To: Idaho Power



To: Idaho Power

From: Borah Mitigators

Purpose: to modify the current mitigation scheme for the Borah West Path using thermal limits

We propose, that calculating the thermal limits of the lines in the Borah West Path will help to increase the efficiency of a modified remedial action scheme. We are seeking approval in our conceptual design and verification of the scope of our work.

By using PowerWorld and ETAP or a similar program, we plan to calculate the dynamicthermal limits of the transmission lines through the Borah West Path. Once the thermal limits have been calculated the current remedial action scheme can be tested for efficiency. If the new limits change the parameters of the current mitigation scheme, an updated remedial action scheme will be developed using the thermal limits.

The amount of power that can flow through transmission lines varies as the temperature changes. By calculating the thermal limits of the lines more precisely, we will be able to use other actions instead of dropping generators.

If you have any questions or concerns please contact us. We would appreciate any input you have to offer. Thank you for your consideration and we look forward to a response by May 13, 2006.

Thank you,

Borah Mitigators

Jason Rippee (Team contact)

ripp4862@uidaho.edu

(208)-731-3215

Borah Mitigators

Transmission Overload Mitigation Scheme

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Team Members:

Jason Rippee

Mark Magee

Kyle Jones

Executive Summary

We understand this project to entail the following goals:

1. To have a Jim Bridger generator unit trip is a last resort in our revised mitigation scheme.

2. Our team is to determine other mitigation actions which include maximizing the thermal capability of transmission lines, bypassing series capacitors when needed, switching in shunt capacitor banks and as a second to last resort dropping generator units.

We understand that bypassing series capacitors has the effect of shifting power from the transmission line with the series capacitor onto other paths parallel to that line. Generator unit dropping is done to reduce the amount of power entering the power lines in its path of transmission. Load shedding may be done to reduce system loading. Thermal effects may be taken into account to maximize the ampacity of lines for given environmental conditions, or to find the time allocated over which mitigation actions may take place.

Suggested Deliverables:

To provide a mitigation scheme for all critical outages, as defined by the document sent by Orlando Ciniglio (file name: Borah West OMS V2 - preliminary description) Calculation of Borah Operating Transfer Capability Rev2: 3/15/06. Editorial changes (OAC). (This is not to include ambient temperature considerations as mentioned in the document, and ampacity will be treated as that for the summer case only being 40C.)

Coefficients for regression equations would be developed for a set of N-1, N-2, and bus contingencies for each of the given contingencies. Logic expressions would then be developed that reflect the remedial action desicions made based on regression equations.

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TABLE OF CONTENTS

1. Introduction…………………………………………………………… 1

1.1 Project Background …………………………………………… 1

1.2 Project Definition………………………………………….…... 1

2. Concepts……………………………………………….……………… 2

2.1 Thermal Line Monitoring ………………...…………………… 2

2.2 Series Capacitors ……………………………………………… 4

2.3 Generator Dropping …….…………………………………….. 5

2.4 Load Shedding ………………………………………………… 6

2.5 Concept Selection……………………………………………… 6

3. PowerWorld Simulation ……………..……………………………… 7

3.1 Contingency Analysis ………………..……………………….. 7

4. Economic Analysis……………………………...……………………. 8

5. Future Work…………………………………………………….……. 9

Appendix A: Work Breakdown ………….………………………………… A1

Appendix B: Contingencies to be Evaluated.……………………………… B1

Appendix C: References……………..……………………………………… C1

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1. Introduction

1.1 Project Background

Idaho Power wants to modify/replace a remedial action scheme for the Borah West Path located in Southern Idaho. The path is subject to transmission line overloads following the loss of two transmission lines. This revised scheme is to include the impact of ambient temperature changes within the path. This is important because the ambient temperature effects the ampacity transmission lines can handle. The transmission lines we are concerned with are the two lines connecting Borah and Midpoint as well as the line running from Kinport to Midpoint, refer to figure 1 below.

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Figure 1: Borah West Transmission Path

With the addition of thermal monitoring of ambient temperature the new mitigation scheme may be able to avoid dropping generators for most of the contingencies. The current mitigation scheme trips a generator unit at the Jim Bridger power plant as the first action in the mitigation scheme. This is an undesirable action because it is very costly to bring a generator back online once the power system is stable again, as well as the costs lost for every minute the generator is offline.

1.2 Project Definition

Due to the growth of Boise and surrounding southern Idaho areas, the Borah West Path has had an increase in power flowing through the path. With the addition of thermal monitoring, a more accurate prediction of when the transmission lines will exceed their thermal limits can be obtained. By knowing the time it takes to change from a nominal temperature to maximum allowable temperature we will be able to design an updated mitigation scheme.

The final mitigation scheme will include a time range for the lines to exceed maximum temperature levels depending on the magnitude of current flow as well as the ambient temperature. The current flowing through the lines will tell us how fast the temperature is going to change, defining a time period over which to run the mitigation scheme. Ambient temperature monitoring will tell us how much the temperature can change, which will narrow or increase the amount of time we have for the mitigation scheme to act.

The mitigation scheme should be designed to avoid generator dropping in the early stages. If actions using series and shunt capacitors do not stabilize the system then generator tripping is allowed. If the system is still unstable often the two Jim Bridger generators are tripped then we must determine what loads need to be dropped to stabilize the system. The mitigation scheme should also keep voltage deviations below 5% of nominal voltage for a one line loss case, and 10% for a two line loss case. The conductor temperature can not exceed 100 C after a double line loss for more than fifteen minutes and for normal operating conditions the conductor temperature should not exceed 80 C.

2. Concepts

2.1 Thermal Line Monitoring

In order to find the ampacity (maximum current carrying capacity) of an overhead conductor, it is necessary to consider thermal effects. This analysis begins by finding a maximum operating temperature for the conductor based on manufacturer supplied specifications [1]. Once a base operating temperature is chosen for the conductor, it can be said, in the dynamic sense, that the ampacity is mainly dependent on ambient temperatures (outside air temperature for this case), wind and intensity of sunlight [2]. The line has heat inputs of |I|2Rac where |I| is the magnitude of current through the line and Rac is the alternating current resistance of the line at 60Hz (which is also temperature dependent), and sunlight heat input which is proportional to absorptivity (absorptivity is the inverse of the thermal conductivity). It also holds that the heat output of the line is equal to the convected heat and the radiated heat combined. Convected heat is proportional to wind speed, while radiated heat is proportional to the emissivity (or thermal conductivity) of the line [3]. When the conductor is at its maximum operating temperature and the heat output is equal to the heat input. The ampacity of the conductor is the magnitude of the current flowing through the line at that time, as shown by the Aluminum Electrical Conductor Handbook[1].

This ampacity may be assigned to be a fixed value for a conductor by assuming a maximum ambient temperature of operation (i.e. 40 degrees C, or 104 degrees F), and a maximum conductor operating temperature (i.e. 80 degrees C, or 176 degrees F). This gives a conservative, not fully optimized base value of ampacity. Idaho Power terms this as the “summertime rating” of the line.

The premise of this paper is an approach using inputs of actual ambient temperatures, wind speed, and time of day. These inputs would then yield an associated ampacity. However, since the base limits of ampacity have already been established by Idaho Power, it is in the scope of this research to focus on finding the change in ampacity based on a change in ambient temperature from that of the base ampacity [2]. This increase or decrease in conductor ampacity may be calculated using (6), based on IEEE standard 738-1993[3].

Equation (1) shows the heat balance of the conductor when the conductor is at operating temperature, and is an equation that relates weather conditions to ampacity. Equation (3) is a heat balance equation of a current rating, under old conditions. Equation (4) is a new heat balance equation of a current rating under new conditions and the same unchanging conductor attributes (i.e. wire size and type) as the previous conditions. Equation (6) shows that a factor may be developed that gives the ratio of the new ampacity to the old ampacity. For example if the factor from equation (6) is AF=|I2|/|I1|=1.2 and the old ampacity of a conductor was 100Amps at an old temperature, the new ampacity at the new temperature and conditions would be (1.2)(100Amps) =120Amps.

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Where qc is the convected heat, qr is the radiated heat, qs is the heat absorbed by the sun, and |I|2Rac is the heat input to the conductor due to power loss in transmission. This does not take into account hot spots (areas of no wind), or where conductors are going from above ground to below ground (i.e. insulated cables in conduit).

2.2 Series Capacitors

A series capacitor is used to take reactance out of the transmission system. Since transmission lines are mostly inductive, the addition of a series capacitor into the line cancels out the inductive reactance induced into the line.

The inductance in the transmission line makes the current lag the voltage, which takes some of the real power out of the system and shifts it into reactive power. Adding the capacitors to the system shifts the voltage back so some of the reactive power is then shifted back into real power.When a series capacitor is bypassed, some of the current is shifted out of the line, decreasing the line losses which where causing the line to overheat.

Where XL is the line reactance, XC is the reactance of the series capacitor, and |V1| and |V2| are the voltage magnitudes at two busses and (1 and (2 are the phase shifts between the voltages.

The advantages of using series capacitors are the following:

1) The ease of implementation.

2) The efficiency of the system.

3) The cost of implementation.

Implementing the series capacitor banks is done at a substation and can be implemented without taking the line out of the system. The initial installation can be done without putting the capacitor bank into the system. Once the bank is installed at the substation the, capacitor bank can be connected to the transmission lines with a switch in the connecting lines to put the capacitor bank into the system.

The series capacitors don’t affect the consumer directly when they are bypassed. The capacitors are simply switched out of the system to allow less power flow through the lines adjusting time.

2.3 Generator Dropping

Dropping a generator is used when the generator is sending out more power that the system is using. The extra power is then consumed in the power lines which, causes over heating. When a fault occurs there is too much voltage for households to consume, and as a result the electronics in the house holds will get overloaded and burn up. The generators that are dropped will take hours to bring back into the power system.

The advantage to generator dropping is that it takes very little effort to switch the generator out of the power system. By knowing the general area that the fault occurs in, any generator supplying power to that area can be dropped with literally the flip of the switch.

The disadvantage of dropping a generator is that getting the coal plants at Jim Bridger back in the power system takes hours. Shutting a generator off without gradually slowing it down can cause mechanical damage to the generator. The generator must be inspected to make sure is operational before it can be reconnected to the power system. The generator then has to be inserted at the right time when all of the transmission lines are in phase with each other or it could cause the power system to have huge current spikes in it. This could take several hours for the phases to line up. If a 560MVA Bridger Generator is taken out of the power system for six hours at the current cost for electricity, it would cost Idaho Power $14,110.00.

2.4 Load Shedding

Load dropping is used when a line faults and the towns and industries are consuming more power than the remaining transmission lines can handle. The flow of the lines is observed and load that needs to be dropped is automatically dropped. The loads will be dropped long enough for Idaho Power to put the faulted lines back into the power system.

The advantage of load dropping is that it cuts the power flow through the system. In this case a load is a section of town or possibly a whole town. Dropping a load in a power system is used if there is too much power being consumed and not enough power being generated. This is a very effective way to make sure the system as a whole stays running.

The disadvantage of dropping loads is that a section of a town loses power. When the consumer loses power the power company loses money. If a 22 MW load is dropped for one hour at the current cost of electricity it would cost Idaho Power $1,194.

2.5 Concept Selection

This project requires the combination of all four design concepts in order to solve the required contingencies. Utilizing the series capacitors in addition with thermal line monitoring, the Borah West Path’s power transfer capabilities will increase. Load shedding when needed will help with voltage stability. When lines exceed their capacities and all other possible actions have been used then generator dropping will occur to help stabilize the power system. In the order of importance the following should be avoided when solving the contingencies:

1) Avoid tripping generators

2) Avoid dropping loads

3) Avoid bypassing series capacitors

3. PowerWorld Simulation

3.1 Contingency Analysis

The proposed method for contingency analysis is to use the program PowerWorld Simulator to perform N-1 (single line outage), N-2 (double line outage), and bus fault (substation outage) contingencies. The desirable method for contingency analysis, given the limitations of PowerWorld for calculating thermal models and doing analysis on all temperature and wind levels through the area, would be to scale all values of ampacity by a factor (in %) given by equation 5. This would provide a way of producing contingency analysis with varying levels of ampacity, with consideration to varying weather conditions.

It is assumed that Idaho Power has calculated all steady state base values of ampacity at a level of 40 degrees Celsius as an industry standard, with a conductor operating temperature of 80 degrees Celsius. Based on this, it is possible to calculate an increased or decreased ampacity based on current weather conditions and time of day. This would also give Idaho Power flexibility in choosing methods of determining ampacity factors, which when input into regression equations would yield appropriate results. This opposed to re-calculating a value of ampacity from scratch, and from re-establishing regression equations, which may be a time consuming effort for Idaho Power in the event hot spots or anomalies to the equations are discovered.

For example, were there to be a need to alter compensation in wind readings (such as for a conductor that begins to show hot spots in low winded areas), it may be necessary to alter the regression equations if temperature and wind parameters were included in regression calculations. However, it would provide more flexibility to have an ampacity factor as an input, which would give a stable base for regression equations to be calculated without needing to be modified.

A separate set of equations for calculating this ampacity factor could then be developed, which would yield an appropriate input to the regression equation. For example, 1350-H19 62% IACS in still air, ambient temperature of 40 degrees Celsius, conductor temperature of 80 degrees Celsius, is 525 Amps. At 20 degrees Celsius, the ampacity under the same conditions would be 650 Amps[1]. An alternate to this approach would be to simply multiply the 525 Amps by an ampacity factor of 650/525, or 124%. Performing contingency analysis under 40 degrees Celsius would be done by setting the maximum ampacity of the system at 100%; at 20 degrees Celsius contingency analysis could be performed by setting the maximum ampacity of conductors to 124% of their normal rated value at 40 degrees Celsius. This would apply across all overhead conductor types, given a calculated factor which is the most conservative of all conductor types for the said changes in ambient temperature.

Following setting the limits of conductor ampacity, Orlando Ciniglio has recommended limiting bus Voltage from 0.9 per unit to 1.1 per unit during an N-2 outage. He has also recommended providing limits of 0.95 to 1.05 per unit during an N-1 outage. Given these conditions, we are assuming a limit of 0.9 to 1.1 per unit for a bus fault.

By scaling the ampacity limits of conductors, this would provide for use of the contingency analysis program in PowerWorld without modifications to the program or serious modifications to inputs. It is in the view of our team that we do not have enough time available to scale every conductor by a factor that is specific to that conductor only.

Idaho Power supplied a list of N-1, N-2, and bus fault contingencies to solve using PowerWorld. There is also 13 system starting conditions that need to be taken into consideration. The required contingencies and system initial conditions can be found in Appendix B.

4. Economic Analysis

This projects cost consist primarily of labor costs, software costs, document costs, and presentation/meeting costs. The proposed budget is shown in the following table; the table displays costs already incurred and all foreseen future costs. The hours per week are only an estimate. There was no set budget for the project.

Table #1. Project Costs

|Investments/Costs |Hours |Total |Total |Dollars |Total |Budget Source |

| |per Week |Weeks |Hours |per Hour |Item Cost |  |

|Student Time |15 |26 |390 |$50.00 |$19,500.00 |UofI |

|Faculty Time |2 |26 |52 |$150.00 |$7,800.00 |UofI |

|Laboratory Facility |10 |4 |40 |$25.00 |$1,000.00 |UofI |

|PowerWorld Simulator |  |  |  |  |$12,000.00 |Idaho Power |

|IEEE 738-1993 |  |  |  |  |$143.35 |O'Connor ECE Fund |

|Poster Board |  |  |  |  |$14.69 |O'Connor ECE Fund |

|Poster Photo |  |  |  |  |$45.00 |O'Connor ECE Fund |

|  |  |  |  |Projected Total Cost: |$40,503.04 |  |

The PowerWorld simulator was supplied by the teams sponsor, Idaho Power, and that IEEE document was funded by sponsors to the EE Senior Design Project Funds. Because this projects main deliverable is a simulation and a report including a recommended mitigation scheme, the majority of the costs are engineering costs.

5. Future Work

In order to finish this project by next December we have decided to try and accomplish some of the work involved over the summer. We are all going to continue to do PowerWorld scoping in order to properly run simulations. Also this summer we will be doing contingency analysis on the base case and explore the effects each possible contingency action has on the Borah West Path for the required outages. Mark will explore the N-1 contingencies, Jason will explore the bus fault contingencies, and Kyle will explore the N-2 contingencies. This should prepare us to implement thermal monitoring to the remedial action scheme next fall.

In the fall we will be ready to start implementing thermal monitoring. For our remedial action scheme we will be using an ambient temperature of 40C. We will be developing an equation to calculate the amount of time the remedial action scheme has to act before the conductor temperature rises above the maximum allowable temperature. The next step is to incorporate this temperature equation into the Borah West Path operating transmission capability limit equations. These equations will then dictate what actions need to occur and when they need to occur in the mitigation scheme.

The scope of this project has been limited by enlarge due to time constraints. Suggested items that would be of benefit to Idaho Power for future analysis would be: Voltage stability analysis, review of overhead line locations for the full length of their run to determine critical spans or hot spots, possible methods of mitigating potential hot spots.

Appendix A:

Work Breakdown Summary

Summer Schedule

Fall Schedule

A1

Appendix B:

Contingencies Required

A. Line Outages

N-1 Contingencies:

1. Midpoint- Summer Lake 500kV line

2. Borah-Adelaide #2 345kV line

3. Borah-Adelaide-Midpoint #1 345kV line

4. Midpoint-Adelaide #2 345kV line

5. Kinport-Midpoint 345kV line

6. Borah-Hunt 230kV line

7. American Falls-Minidoka 138kV line

8. Minidoka-Adelaide 138kV line

9. Minidoka-Unity 138kV line

10. Unity-Heyburn 138kV line

11. Adelaide-Heyburn 138kV line

12. Adelaide-Heyburn Jct- Heyburn-Paul 138kV line

13. Hunt-Milner Jct.-Paul 138kV line

N-2 Contingencies:

14. Borah-Adelaide #2 & Midpoint-Kinport 345kV lines

15. Borah-Adelaide #2 & Borah-Adelaide-Midpoint#1 345kV lines

16. Borah-Adelaide #2 & Midpoint-Adelaide #2 345kV lines

17. Borah-Adelaide #2 & Borah-Hunt 230kV lines

18. Midpoint-Kinport & Borah-Adelaide-Midpoint #1 345kV lines

19. Midpoint-Kinport & Midpoint-Adelaide #2 345kV lines

20. Midpoint-Kinport 345kV & Borah-Hunt 230kV lines

21. Borah-Adelaide-Midpoint #1 & Midpoint-Adelaide #2 345kV lines

22. Borah-Adelaide-Midpoint #1 345kV & Borah-Hunt 230kV liens

23. Midpoint-Adelaide #2 345kV & Borah-Hunt 230kV lines

B. Bus Faults:

24. Adelaide 345kV bus

25. Adelaide 138kV bus

26. Borah 230kV bus

27. Borah 345kv bus

28. Hunt 230kV bus

29. Midpoint 230kV bus

30. Midpoint 345kV bus

B1

C. Initial System Conditions:

1. System Normal

2. Borah-Adelaide #2 345kV line out

3. Midpoint-Kinport 345kV line out

4. Borah-Adelaide-Midpoint #1 345kV line out

5. Midpoint-Adelaide #2 345kV line out

6. Borah-Hunt 230kV line out

7. American Falls-Minidoka 138kV line out

8. Minidoka-Adelaide 138kV line out

9. Minidoka-Unity 138kV line out

10. Unity-Heyburn 138kV line out

11. Adelaide-Heyburn 138kV line out

12. Adelaide-Heyburn Jct-Heyburn-Paul 138kV line out

13. Hunt-Milner Jct-Paul 138kV line out

B2

Appendix C:

Reference List

[1] M. Walker, “Aluminum Electrical Conductor Handbook, Second Edition”, The Aluminum Association, 1982, section 3-7 to 3-26.

[2] T.A. Short, “Electric Power Distribution Handbook”, CRC Press, 2004,

pp. 59-71.

[3] G.A. Davidson, “IEEE Std. 738-1993”, IEEE, 1993, pp 1-47

[4] J. Grainger and W. Stevenson, “Power System Analysis”, McGraw-Hill, 1994, pp. 591-637.

[5] A.S. Debs, “Modern Power Systems Control and Operation”, Springer, 1988, pp. 87- 139.

[6] C. Gross, “Power System Analysis”, John Wiley & Sons, 1986, pp. 230

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