SURGES -- Re-rating AEP

TRANSMISSION LINE RE-RATING PROGRAM BY THE NUMBERS IMPCO

»» 22 circuits studied

OPCO

»» 40 line assets studied

»» 57 circuits studied

»» 70%: line assets with potential LOCs

»» 114 line assets studied

»» 467 miles studied

»» 62%: line assets with potential LOCs

(left). Crew installs

»» 2,476 spans studied

»» 956 miles studied

suspension clamps to

»» 1,551 MVA: estimated capacity increase to system*

»» 4,631 spans studied

282 new steel poles.

Steel pole readied to replace lattice tower

PHOTOS: POWER ENGINEERS

finish installation (right).

»» 5,196 MVA: estimated capacity increase to system*

»» 1949: the average year the studied lines were built

RE-RATING AEP

»» 1956: the average year the studied lines were built

POWER helps add 9,000 megawatts of capacity to AEP’s grid

WPCO

»» 4 circuits studied

By Kate Wutz

I

»» 8 line assets studied

magine improving a portion of an interstate highway to allow more traffic to flow through more efficiently.

Now, instead of asphalt and cars, imagine conductors and current, and lengthen the distance of that “portion” to about 2,000 miles—the equivalent of driving from Columbus, Ohio, to Tulsa, Oklahoma, and turning around and heading back to Roanoke, Virginia.

That analogy should give you some idea of the vast challenges POWER faced when it embarked on a four-year re-rating effort for client American Electric Power (AEP) in 2011.

Suddenly, the newly christened Transmission Line Re-Rating Program became what AEP referred to as the “biggest and most complicated transmission project of its kind in AEP history,” involving 2,000 miles of transmission line alone, plus distribution and communication circuits.

...the “biggest and most complicated transmission project of its kind in AEP history,” involving 2,000 miles of transmission line alone...

»» 36 miles studied »» 139 spans studied

KPCO

»» 295 MVA: estimated capacity increase to system*

»» 7 circuits studied

»» 1945: the average year the studied lines were built

»» 15 line assets studied Identifying LOCs

POWER Engineers and IJUS, an engineering firm based in Ohio, partnered to perform the re-rating studies and identify specific “locations of concern,” referred to as LOCs. Once specific LOCs were identified, POWER set to work to find solutions for raising load Modest beginnings capacity. This effort soon included Except, it didn’t start as a 2,000-mile project. It started when AEP POWER’s Environmental and GIS divisions as well, who racked up identified roughly 244 miles of line that needed to be re-rated, or 148,000 labor hours over the course of the next four years. modified to carry a greater load.

POWER used LiDAR survey data provided by AEP to created However, the project was boosted to a new level by PJM 3-D computer models of 237 line segments and then studied those Interconnection, the regional transmission operator that coordinates models to evaluate future load increases. POWER’s team identified the movement of wholesale electricity in 13 states, including Ohio, 302 LOCs, most of which involved ground or distribution line Virginia, West Virginia, Kentucky, Michigan and Indiana— clearance issues—giving rise to the colloquial name for this project, including AEP’s service area. the “AEP Sag Study.”

PJM identified approximately 1,600 miles of AEP transmission lines that needed to be modified by 2015 in order to meet a pro- POWER’s solutions jected increase in load—widening the electric highway in order to AEP already knew that remediating these LOCs would increase deal with an expected rise in traffic. This load increase would be the capacity of their grid and allow them to meet PJM’s increased spurred by the retirement of coal-fired generation in the region. load-rating projections. POWER’s team identified and categorized The circuits carrying the replacement power needed to be rated potential LOCs according to the type of remediation necessary, to handle it. then developed tailored solutions for each one.

10 Surges January 2016

»» 50%: line assets with potential LOCs

»» 53%: line assets with potential LOCs identified »» 87 miles studied »» 400 spans studied »» 336 MVA: estimated capacity increase to system* »» 1968: the average year the studied lines were built

APCO

»» 26 circuits studied »» 60 line assets studied »» 45%: line assets with potential LOCs »» 484 miles studied »» 2,225 spans studied »» 1,650 MVA: estimated capacity increase to system* »» 1960: the average year the studied lines were built

KEY Transmission lines included in the Re-Rating Program Transmission lines owned by AEP, but not part of the Re-Rating Program

*MVA calculations note The estimated system capacity increases were calculated by summing the anticipated rating increase for each circuit. It was assumed that the starting maximum operating temperature for each line asset was 203°F, which was used in conjunction with the re-rated maximum operating temperature to determine an increased ampacity (MVA) for each segment.

January 2016 Surges 11

COST

37 lattice tower mods.

Installing a cage

SCHEDULE

VALUE MANAGED

Return on Investment

extension into an existing

SCOPE

345 kV double-circuit

WORKING SMARTER

lattice tower structure to make it taller. ($220/MVA-Mile Estimated Cost)

PHOTOS: POWER ENGINEERS

$4.0 B

“Sag,” in simplest terms, is the “swoop” a conductor makes between two poles. According to AEP, engineers design sag—also known as a catenary curve—in transmission line to achieve efficient power delivery and also safe clearances between the line and other lines or the ground. “Sag” also changes with the weather, as cold causes the metals in a conductor to contract, and warm weather—or heavy power usage—can cause the line to expand as a result of an increase in temperature.

Though it might not seem to matter much, the ideal amount of sag in a line is carefully calculated based on factors such as structure height, span between structures, conductor capacity and topography. Too little sag, and the line might not be able to withstand storms, causing service to be less reliable. Too much sag, and a line can dip too low, causing clearance concerns. If a line is dipping much lower than expected, it can indicate that the line is carrying a load larger than it’s designed for.

POWER recommended the installation of 282 new steel poles, working seamlessly with the engineering staff. The project team attaching catenary weights on 117 segments to equalize the sag used standard materials as much as possible, reducing the lead time between two spans, resolving vegetation issues on 547 spans and on materials in order to meet the tight schedule. POWER closely right of way encroachments on 48 spans. coordinated with AEP procurement to identify, track and expedite Rather than replacing roughly 37 more lattice towers, POWER critical materials to take full advantage of outage opportunities. recommended modifying the height instead, as well as installing They also worked to maintain flexible project schedules, allowing floating dead-ends on 17 towers and removing 86 swing angle adjustments for sponsor priorities, outage opportunities and brackets. resource availability.

POWER also identified 121 spans with LOCs involving distribution or Process improvements communication lines, most of which were POWER offered solutions not only for relocated to solve the problem.

AEP’s LOCs, but also for streamlining processes. POWER’s project team Time and resources crunch created a standardized re-rating The project rapidly evolved from request form that was consistently 244 miles to 2,000 miles of re-rating applied for each circuit, defining scope studies, with the same fixed June 2015 of work, potential LOCs and proposed PJM-set deadline in place. AEP needed remediations. Team members from the work to be done on time, even though the scope was quickly each discipline were required to sign off on these forms, ensuring expanding, forcing POWER to find innovative ways to solve the an accurate record of the study and any action that resulted. sag concerns.

POWER’s approach to permitting has been integrated into POWER subcontracted all non-transmission LOCs to IJUS, other AEP transmission projects as well. Prior to any construction who coordinated with the owners of these distribution and personnel engaging in the project, POWER’s environmental team communications lines to identify issues, manage remediation and had obtained and compiled all environmental and access permits inspect all final solutions after construction. into a permit book. Permit book completion was required before any POWER’s environmental team worked tirelessly to obtain all field activities started, eliminating the possibility of construction environmental and access permits required for the remediation, delays due to permitting.

POWER offered solutions not only for AEP’s LOCs, but also for streamlining processes.

12 Surges January 2016

REMEDIATION COST

SO WHAT’S SAG?

$72.6 M

dO uil eb R te ple om

on pti

n Optio Rate d Ree g a n Ma Value C

($4/MVA-Mile Actual Cost)

9,000 MVA SYSTEM CAPACITY INCREASE

The value-managed scope satisfied the sponsor’s need to increase the operating capacity on more than 2,000 miles of AEP transmission lines, and left sufficient budgets to support other high-value AEP projects in 2012–2015.

POWER’s GIS team found an innovative way to track outages. The team knew that identifying, obtaining and tracking outages would be complex and difficult. So, they developed an overlay for the AEP Transmission GIS program that displayed requested outages with respect to time. At a glance, all involved could see outage status and windows, keeping everyone aware of these crucial windows.

Huge savings

2015 saw the completion of this massive project. At final tally, AEP was able to add the equivalent of 9,000 megawatts of capacity to its grid, relieving the anticipated stress on the lines following the coal-fired generation retirement.

AEP estimated that the $72.6 million project price tag is equivalent to the annual sale of the 9,000 megawatts of additional power capacity, at $8,000 per megawatt. This represents a huge savings to AEP—rebuilding all of the affected lines could have cost up to $4 billion. And it was only possible through close collaboration among POWER, AEP and affected stakeholders.

“I cannot say enough about the teamwork and cooperation we had over the years,” says Ed Caldwell, AEP’s project manager. “Everybody worked together.

It was a devoted staff of people.”

With POWER’s help, AEP was able to extend the service life of 116 circuits, allowing the utility to accommodate PJM’s load growth expectations for 2015 and beyond.

Kate Wutz is a marketing and proposal coordinator for Power Delivery Division in Hailey.

Program Deliverables 110 engineering issue-forconstruction (IFC) documents

90 environmental permit books

275 estimated material requests issued

116 Transmission Line Re-Rating forms

2,250 estimated number of plan and profile drawings issued for record

KEY CONTRIBUTORS Tim Kautz, T-Line Engineering Sponsor Pat Hanna, Program Manager Tim Kritis, Project Engineer Ryan Weyant, Project Engineer Kevin Wortmann, Project Engineer Scott Brondyke, Project Coordinator Jaime Newell, Environmental Lead Anette Dearden, Environmental Lead Tim Shiffer, GIS Coordinator Mark Colbert, Drafting Coordinator Tanya Barrus, PMA Jon Ferguson, Corporate Sponsor January 2016 Surges 13