EE 521 PROJECT DESIGN CASE 2

PROF.M.J.BESHIR
EE521
PROJECT REPORT 2
POWER SYSTEM ANALYSIS AND DESIGN (CASE_2)

AKSHAY ANAND NERURKAR 8759392138
1
TABLE OF CONTENT:
1. Introduction and Background……………………………………………………1
2. Purposeand Goal of the Project…………………………………………………1
3. Design Assumptions……………………………………………………………..2
4. Procedure
A.STEP 1, 2(BASE CASE)…………………………………………5, 11
B.STEP 3 (MAIN CASE)………………………………………..….14-31
5. Study Outcome……………………………………………………………….32
6. Recommendations …………………………………………………………….32
7. Appendix…………………………………………………………………….33

2
INTRODUCTION
After more than 70 years of supplying downtown Metropolis with electricity it is time to
retire the SANDERS69 power plant. The city’s downtown revitalization plan, coupled with a
desire for more green space, make it impossible to build new generation in the downtown
area. At the same time, a blooming local economy means that the city- wide electric
demand is still as high as ever, so this impending plant retirement is going to have some
adverse impact on the electric grid.
PURPOSE AND GOAL OF THE PROJECT
As a planning engineer for the local utility, Metropolis Light and Power (MLP), my job is to
make recommendations on the construction of new transmission lines and transformers to
ensure that the transmission system in MLP system is adequate for any base case or first
contingency loading situation.
It is my job to iteratively determine the least expensive system additions so that the base
case and all the contingencies result in secure operation points. The parameters of the new
transmission line(s) will be derived using the tower configuration and conductor types
available. The total cost of an addition is defined as the construction costs minus the
savings associated with any decrease in system losses over the next five years.
I will be using the PowerWorld Simulator to conduct my studies. Any data assumed or
referenced will be listed in the Appendix for reference. I will use the PowerWorld Design
Case 2 for the purpose of the study. I have been asked to submit a detailed report including
the justification of the final recommendation.

3
DESIGN ASSUMPTIONS
The following assumptions are made for the purpose of simplifying the analysis:
1. I will only consider the base case loading level given in design Case1. In a real design,
typically a number of different operating points/loading levels must be considered.
2. I will consider the generator outputs as fixed values; any changes in the losses are
always picked up by the system slack.
3. I will not modify the status of the capacitors or the transformer taps.
4. The total system losses will be assumed to remain constant over the five-year period. I
will only consider the impact that new design has on the base case losses. The price for
losses is fixed at $50/MWh.
DESIGN CASE2: AVAILABLE NEW RIGHT-OF-WAYS
Table1:AvailableNewRight-of-Ways
Right-of-Ways/Substation Right-of-Way Mileage (km) Right-of-Way Mileage
(miles)
BOB to SCOT 13.68 8.5
BOB to WOLEN 7.72 4.80
FERNA to RAY 9.66 6.002
LYNN to SCOT 19.31 11.999
LYNN to WOLEN 24.14 14.999
SANDER to SCOTT 9.66 6.071
SLACK to WOLEN 18.51 11.502
JO to SCOT 24.14 14.999

4
SYSTEM REQUIREMENTS TO BE FULFILLED DURING THE PROJECT INCLUDE:
1. All the bus voltages should be in the range of: 0.95p.u and 1.10p.u.
2. All the line flows must be below 100% of their limit values.
3. The recommended system design should have zero violations.
4. The recommended system design should be the most economical choice.
WORK CONDUCTED ON DESIGN CASE_2
Figure 1: Base case circuit showing the disconnected SANDERS69 power
plant

5
STEPS EXECUTED
STEP 1: Determining the initial operating point using the base case
Aim: To identify the base case operating point of the system to study the impact of the
disconnected power plant at bus SANDERS69.
Procedure:
1. Load design case 2 in the PowerWorld simulator
2. Initial case has the power plant at SANDERS69 disconnected from the grid
3. Perform the initial power flow solution and determine the system operating point
4. Check whether all bus and line voltages are within the limit of 0.95 and 1.10 per unit
5. Check whether all the line MVA flows are less than 100 % of the limit values
The figure below shows the net system losses to be 13.54 MW, for the base case when
the power plant at SANDERS69 is disconnected from the grid.
Figure 2: Figure showing the base case system loss with the
disconnected
SANDERS69 power plant (GENERATOR)

6
Table 2: Power system bus voltage data
Number Name
Area
Name Monitor
Limit
Group PU Volt Volt (kV)
Limit
Low PU
Volt
Limit
High PU
Volt
Contingency
Limit Low PU
Volt
Contingency
Limit High
PU Volt
28 JO345 1 YES Default 1.03 355.35 0.95 1.1 0.95 1.1
31 SLACK345 1 YES Default 1.03 355.35 0.95 1.1 0.95 1.1
29 JO138 1 YES Default 1.02161 141.258 0.95 1.1 0.95 1.1
35 SLACK138 1 YES Default 1.02151 141.245 0.95 1.1 0.95 1.1
38 RAY345 1 YES Default 1.02194 352.913 0.95 1.1 0.95 1.1
1 TIM345 1 YES Default 1.02164 352.81 0.95 1.1 0.95 1.1
56 LYNN138 1 YES Default 1.02131 141.079 0.95 1.1 0.95 1.1
12 TIM69 1 YES Default 1.01191 70.511 0.95 1.1 0.95 1.1
10 RAY69 1 YES Default 1.01101 70.449 0.95 1.1 0.95 1.1
44 LAUF69 1 YES Default 1.02 70.38 0.95 1.1 0.95 1.1
50 DAVIS69 1 YES Default 1.02 70.38 0.95 1.1 0.95 1.1
17 PAI69 1 YES Default 1.06593 69.892 0.95 1.1 0.95 1.1
19 GROSS69 1 YES Default 1.07586 69.887 0.95 1.1 0.95 1.1
33 NICOL69 1 YES Default 1.01255 69.866 0.95 1.1 0.95 1.1
5 HOMER69 1 YES Default 1.0044 69.728 0.95 1.1 0.95 1.1
39 RAY138 1 YES Default 1.0048 139.393 0.95 1.1 0.95 1.1
18 HANNAH69 1 YES Default 1.009 69.621 0.95 1.1 0.95 1.1
14 WEBER69 1 YES Default 1.00883 69.609 0.95 1.1 0.95 1.1
32 NICOL138 1 YES Default 1.00873 139.204 0.95 1.1 0.95 1.1
20 SCOT69 1 YES Default 1.00821 69.566 0.95 1.1 0.95 1.1
37 AMANDA69 1 YES Default 1.00762 69.526 0.95 1.1 0.95 1.1
30 CAROL138 1 YES Default 1.00586 138.808 0.95 1.1 0.95 1.1
34 PATTEN69 1 YES Default 1.00472 69.326 0.95 1.1 0.95 1.1
13 FERNA69 1 YES Default 1.0035 69.242 0.95 1.1 0.95 1.1

7
41 LAUF138 1 YES Default 1.0009 138.125 0.95 1.1 0.95 1.1
48 BOB69 1 YES Default 1 69 0.95 1.1 0.95 1.1
40 TIM138 1 YES Default 0.99908 137.873 0.95 1.1 0.95 1.1
3 MORO138 1 YES Default 0.99867 137.816 0.95 1.1 0.95 1.1
27 HISKY69 1 YES Default 0.99582 68.712 0.95 1.1 0.95 1.1
55 DEMAR69 1 YES Default 0.99375 68.569 0.95 1.1 0.95 1.1
16 PETE69 1 YES Default 0.99147 68.411 0.95 1.1 0.95 1.1
54 SANDERS69 1 YES Default 0.9914 68.407 0.95 1.1 0.95 1.1
24 HIMAN69 1 YES Default 0.991 68.379 0.95 1.1 0.95 1.1
15 ZEB69 1 YES Default 0.98946 68.273 0.95 1.1 0.95 1.1
21 WOLEN69 1 YES Default 0.98743 68.133 0.95 1.1 0.95 1.1
53 SANDERS138 1 YES Default 0.98418 135.817 0.95 1.1 0.95 1.1
47 BOB138 1 YES Default 0.98207 135.525 0.95 1.1 0.95 1.1

8
Figure3: TransmissionlinepowerflowMVAutilization
From
Number
From
Name
To
Number To Name
Circ
uit Status Xfrmr
MW
From
Mvar
From
MVA
From
Lim
MVA
% of MVA
Limit
(Max)
MW
Loss Mvar Loss
48 BOB69 47 BOB138 1 Closed YES -111 -66.5
129.
4 187 64.7 0.19 7.6
39 RAY138 47 BOB138 1 Closed NO 145.6 36.9
150.
2 233 64.5 1.72 10.1
12 TIM69 27 HISKY69 1 Closed NO 68.5 20.3 71.5 112 64.1 0.72 -3.26
44 LAUF69 41 LAUF138 2 Closed YES -64 0.9 64 101 63.6 0.1 3.41
10 RAY69 13 FERNA69 1 Closed NO 51.9 1.4 51.9 82 63.3 0.87 1.92
44 LAUF69 41 LAUF138 1 Closed YES -61.2 0.7 61.2 101 60.8 0.09 3.14
32
NICOL1
38 29 JO138 1 Closed NO
-
112.8 -3.3
112.
9 191 59.9 1.29 5.42
1 TIM345 40 TIM138 1 Closed YES 141.8 42.5 148 250 59.2 0.21 13.05
21
WOLEN
69 48 BOB69 1 Closed NO -37.2 -13.4 39.6 72 55.3 0.29 -0.06
21
WOLEN
69 48 BOB69 2 Closed NO -37.2 -13.4 39.5 72 55.2 0.29 -0.1
12 TIM69 18 HANNAH69 1 Closed NO 58.1 -1.7 58.1 106 54.8 0.89 2.68
10 RAY69 39 RAY138 1 Closed YES
-
100.7 0.6
100.
7 186.7 54 0.11 4.36
24
HIMAN
69 44 LAUF69 1 Closed NO -40 -12.3 41.8 82 52.4 0.71 1.57
-
110.5 -19.7
112.
2 224 50.9 0.12 7.63
-
110.3 -19.7 112 224 50.8 0.12 7.59
28 JO345 29 JO138 2 Closed YES 103.6 13.7
104.
5 220 47.5 0.09 5.25

9
28 JO345 29 JO138 1 Closed YES 103.6 13.7
104.
5 220 47.5 0.09 5.25
16 PETE69 27 HISKY69 1 Closed NO -47.7 -21.7 52.4 112 46.8 0.1 -4.19
12 TIM69 40 TIM138 2 Closed YES -84.6 -16.1 86.1 187 46.5 0.08 3.48
12 TIM69 40 TIM138 1 Closed YES -84.6 -16.1 86.1 187 46.5 0.08 3.48
10 RAY69 19 GROSS69 1 Closed NO 32 -4.5 32.3 72 44.9 0.41 0.74
20 SCOT69 50 DAVIS69 1 Closed NO -35 4.4 35.3 82 43.6 0.52 0.84
29 JO138 41 LAUF138 1 Closed NO 76.9 8.7 77.3 191 40.5 1.07 3.58
54
SANDER
S69 53 SANDERS138 1 Closed YES -73 17.7 75.1 187 40.1 0.08 2.9
33
NICOL6
9 32 NICOL138 1 Closed YES -39.8 7.3 40.5 101 40.1 0.04 1.15
30
CAROL1
38 32 NICOL138 1 Closed NO -72.9 -9.2 73.5 191 38.5 0.12 0.31
31
SLACK3
45 38 RAY345 1 Closed NO 221.7 47.6
226.
8 597 38.2 0.37 -6.97
13
FERNA6
9 55 DEMAR69 1 Closed NO 31 3.5 31.2 90 34.7 0.21 0.71
17 PAI69 19 GROSS69 1 Closed NO -13.2 10.1 16.6 50 33.5 0.07 -0.11
47 BOB138 53 SANDERS138 1 Closed NO 32.6 -47.3 57.5 185 31.1 0.06 -15.3
35
SLACK1
38 31 SLACK345 1 Closed YES -64.8 -10.9 65.7 220 30.1 0.04 2.1
5
HOMER
69 44 LAUF69 1 Closed NO -28.9 0.8 29 102 28.7 0.28 0.51
15 ZEB69 54 SANDERS69 1 Closed NO -21.7 -2.8 21.9 77 28.5 0.04 -2.04
15 ZEB69 54 SANDERS69 2 Closed NO -21.5 -2.8 21.7 77 28.2 0.04 -2.07
15 ZEB69 54 SANDERS69 3 Closed NO -21.4 -2.8 21.6 77 28 0.04 -2.08
48 BOB69 54 SANDERS69 1 Closed NO -3.8 21.7 22.1 105 27.8 0.1 -7.14
20 SCOT69 34 PATTEN69 1 Closed NO 19.7 -2.1 19.8 72 27.5 0.09 0.12
30
CAROL1
38 41 LAUF138 1 Closed NO 49.5 3 49.6 191 26 0.18 -0.17
12 TIM69 17 PAI69 1 Closed NO 19.7 7.1 20.9 82 25.5 0.09 0.09

10
1 TIM345 31 SLACK345 1 Closed NO
-
141.8 -42.5 148 597 24.8 0.24 -15.7
35
SLACK1
38 39 RAY138 1 Closed NO 66.8 10 67.5 288 23.4 0.45 1.35
33
NICOL6
9 50 DAVIS69 1 Closed NO 11.8 -13.3 17.8 82 21.7 0.15 0.05
14
WEBER6
9 44 LAUF69 1 Closed NO -15.3 -8 17.3 81 21.3 0.11 -4.65
18
HANNA
H69 37 AMANDA69 2 Closed NO 13.5 -1.1 13.6 68 20 0.02 -2.56
18
HANNA
H69 37 AMANDA69 1 Closed NO 13.5 -1.1 13.6 68 20 0.02 -2.56
39 RAY138 40 TIM138 1 Closed NO 40.7 7.4 41.4 233 17.8 0.2 -0.9
54
SANDER
S69 55 DEMAR69 1 Closed NO -8.1 3.4 8.8 50 17.6 0.05 0.04
15 ZEB69 16 PETE69 1 Closed NO 10.1 -11.6 15.4 93 16.5 0.02 -1.96
31
SLACK3
45 28 JO345 1 Closed NO -92.7 -10.9 93.3 600 16 0.18 -34.5
5
HOMER
69 18 HANNAH69 1 Closed NO 14.9 -4 15.5 102 15.2 0.07 0.03
56
LYNN13
8 29 JO138 1 Closed NO -16 -0.8 16 133 12 0.02 -1.31
14
WEBER6
9 34 PATTEN69 1 Closed NO 3.1 5.1 6 72 8.4 0.01 -0.1
15 ZEB69 24 HIMAN69 1 Closed NO -3.7 -4.1 5.5 74 7.4 0 -2.16
3
MORO1
38 40 TIM138 1 Closed NO -12.7 -0.4 12.7 233 5.5 0.01 -1.76
35
SLACK1
38 56 LYNN138 1 Closed NO -2 0.9 2.1 100 3.5 0 -2
3
MORO1
38 41 LAUF138 1 Closed NO 0.4 -4.6 4.7 233 2 0 -1.34
20 SCOT69 48 BOB69 1 Open NO 0 0 0 82 0 0 0

11
Observation:
1. It is observed from the above base case analysis that all the power system transmission
lines and the bus voltages are within the defined voltage limits of 0.95 and 1.10 per unit
2. From Table 1, it is observed that:
 The least value of voltage obtained by the transmission lines and buses is
0.98207 per unit
 The maximum value of voltage obtained by the transmission line and buses is
1.03 p.u
3. Also from the base case analysis, it was observed that all the power system line MVA are
within the defined MVA limit of 100% as shown in Table 2:
 The least % of MVA is utilized by transmission line is 0%
 The maximum % of MVA is utilized by the transmission line is 71.5%
STEP 2: Perform contingency analysis on the power system
Aim: To study the impact of any single transmission line or transformer or outage on the
remaining system operation. This procedure is known as (n-1) contingency analysis.
Procedure:
1. Select tools in the PowerWorld simulator window
2. Click on the Contingency Analysis option
3. Note that 57 single line or transformer contingencies are defined
4. Select start run button at the bottom right corner of the display to see the impact of
removing any single element on the rest of the power system operation
Figure 4: Result of contingency analysis when conducted on the base
case

12
Figure 5: Table showing contingency analysis on base case
Label Skip Processed Solved Violations
Max
Branch % Min Volt Max Volt
# of
iterations
L_RAY138-BOB138C1 NO YES YES 7 125.2 0.934 2
T_BOB69-BOB138C1 NO YES YES 2 114.5 0.949 1
L_WOLEN69-BOB69C1 NO YES YES 1 112.7 2
T_LAUF69-LAUF138C1 NO YES YES 1 104.3 2
T_LAUF69-LAUF138C2 NO YES YES 1 102.7 2
L_WOLEN69-BOB69C2 NO YES YES 1 112.7 2
L_RAY69-FERNA69C1 NO YES YES 0 2
L_HOMER69-LAUF69C1 NO YES YES 0 2
L_MORO138-TIM138C1 NO YES YES 0 2
L_TIM69-HANNAH69C1 NO YES YES 0 1
L_TIM69-HISKY69C1 NO YES YES 0 2
T_TIM69-TIM138C1 NO YES YES 0 2
L_FERNA69-DEMAR69C1 NO YES YES 0 1
L_TIM69-PAI69C1 NO YES YES 0 2
L_HOMER69-
HANNAH69C1 NO YES YES 0 2
L_ZEB69-HIMAN69C1 NO YES YES 0 1
L_ZEB69-PETE69C1 NO YES YES 0 2
L_ZEB69-SANDER69C1 NO YES YES 0 1
L_PETE69-HISKY69C1 NO YES YES 0 2
L_PAI69-GROSS69C1 NO YES YES 0 2
L_HANNAH69-
AMANDA69C1 NO YES YES 0 1
L_HANNAH69- NO YES YES 0 1

13
AMANDA69C2
L_SCOT69-PATTEN69C1 NO YES YES 0 2
L_SCOT69-BOB69C1 NO YES YES 0 0
L_SCOT69-DAVIS69C1 NO YES YES 0 1
T_RAY69-RAY138C1 NO YES YES 0 2
T_JO345-JO138C2 NO YES YES 0 2
L_WEBER69-LAUF69C1 NO YES YES 0 2
T_JO345-JO138C1 NO YES YES 0 2
L_HIMAN69-LAUF69C1 NO YES YES 0 2
L_SLACK345-JO345C1 NO YES YES 0 2
L_NICOL138-JO138C1 NO YES YES 0 1
L_JO138-LAUF138C1 NO YES YES 0 1
L_LYNN138-JO138C1 NO YES YES 0 2
L_CAROL138-NICOL138C1 NO YES YES 0 1
L_CAROL138-LAUF138C1 NO YES YES 0 1
T_SLACK138-SLACK345C1 NO YES YES 0 2
L_SLACK345-RAY345C1 NO YES YES 0 1
T_NICOL69-NICOL138C1 NO YES YES 0 2
L_NICOL69-DAVIS69C1 NO YES YES 0 2
L_SLACK138-RAY138C1 NO YES YES 0 2
L_SLACK138-LYNN138C1 NO YES YES 0 1
L_RAY138-TIM138C1 NO YES YES 0 2
L_WEBER69-PATTEN69C1 NO YES YES 0 1
L_RAY69-GROSS69C1 NO YES YES 0 2
L_MORO138-LAUF138C1 NO YES YES 0 1
L_BOB138-SANDER138C1 NO YES YES 0 2
L_BOB69-SANDER69C1 NO YES YES 0 1

14
OBSERVATION:
1. After performing the contingency analysis, it is observed from the above table that the
power system has 13 contingency violations in the base case when the SANDERS69
power plant is disconnected from the grid.
STEP 3: Finding least cost design to install the new transmission lines and transformers to
ensure that the transmission system in MLP is adequate for any base case or first case
contingency loading situation with the retirement of the SANDERS69 power plant.
PROCEDURE:
1. Determine the parameters (resistance, inductive and capacitive reactance, line
length, GMD, GMR, B and G) of all the transmission lines using the tower
configuration and conductor type, which in this case is Cardinal with a symmetrical
tower configuration, having a spacing of 4m between the conductor strands for a
69KV transmission line and 5m spacing for 138 KV transmission line.
2. After determining the transmission line parameters, I use the available rights-of-
ways data from the table given below to construct the transmission line on the
existing Base case, initially keeping all the circuit breakers open.
3. Once, all the transmission lines have been constructed, I now construct a bus of 138
KV, to upgrade the 69 KV buses: WOLEN69, BOB69,FERNA69, SCOT69 and RAY69 to
the 138 KV buses in an arrangement with no contingency violations.
4. Now, that I have my circuit ready for analysis, I close the circuit breakers for single
transmission lines first, then in the second stage I select a combination of two
transmission line pairs in the order given in the table enlisting the Rights-of-Ways
data.
5. After closing the circuit breakers for the single transmission line and later of the
pair of two transmission lines, I note down the total system losses given by the
highlighted yellow box on the top left corner of the one line diagram for each
arrangement.
6. Next, I perform the contingency analysis on the circuit considered. A contingency
analysis window pops up. I select the Start Run option to perform the contingency
analysis.
7. Within a few seconds, the PowerWorld window displays the number of violations
encountered by the considered system on the bottom left corner of the contingency
analysis window.
8. Once, all the combinations of one transmission lines and two transmission line pairs
have been considered, I now calculate the total cost incurred by the construction of
the pair of transmission lines using the equation:
𝑭𝒊𝒏𝒂𝒍 𝒄𝒐𝒔𝒕 𝒐𝒇 𝒑𝒓𝒐𝒋𝒆𝒄𝒕 𝒂𝒇𝒕𝒆𝒓 𝒊𝒏𝒔𝒕𝒂𝒍𝒍𝒊𝒏𝒈 𝒕𝒓𝒂𝒏𝒔𝒎𝒊𝒔𝒔𝒊𝒐𝒏 𝒍𝒊𝒏𝒆 𝒑𝒂𝒊𝒓( 𝒇𝒐𝒓 𝟓 𝒚𝒆𝒂𝒓𝒔)
= 𝑻𝒐𝒕𝒂𝒍 𝒄𝒐𝒏𝒔𝒕𝒓𝒖𝒄𝒕𝒊𝒐𝒏 𝒄𝒐𝒔𝒕
− 𝑺𝒂𝒗𝒊𝒏𝒈𝒔 𝒂𝒔𝒔𝒐𝒄𝒊𝒂𝒕𝒆𝒅 𝒘𝒊𝒕𝒉 𝒅𝒆𝒄𝒓𝒆𝒂𝒔𝒆 𝒊𝒏 𝒔𝒚𝒔𝒕𝒆𝒎 𝒍𝒐𝒔𝒔 𝒐𝒓
+ 𝑨𝒅𝒅𝒊𝒕𝒊𝒐𝒏𝒂𝒍 𝒄𝒐𝒔𝒕 𝒐𝒇 𝒊𝒏𝒔𝒕𝒂𝒍𝒍𝒂𝒕𝒊𝒐𝒏

15
From the calculations, I can now select the most cost effective approach to install the new
transmission line/lines and transformers to ensure that MLP is adequate for any base case
or first case contingency loading situation with the retirement of the SANDERS69 power
plant.
DESIGN CASE SPECIFICATIONS:
1. Tower configuration- Symmetrical tower type
2. Transmission line conductor type- Cardinal
3. Conductor spacing- 4m for 69KV line; 5m for 138 KV line
4. Base MVA- 100 MVA
5. Current rating- 1110 A
6. Fixed cost- $200,000 for 138 KV line; $125,000 for 69 KV line
7. Variable cost- $310,000/mile for 138KV line; $260,000/mile for 69 KV line
8. Cost of transformer- $950,000 for 101 MVA transformer; $1,200,000 for 187 MVA
transformer
9. Transformer configuration- Per Unit resistance- 0.0025 p.u; Per Unit reactance- 0.04
p.u
10. Cost of bus upgrading from 69KV to 138KV- $200,000
11. Initial Base case system losses= 13.54 MW, which is assumed to be constant
throughout the designing process
CALCULATIONS:
1. Calculating GMR for the Cardinal conductor- Since, radius of the conductor is not
specified in the case, therefore, assuming the GMR from the Table A4 as-
GMR= 0.0403’= 0.4836”
2. Calculating GMD for the symmetrical tower configuration using equation-
GMD =√ 𝒅 ∗ 𝒅 ∗ 𝒅
𝟑
, where d= distance between the conductors.
Here, d= 4m for 69 KV line and d= 5m for 138 KV line
Therefore:
GMD for 69 KV line =√ 𝟒 ∗ 𝟒 ∗ 𝟒
𝟑
= 𝟒𝒎 = 𝟏𝟑. 𝟏𝟐𝟑𝟑′
= 𝟏𝟓𝟕. 𝟒𝟕𝟗𝟔”
GMD for 138 KV line =√ 𝟓 ∗ 𝟓 ∗ 𝟓
𝟑
= 𝟓𝒎 = 𝟏𝟔. 𝟒𝟎𝟒𝟏𝟗′
= 𝟏𝟗𝟔. 𝟖𝟓𝟎𝟐”

16
3. Inductance for the conductor is calculated using equation
𝑳 = 𝟎. 𝟕𝟒𝟏𝟏𝐥𝐨𝐠 (
𝑮𝑴𝑫
𝑮𝑴𝑹
) 𝒎𝑯/𝒎𝒊𝒍𝒆 /𝒑𝒉𝒂𝒔𝒆
Therefore:
L for 69 KV line:
𝐿 = 0.7411log(
157 .4796
0.4836
) 𝑚𝐻/𝑚𝑖𝑙𝑒 /𝑝ℎ𝑎𝑠𝑒= 1.8621 𝑚𝐻/𝑚𝑖𝑙𝑒 /𝑝ℎ𝑎𝑠𝑒
L for 138 KV line:
𝐿 = 0.7411log(
196 .8502
0.4836
) 𝑚𝐻/𝑚𝑖𝑙𝑒 /𝑝ℎ𝑎𝑠𝑒= 1.93401 𝑚𝐻/𝑚𝑖𝑙𝑒 /𝑝ℎ𝑎𝑠𝑒
4. Calculating Inductive reactance for the transmission lines using equation
𝑿 𝑳 = 𝟐 ∗ 𝝅 ∗ 𝒇 ∗ 𝑳 Ω
Therefore:
𝑋 𝐿 For 69 KV line:
𝑿 𝑳 = 𝟐 ∗ 𝝅 ∗ 𝟔𝟎 ∗ 𝟏. 𝟖𝟔𝟐𝟏𝒎 = 0.701 𝛺/𝑚𝑖𝑙𝑒 /𝑝ℎ𝑎𝑠𝑒
𝑋 𝐿 For 138 KV line:
𝑿 𝑳 = 𝟐 ∗ 𝝅 ∗ 𝟔𝟎 ∗ 𝟏. 𝟗𝟑𝟒𝟎𝟏𝒎 = 0.72910 𝛺/𝑚𝑖𝑙𝑒 /𝑝ℎ𝑎𝑠𝑒
5. Capacitance for the conductor is calculated using equation
𝑪 = (
𝟎. 𝟎𝟑𝟖𝟖
𝐥𝐨𝐠(
𝑮𝑴𝑫
𝑮𝑴𝑹
)
) µ𝑭/ 𝒎𝒊𝒍𝒆 /𝒑𝒉𝒂𝒔𝒆
Therefore:
C for 69 KV line:
𝑪 = (
𝟎. 𝟎𝟑𝟖𝟖
𝐥𝐨𝐠(
𝟏𝟓𝟕. 𝟒𝟕𝟗𝟔
𝟎. 𝟒𝟖𝟑𝟔
)
) = 𝟎. 𝟎𝟏𝟓𝟒𝟒𝟏 µ𝑭/ 𝒎𝒊𝒍𝒆 /𝒑𝒉𝒂𝒔𝒆
C for 138 KV line:
𝑪 = (
𝟎. 𝟎𝟑𝟖𝟖
𝐥𝐨𝐠(
𝟏𝟗𝟔. 𝟖𝟓𝟎𝟐
𝟎. 𝟒𝟖𝟑𝟔
)
) = 𝟎. 𝟎𝟏𝟒𝟖𝟔𝟕 µ𝑭/ 𝒎𝒊𝒍𝒆 /𝒑𝒉𝒂𝒔𝒆
6. Calculate Capacitive reactance for the transmission lines using equation

17
𝑿 𝑪 = (
𝟏
𝟐∗𝝅∗𝒇∗𝑪
) Ω
Therefore:
𝑿 𝑪 For 69 KV line:
𝑿 𝑪 = (
𝟏
𝟐∗𝝅∗𝟔𝟎∗𝟎.𝟎𝟏𝟓𝟒𝟒𝟏
) = 𝟏𝟕𝟏. 𝟕𝟖𝟖𝟐 KΩ/𝒎𝒊𝒍𝒆 /𝒑𝒉𝒂𝒔𝒆
𝑿 𝑪 For 138 KV line:
𝑿 𝑪 = (
𝟏
𝟐∗𝝅∗𝟔𝟎∗𝟎.𝟎𝟏𝟒𝟖𝟔𝟕
) = 𝟏𝟕𝟖. 𝟒𝟐𝟎𝟖 KΩ/𝒎𝒊𝒍𝒆 /𝒑𝒉𝒂𝒔𝒆
7. Calculate Susceptance for the transmission lines using equation
𝑩 =
𝒋
𝑿 𝑪
Mhos/mile
Therefore:
B for 69 KV line:
𝑩 =
𝒋
𝟏𝟕𝟏.𝟕𝟖𝟖𝟐 𝑲
= 5.821121 µmhos/mile
B for 138 KV line:
𝑩 =
𝒋
𝟏𝟕𝟖.𝟒𝟐𝟎𝟖𝑲
= 5.604227 µmhos/mile
8. Resistance of the conductor is take from table as 𝒓 𝒂 = 𝟎. 𝟏𝟏𝟐𝟖 Ω/𝒄𝒐𝒏𝒅 /𝒎𝒊𝒍𝒆
9. Assuming Conductance G=0
10. The total cost for the project after installing the new combination of transmission
line and transformer is calculated using equation:
Total cost= [($200,000) + ($125,000) + (310,000*𝒍𝒆𝒏𝒈𝒕𝒉 𝟏𝟑𝟖 𝑲𝑽 𝒍𝒊𝒏𝒆 ) +
(260,000*𝒍𝒆𝒏𝒈𝒕𝒉 𝟔𝟗 𝑲𝑽 𝒍𝒊𝒏𝒆)+Additional cost – savings + ($950,000 or
$1,200,000) if transformer used+ $200,000 for upgrading the 69
KV to 138 KV]

18
OBSERVATIONS
Single transmissionline considered
Transmission Line System Losses Contingency Violations
BOB69 to SCOT69 13.66 MW 6 violations
BOB138 (101 MVA) to SCOT69 13.54 MW 8 violations
BOB69 to WOLEN69 13.33 MW 10 violations
BOB138 (101 MVA) to
WOLEN69
13.13 MW 9 violations
BOB138 (187 MVA) to
WOLEN69
FERNA69 to RAY69 13.16 MW 12 violations
FERNA69 to RAY138 (101
MVA)
MVA)
LYNN138 (101 MVA) to
SCOT69
SCOT69
LYNN138(101 AND 187 MVA)
to WOLEN69
SANDER69 to SCOT69 13.67 MW 7 violations
SANDER138(101 AND 187
MVA) to SCOT69
SLACK138(101 MVA) to
WOLEN69
11.09 MW 0 violation
WOLEN69
JO138(101 AND 187 MVA) to
SCOT69
2 transmissionlinesconsidered
CASE1: BOB69 toSCOT69 fixed
Variable Transmission line System Losses Contingency Violations
BOB138 (101 MVA) to
WOLEN69

19
BOB138 (187 MVA) to
WOLEN69
MVA)
MVA)
SCOT69
SCOT69
SLACK138(101 AND 187 MVA)
to WOLEN69
11.07MW AND 10.68 MW 0 violation
JO138(101 AND 187 MVA) to
SCOT69
12.21 AND 12.06 MW 2 violation
CASE2: BOB138 toSCOT69 fixed
101 MVA transformer:
BOB138 (101 MVA) to
WOLEN69
BOB138 (187 MVA) to
WOLEN69
MVA)
MVA)
SCOT69
WOLEN69
WOLEN69
SANDER138 (101 MVA) to
SCOT69
SLACK138 (101 MVA) to
WOLEN69
SLACK138 (187 MVA) to 10.85 MW 0 violations

20
WOLEN69
JO138 (101 MVA) to SCOT69 11.24 MW 4 violations
BOB138 (101 MVA) to
WOLEN69
BOB138 (187 MVA) to
WOLEN69
MVA)
MVA)
SCOT69
WOLEN69
WOLEN69
SCOT69
WOLEN69
WOLEN69
CASE3: BOB69 toWOLEN69 fixed
BOB138 (101 MVA) to
WOLEN69
BOB138 (187 MVA) to
WOLEN69
MVA)
MVA)

21
SCOT69
SCOT69
WOLEN69
WOLEN69
SCOT69
SCOT69
WOLEN69
WOLEN69
CASE4: BOB138 toWOLEN69 fixed
BOB69 TO SCOT69 13.61 MW 5 violations
BOB69 TO WOLEN69 13.05 MW 9 violation
MVA)
MVA)
SCOT69
SCOT69
12.46MW 8 violations
WOLEN69
SCOT69
SCOT69
SLACK138 (101 AND 187 10.71 MW 1 violations

22
MVA) to WOLEN69
MVA)
MVA)
SCOT69
SCOT69
12.46MW 8 violations
LYNN138 (101 AND 187 MVA)
to WOLEN69
SCOT69
SCOT69
SLACK138 (101 AND 187
MVA) to WOLEN69
CASE5: FERNA69 toRAY69 fixed
MVA)
MVA)
SCOT69
SCOT69
LYNN138 (101 MVA) to 10.83 MW 2 violations

23
WOLEN69
WOLEN69
SCOT69
SCOT69
WOLEN69
WOLEN69
CASE6: FERNA69 toRAY138 fixed
WOLEN69
WOLEN69
SCOT69
SCOT69
WOLEN69
10.5MW 9 violations
WOLEN69
10.5MW 0 violations
WOLEN69
WOLEN69
SANDER138 (101 MVA) to 13.06 MW 5 violations

24
SCOT69
SCOT69
WOLEN69
10.5MW 9 violations
WOLEN69
10.5MW 0 violations
CASE7: J0E138 TO SCOT69
101 AND 187 MVA Transformer
PAIRS SYSTEM LOSSES CONTINGENCY VIOLATIONS
LYNN138(101 MVA) to
WOLEN69
LYNN138(187 MVA) to
WOLEN69
SLACK138(101 AND 187 MVA)
to WOLEN69
10.13 MW AND 10.51 MW 0 violations
CASE8: LYNN138 toSCOT69 fixed
101 MVA Transformer-0 cases without contingency violation.
187 MVA Transformer:
SCOT69
SCOT69
WOLEN69
WOLEN69

25
CASE9: SANDER138 toSCOT69 fixed
WOLEN69
WOLEN69
CASE10: SLACK138 toWOLEN69
SCOT69
CASE11: LYNN138toWOLEN69
187 MVA Transformer
LYNN138 to WOLEN69 10.71 MW 0 violations
WOLEN69
JO138 to SCOT69 12.74 MW 11 violations

26
COST CALCULATIONS:
The observation tables above show that there are several combinations of transmission
lines and transformers which result in zero contingency violation. But, the goal of our
project is to determine the least expensive combination with zero violations.
Below are the steps, which show calculations for cases which most likely can be the least
cost combination.
CASE A: COMBINATION OF TRANSMISSION LINES: SLACK138 TO WOLEN69
(TRANSFORMER 187MVA) AND BOB138 TO SCOTT69 (TRANSFORMER 187MVA)
Fixed cost for lines SLACK138 to WOLEN69 and BOB138 and SCOT69= [$200,000 × 2]
Variable cost= [$310,000 × 11.5015 + $310,000 × 8.50]
Transformer cost (Qty:2)= [$1,200,000 × 2]
Bus upgrading cost= [$200,000 × 2]
Therefore, net construction cost= $9,400,000.00
Base case system loss= 13.54 MW
System loss for combination considered= 10.13 MW
Saving= [13.54 – 10.13] × 50 × 24 × 365 × 5= $7,467,900
Therefore Net cost of project= [$7,853,503.465 − $7,467,900]= $193,210.
CASE B: COMBINATION OF TRANSMISSION LINES: BOB138 TO WOLEN69
(TRANSFORMER 187MVA) AND SLACK138 TO WOLEN69 (TRANSFORMER 187MVA)
Fixed cost for lines BOB138 TO WOLEN69 and SLACK138 TO WOLEN69 = [$200,000 × 2]
Variable cost= [$310,000 × 4.8 + $310,000 × 11.5]
Transformer cost (One 187 MVA, One 101 MVA)= [$1,200,000 + $950,000]
Bus upgrading cost= [$200,000 × 2]
Therefore, net construction cost= $8,253,000
Saving= [13.54 – 10.49] × 50 × 24 × 365 × 5= $6,679,500
Therefore Net cost of project= [$12,249,876− $6,679,500]= $1,573,500

27
CASE C: COMBINATION OF TRANSMISSION LINES: BOB69 to WOLEN69 AND
SLACK138 to WOLEN69 (TRANSFORMER 187MVA)
Fixed cost for lines LYNN138 to WOLEN69 and SLACK138 to WOLEN69 = [$200,000
+125,000]
Variable cost= [$310,000 × 11.5]
Transformer cost (Qty:2)= [$1,200,000 ]
Bus upgrading cost= [$200,000]
Saving= [13.54 – 10.83] × 50 × 24 × 365 × 5= $5,270,800
Therefore Net cost of project= [$7290000 − $7,270,800] = $644,900.
CASE D: COMBINATION OF TRANSMISSION LINES: LYNN69 to WOLEN69 AND
SLACK138 to WOLEN69 (TRANSFORMER 187MVA)
+$200,000 ]
Variable cost= [$260,000 × 6.0024 + $310,000 × 11.5015]
Transformer cost (Qty: 1)= $1,200,000
Saving= [13.54 – 10.5] × 50 × 24 × 365 × 5= $6,679,500
Therefore Net cost of project= [$6,851,089− $6,679,500]= $170,500.
CASE E: COMBINATION OF TRANSMISSION LINES: FERNA69 to RAY69 AND SLACK138
to WOLEN69 (TRANSFORMER 187MVA)
+$200,000 ]
Variable cost= [$260,000 × 12 + $310,000 × 11.5015]
Therefore, net construction cost= $8210000

28
Saving= [13.54 – 10.49] × 50 × 24 × 365 × 5= $6,679,500
Therefore Net cost of project= [$6,851,089− $6,679,500]= $1,530,500.
CASE F: COMBINATION OF TRANSMISSION LINES: FERNA69 to
RAY138(TRANSFORMER 101MVA) AND SLACK138 to WOLEN69 (TRANSFORMER
187MVA)
+$200,000 ]
Variable cost= [$260,000 × 6.0024 + $310,000 × 11.5015]
Transformer cost (Qty: 1)= $950, 000 + 1200000
Bus upgrading cost= [$200,000*2]
Saving= [13.54 – 10.5] × 50 × 24 × 365 × 5= $6,679,500
CASE G: COMBINATION OF TRANSMISSION LINES FERNA69 to
RAY138(TRANSFORMER 187MVA) AND SLACK138 to WOLEN69 (TRANSFORMER
187MVA)Fixed cost for lines LYNN69 to WOLEN69 and SLACK138 to WOLEN69 =
[$125,000 +$200,000 ]
Variable cost= [$260,000 × 6.0024 + $310,000 × 11.5015]
Transformer cost (Qty: 1)= $1,200,000∗ 2
Saving= [13.54 – 10.51] × 50 × 24 × 365 × 5= $6,679,500
CASE H: COMBINATION OF TRANSMISSION LINES: JOE138 to SCOTT69 AND SLACK138
Fixed cost for lines JOE69 to SCOTT69 and SLACK138 to WOLEN69 = [$125,000
+$200,000 ]
Variable cost= [$260,000 × 15 + $310,000 × 11.5015]
Transformer cost (Qty: 1)= $950,000∗ 2

29
Saving= [13.54 – 10.53] × 50 × 24 × 365 × 5= $6,679,500
CASE I: COMBINATION OF TRANSMISSION LINES: JOE138 to SCOTT69 AND SLACK138
+$200,000 ]
Variable cost= [$260,000 × 6.0024 + $310,000 × 11.5015]
Saving= [13.54 – 10.5] × 50 × 24 × 365 × 5= $6,679,500
CASE J: COMBINATION OF TRANSMISSION LINES: JOE138 to SCOTT69 AND SLACK138
to WOLEN69 (TRANSFORMER 101MVA AND 187 MVA)
+$200,000 ]
Variable cost= [$260,000 × 6.0024 + $310,000 × 11.5015]
Transformer cost (Qty: 1)= $1,200,000+950,000
Saving= [13.54 – 10.6] × 50 × 24 × 365 × 5= $6,679,500
CASE K: COMBINATION OF TRANSMISSION LINES: LYNN69(TRANSFORMER 187MVA)
to SCOTT69 AND SLACK138 to WOLEN69 (TRANSFORMER 101MVA)
Fixed cost for lines LYNN69 to SCOTT69 and SLACK138 to WOLEN69 = [$125,000
+$200,000 ]
Variable cost= [$310,000 × 12 + $310,000 × 11.5015]
Transformer cost (Qty: 1)= $1,200,000+950000

30
Saving= [13.54 – 10.5] × 50 × 24 × 365 × 5= $6,679,500
CASE L: COMBINATION OF TRANSMISSION LINES: LYNN69(TRANSFORMER 187MVA)
to SCOTT69 AND SLACK138 to WOLEN69 (TRANSFORMER 187MVA)
+$200,000 ]
Variable cost= [$310,000 × 12 + $310,000 × 11.5015]
Transformer cost (Qty: 1)= $1,200,000*2
Saving= [13.54 – 10.7] × 50 × 24 × 365 × 5= $6,679,500
CASE M: COMBINATION OF TRANSMISSION LINES: SANDER138(TRANSFORMER
187MVA) to SCOTT69 AND SLACK138 to WOLEN69 (TRANSFORMER 187MVA)
+$200,000 ]
Variable cost= [$310,000 × 6 + $310,000 × 11.5015]
Saving= [13.54 – 10.63] × 50 × 24 × 365 × 5= $6,679,500
Therefore Net cost of project= [$6,851,089− $6,679,500]= $670,500
CASE N: COMBINATION OF TRANSMISSION LINES: SLACK138(TRANSFORMER
187MVA) to WOLEN69 AND JOE138 to SCOT69 (TRANSFORMER 187MVA)
+$200,000 ]
Variable cost= [$310,000 × 11.50 + $310,000 × 15]
Transformer cost (Qty: 1)= $1,200,000*2

31
Saving= [13.54 – 10.49] × 50 × 24 × 365 × 5= $4,660,500
Therefore Net cost of project= [$6,851,089− $6,679,500]= $171,589.
CASE O: COMBINATION OF TRANSMISSION LINES: LYNN138(TRANSFORMER
187MVA) to WOLEN69 AND SLACK138 to WOLEN69 (TRANSFORMER 187MVA)
+$200,000 ]
Variable cost= [$310,000 × 15 + $310,000 × 11.5015]
Saving= [13.54 – 10.43] × 50 × 24 × 365 × 5= $6,679,500

32
Observation:
The above observation tables show all the combinations of single and two transmission line
pairs, of which we find the least system cost to be 10.13 MW for the case with transmission
lines: SLACK138 to WOLEN69(with transformer of 187MVA) and JO138 to SCOT69(with
transformer of 187MVA)PG.24. But from the cost calculations shown above, it can be seen
that the most economical combination of transmission lines and transformers is achieved
for the combination of transmission lines: LYNN69 to WOLEN69 AND SLACK138 to
WOLEN69 (TRANSFORMER 187MVA)
Project recommendations:
After studying the impact of all the possible combinations of transmission line pairs, we
arrived at the study outcome table shown above, which represents all the cases which
result in one or more zero violation scenarios.
By further calculating the total cost of the project for the combinations with zero violations,
it is found that the project case with the least cost is obtained by installing the transmission
lines LYNN69 to WOLEN69 AND SLACK138 to WOLEN69 (TRANSFORMER 187MVA)
With Transformer of rating 187 MVA. This transmission line combination incurs a total cost
of $170,500.
This combination LYNN69 to WOLEN69 AND SLACK138 to WOLEN69 (TRANSFORMER
187MVA) satisfies the two main requirements of our study: (1) To result in zero
contingency violations with the power plant at SANDERS69 disconnected from the grid; (2)
To be the least expensive approach.
Therefore, the least expensive system additions that can be implemented so that base case
and all contingencies result in reliable operation with the SANDERS69 power plant
disconnected is achieved by using the LYNN69 to WOLEN69 AND SLACK138 to
WOLEN69 (TRANSFORMER 187MVA)

33
APPENDIX
TABLE A.3
Electrical characteristics of bare aluminium conductors steel-
reinforced (ACSR)*
Resis
tance
A
c
,
6
0
H
z
Code
word
Aluminum
area,
cmil
Strandi
ng
Al
/S
t
Layers
of
alumin
um
O
u
t
s
i
d
e
d
i
a
m
e
t
e
r
,
i
n
Dc,
20°C,
Ω/1,000
ft
20°C,
Ω/mi
50°C,
Ω/mi
GMR Ds
ft
Inductive
Xa,
Ω/miWaxwing 266.800 18/1 2 0
,
6
0
9
0,064
6
0,348
8
0,383
1
0,0198 0,476
Partridge 266.800 26/7 2 0
,
6
4
2
0,064
0
0,345
2
0,379
2
0,0217 0,465
Ostrich 300.000 26/7 2 0
,
6
8
0
0,056
9
0,307
0
0,337
2
0,0229 0,458
Merlin 336.400 18/1 2 0
,
6
8
4
0,051
2
0,276
7
0,303
7
0,0222 0,462
Linnet 336.400 26/7 2 0
,
7
2
1
0,050
7
0,273
7
0,300
6
0,0243 0,451
Oriole 336.400 30/7 2 0
,
7
4
1
0,050
4
0,271
9
0,298
7
0,0255 0,445
Chickade
e
397.500 18/1 2 0
,
7
4
3
0,043
3
0,234
2
0,257
2
0,0241 0,452
Ibis 397.500 26/7 2 0
,
7
8
3
0,043
0
0,232
3
0,255
1
0,0264 0,441
Pelican 477.000 18/1 2 0
,
8
1
4
0,036
1
0,195
7
0,214
8
0,0264 0,441
Flicker 477.000 24/7 2 0
,
8
4
6
0,035
9
0,194
3
0,213
4
0,0284 0,432
Hawk 477.000 26/7 2 0
,
8
5
8
0,035
7
0,193
1
0,212
0
0,0289 0,430
Hen 477.000 30/7 2 0
,
8
8
3
0,035
5
0,191
9
0,210
7
0,0304 0,424
Osprey 556.500 18/1 2 0
,
8
7
9
0,030
9
0,167
9
0,184
3
0,0284 0,432
Parakeet 556.500 24/7 2 0
,
9
1
4
0,030
8
0,166
9
0,183
2
0,0306 0,423
Dove 556.500 26/7 2 0
,
9
2
7
0,030
7
0,166
3
0,182
6
0,0314 0,420
Rook 636.000 24/7 2 0
,
9
7
7
0,026
9
0,146
1
0,160
3
0,0327 0,415
Grosbeak 636.000 26/7 2 0
,
9
9
0
0,026
8
0,145
4
0,159
6
0,0335 0,412
Drake 795.000 26/7 2 1
,
1
0
8
0,021
5
0,117
2
0,128
4
0,0373 0,399
Tern 795.000 45/7 3 1
,
0
6
3
0,021
7
0,118
8
0,130
2
0,0352 0,406
Rail 954.000 45/7 3 1
,
1
6
5
0,018
1
0,099
7
0,109
2
0,0386 0,395
Cardinal 954.000 54/7 3 1
,
1
9
6
0,018
0
0,098
8
0,112
8
0,0402 0,390
Ortolan 1.033.500 45/7 3 1
,
2
1
3
0,016
7
0,092
4
0,101
1
0,0402 0,390
Bluejay 1.113.000 45/7 3 1
,
2
5
9
0,015
5
0,086
1
0,094
1
0,0415 0,386
Finch 1.113.000 54/1
9
3 1
,
2
9
3
0,015
5
0,085
6
0,093
7
0,0436 0,380
Bittern 1.272.000 45/7 3 1
,
3
4
5
0,013
6
0,076
2
0,083
2
0,0444 0,378
Pheasant 1.272.000 54/1
9
3 1
,
3
8
2
0,013
5
0,075
1
0,082
1
0,0466 0,372
Bobolink 1.431.000 45/
7
3 1
,
4
2
7
0,012
1
0,068
4
0,074
6
0,047
0
0,371

EE 521 PROJECT DESIGN CASE 2

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