Pse4ne2 - Power System Analysis 101

Competency Training and Certification Program in Electric Power Distribution System Engineering

Training Course in

Power System Engineering for Non-Engineers

Power System Analysis 101

U. P. NATIONAL ENGINEERING CENTER NATIONAL ELECTRIFICATION ADMINISTRATION

Power System Analysis 101

2

Power System Analysis Performance Standards Power Quality Efficiency Safety Reliability

Power System Analysis Load Flow Analysis System Loss Analysis Short Circuit Analysis Reliability Analysis

U. P. National Engineering Center National Electrification Administration

Power System Engineering for Non-Engineers

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Power System Analysis 101

3

LOAD FLOW ANALYSIS

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Power System Engineering for Non-Engineers

Power System Analysis 101

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Load Flow Analysis 1. What is Load Flow? 2. Uses of Load Flow Studies 3. Load Flow Control

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Power System Analysis 101

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What is Load Flow?

Bus2 Bus1 I12 , Loss12 = ?

Utility Grid

V1 = 67 kV P1 , Q1 = ?

Bus3 V3 = ? P3 , Q3 = ?

I23 , Loss23 = ?

I24 , Loss24 = ? V4 = ? P4 , Q4 = ? Bus4 V2 = ? Lumped Load A P2 , Q2 = ? 2 MVA 85%PF Lumped Load B 1 MVA 85%PF

What are the Voltages, Currents, Power and Losses of the Distribution System? U. P. National Engineering Center National Electrification Administration

Power System Engineering for Non-Engineers

Power System Analysis 101

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What is Load Flow? Load Flow of an Existing System 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 U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

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What is Load Flow? Load Flow of a Contemplated System 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 U. P. National Engineering Center National Electrification Administration

Power System Engineering for Non-Engineers

Power System Analysis 101

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What is Load Flow? 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. U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

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What is Load Flow? How would the engineers do that? • Identify physical components • Know the characteristic of components • Mathematically represent the behavior of components • Calculate electrical parameters

Power System Engineering for Non-Engineers

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Power System Analysis 101

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What is Load Flow?

G

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Power System Analysis 101

11

What is Load Flow? Substation Transformer

Utility Grid or Generator

Transmission Line

G Bus

Distribution Line

Distribution Transformer

Load Flow mathematically determines the Voltages, Currents, Power and Losses Load U. P. National Engineering Center National Electrification Administration

Power System Engineering for Non-Engineers

Power System Analysis 101

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Uses of Load Flow Studies 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)

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Power System Analysis 101

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Uses of Load Flow Studies Other Information From a Load Flow Study Overvoltage and Undervoltage Buses Critical and Overloaded Transformers and Lines Total System Losses

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Uses of Load Flow Studies Sensitivity Analysis 1) Take any line, transformer or generator out of service. 2) Add, reduce or remove load to any or all buses. 3) Add, remove or shift generation to any bus. 4) Add new transmission or distribution lines. 5) Increase conductor size on T&D lines. 6) Change bus voltages. 7) Change transformer taps. 8) Increase or decrease transformer size. 9) Add or remove rotating or static var supply to buses. U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

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Uses of Load Flow Studies 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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Power System Analysis 101

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Uses of Load Flow Studies 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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Power System Analysis 101

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Uses of Load Flow Studies 2) ANALYSIS FOR CORRECTING PQ PROBLEMS • 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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Uses of Load Flow Studies 2) ANALYSIS FOR CORRECTING PQ PROBLEMS •Capacitor compensation • Compensate for Peak Loading • Check overvoltages during Off-Peak • Optimize Capacitor Plan • System configuration improvement

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Power System Analysis 101

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Uses of Load Flow Studies 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

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Uses of Load Flow Studies 4) CONTINGENCY ANALYSIS Reliability analysis of the Transmission (Grid) and Subtransmission System 5) SYSTEM LOSS ANALYSIS Segregation of System Losses

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Power System Analysis 101

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Load Flow Control 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 U. P. National Engineering Center National Electrification Administration

Power System Engineering for Non-Engineers

Power System Analysis 101

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SYSTEM LOSS ANALYSIS

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Power System Analysis 101

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System Loss Analysis 1. Components of Distribution System Losses 2. Segregation of Distribution System Losses 3. System Loss Reduction and Control

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Power System Analysis 101

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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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Power System Analysis 101

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Total Distribution System Losses Energy Delivered to the Distribution System

-

Energy Delivered to Users

=

Total Distribution System Losses

Administrative + Loss

Technical Loss

+ Non-Technical Loss

Bundled Technical & Non-Technical Losses U. P. National Engineering Center National Electrification Administration

Power System Engineering for Non-Engineers

Power System Analysis 101

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Components of Distribution System Losses Administrative Losses 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.

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Power System Analysis 101

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Components of Distribution System Losses Technical Losses 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. U. P. National Engineering Center National Electrification Administration

Power System Engineering for Non-Engineers

Power System Analysis 101

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Components of Distribution System Losses Non-Technical Losses 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. U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

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Total Distribution System Losses 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] Power System Engineering for Non-Engineers

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Power System Analysis 101

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Unbundling the Technical and Non-Technical Loss Technical Losses

+

Non-Technical Losses

Technical Losses Residual after subtracting Administrative & Technical Losses from the Total Distribution System Losses

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

=

Non-Technical Losses

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Power System Analysis 101

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Unbundling the Technical and Non-Technical Loss Technical Loss = Σ[Hourly Load and No-Load (or Fixed) Losses in all

electrical equipment, devices and conductors] a)Sub-transmission Lines b)Substation Power Transformers c)Primary Distribution Lines d)Distribution Transformers e)Secondary Distribution Lines f) Service Drops

g) h) i) j)

Voltage Regulators Capacitors Reactors Other electrical equipment

Hourly Load Flow Simulations

Plus Calculated Metering Equipment Loss Power System Engineering for Non-Engineers

U. P. National Engineering Center National Electrification Administration

Power System Analysis 101

32

Unbundling the Technical and Non-Technical Loss Primary Distribution Lines (Main Feeder)

Subtransmission Lines

Substation Transformer

Three-Phase Unbalanced Load Flow Simulations a)Sub-transmission Lines b)Substation Power Transformers c)Primary Distribution Lines Distribution d)Distribution Transformers Transformer e)Secondary Distribution Lines f) Service Drops g)Voltage Regulators h)Capacitors i) Reactors j) Other electrical equipment U. P. National Engineering Center National Electrification Administration

Primary Distribution Lines (Laterals) Misc Loads

Secondary Distribution Lines Service Drop

Residential

Commercial

Industrial

Load Losses and No-Load (Fixed) Losses Power System Engineering for Non-Engineers

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Power System Analysis 101

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Unbundling the Technical and Non-Technical Loss Calculation of Metering Equipment 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 U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

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Unbundling the Technical and Non-Technical Loss 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. U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

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DSL Segregation Distribution System Loss Segregation Program Distribution System Data

Customer Energy Bill

(3-phase Load Flow)

Distribution Reliability Assessment Metering Equipment Inventory

U. P. National Engineering Center National Electrification Administration

Segregated Technical Loss (Billing Period)

Metering Equipment Loss Power System Engineering for Non-Engineers

Power System Analysis 101

36

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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Power System Analysis 101

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Distribution Network Models Ia

IA A

Impedance/ Admittance parameters of Distribution System Element

IB

Distribution B System C Element

IC

a Ib b Ic

VA VB VC

c Vc Vb Va

Ground (Reference Node)

Distribution Network Model must capture the unbalance characteristics of the System

Power System Engineering for Non-Engineers

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Power System Analysis 101

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Distribution Load Models 350 300

Customer Energy Bill NormalizedDemand(per unit)

1.2 1

Demand (W)

250 200 150 100

0.8

50

0.6

Area under the curve = Customer Energy Bill

0.4

0

0.2 0 Time (24 hours)

Normalized Customer Load Curve U. P. National Engineering Center National Electrification Administration

Customer Energy Bill Converted to Hourly Power Demand Power System Engineering for Non-Engineers

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Power System Analysis 101

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Data Requirements 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

ERC-DSL-01 ERC-DSL-02 ERC-DSL-03 ERC-DSL-04 ERC-DSL-05 ERC-DSL-06 ERC-DSL-07 ERC-DSL-08 ERC-DSL-09 ERC-DSL-10 ERC-DSL-11 ERC-DSL-12 ERC-DSL-13 ERC-DSL-14 ERC-DSL-15 ERC-DSL-16 ERC-DSL-17 ERC-DSL-18 ERC-DSL-19 ERC-DSL-20 ERC-DSL-21

Power System Engineering for Non-Engineers

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Power System Analysis 101

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Optimal Level of System Loss

Total Cost

Cost

System Loss Reduction Program Cost

Unrecovered Energy Cost

High

Optimal

U. P. National Engineering Center National Electrification Administration

Low

System Loss Power System Engineering for Non-Engineers

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Power System Analysis 101

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BENECO DSL Segregation SEGREGATED DISTRIBUTION SYSTEM LOSSES ANALYSIS

NON-TECHNICAL LOSS REDUCTION PROGRAM TECHNICAL, ECONOMIC & FINANCIAL ANALYSIS

TECHNICAL LOSS REDUCTION PROGRAM TECHNICAL, ECONOMIC & FINANCIAL ANALYSIS Power System Engineering for Non-Engineers

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Power System Analysis 101

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BENECO DSL Segregation Technical Loss, 52.76%

TEST YEAR SEGREGATED DISTRIBUTION SYSTEM LOSSES

NonTechnical Loss, 46.74%

Administrative Loss, 0.50%

Loss Administrative

Kwhr

%

167, 791

0.0594%

Technical

18,181,059

6.3153%

Non-Technical

15,487,726

5.5951%

TOTAL

33,836,577

11.9698%

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Power System Analysis 101

BENECO DSL Segregation

43

SEGREGATED SYSTEM LOSSES

13.2 KV System

Administrative Loss

0.3998%

Technical Loss

9.8906% 7.4183%

Non-Technical Loss TOTAL LOSSES

17.7088%

13.2KV SYSTEM 23KV SYSTEM SEGREGATED SYSTEM LOSSES

23 KV System

Administrative Loss

0.0393%

Technical Loss

6.1051%

Non-Technical Loss

5.4879%

TOTAL LOSSES

11.6324%

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Power System Analysis 101

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DSL RESULT PER FEEDER PER HOUR PER DAY IN A MONTH

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Power System Engineering for Non-Engineers

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BENECO DSL Segregation SEGREGATED TECHNICAL LOSS

% LOSS

% SHARE

Power Transformer Load Loss

0.0590%

0.9338%

Power Transformer No-Load Loss

0.2372%

3.7559%

Primary Line

1.3805%

21.8597%

Primary Service Drop

0.0000%

0.0000%

Dist. XF Load Loss

0.3438%

5.4445%

Dist. XF No-Load Loss

1.7397%

27.5469%

Secondary

2.1652%

34.2848%

Secondary Service Drop

0.0691%

1.0937%

Shunt Capacitor Loss

0.0029%

0.0456%

kWhR Meter Loss

0.3180%

5.0350%

Total Technical Loss

6.3153%

100.0000%

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Power System Analysis 101

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BENECO DSL Segregation TECHNICAL LOSS DISTRIBUTION TECHNICAL LOSS ALLOCATION kWhR Meter Loss 5% Pow er Xformer Load Loss 1% Shunt Capacitor Loss 0%

Pow er Xformer No-Load Loss 4% Primary Line 22%

Secondary Service Drop 1% Secondary 34%

Dist. XF Load Loss 5%

Dist. XF No-Load Loss 28%

Power System Engineering for Non-Engineers

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BENECO DSL Segregation TEST YEAR SEGREGATED DISTRIBUTION SYSTEM LOSSES PER SYSTEM VOLTAGE PERCENT (%) TECHNICAL LOSSES

KWHR TECHNICAL LOSSES

SEGREGATED SYSTEM LOSSES

13.2 KV System

23 KV System

Total

13.2 KV System

23 KV System

Total

Administrative Loss

62,768.60

105,022.54

167,791.14

0.3998%

0.0393%

0.0594%

Technical Loss

1,552,634.80

16,299,669.83

17,852,304.63

9.8906%

6.1051%

6.3153%

Non-Technical Loss

1,164,538.99

14,651,941.84

15,816,480.83

7.4183%

5.4879%

5.5951%

33,836,576.60

17.7088 %

11.6324 %

11.9698 %

TOTAL LOSSES

2,779,942.39

31,056,634.21

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Power System Analysis 101

49

BENECO DSL Segregation TEST YEAR SEGREGATED TECHNICAL LOSSES PER SYSTEM VOLTAGE KWHR TECHNICAL LOSSES

TECHNICAL LOSSES Power Xformer Load Loss

13.2 KV System 5,232

23 KV System 161,467

PERCENT (%) TECHNICAL LOSSES 13.2 KV System

Total

23 KV System

Total

166,700

0.0333%

0.0605%

0.0590%

Power Xformer No-Load Loss

105,295

565,221

670,517

0.6708%

0.2117%

0.2372%

Primary Line

451,032

3,451,427

3,902,460

2.8732%

1.2927%

1.3805%

0.0000%

0.0000%

0.0000%

Primary Service Drop Dist. XF Load Loss

-

6

6

32,239

939,729

971,968

0.2054%

0.3520%

0.3438%

Dist. XF No-Load Loss

591,212

4,326,553

4,917,765

3.7661%

1.6205%

1.7397%

Secondary

209,447

5,911,176

6,120,623

1.3342%

2.2141%

2.1652%

4,275

190,979

195,254

0.0272%

0.0715%

0.0691%

0.0025%

0.0029%

0.0029%

898,866

0.9779%

0.2792%

0.3180%

17,852,305

9.8906%

6.1051%

6.3153%

Secondary Service Drop Shunt Capacitor Loss kWhR Meter Loss Total Technical Loss

394 153,507 1,552,635

7,753 745,359 16,299,670

8,147

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BENECO DSL Segregation FORECASTED SEGREGATED DISTRIBUTION SYSTEM LOSSES

YEAR

2006

2007

2008

2009

2010

Energy Input (KWH)

Total System Losses (%)

Administrativ e Loss (%)

Technical Loss (%)

Non Technical Loss (%)

313,577,324

12.1222%

0.0621%

6.4611%

5.5951%

341,755,055

12.2757%

0.0583%

6.6187%

5.5951%

372,339,284

12.3994%

0.0535%

6.7477%

5.5951%

405,588,445

12.5074%

0.0491%

6.8604%

5.5951%

442,271,657

12.7071%

0.0493%

7.0604%

5.5951%

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Power System Analysis 101

51

PROPOSED DISTRIBUTION SYSTEM LOSS CAPS YEAR

Technical Loss Cap

Declining NonTechnical Loss Caps

Administrative Loss Cap (Annual KWH)

2006

5.9833% to 6.9388%

5.5951%

194,741

2007

6.1281% to 7.1094%

4.7486%

199,147

2008

6.2431% to 7.2523%

3.8585%

199,147

2009

6.3431% to 7.3778%

3.1278%

199,147

2010

6.5249% to 7.5959%

2.7644%

218,218

FORECASTED DISTRIBUTION SYSTEM LOSS FORECASTED SYSTEM LOSS RANGE

YEAR 2006

11.6480%

-

12.6047%

2007

10.9425%

-

11.9251%

2008

10.1628%

-

11.1733%

2009

9.5279%

-

10.5639%

2010

9.3467%

-

10.4191% Power System Engineering for Non-Engineers

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Power System Analysis 101

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BENECO SEGREGATED DISTRIBUTION SYSTEM LOSS (base year 2004) Distribution System Loss Total System Loss

Administrative Loss

Energy (KWHR)

Peso Equivalent (Php) (as of February 2007 costing**)

Percentage (%)

33,836,577

11.970%

P 239,339,641

167,791

0.059%

P 1,186,854

Technical Loss

17,852,305

6.315%

P 126,276,492

Non-Technical Loss

15,816,481

5.595%

P 111,876,296

BENECO SEGREGATED TECHNICAL LOSS (base year 2004) Technical Losses

Power Xformer Load Loss Power Xformer No-Load Loss Primary Line Primary Service Drop

Energy (KWHR)

Percentage (%)

Peso Equivalent (Php) (as of February 2007 costing**)

166,700

0.0590%

670,517

0.2372%

P 1,179,134 P 4,742,833

3,902,460

1.3805%

P 27,603,658

6

0.0000%

P 42

971,968

0.3438%

P 6,875,117

Dist. XF No-Load Loss

4,917,765

1.7397%

P 34,785,321

Secondary

6,120,623

2.1652%

P 43,293,617

195,254

0.0691%

P 1,381,108

8,147

0.0029%

P 57,626

898,866

0.3180%

P 6,358,036

6.3153%

P 126,276,492

Dist. XF Load Loss

Secondary Service Drop Shunt Capacitor Loss kWhR Meter Loss

U. P. National Engineering 17,852,305 Center National Electrification Administration

Total Technical Loss

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Power System Analysis 101

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SEGREGATED SYSTEM LOSS PER METERING CONNECTION POINT ENERGY LOSSES (KWHR) Metering Connection

Metering Connection Pt. Loss

Lamut

4,898,458

Irisan NSC Old 20MVA NSC New 20MVA NPC-Beckel

Admin Loss 38,384

5,182,063

6,636

7,770,156

22,323

9,854,817

37,680

2,682,647

Atok

1,595,739

Mankayan

932,559

Asin Mini-Hyrdo Bakun Mini-hydro Ampuhaw Minihydro Ambuclao NPC-Itogon LUELCO

Technical Loss

50,108 11,625

97,772

-

25,055

-

63,242

-

251,644

1,036

371,989

-

110,435

-

LOSSES IN PERCENTAGE (%)

Non-Technical Loss

Metering Connection Pt. Loss

Admin Loss

Technical Loss

NonTechnical Loss

3,326,440

1,533,634

10.0966%

0.0791%

6.8564%

3.1611%

3,081,395

2,094,032

11.8636%

0.0152%

7.0544%

4.7940%

3,643,277

4,104,556

11.8636%

0.0341%

5.5626%

6.2669%

4,973,278

4,843,859

11.8636%

0.0454%

5.9870%

5.8312%

959,893

1,722,755

11.8636%

0%

4.2450%

7.6186%

890,558

655,073

19.5406%

0.6136%

10.9053%

8.0217%

547,017

373,918

14.8130%

0.1846%

8.6889%

5.9394%

38,621

59,151

16.4621%

0%

6.5027%

9.9594%

17,677

7,378

12.1417%

0%

8.5662%

3.5755%

24,629

38,613

15.0311%

0%

5.8537%

9.1774%

115,060

135,549

20.3546%

0.0838%

9.3068%

10.9641%

190,389

181,600

18.8304%

0%

9.6377%

9.1927%

66,364

26.5489%

0%

10.5949%

15.9540%

44,072

Power System Engineering for Non-Engineers

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Power System Analysis 101

54

NON-TECHNICAL LOSS PER METERING CONNECTION POINT Metering Connection

Non-Technical Loss (kWhr)

Cost of Unrecovered NTL (Pesos)

NTL % (System)

NTL % (Feeder)

Lamut

1,533,634.21

P 11,289,465

0.5425%

3.1611%

Irisan

2,094,031.95

P 15,414,693

0.7408%

4.7940%

NSC Old 20MVA

4,104,556.00

P 30,214,663

1.4520%

6.2669%

NSC New 20MVA

4,843,859.12

P 35,656,858

1.7135%

5.8312%

NPC-Beckel

1,722,754.60

P 12,681,627

0.6094%

7.6186%

Atok

655,072.51

P 4,822,153

0.2317%

8.0217%

Mankayan

373,917.67

P 2,752,501

0.1323%

5.9394%

59,150.85

P 435,424

0.0209%

9.9594%

7,378.26

P 54,313

0.0026%

3.5755%

38,613.44

P 284,243

0.0137%

9.1774%

Ambuclao

135,548.81

P 997,809

0.0480%

10.9641%

NPC-Itogon

181,599.91

P 1,336,802

0.0642%

9.1927%

66,363.50

P 488,518

0.0235%

15.9540%

15,816,480.83

P 116,429,070

5.5951%

Asin Mini-Hyrdo Bakun Mini-hydro Ampuhaw Minihydro

LUELCO TOTAL

ACTIVITIES CONSIDERED AND COSTED FOR NON-TECHNICAL LOSS REDUCTION OPTIMIZATION COMPUTATION Communal Distribution Transformer Block Metering

►

Streetlight kwhr Metering

►

Streetlight Photo Switching

►

Right-of-Way Clearing

►

Inspection, Calibration and Apprehension Kwhr Meter Replacement (apprehended and defective) Phased-Out Kwhr Meter Replacement (Old kwhr meters)

►

►

Sole-Use Distribution Transformer Monitoring

►

Loose Connection Correction Software and Hardware Requirements Procurement

► ► ►

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Power System Analysis 101

55

PRIORITY RANKING IN TERMS OF SELECTED NTL ACTIVITES FOR IMPLEMENTATION COMMUNAL TRANSFORMER BLOCK METERING Average Rank

INSPECTION, APPREHENSION, CALIBRATION

Metering Connection

Metering Connection KWHR NTL / NO. OF DT's

RANK

KWHR NTL / NO. OF METERS

NSC Old 20MVA

38,722

1

RANK

NSC Old 20MVA

430

2.5

NPC-Beckel

10,194

1

3

NPC-Beckel

201

2.5

NSC New 20MVA

2

11,009

2

NSC New 20MVA

157

5.5

3

Lamut

6,786

4

Lamut

88

7

5.5

LUELCO

2,765

7

LUELCO

155

4

5.5

NPC-Itogon

2,977

6

NPC-Itogon

107

5

6.5

Irisan

6,326

5

Irisan

86

8

7

Ampuhaw Mini-hydro

2,413

8

Ampuhaw Mini-hydro

105

6

9

Asin Mini-Hyrdo

2,366

9

Asin Mini-Hyrdo

83

9

Atok

2,120

10

Atok

77

10 11

1

10 11.5

Ambuclao

1,442

12

Ambuclao

69

11.5

Mankayan

1,723

11

Mankayan

42

12

434

13

Bakun Mini-hydro

21

13

13

Bakun Mini-hydro

FEEDER COVERAGE Single Feeder Metering Points

Multi-Feeder Metering Connection Points

Lamut

Asin Mini-Hyrdo

NSC New 20MVA

Feeder 1

Feeder 7

Feeder 2

Feeder 8

Irisan

Feeder 9

Feeder 3

Feeder 10

Feeder 4

FeederU. 5

Circuit 1

Ampuhaw Mini-hydro

Circuit 2

Ambuclao

Circuit 3

NPC-Itogon LUELCO

Mankayan

NPC-Beckel

NSC Old 20MVA

Bakun Mini-hydro

Atok

Circuit 4

Totalizer 1 Engineering

Power System Engineering for Non-Engineers

P. National Center Circuit 5 TotalizerAdministration 2 Electrification

FeederNational 6

Power System Analysis 101

56

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

% Unrecovered NTL per Feeder

Level of Optimum %NTL per Feeder

% Recovered NTL per Feeder

% Recovered NTL as per Entire System

Optimized Project Cost for NTL Reduction

Lamut

3.161%

2.024%

1.137%

0.3474%

6,643,459.93

Irisan

4.794%

3.053%

1.741%

0.4718%

9,021,486.28

NSC Old 20MVA

6.267%

2.154%

4.113%

0.4991%

9,544,620.05

NSC New 20MVA

5.831%

3.029%

2.802%

0.8901%

17,019,823.88

NPC-Beckel

7.619%

3.237%

4.382%

0.2589%

4,950,875.25

Atok

8.022%

5.403%

2.618%

0.1561%

2,984,882.11

Mankayan

5.939%

4.532%

1.408%

0.1009%

1,929,917.47

Asin Mini-Hyrdo

9.959%

5.623%

4.337%

0.0118%

225,901.85

Bakun Mini-hydro Ampuhaw Minihydro

3.575%

3.056%

0.520%

0.0022%

42,656.16

9.177%

4.752%

4.426%

0.0071%

135,238.81

10.964%

7.769%

3.195%

0.0340%

649,735.01

9.193%

5.534%

3.659%

0.0387%

739,469.91

LUELCO

15.954%

8.611%

7.343%

0.0127%

242,309.48

TOTAL =

5.5951%

2.7644%

Ambuclao NPC-Itogon

2.8308%

P 54,130,376.19

NOTE: Project Cost for implementation per Metering Connection at targeted reduced Non-technical Loss percentage SHALL NOT EXCEED the computed Optimized Project Cost.

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Power System Analysis 101

57

BENECO NON-TECHNICAL LOSS REDUCTION ECONOMIC ANALYSIS Cost of Unrecovered VS NTL Reduction Program

M illion s

120 110

Cost of Unrecovered NTL

100

Cost NTL Reduction Program

90

Optimum level of loss reduction

C ost (Php )

80 70 60 50 40 30 20 10

0.5595%

0.7693%

0.9791%

1.1890%

1.3988%

1.6086%

1.8184%

2.0282%

2.2381%

2.4479%

2.6577%

2.8675%

3.0773%

3.2871%

3.4970%

3.7068%

3.9166%

4.1264%

4.3362%

4.5461%

4.7559%

4.9657%

5.1755%

5.3853%

5.5951%

0

Non-Technical Loss (%)

OPTIMUM LEVEL OF NON-TECHNICAL LOSS REDUCTION = 2.7644%

EQUIVALENT PROJECT COST = P53,447,802.55 U. P. National Engineering Center National Electrification Administration

Power System Engineering for Non-Engineers

Power System Analysis 101

58

System Loss Reduction and Control 

Reduction and Control of Technical Losses



Reduction and Control of Non-Technical Losses

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Power System Analysis 101

59

Reduction and Control of Technical Losses 

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

Power System Engineering for Non-Engineers

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Power System Analysis 101

60

Reduction and Control of Technical Losses 

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 Plan • Technical Analysis • Economic Analysis U. P. National Engineering Center National Electrification Administration

• Financial Analysis Power System Engineering for Non-Engineers

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Power System Analysis 101

61

Reduction and Control of Non-Technical Losses 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.) U. P. National Engineering Center National Electrification Administration

Power System Engineering for Non-Engineers

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62

Reduction and Control of Non-Technical Losses 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 classified 1. Match all service connections found in the field to a distribution transformer 2. Match the meter number to the account number 3. Check meter reading against previous readings to assure that meter readings are being properly reported U. P. National Engineering Center National Electrification Administration

Power System Engineering for Non-Engineers

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Power System Analysis 101

63

Reduction and Control of Non-Technical Losses 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

U. P. National Engineering Center National Electrification Administration

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64

Reduction and Control of Non-Technical Losses 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

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Power System Analysis 101

65

Reduction and Control of Non-Technical Losses NEA SLRP 

Punitive Measures Against Pilferers R.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

U. P. National Engineering Center National Electrification Administration

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66

Reduction and Control of Non-Technical Losses 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

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Power System Analysis 101

67

Reduction and Control of Non-Technical Losses 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

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68

Reduction and Control of Non-Technical Losses 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.

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Power System Analysis 101

69

SHORT CIRCUIT ANALYSIS

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Short Circuit Analysis 1. What is Short Circuit? 2. Short Circuit Studies 3. Selection of Device Duties

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Power System Analysis 101

71

What is Short Circuit?

Very Large Current Flow

+

Very Small Resistance

I=

V ⇒∞ R →0

Short Circuit

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What is Short Circuit?

Analogy of Normal and Short Circuit Current in a Hydroelectric plant U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

73

What is Short Circuit? Equipment Explosion because of Short Circuit

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What is Short Circuit? Type of Faults

Three Phase Fault

Double Line-to-Ground Fault U. P. National Engineering Center National Electrification Administration

Line-to-Line Fault

Single Line-to-Ground Fault Power System Engineering for Non-Engineers

37

Power System Analysis 101

75

What is Short Circuit? Sources of Short Circuit Currents G

Utility

MV

Fault LV

Fault Current Contributors U. P. National Engineering Center National Electrification Administration

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76

What is Short Circuit? PROTECTIVE DEVICES: FUSE 

Low Voltage Fuses
Up to 1000 Volts



High Voltage Fuses
Above 1000 Volts

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Power System Analysis 101

77

What is Short Circuit? PROTECTIVE DEVICES: LOW VOLTAGE CIRCUIT BREAKERS

Molded-Case Circuit Breakers Low Voltage Power Circuit Breakers U. P. National Engineering Center National Electrification Administration

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78

Substation Vacuum Circuit Breakers

What is Short Circuit? PROTECTIVE DEVICES: HIGH VOLTAGE CIRCUIT BREAKERS

Outdoor-Type Circuit Breaker in Switchyard U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

79

What is Short Circuit? PROTECTIVE DEVICES: HIGH VOLTAGE CIRCUIT BREAKERS

Indoor Type Circuit Breaker in a Switchgear U. P. National Engineering Center National Electrification Administration

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80

Short Circuit Studies

Short Circuit Current and Time Characteristics of Protective Devices U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

81

Short Circuit Studies 

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

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82

Short Circuit Studies 

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

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Power System Analysis 101

83

Short Circuit Studies 

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

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Selection of Device Duties 

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



IEC: International Electrotechnical Commission

Prescribes Test Procedures and Calculation Methods U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

85

Selection of Device Duties 8-Cycle Total-Rated Circuit Breakers (KA)

5-Cycle Symmetrical-Rated Circuit Breakers (KA)

Circuit Breaker Nominal Size Identification

Example Maximum System Operating Voltage

Momentary Rating (Total 1st-Cycle RMS Current

Interrupting Rating (Total RMS Current at 4-cycle ContactParting Time

Closing and Latching Capability (Total First Cycle RM Current)

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

4.16 – 75

4.16 KV

20

10.5

19

10.1

4.16 – 250

4.16 KV

60

35

58

33.2

4.16 – 350

4.16 KV

80

48.6

78

46.9

13.8 – 500

13.8 KV

40

21

37

19.6

13.8 – 750

13.8 KV

60

13.5

58

30.4

13.8 – 1000

13.8 KV

80

42

77

40.2 Power System Engineering for Non-Engineers

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86

COMPARISON OF DUTIES TFF (KA)

LLF (KA)

BUS ID

PHASE

S/S PG-17 PG-26 PG-40 PG-52 PG-53 PG-63

3 3 3 3 3 3 3

2.30005 2.09517 1.98127 1.82417 1.70334 1.69336 1.59908

1.99190 1.81447 1.71583 1.57978 1.47514 1.46650 1.38485

PG-17-1 PG-17-2 PG-17-1-3 PG-17-2-3 PG-17-3-7

3 1 1 1 1

2.08156 0.00000 0.00000 0.00000 0.00000

1.80268 0.00000 0.00000 0.00000 0.00000

PG-26-5 PG-26-5-3

3 1

1.86883 0.00000

1.61845 0.00000

PG-40-2 PG-40-2-5 PG-40-2-6

3 1 1

1.78352 0.00000 0.00000

1.54457 0.00000 0.00000

PG-52-7

1

0.00000

0.00000

1

0.00000

0.00000

PG-53-1

DLGF SLGF (KA) (KA) BACKBONE LINES 2.86464 2.76467 2.32896 2.21705 2.10904 1.96635 1.85435 1.66821 1.68370 1.46936 1.67035 1.45395 1.54879 1.31529 LATERAL LINES 2.30059 2.18533 0.00000 2.14564 0.00000 2.01008 0.00000 2.06014 0.00000 1.87921 LATERAL LINES 2.15303 1.79814 0.00000 1.54157 LATERAL LINES 1.83166 1.61561 0.00000 1.50666 0.00000 1.58620 LATERAL LINES 0.00000 1.38134 LATERAL LINES 0.00000 1.44395

U. P. National Engineering Center National Electrification Administration

MAX I

SC Duty

Margin Remarks

2.86464 2.32896 2.10904 1.85435 1.70334 1.69336 1.59908

15 4 4 4 4 4 4

524 172 190 216 235 236 250

% % % % % % %

Adequate Adequate Adequate Adequate Adequate Adequate Adequate

2.30059 2.14564 2.01008 2.06014 1.87921

4 4 4 4 4

174 186 199 194 213

% % % % %

Adequate Adequate Adequate Adequate Adequate

2.15303 1.54157

4 4

186 % 259 %

Adequate Adequate

1.83166 1.50666 1.58620

4 4 4

218 % 265 % 252 %

Adequate Adequate Adequate

1.38134

4

290 %

Adequate

1.44395

4

277 %

Adequate

Power System Engineering for Non-Engineers

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Power System Analysis 101

87

POWER SYSTEM RELIABILITY ANALYSIS

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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

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89

What is Reliability?
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 U. P. National Engineering Center National Electrification Administration

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What is Reliability? A reliable piece of equipment or a System is understood to be basically sound and give troublefree 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. U. P. National Engineering Center National Electrification Administration

Power System Engineering for Non-Engineers

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Power System Analysis 101

91

Measuring Reliability 1

2

System Failure

3 Mathematical Reliability Model

Failure Events

5

Application (Reliability Index)

4 Reliability Data

Power System Reliability Evaluation U. P. National Engineering Center National Electrification Administration

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92

Measuring Reliability ORGANIZATION, CUSTOMER, kVA

INCIDENTS HISTORICAL ASSESSMENT

COMPONENT POPULATION COMPONENT PERFORMANCE SYSTEM DEFINITION

PREDICTIVE ASSESSMENT

U. P. National Engineering Center National Electrification Administration

HISTORICAL SYSTEM PERFORMANCE MANAGEMENT OPERATIONS ENGINEERING CUSTOMER INQUIRIES

PREDICTED SYSTEM PERFORMANCE COMPARATIVE EVALUATIONS AID TO DECISION-MAKING PLANNING STUDIES

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46

Power System Analysis 101

93

Component Reliability Component Failure Data Item No.

Time-to-Failure (hrs.)

1

8

2

20

3

34

4

46

5

63

6

86

7

111

8

141

9

186

10

266

How Reliable is the component?

Power System Engineering for Non-Engineers

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Power System Analysis 101

94

Component Reliability Failure Density Function

Time

f(t) measure of the overall speed at which failures are occurring.

∆ ti

f(t)

0–8

8

8 – 20

12

20 – 34

14

34 – 46

12

46 – 63

17

63 – 86

23

86 – 111

25

111 – 141

30

141 – 186

45

186 – 266

80

1 10 = 0.0125 8 1 10 = 0.0084 12 1 10 = 0.0074 14 1 10 = 0.0084 12 1 10 = 0.0059 17 1 10 = 0.0043 23 1 10 = 0.0040 25 1 10 = 0.0033 30 1 10 = 0.0022 45 1 10 = 0.0013 80

U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

95

f(t) fractional failures/hr.x10-2

Component Reliability 1.4 1.2 1.0 0.8

0.6 0.4 0.2

0

0

100 200 Operating time, hr.

300

Failure Density Function from Component Failure Data Power System Engineering for Non-Engineers

U. P. National Engineering Center National Electrification Administration

Power System Analysis 101

96

Component Reliability Failure Hazard Function

h(t) measure of the instantaneous speed of failure [Propones to Failure]

Time

∆ ti

0–8

8

8 – 20

12

20 – 34

14

34 – 46

12

46 – 63

17

63 – 86

23

86 – 111

25

111 – 141

30

141 – 186

45

186 – 266

80

U. P. National Engineering Center National Electrification Administration

h(t) 1 10 = 0.0125 8 19 = 0.093 12 18 = 0.0096 14 17 = 0.0119 12 16= 0.0098 17 15= 0.0087 23 14= 0.0100 25 13 = 0.0111 30 12 = 0.0111 45 11 = 0.0125 80

Power System Engineering for Non-Engineers

48

Power System Analysis 101

97

Component Reliability h(t) failures/hr.x10-2

1.4 1.2

1.0 0.8

0.6 0.4 0.2 0

0

100

300

200

Operating time, hr.

Hazard Function from Component Failure Data 0.011 failure/hr x 8760 hrs/yr = 97 failures/yr Power System Engineering for Non-Engineers

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Power System Analysis 101

98

Component Reliability Reliability Function t

h (τ )d τ R (t ) = e ∫0 −

For the component with a hazard rate of 0.011 f/hr, R(1 hour) = 0.989

R(24 hours) = 0.768

For a component with a constant Hazard h = 0.01 f/yr

R(1) = 0.99

h = 0.02 f/yr

R(1) = 0.98

U. P. National Engineering Center National Electrification Administration

[Probability that the component will not fail in 1 year] Power System Engineering for Non-Engineers

49

Power System Analysis 101

99

Component Reliability h(t )

h(t )

Kt

λ

t

t

a. Constant Hazard

b. Increasing Hazard

h(t )

K0 t

h (τ )d τ R (t ) = e ∫0 −

K0 K1

t

t0

a. Decreasing Hazard

Reliability Function

U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

100

Component Reliability The Bathtub Curve

a. Hazard Function

b. Failure Density Function U. P. National Engineering Center National Electrification Administration

Power System Engineering for Non-Engineers

50

Power System Analysis 101

101

Component Reliability Hazard Model for Different System

a. Mechanical

b. Electrical

c. Software

Power System Engineering for Non-Engineers

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Power System Analysis 101

102

Component Reliability Weibull Model (A General Reliability Model) R (t )

h (t ) K

5

m=3 m=2

5 4 3

m=1

2 1

m = 0 .5 m=0 m = −0 .5

t→

1

2

Hazard function U. P. National Engineering Center National Electrification Administration

4 3

2 1

τ →

m = − 0 .5 m=0 m = 0 .5

m=1 m=2 m=3

1

2

Reliability function Power System Engineering for Non-Engineers

51

Power System Analysis 101

103

Component Reliability RELIABILITY ASSESSMENT of MERALCO Distribution Transformers* Distribution Transformer Failures • 1997: 996 DT Failures • Average of three (3) DT Failures/day • Lost Revenue during Downtime • Additional Equipment Replacement Cost • Lost of Customer Confidence
Identify the Failure Mode of DTs
Develop strategies to reduce DT failures * R. R. del Mundo, et. al. (2000) U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

104

Component Reliability METHODOLOGY: Reliability Engineering (Weibull Analysis of Failure Data) • Gather Equipment History (Failure Data) • Classify DTs (Brand, Condition, KVA, Voltage) • Develop Reliability Model • Determine Failure Mode • Recommend Solutions to Improve Reliability

U. P. National Engineering Center National Electrification Administration

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52

Power System Analysis 101

105

Component Reliability Parametric Model • Shape Factor • Characteristic Life Shape Factor <1 =1 >1

Failure Mode

Hazard Function Decreasing Constant Increasing

Failure Mode Early Random Wear-out Power System Engineering for Non-Engineers

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Power System Analysis 101

106

Component Reliability MERALCO DTs (1989–1997) Brand

New

Recond

Rewind

Convert

Total

A

29,960

835

1,333

2,048

34,712

B

5,986

118

135

269

6,586

C

6,358

49

31

21

6,561

D

2,037

116

90

E

-

-

F

-

G H TOTAL

-

2,344

-

-

192

-

-

-

168

-

-

-

-

79

-

-

-

-

69

1,118

1,588

2,338

44,341

51,129

Note: Total Include Acquired DTs U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

107

Component Reliability Reliability Analysis: All DTs Interval 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000

Failures 1444 797 638 508 475 363 295 224 159 89 98 51 19 2 0

Survivors 57095 48852 39997 32802 27515 22129 18200 14690 11865 9010 6473 4479 2254 821 127

U. P. National Engineering Center National Electrification Administration

Hazard 0.0269 0.0178 0.0174 0.0167 0.0189 0.0178 0.0178 0.0167 0.0151 0.0114 0.0177 0.015 0.0122 0.0042 0 Power System Engineering for Non-Engineers

Power System Analysis 101

108

Component Reliability Reliability Analysis: All DTs 0.03 0.025

Hazard

Weibull Shape = 0.84 0.02 0.015 0.01

Failure Mode: EARLY FAILURE 0.005

Is it Manufacturing Defect?

0 0

200

400

600

800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000

Time Interval U. P. National Engineering Center National Electrification Administration

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54

Power System Analysis 101

109

Component Reliability Reliability Analysis: By Manufacturer BRAND A B C D E F G H

Size 34712 6586 6561 2344 192 168 79 69

Shape 0.84 0.81 0.86 0.76 0.85 0.86 0.76 0.98

Failure Mode Early Failure Early Failure Early Failure Early Failure Early Failure Early Failure Early Failure Early Failure

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110

Component Reliability Reliability Analysis: By Manufacturer & Condition BRAND A B C D

New 1.11 0.81 0.81 0.67

Reconditioned Rewinded 1.23 1.12 1.29 1.27 1.13 0.77 1.11 1.49

U. P. National Engineering Center National Electrification Administration

Converted 1.4 1.23 0.94 -

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55

Power System Analysis 101

111

Component Reliability Reliability Analysis: By Voltage Rating PRI 20 20 20 20 13.2 13.2 7.62 7.62 4.8 3.6 2.4

SEC 7.62 120/240 139/277 DUAL 120/240 240/480 120/240 DUAL 120/240 120/240 120/240

U. P. National Engineering Center National Electrification Administration

All DTs 0.75 0.79 1.14 0.72 0.88 0.91 0.99 0.77 0.87 0.78 1.15

New DTs 0.94 1.1 1.03 1.54 1.46 1.61 1.17 Power System Engineering for Non-Engineers

Power System Analysis 101

112

Component Reliability Reliability Analysis: By KVA Rating (New DTs) KVA 10 15 25 37.5 50 75 100 167 250 333

Shape 1.3 1.25 0.92 0.83 0.73 1.05 1.04 1.16 1.11 1.46

U. P. National Engineering Center National Electrification Administration

Failure Mode Wear-out Wear-out Early Early Early Random Random Random Random Wear-out Power System Engineering for Non-Engineers

56

Power System Analysis 101

113

Component Reliability 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 Power System Engineering for Non-Engineers

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114

Component Reliability Preventive Maintenance and Hazard Rates Hazard rate

m

2m

3m

Effect of PM on Increasing Hazard Rate

Hazard rate

Hazard rate

m

2m

3m

Effect of PM on Constant Hazard Rate U. P. National Engineering Center National Electrification Administration

m

2m

3m

Effect of PM on Decreasing Hazard Rate Power System Engineering for Non-Engineers

57

Power System Analysis 101

115

Component Reliability RELIABILITY ASSESSMENT of MERALCO Power Circuit Breakers* Number of Feeder Power Circuit Breakers VOLTAGE

OCB

VCB

GCB

34.5 KV 13.8 KV 6.24 KV 4.8 KV TOTAL

149 7

160 28 26 2 216

41 2

156

43

MOCB

ACB

36 3

12 122 11 145

39

* R. R. del Mundo & Melendrez (2001) Power System Engineering for Non-Engineers

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Power System Analysis 101

116

Component Reliability RELIABILITY ASSESSMENT of MERALCO Power Circuit Breakers* Annual Failures of 34.5 kV OCBs 1997 Causes of Failure

Installed

1998 Failed

Installed

1999

2000

Failed

Installed

Failed

Installed

Failed

Average Failures (Units/yr)

Contact Wear

158

2

155

2

149

1

145

2

1.15

Bushing Failure

158

1

155

3

149

3

145

1

1.317

-

-

155

1

-

-

-

-

0.645

158

3

155

6

149

4

145

3

2.636

Mechanism Failure Totals

3 Circuit Breakers failing per year! Preventive Maintenance Policy: Time-based (Periodic) U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

117

Reliability Assessment of MERALCO Power Circuit Breakers 0.4

0.3 0.2 0.1 0

H a z a rd R a t e

0.2 H a z a r d R a te

H a za rd R a te

0.4

0.15 0.1 0.05 0 6

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

0.1 3 6 9 12 15 18 21 24 27 30 33 36 39 42 45 48 51 54 57 60 Time Interval (months)

13.8 kV MOCBs

34.5 kV GCBs

HAZARD FUNCTION CURVE FOR 6.24 KV MOCBs

HAZARD FUNCTION CURVE FOR ALL PCBs CONSIDERED

HAZARD FUNCTION CURVE FOR 6.24 KV ACBs

0.3 0.2 0.1 0

0.2 0.15 0.1 0.05 0

9 12 15 18 24 30 36 42 48 54 60

H az ard R ate

H a z a r d R a te

0.4

6

0.2

Time Interval (months)

34.5 kV OCBS OCBs

3

0.3

0

12 18 24 30 36 42 48 54 60

Time Interval (months)

H a z a rd R a t e

HAZARD FUNCTION CURVE FOR 13.8 KV MOCBs

HAZARD FUNCTION CURVE FOR 34.5 KV GCBs

HAZARD FUNCTION CURVE FOR 34.5 KV OCBs

6

0.4 0.3 0.2 0.1 0

.

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

12 18 24 30 36 42 48 54 60

Time Interval (months)

Time Interval (months)

Time Interval (months)

6.24 kV ACBs

6.24 kV MOCBs

All PCBs

TIME-BASED HAZARD FUNCTION Power System Engineering for Non-Engineers

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Reliability Assessment of MERALCO Power Circuit Breakers 0.00006x2

y= + 0.032

0.04

0.05

– 0.0007x

H a z a r d R a te

H a z a r d R a te

H a z a rd R a t e

0.05

0.25 0.2 0.15 0.1 0.05 0

0.03 0.02 0.01

10

15

20

25

30

25

35

50

34.5 kV OCBS OCBs

0.1 0

6.24 kV MOCBs

100

125

0.01 25

150

50

20

0.1 0 10

15

6.24 kV ACBs

125

150

HAZARD FUNCTION CURVE FOR 34.5 KV OCBs

0.2

Tripping Interval

100

13.8 kV MOCBs

0.3

5

75

Tripping Interval

H a z a rd R a te

H a z a rd R a te

0.2

Tripping Interval

75

HAZARD FUNCTION CURVE FOR 6.24 KV MOCBs

0.3

15

0.02

34.5 kV GCBs

HAZARD FUNCTION CURVE FOR 6.24 KV MOCBs

10

0.03

Tripping Interval

Tripping Interval

5

0.04

0

0

5

H a z a rd R a te

HAZARD FUNCTION CURVE FOR 34.5 KV GCBs

HAZARD FUNCTION CURVE FOR 34.5 KV GCBs

HAZARD FUNCTION CURVE FOR 34.5 KV OCBs

20

0.25 0.2 0.15 0.1 0.05 0 5

10

15

20

25

30

35

Tripping Interval

All PCBs

TRIPPING OPERATIONS-BASED HAZARD FUNCTION U. P. National Engineering Center National Electrification Administration

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Power System Analysis 101

119

Component Reliability RELIABILITY ASSESSMENT of MERALCO Power Circuit Breakers*

Hazard Rate

Schedule of Servicing for 41XV4 0.08 0.06 0.04 0.02 0 0

10

20

30

40

50

60

70

Number of Tripping Operations

Reliability-Based Preventive Maintenance Schedule Power System Engineering for Non-Engineers

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120

System Reliability Series Reliability Model R(x1)

R(x2)

R(x3)

R(x4)

Series System 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. n

Rs = ∏ R( xi ) i =1 U. P. National Engineering Center National Electrification Administration

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60

Power System Analysis 101

121

System Reliability Parallel Reliability Model R(x1) R(x2)

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

R(x3) R(x4)

n

Rs = 1 − ∏ [1 − R( xi )] i =1

Parallel Network U. P. National Engineering Center National Electrification Administration

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122

System Reliability Standby Redundancy Model R(x1) R(x2) R(x3) R(x4) 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. U. P. National Engineering Center National Electrification Administration

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61

Power System Analysis 101

123

System Reliability K-Out-of-N Reliability Model R(x1) R(x2) R(x3)

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

 n Rs = ∑   R i ( 1 − R )n −i i=k  i  n

This is another form of redundancy. It is used where a specified number of units must be good for the system success. Power System Engineering for Non-Engineers

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Power System Analysis 101

System Reliability Networks

124 1 2 3 5

4 6

7

Primary side

8

9

10 11 12 13 14 15 17

16 18

Reliability Network Models for Typical Substation Configurations of MERALCO*

19 21

20 22

23 25

24 26

27 28 29 30

31

32

33

34 35

Secondary side

36

37 38

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

39 40 41 42 43 44 45 46 47 48

49

50 51 52 53 54 55

* Source: A. Gonzales (Meralco) & R. del Mundo (UP), 2005 U. P. National Engineering Center National Electrification Administration

56 57

58

Power System Engineering for Non-Engineers

62

Power System Analysis 101

125

System Reliability Networks Reliability Network Diagram of Single breaker-single bus scheme (Scheme 1) 15λ λc

29λ λct

2λ λbus

4λ λd1

λp

2λ λb1

2λ λb2

3λ λd2

Summary of Substation Reliability Indices for Scheme 1 Event 1

Probability

λs (failure/yr)

Us (hr/yr)

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

1.0

0.247152 0.828784

Total

1.0

0.247152 0.828784

where: λs - substation failure rate or interruption frequency Us – substation annual outage time or unavailability Power System Engineering for Non-Engineers

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Power System Analysis 101

126 L1

System Reliability Networks

L2

1

70 2

71

4

73

3

72 5

6

76 77

8

78

9 18

16

127 19

128

129

14 13

22 132

133

12

23 10

134

17

15

20 21

130 131

Reliability Network Models for Typical Substation Configurations of MERALCO

92

11

35 135

136

34

140

81 89

82

32

26

88 87

31

27

141

80

90 33

25

139

79 91

24

137 138

28

86

30

83 84 85 29

36

93

37

Primary side

94 95

38 39

96

40

97

41

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

74

75

7

98

Bank 1

42

99

101

44

102

45

103

46 104

47 49

48

105

106 107

50

109

52 110

53

111

54 55

126

112

56 125

59

119

124 121

58 61

Secondary side

108

51

57

Bank 2

100

43

122

60 123

120

115 117 116

113

114

118

62 63

64 65 66 67 68 69

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127

Substation Reliability Models Reliability Network Diagram of Single breaker-double bus with normally opened 115kV bus tie breaker (Scheme 2) 16λ λc

29λ λct

2λ λbus

3λ λd1

2λ λb1

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

20λ λc

37λ λct

3λ λbus

5λ λd1

2λ λb1

λp

2λ λb2

3λ λd2

2λ λb2

3λ λd2

P1 = 0.997985

λp

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

20λ λc

37λ λct

2λ λbus

3λ λd1

2λ λb1

λp

3λ λb2

5λ λd2

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

20λ λc

37λ λct

2λ λbus

3λ λd1

2λ λb1

λp

3λ λb2

5λ λd2

Event 4: Opened 115kV bus tie breaker & closed 34.5kV bus tie breaker; P4 = 0.00182614 Power System Engineering for Non-Engineers

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128

Substation Reliability Models Summary of Substation Reliability Indices for Scheme 2 Event

Probability

λs (failure/yr)

Us (hr/yr)

1

0.997985

0.251752

0.848919

2

0.000188

0.302966

1.008374

3

0.000000344

0.308936

1.023840

4

0.001826

0.308936

1.023840

1.0

0.251866

0.849275

Total

Event 1: With two primary lines energized & opened 34.5kV bus tie breaker; P1 = 0.997985 Power System Engineering U. P. National Engineering Center for Non-Engineers National Electrification Administration

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Power System Analysis 101

129

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

λ17

λ54

λΒ3

λΒ4

λΒ1

λΒ1 Β3

λΒ2 Β3

λΒ1 Β3

λΒ1

λΒ2 Β3

λΒ2 Β3

λΒ6

λΒ7

λΒ7 Β4

λλΒ4 29

λΒ9

λΒ6

λΒ4 29

λΒ5

Event 1: With two primary lines energized & opened 34.5kV bus tie breaker; P1 = 0.997985 λ17

λB1

λB2

λB3

λB5

λB4

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

λ17

λ29

λB1

λB2

λB5

λB8

P2 = 0.000188

λB9

λB10

λB11

Event 3: With one line, L2 interrupted and closed 34.5kV bus tie breaker; P3 = 0.000000344 Power System Engineering for Non-Engineers

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

λ29

λ111

λΒ5

λΒ8

λΒ10

λΒ1

λΒ1

λΒ3 Β2

λΒ3 Β6

λΒ3 Β2

λΒ6

λΒ6

λΒ7

λΒ7

λλΒ4 17

λΒ4 Β6

λΒ9

λΒ3 Β7

λλΒ3 Β7

λΒ7 Β3

λΒ9

λλΒ4 Β8

λλΒ4 17

λΒ11

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

P4 = 0.001826140

Summary of Substation Reliability Indices for Modified Scheme 2

Event

Probability

λs (failure/yr)

Us,(hr/yr)

1

0.997985

0.176076

0.583548

2

0.000188

0.251122

0.847621

3

0.000000344

0.377120

1.261549

4

0.001826

0.233261

0.758472

1.0

0.176194

0.583923

Total

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Power System Analysis 101

131

Substation Reliability Models Comparison of Substation Reliability Indices for Scheme 2 Scheme 2

λs (failure/yr)

Original (opened 115kV bus tie breaker) Modified (closed 115kV bus tie breaker)

Us (hr/yr)

0.251866

0.849275

0.176194

0.583923

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

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132

System Reliability Networks

B1

67

1

B4

17 16

15

32

81 79

78

12 11

B2

82 80

14 13

77

10

76

B5

75

9 7

8

73

6

74 72

71

5

70 4

Reliability Network Models for Typical Substation Configurations of MERALCO

3

69

68

Primary side

2 3

69

18

20

85 21

86

87

22

B3

83 84

19

88

23 24

89 26

B6

90

25

91 92

27 93

28 29

94 95

30 31

96

33

97

B7

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

34

99

36

101

37

104 105

41

106 43

107 108 109 110 111

48

112 49

51 53

113

50

114

130

B10

128

123 125

129

57

58

Secondary side 115

116

55 56

100

103

39

44 45 46 47

52

Bank 2

102

38 40 42

54

B8

98

35

Bank 1

127

119 117

121

126 124

120

118

122

59 60 62

61 63

B9

64 65 66

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Substation Reliability Models Reliability Block Diagram of Ring Bus Scheme (Scheme 3) λB1

λB4

λB1

λB2

λB5

λ17

λB2

λB4

λ51

λB7

λB10

λB5 λB6

λB3

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

λB1

P1 = 0.997985

λB4

λB1

λB3

λB5

λ31

λB2

λB4

λB8

λB9

λB10

λ51

λB6 λB6

λB3

Event 2: With two primary lines energized & closed 34.5kV bus tie breaker; P2 = 0.00182614 Power System Engineering for Non-Engineers

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Substation Reliability Models Reliability Block Diagram of Ring Bus Scheme (Scheme 3)

CONT. λB2

λB2

λB2

λB2

λ17

λB1

λB3

λ31

λB7

λ51

λB5

λB6

Event 3: With one primary line (L2) interrupted and opened 34.5kV bus tie breaker; λB2

λB3

λB3

λ31

λ17

λB5

P3 = 0.000188056

λB3

λB1

λB3

λB10

λB8

λB9

λ51

λB10

λB6

Event 4: With one primary line (L2) interrupted and closed 34.5kV bus tie breaker; P4 = 0.000000344 U. P. National Engineering Center National Electrification Administration

Power System Engineering for Non-Engineers

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Power System Analysis 101

135

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

Probability

λs (failure/yr)

Us (hr/yr)

1

0.997985

0.137928

0.436499

2

0.001826

0.195112

0.618379

3

0.000188

0.147283

0.468233

4

0.000000344

0.204467

0.650114

1.0

0.138034

0.436836

Total

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136 L 1

System Reliability Networks

L 2 1

B2

1 7

1 61 4

1 5 1 3 1 1 9

1 21 0

9 9 3 1 8 89 7 8 5 8

B5

8

7

7 8

B1

6

3

5 4

3

8 1 2

7 9

Reliability Network Models for Typical Substation Configurations of MERALCO

2 2 0 2 2 4 2

B3

9 4

1 9 2 1

62 2 7 8 2 9

2 5

10 0 10 2 10 4

4 2

10 6 10 118 0

B9

Scheme 4: Breaker-and-a-half bus (primary side) and two single breaker-single bus with bus tie breaker (secondary side)

Bank 1

6 4 6 6 66 6 7 8 9 7 0 7 1 7 7 37 2 4 7 5 7 7 6 7

U. P. National Engineering Center National Electrification Administration

6 2

12 1

4 5

12 2

4 7 4 9 5 0 5 2

9 5 9 7 10 1 10 3

9 9

12 5

Primary side

10 5 10 7 10 9

B8

B10 12 3

12 4 12 6 12 7 12 9 13 1 13 3 13 5

12 13 8 5 0 4 5 13 5 5 5 2 13 6 75 4 8 5 13 6 13 9 6 13 7 6 0 8 1 15 14 4 0 14 14 15 14 14 6 14 2 158 1 4 2 0 15 14 14 15 14 14 3 5 3 1 9 7 5 5 1 3

6 3 6 5

4 4

4 6 4 8

8 0

11 1 11 11 2 11 3 11 4 5 11 6 11 11 7 8

11 9

1

8 2

10 5

12 0

4 3

2 3 9 0 3 3 1 3 3 2 3 4 3 5 3 6 3 3 7 83 4 9 0 4

B4

9 96 8

B7

2 3

B6

8 6

8 4

8 0

3 1 8

9 2 9 0 8 8

Bank 2

Secondary side 13 9

B1 1

Power System Engineering for Non-Engineers

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Power System Analysis 101

137

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

λΒ1 λΒ9

λ62

λΒ3

λΒ3

λΒ4

λΒ7

λΒ2 Β3

λλΒ1 6

λλΒ1 6

λΒ6 Β2

λΒ3 33

λλΒ7 7

λΒ8

λΒ7 33

λΒ5 34

λ17

λΒ2 17

λΒ3

λΒ12 λΒ5

A

λΒ3

λΒ1 Β3

λλ119 Β4

A

λΒ8 Β4

λΒ1 Β3

λΒ1 Β3

λΒ1 Β3

λΒ1 Β3

λλΒ1 6

λλΒ1 6

λΒ3

λΒ3

λλΒ3 6

λλΒ3 6

λλΒ2 17

λλΒ4 33

λΒ2

λλΒ2 33

λλΒ2 7

λΒ2

λΒ5 Β2

λΒ5 33

λλΒ5 7

λΒ5

λλ119 33

λ17 34

λΒ7 33

λλΒ8 34

λ119

λΒ4 Β2

λ17 33

λΒ6 34

λΒ8

λλ119 Β2

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

P1 = 0.997985

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

λΒ7

λΒ1

λΒ10

λ139

λΒ11

λ62

λΒ8

λλ119 Β4

λΒ7

λΒ2 Β3

λλΒ1 6

λλΒ5 6

λΒ6 Β2

λΒ3 33

λλΒ2 7

λΒ8

λλΒ7 33

λΒ5 34

λΒ7

λλΒ2 17

λΒ4 Β3

λΒ12

λΒ5

A

λΒ7 Β3

λΒ3

λΒ1 Β3

A

λΒ7 Β4

λΒ5 Β3

λΒ3

λΒ3

λΒ2 Β3

λλΒ2 6

λλΒ2 6

λΒ5 Β3

λΒ4 Β3

λλΒ4 6

λλ119 6

λλ119 6

λΒ2 17

λΒ5 33

λΒ5 Β2

λΒ5 33

λλΒ5 7

λΒ4

λΒ6 Β2

λΒ5 33

λλΒ5 7

λΒ5

λΒ5

λλ119 33

λ17 34

λΒ6 33

λΒ8 34

λ119

λΒ5 Β2

λΒ8 33

λΒ6 34

λ17

λΒ7 Β2

λΒ6 Β2

Event 2: With two primary lines energized and closed 34.5kV bus tie breaker; P2 = 0.001826 U. P. National Engineering Center National Electrification Administration

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Substation Reliability Models Reliability Block Diagram of Breaker-and-a-half Scheme (Scheme 4) λΒ3

λΒ9

λ62

λΒ12

λΒ6 Β3

λΒ6 Β3

λΒ6 Β3

λΒ6 Β3

λΒ7 Β3

λΒ5

A

λΒ4

λΒ7

λΒ8 Β4

λλ119 Β4

λΒ4

λΒ4 17

λΒ7

λΒ7 Β3

λΒ8 Β3

λΒ8 Β3

λΒ8

λΒ3 17

λΒ3 17

λΒ2 Β3

λλ119 Β3

λλ119 Β3

λΒ2

λΒ3

λΒ4 17

λΒ2 Β4

λΒ3

λ119

λΒ4

λΒ4

λΒ2 Β4

λΒ3 Β4

A

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

P3 = 0.000188

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

λΒ10

λ139

λΒ11

λ62

λΒ12

λΒ7

λΒ6 Β3

λΒ7 Β3

λΒ7 Β3

λΒ7

λΒ8

λΒ7

λλΒ4 17

λΒ2 Β4

λΒ3

λΒ4 Β3

λλ119 Β3

λΒ7

λΒ7 Β4

λΒ5

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) Event

Probability

λs (failure/yr)

Us (hr/yr)

1

0.997985

0.137306

0.435214

2

0.001826

0.195120

0.611433

3

0.000188

0.146674

0.466972

4

0.000000344

0.204473

0.643165

1.0

0.137413

0.435545

Total

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System Reliability Networks Substation Reliability Models Comparison of Substation Reliability Indices (Scheme 1 to 4) Configuration

λs (failures/yr)

Us (hrs/yr)

Scheme 1 (Single breaker-single bus)

0.247152

0.828784

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

0.251866 0.176194

0.849275 0.583923

Scheme 3 (Ring bus)

0.138034

0.436836

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

0.137413

0.435545

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

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Distribution System Reliability CUSTOMER-ORIENTED RELIABILITY INDICES System Average Interruption Frequency Index (SAIFI)* The average number of interruptions per customer served during a period

SAIFI =

Total number of customer interruptions Total number of customers served

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

SAIDI =

Sum of customer interruption duration Total number of customers served

Note: SAIFI for Sustained interruptions. MAIFI for Momentary Interruptions U. P. National Engineering Center National Electrification Administration

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Distribution System Reliability CUSTOMER-ORIENTED RELIABILITY INDICES Customer Average Interruption Frequency Index (CAIFI) The average number of interruptions per customer interrupted during the period

CAIFI =

Total number of customer interruptions Total number of customers interrupted

Customer Average Interruption Duration Index (CAIDI) The average interruption duration of customers interrupted during the period

CAIDI =

Sum of customer interruption duration Total number of customers interrupted

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Distribution System Reliability CUSTOMER-ORIENTED RELIABILITY INDICES 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 Customer hours of available service

ASAI =

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 C ustomer hours of unavailabl e service ASUI = Customer hours demanded U. P. National Engineering Center National Electrification Administration

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Distribution System Reliability 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.

ALII =

Total load interruption Total connected load

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.

ASCI =

Total energy curtailment Total number of customers served

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Distribution System Reliability LOAD- AND ENERGY-ORIENTED RELIABILITY INDICES Average Customer Curtailment Index (ACCI) The KWh of connected load interruption per affected customer per year.

ACCI =

Total energy curtailment Total number of customers affected

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Distribution System Reliability Historical Reliability Performance Assessment 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

d1 Number of customers interrupted

d3 d2

N1

N3

N2 Time

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Distribution System Reliability 2

1

S Source

L1

3 C

B

A

L2

L3

SYSTEM LOAD DATA Load Point L1 L2 L3

Number of Average Load Customers Demand (KW) 200 1000 150 700 100 400 INTERRUTION DATA

Number of Interruption Load Point Average Load Duration of Disconnected Event i Affected Curtailed (KW) Interruption Customers 1 L3 100 400 6 hours U. P. National Engineering Center National Electrification Administration

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Distribution System Reliability SAIFI =

∑N ∑N

C

=

100 200 + 150 + 100

= 0.222222 interruption customer - yr SAIDI =

∑ N d = (100 )(6 ) ∑ N 200 + 150 + 100 C

= 1.333333 hours customer - yr CAIDI =

∑ N d = (100 )(6 ) 100 ∑N C

C

= 6 hours custumer - interruption Power System Engineering for Non-Engineers

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Distribution System Reliability ASUI =

∑N

C

d

∑ N = SAIDI = 1.333333

8760 = 0.000152

8760

8760

ASAI = 1 − ASUI = 1 − 0.000152 = 0.999848

ASCI =

ENS = ∑N

∑ L d = (400 )(6 ) ∑ N 200 + 150 + 100 a

= 5.333333 KWh customer − yr Note: ENS - Energy Not Supplied U. P. National Engineering Center National Electrification Administration

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Distribution System Reliability Outage & Interruption Reporting

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Historical Reliability Performance Assessment Outage & Interruption Reporting *Not included in Distribution Reliability Performance Assessment

152

Date 1 2* 3 4* 5 6* 7 8 9 10* 11 12* 13 14* 15 16 17* 18* 19* 20

01/08/04 02/06/04 02/14/04 03/15/04 04/01/04 05/20/04 05/30/04 06/12/04 07/04/04 07/25/04 07/30/04 08/15/04 09/08/04 09/30/04 10/25/04 11/10/04 11/27/04 12/14/04 12/27/04 12/28/04

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Affected hours 3 All 5, 6 4, 5, 6 3, 4 1, 2, 1 5 All 5 4 2 1, 2, 3 2, 3 3 3, 4, 2, 3 1, 2,

6

3

3

5 3

1.5 4 0.5 3 1.5 3.5 0.5 2 1 5 1 2 1 2.5 1.5 1.5 2 3.5 3 0.075

Line Fault at C Transmission Line Fault at D Pre-arranged Overload Pre-arranged Line Tripped Line fault Line Overload Transmission Line Fault Pre-arranged Line Fault Pre-arranged Line Tripped Line Fault at A Pre-arranged Pre-arranged Pre-arranged Line Fault

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Distribution System Reliability Outage & Interruption Reporting Customer Count Month January February March April May June July August September October November December Annual Average

1 900 905 904 908 912 914 917 915 924 928 930 934 916

2 800 796 801 806 804 810 815 815 821 824 826 829 812

3 600 600 604 606 608 611 614 620 622 626 630 635 615

4 850 855 854 859 862 864 866 872 876 881 886 894 868

5 500 497 496 501 509 507 512 519 521 526 530 538 513

6 300 303 308 310 315 318 324 325 328 331 334 332 319

Total 3,950 3,956 3,967 3,990 4,010 4,024 4,048 4,066 4,092 4,116 4,136 4,162 4,043

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Distribution System Reliability Outage & Interruption Reporting Interruption Number

Load Points Affected

1 3

3 5 6 6 1 2 3 1 5 5 2 3 2 3

5 7

8 9 11 13 15 16

Number of Duration Customer Customers (Hrs.) Hours Affected Curtailed 600 497 303 310 912 804 608 914 512 512 821 626 826 630

U. P. National Engineering Center National Electrification Administration

1.5 0.5 0.5 1.5 0.5 0.5 0.5 2 1 1 1 1.5 1.5 1.5

Date

900 01/08/04 248.5 02/14/04 151.5 465 04/01/04 456 05/30/04 402 304 1,828 06/12/04 512 07/04/04 512 07/30/04 821 09/08/04 939 10/25/04 1,239 11/10/04 945

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Distribution System Reliability Outage & Interruption Reporting Calculate the Annual Reliability Performance of the Distribution System (according to Phil. Distribution Code)

∑N ∑N ∑N d SAIDI = ∑N ∑N MAIFI = ∑N SAIFI =

C

C

C

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Distribution System Reliability Predictive Reliability Performance Assessment A Source

Distribution System

B Loads

Source

C

λA, rA, UA

A

λB, rB, UB

B Loads

λC, rC, UC

C

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 U. P. National Engineering Center National Electrification Administration

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157

Distribution System Reliability Load Point Reliability Equivalents For parallel combinations:

For series combinations:

1 1

2

P

S 2

n

λs = Σ λi

λp = λ1λ2 (r1 + r2)

i=1

r1 r2 rp = __________ r1 + r2

n

Σ λiri

i=1

rs = _________ λs

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Distribution System Reliability S Source

2

1

3

B

A L1

C L3

L2

COMPONENT DATA Feeder A B C

Load Point L1 L2 L3

r λ (f/year) (hours) 0.2 6 0.1 5 0.15 8 SYSTEM LOAD DATA Number of Customers 200 150 100

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Average Load Demand (KW) 1000 700 400 Power System Engineering for Non-Engineers

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159

Load Point Reliability Equivalents
For L1 λ1 = λ A

r1 = rA

U 1 = λ1r1

= 6 hrs

= 0.2 f yr


For L2

r2 =

λ2 = λ A + λB = 0.2 + 0.1

=

= 0.3 f yr

λ A rA + λB rB λ A + λB

(0.2 )(6 ) + (0.1)(5 )

0.2 + 0.1 = 5.666667 hrs


For L3

λ3 = λ A + λB + λC

r3 =

= 0.2 + 0.1 + 0.15

λ A rA + λB rB + λC rC λ A + λB + λB

(0.2)(6) + (0.1)(5) + (0.15)(8) =

= 0.45 f yr

= (0.2 )(6 ) = 1.2 hrs yr

U 2 = λ2 r2 = (0.3)(5.666667 ) = 1.7 hrs yr

U 3 = λ3 r3 = (0.45 )(6.444444 ) = 2.9 hrs yr

0.2 + 0.1 + 0.15 = 6.444444 hrs

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Reliability Indices SAIFI =

∑ λ N = (0.2 )(200 ) + (0.3)(150 ) + (0.45 )(100 ) 200 + 150 + 100 ∑N i

i

i

= 0.288889 interruption customer − yr

SAIDI =

∑U N = (1.2 )(200 ) + (1.7 )(150 ) + (2.9 )(100 ) 200 + 150 + 100 ∑N i

i

i

= 1.744444 hours customer - yr

CAIDI =

∑U N ∑λ N i

i

i

i

=

SAIDI 1.744444 = SAIFI 0.288889

= 6.038462 hours customer - interruption

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ASUI =

161

∑U N ∑ N i

i

i

SAIDI 1.744444 = 8760 8760

=

8760 = 0.000199

ASAI = 1 − ASUI = 1 − 0.000199 = 0.999801

ASCI =

ENS = ∑ Ni

∑ L ( )U ∑N a i

i

(1000 )(1.2 ) + (700 )(1.7 ) + (400 )(2.9 )

=

200 + 150 + 100

i

= 7.888889 KWh customer - yr

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Distribution System Reliability

Source

2

1 a

3 b

4 c

d D

A C B Typical radial distribution system

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SYSTEM RELIABILITY DATA

Main

Component Length (km) λ (f/yr) r (hrs) 1 2 0.2 4 2 1 0.1 4 3 3 0.3 4 4 2 0.2 4 Lateral

a b c d

1 3 2 1

0.2 0.6 0.4 0.2

2 2 2 2

SYSTEM LOAD DATA Component No. of Customers Ave. Load Connected (KW) A B C D

1000 800 700 500

5000 4000 3000 2000

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RELIABILITY INDICES FOR THE SYSTEM

Main

Load pt. A Load pt. B Load pt. C Load pt. D U U U U Component λ r λ r λ r λ r (hrs/ (hrs/ (hrs/ (hrs/ failure (f/yr) (hrs) (f/yr) (hrs) (f/yr) (hrs) (f/yr) (hrs) yr) yr) yr) yr) 1 0.2 4 0.8 0.2 4 0.8 0.2 4 0.8 0.2 4 0.8 0.1

4

0.4

0.1

4

0.4

0.1

4

0.4

0.1

4

0.4

3 4

0.3 0.2

4 4

1.2 0.8

0.3 0.2

4 4

1.2 0.8

0.3 0.2

4 4

1.2 0.8

0.3 0.2

4 4

1.2 0.8

a b

0.2 0.6

2 2

0.4 1.2

0.2 0.6

2 2

0.4 1.2

0.2 0.6

2 2

0.4 1.2

0.2 0.6

2 2

0.4 1.2

c

0.4

2

0.8

0.4

2

0.8

0.4

2

0.8

0.4

2

0.8

d Total

0.2 2.2

2 2.73

0.4 6.0

0.2 2.2

2 2.73

0.4 6.0

0.2 2.2

2 2.73

0.4 6.0

0.2 2.2

2 2.73

0.4 6.0

Lateral

2

where : λtotal = ∑ λ ; U total = ∑ U ; rtotal = ∑ U U. P. National Engineering Center National Electrification Administration

∑λ Power System Engineering for Non-Engineers

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Power System Analysis 101

SAIFI =

165

∑ λ N = (2.2)(1000) + (2.2)(800) + (2.2)(700) + (2.2)(500 ) 1000 + 800 + 700 + 500 ∑N i

i

i

= 2.2 int customer − yr SAIDI =

∑U N = (6.0 )(1000) + (6.0 )(800) + (6.0 )(700) + (6.0 )(500) 1000 + 800 + 700 + 500 ∑N i

i

i

= 6.0 hours customer - yr CAIDI =

∑U N ∑λ N i

i

i

i

=

SAIDI 6.0 = SAIFI 2.2

= 2.727273 hours customer - interruption

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ASUI =

∑U N ∑ N i

i

8760 = 0.000685

166

i

=

SAIDI 6 .0 = 8760 8760

ASAI = 1 − ASUI = 1 − 0.000685 = 0.999315

ASCI =

∑L U ∑N ai

i

i

=

(5000 )(6.0 ) + (4000 )(6.0 ) + (3000 )(6.0 ) + (2000 )(6.0 )

1000 + 800 + 700 + 500 = 28.0 KWh customer - yr

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167

Distribution System Reliability 

Effect of lateral protection 2

1

Source

a

3

4

b

c

d D

A C B

Typical radial distribution system with lateral protections

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RELIABILITY INDICES WITH LATERAL PROTECTION Load pt. B Load pt. C Load pt. D U U U U Component λ r r r r λ λ λ (hrs/ (hrs/ (hrs/ (hrs/ failure (f/yr) (hrs) (f/yr) (hrs) (f/yr) (hrs) (f/yr) (hrs) yr) yr) yr) 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 Main

Load pt. A

Lateral

a b c d Total

0.2

2

0.4 0.6

1.0

3.6

3.6

1.4

2

3.14

1.2

4.4

0.4

2

0.8

1.2

3.33

4.0

where : λtotal = ∑ λ ; U total = ∑ U ; rtotal = ∑ U U. P. National Engineering Center National Electrification Administration

0.2 1.0

2 3.6

0.4 3.6

∑λ Power System Engineering for Non-Engineers

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Power System Analysis 101

SAIFI = ∑

λi Ni

∑N

169

(1.0)(1000) + (1.4)(800) + (1.2)(700) + (1.0)(500)

=

1000+ 800 + 700 + 500

i

= 1.153333 int customer− yr

SAIDI =

∑U N = (3.6 )(1000) + (4.4 )(800) + (4.0 )(700) + (3.6 )(500) 1000 + 800 + 700 + 500 ∑N i

i

i

= 3.906667 hours customer - yr CAIDI =

∑U N ∑λ N i

i

i

i

=

SAIDI 3.906667 = SAIFI 1.153333

= 3.387283 hours customer - interruption

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ASUI =

∑U N ∑ N i

i

8760 = 0.000446

170

i

=

SAIDI 3.906667 = 8760 8760

ASAI = 1 − ASUI = 1 − 0.000446 = 0.999554 ASCI =

∑L U ∑N ai

i

i

=

(5000 )(3.6 ) + (4000 )(4.4 ) + (3000 )(4.0 ) + (2000 )(3.6 )

1000 + 800 + 700 + 500 = 18.266667 KWh customer - yr

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Distribution System Reliability 

Effect of disconnects 2

1

Source

a

3

4

b

c

d D

A C B Typical radial distribution system reinforce with lateral protections and disconnects

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RELIABILITY INDICES WITH LATERAL PROTECTION AND DISCONNECTS Load pt. B Load pt. C Load pt. D U U U U Component λ r r r r λ λ λ (hrs/ (hrs/ (hrs/ (hrs/ failure (f/yr) (hrs) (f/yr) (hrs) (f/yr) (hrs) (f/yr) (hrs) yr) yr) yr) 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 Main

Load pt. A

Lateral

a b c d Total

0.2

2

0.4 0.6

1.0

1.5

1.5

1.4

2

1.2

1.89 2.65

0.4

2

0.8

1.2

2.75

3.3

where : λtotal = ∑ λ ; U total = ∑ U ; rtotal = ∑ U U. P. National Engineering Center National Electrification Administration

0.2 1.0

2 3.6

0.4 3.6

∑λ Power System Engineering for Non-Engineers

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Power System Analysis 101

SAIFI =

173

∑ λ N = (1.0 )(1000) + (1.4 )(800) + (1.2)(700) + (1.0 )(500) 1000 + 800 + 700 + 500 ∑N i

i

i

= 1.153333 int customer − yr SAIDI =

∑U N = (1.5)(1000) + (2.65)(800) + (3.3)(700) + (3.6 )(500) 1000 + 800 + 700 + 500 ∑N i

i

i

= 2.576667 hours customer - yr CAIDI =

∑U N ∑λ N i

i

i

i

=

SAIDI 2.576667 = SAIFI 1.153333

= 2.234105 hours customer - interruption

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ASUI =

∑U N ∑ N i

i

8760 = 0.000294

174

i

=

SAIDI 2.576667 = 8760 8760

ASAI = 1 − ASUI = 1 − 0.000294 = 0.999706 ASCI =

∑L U ∑N ai

i

i

=

(5000 )(1.5 ) + (4000 )(2.65 ) + (3000 )(3.3) + (2000 )(3.6 )

1000 + 800 + 700 + 500 = 11.733333 KWh customer - yr

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Effect of protection failures RELIABILITY INDICES IF THE FUSES OPERATE WITH PROBABILITY OF 0.9

Load pt. B Load pt. C Load pt. D U U U U Component λ r r r r λ λ λ (hrs/ (hrs/ (hrs/ (hrs/ failure (f/yr) (hrs) (f/yr) (hrs) (f/yr) (hrs) (f/yr) (hrs) yr) yr) yr) 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 Main

Load pt. A

Lateral

a b c d Total

0.2 2 0.06 0.5 0.04 0.5 0.02 0.5 1.12 1.39

0.4 0.03 0.02 0.01 1.56

0.02 0.5 0.6 2 0.04 0.5 0.02 0.5 1.48 1.82

0.01 0.02 0.5 1.2 0.06 0.5 0.02 0.4 2 0.01 0.02 0.5 2.69 1.3 2.58

where : λtotal = ∑ λ ; U total = ∑ U ; rtotal = ∑ U

0.01 0.03 0.8 0.01 3.35

0.02 0.5 0.06 0.5 0.04 0.5 0.2 2 1.12 3.27

0.01 0.03 0.02 0.4 3.66

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Effect of load transfer to alternative supply RELIABILITY INDICES WITH UNRESTRICTED LOAD TRANSFERS

Load pt. B Load pt. C Load pt. D U U U U Component λ r r r r λ λ λ (hrs/ (hrs/ (hrs/ (hrs/ failure (f/yr) (hrs) (f/yr) (hrs) (f/yr) (hrs) (f/yr) (hrs) yr) yr) yr) 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 Main

Load pt. A

Lateral

a b c d Total

0.2

2

0.4 0.6

2

1.2 0.4

1.0

1.5

1.5

1.4

1.39 1.95

1.2

where : λtotal = ∑ λ ; U total = ∑ U ; rtotal = ∑ U U. P. National Engineering Center National Electrification Administration

2

0.8

1.88 2.25

0.2 1.0

2 1.5

0.4 1.5

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Effect of load transfer to alternative supply RELIABILITY INDICES WITH RESTRICTED LOAD TRANSFERS

Load pt. B Load pt. C Load pt. D U U U U Component λ r r r r λ λ λ (hrs/ (hrs/ (hrs/ (hrs/ failure (f/yr) (hrs) (f/yr) (hrs) (f/yr) (hrs) (f/yr) (hrs) yr) yr) yr) 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 Section

Load pt. A

Distributor

a b c d Total

0.2

2

0.4 0.6

2

1.2 0.4

1.0

1.5

1.5

1.4

1.59 2.23

2

1.2

0.8 0.2 1.0

2.23 2.67

where : λtotal = ∑ λ ; U total = ∑ U ; rtotal = ∑ U

2 2.3

0.4 2.3

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Distribution System Reliability SUMMARY OF INDICES Load Point A λ (f/yr) r (hrs) U (hrs/yr) Load Point B λ (f/yr) r (hrs) U (hrs/yr) Load Point C λ (f/yr) r (hrs) U (hrs/yr) Load Point D λ (f/yr) r (hrs) U (hrs/yr)

Case 1

Case 2

Case 3

Case 4

Case 5

Case 6

2.2 2.73 6.0

1.0 3.6 3.6

1.0 1.5 1.5

1.12 1.39 1.56

1.0 1.5 1.5

1.0 1.5 1.5

2.2 2.73 6.0

1.4 3.14 4.4

1.4 1.89 2.65

1.48 1.82 2.69

1.4 1.39 1.95

1.4 1.59 2.23

2.2 2.73 6.0

1.2 3.33 4

1.2 2.75 3.3

1.3 2.58 3.35

1.2 1.88 2.25

1.2 2.23 2.67

2.2 2.73 6.0

1.0 3.6 3.6

1.0 3.6 3.6

1.12 3.27 3.66

1.0 1.5 1.5

1.0 2.34 2.34

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Distribution System Reliability SUMMARY OF INDICES (cont.) Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Sytem Indices 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 1. Base case. Case 2. As in Case 1, but with perfect fusing in the lateral distributors. 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. U. P. National Engineering Center National Electrification Administration

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Economics of Power System Reliability Supply Cost • Investment Cost • Operation and Maintenance Cost • Fuel Cost IC + O&M + FC Annual Supply Cost (ASC) = Annual kWh Generation

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Supply Cost Luzon Grid Supply Cost* LOLP (days/yr)

Frequency (per year)

Duration (Hours)

Supply Cost (Php/kWh)

12.26

70

2.11

0.90

6.25

38

2.00

0.94

1.88

13

1.73

1.01

0.94

7

1.61

1.03

0.45

4

1.50

1.06

0.21

2

1.38

1.09

0.08

0.73

1.31

1.11

0.04

0.31

1.30

1.14

Source: del Mundo (1991) Power System Engineering for Non-Engineers

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Supply Cost

Luzon Grid Supply Cost Source: del Mundo (1991) U. P. National Engineering Center National Electrification Administration

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Outage Cost Impact of Power Interruptions
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

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Outage Cost 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 U. P. National Engineering Center National Electrification Administration

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Outage Cost 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

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Outage Cost Outage Cost to Industrial Sector in Luzon (0.0086 + 0.0023D)F + 0.1730 Pesos/kWh Where, F – Frequency of Interruptions D – Average Duration of Interruptions

Losses of MERALCO Industrial Customers in 1989 Energy Sales: 3.781 billion kWh Outage Cost: Php 0.3544/kWh Total Losses: Php 1.34 billion Source: del Mundo (1991) U. P. National Engineering Center National Electrification Administration

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Outage Cost Luzon Grid Outage Cost* LOLP (days/yr)

Frequency (per year)

Duration (Hours)

Outage Cost (Php/kWh)

12.26

70

2.11

1.12

6.25

38

2.00

0.68

1.88

13

1.73

0.34

0.94

7

1.61

0.26

0.45

4

1.50

0.22

0.21

2

1.38

0.20

0.08

0.73

1.31

0.18

0.04

0.31

1.30

0.18

Source: del Mundo (1991) Power System Engineering for Non-Engineers

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Outage Cost

Luzon Grid Outage Cost Source: del Mundo (1991) U. P. National Engineering Center National Electrification Administration

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Total Cost Luzon Grid Total Cost

ATC = ASC + AOC

LOLP (days/yr)

Supply Cost (Php/kWh)

Outage Cost (Php/kWh)

Total Cost (Php/kWh)

12.26

0.90

2.11

2.02

6.25

0.94

2.00

1.62

1.88

1.01

1.73

1.35

0.94

1.03

1.61

1.29

0.45

1.06

1.50

1.28

0.21

1.09

1.38

1.29

0.08

1.11

1.31

1.29

0.04

1.14

1.30

1.32

Source: del Mundo (1991) U. P. National Engineering Center National Electrification Administration

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Optimal Reliability Level

Luzon Grid Total Cost Source: del Mundo (1991) U. P. National Engineering Center National Electrification Administration

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