POWER MANAGEMENT SYSTEM IN BPCL full report
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POWER MANAGEMENT SYSTEM IN BPCL - KR

ABSTRACT
For the protection of power system, relays are used. Different types of relays include electromechanical, static and numeric relays. In an automated system numerical relay has a vital role. The project and implimentation based on substation automation has been named as Power Management System.
Supervisory control and data acquisition (SCADA) allows a utility operator to monitor and control processes that are distributed among various remote sites. SCADA systems include hardware and software components. The hardware gathers and feeds data into a computer that has SCADA software installed. The computer then processes this data and presents it in a timely manner. SCADA also records and logs all events into a file stored on a hard disk or sends them to a printer. SCADA warns when conditions become hazardous by sounding alarms.
Power Management System is a system which presents all network data to an operator to allow safe and reliable operation to control the complete network from a Central Control room through various plant overviews. BPCL - KR already has three substations automated using SCADA system. The objective of this project and implimentation is to conduct a detailed study on this existing system and extend this to other substations.


PROJECT REPORT
Submitted by
JAIN KURIAKOSE RESHMA S JASIL BABU

OVERVIEW
BPCL - KR AT A GLANCE
INTRODUCTION
FAULTS IN POWER SYSTEM
< NEED FOR PROTECTIVE SYSTEMS
INTRODUCTION TO PROTECTIVE RELAYS
INTRODUCTION TO SCADA
NEED OF PMS IN BPCL - KR
COMPONENTS OF PMS
SIPROTEC PROTECTIVE RELAYS
CONCLUSION
REFERENCES
BPCL KOCHI REFINERIES
AMBALAMUGAL, ERNAKULAM
BPCL Kochi Refineries, formerly known as Cochin Refineries Limited is a public sector enterprise which came into being as a result of a three party agreement among the Government of India. Philips Petroleum Company of the United States of America and [the Duncan Brothers of Calcutta.
Bharat Petroleum Corporation Ltd acquired the Govt*s share in KRL in March loo 1. With this KRL became a subsidiary of BPCL. In 2005 KRL modified its DHDS and FCCU unit to meet the EURO specifications. In 2006, Jan, BPCL and KRL approved Rie merge of KRL with BPCL.
Milestones of growth
Year Development
* 1966 Unit commissioned with Crude Oil Refining capacity
of 2.5 MMPTA
f 1973
Capacity expanded from 2.5 to 3.3 MMPTA
r 1984
Capacity expanded from 3.3 to 4.5 MMPTA
f 1989
Aromatic production commenced
* 1990
Captive power plant (26.3 MW) commissioned
L
1994 Capacity expanded to 7.5 MMPTA
1998 Steam turbine generator (17.8) commissioned
1999 DHDS commissioned
2000 Company renamed as Kochi Refineries Limited
Products of BPCL - KR
¢ Natural rubber modified Bitumen (Rubberized Bitumen) NRMB
¢ Liquefied Petroleum Gas & Kerosene for households and industrial uses
¢ Petrol & Diesel for automobiles
¢ Naphtha, the major raw material for fertilizer and petrochemical industries
¢ Benzene for manufacture of caprolactum, phenol, insecticides and other chemicals
¢ Furnace oil and low sulphur heavy stock for fuel in industries
¢ Aviation turbine fuel (ATF) for aircrafts
¢ Special boiling point spirit used as a solvent in tyre industry
¢ Toluene for the manufacture of solvents and insecticides, pharmaceuticals & paints
¢ MTO (Textile grade) and MTO (Paint grade) for use in textile and paint industry
¢ Poly isobutene for the manufacture of lubricants
¢ Sulphur for use in fertilizer, sugar, chemical and tyre industry
fCaptive Power Plant (CPP)
A captive power plant of 26.3 MW was commissioned in 1991. An additional aptive power plant of 17.8 MW was commissioned in 1998.
Captive Power Plant (CPP) is the heart of BPCL - KR. It has a gas turbine generator (GTG) and a steam turbine generator (STG) which caters the electrical load of retire refinery. The captive power plant generates about 7 lakhs units of electrical energy pn an average day in which the contribution of GTG is about 65% and STG about 30%. The remaining 5% is contributed by TG, which generates at 3.3KV level. BPCL - KR also have 66KV feeders for KSEB substations, which are normally kept as emergency stand of source central maximum demand of 20 MVA. The 66KV feeder's line 1 and line I are tapped from (Kalamassery-Vytla) No. 1 feeder and (Kalamassery-Vytla) No.2 feeder [respectively. The 66KV/11KV transformer TR-1 & TR-2 primary windings (66KV side) are kept energized always, synchronizing with state grid. This is done to draw power [when required.
Power is distributed to plants through XLPE cables both buried underground and In GRP trays. Primary process substation, FCCU substation, CDU-I substation, ACTP Substation, CPP offsite substation and PIBU substation receive 11KV supply directly rom CPP. The electrical system in BPCL - KR also consists of about 80 transformers.
FAULTS IN POWER SYSTEM
Fault occurs when two or more conductors that normally operate with potential Rifference coming in contact with each other. These faults may be caused by sudden failure of piece of equipment, accidental damage or short circuit to overhead lines, or by msulation failure resulting from lightning surges. The faults generally occurring in a j lower system are
t)ver Current : It occurs mainly due to short circuit / leakage due to corona effect and Imetimes due to overload on the supply system.
Lnder Voltage : It occurs either on short circuits because of more voltage drop in lines and machines or on failure of alternators field.
Unbalance : It occurs either on grounding of one or two phases or on short circuit of two phases or breaking of one of the conductors. In such cases different current flow through different phases and fault is known as unbalanced fault.
Reversed Power : This fault occurs only in inter - connected systems. A generator, on failure of its field starts working as a motor takes power instead of delivering power ie. lie flow of power is reversed. Similarly in case of feeders connected in parallel, whenever some fault occurs on any one of the feeders, the fault is fed from both ends ie. again direction of How of power in faulty feeder is reversed.
Surges : Whenever lightning takes place or severe fault occurs in the neighbouring circuits, some short lived waves of very high voltage and current are set up in lines. Such fault is known as surge and it may be considered as high voltage of very high frequency.
Effects of faults
Heavy short circuit current may cause damage to equipment or any other element of the system due to over heating and high mechanical forces set up due to heavy current.
Arcs associated with short circuit, may destroy the faulty element of the system. There is also a possibility of the fire spreading to other parts of the system if the fault is not isolated quickly.
There may be reduction in the supply voltage of the healthy feeders , resulting in the loss of industrial loads.
Short circuits may cause the unbalancing of supply voltages and currents. There may be a loss of system stability.
The above faults may cause an interruption of supply to consumers.
Zones of protection
A power system contains generators, transformers, bus bars, transmission and listribution lines etc. There is a separate protective scheme for each element of the power System such as generator protection, transformer protection, bus bar protection etc. Thus a power system is divided into number of zones for protection. If a fault occurs in a particular zone, it is the duty of relays of that zone to isolate the faulty element.

NEED FOR PROTECTIVE SYSTEM
An electrical power system consists of generators, transformers , transmission and Bistribution lines etc. Short circuit and other abnormal condition often occur on a power ystem. The heavy current associated with short circuits is likely to cause damage to ;quipment if suitable protective relays and circuit breakers are not provided for protection J»f each section of power fault means defect. Some defects other than short circuit are also rmed as faults. For example the failure of conducting path due to a break in a conductor [is a type of fault.
If fault occurs in an element of a power system, an automatic protective device is ceded to isolate the faulty element as possible to keep the healthy section of the system h normal operation. The fault must be cleared in a fraction of second. If a short circuit Persists on a system for a long period, it may cause damage to some impedance section of jhe power system. A heavy short circuit may cause a fire. It may spread in the system and amage a part of it. The system voltage may reduce to allow level and individual nerators in a power station or group of generators in different power stations may loss |ynchronism. Thus an uncleared heavy short circuit may cause the total failure of system.
Protection is needed not only against Short Circuit but also against any other Ebnormal conditions, which may arrive on a Power System. A few example of other pbnormal conditions are over speed of generators and motors, over - voltage, under -requency, loss of excitation, overheating of stator and rotor of an alternator etc. protective relays are also provided to detect such abnormal condition and issue alarm [signals to alert operations or trip circuit breaker.
Inspects of Protection system
[Dependability/Reliability
¢ Protection must operate when required
¢ Failure to operate can be extremely damaging and disruptive
¢ Faults are rare: Protection must operate even after years of inactivity
¢ Improved by use of back up protection and duplicate protection
Security/Stability
Protection must not operate when not required to e.g., due to
¢ Load Switching
¢ Faults on other parts of the system
¢ Recoverable process swings
Lpeed
Fast operation
¢ Minimizes damage and danger
¢ Minimizes system instability
¢ Discrimination and security can be costly to achieve as it generally involves additional signaling/communication equipment
Cost
The cost of protection is equivalent to an insurance policy against damage to plant, and loss of supply and customer goodwill.
Acceptable cost is based on a balance of economics and technical factors. Cost of protection should be balanced against cost of potential hazards. There is an economic limit on what we can spent.
J
PROTECTIVE RELAYS
A relay is an automatic device by means of which an electric circuit is indirectly bntrolled and is governed by a change in the same or another electrical circuit. It detects n abnormal condition in an electrical circuit and causes a circuit breaker to isolate the ulty element of the system. In some cases, it may give an alarm or visible indication to lien the operator.
IT he Function of Protective Relaying
The function of protective relaying is to cause the prompt removal from service of y element of a power system when it suffers a short circuit, or when it starts to operate any abnormal manner that might cause damage or otherwise interfere with the jfective operation of the rest of the system. The relaying equipment is aided in this task circuit breakers that are capable of disconnecting the faulty element when they are lied upon to do so by the relaying equipment.
Circuit breakers are generally located so that each generator, transformer, bus, [ransmission line, etc. can be completely disconnected from the rest of the system. These frcuit breakers must have sufficient capacity so that they can cany momentarily the aximum short-circuit current that can flow through them, and then interrupt this Irrent; they must also withstand closing in on such a short circuit and then intemipting it Recording to certain prescribed standards.
Although the principal function of protective relaying is to mitigate the effects of hort circuits, other abnormal operating conditions arise that also require the services of fcrotective relaying. This is particularly true of generators and motors.
¦ A secondary function of protective relaying is to provide indication of the location Snd type of failure. Such data not only assist in expediting repair but also, by comparison ^ith human observation and automatic oscillograph records, they provide means for lalyzing the effectiveness of the fault-prevention and mitigation features including the Protective relaying itself.
Automatic Reclosing
About 90% of faults on over head lines are of transient nature. Transient faults are [aused by lightening or external bodies falling on the lines. Such faults are always associated with arcs. If the line is disconnected with the system for a time the arc is extinguished and the fault disappears. Immediately after this the circuit breaker can be reclosed automatically to restore the supply.
Most faults on EHV lines are caused by lightening. Flashover across insulators takes place due to over voltage caused by lightening and short time. Hence only one instantaneous reclosure is used in the case of EHV lines. There is no need for more than one reclosure for such a situation. For EHV lines one reclosure is 12 cycles is recommended. A fast reclosure is desired from the stability point of view. Statistical reports show that over 80% faults are cleared after the first reclosure, 10% requires the jecond reclosure and 2% need the third reclosure, while the remaining 8% are permanent Faults. If the fault is not cleared after three reclosures it indicates that the fault is of permanent nature. Automatic reclosure are not used on cables as the breakdown of insulation cables causes a permanent fault.
Back - up Relaying
Back-up relaying is employed only for protection against short circuits. Because |hort circuits are the preponderant type of power failure, there are more opportunities for ailure in short primary relaying. Experience has shown that back-up relaying for other I than short circuits is not economically justifiable.
Primary relaying may fail because of failure in any of the following: Current or voltage supply to the relays. DC tripping-voltage supply. Protective relays.
Tripping circuit or breaker mechanism. Circuit breaker.
It is highly desirable that back-up relaying be arranged so that anything that might Pause primary relaying to fail will not also cause failure of back-up relaying. A second function of back-up relaying is often to provide primary protection when the primary-laying equipment is out of service for maintenance or repair. It must operate with
E
fficient time delay so that primary relaying will be given enough time to function if it is Fie to.
When primary relaying fails, even though back-up relaying functions properly, lie service will generally suffer more or less. Consequently, back-up relaying is not a Sroper substitute for good maintenance.
Uixiliary Relays : Auxiliary relays assist protective relays. They repeat operations of protective relays, control switches etc. They relieve the protective relays of duties like ¦ripping, time lag, sounding an alarm etc. They may be instantaneous or may have a time Belay.
IJnder Voltage Relay : A relay which operates when the system voltage falls below Certain preset value.
¦Time Delay Relay : A time delay operates after a certain preset time delay. The time Belay may be due to its inherent design features or may be due to the presence of a time Belay component. Such relays are used in the protection schemes as a means of time discrimination. They are frequently used in control and alarm schemes.
ifferential Relay : A relay which operates in response to the difference of two f tuating quantities.
¦arth Fault Relay : A relay used for the protection of an element of a power system gainst earth faults is known an earth relay.
ver Current Relay : A relay which operates when the actuating current exceeds a ertain preset value. The value of a preset current above, which the relay operates, is own as its pick up value. An over current relay is used for the protection of distribution es, large motors, power equipments etc.
lassification of Protective Relays based on Technology
Protective relays can be broadly classified into the following categories depending 1 the technology they use for their construction and operation .
1. Electromechanical Relays
2. Static Relays
3. Numerical Relays
f echnology Comparison for Protective Relays
SI.
No SUBJECT ELECTRO MECHANICAL STATIC/ ELECTRONIC NUMERICAL
1 Measuring elements/ (Hardware Induction disc, Electromagnets, Induction cup. Balance Beam Discrete R, L, C Transistors, Analogue ICs comparators Microprocessors, Digital ICs, Digital signal processors
2 Measuring method Electrical qtys converted into mechanical force, torque Level detectors, comparison with reference value in analogue comparator A/D conversion,
Numerical algorithm techniques evaluate trip criteria
->
:> Timing function Mechanical clock works, dashpot Static timers Counters
f 4 Sequence of events Not possible Not possible Provided
5 Visual indication Flags, targets LEDs LEDs, LCD Display
Trip
[command Additional trip duty relay required Additional trip duty relay required Trip duty contact inbuilt
Self
monitoring No Yes
Hardware
Partly Power supply Yes
Hardware Power supply O/P relays Firm ware CT, PT ckts
r x Construction size Bulky Modular, compact Most compact
9 Temp. Stability Yes No Yes
f 10 Contacts Assignments Fixed Fixed Freely Marshable
11
1 Parameter Setting Plug setting. Dial setting Thumb Wheel, Potentiometers, Dual in line switches Keypad for Numeric values
Binary inputs for adaptive relaying Not Available Not Available Freely Marshable from 24v to 250v
13 CT loading/ Burden 8- 10 VA 1 VA < 0.5 VA
" CT offset adjustment No No Yes
! '5 Vibration proof No Yes Yes
I 16 Harmonic Immunity No Possible through Analog filtering Yes, digital filtering incorporated
17 Calibration Frequently required as settings drift due to ageing Required as settings drift due to ageing Not required as settings are stored in memory in digital format
[18 Auxilliary supply Required Required Required
1 19 Electromagnetic/ electrostatic/high freq. disturbance Immune Susceptible Immune
1 20 Multiple characteristics Not possible Not possible Possible
! 21 Integrated
protection functions Not possible Not possible Possible
! 22 ¦Range of settings Limited Wide Wide
[23 [Operational value indication Not possible Possible Possible
| 24 Fault disturbance [ recording Not possible Not possible Possible
11 25 Digital
communication port Not possible Not possible Available
26 Commission-ing support from relay No No Yes
Project Report 2007
imitations of the previous system
The protective system working with the help of electromechanical relays have the (pillowing limitation.
¢ Less accuracy
¢ Slow response to faulty condition
¢ Fault event analysis is difficult
¢ Burdon on CTs and PTs are more
¢ Different elements are required for different protection
¢ Limited loads shedding facility
fdvantages of PMS
¢ Centralized controlling of power system
¢ Fault analysis efficient
¢ Integration and standardization of relays
¢ Control and monitoring possible
imitation
Auto synchronization facility is not included
SCADA (Supervisory Control And Data Acquisition,)
SCADA is the acronym for Supervisory Control And Data Acquisition. The term |ers to a large-scale, distributed measurement (and control) system. SCADA systems used to monitor or to control chemical or transport processes, in municipal water ply systems, to control electric power generation, transmission and distribution, gas fd oil pipelines, and other distributed processes.
This is an industrial measurement of control system consisting of a central host jsually called Master Terminal unit, MTU), one or more field data gathering and control fits (Usually called Remote Terminal Unit, RTU) and a collection of standard software Ised to monitor and control remotely located field data elements. It generally covers jrge geographic areas and rely on a variety of communication system that are normally res reliable. The data is processed to detect alarm conditions and if an alarm is present, it fill be displayed on special alarm lists.
Systems concepts
A SCADA system includes input/output signal hardware, controllers, HMI, Networks, communication, database and software. It mainly comes in the branch of strumentation Engineering. The term SCADA usually refers to a central system that onitors and controls a complete site or a system spread out over a long distance kilometres/miles). The bulk of the site control is actually performed automatically by a emote Terminal Unit (RTU) or by a Programmable Logic Controller (PLC). Host jontrol functions are almost always restricted to basic site over-ride or supervisory level apability. For example, a PLC may control the flow of cooling water through part of an hdustrial process, but the SCADA system may allow an operator to change the control et point for the flow, and will allow any alarm conditions such as loss of flow or high
J
[emperature to be recorded and displayed. The feedback control loop is closed through Be RTU or PLC; the SCADA system monitors the overall performance of that loop.
Data acquisition begins at the RTU or PLC level and includes meter readings and equipment statuses that are communicated to SCADA as required. Data is then compiled End formatted in such a way that a control room operator using the HM1 can make appropriate supervisory decisions that may be required to adjust or over-ride normal RTU ¦PLC) controls. Data may also be collected in to a Historian, often built on a commodity Database Management System, to allow trending and other analytical work.
The SCADA software is graphical package using any Windows NT operating wstem. SCADA automatically generates alarms and monthly energy reports and is easily Expandable as the needs grow.
When a particular section of the distribution system goes down, the operator is trovided with instant information. This enables the system operator to provide individual lonceming officials, information on the problem. In addition the engineers are able to examine historical data for load trending, planning and improving system performance, ¦he additional benefits of this system includes manual meter reading is being replaced tvith automatic reporting and real time alarms and data give operators the information [hey need to respond quickly. With the installation of this technology the excessive time spent investigating faults and problems is reduced substantially.
Human Machine Interface
A Human-Machine Interface or HMI is the apparatus which presents process data to a human operator, and through which the human operator controls the process.
The HMI industry was essentially bom out of a need for a standardized way to monitor and to control multiple remote controllers, PLCs and other control devices, ^hile a PLC does provide automated, pre-programmed control over a process, they are
¦sually distributed across a plant, making it difficult to gather data from them manually. Historically PLCs had no standardized way to present information to an operator. The ICADA system gathers information from the PLCs and other controllers via some form If network, and combines and formats the information. An HMI may also be linked to a latabase, to provide trending, diagnostic data, and management information such as [scheduled maintenance procedures, logistic information, detailed schematics for a particular sensor or machine, and expert-system troubleshooting guides. Since about ¦998, virtually all major PLC manufacturers have offered integrated HMI/SCADA lystems, many of them using open and non-proprietary communications protocols, ¦umerous specialized third-party HMI/SCADA packages, offering built-in compatibility with most major PLCs, have also entered the market, allowing mechanical engineers, Electrical engineers and technicians to configure HMIs themselves, without the need for a lustom-made program written by a software developer.
SCADA is popular, due to its compatibility and reliability. It is used in small Ipplications, like controlling the temperature of a room, to large applications, such as the control of nuclear power plants.
[Hardware solutions
SCADA solutions often have Distributed Control System (DCS) components. Use »f "smart" RTUs or PLCs, which are capable of autonomously executing simple logic processes without involving the master computer, is increasing. A functional block irogramming language, IEC 61131-3, is frequently used to create programs which run on liese RTUs and PLCs. Unlike a procedural language such as the C programming Enguage or FORTRAN, IEC 61131-3 has minimal training requirements by virtue of lesembling historic physical control arrays. This allows SCADA system engineers to perform both the design and implementation of a program to be executed on a RTU or IPLC.
[PLC's Vs RTU's
I A PLC (Programmable Logic Controller) is a small industrial computer which originally replaced relay logic. It had inputs and outputs similar to those an RTU has. It contained a program which executes a loop, scanning the inputs and taking actions based In these inputs. Originally the PLC had no communications capability, but they began to Be used in situations where communications was a desirable feature. So communication [nodules were developed for PLC's, supporting Ethernet (for use in distributed control Systems) and the Modbus communications protocol for use over dedicated (wire) links, lis time goes on we will see PLC's support more sophisticated communication protocols.
RTU"s have always been used in situations where the communications are more lifficult, and the RTU's strength was its ability to handle difficult communications. |RTU*s originally had poor programmability in comparison to PLC's. As time has went In, the programmability of the RTU has increased.
[System components
The three components of a SCADA system are:
¢ Multiple Remote Terminal Units (also known as RTUs or Outstations).
¢ Master Station and HMI Computer(s).
¢ Communication infrastructure
Remote Terminal Unit (RTU)
The RTU connects to physical equipment, and reads status data such as the Ipen/closed status from a switch or a valve, reads measurements such as pressure, flow, loltage or current. By sending signals to equipment the RTU can control equipment, such |s opening or closing a switch or a valve, or setting the speed of a pump. The RTU can
lead digital status data or analogue measurement data, and send out digital commands or analogue setpoints.
An important part of most SCADA implementations are alarms. An alarm is a digital status point that has either the value NORMAL or ALARM. Alarms can be treated in such a way that when their requirements are met, they are activated. An example of an alarm is the "fuel tank empty" light in a car. The SCADA operator's attention is drawn to the part of the system requiring attention by the alarm. Emails and lext messages are often sent along with an alarm activation alerting managers along with the SCADA operator.
Master Station
The term "Master Station" refers to the servers and software responsible for lommunicating with the field equipment (RTUs, PLCs, etc), and then to the HMt" |oftware running on workstations in the control room, or elsewhere. In smaller SCADA Systems, the master station may be composed of a single PC. In larger SCADA systems, Ie master station may include multiple servers, distributed software applications, and iisaster recovery sites.
The SCADA system usually presents the information to the operating personnel graphically, in the form of a mimic diagram. This means that the operator can see a [schematic representation of the plant being controlled. For example, a picture of a pump lonnected to a pipe can show the operator that the pump is running and how much fluid it |s pumping through the pipe at the moment. The operator can then switch the pump off. [The HMI software will show the flow rate of the fluid in the pipe decrease in real time. Lvlimic diagrams may consist of line graphics and schematic symbols to represent process elements, or may consist of digital photographs of the process equipment overlain with inimated symbols.
Communication infrastructure
SCADA systems have traditionally used combinations of radio and direct serial or modem connections to meet communication requirements, although Ethernet and IP over BONET is also frequently used at large sites such as railways and power stations. fCADA protocols are designed to be very compact and many are designed to send information to the master station only when the master station polls the RTU. Typical Igacy SCADA protocols include Modbus, RP-570 and Conitel.
Applications of SCADA
SCADA systems are used in supervision, control and automation processes in tiany fields of engineering and technology. Some of the areas of its utility are mentioned below of which its role in power utility is described in detail.
¢ Power systems.
¢ Water supply systems.
¢ Industrial Automation.
¢ Telecommunications.
¢ Coal and Petroleum Sector.
¢ Sewage and Irrigation systems.
¢ Railways.
¢ Transport and Logistics etc.
SCADA in Power System
The inefficient operation of the conventional distribution system can be mainly attributed to the frequent occurrence of faults and the uncertainty in detecting them. To enhance the electrical power distribution reliability, sectionalizing switches are provided
Bong the way of primary feeders. Thus, by adding fault detecting relays to the Bectionalizing switches along with circuit breakers and protective relays at the iistribution substations, the system is capable to determine fault sections. To reduce the rervice disruption area in case of power failure, normally open (NO) sectionalizing switches called as route (tie) switches are used for supply restoration process. The Iperation of these switches is controlled from the control center through remote Terminal Units (RTU's).
SCADA
DISTRIBUTION AUTOMATION
DAS Communication and Control Computer Network
Kales
Rates
Distribution Information
Operation's
Planning
Utility systems with SCADA and Distribution Automation
In distribution automation (DA) system the various quantities (e.g., voltage, Rirrent, switch status, temperature and oil levels, etc.) are recorded in the field at the Iistribution transformers and feeders, using data acquisition by RTU. These quantities are pansmitted on line to the base station (MTU) through a communication media. The data acquired is processed at the base station for display at multiple computers through a Kraphic User Interface (GUI). In the event of a system quantity crossing a pre-defined
Iireshold. an alarm is generated for operation intervention. Any control action, for Opening or closing of the switch or circuit breaker, is initiated by the operator and ¦ ansmitted from the base station through the communication channel to the RTU jssociated with the corresponding switch or CB. The desired switching takes place and the action is acknowledged back to the operator.
All the above mentioned functions of data collection, data transmission, data iionitoring, data processing, man-machine interface, etc. are realized using an integrated jistribution SCADA system.
NEED OF PMS IN BPCL - KR
Alter incoiporating additional power generation facilities and after commissioning of DHDS plant and other expansion schemes, the BPCL - KR power system has become very large and complex.
Such a complex system requires a system, which presents all network data to allow safe and reliable operation to control the complete network from a central control room through various plant overviews. Shortage of power may occur in situations when BPCL - KR's capitive generation is not enough and KSFB grid power supply is unreliable. Such situations load shedding scheme has to be devised for switching off non-critical loads to secure continuous power to critical loads. This scheme is complex for the BPCL - KR power system network, as the network itself has increased in complexing in the last decade after many expansions. After commissioning of DHDS, the plant load of BPCL - KR has increased and real time load management has become a crucial and complex task. To obtain stable plant operation inspite of instability in grid supply, it is now necessary to introduce real time automation for load.
PMS
The proposed electrical system/PMS shall have basically the following base level functions and advanced level functions.
Base Level Functions
f ¢ Electrical plant data acquisition and dynamic mimic display. ¢ Control functions covering ON/OFF. [ ¢ Sequence of event logger.
¢ Serial interface to IED"s (Intelligent Electronic devices) for the display of status/alarm/event/disturbance recording on PC and generation of dynamic mimic on PC of the network.
¢ Control of switchgear devices, eg. circuit breakers from HMI/PC-acquisition, preprocessing and display of measured values on HMI.
¢ Operational metering
¢ Sequence of event recording (SOE)/disturbance recording.
¢ Archiving of data comprising of values, event and alarm data, including those obtained from the protection relay.
¢ Synchrocheck.
Advanced Level Function
load shedding : The master station is constantly monitoring the load at the station E'here the load shedding is to take place. It makes calculations on which breaker should |e opened when the L.S starts. Now this information on which breaker should be open is |ent to RTU in 3 big pattern telegrams. The load shedding scheme provides a rapid seduction of plant load in one of the following.
¢ When the trip of captive generator takes place [ ¢ When the trip of bus-tie-breakers takes place
¢ When the KSEB grid support is interrupted
The amount of load to be shed is decided by measuring the instantaneous measurements of power generation and consumption prior to the occurance of Contingency.
There are 2 different stages of load shedding. Predictive demand meters activate fie first level of load shedding. The islanded section of power system is subjected to ¦arther monitoring for U/F and also for rate of decay. If the first level of shedding is not able to remove the generation - load mismatch, the second stage of load shedding based In priority is activated by U/F relays in the substation. Stage 1 to 4 is each associated K-ith a different frequency. So when the frequency at the specific station reaches the value If stage, the relay will give us an output pulse of on the stage 1 output. All four stages of U/F work in this way. Stages can also be actived at the same time. Thus four stage operations are fed into RTU to active the load shedding program.
COMPONENTS OF PMS
PMS consists of a PC based Substation Automation which comprises of the following .
> Numerical Relays and Meters at the feeder level interfaced to Sicam PCC Device Interface Processor (DIP) on IEC - 103 and Profibus DP protocols respectively in three 1 1 KV substations namely MRS , CPP and CDU. The load shedding features is provided by a RTU connected to DIP - MRS on IEC - 101 interface.
> The three Device Interface Processors/Data concentrators at different substations are connected to a Sicam PCC Central Server (HMI PC) placed in the MRS substation on a Fibre Optic TCP/IP network LAN. This Central Server is the main Database for the entire system, which has the configuration and the operational data.
> The process visualization software Simatic WinCC is installed on HMI PC. The control and monitoring is possible from HMI.
> At MRS S/s there are two machines available. One will be used as Operator console and other one as Engineering console. Generally Operator console shall be used for HMI operation and Engineering console for Engineering operations like Relay settings, Fault analysis etc. Only in case of failure of Operator console. Engineering console is used for HMI operations additionally.
System Structure
The system is based on a distributed two - tier hierarchical scheme. The entire fwitchgear will be controlled and supervised via a PC based HMI Simatic WinCC at the IdRS S/s, while individual feeders are covered by the Numeric Relays. Switchgear auxiliary contacts for monitoring and control are hardwired to the numeric relays, which fere inturn interacted with the PC based controller Sicam PCC.
Station Level
The Device Interface Processors at the individual substations constantly monitor tall substations and poll data automatically from the individual feeders. This data is transferred to the Sicam PCC Full Server placed in the MRS substation. This Full Server PCC has an interface to the HMI Simatic WinCC, which is windows based process Visualization software tool to control and monitor the power system switchgear. The HMI pisplays switchgear status by a customized overview and by detail single line diagrams fcvith coloured mimic displays of different switchgear components, which represents Btatus. Online alarmlist and eventlist provide additional information on historical data . Printer is provided for printing the reports.
Feeder Level
Numeric protective relays and meters present in each feeders are hardwired to the auxiliary contacts, trip coils and CTs/PTs of the switchgear. Feeder units are independent of each other and their individual operations are not affected by any fault occurring at the itation level or any other feeder. These Numeric Relays constantly collect and pre -process status information alarms and measured values from the switchgear. This pre -processed data is then transmitted to Sicam PCC controller on the request for the further processing and display. These relays commands initiated by the operator at the station level and they also provided local control capability.
Load shedding
PMS provides facility for load shedding. Depending upon the Circuit Breaker ¦tatus of four Incomer Circuit Breakers ie. STG, GTG, KSEB 66/TlkV Trasformer Picomer -1 and KSEB Trasformer Incomer -2, RTU initiates load shedding in groups as Per the load shedding priorities (User Adjustable) such that feeders having priority 1 trips
i-rst and then RTU waits if the Load shedding initiating conditions have gone . If it is still Persisting then the feeders having tripping priority 2 are tripped and the sequence Continues till the system stabilizes. PMS comprises tripping for 1 lkV feeders available at MRS. CDU and CPP substations.
List of Hardware used
| ¢ PC's : 3 No's (HMI, Engineering PC, DIPMRS) Location: MRS S/s.
¢ PC : 1 No (DIPCDU) Location: CDU S/s.
¢ PC : 1 No (DIPCPP) Location: CPP S/s.
¢ Printer : Inkjet connected to Engineering PC at MRS S/s.
¢ Printer : Dot-matrix connected to HMI PC at MRS S/s for online printing of Events.
¢ OSM*s : Optical Switch module.
1 No. connected with each PC which is basically used as RJ45 to FO cable converter for connecting the PC's over a FO cable TCP IP LAN.
¢ SITOP : 230, 1 1OV AC to 24V DC power supply. 1 No. used with each OSM.
¢ RTU : Remote Terminal Unit.
RTU is used for Load shedding puipose. Also it takes inputs from ION meters connected to 4 no. incomers at MRS S/s.
List of Software used HMI PC
¢ Sicam PCC-Full Server for gathering data from DIP's located at various locations.
¢ Simatic WinCC for process visualization, which is taking data from Sicam PCC running in background of the system.
Engineering PC
¢ Simatic Manager with Digsi (Inbuilt) for analyzing fault records, changing relay setting, visualizing synchronization measurement values required at the time of CB synchronization.
¢ In addition to above Engineering PC is also having Sicam PCC full Server and Simatic WinCC to be used only in case of using Engineering PC for HMI puipose when main HMI PC is down.
DIP PC's at MRS, CDU, CPP S/s
Sicam PCC-DIP.
HMI Operation
The HMI PC is the server for all machines. Only HMI and Engineering PC is provided with monitors, as DIP's dont require monitor for general use. HMI PC desktop fis having icons for software - PC, Windows Control Centre (WinCC) services. PCC (starts automatically gathering data from DIP's.
h>cc
There are two modes of operation, configuration mode and operation mode. The [user can switch over between the two modes of operation with the help of icons available in the main menu.
Mode 1 : (Configuration Mode)
This mode is used to measure system configuration. Any alternation in this mode can disturb the whole system.
Mode 2 : (Operation Mode)
This mode is used to monitor the healthy functioning of the system. In this mode one can find that all the DIP's along with the devices are communicating with the system or not.
Red colour : Device not communicating with the system (Problem).
Blue colour : Device delibrately kept off in PCC and hence it is not
communicating with the system.
Green colour : Device is healthy and is communicating with the system.
SIMATIC WinCC & HMI Control
Similar to PCC, WinCC has got two modes of operation configuration mode and run time mode.
[Mode 1 : (Configuration Mode)
When WinCC is opened, it always opens into its configuration mode. Any alteration in this mode can disturb the whole system.
Mode 2 : (Runtime Mode)
WinCC runtime can be activated with the help of activate button available in the main menu in operation mode.
Also there is provision for obtaining Overall System Overview for individual substation in WinCC.
Display & control
The Overview station diagram shows the simplified single line diagram of the [substations connected to PMS (MRS, CDU, CPP S/s). All controls are accessible to operator from the console. Similarly in System overview (available on the extreme LHS fef screen), communication status of the devices (meters, relays. RTU) can be know. jThere are total of 6 button provided for puipose.
¢ Overall System Overview
¢ Overall Station Overview
I ¢ MRS System Overview
¢ MRS Station Overview
¢ CDU System Overview
¢ CDU Station Overview
¢ CPP System Overview
¢ CPP Station Overview
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System Overview for individual Substations
System overview shows how various devices are connected to the PCC DIP's. Advantage of system overview is that in case of any device communication failure, same in represented with the red blinking line and hence operator can come to know in case of communication failure of any device.
Station Overview for individual Substation
This shows the circuit breaker status for the complete station along with control. Current for the respective bays is also given for each feeder. Significance of various colours for circuit beaker is as follows : Red colour : CB closed Green colour : CB open
Yellow colour : CB neither open nor closed - Intermediate state.
Any of the above mentioned colours along with the Blue colour dot is the CB symbol means that the CB status is not reliable, an WinCC is not able to get the information from PCC. This kind of situation may arise for some time when WinCC runtime is activated as it takes some time for PCC to restore connection with WinCC.
Control Authority
Generally a Local/Remote selector switch is provided in 7SJ64 relay & Function Key in (7SJ61.7SJ62,7UT61) is available on the relays. So that when switch is in 'Local' position no command from remote (SCADA) shall be executed & vice versa. So in case ;L' is red in colour then that means relay control authority is set into Local mode & hence any command from HMI shall not be executed. Similarly in case 'R" is red in color then the relay control authority is set into remote & hence command shall be accepted by the system from remote.
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Fig: Screen shot of CPP
Alarm/Event List *
All the events are logged into event list. All the alarms will appear in the alarm list. The same can be acknowledged. The acknowledged alarms will move from alarm list as operator acknowledged events to the event list. One line will be displayed for each event and alarm comprising the following information :
¢ Date
¢ Time day with date, hour, minute & millisecond
¢ Substation name
¢ Panel No.
¢ Feeder Name
¢ Manage Text (Details description of the event)
¢ Value of the message (ie. 'Came In' or "Went Out')
¢ Cause (Spontaneous or Irrelevant or General interrogation)
¢ Status (ie. validity of the Alarm) : Please note that only alarms having status valid are true alarms. Please ignore all alarms having not valid status.
¢ Condition (ie. acknowledged by the operator or System acknowledged) : In case any alarm is acknowledged by the operator then the same shall be transferred to event list with the condition : operator acknowledged . But in case of alarms, which have changed status then the same shall be logged into event list with both the status along with the acknowledged status of the message - system acknowledged as system.
Local/Remote Control Switchover
Generally a Local/Remote selector switch is provided in 7SJ64 but in 7SJ61. 7SJ62, 7UT61 relays control authority can be switched between Local & Remote.
Fig: Screen shot showing power consumption in various plants
Display Sections and Measurements Display
Metering values for various circuits comprise of following parameter :
For general Load Feeder : la, P, Wpi are displayed in the individual bay details. However for KSEB Transformer Feeders and STG, GTG Incomer feeders at MRS S/s where ION meters are mounted following parameters are observed :
Vab. la, Active Power(P), Reactive Power(Q), PF, Frequency(F), Active Energy Import(Wpi), Active Energy Export(Wpe), KVA real time demand(KVAd). KVA maximum demand(KVAm), KVA predictive demand(KVAp).
Synchronisation
For all the breakers at MRS & CPP substation, which needs to be synchronized, a separate 'Synch' button is provided in the respective breaker bay details. On pressing that Synch button user can go to the CB synchronization screen for that breaker.
Reporting
The system shall support the operator in creating and the printing user - defined
reports.
¢ Current event and alarm data (online printing)
¢ Archived event and alarm data
¢ Diagrams and charts of archived analogue values
¢ Hard copies
¢ Operator reports
¢ System configuration data
¢ Protection settings for various feeders
Fig: Graphical representation of fault current
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SIPROTEC PROTECTIVE RELAYS
Overview
Fig: Overall view of Siemens Siprotec Relay
High-performance protective relaying comes into its own when it's a question of minimizing power system operating costs. Uncomplicated operation, convenient commissioning tools and flexible communication are all important elements when service and maintenance costs have to be reduced. The Siemens SIPROTEC family with its protection relays and bay control units is an integrated system for medium-voltage to extra-high-voltage applications. These relays not only handle fault detection and location tasks but also control, metering and monitoring functions. And it is these additional functions - impossible before the advent of numerical technology - which offer major cost-cutting potential.
Hardware Block Diagram
A/D -> Analog to digital
MP -> Microprocessor
HMI -> Human machine interface
B.I -> Binary input
BO -> Binary output
CP -> Communication port
IS -> Input signal
OS -> Output signal
RAM
ROM
EEPROM
HMI
MP
MP
E A

IS
B 0

OS
CP
Signal Flow Graph
Data Acquisition & Processing
Analog Signal Input
1
Analog Filters
*
Sample & Hold Circuit
*
Multiplexer
*
A/D Converter
i
Digital Filters
*
Microprocessor
Protection Algorithm
1
Relay Logics
*
Trip & Alarm Output
System Advantages *
¢ One bay, one unit
The SIPROTEC 4 relay family offers fully integrated protection, control, monitoring, and automation functions incorporated in a single device. For many applications, this product contains all the functions you need to meet all your protection and control requirements with just one unit per bay. saving on investment and installation costs and enhancing availability.
¦ DIGSI 4 - one tool for all tasks and products
DIGSI 4 is a computer program designed for all SIPROTEC relays. DIGSI 4 offers users a universal tool for all support tasks from setting and commissioning of devices to simple analysis and documentation of system faults. This powerful analysis tool speeds up troubleshooting and supplies important service information.
Overall Protection
The SIPROTEC 4 type relays are numerical, multifunctional, and protective and control devices equipped with a powerful microprocessor. All tasks such as acquisition of the measured quantities, issuing of commands to CBs and other primary power system equipment are processed in a completely digital way.
Analog Inputs
Measuring inputs (MI) selection consists of current and voltage transformers. They convert he signals from the measuring transducers to levels appropriate for the internal processing of the device.
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Fig: Hardware structure of a Siprotec Numerical Relay
Four current inputs are available in the MI section. These inputs are used for measuring of the phase currents. The use of the fourth current depends on the version of the device ordered. The fourth input can be used for measuring the ground current as the residual of the phase current of the transformers, or for measuring the ground current from a separate current transformer. The latter is used in a highly sensitive ground fault protective scheme or a polarizing current to determine the fault direction.
The four voltage transformers of relay can either be applied for the input of 3 phase ground voltages, one displacement voltage or a further voltage for the synchronizing function.
The analog input quantities from the MI stage are passed on to the input amplification (IA) stage, which provides high resistance termination for the analog quantities. The IA stage consists of filters for processing in the measured values. The filters are optimized with regard to band width and processing speed.
The analog to digital stage (AD) consist of memory components, a multiplexer and an analog to digital (A/D) converter. The A/D converter processes the analog signals from the IA stage. The digital signals from the converter are input to the microcomputer system where there are processed as numerical values in the residing algorithms.
Micro computer System
The protection and control functions of the numerical relays are processed in the microcomputer system. In addition, the microcomputer controls the measured quantity specifically, the microcomputer performs:
¢ Filtering and preparation of the measured quantities.
¢ Continuous monitoring of the measured quantities.
¢ Monitoring of the pickup conditions for the individual elements and functions.
¢ Evaluation of limit values and sequences in time.
¢ Control signals for the logic functions.
¢ Decision of trip, close and other control commands.
¢ Output of control commands for switching devices.
¢ Recording of messages and data for events, alarms, faults, control actions and provision of their data for analysis.
¢ Management of the operating system and the associated functions such as data recording, real time clock, communication, interfaces etc.
Binary Inputs and Outputs
The microcomputer obtains external information through the binary inputs such as blocking commands for protective elements or position indications of CB. The microcomputer issues commands to external equipments via output contacts. These output commands are generally used to operate CBs or other switching devices. They can also be connected to other protective devices, annunciators, or external carrier equipments for use in pilot relaying schemes.
Serial Interfaces
Serial interfaces are available for communication with PCs, RTU s and SCADA systems.
A serial PC port on device is provided for local communication with the relay through a personnel computer. D1GSI 4 software is required to communicate via this port. Using the DIGSI 4 software, settings and configuration can be made to the relay, real-time operating quantities can be viewed, waveform capture and event by records can be displayed, and controls can be issued.
A separate service port can be provided for remote communication in a modem or substation computer. The operating program is required. The port is especially well suited for the fixed wiring of the devices to the PC or operation via a modem. The service port can also be used to connect a RTD-Box for entering external temperature (e.g. for overload protection). The additional port is exclusively designed for the connection of a RTD-Box for entering external temperature.
All relay data can be transferred to a central control and monitor system through the SCADA port. Various protocols and physical interfaces are available to suit the particular operation. A further port is provided for the time synchronization of the internal clock via external synchronization sources.
Applications
The numerical, multifunctional SIPROTEC 4 relay is versatile devices designed for many applications. The relay can be used as a protective, control, and monitoring devices for distribution feeders and transmission lines any voltage in networks that are grounded, or of a compensated neutral point structures, the devices are suited for networks that are radial or looped, and for lines in single or multi terminal feeds; the relay are equipped with motor protection available for asynchronous machine of all sizes.
The relay includes the functions that are necessary for protection, monitoring of circuit breaker position, and control of the circuit breaker in straight bus application or breaker and a half configuration; therefore, the devices can be inversely employed. The relay provides excellent backup facilities of differential protective scheme of lines, transformers, generators, motors, and bus bars of all voltage levels.
Protectiue Relays a SCADA Systems
SlPROTEC Protective Relays mum
ANSI Selection List for Protective Rtihys
- - - - - - - - - 1 I ¦ ¦ I ” ” ” ” ” ” ”
CONCLUSION
A complex power system like BPCL requires a system, which presents all networks data to allow safe and reliable operation to control the complete network from a central control room through various plant overviews. For obtaining a stable plant operation inspite of instability in grid supply, real time load automation is required and that's why power management system is introduced. The application of SCADA system can be extended to various fields of engineering & technology for supervision, control and automation. Here we also see the advantages of replacing conventional relays with numerical relays.
REFERENCES
1. siemens.com.
2. kochirefineries.com
3. wikipedia.com
4. CPP Manual of BPCL - KR
5. Manual of Power Management System by Siemens
6. The Art and Science of Protective Relaying by C. Russell Mason
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