pse4ne2 - power system analysis 101

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NATIONAL ELECTRIFICATION ADMINISTRATION

U. P. NATIONAL ENGINEERING CENTER

Training Course in

Power System Engineering for Non-Engineers

Competency Training and Certification Program in Electric Power Distribution System Engineering

U. P. NATIONAL ENGINEERING CENTER

Power System Analysis 101

2

Power System Engineering

for Non-EngineersU. P. National Engineering Center

National Electrification Administration


Power System Analysis

Reliability AnalysisReliability

Short Circuit AnalysisSafety

System Loss AnalysisEfficiency

Load Flow AnalysisPower Quality

Power System Analysis

Performance Standards

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LOAD FLOW ANALYSIS

4





1. What is Load Flow?

2. Uses of Load Flow Studies

3. Load Flow Control

Load Flow Analysis

3

5





What is Load Flow?

What are the Voltages, Currents, Power and Losses of the Distribution System?

Bus1

Utility Grid

Bus2Bus3

Bus4V1 = 67 kV

Lumped Load A2 MVA 85%PF

Lumped Load B1 MVA 85%PF

V2 = ?

V4 = ?

V3 = ?

I23 , Loss23 = ?

I24 , Loss24 = ?

I12 , Loss12 = ?

P1 , Q1 = ?

P2 , Q2 = ?

P3 , Q3 = ?

P4 , Q4 = ?

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Can we see how electric power flows in the system, coming from the sources (where power is purchased) and down to all customers (where power is sold)?

Can we determine:

• If any customer is being provided with voltage that is too low (or even too high)?

• If too much power flow through any of our equipment, especially our transformers?

• How much power is lost along the lines and equipment?

YES! LOAD FLOW ANALYSIS

Load Flow of an Existing System

What is Load Flow?

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Can we have a picture of the system as we

contemplate possible changes?

Can we determine in advance the effects of:• Growth or addition of new loads• Addition of generating plants• Upgrading of Substation• Expansion of distribution lines• Installations of equipment such as capacitors

before the proposed changes are implemented?

YES! LOAD FLOW ANALYSIS

Load Flow of a Contemplated System

What is Load Flow?

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Load Flow (also called Power Flow) is a snapshot picture of the power system at a given point.

Load Flow Analysis simulates (i.e., mathematically determine) the performance of an electric power system under a given set of conditions.

What is Load Flow?

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How would the engineers do that?

• Identify physical components

• Know the characteristic of components

• Mathematically represent the behavior of components

• Calculate electrical parameters

What is Load Flow?

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G

What is Load Flow?

6

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Utility Grid or Generator

Bus

Load

Substation Transformer

TransmissionLine

DistributionLine

G

DistributionTransformer

What is Load Flow?

Load Flow mathematically determines the Voltages, Currents, Power and Losses

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Basic Information From a Load Flow Study

Voltage Profile

Injected Power (Pp and Qp)

Line Currents (Ipq and Ipq)

Power Flows (Ppq and Qpq)

Line Losses (I2R and I2X)

Uses of Load Flow Studies

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Other Information From a Load Flow Study

Overvoltage and Undervoltage Buses

Critical and Overloaded Transformers and Lines

Total System Losses


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Sensitivity Analysis

9) Add or remove rotating or static var supply to buses.

8) Increase or decrease transformer size.

7) Change transformer taps.

6) Change bus voltages.

5) Increase conductor size on T&D lines.

4) Add new transmission or distribution lines.

3) Add, remove or shift generation to any bus.

2) Add, reduce or remove load to any or all buses.

1) Take any line, transformer or generator out of service.


8

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1) ANALYSIS OF EXISTING CONDITIONS

• Check for voltage violations� PGC: 0.95 – 1.05 p.u. (For Transmission)� PDC: 0.90 – 1.10 p.u (For Distribution)*

*Recommended 0.95 – 1.05 p.u.

• Check for branch power flow violations� Transformer Overloads� Line Overloads

• Check for system losses

� Caps on Segregated DSL


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2) ANALYSIS FOR CORRECTING PQ PROBLEMS

• Voltage adjustment by utility at delivery point� Request TransCo to improve voltage at

connection point� TransCo as System Operator will determine

feasibility based on Economic Dispatch and other adjustments such as transformer tap changing and reactive power compensation


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• Transformer tap changing� Available Taps

� At Primary Side

� At Secondary Side

� Both Sides

� Typical Taps � Tap 1: +5%

� Tap 2: +2.5%

� Tap 3: 0% (Rated Voltage)

� Tap 4: -2.5%

� Tap 5: -5%



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•Capacitor compensation• Compensate for Peak Loading• Check overvoltages during Off-Peak• Optimize Capacitor Plan

• System configuration improvement



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3) EXPANSION PLANNING

• New substation construction• Substation capacity expansion• New feeder segment construction / extension• Addition of parallel feeder segment• Reconducting of existing feeder segment/ circuit • Circuit conversion to higher voltage• Generator addition


20





4) CONTINGENCY ANALYSIS

Reliability analysis of the Transmission (Grid) and Subtransmission System

5) SYSTEM LOSS ANALYSIS

Segregation of System Losses


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1. For Generating plants, the amount of power that can be delivered

can be controlled by the plant operator (as long as within the

capacity of the plant)

2. Flow of power is affected by the voltages and impedances across

the components

• Specialized Transformers and other equipment may be

utilized to control the flow of power across the network

3. Capacitors are used to improve the voltage profile across the

network

• The current drawn by the load is reduced

• The voltage drop across the line is reduced

• The voltage at the load side is increased

Load Flow Control

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SYSTEM LOSS ANALYSIS

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1. Components of Distribution System Losses

2. Segregation of Distribution System Losses

3. System Loss Reduction and Control

System Loss Analysis

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Components of Distribution System Losses

The Philippine Distribution Code (PDC)

mandates system losses to be segregated into the following components:

a. Technical Loss;

b. Non-Technical Loss; and

c. Administrative Loss.

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Total Distribution System Losses

Administrative

Loss+

Total Distribution

System Losses

=

Energy Delivered to the Distribution

System

Energy Delivered to Users

-

Technical Loss Non-Technical Loss+

Bundled Technical & Non-Technical Losses

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The electric energy used by the Distribution Utility in the proper operation of the Distribution System.

a. Distribution Substations;

b. Offices, warehouses and workshops of the DU; and

c. Other essential electrical loads of the Distribution Utility.


Administrative Losses

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Load and no-load losses in:

a. Sub-transmission lines and substation transformers;

b. Primary distribution lines and distribution transformers;

c. Secondary distribution lines and service drops;

d. Voltage regulators, Capacitors and reactors; and

e. All other electrical equipment necessary for the operation of the distribution system.


Technical Losses

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The component that is not related to the physical characteristics and functions of the electrical system, and is caused primarily by human error, whether intentional or not.

Includes the electric energy lost due to pilferage, tampering of meters and erroneous meter reading.

Errors that are attributable to inaccuracies in metering and billing.


Non-Technical Losses

15

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Total DSL = Energy Input - Energy Output

Total DSL

= Σ[Energy delivered by the Transmission System]

+ Σ[Energy delivered by Embedded Generating Plants]

+ Σ[Energy delivered by Other Distribution Systems]

+ Σ[Energy delivered by User Systems with Generating Units]

- Σ[Energy delivered to the Users of the Distribution System]

Total Distribution System Losses

30





Unbundling the Technical and Non-Technical Loss

Technical

Losses

Non-Technical

Losses+

-Technical

Losses

Shall be quantified through 3-Phase (Unbalanced) Load Flow Simulations

Non-Technical

Losses

=Residual after

subtracting Administrative &

Technical Losses from the Total Distribution

System Losses

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Technical Loss

= ΣΣΣΣ[Hourly Load and No-Load (or Fixed) Losses in all electrical equipment, devices and conductors]

g) Voltage Regulators

h) Capacitors

i) Reactorsj) Other electrical equipment

a)Sub-transmission Lines

b)Substation Power Transformersc)Primary Distribution Lines

d)Distribution Transformers

e)Secondary Distribution Lines

f) Service Drops Hourly Load Flow Simulations


Plus Calculated Metering Equipment Loss

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Primary Distribution Lines

(Main Feeder)

Substation

Transformer

Residential

Subtransmission Lines

Primary Distribution Lines (Laterals)

Distribution

Transformer

Commercial Industrial

Misc Loads

Secondary Distribution Lines

Service

Drop

Three-Phase Unbalanced Load Flow Simulations

a)Sub-transmission Lines

b)Substation Power Transformersc)Primary Distribution Lines

d)Distribution Transformerse)Secondary Distribution Linesf) Service Drops

g)Voltage Regulatorsh)Capacitorsi) Reactorsj) Other electrical equipment

Load Losses and

No-Load (Fixed) Losses


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Potential Transformer Loss

= Power Loss in PT (kW) x Number of PT x Number of Operating

Hours in the Billing Period

Current Transformer Loss

= Power Loss in CT (kW) x Number of CT x Number of Operating

Hours in the Billing Period

Electric Meter Potential Coil Loss

= Power Loss in Electric Meter Potential Coil (kW) x Number of

Electric Meters x Number of Operating Hours in the Billing Period

Electric Meter Current Coil Loss

= Power Loss in Electric Meter Current Coil (kW) x Number of

Electric Meters x Number of Operating Hours in the Billing Period

Operating Hours = No. of days x 24 hours – SAIDI

Calculation of Metering Equipment


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Non-Technical Loss

= Total Distribution System Losses

- Administrative Loss

- Technical Loss

- Recovered Losses

Note: Losses recovered from anti-pilferage activities are subtracted from the total distribution system losses.


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Customer Energy Bill

Distribution System Data

Distribution System Loss Segregation

Program

(3-phase Load Flow)

Segregated

Technical

Loss(Billing Period)

Metering Equipment

LossMetering Equipment Inventory

Distribution Reliability Assessment

DSL Segregation

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Segregated Distribution System Losses

�Monthly DSL Segregation

� Segregated DSL for the Whole Distribution System

� Segregated DSL Per Receiving/Metering Point

� Segregated DSL per Substation

� Segregated DSL per Feeder

� Segregated DSL per Distribution Transformer

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Distribution Network Models

Impedance/

Admittance

parameters of

Distribution

System Element

IA

IB

IC

Ia

Ib

Ic

VA VB VC Vc Vb Va

Ground (Reference Node)

A

B

C

a

b

c

Distribution System Element

Distribution Network Model must capture the unbalance characteristics of the System

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Distribution Load Models

0

50

100

150

200

250

300

350

Dem

an

d (

W)

Customer Energy Bill

Customer Energy Bill Converted to Hourly Power

Demand

Area under the curve

= Customer Energy

Bill

Normalized Customer Load

Curve

0

0.2

0.4

0.6

0.8

1

1.2

Time (24 hours)

Norm

alized D

em

and (per unit)

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Data Requirements

ERC-DSL-21

ERC-DSL-20

ERC-DSL-19

ERC-DSL-18

ERC-DSL-17

ERC-DSL-16

ERC-DSL-15

ERC-DSL-14

ERC-DSL-13

ERC-DSL-12

ERC-DSL-11

ERC-DSL-10

ERC-DSL-09

ERC-DSL-08

ERC-DSL-07

ERC-DSL-06

ERC-DSL-05

ERC-DSL-04

ERC-DSL-03

ERC-DSL-02

ERC-DSL-01 Administrative Load Data

Customer Data

Billing Cycle Data

Customer Energy Consumption Data

Load Curve Data

Bus Data

Subtransmission Line Data - Overhead

Subtransmission Line Data - Underground/Submarine Cable

Substation Power Transformer Data - Two Winding

Substation Power Transformer Data - Three Winding

Primary Distribution Line Data - Overhead

Primary Distribution Line Data - Underground Cable

Primary Customer Service Drop Data - Overhead

Primary Customer Service Drop Data - Underground Cable

Distribution Transformer Data

Secondary Distribution Line Data

Secondary Customer Service Drop Data

Voltage Regulator Data

Shunt Capacitor Data

Shunt Inductor Data

Series Inductor Data

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Optimal Level of System Loss

Cost

System LossHigh Low

System Loss

Reduction

Program CostUnrecovered

Energy Cost

Total Cost

Optimal

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TECHNICAL LOSS REDUCTION

PROGRAM

NON-TECHNICAL LOSS

REDUCTION PROGRAM

SEGREGATED DISTRIBUTION SYSTEM LOSSES ANALYSIS

TECHNICAL, ECONOMIC & FINANCIAL

ANALYSIS

TECHNICAL, ECONOMIC & FINANCIAL

ANALYSIS

BENECO DSL Segregation

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11.9698%33,836,577 TOTAL

5.5951%15,487,726Non-Technical

6.3153%18,181,059Technical

0.0594%167, 791Administrative

%KwhrLoss

TEST YEAR SEGREGATED

DISTRIBUTION SYSTEM LOSSES

Administrative

Loss, 0.50%

Technical

Loss,

52.76%

Non-

Technical

Loss,

46.74%


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13.2KV SYSTEM

23KV SYSTEM

TOTAL LOSSES

Non-Technical Loss

Technical Loss

Administrative Loss

SEGREGATED SYSTEM LOSSES

17.7088%

7.4183%

9.8906%

0.3998%

13.2 KV System

TOTAL LOSSES

Non-Technical Loss

Technical Loss

Administrative Loss


11.6324%

5.4879%

6.1051%

0.0393%

23 KV System


44





DSL RESULT PER FEEDER PER HOUR PER DAY IN A MONTH

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100.0000%6.3153%Total Technical Loss

5.0350%0.3180%kWhR Meter Loss

0.0456%0.0029%Shunt Capacitor Loss

1.0937%0.0691%Secondary Service Drop

34.2848%2.1652%Secondary

27.5469%1.7397%Dist. XF No-Load Loss

5.4445%0.3438%Dist. XF Load Loss

0.0000%0.0000%Primary Service Drop

21.8597%1.3805%Primary Line

3.7559%0.2372%Power Transformer No-Load Loss

0.9338%0.0590%Power Transformer Load Loss

% SHARE% LOSSSEGREGATED TECHNICAL LOSS


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TECHNICAL LOSS ALLOCATION

Shunt Capacitor Loss

0%

Pow er Xformer Load Loss

1%

kWhR Meter Loss

5%

Secondary Service Drop

1%

Pow er Xformer No-Load

Loss

4%

Secondary

34%

Dist. XF No-Load Loss

28%

Primary Line

22%

Dist. XF Load Loss

5%

TECHNICAL LOSS DISTRIBUTION


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5.5951%5.4879%7.4183%15,816,480.83 14,651,941.84 1,164,538.99

Non-Technical Loss

11.9698%

11.6324%

17.7088%33,836,576.60 31,056,634.21 2,779,942.39 TOTAL LOSSES

6.3153%6.1051%9.8906%17,852,304.63 16,299,669.83 1,552,634.80 Technical Loss

0.0594%0.0393%0.3998%167,791.14 105,022.54 62,768.60

Administrative Loss

Total23 KV System

13.2 KV SystemTotal23 KV System13.2 KV System

PERCENT (%) TECHNICAL LOSSESKWHR TECHNICAL LOSSES


TEST YEAR SEGREGATED DISTRIBUTION SYSTEM LOSSES

PER SYSTEM VOLTAGE


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TEST YEAR SEGREGATED TECHNICAL LOSSES

PER SYSTEM VOLTAGE

6.3153%6.1051%9.8906%17,852,305 16,299,670 1,552,635 Total Technical Loss

0.3180%0.2792%0.9779%898,866 745,359 153,507 kWhR Meter Loss

0.0029%0.0029%0.0025%8,147 7,753 394 Shunt Capacitor Loss

0.0691%0.0715%0.0272%195,254 190,979 4,275 Secondary Service Drop

2.1652%2.2141%1.3342%6,120,623 5,911,176 209,447 Secondary

1.7397%1.6205%3.7661%4,917,765 4,326,553 591,212 Dist. XF No-Load Loss

0.3438%0.3520%0.2054%971,968 939,729 32,239 Dist. XF Load Loss

0.0000%0.0000%0.0000%6 6 -Primary Service Drop

1.3805%1.2927%2.8732%3,902,460 3,451,427 451,032 Primary Line

0.2372%0.2117%0.6708%670,517 565,221 105,295 Power Xformer No-Load

Loss

0.0590%0.0605%0.0333%166,700 161,467 5,232 Power Xformer Load Loss

Total23 KV System13.2 KV SystemTotal23 KV System13.2 KV System

PERCENT (%) TECHNICAL LOSSESKWHR TECHNICAL LOSSES

TECHNICAL LOSSES


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FORECASTED SEGREGATED DISTRIBUTION SYSTEM LOSSES

5.5951%7.0604%0.0493%12.7071%442,271,657 2010

5.5951%6.8604%0.0491%12.5074%405,588,445 2009

5.5951%6.7477%0.0535%12.3994%372,339,284 2008

5.5951%6.6187%0.0583%12.2757%341,755,055 2007

5.5951%6.4611%0.0621%12.1222%313,577,324 2006

Non Technical Loss(%)

Technical Loss (%)

Administrative Loss(%)

Total System

Losses (%)

Energy Input (KWH)

YEAR


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PROPOSED DISTRIBUTION SYSTEM LOSS CAPS

218,2182.7644%6.5249% to 7.5959%2010

199,1473.1278%6.3431% to 7.3778%2009

199,1473.8585%6.2431% to 7.2523%2008

199,1474.7486%6.1281% to 7.1094%2007

194,7415.5951%5.9833% to 6.9388%2006

AdministrativeLoss Cap (Annual

KWH)

Declining Non-Technical Loss

Caps

Technical LossCap

YEAR

FORECASTED DISTRIBUTION SYSTEM LOSS

2010

2009

2008

2007

2006

YEAR

10.4191%-9.3467%

10.5639%-9.5279%

11.1733%-10.1628%

11.9251%-10.9425%

12.6047%-11.6480%

FORECASTED SYSTEM LOSS RANGE

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P 111,876,2965.595%15,816,481 Non-Technical Loss

P 126,276,4926.315%17,852,305 Technical Loss

P 1,186,8540.059%167,791 Administrative Loss

P 239,339,64111.970%33,836,577 Total System Loss

Peso Equivalent (Php)(as of February 2007

costing**)Percentage (%)Energy (KWHR)Distribution System Loss

P 126,276,4926.3153%17,852,305Total Technical Loss

P 6,358,0360.3180%898,866kWhR Meter Loss

P 57,6260.0029%8,147Shunt Capacitor Loss

P 1,381,1080.0691%195,254Secondary Service Drop

P 43,293,6172.1652%6,120,623Secondary

P 34,785,3211.7397%4,917,765Dist. XF No-Load Loss

P 6,875,1170.3438%971,968Dist. XF Load Loss

P 420.0000%6Primary Service Drop

P 27,603,6581.3805%3,902,460Primary Line

P 4,742,8330.2372%670,517Power Xformer No-Load Loss

P 1,179,1340.0590%166,700Power Xformer Load Loss

Peso Equivalent (Php)(as of February 2007

costing**)Percentage (%)Energy (KWHR)Technical Losses

BENECO SEGREGATED DISTRIBUTION SYSTEM LOSS (base year 2004)

BENECO SEGREGATED TECHNICAL LOSS (base year 2004)

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15.9540%10.5949%0%26.5489%66,364 44,072 -110,435

LUELCO

9.1927%9.6377%0%18.8304%181,600 190,389 -371,989

NPC-Itogon

10.9641%9.3068%0.0838%20.3546%135,549 115,060 1,036 251,644

Ambuclao

9.1774%5.8537%0%15.0311%38,613 24,629 -63,242

Ampuhaw Mini-hydro

3.5755%8.5662%0%12.1417%7,378 17,677 -25,055

Bakun Mini-hydro

9.9594%6.5027%0%16.4621%59,151 38,621 -97,772

Asin Mini-Hyrdo

5.9394%8.6889%0.1846%14.8130%373,918 547,017 11,625 932,559

Mankayan

8.0217%10.9053%0.6136%19.5406%655,073 890,558 50,108 1,595,739

Atok

7.6186%4.2450%0%11.8636%1,722,755 959,893 -2,682,647

NPC-Beckel

5.8312%5.9870%0.0454%11.8636%4,843,859 4,973,278 37,680 9,854,817

NSC New 20MVA

6.2669%5.5626%0.0341%11.8636%4,104,556 3,643,277 22,323 7,770,156

NSC Old 20MVA

4.7940%7.0544%0.0152%11.8636%2,094,032 3,081,395 6,636 5,182,063

Irisan

3.1611%6.8564%0.0791%10.0966%1,533,634 3,326,440 38,384 4,898,458

Lamut

Non-TechnicalLoss

Technical LossAdmin Loss

MeteringConnection Pt.Loss

Non-TechnicalLossTechnical Loss

AdminLoss

MeteringConnection Pt.Loss

LOSSES IN PERCENTAGE (%)ENERGY LOSSES (KWHR)

Metering Connection

SEGREGATED SYSTEM LOSS PER METERING CONNECTION POINT

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5.5951%P 116,429,07015,816,480.83 TOTAL

15.9540%0.0235%P 488,51866,363.50 LUELCO

9.1927%0.0642%P 1,336,802181,599.91 NPC-Itogon

10.9641%0.0480%P 997,809135,548.81 Ambuclao

9.1774%0.0137%P 284,24338,613.44 Ampuhaw Mini-hydro

3.5755%0.0026%P 54,3137,378.26 Bakun Mini-hydro

9.9594%0.0209%P 435,42459,150.85 Asin Mini-Hyrdo

5.9394%0.1323%P 2,752,501373,917.67 Mankayan

8.0217%0.2317%P 4,822,153655,072.51 Atok

7.6186%0.6094%P 12,681,6271,722,754.60 NPC-Beckel

5.8312%1.7135%P 35,656,8584,843,859.12 NSC New 20MVA

6.2669%1.4520%P 30,214,6634,104,556.00 NSC Old 20MVA

4.7940%0.7408%P 15,414,6932,094,031.95 Irisan

3.1611%0.5425%P 11,289,4651,533,634.21 Lamut

NTL % (Feeder)NTL % (System)Cost of Unrecovered

NTL (Pesos)Non-Technical Loss

(kWhr)Metering Connection

NON-TECHNICAL LOSS PER METERING CONNECTION POINT

ACTIVITIES CONSIDERED AND COSTED FOR NON-TECHNICAL LOSS REDUCTION OPTIMIZATION COMPUTATION

Sole-Use Distribution Transformer Monitoring►

Phased-Out Kwhr Meter Replacement (Old kwhrmeters)►

Kwhr Meter Replacement (apprehended and defective)►

Inspection, Calibration and Apprehension►

Communal Distribution Transformer Block Metering►

Software and Hardware Requirements Procurement►

Loose Connection Correction►

Right-of-Way Clearing►

Streetlight Photo Switching►

Streetlight kwhr Metering►

28

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1321Bakun Mini-hydro13434Bakun Mini-hydro13

1242Mankayan111,723Mankayan11.5

1169Ambuclao121,442Ambuclao11.5

1077Atok102,120Atok10

983Asin Mini-Hyrdo92,366Asin Mini-Hyrdo9

6105Ampuhaw Mini-hydro82,413Ampuhaw Mini-hydro7

886Irisan56,326Irisan6.5

5107NPC-Itogon62,977NPC-Itogon5.5

4155LUELCO72,765LUELCO5.5

788Lamut46,786Lamut5.5

3157NSC New 20MVA211,009NSC New 20MVA2.5

2201NPC-Beckel310,194NPC-Beckel2.5

1430NSC Old 20MVA138,722NSC Old 20MVA1

RANKKWHR NTL / NO. OF METERSRANKKWHR NTL / NO. OF DT's

INSPECTION, APPREHENSION, CALIBRATION

Metering Connection

COMMUNAL TRANSFORMER BLOCK METERING

Metering ConnectionAverage Rank

PRIORITY RANKING IN TERMS OF SELECTED NTL ACTIVITES FOR IMPLEMENTATION

Feeder 6

Feeder 5

NSC Old 20MVA

Feeder 4

Feeder 3

Irisan

Feeder 2

Feeder 1

Lamut

Totalizer 2

Totalizer 1

NPC-Beckel

Feeder 10

Feeder 9

Feeder 8

Feeder 7

NSC New 20MVA

Circuit 5

Circuit 4

Mankayan

Circuit 3

Circuit 2

Circuit 1

Atok

Multi-Feeder Metering Connection Points

LUELCO

NPC-Itogon

Ambuclao

Ampuhaw Mini-hydro

Bakun Mini-hydro

Asin Mini-Hyrdo

Single Feeder Metering Points

FEEDER COVERAGE

56





P 54,130,376.192.8308%2.7644%5.5951%TOTAL =

242,309.48 0.0127%7.343%8.611%15.954%LUELCO

739,469.91 0.0387%3.659%5.534%9.193%NPC-Itogon

649,735.01 0.0340%3.195%7.769%10.964%Ambuclao

135,238.81 0.0071%4.426%4.752%9.177%Ampuhaw Mini-hydro

42,656.16 0.0022%0.520%3.056%3.575%Bakun Mini-hydro

225,901.85 0.0118%4.337%5.623%9.959%Asin Mini-Hyrdo

1,929,917.47 0.1009%1.408%4.532%5.939%Mankayan

2,984,882.11 0.1561%2.618%5.403%8.022%Atok

4,950,875.25 0.2589%4.382%3.237%7.619%NPC-Beckel

17,019,823.88 0.8901%2.802%3.029%5.831%NSC New 20MVA

9,544,620.05 0.4991%4.113%2.154%6.267%NSC Old 20MVA

9,021,486.28 0.4718%1.741%3.053%4.794%Irisan

6,643,459.93 0.3474%1.137%2.024%3.161%Lamut

Optimized ProjectCost for NTL Reduction

% Recovered NTL as per Entire System

% Recovered NTL per Feeder

Level of Optimum %NTL per Feeder

% UnrecoveredNTL per Feeder

Metering Connection

SUMMARY OF OPTIMIZED PROJECT COST FOR NON-TECHNICAL LOSS REDUCTION PROGRAM

NOTE:

Project Cost for implementation per Metering Connection at targeted reduced Non-technical Loss

percentage SHALL NOT EXCEED the computed Optimized Project Cost.

29

57





Cost of Unrecovered VS NTL Reduction Program

0

10

20

30

40

50

60

70

80

90

100

110

120

5.5

95

1%

5.3

85

3%

5.1

75

5%

4.9

65

7%

4.7

55

9%

4.5

46

1%

4.3

36

2%

4.1

26

4%

3.9

16

6%

3.7

06

8%

3.4

97

0%

3.2

87

1%

3.0

77

3%

2.8

67

5%

2.6

57

7%

2.4

47

9%

2.2

38

1%

2.0

28

2%

1.8

18

4%

1.6

08

6%

1.3

98

8%

1.1

89

0%

0.9

79

1%

0.7

69

3%

0.5

59

5%

Mil

lio

ns

Non-Technical Loss (%)

Co

st

(Ph

p)

Cost of Unrecovered NTL

Cost NTL Reduction Program

BENECO NON-TECHNICAL LOSS REDUCTION ECONOMIC ANALYSIS

OPTIMUM LEVEL OF NON-TECHNICAL LOSS REDUCTION = 2.7644%

EQUIVALENT PROJECT COST = P53,447,802.55

Optimum level of loss reduction

58





System Loss Reduction and Control

� Reduction and Control of Technical Losses

� Reduction and Control of Non-Technical Losses

30

59





� Use the results of the Distribution System Loss Segregator for System Loss Reduction Program.� Ranks the losses from the highest to lowest ( Per

Substation, Per feeder, per distribution transformer)

� Prepare a Specific Technical Loss Reduction Program

based on your technical analysis!!!

� Simulate your proposed technical loss reduction solutions

to quantify the technical loss reduction

� Optimize your proposed technical loss reduction solutions

Reduction and Control of Technical Losses

60





� Distribution Rehabilitation Plan� Safety

� Power Quality Problem Correction

� Reduce Technical Losses

� Distribution Expansion Plan� Capacity that complies with Power Quality Standards and

Controlled Technical Losses

PDC: Distribution Development PlanPDC: Distribution Development Plan

•• Technical Analysis Technical Analysis •• Economic Analysis Economic Analysis •• Financial AnalysisFinancial Analysis

Reduction and Control of Technical Losses

31

61





NEA SLRP

� Causes of Pilferages� Long run of secondary networks “conducive” for illegal

tapping

� Services run from one building to the next and attached to various structures (e.g., trees) making it difficult for meter readers to follow the wires or spot illegal connections

� Secondary wiring with “rat’s nest” appearance due to poor workmanship

� Inaccessible meters (located indoor or inside a compound)

� Control of meter seals

� Poor meter records (where and when the meters are installed, maintained, removed, condemned, etc.)

Reduction and Control of Non-Technical Losses

62





NEA SLRP

� Detection of Pilferages� Surveillance Teams (working full time)

� Consumer connections inventory to assure that:• All service connections are metered• All energized services are in an “active” status in the billing system

• There are no illegal taps, by-passed meters, or tampered meters

• Each household is metered separately (no flying taps)

• Each consumer is properly classified1. Match all service connections found in the field to a

distribution transformer2. Match the meter number to the account number3. Check meter reading against previous readings to assure

that meter readings are being properly reported


32

63





NEA SLRP

� Tampered Meters

� In-Place Quick-test for Accuracy

� Hard-to-Detect Tampering• Gear teeth removed• Small hole bored at the top of the meter housing• “Floating Neutral”• Swapping the line-side and load side

� Correcting Problems• Service conductors are not properly supported• Service wire insulation has deteriorated


64





NEA SLRP

� Apprehension of Pilferers

� Confronting the consumer

� Documenting the findings

� Calculating the amount of electricity stolen

� Setting the penalty amount to be charged

� Disconnecting service and removing the meter

• May include policemen or barangay officials


33

65





NEA SLRP

� Punitive Measures Against PilferersR.A. 7832 – Theft of electricity is a crime

� Removal of fraudulent hook-ups

� Collection for unregistered consumption

� Penalty charge

� Connection charge

� Disconnection of service

� Filing charges with judicial authorities

� Charging for tampering with seals

� Regularly scheduled inspections


66





NEA SLRP

� Prevention of Pilferage by Service Entrance Modification

� Installation of meters on the service pole

� Meter clustering in apartment buildings

� Better meter seals

� Security plates or cabinets

� Coaxial service cable


34

67





NEA SLRP

� Political and legal measures

� Strengthening of laws that would impose severe penalties

on employees who collaborate with consumers for the

purpose of defrauding the DU

� Modification of Procedures for recovery and prosecution

� Elimination of political interference with bill collections

� Consistent enforcement practices

� Publicize successes


68





NEA SLRP

� Complaints for low voltage from the customers

� Look for the overload distribution transformers and compared the billings of all customers connected to that DT.

� Distribution transformers that always trips may be suspected for illegal connections.


35

69





SHORT CIRCUIT ANALYSIS

70





1. What is Short Circuit?

2. Short Circuit Studies

3. Selection of Device Duties

Short Circuit Analysis

36

71





+

-

Very Large

Current

Flow

Short Circuit

Very Small Resistance

What is Short Circuit?

∞⇒→

=0R

VI

72






Analogy of Normal and Short Circuit Current in a Hydroelectric plant

37

73





Equipment Explosion because of Short Circuit


74





Line-to-Line Fault

Double Line-to-Ground Fault Single Line-to-Ground Fault

Three Phase Fault

Type of Faults


38

75





FaultMV

LV

UtilityG

Fault Current Contributors

Sources of Short Circuit Currents


76





� Low Voltage Fuses

� Up to 1000 Volts

� High Voltage Fuses

� Above 1000 Volts

What is Short Circuit?PROTECTIVE DEVICES: FUSE

39

77





What is Short Circuit?PROTECTIVE DEVICES: LOW VOLTAGE

CIRCUIT BREAKERS

Molded-Case Circuit Breakers

Low Voltage Power Circuit

Breakers

78





Substation Vacuum Circuit Breakers

Outdoor-Type Circuit Breaker in Switchyard

What is Short Circuit?PROTECTIVE DEVICES: HIGH VOLTAGE

CIRCUIT BREAKERS

40

79





What is Short Circuit?PROTECTIVE DEVICES: HIGH VOLTAGE

CIRCUIT BREAKERS

Indoor Type Circuit Breaker in a Switchgear

80





Short Circuit Studies

Short Circuit Current and Time Characteristics of Protective Devices

41

81






� Comparison of Momentary and Interrupting Duties of Interrupting Devices

� Comparison of Short-time or withstand rating of system components

� Selection of rating or setting of short circuit protective devices

� Evaluation of current flow and voltage levels in the system during fault

82





� First Cycle Fault Current

� Short circuit ratings of low voltage equipment

� Ratings of Medium Voltage (MV) to High Voltage (HV) switch and fuse

� Close & Latch (Making) capacity or ratings of HV Circuit Breakers

� Maximum Fault for coordination of instantaneous trip of relays


42

83





� 1.5 to 4 Cycles Fault Current

� Interrupting (breaking) duties of HV circuit breakers

� Interrupting magnitude and time of breakers for coordination

� 30 Cycles Fault Current

� For time delay coordination


84





� ANSI/IEEE: American National Standards Institute/ Institute of Electrical and Electronics Engineers

� IEC: International ElectrotechnicalCommission

Prescribes Test Procedures and

Calculation Methods

Selection of Device Duties

43

85





Selection of Device Duties

40.277428013.8 KV13.8 – 1000

30.45813.56013.8 KV13.8 – 750

19.637214013.8 KV13.8 – 500

46.97848.6804.16 KV4.16 – 350

33.25835604.16 KV4.16 – 250

10.11910.5204.16 KV4.16 – 75

Short-Circuit Capability (Symmetrical RMS Current at 3-Cycle Parting

Time

Closing and Latching

Capability (Total First Cycle RM Current)

Interrupting Rating (Total RMS Current at 4-cycle Contact-Parting Time

Momentary Rating (Total 1st-Cycle RMS Current

Example Maximum System Operating Voltage

Circuit Breaker Nominal Size Identification

8-Cycle Total-Rated Circuit Breakers (KA)

5-Cycle Symmetrical-Rated Circuit Breakers (KA)

86





COMPARISON OF DUTIES

S/S 3 2.30005 1.99190 2.86464 2.76467 2.86464 15 524 % Adequate

PG-17 3 2.09517 1.81447 2.32896 2.21705 2.32896 4 172 % Adequate

PG-26 3 1.98127 1.71583 2.10904 1.96635 2.10904 4 190 % Adequate

PG-40 3 1.82417 1.57978 1.85435 1.66821 1.85435 4 216 % Adequate

PG-52 3 1.70334 1.47514 1.68370 1.46936 1.70334 4 235 % Adequate

PG-53 3 1.69336 1.46650 1.67035 1.45395 1.69336 4 236 % Adequate

PG-63 3 1.59908 1.38485 1.54879 1.31529 1.59908 4 250 % Adequate

PG-17-1 3 2.08156 1.80268 2.30059 2.18533 2.30059 4 174 % Adequate

PG-17-2 1 0.00000 0.00000 0.00000 2.14564 2.14564 4 186 % Adequate

PG-17-1-3 1 0.00000 0.00000 0.00000 2.01008 2.01008 4 199 % Adequate

PG-17-2-3 1 0.00000 0.00000 0.00000 2.06014 2.06014 4 194 % Adequate

PG-17-3-7 1 0.00000 0.00000 0.00000 1.87921 1.87921 4 213 % Adequate

PG-26-5 3 1.86883 1.61845 2.15303 1.79814 2.15303 4 186 % Adequate

PG-26-5-3 1 0.00000 0.00000 0.00000 1.54157 1.54157 4 259 % Adequate

PG-40-2 3 1.78352 1.54457 1.83166 1.61561 1.83166 4 218 % Adequate

PG-40-2-5 1 0.00000 0.00000 0.00000 1.50666 1.50666 4 265 % Adequate

PG-40-2-6 1 0.00000 0.00000 0.00000 1.58620 1.58620 4 252 % Adequate

PG-52-7 1 0.00000 0.00000 0.00000 1.38134 1.38134 4 290 % Adequate

PG-53-1 1 0.00000 0.00000 0.00000 1.44395 1.44395 4 277 % Adequate

LATERAL LINES

LATERAL LINES

LATERAL LINES

BACKBONE LINES

LATERAL LINES

LATERAL LINES

RemarksSLGF

(KA)

MAX

I

SC

DutyMargin

TFF

(KA)BUS ID

LLF

(KA)

DLGF

(KA)PHASE

44

87





POWER SYSTEM RELIABILITY ANALYSIS

88





Reliability Analysis

1. What is Reliability?

2. Measuring Reliability

3. Component Reliability

4. System Reliability

5. Distribution System Reliability

6. Economics of Power System Reliability

45

89





� Outage (Component State)

Component is not available to perform its intended function due to the event directly associated with that component (IEEE-STD-346).

� Interruption (Customer State)

Loss of service to one or more consumers as a result of one or more component outages (IEEE-STD-346).

� Types of Interruptions

Momentary Interruption. Service restored by switching operations (automatic or manual) within a specified time (5 minutes per IEEE-STD-346).

Sustained Interruption. An interruption not classified as momentary

What is Reliability?

90





A reliable piece of equipment or a System is understood to be basically sound and give trouble-free performance in a given environment.

But, How do you measure reliability? How do we compare reliability of the same equipment from two different manufacturers?

Definition of Reliability

Reliability is the probability that an equipment or system will perform satisfactorily for at least a given period of time when used under stated conditions.

What is Reliability?

46

91





System

Failure

Failure

Events

Mathematical

Reliability

Model

Reliability Data

Application

(Reliability Index)

1

2

3

4

5

Measuring Reliability

Power System Reliability Evaluation

92





INCIDENTS

HISTORICAL

ASSESSMENT

COMPONENT

PERFORMANCE

PREDICTIVE

ASSESSMENT

ORGANIZATION,

CUSTOMER, kVA

COMPONENT

POPULATION

SYSTEM

DEFINITION

HISTORICAL SYSTEM

PERFORMANCE

MANAGEMENT

OPERATIONS

ENGINEERING

CUSTOMER INQUIRIES

PREDICTED SYSTEM

PERFORMANCE

COMPARATIVE EVALUATIONS

AID TO DECISION-MAKING

PLANNING STUDIES

Measuring Reliability

47

93





Component Reliability

Component Failure Data

26610

1869

1418

1117

866

635

464

343

202

81

Time-to-Failure (hrs.)Item No.How Reliable

is the

component?

94





Failure Density Function

f(t)

80186 – 266

45141 – 186

30111 – 141

2586 – 111

2363 – 86

1746 – 63

1234 – 46

1420 – 34

128 – 20

80 – 8

f(t)∆∆∆∆tiTime

0013.080

101=

0022.045

101=

0033.030

101=

0084.012

101=

0074.014

101=

0084.012

101=

0125.08

101=

measure of the overall speedat which failures are occurring.

0059.017

10=

0043.023

101=

0040.025

101=

1


48

95





0.2

0.4

0.6

0.8

1.0

1.2

1.4

100 200 300

f(t)

fra

ctiona

l fa

ilure

s/h

r.x1

0-2

00

Operating time, hr.

Failure Density Function from Component Failure Data


96





Failure Hazard Function h(t)

80186 – 266

45141 – 186

30111 – 141

2586 – 111

2363 – 86

1746 – 63

1234 – 46

1420 – 34

128 – 20

80 – 8

h(t)∆∆∆∆tiTime

0125.08

101=

093.012

91=

0096.014

81=

0119.012

71=

0111.030

31=

0111.045

21=

0125.080

11=

measure of the instantaneous speed of failure

[Propones to Failure]

0098.017

61=

0087.023

51=

0100.025

41=


49

97





0.2

0.4

0.6

0.8

1.0

1.2

1.4

100 200 30000

h(t

) fa

ilure

s/h

r.x1

0-2

Operating time, hr.

Hazard Function from Component Failure Data


0.011 failure/hr x 8760 hrs/yr = 97 failures/yr

98






( )( )∫=

−t

dh

etR 0ττ

Reliability Function

For a component with a constant Hazard

h = 0.01 f/yr

h = 0.02 f/yr

R(1) = 0.99

R(1) = 0.98

[Probability that the component will not fail in 1 year]

For the component with a hazard rate of 0.011 f/hr,

R(1 hour) = 0.989 R(24 hours) = 0.768

50

99





( )th

λ

t

a. Constant Hazard b. Increasing Hazard


t

( )th

Kt

( )th

t

0K

10 KK0t

a. Decreasing Hazard

( )( )∫=

−t

dh

etR 0ττ

Reliability Function

100





a. Hazard Function

b. Failure Density Function

The Bathtub Curve


51

101





Hazard Model for Different System

a. Mechanical b. Electrical c. Software


102





Hazard function

( ) Kth

1

2

3

4

5

1 2→t5.0m −=

0m =5.0m =

1m =

2m =3m =

Weibull Model (A General Reliability Model)


Reliability function

( )tR

1

2

3

4

5

1 2→τ

5.0m −=0m =

5.0m =

1m =2m =3m =

52

103





• 1997: 996 DT Failures

• Average of three (3) DT Failures/day

• Lost Revenue during Downtime

• Additional Equipment Replacement Cost

• Lost of Customer Confidence

Distribution Transformer Failures

RELIABILITY ASSESSMENTof MERALCO Distribution Transformers*

* R. R. del Mundo, et. al. (2000)

� Identify the Failure Mode of DTs

� Develop strategies to reduce DT failures


104





•Gather Equipment History (Failure Data)

• Classify DTs (Brand, Condition, KVA, Voltage)

•Develop Reliability Model

•Determine Failure Mode

• Recommend Solutions to Improve Reliability

METHODOLOGY: Reliability Engineering(Weibull Analysis of Failure Data)


53

105





Parametric Model

• Shape Factor Failure Mode

• Characteristic Life

Shape Factor Hazard Function Failure Mode

< 1 Decreasing Early

= 1 Constant Random

> 1 Increasing Wear-out


106





MERALCO DTs (1989–1997)

51,1292,3381,5881,11844,341TOTAL

69----H

79----G

168----F

192----E

2,344-901162,037D

6,5612131496,358C

6,5862691351185,986B

34,7122,0481,33383529,960A

TotalConvertRewindRecondNewBrand

Note: Total Include Acquired DTs


54

107





Reliability Analysis: All DTsInterval Failures Survivors Hazard

200 1444 57095 0.0269

400 797 48852 0.0178

600 638 39997 0.0174

800 508 32802 0.0167

1000 475 27515 0.0189

1200 363 22129 0.0178

1400 295 18200 0.0178

1600 224 14690 0.0167

1800 159 11865 0.0151

2000 89 9010 0.0114

2200 98 6473 0.0177

2400 51 4479 0.015

2600 19 2254 0.0122

2800 2 821 0.0042

3000 0 127 0


108





0

0.005

0.01

0.015

0.02

0.025

0.03

0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000

Haza

rd

Time Interval

Weibull Shape = 0.84

Reliability Analysis: All DTs

Failure Mode: EARLY FAILURE

Is it Manufacturing Defect?


55

109





BRAND Size Shape Failure Mode

A 34712 0.84 Early Failure

B 6586 0.81 Early Failure

C 6561 0.86 Early Failure

D 2344 0.76 Early Failure

E 192 0.85 Early Failure

F 168 0.86 Early Failure

G 79 0.76 Early Failure

H 69 0.98 Early Failure

Reliability Analysis: By Manufacturer


110





BRAND New Reconditioned Rewinded Converted

A 1.11 1.23 1.12 1.4

B 0.81 1.29 1.27 1.23

C 0.81 1.13 0.77 0.94

D 0.67 1.11 1.49 -

Reliability Analysis: By Manufacturer & Condition


56

111





Reliability Analysis: By Voltage Rating

PRI SEC All DTs New DTs

20 7.62 0.75 -

20 120/240 0.79 0.94

20 139/277 1.14 1.1

20 DUAL 0.72 1.03

13.2 120/240 0.88 1.54

13.2 240/480 0.91 -

7.62 120/240 0.99 1.46

7.62 DUAL 0.77 -

4.8 120/240 0.87 1.61

3.6 120/240 0.78 1.17

2.4 120/240 1.15 -


112





KVA Shape Failure Mode

10 1.3 Wear-out

15 1.25 Wear-out

25 0.92 Early

37.5 0.83 Early

50 0.73 Early

75 1.05 Random

100 1.04 Random

167 1.16 Random

250 1.11 Random

333 1.46 Wear-out

Reliability Analysis: By KVA Rating (New DTs)


57

113





MERALCO Distribution Transformer Reliability Analysis: Recommendations

• Review Replacement Policies

- New or Repair

- In-house or Remanufacture

• Improve Transformer Load Management Program

- Predict Demand Accurately (TLMS)

• Consider Higher KVA Ratings

• Consider Surge Protection for 20 kV DTs


114





Hazard

rate

m 2m 3m

Effect of PM on Decreasing Hazard Rate

Hazard

rate

m 2m 3m

Effect of PM on Constant Hazard Rate

Hazard

rate

m 2m 3m

Effect of PM on Increasing Hazard Rate


Preventive Maintenance and Hazard Rates

58

115






RELIABILITY ASSESSMENTof MERALCO Power Circuit Breakers*

* R. R. del Mundo & Melendrez (2001)

VOLTAGE OCB VCB GCB MOCB ACB

34.5 KV 149 160 41

13.8 KV 7 28 2 36 12

6.24 KV 26 3 122

4.8 KV 2 11

TOTAL 156 216 43 39 145

Number of Feeder Power Circuit Breakers

116





Annual Failures of 34.5 kV OCBs

2.6363145414961553158Totals

0.645----1155--Mechanism Failure

1.3171145314931551158Bushing Failure

1.152145114921552158Contact Wear

FailedInstalled FailedInstalledFailedInstalledFailedInstalled

Average Failures

(Units/yr)

2000199919981997Causes of

Failure

3 Circuit Breakers failing per year!

Preventive Maintenance Policy: Time-based (Periodic)



59

117





HAZARD FUNCTION CURVE FOR ALL PCBs CONSIDERED

0

0.1

0.2

0.3

0.4

3 6 9 12 15 18 21 24 27 30 33 36 39 42 45 48 51 54 57 60

Time Interval (months)

Ha

za

rd R

ate

.

All PCBs

HAZARD FUNCTION CURVE FOR 34.5 KV OCBs

0

0.1

0.2

0.3

0.4

3 6 9 12 15 18 21 24 27 30 33 36 39 42 45 48 51 54 57 60


Ha

za

rd R

ate

34.5 kV OCBS OCBs

HAZARD FUNCTION CURVE FOR 34.5 KV GCBs

0

0.05

0.1

0.15

0.2

6 12 18 24 30 36 42 48 54 60


Ha

za

rd R

ate

34.5 kV GCBs

HAZARD FUNCTION CURVE FOR 13.8 KV MOCBs

0

0.1

0.2

0.3

0.4

3 6 9 12 15 18 21 24 27 30 33 36 39 42 45 48 51 54 57 60


Ha

za

rd R

ate

13.8 kV MOCBs

HAZARD FUNCTION CURVE FOR 6.24 KV MOCBs

0

0.1

0.2

0.3

0.4

3 6 9 12 15 18 24 30 36 42 48 54 60


Ha

za

rd R

ate

6.24 kV MOCBs

HAZARD FUNCTION CURVE FOR 6.24 KV ACBs

0

0.05

0.1

0.15

0.2

6 12 18 24 30 36 42 48 54 60


Ha

za

rd R

ate

6.24 kV ACBs

Reliability Assessment of MERALCO Power Circuit Breakers

TIME-BASED HAZARD FUNCTION

118





TRIPPING OPERATIONS-BASED HAZARD FUNCTION


00.05

0.10.15

0.20.25

5 10 15 20 25 30 35

Tripping Interval

Ha

za

rd R

ate


00.05

0.10.15

0.20.25

5 10 15 20 25 30 35

Tripping Interval

Ha

za

rd R

ate

y = 0.00006x2 – 0.0007x

+ 0.032


0

0.01

0.02

0.03

0.04

0.05

25 50 75 100 125 150

Tripping Interval

Ha

za

rd R

ate

All PCBs

34.5 kV OCBS OCBs 34.5 kV GCBs 13.8 kV MOCBs

6.24 kV MOCBs 6.24 kV ACBs


0

0.01

0.02

0.03

0.04

0.05

25 50 75 100 125 150

Tripping Interval

Ha

za

rd R

ate

HAZARD FUNCTION CURVE FOR 6.24 KV

MOCBs

0

0.1

0.2

0.3

5 10 15 20

Tripping Interval

Ha

za

rd R

ate

HAZARD FUNCTION CURVE FOR 6.24 KV

MOCBs

0

0.1

0.2

0.3

5 10 15 20

Tripping Interval

Ha

za

rd R

ate

Reliability Assessment of MERALCO Power Circuit Breakers

60

119





Schedule of Servicing for 41XV4

0

0.02

0.04

0.06

0.08

0 10 20 30 40 50 60 70

Number of Tripping Operations

Hazard

Rate

Reliability-BasedPreventive Maintenance Schedule



120





System Reliability

Series Reliability Model

This arrangements represents a system whose subsystems of components form a series network. If any of the subsystem of component fails, the series system experiences an overall system failure.

R(x1) R(x2) R(x3) R(x4)

Series System

( )∏=

=n

i

is xRR1

61

121





Parallel Reliability Model

R(x1)

R(x2)

R(x3)

R(x4)

Parallel Network

This structure represents a system that will fail if and only if all the units in the system fail.

( )[ ]∏=

−−=n

i

is xRR1

11

System Reliability

122





Standby Redundancy Model

This type of redundancy represents a distribution with one

operating and n units as standbys. Unlike a parallel network

where all units in the configuration are active, the standby units

are not active.

R(x1)

R(x2)

R(x3)

R(x4)

System Reliability

62

123





K-Out-of-N Reliability Model

This is another form of redundancy. It is used where a specified number of units must be good for the system success.

R(x1)

R(x2)

R(x3)

The system reliability for k-out-of-n number of independent and identical units is given by

∑=

−−

=

n

ki

ini

s )R(Ri

nR 1

System Reliability

124





Primary side

Secondary side

1

2

3

45

6

7

89

10

11

12

13

14

15

1617

18

19

2021

22

23

2425

26

27

28

29

30

31

32

33

34

35

3637

38

39

40

41

4243

44

4546

47

4849

50

51

52

5354

55

56

57

58

Scheme 1: Single breaker-single bus(primary and secondary side)

Reliability Network Models for Typical Substation Configurations of MERALCO*

System Reliability Networks

* Source: A. Gonzales (Meralco) & R. del Mundo (UP), 2005

63

125





15λλλλc 29λλλλct 2λλλλbus 4λλλλd1 2λλλλb1λλλλp 2λλλλb2 3λλλλd2

Summary of Substation Reliability Indices for Scheme 1

0.8287840.2471521.0Total

Opened 115kV bus tie breaker & opened 34.5kV bus tie breaker (normal condition)

0.8287840.2471521.0

Us (hr/yr)λs (failure/yr)ProbabilityEvent 1

where: λλλλs - substation failure rate or interruption frequency

Us – substation annual outage time or unavailability

Reliability Network Diagram of Single breaker-single bus scheme (Scheme 1)


126





Primary side

Secondary side

1

2

3

4

7

65

8

9

10 11

12

13

14

15

1617

18

1920

21

22

23

24

25

26

2728

2930

31

32

3334

35

36

37

38

39

40

41

42

43

44

45

46

4748

49

50

51

5253

5455

61

5657

58

5960

62

6364

6566

67

68

69

70

71

72

7374

75

76

77

78

79

80

81

82

8384

8586

8788

89

90

91

92

93

94

95

96

97

98

99

100

101

102

103

104105

106107

108

109

110111

112

113

114

115

116

117

118

119

120

121

122123

124125

126

127128

129

130

131132

133

134

135136

137

138

139

140

141

L1 L2

Bank 2Bank 1Scheme 2: Single breaker-double bus (primary side) and two single breaker-single bus with bus tie breaker (secondary side)

Reliability Network Models for Typical Substation Configurations of MERALCO


64

127






20λλλλc 37λλλλct 3λλλλbus5λλλλd1 2λλλλb1

λλλλp 2λλλλb2 3λλλλd2



Event 1: Opened 115kV and 34.5kV bus tie breakers; P1 = 0.997985

Event 2: Closed 115kV bus tie breaker & opened 34.5kV bus tie breaker; P2 = 0.000188

Event 3: Closed 115kV bus tie breaker & closed 34.5kV bus tie breaker; P3 = 0.000000344

Event 4: Opened 115kV bus tie breaker & closed 34.5kV bus tie breaker; P4 = 0.00182614

Substation Reliability ModelsSubstation Reliability Models

Reliability Network Diagram of Single breaker-double bus with normally opened 115kV bus tie breaker (Scheme 2)

128





0.8492750.2518661.0Total

1.0238400.3089360.0018264

1.0238400.3089360.0000003443

1.0083740.3029660.0001882

0.8489190.2517520.9979851

Us (hr/yr)λs (failure/yr)ProbabilityEvent

Summary of Substation Reliability Indices for Scheme 2

Event 1: With two primary lines energized & opened 34.5kV bus tie breaker; P1 = 0.997985


65

129





λλλλΒ4λλλλ54 λλλλΒ3

λλλλΒ1

λλλλΒ6λλλλΒ4

λλλλΒ3

λλλλΒ7

λλλλΒ2

λλλλΒ7


λλλλΒ4

λλλλΒ3

λλλλ29

λλλλΒ1

λλλλ17

λλλλΒ1


λλλλΒ3

λλλλ29

λλλλΒ2

λλλλΒ6


λλλλΒ5


Substation Reliability ModelsSubstation Reliability ModelsReliability Network Diagram of Single breaker-double bus with normally closed 115kV bus tie breaker (Modified Scheme 2)

Event 2: With one line, L2 interrupted & opened 34.5kV bus tie breaker; P2 = 0.000188

λλλλB1 λλλλB2 λλλλB3 λλλλB4λλλλB5

λλλλ17

Event 3: With one line, L2 interrupted and closed 34.5kV bus tie breaker; P3 = 0.000000344

λλλλ29 λλλλB1 λλλλB2λλλλ17 λλλλB5

λλλλB8 λλλλB9 λλλλB10 λλλλB11

130





Event 4: With two lines energized and closed 34.5kV bus tie breaker; P4 = 0.001826140

λλλλΒ1

λλλλΒ6

λλλλΒ10

λλλλΒ1

λλλλΒ7 λλλλΒ4

λλλλΒ3

λλλλ17

λλλλΒ6

λλλλΒ7



λλλλΒ4

λλλλΒ3

λλλλΒ6

λλλλΒ2

λλλλ111λλλλ29 λλλλΒ11

λλλλΒ6


λλλλΒ3

λλλλΒ8

λλλλΒ7

λλλλΒ9


λλλλΒ4

λλλλΒ3

λλλλ17

λλλλΒ7

Substation Reliability ModelsSubstation Reliability ModelsReliability Network Diagram of Single breaker-double bus with normally closed 115kV bus tie breaker (Modified Scheme 2)

0.5839230.1761941.0Total

0.7584720.2332610.0018264

1.2615490.3771200.0000003443

0.8476210.2511220.0001882

0.5835480.1760760.9979851

Us,(hr/yr)λs (failure/yr)ProbabilityEvent

Summary of Substation Reliability Indices for Modified Scheme 2

66

131





0.5839230.176194Modified (closed 115kV bus tie breaker)

0.8492750.251866Original (opened 115kV bus tie

breaker)

Us (hr/yr)λs (failure/yr)Scheme 2

Comparison of Substation Reliability Indices for Scheme 2

Note: A remarkable 30% improvement in the performance of Scheme 2 by making the 115kV bus tie breaker normally closed.


132





Primary side

Secondary side

1

2

3

4

5

67

8

9

1011

1213

1415

16

17

18

19

2021

22

23

2425

26

27

2829

30

31

32

33

34

35

36

37

38

3940

4142

43

4445

46

47

48

49

5051

5253

54

55

5657

58

59

6061

62

63

64

65

66

67

6869

7071

7273 74

75

7677

7879

8081

82

83

95

84

8586

87

88

8990

9192

93

94

96

97

98

99

100101

102

103

104 105

106

107

108109

110

111

112

113114 115

116

117

118

119

120

121

122

123

124

125

126

127

128

129

130

B2

B3

B5

B6

B7 B8

B10

B9

B1 B4

3 69

Bank 1 Bank 2Scheme 3: Ring bus (primary side) and two single breaker-single bus with bus tie breaker (secondary side)



67

133





λλλλ17

λλλλB1

λλλλB4

λλλλB1

λλλλB5

λλλλB6

λλλλB4

λλλλB2

λλλλB3

λλλλB2

λλλλB5

λλλλ51 λλλλB7 λλλλB10


Event 2: With two primary lines energized & closed 34.5kV bus tie breaker; P2 = 0.00182614

λλλλ31

λλλλB1

λλλλB4

λλλλB1

λλλλB5

λλλλB6

λλλλB4

λλλλB2

λλλλB3

λλλλB3

λλλλB6

λλλλB8 λλλλB9 λλλλ51 λλλλB10

Substation Reliability ModelsSubstation Reliability ModelsReliability Block Diagram of Ring Bus Scheme (Scheme 3)

134





Event 3: With one primary line (L2) interrupted and opened 34.5kV bus tie breaker; P3 = 0.000188056

λλλλ17

λλλλB2

λλλλB3

λλλλB2

λλλλB5

λλλλB7 λλλλ51 λλλλB10λλλλB1

λλλλB2

λλλλ31

λλλλB2

λλλλB6

Event 4: With one primary line (L2) interrupted and closed 34.5kV bus tie breaker; P4 = 0.000000344

λλλλ31

λλλλB2

λλλλB3

λλλλB3

λλλλB6

λλλλB8 λλλλB9 λλλλ51λλλλB1

λλλλB3

λλλλ17

λλλλB3

λλλλB5

λλλλB10

Substation Reliability ModelsSubstation Reliability ModelsReliability Block Diagram of Ring Bus Scheme (Scheme 3)

CONT.

68

135





0.4368360.1380341.0Total

0.6501140.2044670.0000003444

0.4682330.1472830.0001883

0.6183790.1951120.0018262

0.4364990.1379280.9979851


Summary of Substation Reliability Indices of Ring Bus (Scheme 3)


136





Secondary

side

Primary

side

1

2

34

56

78

9

1

0

1

1

1

2

1

3

1

4

1

5

16

1

7

1

8 19

2

02

12

2 232

4 2

62

82

9

3

0313

23

33

4 353

6 3

73

83

94

0414

2

11

9

4

3

44

4

5

7

9

4

6

4

74

8 4

9505

15

25

3 5

455 5

6575

85

9 606

1

6

263 6

46

56

66

76

86

9 7

07

1 7

27

374

7

5767

7

7

8

8

0

8

1

8

2

8

3

8

4

8

5

8

6

8

7

8

8

8

9

9

0

9

1

9

2

93

94

9

59

6979

8 9

910

010110

2 10

310

4 10

5

10

610

710

810

911

0 111

11

211

311

4 11

511

6 11711

8

12

0

121

12

2

12

3

12

412

5 126

12712

812913

0 13

113

213

313

4 13

5136 13

713

813

914

0

141

14

2

14

3

14

414

5

14

6

14

7

148

14

9

150

15

1

15

2

153

154

3

2

9

8

0

10

5

B1

B2

B3

B4

B5

B8

B6

B7

B9 B10

B1

1

2

52

7

L

1

L

2

Bank

1

Bank

2Scheme 4: Breaker-and-a-half bus (primary

side) and two single breaker-single bus with bus tie breaker

(secondary side)



69

137





λλλλΒ1

λλλλΒ5

λλλλΒ12

λλλλΒ3

λλλλΒ4

λλλλΒ2

λλλλΒ8

λλλλ6

λλλλ17

λλλλΒ1λλλλ6

λλλλ17

λλλλ7

λλλλΒ1

λλλλΒ7

λλλλ33

λλλλΒ2

λλλλΒ3

λλλλΒ7

λλλλΒ6

λλλλΒ1

λλλλ34

λλλλΒ3

λλλλ33

λλλλΒ5

λλλλΒ2

λλλλΒ3

λλλλΒ4

λλλλΒ3

λλλλ119

λλλλΒ3

λλλλΒ7


λλλλΒ9 λλλλ62

λλλλΒ4

λλλλΒ3

λλλλΒ8

λλλλΒ3

A

Event 1: With two primary lines energized and opened 34.5kV bus tie breaker; P1 = 0.997985

λλλλΒ2

λλλλΒ5

λλλλ6

λλλλ119


λλλλΒ8

λλλλ7

λλλλΒ3

λλλλΒ5

λλλλ33

λλλλΒ2

λλλλΒ3

λλλλ17

λλλλΒ5

λλλλΒ3

λλλλ34

λλλλΒ3

λλλλ33

λλλλΒ6

λλλλΒ3

λλλλΒ5

λλλλΒ2

λλλλΒ2

λλλλ6

λλλλΒ4


λλλλ119

λλλλ7

λλλλΒ1

λλλλΒ2

λλλλ33

λλλλΒ2

λλλλΒ3

λλλλΒ7

λλλλΒ2

λλλλΒ1

λλλλ34

λλλλΒ3

λλλλ33

λλλλΒ8

λλλλΒ1

λλλλΒ2

λλλλ34

λλλλΒ3

λλλλ33

λλλλ17

λλλλΒ1

λλλλΒ4A

λλλλ33

λλλλΒ2

λλλλΒ3

λλλλ119

λλλλ17

λλλλΒ1


Reliability Block Diagram of Breaker-and-a-half Scheme (Scheme 4)

138





λλλλΒ1

λλλλΒ5

λλλλΒ12

λλλλΒ7

λλλλΒ8

λλλλΒ2

λλλλΒ8

λλλλ6

λλλλ17


λλλλΒ7

λλλλ7

λλλλΒ1

λλλλΒ2

λλλλ33

λλλλΒ2

λλλλΒ3

λλλλΒ7

λλλλΒ6

λλλλΒ1

λλλλ34

λλλλΒ3

λλλλ33

λλλλΒ5

λλλλΒ2

λλλλΒ3

λλλλΒ4

λλλλΒ3

λλλλ119

λλλλΒ7

λλλλΒ7


λλλλΒ11 λλλλ62

λλλλΒ4

λλλλΒ3

λλλλΒ7

λλλλΒ4

Aλλλλ139λλλλΒ10

λλλλΒ2

λλλλΒ5

λλλλ6

λλλλΒ7

λλλλ119λλλλ6

λλλλ17

λλλλ7

λλλλΒ4

λλλλΒ5

λλλλ33

λλλλΒ2

λλλλΒ3

λλλλΒ8

λλλλΒ6

λλλλΒ5

λλλλ34

λλλλΒ3

λλλλ33

λλλλΒ6

λλλλΒ4

λλλλΒ5

λλλλΒ2

λλλλΒ4

λλλλ6

λλλλΒ5


λλλλ119

λλλλ7

λλλλΒ2

λλλλΒ5

λλλλ33

λλλλΒ2

λλλλΒ3

λλλλΒ6

λλλλΒ5

λλλλΒ3

λλλλ34

λλλλΒ3

λλλλ33

λλλλΒ8

λλλλΒ2

λλλλΒ5

λλλλ34

λλλλΒ3

λλλλ33

λλλλ17

λλλλΒ3

λλλλΒ5A

λλλλ33

λλλλΒ2

λλλλΒ3

λλλλ119

λλλλ17

λλλλΒ5

λλλλΒ2

λλλλΒ5

λλλλ6

λλλλΒ6

λλλλ119

Event 2: With two primary lines energized and closed 34.5kV bus tie breaker; P2 = 0.001826



70

139





λλλλΒ3


λλλλΒ3

λλλλΒ8

λλλλΒ6

λλλλΒ7


λλλλΒ4

λλλλΒ3

λλλλ119

λλλλΒ6

AλλλλΒ12λλλλΒ9 λλλλ62 λλλλΒ5

λλλλΒ4

λλλλΒ3

λλλλΒ4

λλλλΒ6

λλλλΒ4

λλλλΒ3

λλλλ17

λλλλΒ7

λλλλΒ8


λλλλΒ3

λλλλΒ4

λλλλ17

λλλλ119


λλλλΒ4

λλλλΒ3

λλλλΒ4

λλλλΒ2

λλλλΒ4

λλλλΒ3

λλλλΒ2

λλλλ119

λλλλΒ4

λλλλΒ3

λλλλΒ3

λλλλ119

λλλλΒ7


λλλλΒ3

λλλλ17

λλλλΒ8

λλλλΒ3


λλλλΒ4

λλλλΒ3

λλλλΒ2

λλλλΒ8

A

Event 3: With one primary line (L1) interrupted and opened 34.5kV bus tie breaker; P3 = 0.000188



140





λλλλΒ12λλλλΒ11 λλλλ62

λλλλΒ7


λλλλΒ3

λλλλ17

λλλλΒ7

λλλλΒ7


λλλλΒ4

λλλλΒ3

λλλλΒ2

λλλλΒ7

λλλλ139λλλλΒ10

λλλλΒ7


λλλλΒ3

λλλλΒ7

λλλλ119

λλλλΒ7


λλλλΒ5

Event 4: With one primary line (L1) interrupted and closed 34.5kV bus tie breaker; P4 = 0.000000344

Summary of Substation Reliability Indices of Breaker-&-a-half (Scheme 4)

0.4355450.1374131.0Total

0.6431650.2044730.0000003444

0.4669720.1466740.0001883

0.6114330.1951200.0018262

0.4352140.1373060.9979851



� Reliability Block Diagram of Breaker-and-a-half Scheme (Scheme 4)

71

141





0.4355450.137413Scheme 4 (Breaker-and-a-half bus)

0.4368360.138034Scheme 3 (Ring bus)

0.849275

0.583923

0.251866

0.176194

Scheme 2 (Single breaker-double bus)- with normally opened 115kV tie bkr.- with normally closed 115kV tie bkr.

0.8287840.247152Scheme 1 (Single breaker-single bus)

Us (hrs/yr)λs (failures/yr)Configuration

Comparison of Substation Reliability Indices (Scheme 1 to 4)

Note: Scheme 3 & 4 - better than Scheme 1 & 2 by 44% & 45% respectively for substation failure rates.Scheme 3 & 4 - better than Scheme 1 & 2 by 47% & 49% respectively for substation interruption duration or unavailabilty.Scheme 3 & 4 - better than Modified Scheme 2 by 22% & 25% for substation failure rates & unavailability, respectively



142





Distribution System Reliability

CUSTOMER-ORIENTED RELIABILITY INDICES

System Average Interruption Frequency Index (SAIFI)*The average number of interruptions per customer served

during a period

System Average Interruption Duration Index (SAIDI)The average interruption duration per customer served during a

period

servedcustomers of number Total

onsinterrupti customer of number otalTSAIFI =


duration oninterrupti customer of umSSAIDI =

Note: SAIFI for Sustained interruptions. MAIFI for Momentary Interruptions

72

143






Customer Average Interruption Frequency Index (CAIFI)

The average number of interruptions per customer interrupted

during the period

Customer Average Interruption Duration Index (CAIDI)

The average interruption duration of customers interrupted

during the period

dinterrupte customers of number Total

onsinterrupti customer of number otalTCAIFI =

dinterrupte customers of number Total

duration oninterrupti customer of umSCAIDI =


144






Average Service Availability Index (ASAI)

The ratio of the total number of customer hours that service

was available during a year to the total customer hours

demanded

Average Service Unavailability Index (ASUI)

The ratio of the total number of customer hours that service

was not available during a year to the total customer hours

demanded


demanded hours Customer

serviceavailable of hours ustomerCASAI =

demanded hours Customer

serviceeunavailabl of hours ustomerCASUI =

73

145





LOAD- AND ENERGY-ORIENTED RELIABILITY INDICES

Average Load Interruption Index (ALII)

The average KW (KVA) of connected load interrupted per year

per unit of connected load served.

Average System Curtailment Index (ASCI)

Also known as the average energy not supplied (AENS). It is

the KWh of connected load interruption per customer served.


load d connecte Total

oninterrupti load TotalALII =


tcurtailmenenergy TotalASCI =

146





LOAD- AND ENERGY-ORIENTED RELIABILITY INDICES

Average Customer Curtailment Index (ACCI)

The KWh of connected load interruption per affected customer

per year.


affected customers of number Total

tcurtailmenenergy TotalACCI =

74

147





Required Data:

1. Exposure Data

N - total number of customers served

P - period of observation

2. Interruption Data

Nc - number of customers interrupted on interruption i

d - duration of ith interruption, hours

Number of

customers

interrupted

Time

1N

1d

2N

2d3N

3d

Historical Reliability Performance Assessment


148





L1 L2 L3

A B CSource

S 1 2 3

Load PointNumber of

Customers

Average Load

Demand (KW)

L1 200 1000

L2 150 700

L3 100 400

SYSTEM LOAD DATA

Interruption

Event i

Load Point

Affected

Number of

Disconnected

Customers

Average Load

Curtailed (KW)

Duration of

Interruption

1 L3 100 400 6 hours

INTERRUTION DATA


75

149





yr-customeroninterrupti 222222.0

100150200

100

N

NSAIFI

C

=

++==

∑∑

( )( )

yr-customerhours 333333.1

100150200

6100

N

dNSAIDI

C

=

++==

∑∑

( )( )

oninterrupti-custumerhours 6

100

6100

N

dNCAIDI

C

C

=

==∑∑


150





000152.0

8760

333333.1

8760

SAIDI

8760

NdNASUI

C

=

===∑∑

999848.0

000152.01ASUI1ASAI

=

−=−=

( )( )

yrcustomerKWh 333333.5

100150200

6400

N

dL

N

ENSASCI

a

−=

++===

∑∑

∑

Note: ENS - Energy Not Supplied


76

151





Outage & Interruption Reporting


152





1 01/08/04 3 1.5 Line Fault at C

2* 02/06/04 All 4 Transmission

3 02/14/04 5, 6 0.5 Line Fault at D

4* 03/15/04 4, 5, 6 3 Pre-arranged

5 04/01/04 6 1.5 Overload

6* 05/20/04 3, 4 3.5 Pre-arranged

7 05/30/04 1, 2, 3 0.5 Line Tripped

8 06/12/04 1 2 Line fault

9 07/04/04 5 1 Line Overload

10* 07/25/04 All 5 Transmission

11 07/30/04 5 1 Line Fault

12* 08/15/04 4 2 Pre-arranged

13 09/08/04 2 1 Line Fault

14* 09/30/04 1, 2, 3 2.5 Pre-arranged

15 10/25/04 3 1.5 Line Tripped

16 11/10/04 2, 3 1.5 Line Fault at A

17* 11/27/04 3 2 Pre-arranged

18* 12/14/04 3, 4, 5 3.5 Pre-arranged

19* 12/27/04 2, 3 3 Pre-arranged

20 12/28/04 1, 2, 3 0.075 Line Fault


*Not included in Distribution Reliability Performance Assessment

Historical Reliability Performance Assessment

hoursAffectedDate

77

153





Month 1 2 3 4 5 6 Total

January 900 800 600 850 500 300 3,950

February 905 796 600 855 497 303 3,956

March 904 801 604 854 496 308 3,967

April 908 806 606 859 501 310 3,990

May 912 804 608 862 509 315 4,010

June 914 810 611 864 507 318 4,024

July 917 815 614 866 512 324 4,048

August 915 815 620 872 519 325 4,066

September 924 821 622 876 521 328 4,092

October 928 824 626 881 526 331 4,116

November 930 826 630 886 530 334 4,136

December 934 829 635 894 538 332 4,162

Annual Average 916 812 615 868 513 319 4,043


Customer Count


154





Interruption

Number

Load

Points

Affected

Number of

Customers

Affected

Duration

(Hrs.)

Customer

Hours

Curtailed

Date

1 3 600 1.5 900 01/08/04

5 497 0.5 248.5

6 303 0.5 151.5

5 6 310 1.5 465 04/01/04

1 912 0.5 456

2 804 0.5 402

3 608 0.5 304

8 1 914 2 1,828 06/12/04

9 5 512 1 512 07/04/04

11 5 512 1 512 07/30/04

13 2 821 1 821 09/08/04

15 3 626 1.5 939 10/25/04

2 826 1.5 1,239

3 630 1.5 945

11/10/0416

3

7 05/30/04

02/14/04



78

155






Calculate the Annual Reliability Performance of the Distribution System (according to Phil. Distribution Code)

∑∑

=N

NSAIFI

C

∑∑

=N

dNSAIDI

C

∑∑

=N

NMAIFI

C


156





Required Data:

1. Component Reliability Data

λi - failure rate of component i

ri - mean repair time of component i

2. System Load Data

Ni - number of customers at point i

Li - the demand at point i

Distribution

SystemSource

A

B Loads

C

λB, rB, UBSource

A

B Loads

C

λA, rA, UA

λC, rC, UC


Predictive Reliability Performance Assessment

79

157





1 2 S

1

2

P

For series combinations:

n

λλλλs = Σ λλλλii=1

n

Σ λλλλirii=1

rs = _________

λλλλs

λλλλp = λλλλ1λλλλ2 (r1 + r2)

r1 r2rp = __________

r1 + r2

For parallel combinations:

Load Point Reliability Equivalents


158





L1 L2 L3

A B CSource

S 1 2 3

Feederλλλλ

(f/year)

r

(hours)

A 0.2 6

B 0.1 5

C 0.15 8

COMPONENT DATA

Load PointNumber of

Customers

Average Load

Demand (KW)

L1 200 1000

L2 150 700

L3 100 400

SYSTEM LOAD DATA


80

159





Load Point Reliability Equivalents

� For L1

� For L2

� For L3

yrf 0.2

A1

=

= λλ

hrs 6

rr A1

=

=( )( )

yrhrs 1.2

62.0

rU 111

=

=

= λ

yrf 0.3

0.10.2

BA2

=

+=

+= λλλ

( )( ) ( )( )

hrs 676666.5

1.02.0

51.062.0

rrr

BA

BBAA2

=

+

+=

+

+=

λλ

λλ

( )( )yrhrs 1.7

5.6666673.0

rU 222

=

=

= λ

yrf 0.45

0.150.10.2

3

=

++=

++= CBA λλλλ

( )( ) ( )( ) ( )( )

hrs 4444446

1501020

8150510620

3

.

...

...

rrrr

BBA

CCBBAA

=

++

++=

++

++=

λλλ

λλλ

( )( )yrhrs 9.2

6.44444445.0

rU 333

=

=

= λ

160





�Reliability Indices

( )( ) ( )( ) ( )( )

yrcustomeroninterrupti 288889.0

100150200

10045.01503.02002.0

N

NSAIFI

i

ii

−=

++

++==

∑∑λ

( )( ) ( )( ) ( )( )


100150200

1009.21507.12002.1

N

NUSAIDI

i

ii

=

++

++==

∑∑

oninterrupti-customerhours 038462.6

288889.0

744444.1

SAIFI

SAIDI

N

NUCAIDI

ii

ii

=

===∑∑

λ

81

161





000199.0

8760

744444.1

8760

SAIDI

8760

NNUASUI

iii

=

===∑∑

999801.0

000199.01ASUI1ASAI

=

−=−=

( ) ( )( ) ( )( ) ( )( )

yr-customerKWh 888889.7

100150200

9.24007.17002.11000

N

UL

N

ENSASCI

i

iia

i

=

++

++===

∑∑

∑

162





A

B

C

D

1 2 3 4Source

a b c d

Typical radial distribution system


82

163





Length (km) λλλλ (f/yr) r (hrs)

1 2 0.2 4

2 1 0.1 4

3 3 0.3 4

4 2 0.2 4

a 1 0.2 2

b 3 0.6 2

c 2 0.4 2

d 1 0.2 2L

ate

ral

Component

SYSTEM RELIABILITY DATA

Ma

in

Component No. of Customers Ave. Load Connected (KW)

A 1000 5000

B 800 4000

C 700 3000

D 500 2000

SYSTEM LOAD DATA

164





λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

1 0.2 4 0.8 0.2 4 0.8 0.2 4 0.8 0.2 4 0.8

2 0.1 4 0.4 0.1 4 0.4 0.1 4 0.4 0.1 4 0.4

3 0.3 4 1.2 0.3 4 1.2 0.3 4 1.2 0.3 4 1.2

4 0.2 4 0.8 0.2 4 0.8 0.2 4 0.8 0.2 4 0.8

a 0.2 2 0.4 0.2 2 0.4 0.2 2 0.4 0.2 2 0.4

b 0.6 2 1.2 0.6 2 1.2 0.6 2 1.2 0.6 2 1.2

c 0.4 2 0.8 0.4 2 0.8 0.4 2 0.8 0.4 2 0.8

d 0.2 2 0.4 0.2 2 0.4 0.2 2 0.4 0.2 2 0.4

2.2 2.73 6.0 2.2 2.73 6.0 2.2 2.73 6.0 2.2 2.73 6.0

RELIABILITY INDICES FOR THE SYSTEM

Total

Load pt. A Load pt. B Load pt. C Load pt. D

Main

Late

ral

Component

failure

∑∑∑∑ === λλλ Ur ;UU ; :where totaltotaltotal

83

165





( )( ) ( )( ) ( )( ) ( )( )

yrcustomerint 2.2

5007008001000

5002.27002.28002.210002.2

N

NSAIFI

i

ii

−=

+++

+++==

∑∑λ

( )( ) ( )( ) ( )( ) ( )( )


5007008001000

5000.67000.68000.610000.6

N

NUSAIDI

i

ii

=

+++

+++==

∑∑


2.2

0.6

SAIFI

SAIDI

N

NUCAIDI

ii

ii

=

===∑∑

λ

166





000685.0

8760

0.6

8760

SAIDI

8760

NNUASUI

iii

=

===∑∑

999315.0

000685.01ASUI1ASAI

=

−=−=

( )( ) ( )( ) ( )( ) ( )( )

yr-customerKWh 0.28

5007008001000

0.620000.630000.640000.65000

N

ULASCI

i

iai

=

+++

+++=

=∑∑

84

167





� Effect of lateral protection

A

B

C

D

1 2 3 4Source

a b c d

Typical radial distribution system with lateral protections


168





λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

1 0.2 4 0.8 0.2 4 0.8 0.2 4 0.8 0.2 4 0.8

2 0.1 4 0.4 0.1 4 0.4 0.1 4 0.4 0.1 4 0.4

3 0.3 4 1.2 0.3 4 1.2 0.3 4 1.2 0.3 4 1.2

4 0.2 4 0.8 0.2 4 0.8 0.2 4 0.8 0.2 4 0.8

a 0.2 2 0.4

b 0.6 2 1.2

c 0.4 2 0.8

d 0.2 2 0.4

1.0 3.6 3.6 1.4 3.14 4.4 1.2 3.33 4.0 1.0 3.6 3.6

RELIABILITY INDICES WITH LATERAL PROTECTION

Total


Ma

inL

ate

ral

Component

failure


85

169





( )( ) ( )( ) ( )( ) ( )( )

yrcustomerint 153333.1

5007008001000

5000.17002.18004.110000.1

N

NSAIFI

i

ii

−=

+++

+++==

∑∑λ

( )( ) ( )( ) ( )( ) ( )( )


5007008001000

5006.37000.48004.410006.3

N

NUSAIDI

i

ii

=

+++

+++==

∑∑


153333.1

906667.3

SAIFI

SAIDI

N

NUCAIDI

ii

ii

=

===∑∑

λ

170





000446.0

8760

906667.3

8760

SAIDI

8760

NNUASUI

iii

=

===∑∑

999554.0

000446.01ASUI1ASAI

=

−=−=

( )( ) ( )( ) ( )( ) ( )( )


5007008001000

6.320000.430004.440006.35000

N

ULASCI

i

iai

=

+++

+++=

=∑∑

86

171





� Effect of disconnects

A

B

C

D

1 2 3 4Source

a b c d

Typical radial distribution system reinforce with

lateral protections and disconnects


172





λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

1 0.2 4 0.8 0.2 4 0.8 0.2 4 0.8 0.2 4 0.8

2 0.1 0.5 0.05 0.1 4 0.4 0.1 4 0.4 0.1 4 0.4

3 0.3 0.5 0.15 0.3 0.5 0.15 0.3 4 1.2 0.3 4 1.2

4 0.2 0.5 0.1 0.2 0.5 0.1 0.2 0.5 0.1 0.2 4 0.8

a 0.2 2 0.4

b 0.6 2 1.2

c 0.4 2 0.8

d 0.2 2 0.4

1.0 1.5 1.5 1.4 1.89 2.65 1.2 2.75 3.3 1.0 3.6 3.6

RELIABILITY INDICES WITH LATERAL PROTECTION AND DISCONNECTS

Total


Ma

inL

ate

ral

Component

failure


87

173





( )( ) ( )( ) ( )( ) ( )( )

yrcustomerint 153333.1

5007008001000

5000.17002.18004.110000.1

N

NSAIFI

i

ii

−=

+++

+++==

∑∑λ

( )( ) ( )( ) ( )( ) ( )( )


5007008001000

5006.37003.380065.210005.1

N

NUSAIDI

i

ii

=

+++

+++==

∑∑


153333.1

576667.2

SAIFI

SAIDI

N

NUCAIDI

ii

ii

=

===∑∑

λ

174





000294.0

8760

576667.2

8760

SAIDI

8760

NNUASUI

iii

=

===∑∑

999706.0

000294.01ASUI1ASAI

=

−=−=

( )( ) ( )( ) ( )( ) ( )( )


5007008001000

6.320003.3300065.240005.15000

N

ULASCI

i

iai

=

+++

+++=

=∑∑

88

175





� Effect of protection failures

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

1 0.2 4 0.8 0.2 4 0.8 0.2 4 0.8 0.2 4 0.8

2 0.1 0.5 0.05 0.1 4 0.4 0.1 4 0.4 0.1 4 0.4

3 0.3 0.5 0.15 0.3 0.5 0.15 0.3 4 1.2 0.3 4 1.2

4 0.2 0.5 0.1 0.2 0.5 0.1 0.2 0.5 0.1 0.2 4 0.8

a 0.2 2 0.4 0.02 0.5 0.01 0.02 0.5 0.01 0.02 0.5 0.01

b 0.06 0.5 0.03 0.6 2 1.2 0.06 0.5 0.03 0.06 0.5 0.03

c 0.04 0.5 0.02 0.04 0.5 0.02 0.4 2 0.8 0.04 0.5 0.02

d 0.02 0.5 0.01 0.02 0.5 0.01 0.02 0.5 0.01 0.2 2 0.4

1.12 1.39 1.56 1.48 1.82 2.69 1.3 2.58 3.35 1.12 3.27 3.66

RELIABILITY INDICES IF THE FUSES OPERATE WITH PROBABILITY OF 0.9

Total


Ma

inL

ate

ral

Component

failure


176





� Effect of load transfer to alternative supply

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

1 0.2 4 0.8 0.2 0.5 0.1 0.2 0.5 0.1 0.2 0.5 0.1

2 0.1 0.5 0.05 0.1 4 0.4 0.1 0.5 0.05 0.1 0.5 0.05

3 0.3 0.5 0.15 0.3 0.5 0.15 0.3 4 1.2 0.3 0.5 0.15

4 0.2 0.5 0.1 0.2 0.5 0.1 0.2 0.5 0.1 0.2 4 0.8

a 0.2 2 0.4

b 0.6 2 1.2

c 0.4 2 0.8

d 0.2 2 0.4

1.0 1.5 1.5 1.4 1.39 1.95 1.2 1.88 2.25 1.0 1.5 1.5

RELIABILITY INDICES WITH UNRESTRICTED LOAD TRANSFERS

Total


Ma

inL

ate

ral

Component

failure


89

177





λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

λλλλ

(f/yr)

r

(hrs)

U

(hrs/

yr)

1 0.2 4 0.8 0.2 1.9 0.38 0.2 1.9 0.38 0.2 1.9 0.38

2 0.1 0.5 0.05 0.1 4 0.4 0.1 1.9 0.19 0.1 1.9 0.19

3 0.3 0.5 0.15 0.3 0.5 0.15 0.3 4 1.2 0.3 1.9 0.57

4 0.2 0.5 0.1 0.2 0.5 0.1 0.2 0.5 0.1 0.2 4 0.8

a 0.2 2 0.4

b 0.6 2 1.2

c 0.4 2 0.8

d 0.2 2 0.4

1.0 1.5 1.5 1.4 1.59 2.23 1.2 2.23 2.67 1.0 2.3 2.3

RELIABILITY INDICES WITH RESTRICTED LOAD TRANSFERS

Total

Load pt. A Load pt. B Load pt. C Load pt. DS

ec

tio

nD

istr

ibu

tor

Component

failure


� Effect of load transfer to alternative supply

178





Case 1 Case 2 Case 3 Case 4 Case 5 Case 6

λ (f/yr) 2.2 1.0 1.0 1.12 1.0 1.0

r (hrs) 2.73 3.6 1.5 1.39 1.5 1.5

U (hrs/yr) 6.0 3.6 1.5 1.56 1.5 1.5

λ (f/yr) 2.2 1.4 1.4 1.48 1.4 1.4

r (hrs) 2.73 3.14 1.89 1.82 1.39 1.59

U (hrs/yr) 6.0 4.4 2.65 2.69 1.95 2.23

λ (f/yr) 2.2 1.2 1.2 1.3 1.2 1.2

r (hrs) 2.73 3.33 2.75 2.58 1.88 2.23

U (hrs/yr) 6.0 4 3.3 3.35 2.25 2.67

λ (f/yr) 2.2 1.0 1.0 1.12 1.0 1.0

r (hrs) 2.73 3.6 3.6 3.27 1.5 2.34

U (hrs/yr) 6.0 3.6 3.6 3.66 1.5 2.34

SUMMARY OF INDICES

Load Point A

Load Point B

Load Point C

Load Point D


90

179





Case 1 Case 2 Case 3 Case 4 Case 5 Case 6

SAIFI 2.2 1.15 1.15 1.26 1.15 1.15

SAIDI 6.0 3.91 2.58 2.63 1.80 2.11

CAIDI 2.73 3.39 2.23 2.09 1.56 1.83

ASAI 0.999315 0.999554 0.999706 0.999700 0.999795 0.999759

ASUI 0.000685 0.000446 0.000294 0.003000 0.000205 0.000241

ENS 84.0 54.8 35.2 35.9 25.1 29.1

ASCI 28.0 18.3 11.7 12.0 8.4 9.7

Case 3. As in Case 2, but with disconnects on the main feeders.

Case 4. As in Case 3, probability of successful lateral distributor fault clearing of 0.9.

Case 5. As in Case 3, but with an alternative supply.

Case 6. As in Case 5, probability of conditional load transfer of 0.6.

Sytem Indices

SUMMARY OF INDICES (cont.)

Case 1. Base case.

Case 2. As in Case 1, but with perfect fusing in the lateral distributors.


180





Economics of Power System Reliability

Supply Cost

• Investment Cost

• Operation and Maintenance Cost

• Fuel Cost

Annual Supply Cost (ASC) =

Annual kWh Generation

IC + O&M + FC

91

181





Supply Cost

1.111.310.730.08

1.141.300.310.04

1.091.3820.21

1.061.5040.45

1.031.6170.94

1.011.73131.88

0.942.00386.25

0.902.117012.26

Supply Cost(Php/kWh)

Duration(Hours)

Frequency(per year)

LOLP(days/yr)

Luzon Grid Supply Cost*

Source: del Mundo (1991)

182





Supply Cost

Luzon Grid Supply Cost


92

183





� To Electric Utility• Loss of revenues• Additional work• Loss of confidence

� To Customers• Dissatisfaction• Interruption of productivity• Additional investment for alternative power supply

� To National Economy• Loss value added/income• Loss of investors• Unemployment

Outage Cost

Impact of Power Interruptions

184





Impact to National Economy:

�NEDA Study (1974)� P 342,380 per day – losses due to brownout in Cebu-Mandaue

area

�Business Survey (1980)� P1.4 Billion – losses due to brownouts in 1980

�CRC Memo No. 27 (1988)� P 3.4 Billion – loss of the manufacturing sector in 1987 due to

power outages

�Viray & del Mundo Study (1988)� P 25 – losses in Value Added per kWh curtailment

�Sinay Report (1989)� 45% – loss in Value Added in the manufacturing sector in

Cebu due to power outages

Outage Cost

93

185





Impact to Customers:

A. Short-Run Direct Cost• Opportunity losses during outages• Opportunity losses during restart period• Raw materials spoilage• Finish products spoilage• Idle workers• Overtime• Equipment damage• Special operation and maintenance during restart period

B. Long-Run Adaptive Response Cost• Standby generators• Power plant• Alternative fuels• Transfer location• Inventory

Outage Cost

186





(0.0086 + 0.0023D)F + 0.1730 Pesos/kWh


Outage Cost to Industrial Sector in Luzon

Where, F – Frequency of Interruptions

D – Average Duration of Interruptions

Outage Cost

Losses of MERALCO Industrial Customers in 1989

Energy Sales: 3.781 billion kWhOutage Cost: Php 0.3544/kWhTotal Losses: Php 1.34 billion

94

187





Outage Cost

0.181.310.730.08

0.181.300.310.04

0.201.3820.21

0.221.5040.45

0.261.6170.94

0.341.73131.88

0.682.00386.25

1.122.117012.26

Outage Cost(Php/kWh)

Duration(Hours)

Frequency(per year)

LOLP(days/yr)

Luzon Grid Outage Cost*


188





Outage Cost

Luzon Grid Outage Cost


95

189





Total Cost

ATC = ASC + AOC

1.291.311.110.08

1.321.301.140.04

1.291.381.090.21

1.281.501.060.45

1.291.611.030.94

1.351.731.011.88

1.622.000.946.25

2.022.110.9012.26

Total Cost(Php/kWh)

Outage Cost(Php/kWh)

Supply Cost(Php/kWh)

LOLP(days/yr)

Luzon Grid Total Cost


190





Optimal Reliability Level


Luzon Grid Total Cost

96

191





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