REVIEW OF DETAILED PROJECT REPORT OF KESCO

Study by ERDA on review of DPR of KESCO

REVIEW OF

DETAILED PROJECT REPORT

OF

KESCO

DATED 23rd FEB 2005

Study by ERDA on review of DPR of KESCO DATED 23rd FEB 2005

ii

CONTENTS Sr. No. Title Page

No. Foreword v Acknowledgement vi Scope vii

SECTION – 1 Review of DPR 1.1 Introduction 11.2 Strategy for Improvement in Sub-Transmission &

Distribution System: 2

1.3 Existing System 4 1.3.1 Declared Loss 4 1.3.2 Commercial Performance 4 1.3.3 Number of Complaint Centers 5 1.3.4 Single Line diagram 6 1.3.5 EHV Sub-Station 6 1.3.6 HV Substation 7 1.3.7 Connection from EHV to HV sub-station 9 1.3.8 11kVfeeders emanating from HV sub-station 10

1.4 Status on metering on feeders 11

1.5 Status on metering at consumers 13

1.6 Requirement of customer indexing/ metering 15

1.7 Requirement of Capacitors 17

1.8 Requirement of Relays 18

1.9 Statement of Distribution Transformer failure 19

1.9.1 Outage data of feeders on account of DTs 20

1.10 Distribution Transformer R&M (Improvement in LT Sub-station)

21

1.11 Overloading of the Transformers 22

1.12 Requirement of Power Transformers 23


iii

Sr. No. Title Page No.

1.13 Feeder details 24

1.14 Reliability Index 25

1.15 Conclusion 26

SECTION – 2 Model Guidelines for Evaluation of Investment Proposals for Distribution Schemes under APDRP

2.1 Introduction 302.2 Technical & Commercial Loss 32 2.2.1 Technical Loss 32 2.2.2 Commercial Loss 33 2.2.3 Measures for reducing Non-technical loss 332.3 Commercial Performance 352.4 Consumer Metering, Billing and Collection 38 2.4.1 Metering 38 2.4.2 Billing 39 2.4.3 Industrial consumer 40 2.4.4 Use of Electronic TOD (Time of day) Maximum

demand meters (MD) 40

2.4.5 Domestic Light and Fan, commercial consumer 42 2.4.6 Meter testing facility 42 2.4.7 Improved metering 44 2.4.8 Periodic Test Schedule for Meters 442.5 System Metering 462.6 Consumer Indexing 482.7 Distribution Transformer 49 2.7.1 Overloaded/ Under loaded distribution transformer 49 2.7.2 Providing distribution boxes on distribution

transformer 50

2.8 Power transformer 51


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Sr. No. Title Page No.

2.8.1 Overloading/ new power transformer 512.9 Capacitors 52 2.9.1 Requirement of capacitors 52 2.9.2 Installation of Capacitors 52 2.9.3 LT Capacitor 52 2.9.4 Pedestal mounted HT capacitor 532.10 Renovation, Strengthening & New substation (feeder

up gradation) 55

2.10.1 Creation of new substation 582.11 Guidelines for system development 612.12 System Studies 632.13 Optimum Utilization of Resources 662.14 Procedural Clearance 682.15 Cost benefits 70

2.16 Documents to be provided with DPR 712.17 Conclusion 73


v

FOREWORD

In the initial stage of power development in the country, power supply facilities

and Transmission & Distribution (T&D) systems were built mainly catering to

urban areas/ towns to feed mostly domestic and commercial loads. After

independence, with the importance given to power development in the five-year

plan programmes, the extent and reach of electricity has undergone dramatic

changes. With thrust on programme for rural electrification and large-scale

energization of pump sets from 3rd five year plan onwards, the sub-transmission

and distribution networks were expanded rapidly. However, this expansion was

very often without adequate studies to evolve optimal network and this resulted in

characterizing distribution systems with poor voltage regulation and increased

losses. With the implementation of APDRP programme the much needed

improvement in the distribution sector has started taking place. Utilities have

drawn out plans for the augmentation of their distribution and sub transmission

system. Many times the investment required is large. The project report submitted

by the utilities has to be evaluated by the funding agency in terms of the benefits to

the consumers and returns to the power suppliers. The evaluation should be done in

a comprehensive manner to cover all the technical and commercial aspects keeping

in view the global standards and the targeted benchmarks

This report gives comments on the DPR submitted by KESCO to UPERC. This

report is made into two sections. The Section-1 gives a detailed review of the DPR

and Section-2 gives the guidelines for evaluation of proposals under APDRP.


vi

Scope A) The scope of the study was to examine the schemes submitted by

UPPCL/DISCOMS for the following:

1. For their completeness

2. Optimum utilization of resources

3. Techno economics

4. Procedural clearances

5. System studies

6. Cost benefits

7. Observations furnished to licensees

8. Interact with licensee to analyze existing system status and its

inadequacies; reasonable assessment of load growth, reduction of

losses/ voltage profile improvement, and reliability

9. The APDRP scheme shall be examined for – increase in revenue

realization, increase in metered energy, billing and commercial losses

and outages; whether it meets growth in demand, and optimum cost/

benefit analysis.

B) Based on best expertise and resources available with ERDA, ERDA

has developed Model Guidelines for Commission to examine the capital

expenditure and prudence of investment schemes in APDRP Project/ DPR

submitted by UPPCL/DISCOMS, from the standpoint of (i) Technical

prudence and (ii) Financial prudence.


vii

SECTION 1


viii

REVIEW OF DPR


1

Introduction

The detailed project report submitted by KESCO to UPERC for APDRP project

has been referred to ERDA for examination. ERDA has carried out in depth

study of the DPR and examined all the proposals made in the DPR based on the

data submitted by KESCO and the prevalent guidelines. ERDA has also taken

into account its experience as an Advisor Cum Consultant (ACC) for the

APDRP project in the Sabarmati circle of Gujarat Electricity Board and its

experience acquired during the field work for energy auditing services for Agra

(UPPCL) and Kanpur (KESCO) to UPERC while assessing the DPR. The

project report has been examined for its completeness, optimum utilization of

resources, techno-economics and cost benefits

1.1


2

1.2 Strategy for Improvement in Sub-Transmission & Distribution System

The formulation of a project report for upgradation of system for the

identified circle should be taken up in two phases:

•Short Term Plan

• Long Term Plan

Short Term Plan:

In the prevailing situation of mounting energy losses, Priority attention need

to be given to achieve the objective of loss reduction especially for reduction

of commercial losses as well as technical losses in the short-term plan. The

short-term plan shall cover the measures required for immediate

improvement and reduction of losses and shall be based upon the

information/ data readily available with the utilities. The works identified as

short term should be completed within 1 to 2 years.

Long Term Plan:

The long term plan will cover all the measures for improvement of quality

and reliability of power supply and reduction of T & D losses in the circle by

upgradation, strengthening and improvement of the sub transmission &

distribution system in a circle to meet the load demand for next 5 years. The

proposal will be prepared through the proper analysis of the system based

on detailed system studies.

In the DPR submitted by KESCO, completion period given is 24 months.

Hence, it is clear that in the DPR is for short-term plan.


3

The broad activities/ works for preparation of a short-term plan are:

• Energy Accounting/ Energy Audit

•Network documentation-Single Line Diagram/ Geographical map up to 11

kV level

• Estimation of T & D losses/ Segregation of losses

•Technical power loss reduction

• Commercial power loss reduction

• Preparation of cost estimates

• Financial Analysis

In the report submitted by KESCO final benefits are given and no basis of

arriving at these figures of benefits are given. Normally, it is expected from

the consultant to give detailed working of each sample where the basis for

computation of benefits is also given. These details are very important

because in absence of these details, problems may occur at the time of

implementation of the project and its assessments when the work is

completed.


4

1.3 Existing System

1.3.1 Declared Losses:

The declared Technical loss is 8 % and it is within the permissible limits and

effort has to be made to reduce the level of commercial loss in the

system. The main factors responsible for high-energy losses are:

> Theft/ pilferage by consumers

> Illegal connections from distribution line

> Illegal use of energy/ under billing

> Defective meters

> At site Calibration of Consumer Meters

> Lack of accountability

> Lack of scientific management principles and human resource

development

> Complicated legal process

1.3.2 Commercial Performance:

According to DPR Commercial Performance in the past 4 years is as

follows :

Particular 2000-01 2001-02 2002-03 2003-04 Metering Efficiency

68 % 67 % 57 % 58 %

Billing Efficiency

68 % 67 % 57 % 58 %

Collection Efficiency

71.31% 78.71% 60.92% 68.88%


5

Efforts have been made to increase all the above three efficiencies as

quickly as possible. The significance of the metering efficiency is that all

meters installed at the consumer end should be in running condition so that

true energy is metered.

Replacement of defective meters and collection must be given top priority to

get fast result.

1.3.3 Number of complaint Centers

According to DPR number of complaint Centers are as follows :

Name of complaint center

Mode

Electricity House

Naubasta

Fazalganj

Telephone & Personnel Service

Only three complaint centers for four lac consumers is not adequate. Exact

assessment cannot be done but average number of complaints per day is 556

nos. (of all categories), i.e. approximately on an average 185 nos. of

complaints per complaint centre and this appears to be reasonable but time

taken for attending to the complaints is on an average twelve hours. which is

too high. To reduce the time of attending the complaints, number of

complaint centers should be increased and methodology of attending to the

faults also should be improved. Implementation of GIS will also help in

reducing this time.


6

1.3.4 Single Line Diagram:

The technical data of the circle should include electrical single line diagram

of the system, physical diagram showing geographic location of sub station

and line, single line diagram for each EHV & HV substation, Geographical

diagram showing location of HV sub station, routing of 11 kV feeders and

location of distribution transformer for the feeders which have been

proposed for inclusion.

1.3.5 EHV Sub Stations:

According to DPR, details of EHV Sub Stations are as follows :

SR NO.

Name of EHV substation

Transformer capacity (MVA)

Maximum demand (MVA)

1 Azad Nagar 100 110

2 Panki 400 163

3 Krishna Nagar 100 109

4 Dada Nagar 20 18

5 Naubasta 180 103

6 R.P.H 120 103

The Azad Nagar, Krishna Nagar and Dada Nagar substation transformers are

marginally overloaded. Hence, effort has to be made to augment the


7

capacity, ensure better reliability of power. These substations are managed

and controlled by UPPCL.

1.3.6 HV Sub Stations:

According to DPR, the following substations are overloaded :

Transformer capacity

Sr. No. Name of Substation

Nos Capacity in MVA

Total MVA

Maximum Demand in MVA

1 Kalyanpur 3 3x5 15 17

2 B S Park 2 10+5 15 18

3 Gumti 2 8+5 13 14

4 Govind Nagar 2 5+10 15 17

5 Vidyut Colony 2 2x5 10 12

6 H-Block (Kidwai Nagar)

1 1x5 5 7

7 Naubasta 3 2x10+1x5 25 26

8 Hanspuram 1 1x8 8 10

9 Delhi Sujanpur 3 2x5+1x10 20 22

Total 19 - 126 143


8

Six new substations are proposed to take care of the overloading of the

existing substation which are over loaded.

Proposed new 33kV Sub-stations are

1) Jawahar Nagar,

2) China Park,

3) Pashupati Nagar,

4) Mandi Parishad,

5) Indira Nagar,

6) Medical college,

The detail as listed below should be given for all the new six sub-stations to

have clear idea at the time of implementation

Following important points are to be considered for creation of new sub-

stations,

1) Existing system status of the HV sub-stations,

2) Single Line Diagram of the proposed sub-station,

3) HV system power loss, voltage regulation,

4) Existing and modified status of the 11/6.6 kV feeders,

5) Calculation of Diversity factor (DF), Load factor (LF) and Loss

load factor (LLF) ,

6) Loss status,

7) Benefits due to the scheme,

8) Estimates,


9

9) 11/6.6 kV feeder map with existing position,

10) 11/6.6 kV feeder map with modified proposed position

The augmentation of power transformer capacity will take place for above

substations. Also from data submitted by KESCO it is found that

approximately 50 % of transformers are loaded beyond 80 % and above as

per 2.3 of DPR, hence augmentation can also be proposed for the same.

1.3.7 Connection from EHV to HV Sub-Station

In most of the feeders, the conductor used is Dog and cable of the size 240

mm2 hence the loading is within the limits. According to ERDA study, there

are about seven cases only where the voltage regulation is poor. For

improvement of voltage regulation, nine feeders are proposed in the DPR.

The details of all should be given as listed below:

1) Annual load growth

2) Existing system status HV substation details,

3) HV substation and feeder details before and after modification

i.e. loading and voltage regulation

4) Losses before modification

5) Existing distribution system without modification and after

modifications,

6) Benefits due to scheme,

7) Estimate,

8) Expected % voltage regulation and losses status after

modification


10

1.3.8 11kV feeders emanating from HV sub-station

The power factor (pf) worked out from the readings of MW and MVA will

not be exact but will give indicative idea of the system. The calculated pf. is

in the range of 0.8 to 0.85, which is poor and can be improved by providing

reactive power compensation, which will reduce the losses and also will

improve the voltage regulation


11

1.4 Status on Metering on Feeders

According to DPR, the Status on metering on feeders & DTCs is as

follows :

Nos. of Feeders Metered provided Electronic

Meters

requirement

Voltage

class

Direct Interconnecting Electro

mechani

cal

Electro

nic

Data

Logging

type

33 kV

feeders

48 20 0 68 0 Nil

11 kV

feeders

265 18 0 226 0 57

11-6.6

/0.44

kV

DTC

Meters

2386 0 0 0 0 2386*

* Only 500 DT will be covered in this scheme

The meters in the sub-stations and 11 kV feeders should be modern

electronic trivector meters of 0.5 class accuracy with load survey capability,

data logging features, down loading facilities through Common Meter

Reading Instruments and provision for export/ import recording as per

requirements of specific locations.


12

DT meters considered is only 500 in the DPR. If this is raised to 750, it will

give faster results of energy Accounting and pin pointing the loopholes. The

improvement of metering of the DTs will not directly help in reduction of

losses but will be helpful through Energy Accounting.


13

1.5 Status on Metering at Consumers

According to DPR, the Customer Metering status is as follows:

Sr.

No.

Category Total

Number

Proposed for

Replacement

Balance

1 Industrial 6423 1200 5223

2 Commercial 68141 19000 49141

3 Domestic 339396 40000 299396

It can be seen that out of 50%(i.e. about 2 lack) customer, only 60200 nos. of

meters replacement is planned which is only 11%. More funds for this

should have been provided for replacing for ex. one lack meters which will

give benefit of 23 units/ installation against capital investment of Rs.1100

lacks i.e. the pay back period will be 20 months.

It is not clear whether the proposed meter replacement plan is for the first

phase or final phase. From the report it is observed that 353760 customers

are having good meters and only 60200 consumers require replacement. But

according to the ERDA report (P-49 of ERDA report), 50 % of the billing

done in KESCO is based on NA / NR / DF / ADF / RDF / CDF where,

NA Consumer Not Available

NR Not Readable,

IDF Instrument Defective,

RDF Reading Defective,

ADF Appeared Defective,

CDF Ceiling Defective


14

In light of this, the replacement of meters has to be stepped up to have

quicker result with lesser investment. The Commercial and Industrial

connections should be given priority.


15

1.6 Requirement of Customer Indexing/ Metering

According to DPR, the requirement of customer indexing/ metering is as

follows :

Benefit* Sr.

No.

Item Quantity

In LU In lakhs

1 Consumer

meters-1∅

40000 110 267.3

2 Consumer

meter-3∅

19000+1200 100 471

3 Feeder meter 57 10 33.7

4 DT meter 500 20 67.4

* No working is provided in DPR

KESCO has planned to change 40000 old meters in the domestic category of

consumers and is expecting an annual increase in the metered energy of 110

LU which is a substantial benefit. This will give the pay back period of

4years on investment for buying quality/ static meter.

In the DPR, benefits are shown against the replacement of quality/ static

meter for feeder and DTs but this is not correct. This is only useful for

energy auditing and identifying high loss consumer area as stated on Pg 2 of


16

APDRP report for KESCO, while in the same report a benefit of Rs 101.1

lack is shown.

Under the benefit column the basis of the benefit in LU and Rs. Lac is to be

explained for each category. According to the clarification now received

form the KESCO this is their rough assessment. It is felt that this does not fit

in properly. Some scientific reasoning is required.

From the data given in the table that the pay back period is less than two

years, hence it is recommended to divert more funds for this activity for

quick return.


17

1.7 Requirements of Capacitors

It is reported that there is no requirement of Capacitors but as can be

computed from table 2.6 P-17 of DPR that the power factor of the system is

between 0.80 and 0.85 this means that adequate compensation is not

available at load centers. In ideal system the power factor is maintained at

0.9 to 0.95 by providing required reactive power compensation which will

improve the quality of power and will reduce losses and improve the voltage

regulation.

It is also seen that the power factor or the MVA readings are not the meter

readings but assessed readings by assuming one of the factor i.e. MVA or pf.


18

1.8 Requirement of Relays

In this report this is shown as “ not required “ but for new Power

Transformers and new feeders protection relays are required and the Table

8.1 should be completed as this also will be required at the time of

implementation unless cost of Power Transformers proposed includes this.


19

1.9 Statement of Distribution Transformer Failure

According to DPR, the statement of DT failure is as follows :

SR

NO.

Capacity of DT Total nos. of

DTs

Nos. of DTs

failed.

Failure rate

in %

1 Less than 25 kVA 18 2 11

2 25kVA 29 38 131

3 63 kVA 75 24 32

4 100 kVA 234 39 17

5 Above 100 kVA 2030 715 35

6 Total 2386 818 34

Sr. No. 2 - 25 kVA the % failure is 131%. How is this possible ?

Major failure rate is for Transformers of capacity of more than 100 kVA.

This is because they are over loaded as shown in10 P-38 of DPR, and action

also is to be taken as per 11.2 P-39 of DPR. This should be given utmost

priority.


20

1.9.1 Outage data of feeders on account of DTs

According to DPR, the outage data of feeders on account of DTs is as

follows :

Name of feeder

No of outages during reference period

Duration of outages

Number of DTs failure

< 5 Mins > 5 Mins 265 feeders (break up not available)

NA 10 min average

31min/feeder 818

It is not clear whether this outage is monthly or yearly. Even if this is

monthly it is a very good condition and nothing is required to be done to

reduce this outage durations.


21

1.10 Distribution Transformer R&M (Improvement in LT Sub-Station)

It is stated that by providing earthing there will be a benefit of the order of

Rs. 14.5 lac. How this benefit is achieved is not explained. No supporting

calculations are available in the report. The configuration of LT distribution

lines is not received. In the absence of these details and some additional

information required about the grounding of the neutral, (whether it is

grounded at the transformer or is a multiple grounding earth system) the

verification of this benefit cannot be done .


22

1.11 Overloading of the Transformers According to DPR, the Overloading of the transformers are as follows

Sr. No. Substation Name Duration of Overload

(Hours)

1 Naubasta 300

2 Hanspuram 250

3 D. Sujanpur 300

4 Vidyut Colony 200

5 Govindnagar 300

6 K. Nagar 350

7 Kalyanpur 200

8 B. S. Park 200

9 Gumti 50

It is seen that out of the nine sub-stations only in three substations there is

overloading of the transformer during peak hours as listed below. It is not

clear how the number of hours of overloading is computed.

i) Hanspuram

ii) D. Sujanpur

iii) Kidwai Nagar

There is a proposal of adding 90 MVA Power Transformers capacity in the

system which will take care of the overloading of these transformers and

also take care of load growth to some extent


23

1.12 Requirement of Power Transformers

The augmentation of power transformer will be done in nine substations as

given in the DPR submitted by KESCO. It is also proposed that nine new

power transformers will be installed at these substations. The annual load

growth rate of KESCO has been taken as per ARR of KESCO as 5% in FY-

04, considering the load and energy pattern of KESCO for the last financial

year. By augmentation of power transformers & new power transformers

possibility of overloading can be reduced.

The revised cost of the 10.0 MVA Transformers shown as 17.0 lac is also on

the lower side. This may be checked.


24

1.13 Feeder Details (a) The strengthening cost of 33 kV feeder is given as Rs. 17.9 Lac/ kM

The cost of a new 33 kV line is Rs. 7.66 Lac./ kM, This discrepancy is

not explainable.

(b) The cost of 11 kV new line is taken as Rs. 22 Lac./ kM, which is too

high.

(c) The cost of 11 kV line re-conductoring is taken as Rs 1.6 Lac/ kM but in

absence of the knowledge of the size of the conductor it is not possible to

comment on this.

(d) If this includes the use of higher size conductor and adding supports, if

required, the cost shown appears to be less.

(e) New LT lines using (ABC conductors) are configured for three wire

systems but the conductor size is not specified.


25

1.14 Reliability Index Normally after implementation of the APDRP, the Reliability is expected to

have improved and to demonstrate this the Reliability Index working is

necessary and this is not specified in the report.


26

1.15 Conclusion The DPR review has brought out the following observations:

1. Acceptable bench mark norms for losses are not specified and the

projected loss reduction due to implementation of suggested schemes

may not be realistic.

2. While computing the increased revenue due to system improvements

and suggestions, the norms used and computation methodology are

not given.

3. The cost figures used for new feeders, strengthening of feeders new

transformers and substations appear to be on the high side.

Accordingly the overall investment required for implementing the

proposed schemes should be checked.

4. No importance is given to improvement of power factor in the report.

Higher power factor means lower losses. It is, therefore, necessary to

assess the quantum of additional reactive power requirement to

improve the power factor.

5. Increasing the percentage of metered energy and replacing old and

defective meters with electronic / quality meters will result in higher

billed energy and reduce the non technical losses. This benefit is

achieved in the shortest possible time and so it is desirable for short-

term plan for system improvement. Therefore, more emphasis should

be placed on the use of new meters.

6. The schemes proposed in the DPR for system improvement are in

general acceptable. They fall in line with prevailing philosophy.


27

However, the number of feeders considered for strengthening and the

number of new meters or meters replacement proposed and the

suggested number of transformers with higher rating to reduce the

possibilities of overloads and thus by improving the reliability of the

system and reduce the system outages requires a review.

If this scheme is restricted due to financial constraints, then the

present DPR should be considered as phase 1 of the plan for overall

system improvement.

7. To avoid any further delay in implementation of the proposed

schemes, it is suggested that the DPR as it is submitted may be

approved and the requested amount be sanctioned to enable KESCO

to start the work immediately


28

SECTION 2


29

MODEL GUIDELINES FOR

EVALUATION OF

INVESTMENT PROPOSALS

FOR DISTRIBUTION

SCHEMES UNDER

APDRP


30

2.1 Introduction

In the initial stage of power development in the country, power supply

facilities and Transmission and Distribution (T&D) systems were built

mainly for catering to urban areas/ towns to feed mostly domestic and

commercial loads. After independence, with the thrust given to power

development in the five-year plan programmes, the extent and reach of

electricity has undergone dramatic changes. With the thrust on programme

for rural electrification and large-scale energization of pump sets from the

3rd five-year plan onwards, the sub-transmission and distribution networks

were expanded rapidly. However, this expansion was very often without

adequate studies to evolve optimal network, size and location of sub-

stations, adequacy of back-up sub-transmission etc. Further the rise in

industrial and agricultural pumping load increased the reactive power

requirements. Adequate attention has not been given to compensate this

reactive demand, which resulted in poor voltage regulation and increased

losses. Hence, distribution systems are characterized by high T&D losses,

poor voltage conditions, frequent interruptions/ outages etc.

The sub transmission and distribution system was completely neglected and

haphazard expansion was done without any planning which resulted in

extremely poor quality of system with high losses in the system . Ministry of

Power (MOP) decided to give top priority for the improvement of

distribution sector and came out with a scheme known as Accelerated Power

Development Programme (APDP), which is now termed as Accelerated

Power Development and Reforms Programme (APDRP). MOP initially

identified 63 distribution circles belonging to different states for improving/


31

strengthening of the sub-transmission and distribution networks in such a

manner so as to develop centers of excellence within the utility to enable the

state to replicate the same latter in their entire distribution system.

In 4 years of this program there was substantial improvement in the

performance of the identified distribution circles and therefore MOP

extended this programme to cover more circle and the present DPR is the

result of that.

As a normal practice the DPRs are required to be vetted by an independent

consultant. Accordingly, ERDA is given this responsibility to evaluate the

investment proposal from Techno-economic criterion.


32

2.2 Technical & Commercial Loss 2.2.1 Technical Loss:

The technical losses are due to energy dissipation in the conductors and

equipments used in the system for transmission and distribution of power.

The magnitude of energy dissipation depends largely on the design of lines,

pattern of loading of transmission and distribution lines, types of loads,

equipments (transformers), etc. It is not possible to eliminate such inherent

losses in a system altogether. This could, however be reduced to some extent

by better design of lines, re-location of distribution sub station, installation

of capacitors, use of higher efficiency transformers and regular system

upgradation. The typical level of losses in the various segment of the system

could be considered as under :

ZONE SYSTEM ELEMENTS POWER LOSS (%)

A Step-up transformer & EHV transmission

system

0.50% to 1.00%

B Transformation to intermediate voltage

level, transmission system & step down to

sub-transmission voltage level

1.5% to 3.00%

C Sub-transmission system and step down to

distribution voltage level

2.25% to 4.50%

D Distribution lines and service connections 4.00% to 7.00%

Total losses 8.25% to 15.50%


33

These losses depend on the pattern and nature of demand, load density and

the capability and configuration of system; equipment used and vary for

various system elements. However, systems where total percentage loss lies

beyond these range of values should become a matter of serious concern and

further study and analysis should be carried out. Targets for reduction of

technical losses should accordingly be fixed, measures identified and action

taken to accomplish the same within the given time period

2.2.2 Commercial Loss:

Commercial or unaccounted losses are caused by theft of energy, meter

tempering, defective meters, meter reading errors, error in estimation of

unmetered supply etc. While it may be difficult to accurately segregate this

loss into various elements, there is absolutely no reason why unaccounted/

commercial losses, especially theft of energy and deficiencies in metering

cannot be eliminated.

2.2.3 Measures for reducing non-technical losses:

(1) Set up vigilance squads comprising engineers and police officers for

conducting surprise check at the consumer premises to detect

pilferage of energy and intensify surprise inspections/ raids, to detect

cases of malpractices and pilferage of energy.

(2) A multidisciplinary vigilance set up in the utilities with personnel

having engineering, legal and police experience should be established

to provide knowledge and expertise in framing suitable policies and

mechanisms for detection and follow up action on cases involving

theft of energy.

(3) The special vigilance groups for tracing the unauthorized consumers

and direct tapping from lines may inspect the feeders periodically.


34

(4) Severe penalties may be imposed for tampering with the meter seal

etc.

(5) Initiate publicity campaign to depict theft of electricity as a social and

economic crime and inform the public regarding provisions in

electricity laws in this regard.

(6) The monthly consumption of industrial consumers should be carefully

watched and any major variation in consumption should be analyzed

and investigated for possible reasons.

(7) Installation of tamper-proof meter boxes and use of tamper proof

numbered seals.


35

2.3 Commercial Performance For good commercial performance, the following should be on higher side in

the range 80 to 100 %.

(i) Metering Efficiency

(ii) Billing Efficiency

(iii) Collection efficiency

(1) Metering Efficiency:

It is defined as the ratio of metered energy to actual energy consumed.

The significance of the metered energy is that all the meter installed at

the consumers end should be in running condition so that energy

assessed should be as accurate as possible.

(2) Billing Efficiency:

It is defined as the ratio of billed energy to the metered energy.

(3) Collection Efficiency:

It is defined as the ratio of revenue collected to amount billed.

For proper energy billing, revenue collection and analysis of large volume of

energy related data, it is necessary to install “Computerized system” at each

billing center.

The system should have an on-line browsing consumers’ ledger, apart from

other facilities.

It may have the facility to carry out the following functions:


36

▪ Billing for different categories of consumers

▪ On the spot billing

▪ Making corrections in the bill

▪ Interactive revenue collection mechanism

▪ Verification of bill with out-of-norm consumption pattern

▪ Sample check to detect under / over billing

▪ Monthly payment on normative basis, with billing on actual, once in

three months for rural area

▪ Identification of meter reader

▪ Generation of MIS report indicating the deviation in energy

consumption pattern for different categories of consumers

▪ Generation of reports where the bills are not paid by the consumers

All entries should be done in the Computer System by authorized persons.

He should have security code which may indicate the name of the person

who has made corrections or changes in the energy bill of the consumers(s).

In case of HT consumers, scrutiny/ check may be carried out by senior

officers in the sub division/ division and in case of LT consumers, regular

sample check may be done.

The responsible officer of the Circle may ensure that HT bills are issued

directly to the respective consumers and the revenue is realized by due date.

As soon as bills are prepared and distributed, list of consumers who are in

arrears may be printed through computer billing system for taking action of

disconnection.

Such list could be generated category-wise (residential, commercial,

industrial etc.), amount-wise (say up to Rs. 5,000/-, between Rs.5,000/- and


37

25,000/-) and period wise (arrears for period less than 3 months, 3 to 6

months and more than 6 months).

It is the responsibility of the concerned officer to promptly disconnect the

supply of defaulting consumers.

In order to identify the revenue loss in a circle, revenue balance sheet may

be prepared. This may be computed by taking into account the total energy

received in a circle and its average cost at the receiving points as well as

revenue realized from consumers for the same period.

The revenue realized may be worked out from the figures of energy

consumed by various consumers and tariff applicable in their case.


38

2.4 Consumer Metering, Billing and Collection

2.4.1 Metering

Average figure of losses in the sub transmission and distribution network in

India is much higher as compared to advance countries. Metering is one of

the most important elements contributing to higher commercial losses. There

are a number of other elements responsible for increase of commercial

losses. However, metering is one which can be tackled on priority and

achieve results with in a short time. This can be done by replacing old

meters by new quality / static meters.

The benefits due to replacement of meters depend upon many factors but it

is observed that on an average 22.5 units extra energy is recorded per month

per installation. This can be taken as a norm for assessing the cost-benefits

involved.

The utility has to identify pockets where the losses are more and

immediately replace all the meters in that area.

This necessitates restructuring and improvement of distribution system. This

can result in reduced figure of distribution system aggregate losses. The pre

requirement for restructuring transmission and distribution system is

installation of good quality of energy meters, at all relevant locations in the

power system network for accurate loading of the quantum of energy

handled by system. Being the major party in the power sector, it is

considered as the foremost duty of the power utility to analyze the metering

system and monitoring methods employed in their distribution system.


39

It has been proved by field studies that faulty status of the meters, age of the

meters, improper connections of CT units, inadequate metering etc. add

directly to the losses in the system. In a particular feeder under survey, when

quality meters replace the old meters, the energy billing can be increased.

Hence, in order to have well-defined accounting procedure, the old meters

have to be replaced with static meters or quality meters.

2.4.2 Billing

Billing is the most important aspect in a system. Employing proper metering

system, providing intelligent methodologies and supervising the same will

bring efficient revenue realization to utility.

On examination of the billing data from a utility shows that approximately

50 % of billing done is based on NA / NR / DF / ADF / RDF / CDF where,

NA Consumer Not Available

NR Not Readable,

IDF Instrument Defective,

RDF Reading Defective,

ADF Appeared Defective,

CDF Ceiling Defective

In light of this, the replacement of meters has to be stepped up to have

quicker results with lesser investment. The commercial and industrial

connections should be given priority.

The consumer metering system should be tamper proof. Appropriate

accuracy class meters should be deployed for different categories of

consumers.


40

2.4.3 Industrial Consumers:

In many cases the power factor of the LT industrial consumer is as low as

0.5-0.6. This burdens the distribution system with increased losses and hence

poor quality of power. To compensate this, the utility should collect the

energy charges based on kVA for industrial connections and also billing

should be done for the reactive energy consumed. Therefore, it becomes

necessary to introduce LT static meters for industrial connections.

Electronic meters of accuracy class listed below are recommended for

replacing the electro-mechanical meters.

Sr.

No.

Size of industrial consumer Accuracy class of meter

1 EHV Bulk supplies at 33 kV and above 0.2

2 500 kW and above (at 11kV and below) 0.5

3 From 50 kW up to 500kW 0.5

4 From 10 kW up to 50 kW 1.0

5 Below 10 kW 1.0

2.4.4 Use of electronic TOD (Time of Day) maximum demand meters

(MD):

The electro-mechanical MD meters should be replaced with electronic MD

meter as MD reset operation in electro-mechanical meters involves human

interaction. This operation provides scope for manipulation. The electronic

meters with auto MD reset facility and also capable of computing


41

cumulative maximum demand provides solution for prevention of such

manipulations. Further, these meters are having memory facilities to give

following data, which can be retrieved through Meter Reading Instrument

(MRI) in each month.

• Hourly load survey data. (kWH, kVA, Voltage, Power Factor)

• Billing data (kVA MD, kWH & Power Factor)

• Tamper Data (CT missing, PT missing, etc)

The analysis of data is useful to expedite billing and reading activity, which

will be carried out without human intervention. Detection of theft and mal-

practices is easier. TOD metering features would also help in introduction of

suitable tariffs, which would enable demand side management to reduce

peak demand on system.

• Programming of CT/PT Ratios:

Manual billing process uses the CT and PT multiplication factors (Ratios)

stated on the paper label affixed to the metering cubicle. This provides scope

for manipulation. The actual ratio should be ascertained periodically.

Preferably, single ratio CTs and PTs for metering purpose may be used.

• Automatic Remote Metering System:

Automatic remote metering system is recommended to overcome the

problem of pilferage of energy by large consumers. This could be adopted in

areas with large number of high value industrial consumers.


42

• Replacement of Meters for small (up to 20 kVA, 3 phase consumers)

and Medium Consumers (20 kVA to 100 kVA)

The small and medium consumers (Industrial) category cover sanctioned

loads up to 100 kVA. The three phase LT consumers having load up to 20

kVA may be provided with static meters with tamper proof features.

Existing electromechanical meters should be replaced with electronic LT

TOD meters having MD, PF recording facility for consumers with load

greater than 20 kVA. Special cubicles may be designed to house the CTs

(encapsulated) of single ratio, MCBs and the meter, so that tampering

becomes difficult to the consumers.

2.4.5 Domestic - light & fan and Commercial Consumers

The meters of domestic light & fan are likely to be tampered as the present

installations provide easy access to incoming power cables, which leads to

tampering. In addition to meter seals, a metallic enclosure with a viewing

window and locking facility for the meter installation is recommended. The

meters could be located so that it becomes easily accessible without having

to go into the living area of premises.

This would facilitate regular reading of the meter regardless of whether the

premises are occupied at the time of the meter reader’s visit, by avoiding the

need for the meter reader to enter into the premises.

2.4.6 Meter Testing Facility:

It is necessary to ensure that the prime means of billing for the utility,

namely, the energy meters are checked regularly for accuracy. The meter

testing facilities need to be modernized and augmented as per anticipated


43

testing load. Portable site meter testing kits are available which should be

used to carry out surprise and spot checks.

It is recommended that computerized meter-testing database is created. This

would enable analysis of performance of meters and weeding out/ scrapping

of old meters.

The computer software to be used for meter records should have the

following minimum objectives.

• Tracking meter performance at individual and supplier level

• Provide data to evolve a policy for replacement of old meters.

Record for each meter may have the following information about the meter:

1. Make

2. Model/ type

3. Serial Number

4. Purchase Order Number

5. Latest Certificate date

6. Dial display details of kWH / kVAH/ Max. demand

7. Connection number

8. Date of installation/ re-installation

9. Dates of Repair

10. New or repaired

11. Malfunction or defective operation reported


44

2.4.7 Improved Metering:

(i) Installation of tamper-proof meter boxes and use of tamper-proof

numbered seals

(ii) Providing cut outs/ MCBs after the meter as per sanctioned load and

use of multi-core P.V.C. cables.

(iii) Installations of tamper proof electronic energy meters.

(iv) Providing adequate meter testing facilities. A time bound programme

should be chalked out for checking the meters and replacement of

defective meters with tested meters.

(v) Pilot studies for introduction of modern technologies such as pre-paid

meters, remote metering, automatic billing etc. should be undertaken to

establish the efficacy and suitability for adoption on a wider scale

covering all categories of consumers.

2.4.8 Periodic Test Schedule for Meters

Meters should be tested according to the following test schedule:

• Single Phase LT meters: Once in 5 years after installation at

consumer’s premises.

• Poly-phase LT meters: Once in 2 years after installation at

consumer’s premises.

• LT three-phase meters (CT operated) 20 kVA to 100 kVA:

Once in a year to be checked since these are

installed for high value consumers.


45

• HT meters:

For EHV level consumer (above 10 MVA)-Once in a quarter year.

For Loads (contract demand 5-10 MVA)-Once in a six months

Remaining HT consumers-Once in a year.

The testing schedule for HT consumers should cover the entire metering

system including CTs, PTs and pilot wire. Detailed ratio testing of CTs and

PTs is to be done. Testing through mobile cubicles through secondary

injections kits and phantom loading may also be carried out.


46

2.5 System Metering The metering plan for an effective energy accounting should cover the input

points of the circle and identify receiving and transfer points at different

voltage levels to ultimately enable measurement of energy input to a 11/6.6

kV feeder and there after to the ultimate consumers. The meters in the sub-

stations and 11/6.6 kV feeders should be modern electronic trivector meters

of 0.5 class accuracy with load survey capability, data logging features,

down loading facilities through Meter Reading Instruments and provision for

export/ import recording as per requirements of specific locations. Such

meters would eliminate scope for manipulation. Metering at these voltage

levels involves CTs and PTs and actual accuracies including ratios are to be

checked periodically.

Till such time, 100% meters are provided to the un-metered class of

consumers, meters may be provided on LV side of selected distribution

transformers feeding say, predominantly agriculture consumers or

consumers without meters and theft prone areas. These meters should also

be 0.5-class accuracy with load survey capability, data logging features and

downloading facilities. This would enable correct estimation of utilization

pattern (average consumption/ consumer or per kW) of consumers on that

distribution transformer. However, care should be taken to select the

transformers for metering in such a way that it capture and address the

consumer metering deficiencies.


47

Installation of meters on DTC centers will help in

(a) Identifying high energy loss pockets in the feeder

(b) Accounting energy in the feeder

(c) In the estimation of the energy catered among agriculture consumers.

The practice presently followed is to compile the energy sent out and

energy-billed figures based on the feeder panel installed meters. However, it

is suggested to follow this practice to downstream also to have the proper

energy accounting, location wise.


48

2.6 Consumer Indexing

It is necessary for the utility to know about the consumers who were located

in the field in relation to distribution feeders and sub-stations emanating

from the divisions: with reference to existing consumers in computer

database.

This is done by consumer indexing. By this utility can know about

1) Consumers who are existing but not present in the ledgers of the utility

2) Duplicate consumers where book number, service connection number

and division codes are the same.

3) The illegal connections are always a matter of concern to electric utilities.

Certain observations on the same can be recorded. Abundance of illegal

connections brings direct revenue loss to utility.

4) By actual site survey (i.e. consumer indexing) the utility can find the

following types of consumers. 1) Metered consumer, 2) Unmetered

consumption of rural domestic consumers and 3) Unmetered

consumption of agriculture consumers. By site survey the connected load

of unmetered consumers can be found for each and every consumer.

Hence norms of consumption per kW connected load can be found out

and hence assessment of unmetered consumers can be done more

accurately.


49

2.7 Distribution Transformer

2.7.1 Overloaded/ Under loaded distribution transformer:

One of the main objectives under APDRP scheme is to ensure quality power

to the consumers by targeting reduction in outages and losses in distribution

system. A review on distribution transformers is found essential because

loading on transformer is to be studied against growing demand of

connected consumers. In the case of overloading of DTC, it is necessary to

propose new distribution transformers or the same may be shifted near to the

load center, so that quality of power supply can be improved.

The distribution transformers to be installed in the circle should preferably

have standard rating of 25,50,63,100,250,315,400,500 and 630kVA. The

higher capacity (i.e. larger than 250 kVA) shall be used for concentrated

loads or areas with high load density and lower (less than 100 kVA) may be

used for rural areas. In high-rise buildings having concentrated loads, higher

capacity distribution transformers such as 1000 kVA may be used. 33/0.415

kV distribution transformers of appropriate rating-630 kVA, 1000 kVA,

1600 kVA, 2000 kVA, may also be used based on techno-economic

considerations. Lower ratings could be used for rural areas/far flung urban

areas. Standardization of ratings would help in achieving reduction in

inventory for purpose of procurement and maintenance and reduction in

price on account of bulk purchase.

The distribution transformers in urban areas should operate at an initial

capacity factor of about 65%-75% of their rated capacity and would have to

be augmented when the maximum demand on the transformer is near its


50

rating. In case of rural areas, a higher loading based on the assessment of

load growth could be considered for adoption.

In addition some new transformers would be required and some would have

to be augmented. Attempts should be made to locate the distribution

transformer as near to the load center as possible. It may not be possible to

determine the actual location where these are to be installed. However, for

the purpose of the scheme, expected load growth indications would have to

be considered for determining number and location of the distribution

transformers.

2.7.2 Providing distribution boxes on distribution transformers:

It is proposed to provide distribution boxes on transformers from the point of

view of protection to distribution transformers and also reduction in losses

because in absence of distribution box, the cables are directly connected to

the transformer and this sometimes leads to loose connections. These loose

connections add to additional losses in the system.


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2.8 Power Transformer

2.8.1 Overloading / New Power transformer:

In case the load on a sub station is found to exceed the rated capacity of the

transformer, it becomes necessary to upgrade the power transformer or add a

new transformer. In many cases, it is not technically possible to bifurcate the

feeder from the same sub station. It becomes necessary to install new power

transformers at the existing substation. The projected load growth of a

substation should be available for future planning.


52

2.9 Capacitors 2.9.1 Requirement of capacitors

In ideal system the power factor is maintained at 0.9 to 0.95 by providing

required compensation, which will improve the quality of power, will reduce

losses and improve the voltage regulation.

It is seen that the power factor or the MVA readings are not the meter

readings but assessed readings by assuming one of the factor i.e. MVA or pf.

2.9.2 Installation of capacitors

The capacitor bank shall be complete with neutral CT/ RVT and series

reactor as required. Circuit breaker, offload isolators, instrument

transformer, control and relay panels, connecting material and any other

material required for capacitor bank may be included in the scope of supply

of capacitor bank supplier or procured separately by the purchaser.

2.9.3 LT capacitor

Shunt capacitor are the simplest and cheapest way of managing the reactive

power. Agricultural pump sets and LT motor loads operate at very low

power factors (0.6 to 0.7) causing reactive power mis-management and

voltage profile problems in the system and thereby increasing system losses.

It has been realized that the installation of LT capacitors close to the

consumer load would (1) reduce load current in the LT feeders. (2) reduce

the overloading of distribution transformers, 11kV lines and back up system.

However, LT consumers do not ensure the working of capacitors even if

these are provided at the time of release of connections, as they are not

benefited due to flat rate tariff. In addition, the consumers do not have


53

requisite knowledge and skill to decide the level of compensation and check

the healthiness of the capacitors. This problem can be taken care of by

providing LT capacitors on distribution transformers. However, the

changing load demand characteristic poses problems in deciding on the level

of compensation. The experience of the power utilities with switched

capacitors has been satisfactory. To overcome this problem, it would be

worthwhile to provide minimum level of fixed compensation at the LT level

to meet the average demand conditions and prescribing for higher nominal

voltage (+10%) to ensure safe operation under possible adverse conditions.

The balance requirement could be met by placing capacitors on 11kV

feeders wherever the site conditions permit. It is, therefore, recommended to

have 440V, 3 phase delta connected 50 cycles, outdoor type LT fixed

capacitor unit intended for power factor improvement to be installed on the

LT side of distribution transformers

LT fixed capacitor

Capacitor units shall comply with ISS: 2834/1986 (with latest version/

amendments) and ISS 13340/1993. The material shall be ISI marked.

Reference for recommended arrangement for connections/ protection for

fixed type capacitors to be installed on the LT side of distribution

transformers can be taken from CEA guidelines

2.9.4 Pedestal mounted HT capacitor

Standards

The shunt capacitor banks and associated equipments shall conform to the

latest edition of the following standards (as amended up to date).


54

1 Capacitors IS: 2834, IS: 13925

2 Circuit breakers IEC: 56

3 Current transformer IS: 2705

4 Potential transformer IS: 3156

5 Isolators IS: 9921

6 Fuses (external) IS: 2208

7 Potential relays IS: 3342

8 Motors IS: 325

9 Surge arresters IS: 3070

Equipment meeting the requirement of any other authoritative standards,

which ensure a quality equal to or better than that as per the standards

mentioned above, shall also be acceptable.


55

2.10 Renovation, Strengthening and New Substation (Feeder Upgradation)

With the substantial increase in load demand expected in the plan period, the

system would need strengthening and augmentation to ensure delivery of

power to the consumers at proper voltage and for reduction of losses to a

reasonable level. For the development of the system, the future load

demands are worked out and imposed on the existing system to assess the

inadequacy of the system for meeting the demand in the horizon year. This

system augmentation/ strengthening is then worked out to cover the

inadequacy of the existing system to meet the proposed demand.

Sub – Transmission

The sub – transmission and distribution system would have to be expanded

to meet the growth in demand. The following options for the expansion of

sub – transmission system would have to be considered.

Augmentation of the transformation capacity at the existing 33/11kV

substation, rearranging/ reconfiguring the 33kV feeders by using higher size

conductors and or increasing the number of feeders.

Establishing new 33/11kV Substation nearer to the load centers and

redistributing the loads between existing and new Substations and feeder

strengthening.


56

Augmenting the transformer capacitors at some of the existing substations

and establishing new substations so as to have an even distribution of load

on the substations and corresponding strengthening and addition of feeders.

The locations for augmentation/ new substations have to be worked out on

the basis of assessment of the area wise power demand potential. In theory

the area supplied by each individual power Substation varies as a function of

distribution system voltage and load density. Once the radius of operation of

the Substation has been determined from these two factors, new Substation

have to be planned to cater to the loads not covered by the existing

Substations. The proposed locations of the new primary Substation have to

be chosen considering the proximity to the load center and availability of

suitable and adequate site. In the case of augmentation of existing

Substations, the availability of land and feasibility of adding new

transformer/ additional lines have to be kept in view.

Planning for site of substation and feeders in rural area should be based on

the load survey, and load centers in the village. The geographical maps of

village/ taluka showing the location of well, village streets, clusters, existing

diesel based industry/ cold storage etc. would have to be plotted ultimately

for use in optimal planning of network for the rural area.

The various options for the sub – transmission system are evaluated on

techno-economic considerations to decide on the final alternative. The load

flow studies would give the losses for the various alternatives and total cost

of each alternative would then be worked out based on capital cost of each

alternative and the cost of losses.

Evaluation of various alternatives


57

The study of each alternative should be analyzed under normal condition as

well as outage condition. It should be ensured that the network does not

experience overloading and the voltage variation in all the alternatives is

within the permissible limits.

To evolve the least cost alternative, subject to their meeting the technical

requirements, the total owning cost of various alternatives should be

estimated.

After identifying the scope of work and estimation of losses under various

alternatives for sub-transmission system, the least cost optimal solution may

be worked out considering the capital cost of proposed works and net

present worth of peak and energy losses over the expected life of the

equipment. The cost benefit ratio can then be worked out for each of the

proposed work.

Distribution system

Once the sub-transmission system has been finalized, the up gradation

requirements of distribution system have to be identified. The peak demand

at the 66 or 33/11 kV sub-station would have to be desegregated to work out

the peak demand in each feeder and the allocation of demand on the

distribution transformers would be made on the basis of actual load

connected to the distribution transformer.

The voltage regulation and the power losses along each feeder section upto

distribution transformer would have to be worked out. Based on the results

of studies (using the software), the feeder section requiring reconductoring/

addition of new feeder and its conductor size may be decided. It may be

ensured that the voltage is within the limit at the each node/ distribution

transformer.


58

In addition, some new transformer would be required and some would have

to be augmented. Attempts should be made to locate the distribution

transformer as near to the load center as possible. It may not be possible to

determine the actual location where these are to be installed. However, for

the purpose of the scheme expected load growth indications would have to

be considered for determining number and location of the distribution

transformers.

The requirement of LT line may be worked out based on detailed study of

LT network emanating from various distribution transformers. However, in

the beginning the requirement of LT lines may be worked out on the basis of

extrapolation of results from studies of typical distribution transformer.

2.10.1 Creation of new substation

Planning criteria for new sub-station should be on the basis of: -

a) Loading of existing substation

b) Accessibility to take feeder outlets

c) Load growth expected in the area

d) Availability of load

Following important points are to be considered for creation of new sub-

station

a) Existing system status of the HV substation

b) Single line diagram of the proposed sub-station

c) HV system power loss, voltage regulation

d) Existing and modified status of the 11/6.6kV feeders

e) Calculation of DF, LF and LLF

f) Loss status

g) Benefit due to the scheme


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h) Estimates

i) 11/6.6kV feeder map with existing position

j) 11/6.6kV feeder map with proposed diagram

Sub-station layout

Before deciding the ratings of the equipment in a sub-station, it is necessary

to prepare a schematic/ lay out of the sub-station. There are a number of

arrangements dependent upon the system voltage, position of the sub-station

in the system, flexibility, reliability of supply and cost. The factors to be

considered while deciding the layout are:-

a) It should be possible to carry out equipment maintenance without

interrupting the entire supply

b) As far as possible there should be alternate arrangements in the

event of outage of any one important item of the equipment

c) The layout should be economical and should not hinder future

expansion

Single bus bar, single bus bar with bus sectionalizer, double bus bar

arrangement are being adopted depending upon the situations. A layout,

which is most economical and satisfies technical requirements as per actual

site conditions may be adopted. Generally, 33/11kV sub-station with single

bus bar and a sectionalizer in between on the 33kV as well as 11kV sides is

being adopted.

To improve the operational flexibility, minimize restoration time of power

supply and to prevent overloading of lines and transformers in real time

mode, modern features such as distribution automation may be incorporated.

The overall planned system subject to meeting the technical requirement for

supplying quality and reliable power supply to the consumers should be of


60

least cost (considering the capital cost of proposed works and capitalizing

the cost of losses over the life of the equipment out of various alternatives

considered). THE FOLLOWING FORMULAS CAN BE USED FOR CALCULATION OF

LOAD FACTORS, LOSS LOAD FACTORS e.t.c

%VR = 1.06 x Load x Dist. x P.F. LDF x DF x Cond. Const.

Losses = 0.105 x Load 2 x Dist x R x LLF

2 x LDF x DF

2

LF = Unit sent out KWH / YR Peak Load in KW x 8760

LLF = 0.8 ( LF ) 2 + 0.2 ( LF ) DF = Connected Load in KVA Peak Load in KVA WHERE : P.F. = Power Factor = Adopted 0.8 LDF = Load Distribution Factor = Adopted 2.0

DF = Diversity Factor

LF = Load Factor

LLF = Loss Load Factor

kVA – kM = KVA KM Constant.

Cond. Const. = 1578 for 30 mm2 ACSR Rabbit Conductor.

Dist = Distance of feeder in KM

R = Resistance of feeder


61

2.11 Guidelines for System Development

A massive programme of upgradation of Sub-Transmission and Distribution

(ST&D) System and reduction of Transmission and Distribution (T&D)

losses has been launched by the Govt. of India under the Accelerated Power

Development & Reforms Programme (APDRP). For achieving the

improvements systematically, a Committee of Experts under the

Chairmanship of Member (PS/ G&O) was constituted by the Govt. to

prepare guidelines covering various aspects of ST&D system development.

The guideline cover the following:

• Project Management

• Performance Evaluation

• Operation & Maintenance of sub-transmission and distribution

equipment

• Residual life assessment and R&M of the sub-transmission and

distribution equipment

• An overview of present situation

• Energy accounting-need and objective

• Organization structure of profit and energy accounting center

• Metering system

• Energy accounting Procedures

• Energy Audit


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• Energy Billing and Revenue collection

• Reporting and Reviewing System

• Benefits and Outcomes

• Task for formulation of short and long term plan

• Planning Criteria

Previous sections outline the methodologies to be adopted in the

implementations of these guidelines. However, reference can be made to the

report made by CEA on this subject (Ref. “Formulation of Project Reports,

CEA, Volume 1, Nov. 2001).


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2.12 System Studies The objective of transmission planing shall be to install sufficient capacity to

evacuate power from generating stations to Grid substations (having regard

to load forecast) while maintaining voltage within the required limits,

containing transmission losses at levels consistent with its Load Forecast and

providing for the economic exchange of power with contiguous states. For

this purpose, utility has to carry out power system studies covering load

flow, short circuit and transient stability studies.

Successful operation of a power system depends largely on the engineer’s

ability to provide reliable and uninterrupted service to load. The reliability of

the power supply implies much more than merely being available. In

practical terms, this means that both voltage and frequency must be held

within close tolerance so that the consumer equipment may operate

satisfactorily. For example, a drop in voltage of 10-15% or a reduction of the

system frequency of only a few hertz may lead to stalling of the motor loads

on the system.

As electric utilities grow in size, and the number of interconnections

increase, planning for future expansion has become increasingly complex.

The increasing cost of additions and modifications has made it imperative

that utilities consider a range of design options, and perform detailed studies

of the effect on the system of each option, based on a number of assumption:

like, normal and abnormal operating conditions, peak and off-peak loadings,

and present and future years of operation. A large volume of network data

must also be collected and accurately handled. To assist the engineer in this

power-system planning, digital computers and highly sophisticated computer


64

programs are used. Future transmission system will be far more complex

than those of today. This means that the power system planner’s task will be

more complex. If the systems being planned are to be optimal with respect to

construction cost, performance, and operating efficiency, better planning

tools are required. In general, the major power system planning tools are:

Load Flow analysis, short circuit analysis, Stability analysis and system

protection and relay co-ordination.

(1) Load Flow Studies:

The main objective of load flow analysis is to identify the potential

problems, in terms of unacceptable voltage conditions, overloading of

facilities, decreasing reliability, or any failure of the transmission system to

meet performance criteria. After this analysis stage, the planner develops the

alternative plans or scenarios that not only will prevent the unforeseen

problems but also will meet the long term objectives of system reliability.

This is done by detailed load flow studies.

(2) Short circuit Study:

After determining the best configuration from load flow study, the power

system can be tested for system behavior under fault conditions. The main

objective of short circuit study can be expressed as to determine the current

interrupting capacity of the circuit breaker so that the faulted equipment can

be disconnected successfully. To establish the relay requirement and settings

to detect the fault and cause the circuit breaker to operate when the current

flowing through it exceeds the maximum allowable current, to calculate

voltage during faulted conditions that affect insulation co-ordination and

lighting arrester applications, and to design the grounding systems.


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(3) Stability Study:

Stability studies are performed in order to be sure that the system will

remain stable following the clearance of a severe fault or disturbance on

transmission line. Stability analysis is defined as the transient behavior of

the power system following a disturbance. The transient stability is defined

as the ability of the system to maintain synchronous operation following a

disturbance, usually a fault condition. These studies are necessary in order to

ensure that the wide variety of protective relays function correctly with

proper discrimination to provide required reliable, sensitive isolation of

faulty power system equipment.


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2.13 Optimum Utilization of Resources

The power from transmission network is delivered to sub-transmission

network after stepping down the voltage to 33kV through 220/33kV Grid

substations. The power is carried at 33 kV by overhead line or cable.

33/11kV transformers step down the power to 11 kV for distribution. The

power is delivered from primary sub station through primary feeders mainly

at 11 kV to various distribution transformers. Distribution transformers

further step down the power to utilization voltage of 400 V. It carries power

from distribution sub station at 400 V to various consumers through service

lines and cable.

Though in time delivery of equipment is important from technical &

commercial considerations the timely installation of the equipment to derive

benefits from it is equally important. Further more, decay / damage of the

equipment / system components can set in due to long storage of equipment

at site. Especially energy meters should be placed in their normal packing

and transported over a distance of at least 40 to 50 kM, in any transport

vehicle.

Thus, the augmentation of power transformer / sub station / feeder can take

place depending on the future load growth. By augmentation of power

transformer & new power transformers possibility of overloading can be

reduced.

In power system network (distribution), at some place distribution

transformers are overloaded and at some place it is under loaded. In this


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situation by changing the location of transformers can reduce this under

loading and overloading conditions.


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2.14 Procedural Clearance The strategy for improvement of the system in each circle should be based

upon a detailed study to identify the factors causing high-energy losses. For

this, the utility should conduct the Energy Accounting / Energy Audit

studies so as to

• Assess the overall energy loss

• Identify system elements causing excessive losses

• Establish cause of losses due to technical or non technical factors

The scheme should cover:

• The analysis of existing system

• Measure for reduction of T & D losses

• Study of possible alternative schemes for strengthening and

improvement of the scheme to meet growing demands and evolving

optimum system for meeting the requirement in a cost effective

manner.

The power utility shall formulate the scheme for each circles either

utilizing in house expertise or through consultant.

The formulation of a project report for up gradation of system for the

identified circle should be taken up in two phases.

• Short Term Plan

• Long Term Plan


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Short Term Plan

In the prevailing situation of mounting energy losses, priority attention needs

to be given to achieve the objective of loss reduction especially for reduction

of commercial loss as well as technical loss in the short-term plan.

The short-term plan shall cover the measures required for immediate

improvement and reduction of losses and shall be placed upon the

information / data readily available with the utilities. The work identified as

short term should be completed within 1 to 2 years.

Long Term Plan:

The long term plan will cover all the measures for improvement of quality

and reliability of power supply and reduction of T & D losses in the circle by

upgradation, strengthening and improvement of the sub transmission &

distribution system in a circle to meet the load demand for next 5 years. The

plan will be prepared by scientific planning of the system on the basis of

detailed system studies.


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2.15 Cost Benefits When one speaks of network optimization, it refers to the minimization of

overall network cost. Therefore, the method of costing, alternative network

scheme is of great importance in optimization. The costing of network

scheme is a complex subject and a number of recognized methods are

available for this purpose. The method adopted should incorporate

recognized financial procedures. Usually the cost of establishing various

items, which make up an electric distribution system, can be broken into two

parts: capital cost and annual cost. The annual cost will cover such charges

as interest, maintenance cost and cost of losses.


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2.16 Documents to be Provided with DPR

To enable The Commission to examine the plans/ proposals, the following

supporting documents should be submitted along with the DPR.

a) Clearances and approval (if required)

b) Acquisition of Land

c) Approval of financing

d) Date wise list of schemes, which were approved by planning

commission in previous plans but could not be taken up so far.

Fresh endorsement with justification is required is to be submitted

to the commission on any of the schemes proposed to be taken up

now.

e) Physical progress in substation, distribution line, others if any.

f) Target date of completion.

g) Original cost with date and revised cost with date

Year wise expenses schedules

Fund requirements in two years (current & next)

Annual plan provision

h) Means of finance including loan sanctioned and equity.

i) Source of own/ balance funds.

j) Govt. guarantee for the loan.


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k) Financial progress (%) in substation, distribution line, and

expenditure proposed.

l) Cost benefits analysis carried out in the schemes.

m) Reports of system planning studies, load flow analysis if required

in accordance to commissions guideline for capital expenditure and

Load Forecast And Resources Plan Under Transmission And

Distribution Planning.

n) Licensee to identify the works and submit proposals by November

of preceding year.

o) Licensee must standardize the formats and have the budgetary cost

data bank, update periodically.

p) The expected loss reduction and improvement in voltage condition

should be worked out. The study should highlight following :

a. Justification for taking up new works.

b. Area of poor voltage/ system reliability where immediate

action for strengthening the system is required.

c. Proposals to mitigate the condition in item (ii)

d. Any other remarks on the system inadequacy and proposals

for strengthening the same.

e. The single line diagrams, bar chart for construction for 2

years duration.

f. Lay out plan, modified plans, existing plans, map of areas

wherever required with the DPR.


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2.17 Conclusion Methodology for over all assessment of the status of the ST&D is discussed.

Various components of the system that contribute to the losses are identified

and the need to augment/ change those equipment and the process of doing

those are explained. Short term and long term planning objectives are

outlined and the guide lines for making proposals for system improvement

are given. Importance of analyzing these schemes to achieve optimal

performance at least cost is stressed. It is expected that the Commission

would use the material presented here for evaluation of schemes submitted

under the APDRP for the improvement of distribution systems in UP.