frequency converter (see Figure 2).

What all frequency converters have in common is that the control circuit uses signals to switch the

inverter semi-conductors on or off. Frequency converters are divided according to the switching pattern

that controls the supply voltage to the motor.

In figure 2, which shows the different design /control principles:

1. Is a controlled rectifier, 2. Is an uncontrolled rectifier, 3. Is a variable DC intermediate circuit, 4. Is a constant DC voltage intermediate circuit, 5. Is a variable DC intermediate circuit, 6. Is a PAM inverter and 7. PWM inverter.

Figure 2 - Different design / control principles of frequency converter

Current Source Inverter: CSI

(1 + 3 + 6)

Pulse-amplitude-modulated converter: PAM

(1 + 4 + 7) (2 + 5 + 7)

Pulse-width-modulated converter: PWM/VVCplus

(2 + 4 + 7)

Direct converters, which do not have an intermediate circuit should also be briefly mentioned for

completeness. These converters are used in the Mega-watt power range to generate alow-

frequency supply directly from the 50 Hz mains and their maximum output frequency is about

30 Hz.

Resource: Fact Worth Knowing About Frequency Converters Danfoss

How to Select Right Frequency Converter for

Variable Speed Drive (VSD)?

Application: Brackish water - 3 APP 2,2 equiped with Danfoss inverters for flexible use at

universety. Place of installation: UK

Selecting of a frequency converter for variable speed drives requires a lot of experience. If the

experience is not available, it is often useful to visit either a reference plant with similar

applications, or exhibitions or trade shows.

Checklist

The following is a brief checklist of points that should be considered:

1. Details of the machine to be controlled 2. Environmental details 3. Mains 4. Maintenance, operation, personnel 5. Financial criteria 6. Protective measures for operators/converter/motor 7. Standards/regulations 8. Environmental considerations 9. Also important

VLT Drives Applications (VIDEOS)

Some of the interesting applications done with Danfoss VLT drives:

1. VLT drives in large desalination plant 2. VLT drives control cooling tower fans 3. VLT control optimizes spindle speed in Indian textile factory 4. VLT frequency converters drive bagage handling system 5. VLT Drives Save 78% Energy in Chester Zoo

1. Details of the machine to be controlled

1. Required plant/machine characteristics 2. Torque characteristics, stalling torque, acceleration torque 3. Speed control range, cooling 4. Power consumption of the converter and the motor 5. Operating quadrants 6. Slip compensation (dynamic) 7. Required ramp-up and ramp-down times 8. Required braking times, brake operating time 9. Direct drives, gears, transmission components, moment of mass inertia 10. Synchronisation with other drives 11. Operating time, controls 12. Computer linkage, interfaces, visualisation 13. Design and protection type 14. Possibility of integrating decentral intelligence in the frequency converter

2. Environmental details

1. Installation height, ambient temperature 2. Cooling requirements, cooling options

3. Climatic conditions, such as humidity, water, dirt, dust, gas-es 4. Special regulations, e.g. for mining, the chemical industry, the ship building industry, food

technology 5. Acoustic noise

3. Mains

1. Mains voltage, voltage fluctuations 2. Mains performance 3. Mains frequency fluctuations 4. Mains interference 5. Short-circuit and overvoltage protection 6. Mains drop-out

4. Maintenance, operation, personnel

1. Training and instruction of operators 2. Maintenance 3. Spare parts/spare units

5. Financial criteria

1. Purchase costs (components) 2. Space requirement, integrated installation, design 3. Installation costs 4. Commissioning of the system 5. Set-up costs 6. Operating costs 7. Efficiency of the system (frequency converter and machine) 8. Reactive power requirement and compensation for harmonic loads 9. Product lifetime

6. Protective measures for operators/converter/motor

1. Galvanic isolation in accordance with PELV 2. Phase drop-out 3. Switching at the converter output 4. Earth and short-circuit protection 5. Motor coils to reduce voltage rise times 6. Electronic thermal monitoring and connection of thermistors

7. Standards/regulations

1. National DIN, BS, UL, CSA, VDE, European EN 2. International IEC, CE, etc.

8. Environmental considerations

1. Ability to recycle the product 2. Manufacturing practice 3. Energy saving factors

Also important

Using this checklist a frequency converter can be selected which covers most of the items as

standard, but you should also double check whether:

The converter has mains or intermediate circuit chokes in order to greatly reduce mains interference

A RFI filter for class A or B is standard or has to be purchased separately Motor derating is required if a frequency converter is used The converter itself is protected against earth and short-circuit The converter reacts adequately in a fault situation.

VLT Drives Applications (VIDEOS)

1. VLT drives in large desalination plant

Cant see this video? Click here to watch it on Youtube.

2. VLT drives control cooling tower fans

Cant see this video? Click here to watch it on Youtube.

3. VLT control optimizes spindle speed in Indian textile factory

Cant see this video? Click here to watch it on Youtube.

4. LT frequency converters drive bagage handling system

Cant see this video? Click here to watch it on Youtube.

5. LT Drives Save 78% Energy in Chester Zoo

Cant see this video? Click here to watch it on Youtube.

Resource: Fact Worth Knowing About Frequency Converters Danfoss

Surge Protection for Frequency Converters

Figure 1 - Schematic diagram of a frequency converter

In principle a frequency converter consists of a rectifier, a d.c. link converter, an inverter and of

the control electronics (Figure 1 above).

At the input of the inverter the single phase or interlinked, three-phase a.c. voltage is

changed into a pulsating d.c. voltage and is pushed into the d.c. link converter that also serves as

energy store (buffer). Capacitors in the d.c. link converter and the LC networks connected to

earth in the a.c. line filter, can cause problems with the residual current devices (RCD)

connected in series.

The reason for this is often wrongly seen in the application of surge arresters.

The problems, however, result from the short-term induction of fault currents by the frequency

converter. These are sufficient to activate sensitive earth leakage circuit breakers (RCDs).

A surge-proof RCD circuit breaker available for a tripping current In = 30 mA and a min.

discharge capability of 3 kA (8/20 s) provides a remedy.

Figure 2 - EMC conforming shield connection of the motor supply line

By the control electronics, the inverter delivers a clocked output voltage. The higher the clock

frequency of the control electronics for the pulse-width-modulation, the more sinusoidal is the

output voltage. With each cycle, a peak voltage is created that is superimposed on the curve of

the fundamental frequency. This peak voltage reaches values of 1200 V and higher (according to

the frequency converter).

The better the simulation of the sine curve at the output, the better is the performance and control

response of the motor. This means, however, that the voltage peaks appear at the output of the

frequency converter more frequently.

For choosing of surge arresters, the maximum continuous operating voltage Uc has to be taken

into account.

It specifies the maximum permissible operating voltage a surge protective device may be

connected to. This means that surge protective devices with a correspondingly higher Uc are

used at the output side of the frequency converter.

This avoids faster ageing due to gradually heating of the surge protective device under normal

operating conditions and the consequential voltage peaks. This heating of the arrester leads to a

shorter service life and consequently to a disconnection of the surge protective device from the

system to be protected.

The voltage at the output of the frequency converter is variable and adjusted a little bit

higher than the nominal voltage at the input. Often it is approx. + 5 % during continuous

operation, in order to compensate the voltage drop at the connected line, for example.

Figure 3 - Structure of a frequency converter with SPD

Example with Dehn devices

1 - DEHNguard S DG S 275

2 DEHNguard S DG S 600 3 BLITZDUCTOR XT

Otherwise, one can simply say that the maximum voltage at the input of the frequency converter

is equal to the maximum voltage at the output of the frequency converter.

The high clock frequency at the output of the frequency converter generates fieldborne

interferences and therefore, requires necessarily a shielded cabling so that adjacent systems are

not disturbed.

For shielding the motor power supply line, a bilateral shield earthing at the frequency

converter and the drive motor has to be ensured. The large-surface contacting of the shield

results from the EMC requirements.

Advantageous is here the use of constant force springs (Figure 2).

By means of intermeshed earth-termination systems, i.e. the earth-termination system the

frequency converters and the drive motor are connected to, potential differences are reduced

between the parts of the installation and thus equalising currents via the shield are avoided.

Figure 3 shows the example of use of surge protective devices Type DEHNguard on the power

supply side and type BLITZDUCTOR for 0 20 mA signals. The protective devices have to be individually adapted according to the interface.

For the integration of the frequency converter into the building automation it is absolutely

essential that all evaluation and communication interfaces are connected with surge protective

devices in order to avoid system failures.

Resource: Lightning-Protection-Guide dehn.de

Basic Steps In PLC Programming

The first step in developing a control program is the definition of the control task. The control

task specifies what needs to be done and is defined by those who are involved in the operation of

the machine or process. The second step in control program development is to determine a

control strategy, the sequence of processing steps that must occur within a program to produce

the desired output control.

This is also known as the development of an algorithm.

A set of guidelines should be followed during program organization and implementation in order

to develop an organized system.

Approach guidelines apply to two major types of projects: new applications and modernizations

of existing equipment.

Flow charting can be used to plan a program after a written description has been developed. A

flowchart is a pictorial representation of the process that records, analyzes, and communicates

information, as well as defines the sequence of the process.

Logic gates or contact symbology are used to implement the logic sequences in a control

program. Inputs and outputs marked with an X on a logic gate diagram represent real I/O.

Three important documents that provide information about the arrangement of the PLC system are the

I/O assignment table, the internal address assignment table, and the register address assignment

table.

1. The I/O assignment table documents the names, locations, and descriptions of the real inputs and outputs.

2. The internal address assignment table records the locations and descriptions of internal outputs, registers, timers, counters, and MCRs.

3. The register address assignment tablelists all of the available PLC registers.

Certain parts of the system should be left hardwired for safety reasons. Elements such as emergency

stops and master start push buttons should be left hardwired so that the system can be disabled

without PLC intervention.

Special cases of input device programming include the program translation of normally closed

input devices, fenced MCR circuits, circuits that allow bidirectional power flow, instantaneous

timer contacts, and complicated logic rungs.

The programming of contacts as normally open or normally closed depends on how they are required to operate in the logic program. In most cases, if a normally closed input device is required to act as a normally closed input, its reference address is programmed as normally open.

Master control relays turn ON and OFF power to certain logic rungs. In a PLC program, an END MCR instruction must be placed after the last rung an MCR will control.

PLCs do not allow bidirectional power flow, so all PLC rungs must be programmed to operate only in a forward path.

PLCs do not provide instantaneous contacts; therefore, an internal output must be used to trap a timer that requires these contacts.

Complicated logic rungs should be isolated from the other rungs during programming.

Program coding is the process of translating a logic or relay diagram into PLC ladder program form.

The benefits of modernizing a relay control system include greater reliability, less energy

consumption, less space utilization, and greater flexibility.

Example Of Simple Start/Stop Motor Circuit

Figure 1 shows the wiring diagram for a three-phase motor and its corresponding three-wire

control circuit, where the auxiliary contacts of the starter seal the start push button. To convert

this circuit into a PLC program, first determine which control devices will be part of the PLC

I/O system; these are the circled items in Figure 2. In this circuit, the start and stop push

buttons (inputs) and the starter coil (output) will be part of the PLC system.

The starter coils auxiliary contacts will not be part of the system because an internal will be used to seal the coil, resulting in less wiring and fewer connections.

Figure 1a - Wiring diagram of three phase motor

Figure 1b - Relay control circuit for a three-phase motor

Figure 2 - Real inputs and outputs to the PLC

Table 1 shows the I/O address assignment, which uses the same addressing scheme as the

circuit diagram (i.e., inputs: addresses 000 and 001, output: address 030).

I/O Address

Module Type Rack Group Terminal Description

Input

0 0 0 Stop PB (NC)

0 0 1 Start PB

0 0 2 -

0 0 3 -

Output 0 3 0 Motor M1

0 3 1 -

0 3 2 -

0 3 3 -

To program the PLC, the devices must be programmed in the same logic sequence as they are in

the hardwired circuit (see Figure 3). Therefore, the stop push button will be programmed as an

examine-ON instruction (a normally open PLC contact) in series with the start push button,

which is also programmed as an examine-ON instruction.

This circuit will drive output 030, which controls the starter.

Figure 3 - PLC implementation of the circuit in Figure 1

If the start push button is pressed, output 030 will turn ON, sealing the start push button and

turning the motor ON through the starter. If the stop push button is pressed, the motor will turn

OFF.

Note that the stop push button is wired as normally closed to the input module. Also, the starter

coils overloads are wired in series with the coil.

Resource: Introduction to PLC Programming and Implementationfrom relay logic to PLC logic

DC Motor Drive Explained In Few Words

Figure 1 - Control loop of a DC Motor Drive (ABB)

In a DC motor, the magnetic field is created by the current through the field winding in the

stator. This field is always at right angles to the field created by the armature winding. This

condition, known as field orientation, is needed to generate maximum torque. The commutator-

brush assembly ensures this condition is maintained regardless of the rotor position.

Once field orientation is achieved, the DC motors torque is easily controlled by varying the armature current and by keeping the magnetising current constant.

The advantage of DC drives is that speed and torque the two main concerns of the end-user are controlled directly through armature current: that is the torque is the inner control loop and

the speed is the outer control loop (see Figure 1).

Features of DC Motor Drive

1. Field orientation via mechanical commutator 2. Controlling variables are Armature Current and Field Current, measured DIRECTLY from the

motor 3. Torque control is direct

Advantages of DC Motor Drive

1. Accurate and fast torque control

2. High dynamic speed response 3. Simple to control

Initially, DC drives were used for variable speed control because they could easily achieve a

good torque and speed response with high accuracy.

A DC machine is able to produce a torque that is:

Direct the motor torque is proportional to the armature current: the torque can thus be controlled directly and accurately.

Rapid- torque control is fast; the drive system can have a very high dynamic speed response. Torque can be changed instantaneously if the motor is fed from an ideal current source. A voltage fed drive still has a fast response, since this is determined only by the rotors electrical time constant (i.e. the total inductance and resistance in the armature circuit)

Simple field orientation is achieved using a simple mechanical device called a commutator/brush assembly. Hence, there is no need for complex electronic control circuitry, which would increase the cost of the motor controller.

Drawbacks

1. Reduced motor reliability 2. Regular maintenance 3. Motor costly to purchase 4. Needs encoder for feedback

The main drawback of this technique is the reduced reliability of the DC motor; the fact that

brushes and commutators wear down and need regular servicing; that DC motors can be costly to

purchase; and that they require encoders for speed and position feedback.

While a DC drive produces an easily controlled torque from zero to base speed and beyond, the

motors mechanics are more complex and require regular maintenance.

Resource: ABB Technical Guide Direct Torque Control

Using MODBUS for Process Control and

Automation (1)

The Schneider Electric Modicon Quantum is a versatile PLC used in a wide variety of sectors

including manufacturing, water/wastewater, oil and gas, chemical and more.

Advertisement

MODBUS is the most popular industrial protocol being used today, for good reasons. It is

simple, inexpensive, universal and easy to use. Even though MODBUS has been around since

the past century nearly 30 years, almost all major industrial instrumentation and automation

equipment vendors continue to support it in new products.

Although new analyzers, flowmeters and PLCs may have a wireless, Ethernet or fieldbus

interface, MODBUS is still the protocol that most vendors choose to implement in new and old

devices.

Another advantage of MODBUS is that it can run over virtually all communication media,

including twisted pair wires, wireless, fiber optics, Ethernet, telephone modems, cell phones and

microwave. This means that a MODBUS connection can be established in a new or existing

plant fairly easily. In fact, one growing application for MODBUS is providing digital

communications in older plants, using existing twisted pair wiring.

In this white paper, well examine how MODBUS works and look at a few clever ways that MODBUS can be used in new and legacy plants.

What is MODBUS?

MODBUS was developed by Modicon (now Schneider Electric) in 1979 as a means for

communicating with many devices over a single twisted pair wire. The original scheme ran over

RS232, but was adapted to run on RS485 to gain faster speed, longer distances and a true multi-

drop network. MODBUS quickly became a de facto standard in the automation industry, and

Modicon released it to the public as a royalty free protocol.

Today, MODBUS-IDA (www.MODBUS.org), the largest organized group of MODBUS users

and vendors, continues to support the MODBUS protocol worldwide. MODBUS is a master-slave system, where the master communicates with one or multiple slaves. The master typically is a PLC (Programmable Logic Controller), PC, DCS (Distributed Control System) or

RTU (Remote Terminal Unit).

MODBUS RTU slaves are often field devices, all of which connect to the network in a multidrop

configuration, Figure 1.

When a MODBUS RTU master wants information from a device, the master sends a message

that contains the devices address, data it wants, and a checksum for error detection. Every other device on the network sees the message, but only the device that is addressed responds.

Figure 1. A MODBUS RTU network consists of one master, such as a PLC or DCS, and up to 247 slave devices connected in a multi-drop configuration

Slave devices on MODBUS networks cannot initiate communication; they can only respond. In

other words, they speak only when spoken to. Some manufacturers are developing hybrid devices that act as MODBUS slaves, but also have write capability, thus making them pseudo-Masters at times.

The three most common MODBUS versions used today are:

1. MODBUS ASCII 2. MODBUS RTU 3. MODBUS/TCP

All MODBUS messages are sent in the same format. The only difference among the three

MODBUS types is in how the messages are coded.

In MODBUS ASCII, all messages are coded in hexadecimal, using 4-bit ASCII characters. For

every byte of information, two communication bytes are needed, twice as many as with

MODBUS RTU or MODBUS/TCP. Therefore, MODBUS ASCII is the slowest of the three

protocols, but is suitable when telephone modem or radio (RF) links are used. This is because

ASCII uses characters to delimit a message. Because of this delimiting of the message, any

delays in the transmission medium will not cause the message to be misinterpreted by the

receiving device. This can be important when dealing with

slow modems, cell phones, noisy connections, or other difficult transmission mediums.

In MODBUS RTU, data is coded in binary, and requires only one communication byte per data

byte. This is ideal for use over RS232 or multi-drop RS485 networks, at speeds from 1,200 to

115Kbaud. The most common speeds are 9,600 and 19,200 baud. MODBUS RTU is the most

widely used industrial protocol, so most of this paper will focus on MODBUS RTU basics and

application considerations.

MODBUS/TCP is simply MODBUS over Ethernet. Instead of using device addresses to

communicate with slave devices, IP addresses are used. With MODBUS/TCP, the MODBUS

data is simply encapsulated inside a TCP/IP packet. Hence, any Ethernet network that supports

TCP/IP should immediately support MODBUS/TCP.

More details regarding this version of MODBUS will be covered in a later section entitled

MODBUS Over Ethernet.

To be continued

Resource: Using MODBUS for Process Control and Automation Moore Industries

Using MODBUS for Process Control and

Automation (2)

The Schneider Electric Modicon Quantum is a versatile PLC

Continued from first part of article Using MODBUS for Process Control and Automation (1)

MODBUS RTU Basics To communicate with a slave device, the master sends a message containing:

Device Address

Function Code

Data

Error Check

The Device Address is a number from 0 to 247. Messages sent to address 0 (broadcast messages)

can be accepted by all slaves, but numbers 1-247 are addresses of specific devices. With the

exception of broadcast messages, a slave device always responds to a MODBUS message so the

master knows the message was received.

Figure 2 Function Codes

Command Function Code

01 Read Coils

02 Read Discrete Inputs

03 Read Holding Registers

04 Read Input Registers

05 Write Single Coil

06 Write Single Register

07 Read Exception Status

08 Diagnostics

.

xx Up to 255 function codes, depending on the device

The Function Code defines the command that the slave device is to execute, such as read data,

accept data, report status, etc. (Figure 2). Function codes are 1 to 255. Some function codes have

sub-function codes.

The Data defines addresses in the devices memory map for read functions, contains data values to be written into the devices memory, or contains other information needed to carry out the function requested. The Error Check is a 16-bit numeric value representing the Cyclic

Redundancy Check (CRC). The CRC is generated by the master (via a complex procedure

involving ORing and shifting data) and checked by the receiving device. If the CRC values do

not match, the device asks for a retransmission of the message. In some systems, a parity check

can also be applied.

When the slave device performs the requested function, it sends a message back to the master.

The returning message contains the slaves address and requested function code (so the master knows who is responding), the data requested, and an Error Check value.

MODBUS Memory Map

Each MODBUS device has memory, where process variable data is stored. The MODBUS

specification dictates how data is retrieved and what type of data can be retrieved. However, it

does not place a limitation on how and where the device vendor maps this data in its memory

map.

Below would be a common example of how a vendor might logically map different types of

process variable data. Discrete inputs and coils are one-bit values, and each has a specific

address. Analog inputs (also called Input Registers) are stored in 16-bit registers. By utilizing two of these registers MODBUS can support the IEEE 32-bit floating point format. Holding

Registers are also 16-bit internal registers that can support floating point.

Figure 3

The literature or operation manuals of most MODBUS compatible devices, such as this TMZ

Temperature Transmitter from Moore Industries, publish the addresses of key variables in the

MODBUS Memory Map. The TMZs addresses conform to the MODBUS spec.

Table Addresses Type Table Name

1-9999 Read or Write Coils

10001-19999 Read Only Discrete Inputs

30001-39999 Read Only Input Registers

40001-49999 Read or Write Holding Registers

Data in the memory map is defined in the MODBUS specification. Assuming that the device

vendor followed the MODBUS specification (not all do), all data can easily be accessed by the

MODBUS master, which follows the specification. In many cases, the device vendor publishes

the memory locations (Figure 3), making it easy for the person programming the master to

communicate with the slave device.

Reading and Writing Data

MODBUS has up to 255 function codes, but 01 (read coils), 02 (read discrete inputs), 03 (read

holding registers) and 04 (read input registers) are the most commonly used read functions that

are used to collect data from MODBUS slaves. For example, to read three 16-bit words of analog

data from device 5s memory map, the master sends a command that looks something like this:

5 04 2 3 CRC

Where 5 is the device address, 04 says to read input registers, 2 is the starting address (address

30,002), 3 means to read three contiguous data values starting at address 30,002, and CRC is the

error check value for this message.

The slave device, upon receiving this command, sends back a response that looks something like

this:

5 04 aa bb cc CRC

Where 5 is the devices address; 04 is the repeated read command; aa, bb and cc are the three 16-bit data values; and CRC is the error check value for this message.

Reading and writing digital inputs and outputs is done in a similar manner using different read

and write functions.

Assuming that the device follows the MODBUS specification, it is a simple programming task to

set up the master to read and write data, check status, obtain diagnostic information and perform

various control and monitoring functions.

Connecting MODBUS Devices

One of the easiest ways to bring field devices into a process control system, PLC or industrial

computer is to simply connect digital and analog I/O into a distributed I/O system that has

MODBUS communication capability.

For example, the NCS (NET Concentrator System) from Moore Industries allows a user to

connect analog and digital signals remotely, which can then be connected to a MODBUS master

via twisted pair cable.

Multiple NCS systems can be installed in several locations throughout the plant, all linked by

MODBUS (Figure 4).

Figure 4 - Home Run Wiring vs MODBUS

Figure 4 In most plants, field instruments connect to the control system with individual home

run twisted pairs (below). When the instruments are wired into a distributed I/O system, such as the

NCS from Moore Industries (center), more devices can be added, but only a single twisted pair is needed

to transmit all the data to the MODBUS master. Multiple NCS systems can be networked (bottom) over

the same MODBUS network, so the entire plant can be converted from home run wiring to MODBUS.

This solution works for both new and existing plants. In many existing plants, field instruments

typically connect to the DCS or PLC via home run wiring, where each device is connected with individual twisted pairs that carry analog signals. With the NCS, one of those twisted pairs

can be used for the MODBUS signal. This is particularly useful if the plant wants to add

additional field instruments, but does not want to run more wiring (at an installed cost of $100

per foot). A distributed I/O system can accommodate all of the existing I/O, or it can be used just

to send data from all the new field instruments.

In some cases, the control system is not able to deal with a MODBUS signal. It may be that the

legacy control system is accustomed to dealing with 4-20mA analog I/O and directly wired

digital I/O, and reprogramming the old system to accommodate MODBUS data would be

difficult. Often, users would like to add new remote signals to their system without having to run

wire or buy expensive MODBUS interface cards that require extensive re-programming. In that

case, a peer-to-peer solution works best.

For example, the CCS (Cable Concentrator System) and the NCS (NET Concentrator System)

from Moore Industries both have peer-to-peer communication abilities. The NCS and CCS are

similar to a distributed I/O module, but have more built-in intelligence and can be set up in either

a peer-to-peer or peer-to-host configuration.

Figure 5 - Peer-to-Peer Wiring

Figure 5 - In some cases, the control system is not able to deal with a MODBUS signal. In that

case, a peer-to peer solution with two NCS systems simply replaces all the home run wiring with

a single MODBUS cable. Analog outputs from the control room NCS are then wired directly into

the host systems I/O card.

With a peer-to-peer NCS system (Figure 5), two concentrators are used: one in the field and one

in the control room. Field instruments connect to the remote NCS, which connects to the control

room NCS via a single twisted pair wire. Then, outputs from the control room NCS are wired

into the control systems existing analog I/O panel. In this way, the analog signals from the new field transmitters can be seen in their original analog state through the plants existing analog I/O cards. This makes programming and commissioning of the new signals less difficult than

programming new digital interface cards.

These peer-to-peer solutions can also accommodate bi-directional communication in which both

sides of the system can have inputs and outputs.

To be continued

Resource: Using MODBUS for Process Control and Automation Moore Industries

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