CPD2 B9 Notes8A - Economic Sizing of Dx Lines.ppt 1x1

NATIONAL ELECTRIFICATION ADMINISTRATION U. P. NATIONAL ENGINEERING CENTER

Distribution System Planning and Distribution Utility CAPEX Planning

Competency Training and Certification Program in Electric Power System Engineering

Economic Sizing of Distribution Lines

2

Competency Training & Certification Program in Electric Power System Engineering

U. P. National Engineering Center National Electrification Administration


Introduction

HOW would you solve the ff. scenario?

A 100-kW load at 0.9 lag PF is 5 km away from the substation. A dedicated primary feeder is to be constructed to serve this load.

What size of wire should be specified?

What size of distribution transformer?

3




Power Distribution Function

Distribution Function:

Move power from point A to point B.

Consequences Power is delivered to end-users. Voltage drop occurs (if PF is lag). Initial costs are incurred to set up the system. Continuing costs (O&M, etc.) are incurred. Electrical losses occur. Losses costs are incurred.

4




Basic Ideas

Lines and transformers are the basic elements of a distribution system.

Voltage is both a performance criteria and a resource to be used well. Voltage drop should not be minimized to zero; voltage should be

managed to be within prescribed criteria.

In a well-designed distribution system, the sizes of lines and transformer will be proportional to loading.

Economic sizing of lines and transformers must account for all costs: Initial costs and the continuing costs over its lifetime

5





1. Load Reach

2. Line Types, Performance, and Economy

3. Distribution Line Cost Function

4. Economic Loading Ranges of Distribution Lines

5. Economic Line Sizing

OUTLINE

6




Load Reach

Definition of Load Reach

Thermal, Emergency, & Economic Load Reach

Effects of Voltage on Load Reach

Load Reach of a Conductor Set

Load Reach as a Planning Criteria

Load Reach Calculations

7




Load S/S

Load Reach

[ zabc ]

[VABC] = 1.0 p.u. [Vabc] 0.9 p.u.

If [zabc] is the impedance per km of line, how far away from the source can the load in kW be such that the load voltage is within limits?

Length = ?

8




Load Reach

Load Reach: the source-to-load distance that a feeder system can move power before encountering the applicable voltage drop limit Measured in units of distance (km or mi). Measured as the feeder runs

Straight point distances may have to be divided by 2.

Load Reach = % VD criteria% VD

km (at specified loading)

9





Thermal Load Reach The load reach if the feeder system is loaded at its

thermal limits (i.e., at its ampacity limits).


km (at thermalload)

10





Emergency Load Reach The load reach if the feeder system is loaded at the

emergency loading, or if the voltage drop criteria is relaxed due to the emergency condition.

Useful if we differentiate the voltage drop criteria during normal and emergency conditions.

Load Reach = % VD criteria (during emergency)% VD

km (at emergency load)

11





Economic Load Reach The load reach if the feeder system is loaded at the

maximum load within their economic loading range.


km (at maximum economic load)

12




Effect of Voltage on Load Reach

Load Reach is affected by Distribution Voltage.

Doubling the voltage doubles the load reach. Load current is halved, which effectively halves the voltage

drop (assuming similar impedance), and doubles the distance before the voltage drop limit is reached.

High voltage, however, has higher fixed costs. In terms of pole, crossarm, insulators, switchgears, etc.

Use the appropriate distribution voltage. In some cases, the voltage has already been chosen.

13





Both the economic and thermal load reach in a conductor set tend to be a constant.

Willis, 2004. Willis, 2004.

14





Both the economic and thermal load reach in a conductor set tend to be a constant.

Exception 1: Largest conductor Used for backbone segments and feeder getaways. Should be able to carry maximum possible load.

Possible Exception 2: Smallest conductor Used for the last-mile connection to customers. Applicable at the secondary distribution level or for

primary distribution with light load density.

15





Load reach suitable for a planning criteria. A single number with a single unit (distance).

Substation spacing cannot be more than twice the conductor set load reach. If load reach is not fully used, DU pays more but gets

less (unused load reach).

16





Under contingency conditions, some paths may have to be reinforced. Use bigger conductor for backbone segments and contingency

paths (feeder tie-line paths). From reliability viewpoint and not load reach, voltage, or losses.

Willis, 2004.

Voltage profile of a feeder for pathways from substation to points A and B. Voltage profile to A shows gradually decreasing voltage drop per mile due to reinforced trunk (oversized over normal need). Voltage profile to B shows constant voltage drop per mile.

17





Voltage drop is a measure of performance. Voltage criteria at customer connection point: nominal

system voltage 0.10 pu.

Voltage drop is a resource to be used well. Voltage drop allows current (and power) to flow. Expensive to minimize voltage drop and still be able to

deliver power. Once the voltage drop is within limits, other factors

(reliability or technical losses costs) should be considered to justify decreasing voltage drop further.

18





VDaVDbVDc

=

zaa zab zaczab zbb zbczac zbc zcc

IaIbIc

VDmaxper km = Max

zaa Ia + zabIb + zac Ic ,

zabIa + zbbIb + zbc Ic ,

zac Ia + zbc Ib + zcc Ic

z in / km

19





VDmaxper km = I Max

zaa 10 + zab 1120 + zac 1 +120 ,

zab 10 + zbb 1120 + zbc 1 +120 ,

zac 10 + zbc 1120 + zcc 1 +120

If currents are balanced:

Load Reach = %VD criteria

VDmaxper km

20





For thermal load reach, use I = ampacity.

For economic load reach, use I = maximum economic load of the line.

For voltage drop criteria, use 0.10 pu total for primary and secondary lines.

Example 1: 0.1 pu drop for the primary, but need to manage the DT taps for secondary

Example 2: 0.075 pu drop for the primary and 0.025 pu drop for the secondary

21




Line Types, Performance, & Economy

Physical Suitability

Capacity

Voltage Line R/X Ratio and Conductor Size Managing Voltage Drop

Reliability

Costs

22




Line Performance & Economy

Five Attributes of Line Types to be Optimized:


Capacity

Voltage Drop

Reliability

Cost

23





Basic Line Type Options Construction: Overhead or Underground Pole Type: Wood, Concrete, or Steel Conductor Type: Copper, ACSR, AAC, or AAAC Number of Phases: One-, Two- (Vee-), or Three-Phase

Vee-phase lines use same structure as three-phase lines Should be treated as Engineering Design decision

24





Construction Type OH: low cost, low reliability, exposure to elements UG: high cost, high reliability, aesthetics

Some areas require UG construction for distribution lines.

Pole Type (for OH Construction) Wood pole: low cost, low strength Concrete pole: medium cost, medium strength Steel pole: high cost, high strength

Consider for areas with high rate of vehicle accidents

25





Conductor Type ACSR for strength and structural flexibility

Less prone to parting and falling during storms

AAC (or AAAC) for coastal areas ACSR is bimetallic (easily corrodes) while AAC is monometallic (no bimetallic corrosion)

Number of Phases One-phase: nearer to (single-phase) loads Three-phase: backbone

26





Engineering Design: While there are a variety of designs to choose for a variety of situations, this is of little interest to Planning.

Planners are more interested in Line Capacity and Cost.

THESE: What size and at what price?

NOT THESE: What configuration (C1, C2, and so on)? How many cross-arms?

27




Capacity

Thermal Capacity Limits Refers to line ampacities Affected by ambient temperatures Normal and contingency/emergency limits

28




Voltage Drop

Should be within prescribed limits PDC: nominal voltage 0.10 p.u. at the customer

connection point Should eventually target 0.05 p.u. VD limit so that

0.10 p.u VD becomes the emergency voltage limit criteria

DT taps affect the voltage drop criteria.

29




Voltage Drop

Line model Carsons equations or approximations of these

Zcc Zcb Zca Zbc Zbb Zba Zac Zab Zaa

Ycc Ycb Yca Ybc Ybb Yba Yac Yab Yaa

Ycc Ycb Yca Ybc Yb

b Yba Yac Ya

b Yaa

A B C

a b c

Unbalanced Three-Phase

System

30




Line R/X Ratio

R and X are proportional to distance. We will look at R and X in ohms/km (ohms/mile).

R and X are a function of conductor size and spacing. Conductor size has a dominant effect on R. Doubling

the size halves R. Conductor spacing has a dominant effect on X. In

general, increasing spacing increases X.

31




Line R/X Ratio

Size Ampacity R (/mi) X (/mi) Z (/mi) R/X

#2 AWG 180 A 1.690 0.665 1.82 2.54

4/0 AWG 340 A 0.592 0.581 0.83 1.02

477 MCM 670 A 0.216 0.430 0.48 0.50

1510 MCM 1340 A 0.072 0.362 0.37 0.20

Analysis of R/X ratios at 12.47 kV: Each row roughly doubles the ampacity of the one above it. R roughly decreases by 2/3 each time. However, X decreases only by a small amount (13% to 26%) each time. Z decreases to half each time, except for the large conductor, where Z decreases only 13%.

32




Line R/X Ratio

X matters on big wires. Primary distribution and above.

R matters on small wires. Secondary distribution and below.

Load power factor is also important. Poor PF makes power flow more sensitive to line

impedance, worsening voltage drop for the same kW load.

33




Line R/X Ratio

There is a limit to when increasing the conductor size will result in a justifiable improvement in voltage drop. In the example, at 1510 MCM, increasing size further

results in very little decrease in impedance because reactance becomes dominant.

In such cases, increase in distribution voltage (using transformers) should be considered to decrease the load current.

34




Managing Voltage Drop

Load balancing

Transformer tap setting

Reconfiguration

Closer phase spacing Usually infeasible or expensive

Shunt and series capacitors

Power electronics

Distributed generation or energy storage

35




Reconfiguration

A simple example of network reconfiguration: instead of increasing the trunk size, reconfiguration may be cheaper (although here, ability to accommodate load growth may have been sacrificed in some areas).

36




Reliability

UG lines are more reliable. Lower exposure to elements and external factors.

ACSR for strength and flexibility. Less prone to parting and falling during storms.

AAC for coastal areas Less corrosion due to being monometallic.

Steel poles Consider for areas with high rate of vehicular accidents.

37




Costs

All costs must be considered.

Initial Acquisition Costs

Installation & Construction Costs

R-O-W, O&M, and Taxes Costs

Electrical Losses Costs

38




Distribution Line Cost Function

Definition of Terms

Recap of Economic Evaluation with Interest, Inflation (Escalation) and Load Growth Rates

Fixed Costs of Lines

Variable Costs of Lines (Electrical Losses Cost)

Total Cost Function of Lines

39




Definition of Terms

Interest Rate (%) The average annual interest rate expected by the DU over the

economic life of the distribution line

Demand Charge (PhP/kW) The initial demand charge paid by the DU for G&T

Energy charge (PhP/kWh) The initial energy charge paid by the DU for G&T

Escalation rates (%) (also, inflation rates) The average annual rate of increase in charges expected by the

DU over the economic life of the distribution line May differ for the demand, energy, and other charges (e.g., O&M)

40




Definition of Terms

Peak Demand (kVA) The expected peak load of the line in its first year. If initial expected peak load is in kW, a reasonable

value of power factor should be assumed.

Load Growth Rate (%) The average rate of load growth over the economic life

of the distribution line

41




Definition of Terms

Loss Factor The ratio of average annual load loss to the load loss

that occurs at the time of peak load:

May be computed from the load factor System simulations are required to determine k

LSF = energy loss due to load losses

peak loss due to load losses

LSF = k LDF + 1 k( ) LDF 2

42




Definition of Terms

Peak Loss Responsibility Factor Accounts for the difference in times when system peak

load and peak load on the distribution line occur:

RF = line load at time of system peak

line peak load

2

43




Definition of Terms

Initial Cost (PhP) Includes acquisition cost, transportation cost, taxes and other

costs to prepare the distribution line for service.

Annual O&M Cost (PhP) The annual fixed cost to operate and maintain the distribution

lines and poles, including taxes and excluding the costs of losses. May include taxes (in this case, O&M&T).

Economic Life (years) The expected useful life of the distribution line. See ERC Resolution No. 43 series of 2006, Annex C for regulators

prescribed values (may differ for distribution lines and poles)

44




Recap of Economic Evaluation

What is the PW of an annuity paid over n periods, considering an interest rate i?

PWF = 1

1+ i( )kk=1n

= 1i 11

1+ i( )n

=

1+ i( )n 1i 1+ i( )n

Note: i > 0

45





What is the PW of an annuity paid over n periods, considering an interest rate i and an escalation rate a?

PWF = 1+ a1+ i

k

k=1

n

= 1i a

11+ a1+ i

n

Note: (1+i) > (1+a)

46





What is the PW of an annuity paid over n periods, considering interest rate i, escalation rate a, and load growth rate g?

PWF =1+ a( ) 1+ g( )2

1+ i( )

k

k=1

n

=1

1+ a( )n 1+ g( )2n1+ i( )n

1+ i( ) 1+ a( ) 1+ g( )2

Note: (1+i) > (1+a)(1+g)2

47





Present Worth Factor (PWF) Gives the present worth equivalent of paying annuity

(of PhP1.00) over n periods, given interest rate i, inflation rate a and load growth rate g.

General form is:

PWF =

11+ a( )n 1+ g( )2n

1+ i( )n

1+ i( ) 1+ a( ) 1+ g( )2

48




Fixed Costs of Lines

Initial Acquisition Costs Costs of poles, wires, peripherals

Installation Costs Costs of construction, right-of-way, labor

Continuing Costs PW of the Costs of Annual O&M (and taxes)

C fixed = Cacq + Cinst( ) + CO& M PWFO& M( )

49




Variable Costs of Lines

Electrical Losses Cost A function of line resistance, load, power factor, loss

factor, and peak loss responsibility factor Requires present worth analysis. In general, may be composed of its demand charge and

energy charge components.

50





Line and load is...

Power is...

Current is...

Current:

Three-phase

S = S3

where n is the no. of phases

Two-phase

S = S2

One-phase

S = S1

I = S

3 VLN

I = S

2 VLN

I = S

1VLN

I = S

n VLN

51




Reff

Its easy to see that for a one-phase line (a):

reff = raa 1 r1

We will show that for a two-phase line (a-b):

reff = (raa + rbb rab) 2 r1

And for a three-phase line (a-b-c):

reff = (raa + rbb + rcc rab rbc rca) 3 r1

52




For a two-phase line:

Sabloss = Iab

T

Vabdrop = Iab

T

zab Iab

= Ia* Ib

*

zaa zabzab zbb

IaIb

= Ia* Ib

*

zaa Ia + zabIb( )zabIa + zbbIb( )

= Ia* zaa Ia + zabIb( ) + Ib* zabIa + zbbIb( )

53




For a two-phase line:

Sabcloss = Ia

* zaa Ia + zabIb( ) + Ib* zabIa + zbbIb( )= Ia

2zaa + Ia

*Ibzab + Ia Ib*zab + Ib

2zbb

Sabcloss = I

2zaa + 1120 +1120( ) I 2 zab + I 2 zbb

= Ia2

zaa + zbb zab( )

If loads are balanced: Ia = I 0 Ib = I 120

54




Pabcloss = I

2raa + rbb rab( )

Qabcloss = I

2xaa + xbb xab( )

Complex power loss

Pabcloss = I

22 rs rm I

22 r1( )

where rs = resistances along the diagonalsrm = resistances on the off-diagonalsr1 = positive-sequence resistance

If line impedance is balanced:

(approximately)

55




For a three-phase line:

Sabcloss = Iabc

T

Vabcdrop = Iabc

T

zabc Iabc

= Ia* Ib

* Ic*

zaa zab zaczab zbb zbczac zbc zcc

IaIbIc

= Ia* Ib

* Ic*

zaa Ia + zabIb + zac Ic( )zabIa + zbbIb + zbc Ic( )zac Ia + zbc Ib + zcc Ic( )

56




For a three-phase line:

Sabcloss = Ia

* Ib* Ic

*

zaa Ia + zabIb + zac Ic( )zabIa + zbbIb + zbc Ic( )zac Ia + zbc Ib + zcc Ic( )

= Ia* zaa Ia + zabIb + zac Ic( ) + Ib* zabIa + zbbIb + zbc Ic( )

+ Ic* zac Ia + zbc Ib + zcc Ic( )

= Ia2

zaa + Ib2

zbb + Ic2

zcc + Ia Ib* + Ia

*Ib( ) zab+ IbIc

* + Ib*Ic( ) zbc + Ia Ic* + Ia*Ic( ) zac

57




If currents are balanced:

Ia Ib

* + Ia*Ib( ) = IbIc* + Ib*Ic( ) = Ia Ic* + Ia*Ic( ) = I 2

Ia = I 0 Ib = I 120 Ic = I +120

Sabcloss = Ia

2zaa + Ib

2zbb + Ic

2zcc + Ia Ib

* + Ia*Ib( ) zab

+ IbIc* + Ib

*Ic( ) zbc + Ia Ic* + Ia*Ic( ) zac= I

2zaa + zbb + zcc zab zbc zac( )

58




Complex power loss

Pabcloss = I

2raa + rbb + rcc rab rbc rac( )

Qabcloss = I

2xaa + xbb + xcc xab xbc xac( )

If line impedance is balanced:

Pabcloss = I

23 rs rm( ) = I

23 r1( )

where rs = resistances along the diagonalsrm = resistances on the off-diagonalsr1 = positive-sequence resistance

59




Peak Losses

I2R losses during peak condition:

Plossespeak =

Speakn VLN

2

reff( ) = Speak2

n2 VLN2 reff

where reff = effective line resistance per km( ) reff = n rs rm( ) = n r1

Plosses

peak =Speak

2

n VLN2 r1 =

PpeakPF

2

r1

n VLN2

60




Energy Charge Component

Cenergy =

8760 hrs yr1000 W kW

kWpeakPF

2

r1

n kVLN2 LSF CEC PWFEC

where Cenergy = energy charge component (PhP/km) CEC = energy charge (PhP/kWh) LSF = loss factor PWFEC = present worth factor kWpeak = peak demand of the line in its first year (kW) PF = power factor of the load r1 = effective resistance of the line (ohms/km) n = number of phases present kVLN = line-to-neutral voltage (kV)

61




Demand Charge Component

Cdemand =

11000

kWW

kWpeakPF

2

r1

n kVLN2 RF CDC PWFDC

where Cdemand = demand charge component (PhP/km) CDC = demand charge (PhP/kW) RF = peak loss responsibility factor PWFDC = present worth factor for demand charges kWpeak = peak demand of the line in its first year (kW) PF = power factor of the load r1 = effective resistance of the line (ohms/km) n = number of phases present kVLN = line-to-neutral voltage (kV)

62





Cvariable = Cenergy + Cdemand

Cvariable =1

1000kW

W kWpeakPF

2

r1

n kVLN2

8760 hrs yr LSF CEC PWFEC( ) + RF CDC PWFDC( ) where Cvariable = variable cost in PhP/km

63





Putting it all together, cost in PhP/km is:

Ctotal = C fixed + Cvariable

Ctotal = Cacq + Cinst( ) + CO& M PWFO& M( ) +1

1000kW

W kWpeakPF

2

r1

n kVLN2

8760 hrs yr LSF CEC PWFEC( ) + RF CDC PWFDC( )

64





Putting it all together, cost in PhP/km is:

k1 = Cacq + Cinst( ) + CO& M PWFO& M( )k2 =

11000

kWW

1PF

2

r1

n kVLN2

8760 hrs yr LSF CEC PWFEC( ) + RF CDC PWFDC( )

Ctotal = k1 + k2 kWpeak

2

65





The cost function for a three-phase 336-MCM line. Fixed cost at 0 MW Ends at thermal load

Willis, 2004.

66




Economic Loading Range of Distribution Lines

Economic Loading Ranges of Distribution Lines Economic Line-Sizing Guidelines Redundant Line Types

Linearizing the Cost Functions of Lines

Economic Analysis of Uprating Conductors

Effect of Load Growth on Economic Loading Range

Effect of Shorter Evaluation Period on Economic Loading Range

67




Economic Loading Range

If the cost functions of different lines are plotted on the one graph, the economic loading range of each line are easily identified.

Willis, 2004.

68





Economic Line-Sizing Guidelines

Willis, 2004. Willis, 2004.

69





Redundant Line Type The darker curve represents

a line type that will never be the economical choice.

Remove the line type from inventory no economic benefit in having it.

Willis, 2004.

70





When to use a single-phase line? vee-phase line? three-phase line?

What neutral wire size to use?

Willis, 2004.

71




Linearized Cost of Lines

Ctotal = C f + Cv D( )

where C f = fixed cost, Php/km

Cv = variable cost coeff.,

Php/ km kW( )D = demand in kW = length in km

Cv =

YX

Y

X C f

72




Uprating Conductors

Willis, 2004.

When to uprate conductors? Fixed cost of existing conductors

decrease. Sunk costs Only continuing costs left May have increased O&M costs

Fixed cost of uprate increase. Include changeout costs

Variable costs stay the same. Cost Functions will have the same shape.

73




Uprating Conductors

The plot below shows that the two curves do not intersect. It would be better to leave the

smaller conductor even if the losses costs are very high.

Planners often have to live with their mistakes.

Willis, 2004.

74




Uprating Conductors

The most economical upgrade is not always the next larger size. It may be two or even three sizes bigger.

Willis, 2004.

75




Effect of Load Growth

0% load growth 5.1 MW

0.5% load growth over 30 years 4.7 MW

0.5% load growth over 30 years; +20% load at year 4

4.0 MW

Higher load growth favors bigger conductors.

Lower load growth and conservation favors smaller conductors.

Same fixed costs (same y-intercepts).

Willis, 2004.

76




Effect of Shorter Evaluation Period Shorter evaluation periods favor smaller

conductors, but not as dramatic as expected. Period drops by 67%, but the PW of losses drops by only 32%. The PW of losses cost are mostly in the first decade.

30-year evaluation period 5.1 MW

10-year evaluation period 5.7 MW

Willis, 2004.

77




Economic Line Sizing

Goals of Economic Line-Sizing Guidelines

Adhering to the Economic Line-Sizing Guidelines

Key Aspects of Economic Line Sizing

Economic Line-Sizing Methodology Required Data Procedure

78





GOALS: A good conductor set achieves the ff.:

Good economy of use Optimal current flow capability

Satisfactory load reach Adequate voltage quality Also affects substation and subtransmission planning

Ease of planning Few planning situations require extensive studies and

deviations from standard designs

79





EFFECT: When the guidelines are followed:

No voltage problem within feeder load reach. Usually no need for capacitors, AVRs, etc.

All conductors are economically sized. Least-cost network

Willis, 2004.

Both the technical and economic goals of planning are achieved.

80





Willis, 2004.

81





Exceptions to the Guidelines

Room for (short-term) growth. Use bigger conductors in anticipation of short-term

growth, with good tradeoff in terms of losses.

Contingency capacity From reliability viewpoint, not load reach, voltage, or

technical losses (although these benefit)

82





Re-examine periodically. After every 5 years, or when significant changes in

construction practices, costs, or planning methods occur.

Willis, 2004.

83





In order of importance:

1. Use three to six conductors in the set. N < 3: not enough choices for different loading conditions N > 6: too many to maintain in inventory N should include the biggest conductor

2. Ensure sufficient economic load reach.

3. Minimize cost per km.

84





4. Include single-phase (and vee-phase) lines For low cost at low load without increasing inventory

5. Thermal capability far beyond the linear range for the biggest available conductor To handle very short but very high-load segments (e.g.,

outgoing feeders from a substation)

6. Focus and compromise: In favor of capability for large conductors In favor of economy for small conductors

85




Economic Line-Sizing Methodology

Required Data Power factor Loss factor (or load factor and A & B coefficients) Interest rates Escalation rates Costs (acquisition, construction, O&M, & taxes) Period of evaluation (usually 30 years) Annual load growth rates (esp. if high) Line data for line modeling

86




Economic Line-Sizing Methodology Procedure

1. Line Modeling

2. Determine voltage drops and lifetime losses of distribution lines.

3. Compute present worth multipliers.

4. Compute Fixed Costs.

5. Compute Variable (Electrical Losses) Costs from no-load condition to thermal load.

6. Compute Total Cost Functions.

7. Plot cost curves.

8. Determine economic loading ranges and load reach.

87




Example Data Value Interest Rate 12%

Escalation Rate 3%

Load Growth Rate 1.5%

O&M & Taxes 5%

Power Factor 0.90

Loss Factor 0.40

Peak Loss Responsibility Factor

0.55

Energy Charge 6.00 PhP/kWh

Demand Charge 4.00 PhP/kW

Parameters for the DU and the load

88




Example

Size (3-Ph) Raa Xaa Rbb Xbb Rcc Xcc Rab Xab Rac Xac Rbc Xbc

4 1.74 0.92 1.74 0.92 1.74 0.92 0.14 0.41 0.14 0.36 0.14 0.41 2 1.19 0.89 1.20 0.88 1.19 0.89 0.14 0.37 0.14 0.32 0.14 0.37

1/0 0.82 0.84 0.83 0.83 0.82 0.84 0.13 0.33 0.13 0.28 0.13 0.33 2/0 0.67 0.81 0.68 0.81 0.67 0.81 0.12 0.31 0.12 0.26 0.12 0.31 3/0 0.55 0.79 0.56 0.78 0.55 0.79 0.11 0.30 0.10 0.25 0.11 0.30 4/0 0.46 0.77 0.46 0.77 0.46 0.77 0.09 0.29 0.09 0.24 0.09 0.29

336.4 0.26 0.63 0.26 0.62 0.26 0.63 0.07 0.25 0.07 0.20 0.07 0.25

Size (1-Ph) Raa Xaa

4 1.75 0.91 2 1.21 0.87

1/0 0.84 0.82 2/0 0.69 0.78 3/0 0.57 0.75 4/0 0.47 0.74

336.4 0.26 0.59

Series impedance [Z] matrices for single- and three-phase distribution lines

89




Size Ampacity (Amperes) 4 170 2 220

1/0 310 2/0 360 3/0 420 4/0 480

336.4 670

Ampacities of distribution wire sizes

Example

90




Example

Required data for costing (PhP/km per size of distribution line) Phase conductor

Size, number, and cost (PhP/km) Neutral conductor

Size, number, and cost (PhP/km) Cost of Materials

Cost of Pole (dependent on conductor size, PhP/pole) Cost of Assembly

Labor and Overhead Costs Contingency Costs O&M Costs Note: Account for all costs associated with distribution lines.

91




References

H.L. Willis, Power Distribution Planning Reference Book, 2nd edition, Revised and Expanded, Marcel-Dekker 2004.

S.M. Leppert & A.D. Allen, Conductor life cycle cost analysis, paper presented at the 39th Annual Rural Electric Power Conference, IEEE 1995.

S. Mandal & A. Pahwa, Optimal selection of conductors for distribution feeders, IEEE Trans. on Power Systems, Vol. 17, No. 1, February 2002.

92




Date post:	07-Oct-2015
Category:	Documents
Upload:	sugar-ray
View:	14 times
Download:	0 times

CPD2 B9 Notes8A - Economic Sizing of Dx Lines.ppt 1x1

Documents