POWER SYSTEM CORPORATION OPERATION LIMITED

(A wholly owned subsidiary company of Power Grid Corporation of India Limited)

14, Golf Club Road, Tollygunge

KOLKATA-700 033

POWER MAP OF EASTERN REGION

A Report on “Functioning of ERLDC” by:

Sr. no.

Trainee Name

College

1.

NIRANJAN KUMAR

Malaviya National Institute of Technology, Jaipur

(RAJ.)

2.

LEKHRAM MEENA

Malaviya National Institute of Technology, Jaipur (RAJ.)

3.

SAURABH MEENA

Malaviya National Institute of Technology, Jaipur

(RAJ.)

Date Name of department Reporting officer/ Mentors

26.05.14 to 04.6.14 Orientation, Overview/Grid Management

Mr. D.K. Shrivastava, AGM

5-6/6/14 & 9-13/6/14 System Studies, MIS Mr. S. Banerjee, CM

16-20/6/14 & 23-24/6/14

SCADA & IT Mr. S.P. Barnwal, CM

25-27/6/14 Technical Services Mr. P. Chaudhury, CM

30.6.14 to 4.7.14 & 7-8/7/14

Metering and Settlement, Short Term Open Access

Mr. G. Chakraborty, DGM

9-11/7/14 & 14/7/14 Regulatory Affairs Mr. P.S. Das, CM

Training Period: 26-05-2014 to 14-07-2014

TRAINING SCHEDULE

Acknowledgement……………………………………………………………………………………..

1. An overview of Indian Power Sector………………………………………………………………….

2. POSOCO………………………………………………………………………………………………...

3. Function of ERLDC……………………………………………………………………………………..

4. Power System Studies…………………………………………………………………………………

5. Management Information System (MIS)……………………………………………………………..

6. SCADA…………………………………………………………………………………………………..

7. PMUs…………………………………………………………………………………………………….

8. Technical Services……………………………………………………………………………………..

9. Metering and Settlement………………………………………………………………………………

10. Short Term Open Access (STOA)………………………………………………………………….

References……………………………………………………………………………………………..

Table of Contents

Internship at ERLDC, Kolkata has been a golden opportunity for learning and self-

development. We consider ourselves very lucky and honored to have so many

wonderful people lead us through. Who guided us, taught us & blessed us with

profound knowledge.

We wish to express our indebted gratitude and special thanks to "Mr. S. Banerjee"

who in spite of being extraordinarily busy with his duties, took time out to hear, guide

and keep us on the correct path and allowing us to learn the basics about their

esteemed organization.

We are also obliged to other staff members too, for the valuable information

provided by them in their respective fields. We’re grateful for their cooperation

during the period of our training.

INDIAN POWER SECTOR: OVERVIEW

Acknowledgement

The Power System in India is organized in five electrical regions for operational and

planning purpose namely North, South, East, West and North-east. Eastern

Region with an installed generating capacity of 28337.75 MW (as on 12.10.2012) is

connected with all four regions of the country. It is also electrically connected with

Bhutan and Nepal.

Eastern Region constituents include mainly five states, Damodar Valley Corporation,

Central Sector Generating Stations (NTPC and NHPC) and one Central

Transmission Utility (CTU). Damodar Valley Corporation (DVC) is a vertically

integrated utility like a SEB and has its own Generation, Transmission and

Distribution in the identified command area of Jharkhand and West Bengal. DVC

has a separate Control Center at Maithon. A few interstate lines between

Jharkhand and West Bengal that form a part of the Inter State Transmission System

are also operated and maintained by the DVC.

Presently all the regions are synchronized electrically as single block. The

Exchange of power among the synchronized regions takes place through

765/400/220KV transmission lines and 800/1200KV HVDC interconnections

whereas the power Exchange with Southern Region is through HVDC

interconnections. In each Region, the Generation, Transmission and Distribution of

Power along with State Lines is organized such that the State owned Power

Systems and Load Despatch Centers are operated by State Transmission

Companies. The State Transmission Companies and the Central Sector Group of

agencies are referred to as Constituents. The operation of the each Regional Grid is

managed by the Regional Load Despatch enter (RLDC) with underlying State Load

Despatch Center (SLDCs) and Sub-LDCs. At National level to supervise the RLDCs

and to monitor the Inter Regional Power Exchanges, a National Load Despatch

Center is in operation. All SLDCs, RLDCs and NLDC control centers are equipped

with full-fledged SCADA/EMS systems.

EASTERN REGION CONSTITUENTS:

The Eastern Region Power System Interconnects the Generation, Transmission and

Distribution facilities of following constitutes:

01. Damodar Valley Corporation (DVC)

02. West Bengal State Electricity Transmission Company Limited (WBSETCL)

03. Orissa Power Transmission Corporation Limited (OPTCL)

04. Bihar State Electricity Board (BSEB)

05. Jharkhand State Electricity Board (JSEB)

06. Energy & Power department, Govt. of Sikkim

Load Despatch and Communication Facilities in Eastern Region:

Load despatch & Communication facilities presently available in

Eastern Region at ERLDC, SLDCs and Sub-LDCs were commissioned beginning

2004 under Unified Load despatch and communication (ULDC) scheme. The control

centers are ERLDC, 5 no’s of SLDCs and 6 no’s of Sub-LDCs reporting in

hierarchical setup. The parameters like voltage, frequency, MW, MVAR, Breaker

and Isolator Positions etc. are acquired by Sub-LDC/SLDC/ERLDC through RTUs

installed at respective Substations/Generating Stations over PLCC and Wideband

link consisting of fiber Optics, VSAT and Microwave. The Central Sector data is

directly transmitted to ERLDC and the state sector data is transmitted to either Sub-

LDC or SLDC. Subsequently ERLDC system was integrated with Main NLDC and

Backup NLDC.

POWER SYSTEM OPERATION CORPORATION LIMITED

Introduction – Formation of POSOCO:

Power System Operation Corporation Limited (POSOCO) is a

wholly owned subsidiary of Power Grid Corporation of India Limited (PGCIL). It was

formed in March 2010 to handle the power management functions of PGCIL. It is

responsible to ensure the integrated operation of the Grid in a reliable, efficient and

secure manner. It consists of 5 Regional Load despatch Centers and a National

Load Despatch Center (NLDC). The subsidiary may eventually be made a separate

company, leaving the parent firm with only the task of setting up transmission links.

The load despatch functions, earlier handled by PGCIL, will now come up to

POSOCO.

Power System Operation Corporation Ltd (POSOCO), a wholly owned subsidiary of

the Power Grid Corporation of India Limited (a Government Company) shall operate

National Load Despatch Center and the five Regional Load Despatch Centers, with

effect from October 1, 2010.

To make load despatch centers financially self-reliant and autonomous, the

committee recommended independent and sustainable revenue streams. The move

to separate the two functions is in keeping with the provisions of the Electricity Act,

2003, which seeks to separate commercial interests from load management

functions. The Pradhan committee had recommended setting up a separate

representative board structure overseeing the functions of the five regional load

despatch centers (RLDCs) run by PGCIL—the northern, eastern, north-eastern,

western and southern regions at that time.

FUNCTIONS OF ERLDC

The role and functions of ERLDC, as per Section 28 of Electricity Act 2003 are: To

ensure integrated operation of power system in the Eastern Region. Specifically,

Eastern Regional Load Despatch Center shall:-

1. be responsible for optimum scheduling and despatch of electricity within the

region, in accordance with the contracts entered into with the licensees or the

generating companies operating in the region

2. Monitor grid operations

3. Keep accounts of quantity of electricity transmitted through the regional grid

4. Exercise supervision and control over the inter-state transmission system

5. be responsible for carrying out real time operations for grid control and despatch

of electricity within the region through secure and economic operation of the regional

grid in accordance with the Grid Standards

6. To levy and collect such fees & charges from the generating companies or

licensees engaged in inter-state transmission of electricity as may be specified by

the Central Commission.

All the utilities like generators, sellers, buyers and traders of the Eastern Regional

grid has to schedule their power transactions through ERLDC for optimum utilization

of power in real time operation.

Eastern Region is connected to all the other four regions of India. Except Southern

Region it is synchronized with the all other grids; while it is connected through

HVDC line with the Southern grid.

THE OPERATION OF ERLDC IS BROADLY CLASSIFIED INTO

TWO SECTIONS:

ERLDC

Instead of these there is one more department, Technical Services which

supervise the maintenance works like water supply for drinking, ac plant and testing

of generators which are needed anytime for backup power and ac plant etc.

MARKET OPERATIONS SYSTEM OPERATIONS

a) SYSTEM STUDIES AND MIS

b) SCADA & IT

a) SHORT TERM OPEN ACCESS

b) METERING AND SETTLEMENT

POWER SYSTEM STUDIES

All studies carried out correspond to operational time frame.

The following studies are undertaken in Siemens PTI PSS®E Software:

01. Inter-regional TTC assessment

02. Studies Prior to charging of new element

03. Contingency analysis

04. Studies prior to finalizing shutdown of important grid elements

05. Fault studies

Inter-regional TTC assessment

POWER FLOW/LOAD FLOW -

The process of solving the algebraic equations for given loads and generator power

outputs, is referred to as Load Flow or Power Flow Calculation.

Problem definition -

“Given the load power consumption at all buses of the electric power system and the

power generation at each power plant, find the power flow through each line /

transformer of the interconnected network”.

Purpose of load flow -

To ensure:

1. The system is stable in the steady-state, i.e. there is enough transmission

capacity

2. Transmission capacity is adequate even with some lines out of service

3. All bus bar voltages are within limits

4. The flow of reactive power in the system is acceptable.

Iteration schemes used -

01. Gauss-Seidel Iteration

02. Full Newton-Raphson iteration

03. Decoupled Newton-Raphson iteration

Contingency Analysis

Contingency analysis is the study of the outage of elements such as transmission

lines, transformers and generators, and investigation of the resulting effects on line

power flows and bus voltages of the remaining system. It represents an important

tool to study the effect of elements outages in power system security during

operation and planning. Contingencies referring to disturbances such as

transmission element outages or generator outages may cause sudden and large

changes in both the configuration and the state of the system. Contingencies may

result in severe violations of the operating constraints. Consequently, planning for

contingencies forms an important aspect of secure operation.

Fault Studies

The short circuit module has a number of short circuit calculation algorithms to meet the diverse needs of fault analyses. All algorithms are self-contained within PSS®E, and the module requires only a valid power flow working case and the power system zero and negative sequence data. The short circuit module can simulate one or all fault types at one bus or all system or sub-system buses in one run, thereby reducing analysis time. In addition, PSS®E performs IEC 60909-based fault analysis. The single requirement prior to entering the IEC fault calculation method is a valid power flow working case.

The system zero and negative sequence data is required only if unsymmetrical faults are to be simulated. The PSS®E short circuit analysis is well suited to follow protection coordination work.

MANAGEMENT INFORMATION SYSTEM

(MIS)

DATA COMPILATION

TO ACQUIRE DATA FROM

a) SCADA

b) METERING

REPORT PUBLICATION

a) WEEKLY REPORT b) MONTHLY REPORT c) ANNUAL REPORT

SCADA

WHAT IS SCADA?

SCADA stands for Supervisory Control and Data Acquisition system.

SCADA is the backbone of automation of all industries. Operators are

able to observe the state of monitored process by simply examining the

data base through display on work stations, control terminals or PCs.

SCADA is composed of remote terminal unit (RTU), communication

system, and control center.

A BRIEF HISTORY

The development of SCADA can be traced back to the early 1900’s with

the advent of telemetry. Telemetry involves the transmission and

collection of data obtained by sensing real-time conditions. The

monitoring of remote conditions became possible with the convergence of

electricity, telegraph, telephone, and wireless communication technology.

Throughout the last century, more industries, such as gas, electric, and

water utilities, used telemetry systems to monitor processes at remote

sites. SCADA began in the early sixties as an electronic system operating

as Input/output (I/O) signal transmissions between a master station and a

Remote Terminal Unit (RTU) station. The master station would receive

the I/O transmissions from the RTU through a telemetry network and then

store the data on mainframe computers.

In the early seventies, DCS

(Distributed Control Systems) were developed. The ISAS5.1 standard

defines a distributed control system as a system that while being

functionally integrated consists of subsystems, which may be physically

separate and remotely located from one another. Large manufacturers

and process facilities utilized DCS primarily because they required large

amounts of analog control. Further development enabled Distributed

Control Systems to use Programmable Logic Controllers (PLC), which

being more intelligent than RTUs, have the ability to control sites without

taking direction from a master.

In the late nineties, the differences

between SCADA and DCS blurred. SCADA Systems had DCS

capabilities. DCS had SCADA capabilities. Systems were customized

based on certain control features built in by designers. Now with the

Internet being utilized more as a communication tool, control functions

that were once old telemetry systems are becoming more advanced,

interconnected and accessible. Automated software products are being

developed to exploit the inter-connectivity of the Internet and certain

portals can connect to a SCADA system and download information or

control a process. Good SCADA systems today not only control

processes but are also used for measuring, forecasting, billing, analyzing

and planning. Today’s SCADA system must meet a whole new level of

control automation, interfacing with yesterday’s obsolete equipment yet

flexible enough to adapt to tomorrow’s changes.

SYSTEM COMPONENTS: SCADA systems typically have four major

elements:

1. Master Terminal Unit (MTU)

2. Remote Terminal Unit (RTU)

3. Communication Equipment

4. SCADA Software

5. TRANSDUCER

1. Master Terminal Unit (MTU)

The Master Terminal Unit is usually defined as the master or heart of a

SCADA system and is located at the operator’s central control facility.

The MTU initiates virtually all communication with remote sites and

interfaces with an operator. Data from remote field devices (pumps,

valves, alarms, etc.) is sent to the MTU to be processed, stored and/or

sent to other systems. For example, the MTU may send the data to the

operator’s display console, store the information, and then send an

operator’s initiate command to a field pump’s RTU.

2. Remote Terminal Unit (RTU)

The Remote Terminal Unit is usually defined as a communication satellite

within the SCADA system and is located at the remote site. The RTU

gathers data from field devices (pumps, valves, alarms, etc.) in memory

until the MTU initiates a send command. Some RTUs are designed with

microcomputers and programmable logic controllers (PLCs) that can

perform functions at the remote site without any direction from the MTU.

In addition, PLCs can be modular and expandable for the purpose of

monitoring and controlling additional field devices. Within the RTU is the

central processing unit (CPU) that receives a data stream from the

protocol that the communication equipment uses. The protocol can be

open like Modbus, Transmission Control Protocol and Internet Protocol

(TCP/IP) or a proprietary closed protocol. When the RTU sees its node

address embedded in the protocol, data is interpreted and the CPU

directs the specified action to take.

Some manufacturers, like EPG’s SCADA division NBT, now make

Remote Access PLCs (RAPLC) specifically designed for SCADA and

Data Acquisition applications. With NBT’s PLC system, you can:

Perform control

Check site conditions

Re-program anytime from anywhere

Have any alarm or event trigger a call to your personal computer

This can all be done from a single, master site and the system can control

one or multiple sites. Both industry representatives and customers

welcome these “smart” PLCs because they provide remote

programmable functionality while retaining the communications capability

of an RTU.

Location of RTUs:

• All 400KV Sub-Station.

• All 220Kv Sub-Station.

• All 132Kv Inter-tie Sub-Stations.

• All Sub-Stations necessary for Network Analysis.

Type of RTUs:

1. Critical RTU: All the RTUs which are located at following stations

-All 400KV Sub-Stations.

-All 220KV Sub-Station.

-Power plants with gross output more than 50MW.

-Critical RTUs shall be supported by two communication channel.

2. Non-Critical RTUs: All the other RTUs are non-critical.

** The specs. For critical and normal RTUs are same.

3. Communication Equipment

The way the SCADA system network (topology) is set up can vary with

each system but there must be uninterrupted, bidirectional

communication between the MTU and the RTU for a SCADA or Data

Acquisition system to function properly. This can be accomplished in

various ways, i.e. private wire lines, buried cable, telephone, radios,

modems, microwave dishes, satellites, or other Atmospheric means, and

many times, systems employ more than one means of communicating to

the remote site. This may include dial-up or dedicated voice grade

telephone lines, DSL (Digital Subscriber Line), Integrated Service Digital

Network (ISDN), cable, fiber optics, Wi-Fi, or other broadband services.

4. SCADA Software

A typical SCADA system provides a Human Machine Interface (HMI)

allowing the operator to visualize all the functions as the system is

operating. The operator can also use the HMI to change set points, view

critical condition alerts and warnings, and analyze, archive or present

data trends. Since the advent of Windows NT, the HMI software can be

installed on PC hardware as a reliable representation of the real system

at work. Common HMI software packages include Cimplicity (GE-Fanuc),

RSView (Rockwell Automation), IFIX (Intellution) and InTouch

(Wonderware). Most of these software packages use standard data

manipulation or presentation tools for reporting and archiving data and

integrate well with Microsoft Excel, Access and Word. Web-based

technology is widely being accepted as well. Data collected by the

SCADA system is sent to web servers that dynamically generate HTML

pages. These pages are then sent to a LAN system at the operator’s site

or published to the Internet.

5 .TRANSDUCER

Data acquisition begins with the physical phenomenon to be measured.

This physical phenomenon could be the temperature of a room, the

intensity of a light source, the pressure inside a chamber, the force

applied to an object, or many other things. An effective data acquisition

system can measure all of these different phenomena. A transducer is a

device that converts a physical phenomenon into a measurable electrical

signal, such as voltage or current. The ability of a data acquisition system

to measure different phenomena depends on the transducers to convert

the physical phenomena into signals measurable by the data acquisition

hardware. Transducers are synonymous with sensors in data acquisition

systems. There are specific transducers for many different applications,

such as measuring temperature, pressure, or fluid flow.

Phenomenon Transducer

Temperature Thermocouple, RTD, Thermistor

Light Photo Sensor

Sound Microphone

Force and Pressure Strain Gage, Piezoelectric Transducer

Position and Potentiometer, LVDT, Optical Encode

Different transducers have different requirements for converting

phenomena into a measurable signal. Some transducers may require

excitation in the form of voltage or current. Other transducers may require

additional components and even resistive networks to produce a signal.

Voltage Transducer:

Input: 110 V

Output: 4 - 20 ma dc

Power Supply: 48 V DC

Accuracy Class: 0.5%

Megawatt /MVAR Transducer:

Input: 1 / 5 Amp

Output: 4 - 20 ma dc

Power Supply: 48 V DC

Accuracy Class: 0.5%

Frequency Transducer

Input: 110 V

Output: 4 - 20 ma dc

Power Supply: 48 V DC

Accuracy Class: 0.1%

USE AND CONTROL OF SCADA:

It provides control and monitoring of the mechanical and electrical utility

systems serving the critical loads.

SCADA control consists of monitoring the state of a critical parameter,

detecting when it varies from the desired state, and taking action to

restore it. Control can be discrete or analog, manual or automatic, and

periodic or continuous.

THE WAY SCADA WORKS:

•DATA ACQUISITION (provides telemetered measurement and status

information to operator)

•PROCESSING OF ACQUIRED DATA. (Process the raw data, checking

of quality, reasonability and conversion)

•DATA EXCHANGE.

•LIMIT / STATUS MONITORING & ALARMING.

•NETWORK STATUS PROCESSOR.

•SEQUENCE OF EVENT RECORDING.

•INFORMATION STORAGE & RETRIEVAL.

•SUPERVISORY CONTROL

(Allows operator to remotely control devices; Circuit breaker open or

close)

PHASOR MEASUREMENT UNITS (PMUs)

History of PMUs

• Invented in 1988 at Virginia Tech

• 1st Commercial PMU in 1992

• 1st Synchrophasor standard: IEEE1344 (1995)

• Updated in 2001: IEEE1344-2001

• Big boost after 2003 US blackout

• Standard updated in 2005: C37.118-2005

• Standard again updated in 2011:

• C37.118.1 – Measurement specifications

• C37.118.2 – Communications specifications

What is a PMU?

A PHASOR MEASUREMENT UNIT (PMU) or SYNCHROPHASOR is a

device which measures the electrical waves on an electricity grid, using a

common time source for synchronization. Time synchronization allows

synchronized real-time measurements of multiple remote measurement

points on the grid. In power engineering, these are also commonly

referred to as synchro-phasors and are considered one of the most

important measuring devices in the future of power systems. A PMU can

be a dedicated device, or the PMU function can be incorporated into a

protective relay or other device.

Reporting following information:

• Voltage Magnitude & Angle (Phasor)

• Current Magnitude & Angle (Phasor)

• Frequency (deviation from nominal in MHz)

• Rate-of-change of frequency (ROCOF in Hz/s)

• Analog user defined data (e.g. sampled control signal or transducer

value)

• Digital user defined data (e.g. status or flag)

PMU Classes (C37.118.1)

• 2 Classes:

– M Class & P Class

• Protection Class: fast response, no filtering required

•Measurement Class: higher accuracy, filtering of aliased signals,

slower response

•User choses what class might be useful for what application

Steady-state requirements

Phasor requirements over a specific

• Frequency range

• Voltage magnitude range

• Current magnitude range

• Phase angle range

• THD range

Applications:

• Real time data analysis

• Low frequency oscillation detection

• Phase angle difference detection

• Voltage stability detection

• Islanding detection

• Oscillation source detection

• Post mortem analysis

• Re-connection after Islanding

• Update state estimator (dynamically)

• Monitor line load

• Automatic load balancing

• Prove valuable input for dynamic system model

Life after Commissioning: Understanding and Tuning Your

Synchrophasor System

One key focus of the synchrophasor community in 2013 is data quality.

Regional coordination entities across the world are collecting

synchrophasor data from utilities and recording metrics on data quality.

This issue of the Synchrophasor Report focuses on tuning your phasor

data concentrator (PDC) configuration to maximize high-quality data.

The phasor measurement units (PMUs) in synchrophasor systems

generate time-stamped data on a synchronized schedule, but the various

network delays between PMUs and PDCs practically guarantee that the

PMU data packets will not arrive simultaneously at their destination. A

core function of the PDC is to time-align synchrophasor data from multiple

sources and serve these data to a client.

Time alignment is the process of collecting all available synchrophasor

data packets with identical time stamps, packaging them into an

aggregate packet, and serving them to a client. As you may have

guessed, time alignment requires the PDC to wait for all packets to arrive

before generating the aggregate packet. To accomplish this, the PDC

uses a timer, often called the “wait timer,” which counts up to a user-

defined maximum wait period. If one or more PMU packets are delayed

beyond the maximum wait period, the PDC will generate and serve the

aggregate packet, omitting the delayed data. Then the PDC will provide

an indication that data from certain PMUs were never received.

What starts the wait timer?

There are two unique methods of time alignment defined by the IEEE

C37.244 Guide for Phasor Data Concentrator Requirements for Power

System Protection, Control, and Monitoring—absolute time alignment and

relative time alignment.

Absolute time alignment means the PDC starts the wait timer on a

Coordinated Universal Time (UTC)-based schedule. This method:

• Requires the PDC to synch to UTC and waits no longer than the

user-defined maximum wait period for data with the equivalent UTC

time stamp.

• Allows a more deterministic packet transmit interval from the PDC,

which can be useful in control applications.

• Benefits client applications that favor minimal latency over data

completeness/quality. Relative time alignment means the PDC starts

the wait timer based on an event, which is typically the receipt of

data with a new UTC time stamp. This method:

• Does not require a synch to UTC.

• Allows latency common to all PMU data to be factored out of

the actual PDC wait time.

• Benefits client applications that favor data

completeness/quality over minimal latency.

Figure 1. Shows an example of each type of time alignment. Notice in

each case that all PMU data packets are received within the duration of

the user-defined maximum wait period.

Fig. 1. Absolute and relative time alignment with no missed data.

SEL’s modern synchrophasor solutions employ relative time alignment for

the sake of data completeness/quality. For latency critical applications,

SEL suggests establishing a dedicated output from your PDC that

includes only the critical data. The remainder of this report will focus

exclusively on relative time alignment.

Figure 2. Shows an example of relative time alignment in a case where

one of the PMU data packets arrives “late.”

Fig. 2. Relative time alignment with missed data.

Note that the PMU 15 packet arrives after the PMU 2 packet’s arrival time

and maximum wait period. As a result, the PDC waits no longer than the

user-defined maximum wait period before closing the time alignment

window and beginning the output processing.

Technical Services

This department supervise the maintenance works like water supply for drinking, ac

plant and testing of generators which are needed anytime for backup power and ac

plant etc.

1. Generator room

2. Ac plant

3. Transformer

4. Water supply system

GENERATOR ROOM:

There are two types of generators in ERLDC, one is 400 KVA, model no. VTA1710

and other one is 125 KVA, both are manufactured by Cummins. These generators

are used for back-up power. Diesel engine is used to run the generator because of

its higher efficiency (as high as 43 – 45 %) and it’s more efficient plant performance

under part loads which is operate at a speed 1500 rpm, 50 Hz frequency. The

manifesto of diesel engine is more oxygen, more power. To achieve this a

turbocharger is used, has two main parts a) turbine b) compressor, it is driven by

exhaust gases, because of this more fuel can burn in the engine and efficiency will

increased.

DG Set as a System

A diesel generating set should be considered as a system since its successful

operation depends on the well-matched performance of the components, namely:

a) The diesel engine and its accessories.

b) The AC Generator.

c) The control systems and switchgear.

d) The foundation and power house civil works.

e) The connected load with its own components like heating, motor drives, lighting

etc.

It is necessary to select the components with highest efficiency and operate them at

their Optimum efficiency levels to conserve energy in this system.

Fig. DG set

Energy Saving Measures for DG Sets

a) Ensure steady load conditions on the DG set, and provide cold, dust free air at

intake (use of air washers for large sets, in case of dry, hot weather, can be

considered).

b) Improve air filtration.

c) Ensure fuel oil storage, handling and preparation as per manufacturers'

guidelines/oil company data.

d) Consider fuel oil additives in case they benefit fuel oil properties for DG set

usage.

e) Calibrate fuel injection pumps frequently.

f) Ensure compliance with maintenance checklist.

TRANSFORMERS:

Electricity in ERLDC, as a bulk consumer, is supplied by Calcutta Electric Supply

Corporation (CESC). Therefore transformers are needed to step down the voltage

6kv to 415v. There are two step-down transformers available in erldc complex but

only one used and other one is for backup. Both transformers are delta-star

connected, rating of 1MVA, 50 Hz, 6000/415 Volts.

AC PLANT:

Chillers are a key component of air conditioning systems for large buildings. They

produce cold water to remove heat from the air in the building. They also provide

cooling for process loads such as file-server rooms and large medical imaging

equipment. As with other types of air conditioning systems, most

Chillers extract heat from water by mechanically compressing a refrigerant.

There are 3 Chillers available at ERLDC, each have a capacity of 40 tons. Two of

them are consecutively used during summer otherwise one chiller is used for cooling

in control room and other departments of grid building.

Mechanical Compression Chillers

During the compression cycle, the refrigerant passes through four major

components within the chiller: the evaporator, the compressor, the condenser, and a

flow-metering device such as an expansion valve. The evaporator is the low-

temperature (cooling) side of the system and the condenser is the high temperature

(heat-rejection) side of the system.

Evaporator

Chillers produce chilled water in the evaporator where cold refrigerant flows over the

evaporator tube bundle. The refrigerant evaporates (changes into vapour) as the

heat is transferred from the water to the refrigerant. The chilled water is then

pumped, via the chilled-water distribution system to the building’s air handling units.

The chilled water passes through coils in the air-handler to remove heat from the air

used to condition spaces throughout the building. The warm water (warmed by the

heat transferred from the building ventilation air) returns to the evaporator and the

cycle starts over.

Compressor

Vaporized refrigerant leaves the evaporator and travels to the compressor where it

is mechanically compressed, and changed into a high-pressure, high-temperature

vapour. Upon leaving the compressor, the refrigerant enters the condenser side of

the chiller.

Condenser

Inside the water-cooled condenser, hot refrigerant flows around the tubes containing

the condenser-loop water. The heat transfers to the water, causing the refrigerant to

condense into liquid form. The condenser water is pumped from the condenser

bundle to the cooling tower where heat is transferred from the water to the

atmosphere. The liquid refrigerant then travels to the expansion valve.

Expansion valve

The refrigerant flows into the evaporator through the expansion valve or metering

device. This valve controls the rate of cooling. Once through the valve, the

refrigerant expands to a lower pressure and a much lower temperature. It flows

around the evaporator tubes, absorbing the heat of the chilled water that’s been

returned from the air handlers, completing the refrigeration cycle.

Chillers are complex machines that are expensive to purchase

and operate. A preventive and predictive maintenance program is the best

protection for this valuable asset. Chillers commonly use more energy than any

other piece of equipment in large buildings. Maintaining them well and operating

them smartly can yield significant energy savings. Nowadays, Chillers are controlled

by sophisticated, on-board microprocessors. Chiller control systems include safety

and operating controls. If the equipment malfunctions, the safety control shuts the

chiller down to prevent serious damage to the machine.

WATER SUPPLY SYSTEM:

Introduction

The water supply system in the ERLDC office complex has an elaborate

arrangement that provides adequate redundancy for maintaining 24 hrs. water

supply to the entire complex. The water supply system caters the supply for drinking

water, make up water for air conditioning plant and rest of the facilities in the

complex. The unique arrangement for the entire supply system depends on three

sources of supply providing adequate redundancy.

Water sources

There are three sources of water as available in the complex

1. Bore well 1: located eastern part of the complex

2. Bore well 2: located western part of the complex

3. Corporation water supply location from southern part of the complex

Reservoirs

There are three reservoirs for the storage of water from where it is lifted to

designated overhead tanks.

Reservoir 1 (location: pump house): for the purpose of intermediate storing

drinking water. This reservoir receives treated water supply meant for drinking

purpose from Kolkata Municipal Corporation (KMC).

Reservoir 2 (location: pump house): for the purpose of intermediate storing

of water for supply to other facilities such as use of water at toilets, bathrooms,

for cleaning & gardening.

Reservoir 3 (location: backyard western part): for the purpose of stand by

storing of water supply of water to overhead tank at Technical block of ERLDC

in case there is a system failure of lifting water from reservoir 2. The real time

monitoring system at the erldc control room has to be kept all times for which

the temperature control of the building is extremely essential. The objective of

this stand by reservoir is to have an independent water supply system for Air

conditioning plant.

Filter tanks:

a) Filter tank 1: the filter tank 1 is used for coarse filter of water.

b) Filter tank 2: the filter tank 2 is meant for fine filter of water.

METERING AND SETTLEMENT

INTRODUCTION

The power system in country is organized in five electrical regions for operation

purpose system namely North, South, East, West and North-east. Eastern region

consists of seven states i.e. Bihar, Jharkhand, Orissa, West Bengal and Sikkim.

Regional Load Despatch Centers are responsible for scheduling and measuring

power within and across the regions. Measurement of electric energy is being

carried out by interface meters called Special Energy Meters (SEMs) installed at the

peripheries of states and regions according to Metering regulation notified by CEA.

POWERGRID being Central Transmission Utility (CTU) is responsible for installation

of SEMs throughout the region and Eastern Regional Load Despatch Center is

responsible for collection and processing the metered data.

OWNERSHIP

These energy meters are owned by the CTU. All agencies/constituents ensure the

security of the energy meters installed in their respective premises.

FACILITIES TO BE PROVIDED AT METERING LOCATIONS

Each agency/constituent makes available the required space and the required outputs of the specified current and voltage transformers, to facilitate installation of energy meters in their premises by CTU for regional energy metering.

SPECIAL ENERGY METERS (SEMs)

Special Energy Meter (SEM) is a Microprocessor based Energy Meter. For metering and data logging it is a handful tool along with data collecting device (DCD) and personal computer. With the use of application software it allows the user to process metered data.

DISPLAY LIST

Display Parameters Display Format Indicator

i) Meter Serial No NP5001 A ii) Date (year month day) yymmdd d iii) Time (hour min. sec.) hhmmss t iv) Cumulative Wh reading xxxxx.x C v) Average frequency of the last block xx.xx F vi) Net Wh transmitted in last block xx.xx E vii) Average % voltage xx.xx U

viii) Reactive power (VAR) xxxx.x r ix) Voltage - high VARh register reading xxxx.x H x) Voltage - low VARh register reading xxxx.x L xi) Real time indication rtC Fit xi) Low battery indication Low Bat

SEM: TECHNICAL SPECIFICATION

01. The energy metering system specified herein is used for tariff metering for bulk,

inter-utility power flows, in different Regions of India. One static type composite

meter is installed for each EHV circuit, as a self-contained device for measurement

of active energy (MWh) transmittals in each successive 15 minute block and certain

other functions, as described in the following paragraphs.

02. The meters is suitable for being connected directly to voltage transformers

(VTs) having a rated secondary line-to-line voltage of 110V, and to current

transformers (CTs) having a rated secondary current of 1 A (model-A) or 5A (model-

B). Any further transformers/transactions/transducers required for their functioning is

in-built in the meters. Necessary isolation and/or suppression is also be built-in, for

protecting the meters from surges and voltage spikes that occur in the VT and CT

circuits of extra high voltage switchyards. The reference frequency is 50Hz.

03. The active energy (Wh) measurement is carried out on 3-phase, 4-wire principle,

with an accuracy as per class 0.2 S of IEC-62053-22:2003. In model-A (for CT

secondary rating 1A), the energy is computed directly in CT and VT secondary

quantities, and indicated in watt-hours. The meter computes the net active energy

(Wh) sent out from the substation bus bars during each successive 15-minutes

block, and stores it in its memory along with plus/minus sign. It also displays on

demand the net Wh sent out during the previous 15-minute block, with a minus sign

if there is net Wh export.

04. Further, the meter continuously integrates and display on demand the net

cumulative active energy sent out from the substation bus bars upto that time. The

cumulative Wh reading at each midnight is stored in the meter’s memory. The

register moves backwards when active power flows back to substation bus bars.

05. The meter counts the number of cycles in VT output during each successive

15-minutes block, and divides the same by 900 to arrive at the average frequency.

This is stored in the meter’s memory as a 2-digit code which is arrived at by

subtracting 49 from the average frequency, multiplying by 50 and neglecting all

decimals. For example, 49.89 Hz is recorded as 44. In case the average frequency

is less than 49.0 Hz, it is recorded as 00. In case it is 51.0 Hz or higher, it is

recorded as 99. The average frequency of the previous

15-minutes block is also be displayed, on demand in hertz.

06. The meter also computes the reactive power (VAR) on 3-phase, 4-wire principle,

with an accuracy as specified in clause 11.0, and integrate the reactive energy

(VARh) algebraically into two separate registers, one for the period for which the

average RMS voltage is 103.0% or higher, and the other for the period for which the

average RMS voltage is below 97.0%. The current reactive power (VAR), with a

minus sign if negative and cumulative reactive energy (VARh) readings of the two

registers is displayed on demand.

The readings of the two registers at each midnight are stored in the meter’s

memory. In model-A (for CT secondary rating of 1 A), the reactive power and

reactive energy transmittals is computed in VAR/VARh directly calculated in CT and

VT secondary quantities. When lagging reactive power is being sent out from

substation bus bars, VAR display have a plus sign or no sign and VARh registers

move forward. When reactive power flow is in the reverse direction, VAR display

have negative sign and VARh registers move backwards.

07. In the model-B (for CT secondary rating of 5A), all computations, displays and

memory storage is similar except that all figures is be one fifth of the actual Wh,

VAR and VARh worked out from CT and VT secondary quantities.

08. The three line-to-neutral voltage is continuously monitored and in case any of

these falls below about 70%, a normally flashing lamp provided on meter’s front

become steady. It go off it all three voltages fall below 70%. The time blocks in

which such a voltage failure occurs/persists is recorded in the meter’s memory. The

lamp automatically resumes flashing when all VT secondary voltages are healthy

again. The two VARh registers specified in clause 7.0 remains stay-put while VT

supply is unhealthy.

09. The whole system is such as to provide a print out (both from the local PC, and

from remote central computer) of the following form:

16 55 +16.28 56 +15.95 55 +15.32 54 +15.66

20 55 +14.93 55 +14.26 54 +14.85 56 +15.17

NP-1234-A 12345.6 01234.5 00123.4 29-03-91

00 57 +14.72 56 +13.83 55 +13.57 53 +12.91

01 52 +13.34 51 +12.76 52 +14.11 52 +15.28

DATA STORAGE This 0.2 class accuracy static energy meter can record integrated average frequency and active energy over every 15 min blocks. The SEM also stores the daily reactive energy flows in low voltage & high voltage conditions. SEM can store data for 10 days. The text file (*.NPC) made from coded files (*.MRI,*.DAT, *.DCD) etc. includes data of one complete day corresponding to the day on which reading is taken and 9 days of complete data for the previous days.

DATA COLLECTING DEVICE (DCDs)

It is basically data collecting device and used to transfer the tapped data from SEM to PC. It has bi -communication with special energy meter along with personnel computer. All these is done with communication cable one at DCD end and other at PC.

CONSTITUENT WISE LOCATION AND QUANTITY S. NO. CONSTITUENT NO. OF LOCATION A-TYPE B-TYPE TOTAL 1 FSTPP (NTPC) 1 27 - 27 2 KhSTPP(NTPC) 1 41 - 41 3 TSTPP(NTPC) 1 27+9 - 27+9 4 BARH (NTPC) 1 2 - 2 5 MPL(RB) 1 8 - 8 6 BSEB 16 29 5 34 7 JSEB 11 20 5 25

8 DVC 12 5 12 17 9 GRIDCO 13 25 1 26 10 WBSETCL 13 18 1 19 11 SIKKIM 1 5 - 5 12 POWERGRID 23 167 - 167 13 WR 4 8 - 8 14 NR 6 13 - 13 15 SR 1 4 - 4 16 NER 3 6 - 6 17 RANGIT 1 9 - 9 18 TEESTA 1 7 - 7 19 BHUTAN 3 18 - 18 TOTAL 113 448 24 472 Total no of location in Eastern region has 113 and out of which power grid has 23 locations. Total no of real meters are 472 (including tie line with NR, NER, WR, SR end) in the region at different locations.

MASTER FREQUENCY METER

It is a special energy meter whose recorded frequency code is used as standard frequency code and is used for region, NR. ER, WR and NER (NEW Grid) and the constituent within the above mentioned Region for any calculation such as Unscheduled interchange (UI) etc. This meter is installed at Korba (WR) end of Korba-Vindhyanchal line. Meter No is NP-2465-A. This meter recorded data is sent by WRLDC to every other RLDC weekly.

SHORT TERM OPEN ACCESS

DEFINITION OF “OPEN ACCESS” IN THE ELECTRICITY ACT, 2003

“Open Access” means the non-discriminatory provision for the use of transmission

lines or distribution system or associated facilities with such lines or system by any

licensee, or consumer, or a person engaged in generation in accordance with the

regulations specified by the Appropriate Commission”.

• Open Access is necessary for utilization of short time surpluses.

• Open Access will also create options for distribution companies to buy power.

• Open Access will provide means to the traders/buyers/sellers.

• Non- discriminatory / Transparent Process

• Freedom to buy/sell power

• Efficient Market Mechanism to address supply / demand mismatches

• Encourage investment in Transmission

•

Agencies involved in Short-Term Open Access Transaction

• RLDC (s)

• SLDC (s)

• CTU

• STU (s)

• Buyer

• Seller

• Trader

Highlights of Regulations for Inter State Trading

• The Inter-State Trading License shall be granted for 25 years

• The application fee is Rs.1 Lakh which is subject to adjustment after the same

is prescribed by the Central Government

• Specifies the methodology for publication of the license application.

• The technical requirements for being an electricity trader stipulates having at

least one full time professional each with experience in

- Power System Operations and commercial aspects of power transfers for 10

years

- Finance, Commerce and Accounts for 5 years

• Four Categories of Trading Licenses ( I to IV )

Customer

• Direct Customer:

Person directly connected to the system owned and operated by the CTU

• Embedded Customer:

– a person who is not a direct customer

• Open Access Customer:

– Consumer permitted by the State Commission to receive supply of

electricity from a person other than distribution licensee of his area of

supply and the expression includes a generating company and a

licensee , who has availed of or intends to avail of open access

• Transmission Customer:

– Any Person including open access customer using transmission licensee

• The transmission customers divided into three categories:

• (a) Long-term Access customers (LTA) - The customers availing or

intending to avail access to the inter-state transmission system for a period of

12 years to 25 years shall be the long-term customers.

• (b) Medium-term Open Access customers (MTOA) - The persons availing

or intending to avail open access to the inter-state transmission system for a

period of 3 months to 3 years shall be the medium-term customers.

• (c) Short-term Open Access customers (STOA) - The persons availing or

intending to avail open access to the inter-state transmission system up to a

period of 3 months but 1 month at a time.

• STOA are categorized into two different ways:

• Bilateral Transaction

• Collective Transaction

Procedure for Scheduling of

Open Access (Bilateral Transaction)

• CERC Regulations on Open Access in inter-State Transmission, 2008 and

amendments thereof

• Applicable for Scheduling of Open Access (Bilateral Transactions)– w.e.f.

01.07.2011

SUBMISSION OF APPLICATION

• Nodal Agency

• RLDC where point of drawl is situated

• Application Contents

• Details -Buyer /Seller /Point of injection/point of drawl/Contracted power

at supplier interface/date/time period

• Application Fee (Rs.5000/-)

• Along with application

• Within 3 working days (for contingency or day ahead transaction) from

the date of Acceptance.

• Endorsement

• Concerned RLDCs/SLDCs

ADVANCE SCHEDULING

Advance Scheduling – 3 months in advance

• Separate Application –

– Month wise - each transaction

• Time Line for submission

– Last date for submission ( -10 / -5 / 0 days prior to end of current month

MO – for transaction in M1, M2, M3)

– Cut-off time of application: 17:30 Hrs. of last day (Day 0)

– day (Day 1)

– Concurrence - by 20:00 Hrs. (Day 1)

– Congestion Information to Applicant – next day 12:00 Hrs. (Day 2)

– Revised Request – next day 11:00 Hrs. (Day3)

– E-bidding – in case of Congestion (next day) (Day 4)

– Acceptance/Refusal of Scheduling Request – (Day 5)

– Request for concurrence (RLDC) – by 12:00 Hr. next

E-Bidding Procedure

• Invitation of Bids from the concerned applicant

– period of congestion

– RTS/IR corridor – expected to get over stressed

• Only Registered Users

– User ID & Password

– Electronic submission – website of CTU

– Bid Closing time as specified

– Single Price Bid

– No Modification/withdrawal once submitted

• Bid Price - in addition to Open Access Transmission Charges

• Multiples of Rs.10/ MWh( Min. Rs.10/MWh)

• Mandatory - Non-participation – Rejection of Application

• Acceptance - Decreasing order of Price Quoted

• Equal Price Bids – Pro-rata

• Applicants getting less quantum than applied shall pay the charges quoted by

him.

• Applicant getting equal quantum of what sought by him shall pay the charges

quoted by the last Applicant getting approval of its full scheduling request.

“FIRST-COME-FIRST-SERVED” BASIS

• Scope

– FCFS shall be considered only when transactions are commencing &

terminating in the same calendar month.

• Separate Application for each month

• To be submitted 4 days prior to date of Scheduling

• Processing time – 3 days

• Processed on FCFS basis

• Application Received up to 17:30 Hrs. in a day to be processed together –

same priority

• Application Received after 17:30 Hrs. - consider as received on next day

• Congestion Management – pro-rata (proportional)

Agencies involved in Short-Term Open Access

Collective Transaction

• Power Exchanges (IEXL & PXIL)

• NLDC

• RLDC (s)

• SLDC (s)

• CTU

• STU (s)

• Buyer

• Seller

• Portfolio Trader

Procedure for Scheduling of

Open Access (Collective Transaction)

• CERC Regulations on Open Access in inter-State Transmission, 2008 and

amendments thereof

• Applicable for Scheduling of Open Access (Collective Transactions)– w.e.f.

01.07.2011

Bidding procedure

• Time Line for submission of bid

• 10 a.m. to 12 a.m. of preceding day

• NLDC communicates the margin to PX at 11:00 hrs.

• During the bid hours the bid can be revised or cancelled.

• Volume and price of the bid submitted by market players are stored in central

order book.

• Matching of bids for each 15 minute time block in carried out.

• Price Determination Process (Provisional) the aggregate supply and demand

curves will be drawn on Price-Quantity axes. The intersection point of the two

curves will give Market Clearing Price (MCP) and Market Clearing Volume

(MCV).

• Successful members will be provided with clearing price and volume.

• After working out of provisional obligation funds available in the settlement

account of the Members shall be checked with the Clearing Banks.

• In case sufficient funds are not available in the settlement account of the

Member then his bid (s) will be deleted from further evaluation procedure.

• Requisition for capacity allocation will be sent to NLDC at 13:00 hrs.

• NLDC at 14:00 hrs. Send the available margin to the PXs.

• Power Exchange at 14:30 hrs. Will run the fresh iteration for final MCP and

MCV.

• Obligations will be sent to the bank of buying members at 14:30 hrs. For

settlement.

• At 15:00 hrs. Cleared volume will be send to NLDC for incorporation in

schedules.

• At 16:00 hrs. NLDC sends the cleared volume to respective RLDCs.

• At 15:30 hrs. NLDC shall confirm the accepted schedule to PX.

• At 18:00 hrs. RLDC issues schedule Rev-0.

Characteristics of Day ahead market

• Bid is submitted for 96 blocks of 15 min. each

• Minimum volume for bidding is 0.5 MW

• Minimum volume step is 0.1 MW

• Minimum quotation is 0.1 MW

• Auction type: closed auction with linear interpolation

• Settlement system : on daily

REFERENCES

www.erldc.org

www.cea.nic.in

www.erpc.gov.in

Wikipedia