# Presentation: 055551

## SW Oregon Coast Reinforcement Project

- Anthony Radcliff
- Transmission Planning
- Bonneville Power Administration

## Background

- The southwest Oregon load service area extends from Fairview to Brookings, serving the City of Bandon, Coos Currey, and PAC’s Isthmus and Coquille feeders.
- The area is served by two 230kV and one 115kV lines from Alvey, Dixonville, and Reedsport respectively.
- The loads served south of Fairview are served with looped service via a 230kV line from Fairview to Rogue and a 115kV line from Bandon to Rogue.

## Challenges

- The weakest portion of the system are both radial lines served from Rogue down the southern Oregon coast to Brookings and Harbor on Coos Currey’s system.
- The southern Oregon coast is a winter peaking system with the worst contingency being the loss of the Fairview-Rogue 230kV line.
- The contingency possibly causes voltage instability, depending on the load level, rather than thermal limit overloads.
- Previous studies recommended constructing a 46 mile long 115kV from Bandon to Rogue to mitigate the voltage instability problems.

## South of Fairview Service Area

## Reactive Power Margin

- Bottom of the QV Curve = 4MVARs
- 90% voltage = 1MVAR
- Initial point violates BPA’s voltage criteria
- Maximum switch-able (8% voltage swing) = 7MVARs....too small!

- 8% Voltage
- Swing

- 7MVAR

## Original Plan of Service: Transmission Line

- New 46 mile long Bandon-Rogue 115kV line constructed to 230kV specification for later upgrade
- 1.1in ACSRTW Rogue conductor was chosen
- Initial estimates:
- Line, Towers, etc... =  $25M plus
- Land/Environmental Survey = $3.6M
- Land/New right of way = $$$$$
- Performance
- Line could be put into service between 2008-2010
- Voltage support would be needed by the 2015 predicted load level
- Options available at that time:
- Upgrade to 230kV
- Requires transformer at Bandon ($5M-$7M)
- SVC at Rogue
- Only small amounts of reactive can be switched without large voltage changes

## Other Considerations on the New Transmission Line

- Light loading conditions
- Area experiences high voltages under light loading conditions that may damage equipment
- Adding another line may aggravate high voltages
- The new line will place other lines below their surge impedance loading, causing them to produce more reactive power than they absorb
- More available reactive power will boost voltages
- Area is under light loading conditions most of the time
- Conductor size
- A larger conductor than necessary (thermal loading) was specified due to the voltage support required
- Adds to the cost of the project

## Other Options Considered

- The drawbacks of the new line project caused another round of studies aimed at finding a non-transmission line solution
-  Main deterrent was price.... $35M to $45M
- Other options:
- Multiple switched shunt capacitor groups
- Would require many due to switching sensitivities and coordination would be difficult
- Series capacitors
- Tapped transmission line would make placement difficult due to voltage profile caused by series capacitor group
- Short transmission lines (distance in km should exceed voltage in kV)
- Static VAR Compensator (SVC)
- Continuous reactive power output (switching sensitivities no longer a problem)
- Can mitigate light loading/high voltage issues
- Supports voltages to the predicted 2016 load level, outperforming the transmission line
- The next limitation on the system is the thermal limit of the Bandon-Rogue 115kV line

## Static VAR Compensator

- The Static VAR Compensator (SVC) became Planning’s preferred plan of service of the alternates to the new transmission line.
- SVC Specification:
- 40MVARs inductive/45MVARs capacitive
- Initial estimate for a turnkey device was $5M
- An additional $2M in site development, communications, and high voltage connections
- Pros
- Solves voltage instability issue
- Delays new line construction nine years
- Cost less than a new transmission line
- Mitigates high voltage issues
- Could be on-line in 14 months
- Cons
- Maintenance: cooling systems, remote location, and untrained personnel
- New line may be required in the future
- The studies showed that if the load continued to grow, both projects would be needed eventually

## Factors Considered in Project Selection

- Matrix Team
- A group of BPA employees consisting of engineers and financial analyst assigned to evaluate projects and give their recommendation to management
- Risk mapping
- Financial Agency Target
- Legal Impacts
- Environmental
- External Stakeholders
- People and Processes
- Reliability
- Each area is graded on severity of impact
- Can be used to compare competing projects
- The line and the SVC would score the same in most categories except Financial Agency Target and Environmental impacts
- New line cost considerably more and would require land in possibly sensitive areas

## South Oregon Coast

## Geographical Map

## System Map

## South of Fairview Service Area

## System One Line

## Project Timeline By Need Date

- 2006

- 2007

- 2008

- 2009

- 2010

- 2011

- 2012

- 2013

- 2014

- 2015

- 2016

- 2017

- 2018

- 2019

- 2020

- 2021

- 2022

- 2023

- 2024

- 2025

- 2026

- 2027

- 2028

- 2029

- 2030

- 2031

- Add SVC first

- Add new line with SVC in place

- Add new line first

- Add SVC with new line in place

- Additional MVARs

**Project**