HomeMy WebLinkAboutRisk Assessment of the Four Dam Pool Hydroelectric Projects; Volume 1-Main Report 1996• .
Risk Assessment of the
Four Dam Pool Hydroelectric Projects
Volume 1-Main Report
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Solomon
Gulch
Project
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Prepared for
the Alaska Energy Authority
and the Four Dam Pool Project Management Committee
by
I-IARZA
Engineering Company
February 1996
Swan Lake
Project
I-IARZA Consulting Engineers and Scientists
---·-----
Mr. Daniel W. Beardsley
Contracts Manager
Alaska Energy Authority
480 West Tudor
Anchorage, AK 99503
Mr. Edwin K. Kozak, P.E.
General Manager
Kodiak Electric Association, Inc.
515 Marine Way
P.O. Box 787
Kodiak AK 99615
Subject: Risk Assessment of the
Gentlemen:
Four Dam Pool Hydroelectric Projects
Final Report
February 8, 1996
We are pleased to present our final report on the Risk Assessment of the Four Dam Pool
Hydroelectric Projects. At your direction, we are furnishing copies also to the operating utilities
and their representatives.
We have considered all of the information that was furnished during the course of the study, with
particular emphasis on your commentary furnished during the review of the draft report. Of
course, there are diverse interests, and we have provided our opinion on many issues. In some
areas, additional investigation is warranted. One example of where additional investigation is
warranted relates to the issues surrounding the Terror Lake diversions and tunnel.
We have appreciated the opportunity to carry out this challenging assignment, and are confident
that the information contained in this report, and the opinions provided by our engineers, will
prove to be valuable in your divestiture efforts.
2353 130th Avenue N.E., Suite 200 Bellevue, Washington 98005
Tel: (206) 882-2455 Fax: (206) 883-7555
RISK ASSESSMENT OF THE
FOUR DAM POOL HYDROELECTRIC PROJECTS
SUMMARY
Harza Engineering Company has carried out an assessment of the possible costs associated
with the continued operation of the hydroelectric projects comprising the "Four Dam Pool."
The projects are:
• Swan Lake Project;
• Solomon Gulch Project;
• Terror Lake Project; and
• Tyee Lake Project.
The following were carried out for each project:
1. A condition assessment was performed to identify the needs for project improvements
and associated costs.
2. A schedule for replacements due to normal wear and tear was identified, along with
associated costs.
3. An assessment of the energy generation potential was made.
4. An analysis of the risks was carried out, probable repair costs and outage duration
were identified; the likely range was identified.
5. Operation and maintenance costs were examined.
The costs were summarized to arrive at a composite annual cost in five-year increments over
a 35-year future planning horizon (1996 to 2030).
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Condition Assessment
As a result of the Condition Assessment, a number of items were identified at each project
that merit attention in the future. In accordance with the Scope of Work, these items are
classified as follows:
• Deficient Design -defined as a condition that does not meet the minimum generally
accepted standards for safety and reliability. Only one item, the Tyee Lake Project
transmission line, was determined to be deficient in design.
• Deferred Maintenance-defined as a condition where either regularly scheduled
maintenance or maintenance to repair a damaged structure or malfunctioning
component was not carried out in a timely manner. Only a few items of deferred
maintenance ware found.
• Other Project Improvements -project structures or equipment planned for replacement
for reasons including obsolescence, unavailability of spare parts, premature failure, or
changing operating conditions, equipment and structural repairs or modifications that
have not been deferred, but are now required to correct a malfunction, or to improve
functionality or safety. Other project improvements may also involve studies to
address operational or design issues. In some cases, the implementation of these items
is discretionary in nature.
A summary of the condition of each plant is presented below.
Swan Lake
The Swan Lake Project is considered to be in excellent condition, with only one item of
deferred maintenance and several needed replacements and project improvement items. A
major deferred maintenance item involves the need to paint the transformers at the Bailey
substation and replace corroded cooling radiators. The major items of replacement involve
the generator excitation system and replacement of the battery system. Present plans and
budgets include the replacement of the draft tube bulkhead gates with stainless steel
replacements and installation of a new intake gate feeder power supply cable is planned.
A continuing maintenance item is the collection and clearing of trash and debris that
accumulates in front of the power intake. The possibility of improving the trash boom and
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acquiring a tugboat and log skidder for handling trash and logs should be considered.
A portion of the transmission line is exposed to landslide risk, and is a major potential source
of plant outage. A landslide stabilization study should be carried out to identify corrective
measures, or alternatively, one to two miles of transmission line could be considered for
relocation to eliminate this hazard.
Solomon Gulch
The Solomon Gulch Project is considered to be in good condition. The only major area of
concern is corrosion of the penstocks. The rate of corrosion is being monitored. Painting the
exterior of the penstocks would be prudent to improve resistance to corrosion and extend the
useful life. In general, the penstock is expected to perform satisfactorily for the next 36
years, but there may be a need for repair in local areas where corrosion is advancing at a
higher rate.
The penstock valves are reportedly capable of closure against full turbine discharge, but
cannot close against the flow that would result in the event of a penstock rupture. In view of
the long portion of exposed penstock, and the corrosion problem that is being monitored, it
would be prudent to replace the penstock valves to provide protection in the event of penstock
rupture. Any deficiencies in the penstock intake bulkheads would need to be corrected to
carry out this work.
The major source of plant outage is the 112 mile transmission line. The section between the
Meals and Pll substations is particularly susceptible to avalanche outage. Consideration
should be given to installation of buried cable in areas susceptible to avalanche outage.
Another source of concern is the settlement of the Pll substation building. Corrective
measures should be implemented to prevent interruption of service if the settlement continues.
Terror Lake
The Terror Lake Project is considered to be in generally good condition. However, there are
some structural aspects that require maintenance and remedial repair measures. The major
aspects that require attention involve the repairing excessive leakage at the intake gate,
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performing tunnel repairs, and reinforcing the side channel spillway at the main dam.
The Rolling Rock diversion is believed to be a source of sediment that causes excessive
turbine wear. The construction of a sand sluicing system was started, but was not finished
because of problems with the contractor. More detailed study should be carried out to
determine the most efficient way to resolve the sediment problem. Possible solutions could
involve completion of the installation of the sediment discharge system or abandoning Rolling
Rock as a diversion, while allowing it to remain in place to function as a surge facility.
The Terror Lake facility was recently affected by a large flood. Some of the project buildings
at the powerhouse site are at-risk due to flooding from the Kizhuyak River. Permanent dikes
and river training facilities should be designed and constructed.
Tyee Lake
Except for the transmission line, the Tyee Lake Project is considered to be generally in good
condition. Some structural maintenance that is required involves shoring up housing and
storage buildings at the site, and reinforcing the exposed rock face that forms the back wall of
the powerhouse. An inspection of the unlined power tunnel by use of a remotely operated
vehicle to evaluate its condition would be prudent.
The transmission line is the source of many outages. The transmission line is considered to
be deficient in design since ground clearance criteria is not met under loading conditions that
could have been reasonably foreseen at the time of design. Studies are underway (by others)
to address corrective measures.
Electrical controls to the gate house for remote operation would improve operation and safety
in the event of an emergency situation. Dredging of the harbor will improve access.
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Energy Generation Potential
Analysis of the energy generation potential results in the following estimates of average
annual generation potential:
Swan Lake Project -
Solomon Gulch Project-
Terror Lake Project -
Tyee Lake Project -
Four Dam Pool Total -
70.1 GWh per year
52.9 GWh per year 3q_ f-.
117.0 GWh per year 'f '
109.0 GWh per year
349.1 GWh per year ~~) \oD J 'U
The output of Tyee Lake is limited by the electrical demand in the areas served by the
project. The proposed intertie with the Swan Lake Project would help better utilize the
generation potential of the Tyee Project.
The Terror Lake powerhouse was designed to accommodate the addition of a third unit. A
preliminary cost analysis indicates that the addition of a third 12.5-MV A generating unit at
Terror Lake warrants additional feasibility level investigation. The third unit will not provide
additional energy, but will provide additional peaking capacity that is needed in the system.
Additional expansion options at Tyee and Swan Lake projects do not appear warranted at this
time. At Tyee, the operating capabilities are not fully utilized because of limited electrical
demand. At Swan, increasing the storage or generation capacity appears to be expensive in
comparison with other possible generation options that may be available, if the need does
indeed exist.
The output of Solomon Gulch is limited by the electrical demand in the areas served by the
project. An expansion of the storage capacity is not warranted or economically justified
based on a detailed study performed in 1992.
Risk Related Costs
The analysis described in the accompanying report included an analysis of cost to repair
structures and components that might be damaged due to natural events, accidents and internal
failures (an unknown failure due to design, construction or material deficiency). The
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associated outage duration was also investigated. The expected annual risk related cost, and
an estimate of the outage that might be associated with the risk-related events, was estimated.
The expected annual cost and outage duration is tabulated below:
Expected Risk-Related Expected Risk-Related
Repair Cost Outage Duration
(1995 US$ per year) (days per year)
Swan Lake Project 159,529 13.4
Solomon Gulch Project 291,464 22.8 ?
Terror Lake Project 349,308 18.9
Tyee Lake Project 312,387 23.5
\ I } l ? ) (,<2<(
Figure 1 presents the cumulative distribution curves that result from the analysis, indicating
the range of possible costs and outage duration for each project.
Although the graphs in Figure 1 illustrate the range and expected probabilities associated with
the anticipated risk related cost and outage duration, there is a possibility of catastrophic
events that will result in very large damage cost and a long outage duration. Financial
planning for covering uncertain events must consider this possibility.
Operation and Maintenance Costs
For this study, operation and maintenance costs are based on an analysis of historical costs,
brought to a common 1995 price level, and averaged. Joint costs are allocated to projects by
prorating on the basis of at-site costs in proportion to the at-site costs of all four projects. The
estimated average annual operation and maintenance cost for all four projects, excluding fixed
charges for debt service and equipment replacement fund contributions, is $6.8 million at the
1995 price level.
Summary of Expected Costs
Table 1 presents a summary of the expected annual costs, in five year increments, for the 35-
year planning horizon considered in this study. All costs are presented in 1995 dollars.
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Table 2 presents a summary of the expected costs for various items. Certain items included
in Table 2 are based on expenditures to take place in the period 1996 to 2000, and are at
1995 price levels. In addition, Table 2 presents the annual costs on a levelized basis for two
separate replacement funds, and the annual risk costs at 1995 price levels.
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Table 1
PROJECTED COSTS
(IN US DOLLARS, AT 1995 PRICE LEVELS, FOR FIVE-YEAR PERIODS INDICATED)
Year
lbNn 1996-2000 ~;:m: 2006-10 E11-l~ 2!!1nJ m;.z 2026-§li
SWANLAKE
Remedial Work for Items d Deficient Design
Remedial Work for Items of Deferred Maintenance 20,000
Other Project Improvements 2,067,000
Replacements due to Normal Wear and Tear . 284 ,400 2,143,600 2,846,400 2,576,600 4,935,128 396,600
Allowances For Replacements Alter 2030 359,309 373,252 408,845 544 ,895 716,926 960,453 1,291 ,170
Normal Operation and Maintenance Costs 6,643,730 6,643,730 6,643,730 . 6,643,730 6,643,730 6,643,730 6,643,730
Risk Costs m~ Z&1. §:4~ ill~ 7!J.Z§:45 ill §:45 ZllZ~ Zlll §:45
TOTAL-SVVAN LAKE 9,887,684 8,099,027 9,993,620 10,832,670 10,734,901 13,336.956 9,129,145
SOLOMON GULCH
Remedial Work for Items of Deficient Design
Remedial Work for Items of Deferred Maintenance
Other Project Improvements 2,047,700 . . ~s.~31~ Replacements due to Normal Wear and Tear 87,000 205,000 . 2,481,000 3,159,000 4,371,950 13,075,000 87,000
Allowances For Replacements Mer 2030 500,087 500,087 689,205 921 ,846 1,170,715 1,824,810 2,107,806
Normal Operation and Maintenance Costs 6,815,030 6,815,030 6,815,030 6,815,030 6,815,030 6,815,030 6,815 ,030
Risk Costs l ~:iZ 3211 H:iZ32!l Bu32!l l ~5Z :1211 !~3211 H5Z32!l U5Z32!l
TOTAL· SOLOMAN GULCH 10,907,137 8,977,437 11,442,555 12,353,196 13,815,015 23,172,160 10,467,156
TERROR LAKE
Remedial Work for Items of Deficient Design
Remedial Work for Items of Deferred Maintenance
Other Project Improvements 5,207,000
1,195,000 ~l,5~ '((·~ Replacements due to Normal Wear and Tear 785,000 985,000 3,253,000 6,702,438 2,471 ,000 1,914,000
Allowances For Replacements Mer 2030 245,959 245,959 297,056 622,556 1,085,922 1,363,530 1,705,657 10 ~ 500 .
Normal Operation and Maintenance Costs 11 ,911 ,380 11 ,911 ,380 11,911,380 11 ,911 ,380 11 ,911,380 11,911 ,380 11,911 ,380
Risk Costs l Z~!i:i~D l~~ lH!i~D lH!i~D l Z~!i~D l Z~!i~D l~~
TOTAL • TERROR LAKE 19,895,879 14,888,879 17,207,976 20,982,914 17,214 ,842 16,935,450 16,558,577
TYEE LAKE
Remedial Work for Items d Deficient Design 17,000,000
Remedial Work for Items of Deferred Maintenance 565,000
Other Project Improvements 1,685,500
Replacements due to Normal Wear and Tear 880,000 920 ,000 2,839,000 4,940,000 20 ,574 ,344 7,636,408 807,500
Allowances For Replacements Alter 2030 405,592 405,592 508,316 790,337 1,535 ,548 2,765,926 3,183,308
Normal Operation and Maintenance Costs 8,760,110 8,760,110 8,760,110 8,760,110 8,760,110 8,760,110 8,760,110
Risk Costs l ~li!J:i l ~l !!35 l ~lW l:i!il m 15!illl35 l:i!il m l:i!il m
TOT AI.-TYEE LAKE 30,858,137 11 ,647,637 13,669,361 16,052,382 32,431,937 20,n4,379 14,312,853
All FOUR PROJECTS
Remedial Work for Items of Deficient Design 17,000,000
Remedial Work for Items of Deferred Main!.-585,000
Other Project Improvements 11,007,200
Replacements due to Normal Wear and Tear 1,752,000 2,394,400 10,716,600 17,647,838 29,993,894 27,560,536 2,486,100 "';l/551 3C..<i'
Allowances For Replacements Alter 2030 1,510,948 1,524,890 1,903,222 2.879,635 4,509,110 6,914,720 8,287,941 -:L7, ~oo', 'f{,~
Normal Operation and Maintenance Costs 34,130,250 34,130,250 34,130,250 34 ,130,250 34 ,130,250 34,130,250 34,130,250 3~"' o<iO Risi<Costs 5~3~~D ~~H~Q :i~~ :iS~~ 5S3~ 55§3Bl 55§3~
TOTAL -ALL FOUR PROJECTS 71 ,548,838 43,812.980 52.313,512 60,221 ,163 74,196,6194 74,168,946 50,467,731 I
6Jl Table 2 u SUMMARY OF EXPECTED COSTS
(IN US DOLLARS, AT 1995 PRICE LEVELS)
Project
Item Swan Lake Soloman Gulch Terror Lake Tyee Lake Total Per Item
Period 1996-2000 (Total Cost)
Remedial Work for Items of Deficient Design ( 1)
Remedial Work for Items of Deferred Maintenance (1)
Other Project Improvements (1)
Subtotal
Period 1996-2030 (Annual Cost)
Replacements due to Normal Wear and Tear (2)
Allowances For Replacements After 2030 (2)
Subtotal
Period 1996-2030 (Annual Cost, not escalated)
Risk Costs (3)
20,000
2 06Z,OOO 2 o~z.zoo
2,087,000 2,047,700
400,667 665,113
H~52~ 233 ~oa
545,192 898,522
159,529 291,464
5 20Z 000
5,207,000
~
763,053
349,308
17,000,000
565,000
1 685,500
19,250,500
1,175,440
263 024
1,438,464
312,387
17,000,000
585,000
11 OOZ 200
28,592,200 ~~
1,112,688 1 ot.f. V
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(1) Based a several expenditures to take place in the period 1996-2000, at 1995 price levels
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(2) Annuallevelized cost (actual cost remains constant throughout the entire 35-year planning horizon)
(3) Annual cost at a 1995 price level f Aeoc:>J G®--.::::::aL >r\\) ~33}, z 21 \
~
~ -:.yg--([1 s-l '{ '=L?\~ '{!Jlc? ~
Figure 1 -Range of Expected Annual Costs and Outage Days
Range of Expected Annual Costs
100%,---------------------------
90% 00%~======------==~~~= 8 70% !ij ~--;__--~~ ~-~~
"0
., 60% ~ ------~ ~ 50%
~ 40%
:g ---·-----~·--·· ~ 30% --0..
1-1~ 0%
0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9
100%
90%
80%
~bo%. ..
~ 860%
" ~50%
0
~4-
"' ~30%
0..
20%
10%
0%
0.0
100%
90%
80%
!ho%
"' "0
~60%-
" ' ~50%'
~40%
.0 ..
~30%
0..
20% ;--·
10% -0.0
100%
90%
80%
8 70% c ..
) 60"4
" ~ 50% ,..
~ 40%
"
.1!: 30%
20%
10%
0%
0.0
0.1
0.1
0.1
Possible damage or repair cost in any year (in million$)
I SOLOMON GULCH I
0 ~ossib1Namage0o1 repaiPJ.st in a~~ year(~ -rnillionfj
8 0.9
TERROR LAKE ·---·---
0.2 0.3 04 05 0.6
Possible damage or repair cost 1n any
TYEE LAKE
0.2 0.3 0.4 0.5 0.6 0. 7 0.8
Possible damage or repair cost in any year (in million$)
0.9
1.0'
1.0
Range of Expected Number of Outage Days 100% ~--------,--·--···-----····-·· ··---··
90% -----------------·-··--
80% t--. . ----. ----·-.
g 7-4-----------SWANLAKE
~ IL--------------------------8 60% +I
" ~ 50% ++---------·
~40%
~~~----------------------------------Ci:
2-
10%
Q%L--~~==~-------------------------~
0 30 60 90 120 150 180 210 240 270 300 330 360
Possible number of outage days in any year
100%o---------------------------
90%*---------------------------·--------·-------
80%
·······--·----
,.
•l-----~~~====~=-----------------
0 30 60 90 120 150 180 210 240 270 300 330 360
Possible number of outage days in any year
100% ...,
90%t---------------------
80%l---------------------.. !:! 70% TERROR LAKE .. --·· -----,
~60% ++--------------------------······
~50%
0
~40%
~ 30% "---\--------------------.r
20% ~-+------··--------------·
10% ----"..-----
0%-
0 30 60 90 120 150 180 210 240 270 300
Possible number of outage days in any year 100% ----------·-· .....
90% +\---------· -····----··
80% ~r-----
TYEE LAKE
10"4 -----'.,..... ---------
I
330 360
0% C ... ~---=:::::::====~----------~
0 30 60 90 120 150 180 210 240 270 300 330 360
Possible number of outage days in any year
Table of Contents
RISK ASSESSMENT OF THE
FOUR DAM POOL HYDROELECTRIC PROJECTS
VOLUME I -MAIN REPORT
TABLE OF CONTENTS
EXECUTIVE SUMMARY
TABLE OF CONTENTS
Chapter 1: INTRODUCTION
1.1 Objectives of the Study
1.2 Scope of Services
1.3 Data Availability and Level of Study
1.3.1 Data Availability
1.3.2 Level of Study
1.4 Condition Assessment Definitions
1.4.1 Deficient Design
1.4.2 Deferred Maintenance
1.4.3 Other Project Improvements
1.4.4 Replacement Due to Normal Wear and Tear
1.5 Organization of the Report
1.6 Acknowledgments
Chapter 2: SWAN LAKE
2.1 Project Description
2.2 Installed Capacity and Energy Generation
2.2.1 Monthly Flows
2.2.2 Energy Generation Potential
2.2.3 Effects of Drought
2.2.4 Potential for Expansion
2.3 Generating Unit and Transmission System Availability
2.3.1 Generating Unit Availability
2.3.2 Transmission System Availability
960208
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TABLE OF CONTENTS (Cont'd)
2.4 Condition Assessment, Recommendations, and Costs
2.4.1 Site Inspection Dates
2.4.2 Reservoir
2.4.3 Powerhouse
2.4.4 Gatehouse
2.4.5 Dam
2.4.6 Turbines
2.4.7 Generators
2.4.8 Governors
2.4.9 Butterfly Valves
2.4.10 Powerhouse Auxiliary Mechanical Equipment
2.4.11 Station Service Transformer and Switchgear
2.4.12 Battery and Battery Charger System
2.4.13 SCADA System
2.4.14 Communications
2.4.15 Emergency Generator
2.4.16 Intake Power Feeder
2.4.17 Protective Relaying
2.4.18 Powerhouse Switchyard
2.4.19 Transmission Line
2.4.20 Baily Substation
2.4.21 Spare Parts
2.4.22 Rolling Stock
2.4.23 Infrastructure
2.4.24 Documentation
1.4.25 Conclusions
Chapter 3: SOLOMON GULCH PROJECT
3.1 Project Description
3.2 Installed Capacity and Energy Generation
3.2.1 Monthly Flows
96020S
3.2.2 Existing Generation Potential
3.2.3 Effects of Drought
3.2.4 Potential for Expansion
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TABLE OF CONTENTS (Cont'd)
3.3 Generating Unit and Transmission System Availability
3.3.1 Generating Unit Availability
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3.3.2 Transmission System Availability
3.4 Condition Assessment, Recommendations, and Costs
3.4.1 Site Inspection Dates
960208
3.4.2 Reservoir
3.4.3 Powerhouse
3.4.4 Dam
3.4.5 Dike
3.4.6 Spillway
3.4.7 Power Intake
3.4.8 Penstocks
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3.4.9 Turbines 3-16
3 .4.1 0 Governors 3-17
3 .4.11 Spherical Valves 3-17
3 .4.12 Generators 3-17
3.4.13 Powerhouse Auxiliary Mechanical Equipment 3-18
3.4.14 Station Service Transformer and Switchgear 3-19
3 .4.15 Battery and Battery Charger System 3-19
3.4.16 SCADA System 3-19
3 .4.17 Communications 3-19
3.4.18 Emergency Generator 3-20
3.4.19 Powerhouse Switchyard 3-20
3.4.20 Transmission Line from the Solomon Gulch Powerhouse to Meals
Substation 3-20
3.4.21 Transmission Line from Meals Substation to P12 Substation, and from
the P12 Substation to the Pll Substation 3-21
3.4.22 Meals Substation 3-24
3.4.23 P12 Substation 3-24
3.4.24 P11 Substation 3-24
3 .4.25 Mile 26 Tap 3-25
3.4.26 Rolling Stock 3-25
3 .4.2 ?Infrastructure 3-26
3 .4.28 Documentation 3-26
3.4.29 Conclusions 3-26
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TABLE OF CONTENTS (Cont'd)
Chapter 4: TERROR LAKE PROJECT
4.1 Project Description
4.2 Installed Capacity and Energy Generation
4.2.1 Monthly Flows
4.2.2 Existing Generation Potential
4.2.3 Effects of Drought
4.2.4 Potential for Expansion
4.3 Generating Unit and Transmission System Availability
4.3.1 Generating Unit Availability
4.3.2 Transmission System Availability
4.4 Condition Assessment, Recommendations, and Costs
4.4.1 Site Inspection Dates
960208
4.4.2 Reservoir
4.4.3 Dam and Spillway
4.4.4 Main Dam Low-Level Outlet Works
4.4.5 Main Tunnel Intake Gatehouse
4.4.6 Main Tunnel
4.4.7 Shotgun Creek Diversion
4.4.8 Falls Creek Diversion
4.4.9 Rolling Rock Creek Diversion
4.4.1 0 Penstock and Intake Portal
4.4.11 Powerhouse
4.4.12 Miscellaneous Facilities
4.4.13 Access Road
4.4.14 Turbines
4.4.15 Governors
4.4.16 Spherical Valves
4.4.17 Powerhouse Auxiliary Mechanical Equipment
4.4.18 Generators
4.4.19 Station Service Transformer and Switchgear
4.4.20 DC System
4.4.21 SCADA System
4.4.22 Communications
4.4.23 Emergency Generator
4.4.24 Controls
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TABLE OF CONTENTS (Cont'd)
4.4.25 Powerhouse Switchyard 4-24
4.4.26 Transmission Line from Terror Lake to Airport Substation 4-25
4.4.27 Airport Substation to Swampy Acres Substation 138-kV Line 4-30
4.4.28 Distribution Line between Terror Lake and Port Lions Diesel Plant 4-30
4.4.29 Airport Substation 4-30
4.4.30 Swampy Acres Substation 4-31
4.4.31 Rolling Stock 4-32
4.4.32 Infrastructure 4-32
4.4.33 Documentation 4-33
4.4.34 Conclusion 4-33
Chapter 5: TYEE LAKE HYDROELECTRIC PROJECT
5.1 Project Description 5-1
5.2 Installed Capacity and Energy Generation 5-3
5.2.1 Monthly Flows 5-3
5.2.2 Existing Generation Potential 5-4
5.2.3 Effects of Drought 5-5
5.2.4 Potential for Expansion 5-5
5.3 Generating Unit and Transmission System Availability 5-6
5.3.1 Generating Unit Availability 5-7
5.3.2 Transmission System Availability 5-7
5.4 Condition Assessment, Recommendations, and Costs 5-7
5.4.1 Site Inspection Dates 5-7
5.4.2 Reservoir 5-8
5.4.3 Gatehouse 5-9
5.4.4 Tunnel and Penstock 5-10
5.4.5 Powerhouse 5-11
5.4.6 Other Facilities 13
5.4.7 Turbines 5-14
5.4.8 Generators 5-15
5.4.9 Governors 5-16
5.4.10 Spherical Valves 5-17
5 .4.11 Powerhouse Auxiliary Mechanical Equipment 17
5.4.12 Station Service, Transformer and Equipment 18
5.4.13 Battery and Battery Charger System 5-18
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TABLE OF CONTENTS (Cont'd)
5.4.14 SCADA System
5.4.15 Communications
5 .4.16 Emergency Generator
5.4.17 15-kV Switchgear
5 .4.18 Alarm and Temperature Monitoring Panels
5.4.19 Protective Relaying
5.4.20 Powerhouse Switchyard
5.4.21 Transmission Line from Powerhouse Switchyard to
Wrangell Switchyard
5.4.22 Transmission Line from Wrangell Switchyard to
Petersburg Substation
5.4.23 Transmission Line between Wrangell Switchyard to
Wrangell Substation
5.4.24 Petersburg Substation
5.4.25 Wrangell Switchyard
5.4.26 Wrangell Substation
5.4.27 Rolling Stock
5 .4.28 Infrastructure
5.4.29 Documentation
5.4.39 Conclusions
Chapter 6: ESTIMATION OF ANNUAL COSTS AND ANALYSIS OF RISK
6.1 Analysis of Historical Operation and Maintenance Costs
6.2 Risk Evaluation
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6.2.1 Methodology
6.2.2 Structures and Equipment Categories
6.2.3 Earthquake
6.2.4 Flood
6.2.5 Fire
6.2.6 Landslide or Rockfall
6.2.7 Avalanche
6.2.8 Tsunami
6.2.9 Volcanic Activity
6.2.10 Wind
6.2.11 Snow
7176/G 2U28T(X'.WP -vi-
5-19
5-19
5-20
5-20
5-21
5-21
5-21
5-22
5-25
5-27
5-28
5-29
5-29
5-30
5-31
5-31
5-32
6-1
6-1
6-1
6-4
6-5
6-5
6-6
6-7
6-8
6-9
6-10
6-10
6-11
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TABLE OF CONTENTS (Cont'd)
6.2.12 Spills 6-11
6.2.13 Contamination 6-11
6.2.14 Accident 6-11
6.2.15 Internal Failure 6-11
6.2.16 Swan Lake 6-12
6.2.17 Solomon Gulch 6-12
6.2.18 Terror Lake 6-12
6.2.19 Tyee Lake 6-13
6.3 Summary of Costs 6-13
VOLUME 2 -APPENDICES
Appendix A: Bibliography
Appendix B: Project Data
Appendix C: Photographs
Appendix D: Methodology for Estimating the Composite Range of Risk-Related
Costs and Outage Duration
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TABLE OF CONTENTS (Cont'd)
No. Tables
1-1 Site Inspection Visits by Harza Personnel
2-1 Swan Lake Project-Significant Data
2-2 Swan Lake Project-Annual Generation
2-3 Swan Lake Project -Annual Outage Time
2-4 Swan Lake Project -Significant Outage Events
2-5 Swan Lake Project-Expected Service Life and Replacement Costs
2-6 Swan Lake Project -Projected Most Likely Repair and Replacement Costs
3-1 Solomon Gulch Project -Significant Data
3-2 Solomon Gulch Project -Annual Generation
3-3 Solomon Gulch Project -Expected Service Life and Replacement Costs
3-4 Solomon Gulch Project -Projected Most Likely Repair and Replacement Costs
4-1 Terror Lake Project -Significant Data
4-2 Terror Lake Project -Annual Generation
4-3 Terror Lake Project -Expected Service Life and Replacement Costs
4-4 Terror Lake Project-Projected Most Likely Repair and Replacement Costs
5-1 Tyee Lake Project -Significant Data
5-2 Tyee Lake Project-Annual Generation
5-3 Tyee Lake Project -Expected Service Life and Replacement Costs
5-4 Tyee Lake Project -Projected Most Likely Repair and Replacement Costs
6-1 Historical Operation and Maintenance Costs and Allocated Revenue Requirements
6-2 Characterization of Earthquake Damage
6-3 Characterization of Flood Damage
6-4 Swan Lake Project -Risks to Project Components
6-5 Swan Lake Project -Estimated Repair Costs or Outage Times due to Natural
Events, Accidents or Equipment Failures
6-6 Swan Lake Project -Allocation of Mean Annual Risk Related Costs to Project
Components and Events
6-7 Swan Lake Project-Allocation of Mean Annual Outage Duration to Project Com-
ponents and Events
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TABLE OF CONTENTS (Cont'd)
No. Tables
6-8 Solomon Gulch Project -Risks to Project Components
6-9 Solomon Gulch Project-Estimated Repair Costs or Outage Times due to Natural
Events, Accidents or Equipment Failures
6-10 Solomon Gulch Project -Allocation of Mean Annual Risk Related Costs to Project
Components and Events
6-11 Solomon Gulch Project -Allocation of Mean Annual Outage Duration to Project
Components and Events
6-12 Terror Lake Project -Risks to Project Components
6-13 Terror Lake Project -Estimated Repair Costs or Outage Times due to Natural
Events, Accidents or Equipment Failures
6-14 Terror Lake Project -Allocation of Mean Annual Risk Related Costs to Project
Components and Events
6-15 Terror Lake Project -Allocation of Mean Annual Outage Duration to Project Com-
ponents and Events
6-16 Tyee Lake Project -Risks to Project Components
6-17 Tyee Lake Project -Estimated Repair Costs or Outage Times due to Natural
Events, Accidents or Equipment Failures
6-18 Tyee Lake Project -Allocation of Mean Annual Risk Related Costs to Project
Components and Events
6-19 Tyee Lake Project -Allocation of Mean Annual Outage Duration to Project Com-
ponents and Events
6-20 Projected Costs
6-21 Replacement Costs -with Escalation and Levelizing
6-22 Summary of Expected Costs
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TABLE OF CONTENTS (Cont'd)
No. Figures
2-1 Swan Lake Project -Measured Historical Flows and Lake Levels
2-2 Swan Lake Project -Fabrication of New Transmission Structure Pipe Support
2-3 Swan Lake Project-Reinforcement of Swan Lake H-Frame Transmission Structures
2-4 Swan Lake Project -Location of New Guy Wiring on Transmission Structures
3-1 Solomon Gulch Project -Measured Historical Flows and Lake Levels
3-2 Solomon Gulch Project -Transmission Structure Configuration -Powerhouse to
Meals substation
3-3 Solomon Gulch Project -Transmission Structure Configuration -Meals to P12
Substation
3-4 Solomon Gulch Project -Main One-Line Diagram
3-5 Solomon Gulch Project-One-Line Diagram -P12 Substation
3-6 Solomon Gulch Project -One-Line Diagram -Pll Substation
3-9 Solomon Gulch Project -One-Line Diagram -Meals Substation
4-1 Terror Lake Project -Measured Historical Flows and Lake Levels
4-2 Terror Lake Project -Transmission and Substation System
4-3 Terror Lake Project -Transmission Structure -Terror Lake to Airport Substation
4-4 Terror Lake Project -Relocation of Transmission Structure Top Arm Insulator
Assembly -Terror Lake to Airport Substation.
5-1 Tyee Lake Project -Measured Historical Flows and Lake Levels
5-2 Tyee Lake Project -Transmission and Substation System
5-3 Tyee Lake Project -Transmission Line Support Structure -Wrangell Switchyard to
Wrangell Substation
6-1 Swan Lake Project -Range of Annual Costs due to Natural Events or Equipment
Failure
6-2 Swan Lake Project -Range of Annual Outage Days due to Natural Events or
Equipment Failures
6-3 Solomon Gulch Project -Range of Annual Costs due to Natural Events or Equip-
ment Failure
6-4 Solomon Gulch Project-Range of Annual Outage Days due to Natural Events or
Equipment Failures
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No. Figures
6-5 Terror Lake Project -Range of Annual Costs due to Natural Events or Equipment
Failure
6-6 Terror Lake Project -Range of Annual Outage Days due to Natural Events or
Equipment Failures
6-7 Tyee Lake Project -Range of Annual Costs due to Natural Events or Equipment
Failure
6-8 Tyee Project-Range of Annual Outage Days due to Natural Events or Equipment
Failures
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7176/G 2028TOC.WP -XI-
Chapter 1
Introduction
Chapter 1
INTRODUCTION
The "Four Dam Pool Hydroelectric Projects" consist of the following:
• Swan Lake Hydroelectric Project,
• Solomon Gulch Hydroelectric Project,
• Terror Lake Hydroelectric Project, and
• Tyee Lake Hydroelectric Project.
The projects are owned by the Alaska Energy Authority (AEA), but are managed by
the Four Dam Pool Project Management Committee, a committee established under the
Long Term Power Sales Agreement between the Alaska Energy Authority and the five
utilities purchasing power from the projects. The five purchasing utilities are Copper
Valley Electric Association, Inc. (Solomon Gulch), Ketchikan Public Utilities (Swan
Lake), Kodiak Electric Association, Inc. (Terror Lake), and Petersburg Municipal
Power and Light and Wrangell Municipal Light and Power (Tyee Lake).
The study described in this report was undertaken to identify the risks and estimate the
costs associated with continued operation of the projects. This study was commis-
sioned jointly by the Alaska Energy Authority and the Four Darn Pool Management
Committee. The results of this study will be used to help establish the costs associat-
ed with the possible transfer of ownership of the projects from AEA to the operating
utilities or other entities.
1.1 Objectives of the Study
The overall objective of the study was to establish the likely cost of continued opera-
tion of the facilities. This objective was achieved through:
1. Inspecting the condition of the facilities and interviewing plant operation
personnel,
2. Assessing the existing condition of the facilities, and estimating remaining
service life,
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7176/G 2028CIIl.Wl' l-1
3. Identifying the needs and costs of repair and replacement, both in the short
term and the long term,
4. Assessing the probabilities, costs, and outage durations associated with natu-
ral events, accidents and failures, and
5. Assessing the potential for future expansion.
1.2 Scope of Services
The services entailed inspection of project facilities, analysis of the project records,
interviews with the operators and managers, and the preparation of this report. The
report includes: A) an estimate of the costs associated with maintenance and improve-
ments needed because of deficient design, deferred maintenance, or normal wear and
tear, B) an analysis of the risks and the costs of repair or replacement of the facilities
or components that might be damaged by natural events, human error, or failure, and
C) an analysis of the potential of each project to generate additional power and energy.
Drawings, maintenance records, standards, specifications, FERC inspection reports, li-
censes and permits, the Long Term Power Sales Agreement, the maximum probable
loss study prepared for insurance purposes, meteorology records, and other documents
necessary to develop the analyses, were reviewed.
Facilities, equipment and property, including the powerhouses, substations, dams,
diversions, structures, penstocks, transmission lines, tunnels, rolling stock, dispatch
equipment, flow monitoring equipment, shops, communication facilities, fuel facilities,
access roads, storage areas, equipment, property, and other related facilities, were
inspected.
Operators, facilities maintenance personnel, managers, owner staff, consultants, and
other knowledgeable parties, were interviewed. No physical testing was carried out.
Cost estimates and cash flows were developed according to the following categories:
1.
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Based on industry standards, and considering local conditions, the expected
service life, remaining service life, and replacement costs of major mechani-
cal and electrical equipment, were estimated. The analysis performed under
this section assumed that there are no items of deferred maintenance, sub-
standard design or design deficiencies.
7176/G 202lK'Hl.WP 1-2
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2. Items of substandard design, and deficiencies in the design, were identified,
and the costs to correct such items were estimated.
3. Items of deferred maintenance were identified. The costs to correct such de-
ferred maintenance were estimated.
4. Other factors requiring remedial action, as well as any factors that may re-
duce the economic life of the project, were identified. The cost to correct
such items were estimated.
5. Items which require replacement as a result of normal use were identified.
The costs of replacement of those items were estimated.
6. Risks of damage and failure were identified for each major component. The
probability of damage or failure occurring, the associated cost of repair, and
any expected duration that a project would be off-line as a result of such
occurrence, was established. The composite risk of loss was quantified for
each project by estimating a probable loss range and a most probable loss
within that range.
Those items that are expected to require replacement within the next five years, and
the cost to replace those items, were identified.
An analysis of the potential to generate additional power and energy was carried out,
including preparation of preliminary cost estimates to increase generation capacity.
It should be noted that the categories of substandard design, deferred maintenance,
other factors requiring remedial action, and replacements due to normal wear and tear,
are categories that were identified for use in this report only, and are not related to the
cost accounting categories of the Four Dam Pool.
1.3 Data Availability and Level of Study
1.3.1 Data Availability
Data were collected during a series of visits to project sites and meetings with the
Alaska Energy Authority and utility representatives of the Four Dam Pool Manage-
ment Committee. Site visits and inspections were conducted as indicated in Table 1-l.
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71 76/G 2028CHI. WP 1-3
Site visits were conducted primarily to assess the condition of each project, as de-
scribed in Chapters 2, 3, 4 and 5 of this report. The site visits were carried out by
senior level engineers experienced in hydroelectric planning, design, and operation.
Structures and equipment were viewed to the extent that circumstances allowed. The
projects were not taken out of service for the inspection. Special arrangements were
not made for inspecting areas that are normally inaccessible or submerged. Assess-
ment of the conditions of the items that could not be physically inspected was based
on the observations of related structural ele~ents or other circumstances that were
evident during the inspection.
Site
Swan Lake
Solomon Gulch
Terror Lake
Tyee Lake
Table 1-1
SITE INSPECTION VISITS BY HARZA PI<:RSONNEL
Engineering Discipline
Civil/Structural
N. Pansic
Oct 18 & 19. 1995
N. Pansic
Oct 9 & 10. 1995
N. Pansic
Oct 11 & 12. 1995
N. Pansic
Oct 16 & 17. 1995
Mechanical Electrical Transmission
J.H.T. Sun
Oct 16 & 17, 1995
J.H.T. Sun
Oct 5 & 6, 1995
J.H.T. Sun
Oct 2 & 3. 1995
J.H.T. Sun
Oct 18 & 19, 1995
J.J. Quinn A. Angelos
Oct 16 & 17, 1995 Oct 18 & 19, 1995
J.J. Quinn P. Donalek/A. Angelos
Oct 5 & 6, 1995 Oct 9, 10 and 23, 1995
J.J. Quinn P. J. Donalek
Oct 2 & 3. 1995 Oct 11 and 12. 1995
J.J. Quinn A. Angelos
Oct 18 & 19. 1995 Oct 16 & 17. 1995
In addition to the above inspections, several meetings were held with Alaska Energy
Authority or with utility personnel. Specifically, the following meetings took place:
1. October 23, 1995 -meeting in Alaska Energy Authority's Anchorage office to
collect project data. This activity was carried out by Mr. L.L. Wang of Harza.
2. November 14, 1995 meeting in Harza's Chicago office to discuss the procedures
and methodologies to be used in the assessment. This meeting was attended by
Messrs. Edwin K. Kozak of Kodiak Electric Association and Dan W. Beardsley of
the Alaska Energy Authority.
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3. December 11, 1995 -meeting in Anchorage with representatives of the Four Dam
Pool and the Alaska Energy Authority to present preliminary findings. Harza per-
sonnel attending were Messrs. J.T. Passage, J.J. Quinn, A. Angelos and
P.G. Hartel.
4. January 16, 1996 -meeting in Anchorage with representatives of the Four Dam
Pool and the Alaska Energy Authority to discuss the risk assessment and the draft
report. Harza personnel attending were Messrs. P.G. Hartel and A. Angelos.
The data collected and reviewed for the assessment are listed in Appendices A and B.
The data include drawings of the project features, and available operational data.
1.3.2 Level of Study
The study is a comprehensive and thorough investigation of the possible costs that are
associated with continued project operation. Parametric and experience data were
utilized to estimate costs for many of the repair and remedial measures that are dis-
cussed in this report. Cost estimates presented in this report are not "engineer's esti-
mates," which are based on detailed designs and quantity estimates prepared for bid-
ding purposes. The estimated costs presented in this report have been developed based
on a knowledge of conditions at the site, but are suitable for preliminary budgetary
planning. Implementation of specific measures will require additional engineering
analysis to better define expected costs.
Costs associated with repairs subsequent to natural events defined as risks for this
study are highly uncertain. A best estimate of damage and repair costs has been
made. However, due to the uncertain nature of extreme events such as earthquakes,
floods, or avalanches, the range of costs that might be incurred in repairing damage·
from such events is quite large. An estimate of the likely cost for repair has been
made, based on knowledge of the behavior and response of structures and equipment
subjected to such events.
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7176/G 2028CHl.WP 1-5
1.4 Condition Assessment Definitions
For each project, a tabulation of the expected service life of major equipment is pre-
sented, along with the expected remaining life, and its replacement cost. All costs are
given at 1995 price levels, without any escalation.
The following descriptors are used to characterize the condition of project components
and equipment:
• Excellent: Relatively new structures or equipment that appear to be in better
than expected condition. Maintenance has been good.
• Good: Structures or equipment that exhibit aging characteristics commensurate
with expectations. Normal maintenance is required.
• Fair: Structures or equipment that exhibit aging characteristics that are worse
than those normally expected. Frequent remedial maintenance is required.
• Poor: Structures or equipment that is either nearing the end of its service life,
requires frequent remedial maintenance, or has been neglected. Structures or
equipment in poor condition are candidates for major rehabilitation, overhaul or
replacement.
Expected future costs for major rehabilitations and replacements are presented in Cha-
pters 2, 3, 4, and 5. However, in some cases, suggestions for maintenance, replace-
ments, or improvement are noted that are already approved and budgeted for imple-
mentation. In these cases, costs are omitted. Recommended and suggested future
work items are classified as follows:
• Remedial work to correct items of deficient design;
• Remedial work to correct items of deferred maintenance;
• Other project improvements; and
• Replacements due to normal wear and tear.
There are at least two other cost categories that are not covered by the above listed
items. These include (a) the costs associated with the day-to-day operation, manage-
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7176/G 2028CHl.WP 1-6
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ment and administration of plant activities, and (b) the costs associated with risk or
unforeseen natural events that might cause damage to project features, accidents, or
major unforeseen structural or equipment failure events. These two categories are
discussed in Chapter 6 of this report.
1.4.1 Deficient Design
Deficient design is defined as a condition that does not meet the minimum generally
accepted standards for safety and reliability. The conclusion of deficient design is
somewhat dependent upon the design standard of the owner. A deficient design in the
eyes of one individual may not be deficient in the eyes of the owner who is funding
the design and construction of the facility, while also accepting the risks. While there
are many instances where hindsight now indicates that some components could have
been designed, constructed or arranged better, the only one instance of truly deficient
design identified in this study involves the Tyee Lake Project transmission line.
1.4.2 Deferred Maintenance
Deferred maintenance is defined as a condition where either regularly scheduled main-
tenance or maintenance to repair a damaged structure or malfunctioning component
was not carried out in a timely manner. Items of deferred maintenance generally
require immediate attention with some associated cost in the next five years.
1.4.3 Other Project Improvements
Project structures or equipment requiring attention that do not conveniently fit the
definition of deficient design or deferred maintenance are classified as "Other Project
Improvements." Such items include equipment that is planned for replacement for
reasons including obsolescence, unavailability of spare parts, premature failure, or
changing operating conditions. Also placed in the Other Project Improvements catego-
ry are equipment and structural repairs or modifications that have not been deferred,
but are now required to correct a malfunction or improve functionality or safety; or are
studies that must be carried out to address critical issues. ·
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7176/G 2028CHI.WP 1-7
1.4.4 Replacements due to Normal Wear and Tear
A schedule for expenditures to replace equipment or to carry out major structural reha-
bilitation was developed. For equipment, the typical service life (adjusted for at-site
conditions) was used as the basis for establishing the replacement and expenditure
schedule. For structures, the existing condition and expected performance were used
to establish an appropriate rehabilitation and expenditure schedule.
Projected expenditures are indicated for a 35-year planning horizon, beginning in year
1996 and ending in year 2030, in five-year increments.
1.5 Organization of the Report
The report is organized into six chapters and four appendices. Chapter 1 is an intro-
duction summarizing the objectives and the scope of study. Chapters 2 through 5
contain results of analyses performed, with a separate chapter dedicated to each pro-
ject. The individual project chapters include the following information:
1. A brief description of the project, with information on recorded streamflow,
generating capacity and energy production, potential for expansion of the gen-
erating capacity, and a summary of generating unit and transmission system
availability.
2. A description of the existing condition of the civil, structural, mechanical, elec-
trical and transmission features, based on site inspection performed by Harza
personnel, plus recommendations and costs for replacements or remedial mea-
sures that are deemed appropriate to be considered for implementation in the
next five years.
3. An estimate of the remaining useful life and the cost for the replacement of
major components at the end of their service life.
Chapter 6 contains a discussion on the estimation of annual operation and maintenan-
ce, replacement, and risk-related costs, including an estimate of the composite repair
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costs and outage durations resulting from the occurrence of natural events, failures or
accidents.
Four appendices accompany the report as described below:
• Appendix A: Bibliography -a selected list of information used as a basis for
evaluations described in this report.
• Appendix B: Project Data -copies of selected drawings and unpublished mate-
rial, primarily related to unit and transmission availability and stream flow at
the project site.
• Appendix C: Photographs -either taken during the site inspection or furnished
to Harza for use in the study.
• Appendix D: Methodology for Estimating the Composite Range of Risk Relat-
ed Cost and Outage Duration -a discussion of the methodology used in the
risk assessment portion of this study.
1.6 Acknowledgments
The following key individuals contributed to the study:
Client Co-Project Managers:
Mr. Dan W. Beardsley
Contracts Manager
Alaska Energy Authority
Other Client Personnel and Consultants:
Mr. Stan Siezkowski, AEA
Mr. Remy Williams, Consultant
96020~
7176/G 2028CHLWP 1-9
Mr. Edwin K. Kozak
General Manager
Kodiak Electric Association
Harza Personnel:
Project Sponsor:
Project Manager and Electrical Engineer:
Mechanical Engineer:
Transmission Engineers:
Civil/Structural Engineers:
Hydroelectric Planning Engineer:
Risk Assessment and Report Production:
960208
7176/G 202KCHl.WP 1-10
James T. Passage
Jack J. Quinn
James H. T. Sun
Andy Angelos
Peter J. Donalek
Nicholas Pansk
W. James Marold
Lee L. Wang
Patrick G. Hartel
Kirk Peterson
Joe Moawad
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Chapter 2
Swan Lake
Chapter 2
SWAN LAKE
2.1 Project Description
This project is located on Revillagigedo Island at the head of Carroll Inlet, approxi-
mately 22 air miles northwest of Ketchikan, Alaska. The project consists of a con-
crete arch dam, power tunnel and powerhouse with two generating units, plus 30.5
miles of transmission line from the switchyard at the powerhouse to the Bailey substa-
tion in Ketchikan. The project general arrangement and sections of major project fea-
tures are illustrated on the project drawings included in Appendix B. Table 2-1 pres-
ents pertinent project data.
Swan Lake was constructed by Ketchikan Public Utilities (KPU), and was purchased
by the Alaska Power Authority (now known as Alaska Energy Authority or AEA)
under the Energy Program for Alaska. The project is operated by KPU under an
agreement with AEA. The project went into commercial service on June 7, 1984.
The two turbines are vertical-shaft, single-runner, Francis type, designed to operate at
450 rpm. The two generators are each rated at 12.5 MVA. The turbines were manu-
factured by Litostroj and the generators by Siemens-Allis.
Access to the project is by boat or fixed-wing aircraft capable of landing in the bay at
the Swan Lake Project. There is no road access.
2.2 Installed Capacity and Energy Generation
2.2.1 Monthly Flows
Flow records for a period beginning in October 1986 to February 1995 were analyzed.
Data from two separate sources were reviewed. Information on powerplant generating
discharges and downstream releases was available from plant operating records for the
period beginning in December 1992 (see Appendix B). Similar information prior to
October 1992 was available from the U. S. Geological Survey. A time-series plot of
generating discharge and flow measured at the Swan Lake Project at a point below the
dam is shown on Figure 2-1.
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717610 2028SWAN.WP 2-1
Table 2-1
SWAN LAKE PROJECT -SIGNIFICANT DATA
RESERVOIR
Normal Maximum Pool Elevation
Normal Minimum Pool Elevation
Maximum Active Storage
Drainage Area
DAM
Type
Crest Elevation
Height
Length
Crest Thickness
Base Thickness
SPILLWAY
Type
Length
Crest Elevation
POWER TUNNEL
Lining
Length
Diameter
EQUIPMENT
Nominal Plant Generating Capacity
Number of Units
Type of Turbines
Maximum Gross Head (approximate)
330.0 ft
271.5 ft
86,000 ac-ft
36.5 sq mi
Concrete thin arch
330ft
174ft
480 ft
6ft
18 ft
Ungated concrete ogee overflow
100ft
330ft
Concrete, partially steel lined
1,950 ft concrete section, 267 ft steel section
11 ft concrete section, 9.5 ft steel section
Turbine Power Output (each, at 291 ft net head)
Generator Rating (each)
22.5 MW at 90 percent power factor
2
Vertical shaft Francis
324.5 ft
15,200 hp
12.5 MVA
450 rpm Speed
TRANSMISSION LINE
Length
Voltage
96020~
7176/G 202~SW AN .WP 2-2
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The average flow at the project site, based on data shown on Figure 2-1, is approxi-
mately 430 cfs. Over the period analyzed, the portion of this flow that is utilized for
generation is approximately equal to 330 cfs, while the portion that is spilled is about
100 cfs. In recent years, the spill has been much lower, presumably because of in-
creased production to meet electrical demands. The maximum powerplant discharge
capacity is approximately 1,100 cfs. The average historical flow for the period ana-
lyzed is about 39 percent of the hydraulic capacity of the plant.
2.2.2 Energy Generation Potential
Based on data for the 10 most recent fiscal operating years (period ending June 30,
1995) the historical average annual generation has been about 54.9 GWh. In the last
three years, production averaged 68.0 GWh per year. Historical production, as fur-
nished by AEA, is listed in Table 2-2.
Based on limited flow data gathered for this study, a preliminary estimate of the ener-
gy generation potential of the existing project, assuming that all of the available ener-
gy could be utilized, is 70.1 GWh per year. The historical annual energy production
appears to be trending upward and approaching the estimated average annual potential.
Table 2-2
SWAN LAKE PROJECT-ANNUAL GENERATION
Year Ending Actual kWh
6/30/86 34,107,000
6/30/87 44,360,000
6/30/88 41,493,400
6/30/89 50,419,590
6/30/90 48,369,074
6/30/91 69,290,320
6130192 57J22,422
6/30/93 71,226,980
6/30/94 67,832,000
6/30/95 64,815,560
Total 549,036,346
Average 54,903,635
10 years
Last 3 years 67,958,180
960201'1
7176/G 2028SWAN.WP 2-3
2.2.3 Effects of Drought
The potential impact of drought on energy generation can be investigated by analyzing
long-term streamflow. The actual streamflow and release data available for the plant
is too short to draw definite conclusions about the impact of drought. However, it is
possible to infer the magnitude of the reduction in generation that might occur in
water-short years by investigating the characteristics of streamflow in nearby rivers
that have long-term streamflow records.
The closest streamflow gaging station with a long-term record is on the Harding River
at a point approximately 40 miles north of the Swan Lake Project. The gage measures
a runoff from an area of about 67.4 square miles, which is about 185 percent of the
drainage area of the Swan Lake Project. The streamflow record contains data over a
period of 42 years. Total annual flow for each year was tabulated, and the distribution
of years with lower than average flows are as follows:
Number of years with annual flow that is:
less than 80 percent of average flow
between 80 and 85 percent of average flow
between 85 and 90 percent of average flow
between 90 and 95 percent of average flow
between 95 and 100 percent of average flow
above I 00 percent of average flow
I out of 42 years
2 out of 42 years
4 out of 42 years
8 out of 42 years
8 out of 42 years
19 out of 42 years
Because of its preliminary nature, the above analysis is not conclusive. However, it
can be inferred that 2.5 percent of the time, the annual generation might be 20 percent
less than average. A detailed hydrologic analysis is required to provide more defini-
tion of the characteristics of generation under drought conditions.
2.2.4 Potential for Expansion
Inspection of operating records and outflow data for the project indicates that in recent
years, the Swan Lake inflows are nearly fully utilized for generation. The installation
of additional electrical generation capacity would likely yield little additional energy.
Figure 2-1 shows a record of the historical project outflows compiled for this investi-
gation. Also shown in the figure is the hydraulic capacity of the powerplant.
96021l8
71 76/G 2028SW AN .WP 2-4
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It is evident in Figure 2-1 that the hydraulic capacity of the powerplant. approximately
1.100 cfs, always exceeds the monthly outflows for the available period of record, and
furthermore, that the difference is substantial for all but two or three months. For all
but six months in the period, the outflows are less than two-thirds the hydraulic capac-
ity of the powerplant.
The comparison between plant hydraulic capacity and the available river flow is not in
itself an indication that additional capacity cannot be utilized. Daily or hourly inflows
may at times exceed the capacity of the plant, while the average inflow for the month
may be less. Unless the prevailing unused reservoir storage capacity is sufficient to
store excess daily flow volume and release it to the powerplant at a later time. this
flow is spilled and represents lost energy that additional plant capacity would be able
to generate. In the case of Swan Lake, however, the active storage capacity of 86,000
acre-feet is large. equivalent to the hydraulic capacity of the powerplant released over
39 days. It is highly unlikely that daily flow volumes in excess of the current plant
hydraulic capacity cannot be stored for later release through the plant.
From the standpoint of production capacity alone, additional generating capacity could
be utilized if peak-period production was a critical function of the facility. In this
case, provided inflows and/or reservoir storage were sufficient, the additional capacity
could be utilized in the critical on-peak periods, and off-peak production would be
curtailed accordingly to impound water. As it stands currently, however, the peak
demand period durations are short and probably do not merit the installation of addi-
tional capacity for the amount of time it would be utilized. Also, the additional flow
through the power tunnel would result in a significant increase in velocities and
headloss when the third unit operates, offsetting the gain of the additional unit to some
extent.
Even on the supposition that additional energy and peaking capacity would be obtain-
able from additional generating capacity at the project, it is highly unlikely that the
benefits accruing to its implementation would exceed the associated cost. For Swan
Lake, the construction and equipment procurement costs would be, at a minimum,
about $7.9 million for a 12.5-MV A expansion (i.e. the addition of a third generating
unit about the same size as the two existing units), including the cost of a turbine,
governor, and inlet valve; generator and exciter; ancillary equipment; and powerhouse
expansion. A second tunnel to convey the additional flow would raise the cost sub-
stantially.
960208
7176/G 2028SW AN .WP 2-5
In view of the above, it appears that neither expansion of the generating capacity or
raising the dam to provide more reservoir storage is warranted.
2.3 Generating Unit and Transmission System Availability
Data furnished for Harza's use in analyzing the availability of the project is presented
in Appendix B. The data includes a list of outage events from January 1, 1990
through October 1995. In addition, plant operation personnel were interviewed, and
the FERC annual operation reports were reviewed.
Table 2-3 presents the number of hours that a unit was off-line for scheduled or un-
scheduled maintenance.
Table 2-3
SWAN LAKE PROJECT -ANNUAL OUTAGE TIME
Year Outage Time (hours)
1990 12.3
1991 469.3
1992 1.4
1993 564.5
1994 3182.0
1995 (up to 10/6/95) 235.3
Other pertinent observations and conclusions are presented below.
2.3.1 Generating Unit Availability
The significant outage events collected from documentation furnished to the inspection
team are listed in Table 2-4.
2.3.2 Transmission System Availability
The only major event noted in the outage history was a transmission line fire in Octo-
ber 1995. Because of this event, the plant was off-line for about 222 hours.
960208
7176/G 2028SW A.J'\LWP 2-6
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Other minor transmission line outages occurred as listed in Appendix B. Outages
noted in Appendix B include outages caused by ice build-up on the conductors, line
phase grounding, vandalism, downing of trees, and maintenance outages.
DATE
9/29/89 to
8115/90
7/90
3/91
3/91
8/91
11/91
4/93
5/93
7!93
9/93
2/94
4/94
6/94
8/95
10/95
96020~
7176/G 2U28SW Al'I.WP
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Table 2-4
SWAN LAKE PROJECT-SIGNIFICANT OUTAGE EVENTS
DURATION DK~CRIPTION OF OUTAGE DATA SOURCE
UNIT2 OF OUTAGE
? Almost I year Intake gate removed and inspected. FERC
3 days Unknown. Narrative
153 hours Collector ring insulation repair. Outage Records
153 hours Collector ring insulation repair (sched-Outage Records
ulcd maintenance).
Unknown Modification of the collector rings. FERC
156 hours Inspection of burnt windings. Outage Records
32 hour.; Inspection for possible future rewind. Outage Records
32 hours Insur.rnce inspection. Outage Records
150 hours Scheduled repairs to draft tube. Outage Records
255 hours Scheduled repairs. Outage Records
122 hours Exciter trouble. Outage Records
2.950 hours Scheduled generator rewind. Outage Records
66 hour.; Tunnel inspection. Outage Records
9 days I.Tnknown. Narratiw
222 hours Transmission lin<' fire. Outage Records
2-7
2.4 Condition Assessment, Recommendations, and Costs
The following section describes the condition assessment and recommendations for
replacements and improvements. At the conclusion of this section, the costs for rec-
ommended replacements and improvements summarized in tabular form.
2.4.1 Site Inspection Dates
Two teams visited project facilities during the period of October 16 through October
19. The first team performed the electrical and mechanical inspection; the second
team performed the transmission line, civil and structural inspection.
On October 16 through October 18, 1995, J.H.T. Sun and J.J. Quinn of Harza, and
Stan Sieczkowski of AEA, performed the electrical and mechanical inspection of the
Swan Lake Project.
The inspection on the morning of October 16 consisted of a meeting in KPU's office
with Tom Waggoner and Mike Scheel, followed by an inspection tour of the Bailey
substation and load dispatch office. Dan Ball and John Philbrook conducted an initial
tour of the powerplant and maintenance building in the afternoon. Harza conducted a
detailed inspection of the electrical and mechanical equipment and also conducted
extensive interviews of the plant personnel on October 17 and on the morning of Oc-
tober 18.
On October 18 and 19, 1995, N. Pansic of Harza inspected the civil and structural
features of the project and A. Angelos of Harza inspected the transmission line and
substation equipment.
The transmission line, civil and structure inspection on October 18 also consisted of a
driving tour of the Ketchikan area and KPU facilities, followed by a helicopter
fly-over of the project, concentrating on the dam and reservoir rim. The October 18
helicopter reconnaissance was done to evaluate the potential for landslide or avalanche
damage to the project structures -particularly the dam, gatehouse, and powerhouse,
and to inspect the transmission line between the project and the Bailey substation. On
the October 18 driving tour, Tom Waggoner, Electric Division Manager for KPU, and
Remy G. Williams, AEA Consultant, accompanied the site inspection team. On the
helicopter reconnaissance, only Remy Williams accompanied the team.
96020!>
7176/G 2U28SW AN.WP 2-8
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The inspection on October 19 was done on foot, concentrating on the powerhouse,
dam, gatehouse, and related project facilities. On October 19, Dan Ball, KPU Fore-
man, and Remy G. Williams accompanied the team.
2.4.2 Reservoir
Condition Assessment. The valley walls surrounding the reservoir are steep to moder-
ately steep, with numerous rock outcrops and a relatively thin soil cover. Spruce trees
are the dominant vegetation. The potential exists for minor landslides, especially
when the thin soil mantle overlying the rock is saturated from heavy rainfall. One
such landslide had occurred near the project gatehouse just shortly before the
mid-October inspection. However, since the soil mantle is thin, there is little opportu-
nity for any significant landslide which could impact the dam or gatehouse. The con-
sequences of any landslide would likely be minor.
A seismic event could possibly cause one of the rock outcrops to slide into the reser-
voir, which could create a wave large enough to overtop the arch dam. However, it is
doubtful that such an occurrence would damage or fail the dam.
The climate of the project region is such that deep snow accumulations are not com-
mon. Hence, it is unlikely that any significant snow avalanches would endanger pro-
ject facilities.
Although the reservoir was apparently cleared prior to filling, an ongoing maintenance
item involves the clearing of trees and trash that collects at the intake and spillway.
Recommendation. Trash and logs from the reservoir accumulate at the power intake
and spillway. Consideration should be given to the installation of an improved log
boom from the left abutment to the spillway and for purchase of a tugboat and log
skidder to remove trash and logs within the reservoir for disposal. A replacement of
the tugboat and log skidder would be scheduled in about 20 years.
2.4.3 Powerhouse
Condition Assessment. The powerhouse foundation area was inspected, including the
locations where the penstocks penetrate the back wall of the powerhouse, the scroll
case embedments, and the perimeter walls. The inspection revealed no evidence of any
cracking (except as noted below) or structural distress. Some groundwater seepage has
960208
7176/G 2028SWAN.WP 2-9
occurred around the penstock penetrations, but recent epoxy patching seems to have
solved the problem. The inspection revealed other minor groundwater seeps. Ground-
water seepage will likely be a continuous maintenance item.
Inspection of the upper levels of the powerhouse noted no particular problems. A
minor floor crack was noted in the on-grade floor slab of the service bay at the north
end of the powerhouse. The crack is tight, and Dan Ball reported that it has existed
since original construction. This crack is not a concern.
Recommendation. Architectural refurbishment should be anticipated after about 30
years of service. (year 2014).
Seepage at the back wall of the powerhouse has been a problem and is expected to
continue. Periodic remedial work will be required.
2.4.4 Gatehouse
Condition Assessment. A short access road extends from the powerhouse to the dam
and power tunnel gatehouse. The gatehouse is a reinforced concrete structure con-
structed atop a concrete gate shaft. The gatehouse was inspected only from the operat-
ing floor. No inspection of the gate shaft, gate or interior of the power tunnel was
made.
The gatehouse is comprised of two rooms. One room is heated and encloses the gate
controls, hydraulic power unit, and communications and remote control from the pow-
erhouse. The other room is unheated, but houses only the gate hoisting equipment.
The second room also encloses a catwalk providing access to the gate stem. The gate
stem is comprised of a system of five screwed stem pieces. An emergency gate do-
sure system uses a hydraulic brake which allows the gate to close in a controlled man-
ner when activated.
The gate is a 15 ft wide by 19ft high slide gate with a hydraulic operator. It is nor-
mally in the open position. The gate and gate seals were not inspected, but were in
excellent condition when inspected in June of 1994 by others. The station service
provides electrical power necessary to operate the gate.
All facilities observed in the gatehouse, and the structure itself, appeared to be in good
condition.
96020~
7! 76/G 2028SW A."l .WP 2-10
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2.4.5 Dam
Condition Assessment. The dam has a high hazard 1 potential classification by
FERC, and is therefore subject to Part 12 requirements for five-year safety inspections
and reports. The most recent Part 12 Safety Inspection Report was completed in Au-
gust, 1994.
The arch dam was inspected from the right abutment, which is the only side of the
dam that has ready road access. Review of the last Part 12 Safety Inspection Report
revealed several minor concerns with the dam: a horizontal lift joint through the dam
below the spillway, showing some efflorescence; and seepage through the dam abut-
ments. The joint was observed from the downstream side, and should continue to be
watched for any significant change in the future. Plans are underway to design and
construct seepage measuring weirs at the downstream contact of both dam abutments.
Access to the weirs for periodic reading, particularly the left abutment weir, will be
somewhat difficult. Possible locations for the weirs were noted by Williams and Ball
during the inspection.
The ungated overflow spillway through the center of the dam crest was inspected from
the right dam crest. No evidence of any problems was noted. The plunge pool area
was inspected visually by walking in from downstream. FERC has requested surveys
of the plunge pool to monitor scour after significant spills. Nothing observed during
this inspection indicated any concern with excessive erosion or undermining of the
,iam.
Although visibility was not good due to poor weather conditions, no evidence of any
cracks or seepage through the arch dam itself or its abutments was noted. The dam
appears to be well-designed and constructed.
The latest Part 12 Safety Inspection Report noted a concern for a joint and possible
failure plane in the downstream right abutment rock but nothing in this regard could
be observed during this inspection. Analyses performed as part of this Part 12 Safety
Inspection Report indicated that "the factor of safety against sliding of foundation
blocks and wedges are conservative and adequate under current conditions."
The hazard classification by FERC relates to the consequences of a failure, and does not
relate to the safety or physical condition of the structure.
96020~
7176/G 202~SWA,'\T.WP 2-11
Comment on Seepage. During the preparation of this report, a concern was raised
about the seepage, and the possibility and implications of an increase in the seepage.
Project drawings show that the foundation rock was excavated to competent rock.
Consolidation grouting of the foundation was also performed to a depth of 20 ft below
the foundation level to fill open joints and cracks in the rock near the foundation level.
Curtain grouting was also performed along the dam alignment to a depth of 50 percent
of the reservoir head to fill smaller joints within the deeper foundation rock, thereby
reducing seepage pressures and flows. Drain holes were drilled to a depth equal to 3 2
percent of the reservoir head downstream of the dam to collect seepage which passes
through the dam foundation. In addition, a low spot in the right foundation rock near
the bottom of the valley was located, overexcavated, and filled with concrete and
grouted. These measures taken to reduce and control seepage appear to be conserva-
tive and in accordance with normally accepted design standards.
The seepage through the abutments was observed to be minor during the inspection.
Seepage measuring weirs are being constructed and will continue to be monitored.
the seepage increases beyond acceptable limits, a program of grouting the contact
between the foundation and the conrete would be required, costing possibly several
hundred thousand dollars.
The probability of seepage quantity through the foundation increasing beyond accept-
able limits is low since most seepage problems historically occur on the first reservoir
filling. However, some failures have occurred in dam foundations as a result of pro-
gressive deterioration of the foundation materials with time. Therefore the probability
of implementing such a program exists. The costs of such a program are accounted
for in a category defined as "internal failures" in the risk analysis presented in Chap-
ter 6.
Recommendation. Flow measuring weirs are planned for construction on both abut-
ments of the dam for monitoring seepage. Access to the left abutment is difficult. A
metal walkway constructed at the base of the dam, under the spillway, may provide
easier access. Soundings should also be taken in plunge pool downstream of the dam
after significant spills2 •
No cost has been assigned to this item since soundings could probably be done by plant
maintenance personnel using a small boat.
96020~
7176/G 2028SWAN.WP 2-12
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2.4.6 Turbines
Condition Assessment. The overall condition of both Francis turbines are considered
to be good to excellent According to the operation personnel, the stainless steel run-
ners do not show any signs of cavitation and/or erosion. Runner wearing ring clear-
ances and the clearances on closed wicket gates were measured every year and were
found to be satisfactory. The Unit 2 turbine guide bearing was repaired for Babbitt
metal fatigue failure in 1994. This fatigue failure could have been caused by the load
transfer from the lower generator guide bearing when its clearance was increased for
the purpose of reducing the lower generator guide bearing operating temperature. The
lower generator guide bearing is the only bearing without oil coolers.
The Unit 1 turbine guide bearing was suspected of having a similar fatigue problem.
In tests performed in April and November 1994, the measured amplitudes of vibration
were within acceptable limits. However, overhauling the Unit 1 guide bearing is rec-
ommended if cracks are found in the Babbitt metal.
During the inspection, plant operators asked about the possibility of adding com-
pressed air injection for reducing rough operation. The Francis turbine has an inherent
rough operating range normally from 20 to 50 percent of the wicket gate opening. To
minimize rough operation at partial gate settings, atmospheric air or compressed air is
sometimes admitted into the draft tube. At Swan Lake, the existing arrangement in-
cludes piping that permits admission of air at atmospheric pressure. This system usu-
ally functions well at low tide, when the pressure in the draft tube is less than atmo-
spheric pressure.
However, when the runner has more submergence during the high tide, the pressure in
the draft tube could be higher than atmospheric pressure, and only compressed air
injection to the draft tube would be effective in reducing rough operation. Modifica-
tion of the draft tube air admission system would be required to inject compressed air.
Before any modifications are made, the effectiveness of compressed air in reducing
rough operation should be tested using the station service compressed air system 3 •
This test should be with the compressed air pressure slightly above the maximum
tailwater pressure. Installation of such a system could slightly extend the life of the
turbines and improve operating characteristics.
3 Utility personnel indicate that the station compressed air system may not be adequate to
provide sufficient air to run the test.
96020ll
7176/G 2028SWAN.WP 2-13
Turbine index and capacity tests were perfonned in 1984 on both Units 1 and 2. The
results indicated that the actual power output slightly exceeded the expected output at
the rated net head. A maximum turbine efficiency of 93.9 percent is shown on the
expected performance curve for the rated net head of 291 ft and 93.6 percent for the
maximum net head of 304 ft. These efficiencies are considered to be very high for the
size of the Swan Lake turbines, and could not be supported by the field test results.
Based on the expected turbine performance and current turbine conditions, the estimat-
ed turbine output is 15,200 hp (11.3 MW) under a net head of 291 ft and 17,000 hp
(12.7 MW) under a net head of 304ft.
In accordance with the performance curves, the best turbine efficiency occurs in the
range of approximately 60 to 90 percent of the wicket gate opening for all operating
net heads.
Recommendation. The Unit 1 turbine guide bearing should be overhauled.
A test of compressed air injection for improving unit performance is recommended to
evaluate improvements of unit performance.
2.4.7 Generators
Condition Assessment. The generators have a continuous overload rating of 115 per-
cent without injurious heating. Therefore, each unit could produce 12.94 MW at a 90
percent power factor, and 16.66 MW at a 95 percent power factor. Operation has
never occurred in this range during the life of the plant. The transformers limit the
project power output to 25 MV A. The generators are classified as suspended types
with a combined thrust and guide bearing located above the rotor and a guide bearing
located below. A major feature is a self-ventilated cooling system where cooling air is
circulated in a closed loop through air-to-water heat exchangers located within the
housing. Another feature is an air brake system capable of stopping the unit from
one-half rated speed within seven minutes. The overall condition of the generators is
considered to be good to excellent.
Each unit was generating with an output of approximately 5 MW and 2 MV AR at the
time of the inspection on October 16, 1995. The Swan Lake generator is rated at 12.5
MV A and 90 percent power factor, hence, each unit was operating at 43 percent of the
rated generator output at the time of the inspection.
%0208
7176/G 2028SW At'I.WP 2-14
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Unit 2 stator windings were replaced in 1994 after an internal fault. During this out-
age, the bearings and shaft were realigned. The lower guide bearing for Unit 1 is
operating at higher than normal temperatures when set to manufacturer's specifica-
tions. Readjustment of the bearing settings could place undue stress on other genera-
tor and turbine components. The heating condition can be corrected by KPU with the
addition of external oil coolers.
The steel collector rings were replaced on Units 1 and 2 in 1992 and 1993, respective-
ly. The rings on the first unit were replaced by A-C Equipment Co., the rings on the
second unit were completely replaced by KPU. Replacement has extended the life of
the brushes for the field leads from several months to three years.
The rotor for Unit 2 was removed and inspected in 1994. The rotor for Unit 1 has
never been removed but is inspected annually. The brake rings and brake shoes for
both units were reported by KPU to be in very good condition. Upon inspection, the
generator air housings and air coolers for both units were in good condition.
In the past, oil vapor accumulated in the collector ring area. This vapor came from
the bearing oil reservoir located directly below the collector ring assembly because
there was no oil seal between the generator shaft and the oil reservoir. KPU installed
a steel plate below the collector ring assembly which reduced the amount of vapor.
Installation of an oil seal barrier between the generator shaft and the oil reservoir
should eliminate this problem altogether.
The excitation system has produced maintenance problems since initial operation. The
problems have included erratic operation of the motor-operated potentiometers, power
supplies being too sensitive to fluctuations, the main DC relay coil being energized
continuously causing the relay coil to overheat frequently, and erratic operation of the
control relays. The motor-operated potentiometers have been replaced. The control
circuits with the power supplies should be replaced with a micro processor.
RTDs (resistance temperature detectors) and auxiliary devices such as speed switches
and temperature relays are in satisfactory condition, with the exception of the defective
oil thermal relay device on Unit 1. This device should be replaced.
960208
7176/G 2028SWAN.WP 2-15
Recommendation. The following are recommended:
1. Install external oil coolers to alleviate the high operating temperatures for the
Unit 1 lower guide bearing. High operating temperature could shorten the
lift of the bearings. This modification is planned and budgeted.
2. Replace the excitation system power supply for both units.
3. Replace defective oil thermal relay device on Unit 1.
KPU has considered the possible merits of installing an oil seal between the generator
shaft and the oil reservoir, but has no current plans to do so.
2.4.8 Governors
Condition Assessment. Each Francis turbine is controlled by an electrical-hydraulic
and cabinet type governor for maintaining the operating speed and positioning the
wicket gates. The governors were manufactured by the Woodward Governor Compa-
ny. The speed sensing of the governor is accomplished by a speed signal generator
mounted on the top of the generator. The normal operating pressure of the governing
system is 300 psi. Minor adjustments and routine maintenance have been performed
on both governors. The governors are kept very clean and in good operating condi-
tion.
2.4.9 Butterfly Valves
Condition Assessment. Each turbine inlet is guarded by a butterfly valve manufactured
by Litostroj. A 210 psi pressure oil system is used to operate the valve. The inlet
valve is designed to close against full turbine discharge for protection of the unit under
runaway conditions. Under balanced head across the valve disc, the valve closing
time is designed to be approximately 70 seconds. This 70-second closure is satisfacto-
ry. However, the operating personnel indicate that the actual valve closing time is
several minutes. In general, both butterfly valves are reported to be in good operating
conditions.
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717(,/G 2028SWAN.WP 2-16
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Recommendation. It is recommended that the inlet valve closing time be verified
under no flow conditions, and adjusted as necessary. This can be done by plant oper-
ating personnel.
2.4.10 Powerhouse Auxiliary Mechanical Equipment
Condition Assessment. The service water is withdrawn from the Unit I penstock
through a 6 inch header. The raw water is fed through a high pressure automatic
strainer and a pressure reducing valve. From the pressure reducing valve, water is
piped to each unit's cooling system. The generating units must be shut down in order
to service either the automatic strainer or the pressure reducing valve. A spare pres-
sure reducing valve is on hand, but replacement may take several hours. A duplicate
cooling water system supplied from the Unit 2 penstock and connected to the existing
cooling water system with an isolation valve is desirable to reduce the potential for
plant outages.
The draft tube gates are the carbon steel bulkhead-type with rubber side and top seals,
and rubber wedge-type bottom seals. The carbon steel bolts for mounting the rubber
seals have shown signs of corrosion because of the sea water at the tailrace. Replace-
ment of the draft tube gates with new gates made of stainless steel is planned.
Other auxiliary mechanical equipment, such as the powerhouse crane, station service
air system, unit unwatering system, potable water system, sewage system, drainage
system, heating and ventilation system, fire protection system and machine shops, are
in good operating condition.
Recommendation. The following are recommended:
1. Replace the draft tube gates as planned.
2. To eliminate the need to shut down the units to service either the automatic
strainer or the pressure reducing valve, install a duplicate cooling water sys-
tem supplied from the Unit 2 penstock and connected to the existing cooling
water system.
96020S
7176/G 2028SWAN.WP 2-17
2.4.11 Station Service Transformer and Switchgear
Condition Assessment. The station service switchgear is a double-ended substation
with two transformers and their main circuit breakers interconnected to a common
480-V bus. Each transformer has the capacity to supply the total station load plus the
site facilities. The original transformers were replaced in 1991.
2.4.12 Battery and Battery Charger System
Condition Assessment. The DC power system consists of one 60-cell battery bank and
two battery chargers. The battery chargers normally supply the DC power to the sys-
tem as well as charging current to the batteries. The batteries appear to be in good
physical shape with very little accumulation of sediment in the cell bottom and very
little plate growth. However, the battery specific gravity readings have been decreas-
ing over the last few months. This reduction in levels is an indication that the batteries
are nearing the end of their useful life, and should be replaced within five years.
Battery capacity performance tests should be performed on the batteries to determine
expected useful life.
Recommendation. Replace the 125-V powerhouse battery system within the next five
years.
2.4.13 SCADA System
Condition Assessment. Swan Lake generating units are normally controlled from the
control room of the Bailey Powerplant. A SCADA system provides operator control
for loading each unit. Manual control at Swan Lake is also possible. The SCADA
system was originally installed in 1982 but the upgrades over the years have provided
a reliable system. The last upgrade occurred three years ago.
2.4.14 Communications
Condition Assessment. Communication between Swan Lake and Bailey Powerplant is
facilitated through a microwave system owned by AEA. The system has proved reli-
able with the exception of a fade problem created by the passive repeater. Installation
of the pressurized waveguide appears to have corrected this problem. KPU is present-
960208
7176/G 202llSWAN.WP 2-18
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ly investigating a dial-up satellite communication system as a backup to the micro-
wave system.
2.4.15 Emergency Generator
Condition Assessment. The two diesel generators which provide backup power are in
excellent condition. Each generator is rated 430 kW, 480 V. Generator "A" has 1345
hours of operation and generator "B" has 475 hours of operation.
Recommendation. One generator should be adequate for this facility. Therefore, re-
placement of only one unit is required.
2.4.16 Intake Power Feeder
Condition Assessment. The power feeder cable is installed in the penstock, and it was
not possible to inspect the cable. However, plant personnel reported it to be in poor
condition. A new 13.8-kV feeder to the intake is planned to replace the existing pow-
er feeder cable.
Recommendation. Replace intake gate feeder cable.
2.4.17 Protective Relaying
Condition Assessment. Generator protective relays are adequate for protection of the
generators, main leads, and power transformers. New protective distance relays are
being considered for the transmission line.
2.4.18 Powerhouse Switchyard
Condition Assessment. One set of three single-phase transformers, each with an
OA/FA rating of 6.66/8.33 MVA, is located in the switchyard. A spare transformer is
also installed in the switchyard. The transformers were recently painted and appear to
be in good condition. The spare transformer was missing a gas pressure indicator.
Plant personnel indicated that a new indicator was ordered. The load on the trans-
formers is such that the cooling fans never operate automatically. Plant personnel
routinely operate the fans manually to verify their operation.
96020ll
7176/G 2028SWAN.WP 2-19
The rating of the transformers limits the Swan Lake power output to 25 MVA.
2.4.19 Transmission Line
The transmission line is a single circuit line, about 30.5 miles in length, designed for
and operated at 115 kV. The line is supported on wood pole H-frame structures. This
is the only line that connects the Swan Lake Project to the KPU system. Any failures
on the transmission line will shut the plant down. For this study, sections of the line
were inspected by vehicle and the entire line was flown by helicopter.
Landslide Activity
Condition Assessment. There is evidence of historical and potential landslide activity
in the vicinity of the Carroll Inlet area, between tower locations 262 and 266. Land-
slides have occurred on both sides of one of the towers. Although the tower has not
been damaged, it is evident that the area is unstable, and any additional landslide
activity could take this section of the line out of service.
Recommendation. The following are recommended:
1. Conduct a geotechnical investigation of the area to establish the degree of
soil stability.
2. Relocate line section in the Carroll Inlet area (1 to 2 miles) or take other
steps to prevent landslide activity and destruction of the line section.
Insulators
Condition Assessment. The insulators are a polymer type fabricated by Lapp. In one
of the locations, the wood poles caught fire and had to be replaced. None of the insu-
lator assemblies appear to be bonded and connected to ground.
Recommendation. The following are recommended:
1. Insulator assemblies that have been in service should be tested to evaluate if
there is a degradation in the insulation strength of the assembly. If insulators
are found to be electrically defective they should be replaced.
2.
9Cl020S
If the utility experiences any additional fires on the wood poles, then a pro-
gram should be implemented to connect the insulator attachment to ground.
7176/G 2028SWAN.WP 2-20
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Pole Replacement
Condition Assessment. The poles are placed in 5-to 60-ft supporting steel "cans."
The steel cans can weigh up to 6,400 pounds. To work on the steel cans and poles, a
special helicopter is needed with a lifting capacity of about 20,000 pounds. Repair
time is estimated to be up to six weeks, depending upon the weather.
Recommendation. To enhance future maintenance and replacement of wood poles in
the event of a failure, the system illustrated in Figure 2-2 should be evaluated. Anoth-
er pipe section and mounting plate could be fabricated to fit over the existing steel
can. The wood pole would be removed from the existing supporting can, and if nec-
essary, saw cut above the in-place can. The new pipe section with a plate can be
placed on top of the existing can. A new steel pole section of equivalent strength can
be bolted to the plate. A number of pipe sections and steel poles should be kept in
storage for emergency conditions.
H-Frame Structure Arms
Condition Assessment. The suspension H-frame structure arms are not braced, and
after 12 years of service, some arms are beginning to bend or bow. Knee braces were
installed on some of the tangent structures this past year to reinforce the cross arm as
shown on Figure 2-3.
Recommendation. It is recommended that the program of reinforcing the arm of the
suspension wood pole H-frame be continued.
Guy Wire Supports
Condition Assessment. Some of the single shaft wood poles at transmission line angle
points are supported with guys attached to the pole roughly halfway between the
ground and the top of the pole. Excessive bending occurs at the connecting point. A
program has been initiated to install an additional guy wire attached to the pole near
the conductor attachment as shown in Figure 2-4.
Recommendation. Continue program to install additional guy wires on selected struc-
tures.
2.4.20 Bailey Substation
Condition Assessment. Overall, the substation appears to be in good condition. Grad-
ing and drainage are adequate. Oil recovery facilities are in place. There is a high
96020~
7176/G 2028SW AN.WP 2-21
concentration of salt in the atmosphere that contributes to increased corrosion rates.
For example, the oil circuit breaker enclosures require frequent maintenance to control
corrosion.
Three single-phase, 6.7/8.3-MVA OAIFA transformers, plus one spare, are located in
the substation.
Recommendation. The transformer tanks are corroded and should be painted. The
transformer cooling radiators are badly corroded. The transformer cooling radiator
walls are very thin, and the cooling fins are closely spaced. The cooling radiators
cannot be scraped and painted and should therefore be replaced.
2.4.21 Spare Parts
Condition Assessment. An adequate number of spare stator coils are available. Addi-
tional spares include one field pole, one single-phase transformer, one oil circuit
breaker bushing, a set of brake shoes, bearings, and a cooling water system pressure
reducing valve. Spares are not available for the 15-kV switchgear, air cooler and oil
cooler. A turbine spare runner, an adequate number of spare wicket gates, two turbine
guide bearings and a set of runner wearing rings are available. Also, a cooling water
system pressure reducing valve is on hand.
2.4.22 Rolling Stock
Condition Assessment. The rolling stock located at Swan Lake is owned by AEA, and
consists of the following:
l. Pickup truck -fairly new and in good condition;
2. Boom truck -good condition;
3. Backhoe -good condition;
4. Front-end loader -inadequate for application;
5. Forklift -fair operating condition;
96020~
7!76iG 2U28SWAN.WP 2-22
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6. Four-wheel vehicle -in good condition; and
7. Skiffs (2) appear to be adequate.
Apparently FERC has approved the removal of the skiff from the reservoir, leaving
only one skiff (at the bay) for the project.
Recommendation. The front-end loader is in good condition, but it has insufficient
load capacity and is difficult to control in snowy conditions. Acquisition of a new
front-end loader is recommended.
2.4.23 Infrastructure
The infrastructure consists of housing-units, storage facilities, boat dock, and other
items. These facilities have varying service lives and replacement costs. The housing
units, storage and other facilities are estimated to have a service life of 30 years. The
dock facilities are estimated to have a service life of 15 years. At the end of the ser-
vice lives of these facilities, an estimated 75 percent of the replacement value is in-
cluded to replace or to upgrade these facilities to current standards. An estimate of
the typical service life replacement costs and schedule for replacement for these items
has been made and included as part of the information provided in Tables 2-5 and 2-6.
2.4.24 Documentation
Condition Assessment. The drawings appear to show "as-built" conditions with minor
exceptions.
Recommendation. Updating of drawings to as-built condition is recommended. The
effort would only involve transferring information from marked-up drawings to the
original tracings.
General Comment: Drawings and records for the project are stored in a rented storage
facility in anchorage. It is important that these records be preserved and transferred to
the new project owners upon completion of the transfer of ownership.
96020il
7176/G 2028SWAN.WP 2-23
2.4.25 Conclusions
Table 2-5 lists the major project equipment, and provides an assessment of the condi-
tion of each item. Table 2-5 also indicates the expected service life, assuming (a) the
conditions prevailing at the project site, (b) no deferred maintenance, and (c) no defi-
cient design. Lastly, Table 2-5 indicates the replacement cost of each equipment item.
All structural components are considered to be in good shape, and are expected to
perform well beyond the remaining 38 years of the nominal 50 year life of the project.
No items of deficient design are noted.
The only item of deferred maintenance is the need to replace the cooling radiators at
the Baily substation.
An estimated disbursement schedule for correcting design deficiencies, deferred main-
tenance, other general project improvements, and replacements due to normal wear and
tear is presented in Table 2-6.
%020l\
7176/G 2028SWAN.WP 2-24
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Table 2-6
Page 1 of2 ,,
SWAN LAKE PROJECT • EXPECTED SERVICE LIFE AND REPLACEMENT COSTS
(where applicabk!, replacement costs are for both generating units)
Expected Remaining 1995 Price Level
Item Condition Service Life Service Life Replacement Cost
(years,l (years) ($)
(see note a)
Equipment
Turbine and other Mechanical Items
Runner Excellent 50 38 1.450,000
Wicket Gates Excellent 50 38 450,000
Remaining Turbine Parts Excellent 50 38 3,100,000
Governor Excellent 50 38 600,000
Butterfly Inlet Valve Good 50 38 500,000
Cooling Water System Good 25 13 85,000
Draft Tube Gate Fair 20 e 80,000
Other Aux Mechanical Equip Good 35 23 345,000
Generator
Stator Excellent 25 13/24 d 1,000,000
Rotor Excellent 35 23 410,000
Bearings Fair 30 18 400,000
Cooling System Good 30 18 150,000
RTDs, Sensing Devices Good 30 18 7,000
Fire Protection Good 35 23 5,000
Excitation System Poor 25 13 200,000
Electrical System
Battery and Chargers Poor 25 3 b 100,000
Controls and Protective Relaying Good 25 13 180,000
Station Service Excellent 30 25 c 270,000
15-kV Switchgear Good 25 13 100,000
Cable System Good 50 38 250,000
SCADA System Excellent 15 13 c 450,000
Communications Excellent 15 13 c 150,000
Emergency Generator Excellent 30 18 200,000
Intake Gate Electrical Controls Good 25 13 20,000
Switchyard, Transmission Line and Substation Equipment
Switchyard at Powerhouse
Transformers Good 30 18 350,000
Circuit Breakers Good 25 13 76,000
Disconnect Switches Good 35 23 30,000
PTs, CTs, Wave Traps Good 30 18 100,000
Bus Structures Good 40 28 150,000
All other Good 35 23 300,000
Table 2-5
Page 2 of 2
SWAN LAKE PROJECT • EXPECTED SERVICE LIFE AND REPLACEMENT COSTS
(where applicable, replacement costs are for both generating units)
Expected Remaining
Item Condition Service Life Service Life
(years) (years)
(see note a)
Transmission Line
Insulators Good 40 28
Hardware Good 40 28
Conductors Good 40 28
Structures Good 80 68
Foundations Good 80 68
Bailey Substation
Transformers Good 30 18
Circuit Breakers Good 25 13
Disconnect Switches Good 35 23
PTs, CTs, Wave Traps Good 30 18
Bus Structures Good 40 28
All Other Good 35 23
Rolling Stock
Pickup Truck Good 10 8
Boom Truck Good 10 8
Back Hoe Good 8 6
Front End Loader Good 10 0
Forklift Fair 10 6
Four-Wheel Vehicle Good 10 10
Skiffs (including motor) Good 12 6
Infrastructure
Housing Fair 30 18
Storage and Other Fair 30 18
Docks Fair 15 12
Notes.
a Plant was essentially completed in 1984, and entered commercial service on June 7, 1984.
Actual in-service time is about 12 years.
b Indicates that remaining life is less than expected.
c Indicates system that was replaced or modified since original construction.
d One stator winding was replaced in 1994.
e Budgeted for replacement in 1996; estimated life of stainless steel replacement is 40 years.
1995 Price Level
Replacement Cost
($)
515,493
859,155
2,291,080
6,142,958
8,004,461
350,000
76,000
30,000
100,000
150,000
300,000
25,200
91,200
90,000
231,600
40,000
6,000
12,000
300,000
375,000
75,000
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Table 2-<1
Page 1 of 3
SWAN LAKE PROJECT· PROJECTED MOST LIKELY REPAIR AND REPLACEMENT COSTS
(in US dollars, at 1995 price levels, excluding repairs or replacements due to natural events. accidents or equipment faAures)
Structure 1996-2000 2001-05 2006-10 2011-15 2016-20 2021-25 2026-30
Remedial Work for Items of Deficient Design
None
Remedial Worl< for Items of Deferred Maintenance
Replace corroded cooling radiators at Bailey substation 20,000
Other Project Improvements
Structures
Improve reservoir trash handll!lg system 290,000
Construct flow measuring weirs downstream of dam budgeted
1m prove access to left abutment of dam 30,000
Take soundings in plunge pool a
Test use of compressed air for turbine performance a
Equipment
0\terhaut unit 1 turbtne guide bearing 10,000
Install coolers on generator unit 1 lower guide bearing budgeted
Replace excitation power supply (2 unns) 60,000
Replace oil reservoir temperature sensing device 400
Replace draft tube gate budgeted
Connect cooling water system to unrt 2 penstocl< 35,000
Replace 125 V·batterv system 60,000
Replace intake gate feeder cable budgeted
Acquire a new front end loader 231,600
SWitchyard, Transmission Line and Substation Equipment
Conduct geotechnical investigation of landslide by Carroll Inlet 25,000
Relocate 1 to 2 miles of line to avoid avalanche outage 1,000,000
Test insulator assemblte:s and evaluate wood pole fire potential 20,000
Install grounding wtre and connect to insulator hardWare 100,000 b
Cost for steel pole spares (6 poles) 20,000
Steel pipe sleeves (spares) for use wnh existing steel "can" 20,000
Install brace on suspension H-frame structures 80,000
Install addttional guy wires on selected structures 80,000
Bailey substation • paint transformer tani<S 5,000
Complete As-Built drawings 20,000
Replacements due to Normal Wear and Tear
structures
Walkway to lett abutment 30,000 b
Epoxy patching powerhouse backwall 20,000 20,000 20,000
Archttectural refurbrshment 200,000
Equipment
Turbine and Other Mecham:al Items
Turbine Runner and Wicket Gates
Governor
Inlet Valve
Draft Tube Gates
Cooling Water System 85,000
Other Auxilial)' Mechanical Equrpment 345,000
Generator
Stator 500,000 500,000
Rotor 410.000
Bearings 400,000
Cooling System 150.000
RTDs, Sens~ng Oev1ces 7,000
Depreciation Depreciation
Used Allllilable
Next Reelacement Through 2030 After 2030
2036
2031
2045
2033 4.700,000 300,000
2033 564 000 36,000
2033 470,000 30,000
2036 68,000 12,000
2033 74,800 10,200
2053 118.286 226.714
U1 coils in 2033, U2 coils in 2044 670,000 330.000
2053 140.571 269.429
2043 226.667 173.333
2043 85.000 65 000
2043 3.967 3 033
Table 2-li Page 2 of 3
SWAN LAKE PROJECT-PROJECTED MOST LIKELY REPAIR AND REPLACEMENT COSTS
(in US dollars, at 1995 price levels, excluding repairs or replacements due to natural events, accidents or equipment failures)
Depreciation Depreciatior,
Used Available
Structure 1996-2000 2001-05 2006-10 2011-15 2016-20 2021-25 2026-30 Next Reelacement Throu~h 2030 Aller 2030
Fire Protection 5,000 2053; Check C02 gas annually 1,714 3,286
Excltalion System 200,000 2033 176,000 24,000
Electrical System
Battery and Chargers 100,000 2048 28,000 72,000
Controls and Protective Relaying 180,000 2033 158,400 21,600
station Service 270,000 2050 90,000 180,000
15-kV Swrtchgear 100,000 2033 88,000 12,000
Cable Syslem 2033 235,000 15,000
Intake Gate Electrical Controls 20,000 2033 17,600 2,400
SCADA System 450,000 450,000 2038 210,000 240,000
Communications 150,000 150,000 2038 70,000 80,000
Emergency Generator 200,000 2043 113,333 86,667
Switchyard, Transmission Line and Substation Equipment
Powerhouse Switchyard
Transformers 350,000 2043 198,333 151,667
Circuit Breakers 76,000 2033 66,880 9,120
Disconnect Switches 30,000 2053 10,286 19,714
PTs, CTs, Wave Traps 100,000 2043 56,667 43,333
Bus structures 150,000 2063 26,250 123,750
All Other 300,000 2053 102,857 197,143
Transmission Line
Insulators 515,493 2063 90,211 425,282
Hardware 859,155 2063 150,352 708,803
Conductors 2,291,080 2063 400,939 1,890,141
Structures 2063 3,608,988 2,533,970
Foundations 2063 4,702,621 3,301,840
Bailey Substation
Transformers 350,000 2043 198,333 151,667
Circuit Breakers 76,000 2033 66,880 9,120
Disconnect Switches 30,000 2053 10,286 19,714
PTs, CTs, Wave Traps 100,000 2043 56,667 43,333
Bus Structures 150,000 2063 26,250 123,750
All Other 300,000 2053 102,857 197,143
Rolling stock and other
Pickup Truck 25,200 25,200 25,200 Replacemenl every 10 years 12,600 12,600
Boom Truck 91,200 91,200 91,200 Replacement every 10 years 45,600 45,600
Back Hoe 90,000 90,000 90,000 90,000 Replacement every 8 years 33,750 56,250
Front End Loader 231,600 231,600 231,600 Replacement every 10 years 231,600
Forklift 40,000 40,000 40,000 Replacement every 10 years 20,000 20,000
Four-Wheel Vehicle 6,000 6,000 6,000 Replacement every 10 years 3,000 3,000
Skill 12,000 12,000 12,000 Replacement every 12 years 5,000 7,000
Tugboal 40,000 2036 28,000 12,000
Logskidder 25,000 2036 17,500 7,500
Infrastructure
Housing 300,000 2044 170,000 130,000
storage and other 375,000 2044 212,500 162,500
Docks 75,000 75,000 75.000 2044 -40000 ~
.....
Table 2-6
Page 3 of 3
SWAN LAKE PROJECT ·PROJECTED MOST LIKELY REPAIR AND REPLACEMENT COSTS
(in us dollars, at 1995 price levels. excluding repairs or replacements due to natural events, accidents or equipment faHures)
Depreciation
Used
Structure 1996-2000 2001-05 2006-10 2011-15 2016-20 2021-25 2026-30 Next Replacement Through 2030
DEPRECIATION TOTALS
5-YR TOTALS
Remedial Work for Items of Deficient Design
Remedial Work lor Items ol Deferred Maintenance 20,000
Other Project Improvements 2,067,000
Replacements due to Normal Wear and Tear 284,400 2,143,600 2,846,400 2,576,600 4,935,128 396,600
Allowances For Replacements Alter 2030 (1) 359,309 373,252 408,645 544,895 716,926 960,453 1,291,170
LEVELIZED PAYMENT ANALYSIS
Replacements due to Normal Wear and Tear (2)
Begonnong of Perood Fund Balance 2,394,116 5,201,112 6.051,719 5,650,771 5,116,978 (1 ,074, 131)
Annual Contribution of $400,667 to Reserve Fund 2,003,337 2,003,337 2,003,337 2,003,337 2.003,337 2,003,337 2,003,337
Expense (333,220) (2, 772,975) (4,065,360) (4,063,039) (8,592, 177) (762,357)
Interest on Average Fund Ba,ance 390,778 1,136,879 1.620,245 1,661,076 1,525,908 397,731 (166,850)
End of Period Fund Batance 2.394,116 5,201,112 6,051,719 5,650,771 5,116,978 (1 ,074, 131) (0)
Allowances for Replacements after 2030 (3)
Beginning of Period Fund Balance 409,816 890,374 1,427,694 1,853,998 2,000,663 1,564,918
Annual Contribution of $144,524 to Reserve Fund 722,622 722,622 722,622 722,622 722,622 722,622 722,622
Expense (381,898) (437,495) (530, 198) (782,090) (1, 132,910) (1,680,906) (2,484.013)
Interest on Average Fund Balance 69,092 195,432 344,897 485,772 556,954 522,539 196,473
End ol Period Fund Balance 409,816 890,374 1.427,694 1,853.998 2.000,663 1,564,918 (0)
a Indicates that the cost for this item is assumed to be included as a part of the normal operations budget and the required activities can be carrted out by ptant personnel as part of day~ to-day activities
b Indicates an item that is contingent on implementation of a recommended project improvement
(1) Calculated in 1995$, us1ng a 4% real discount rate
(2) Analysis assumes a 2% escalation rate, a 6% interest rate an avanable funds, a 8% borrowing rate, and one lump sum payment in the middle o1 the fiv&-year period.
(3) Analysis assumes a 2% escalafion rate, a 6% Interest rate an available funds, a 8% borrowing rate, and beginning of year payments to replacement funds.
18.772.945
Depreciation
Available
Mer 2030
12,865,202
1.600
1.500
1.400
1,300
1,200
1.100
1,000
900
~
"'-800 J
.¥.
700
600
500
400
300
200
100
-Generating Discharge =Spillway Discharge __,._ Powerplant Hydraulic Capacity -Lake level
------....~ /"\. L-.......----...... ......-.,.
~ \ I \_/'-!~A / v VV\ /'../ .A
~ vv V"-J
--
-
-
r--f------------
r-f-::----f--
--I
OIIIJ~•a•JJASOIIIJf·A·JJAIOIIDJf·A·JJASOIII IIAIIJJASOIIIJfiiAIIJJASOIIIJFIIAIIJJASOIIDJfiiAIIJJAIOIIIJFIIAMJJA!IiOIItJf
400
375
350
325
300
275
250
225 ... .. . ...
200 i
;;
175.:...
150
125
100
75
50
25
[ill!] I 1987 I I 1988 I I 1989 I [ 199o I I 1991 I I 1992 I I 1993 II 1994 I (']!ill
Figure 2-1 Swan Lake Project -Measured Historical Flows and Lake Levels
I I
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Figure 2-2 Swan Lake Project -Fabrication of New Pipe Support for Transmission Structures
. Rgure 2-3
Figure 2-4
0 0
Brace added to the
SIIUcture
Swan Lake Project • Reinforcement of H-Frame Transmission Structures
Swan Lake Project -Location of New Guy Wiring on Transmission Structures
Chapter 3
Solomon Gulch
Chapter 3
SOLOMON GULCH
3.1 Project Description
This project is located on the south shore of the Valdez Arm, approximately four miles
southeast of Valdez, Alaska. The project consists of a rockfill dam and dike, two 48-
inch diameter steel penstocks, each 3,800 feet long, and a powerhouse with two gener-
ating units and a switchyard. The project also includes three substations (Meals, P11
and P12) and a 112-mi-long transmission line between Valdez and Glennallen. The
project general arrangement and sections of major project features are illustrated on
the project drawings included in Appendix B. Table 3-1 presents pertinent project data.
Solomon Gulch was constructed by the Copper Valley Electric Association (CVEA),
and was purchased by the Alaska Power Authority (now known as Alaska Energy
Authority or AEA) under the Energy Program for Alaska. The project is operated by
the CVEA under an agreement with AEA. The project went into commercial service
on July I, 1982.
The turbines are vertical-shaft, single-runner, Francis type, designed to operate at a
speed of 900 rpm. Each of the two generators is rated at 7.5 MVA. The turbines and
generators were manufactured by Fuji Electric.
A paved road provides access to the project.
3.2 Installed Capacity and Energy Generation
3.2.1 Monthly Flows
Flow records for a period beginning in January 1987 to about mid-1995 were ana-
lyzed. Data from two separate sources was reviewed. Information on powerplant
generating discharge and downstream release for the period beginning in January 1994
was available from plant operating records (see Appendix B). Similar information
prior to January 1994 was available from the U.S. Geological Survey. A time-series
plot of generating discharge and flow measured in Solomon Gulch at a point below
the dam are illustrated on Figure 3-1.
960208
7l76/G 2028SOLO.WP 3-1
Table 3-1
SOLOMON GULCH-SIGNIFICANT DATA
RESERVOIR
Normal Maximum Pool Elevation
Normal Minimum Pool Elevation
Maximum Active Storage
Drainage Area
DAM
Type
Crest Elevation
Height
Length
SPILLWAY
Type
Length
Crest Elevation
PENSTOCKS
Number
Length (each)
Diameter
Type
EQUIPMENT
Nominal Plant Generating Capacity
Number of Units
Type of Turbines
Maximum Gross Head (approximate)
Turbine Power Output (each, at 620 ft net head)
Generator Rating (each)
Speed
TRANSMISSION LINE
Length, Meals Substation
Voltage, Meals Substation
Length, P 11 Substation
Voltage, Pll Substation
960208
7176/G 2028SOLO.WP 3-2
685ft
618 ft
31,500 ac-ft
19 sq mi
Rockfill with asphaltic-concrete facing
690ft
115 ft
386ft
Ungated concrete ogee
450ft
685ft
2
3,800 ft
48 inches
Steel
12 MW at 80 percent power factor
2
Vertical shaft Francis
670ft
8,770 hp
7.5 MVA
900 rpm
4 mi
25 kV
112 mi
138 kV
•
•
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•
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1
The average flow at the project site, based on data shown on Figure 3-1, is approxi-
mately 157 cfs. The average generating discharge is 123 cfs. The maximum
powerplant discharge capacity is approximately 276 cfs. The average historical flow
for the period analyzed is about 57 percent of the hydraulic capacity of the plant.
In accordance with an agreement between the State and the Valdez Fishery Develop-
ment Association, water is supplied to the hatchery located adjacent to the project.
Plant personnel report that the water requirement is about 4000 gpm. This water is
either pumped from the tailrace or withdrawn from the penstocks.
3.2.2 Energy Generation Potential
The plant has two units, with a combined installed capacity of 15 MV A. At a power
factor of 80 percent, the maximum combined power output of the units is 12 MW.
Based on data for the 10 most recent fiscal operating years (period ending June 30,
1995) the historical average annual generation has been about 39.6 GWh. In the last
three years production averaged 46.7 GWh per year. Historical production, as fur-
nished by ABA, is listed in Table 3-2.
Peak electrical demand occurs during the winter, while summer electrical demands are
lower. During the summer months, larger than average streamflow typically refills the
reservoir, and the reservoir storage is then used during the winter months to meet
heavier electrical demands. The reservoir typically spills in about three months during
the summer but the units are not always operated to their full hydraulic capacity at
these times. The units probably cannot be operated at full hydraulic capacity to avoid
spill because of the lower summer electrical demand.
In recent years, the demand has increased due to industrial development in the area
served by the project. Plant personnel report that spills during recent years have been
lower than in early years of project operation.
Based on limited flow data gathered for this study, a preliminary estimate of the ener-
gy generation potential of the existing project, assuming that all of the available sum-
mertime energy could be utilized, is 52.9 GWh per year. The total annual energy
production appears to be trending upward toward this estimated average annual energy
generation potential.
960208
7176/G 2028SOLO.WP 3-3
Table 3·2
SOLOMON PROJECT -ANNUAL GENERATION
Year Ending Actual kWh
6/30/86 21,594,057
6/30/87 40,584,034
6/30/88 38,582,126
6/30/89 36,686,771
6/30/90 39,388,355
6/30/91 39,147,589
6/30/92 40,159,656
6/30/93 41,304,151
6/30/94 50,311,427
6/30/95 47,814,381
Total 395,572,547
Average 39,557,255
10 years
Last 3 years 46,476,653
3.2.3 Effects of Drought
The potential impact of drought on energy generation can be investigated by analyzing
long-term streamflow records. The actual streamflow and release data available for
the plant is too short to draw definite conclusions about the impact of drought. How-
ever, it is possible to infer the magnitude of the reduction in generation that might
occur in water short years by investigating the characteristics of streamflow in nearby
rivers that have long-term streamflow records.
A streamflow gaging station on Power Creek near Cordova is located about 60 miles
south of the project site. This gage measures a runoff from an area of about 20.5
square miles, which is about 108 percent of the drainage area of the Solomon Gulch
Project. The streamflow record contains data for a period of 46 years. Total annual
flow for each year was tabulated, and the distribution of years with lower than average
flow are indicated below:
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Number of years with annual flow:
less than 80 percent of average flow
between 80 and 85 percent of average flow
between 85 and 90 percent of average flow
between 90 and 95 percent of average flow
between 95 and 100 percent of average flow
above 1 00 percent of average flow
4 out of 46 years
4 out of 46 years
5 out of 46 years
6 out of 46 years
6 out of 46 years
21 out of 46 years
Because of its preliminary nature, the above analysis is not conclusive. However, it
can be inferred that 8 percent of the time, the annual generation might be 20 percent
less than average. A detailed hydrologic analysis is required to provide more defini-
tion of the characteristics of generation under drought conditions.
3.2.4 Potential for Expansion
Over the few years of streamflow record illustrated in Figure 3-1, spill is estimated to
be equivalent to an average and continuous flow of 34 cfs. Subject to demand re-
quirements and economic decision criteria, this spilled water could be used far energy
production.
Increasing the plant hydraulic capacity by 50 percent might be accomplished by add-
ing a third 7.5 MVA unit. The incremental energy production associated with this
expansion is estimated to be on the order of 5 GWh per year. At an average energy
purchase rate of 6 cents per kWh, the increase in annual revenue would amount to
about $300,000 per year.
At Solomon Gulch, the expected cost to construct a 7.5-MVA expansion, including the
penstock and penstock valve; turbine, governor, and inlet valve; generator and exciter;
ancillary equipment costs; and powerhouse expansion, would be at least $8.5 million,
or about $1400 per kW.
Consideration was given to the possibility of increasing the storage to capture and
store excess flows during the summer, when flows are higher, but electrical demand is
low. Plant personnel report that a detailed study was carried out and concluded that
increasing the size of the reservoir for providing additional flow regulation is not
warranted or economically justified at this time. 1
Allison Lake Study by HDR Engineers, September, 1992.
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Based on the above information, it is concluded that there is little potential for expan-
sion of the project at this time.
3.3 Generating Unit and Transmission System Availability
Data furnished for analyzing the availability of the plant is presented in Appendix B.
The data includes a list of outage events from January 1, 1987 to the present. In
addition, plant operation personnel were interviewed, and the FERC annual operation
reports were reviewed.
Excluding the extended outages due to failure of the transmission line by avalanches,
(see discussion in Section 3.3.2) the average annual outage time, on the basis of infor-
mation contained in Appendix B, is tabulated below:
Valdez System Outage
Glennallen System Outage
Total System Outage Excluding
Valdez and Glennallen Outages
Other pertinent observations and conclusions are presented below.
3.3.1 Generating Unit Availability
0.36 hours per year
2.14 hours per year
2.85 hours per year
The four annual FERC operation reports for the period September 26, 1989 through
July 20, 1993 reported that there were no unscheduled unit outages. The most recent
report, for the period July 21, 1993 to July 11, 1994 stated that there were no unsched-
uled unit outages lasting longer than 24 hours, implying that there may have been
some minor unscheduled outage.
The list of outage events contained in Appendix B indicates that the plant was shut
down due to a transformer bushing failure on January 18, 1990, but the duration of
this outage is not stated.
In general, the generating unit availability has been good.
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3.3.2 Transmission System Availability
The plant was shut down for extended periods at least twice due to transmission out-
ages as described below:
• January 10, 1987 to January 26, 1987: avalanche at mile 53; 373 hour outage.
• December 16, 1988 to September 15, 1989: avalanche at mile 28; 6,573 hour
outage.
• March 17, 1987: helicopter accident at mile 18; outage duration not known.
Other minor transmission line outages occurred as listed in Appendix B. These in-
clude problems caused by ice build-up and subsequent phase to ground faults, storm
outages and falling trees.
3.4 Condition Assessment, Recommendations, and Costs
The following section describes the condition assessment and recommendations for
replacements and improvements. At the conclusion of this section, the costs for rec-
ommended improvements and replacements are summarized in tabular form.
3.4.1 Site Inspection Dates
On October 5 and 6, 1995, Messrs. J.H.T. Sun and J.J. Quinn of Harza and Stan
Sieczkowski of AEA inspected the Solomon Gulch Project electrical and mechanical
generating equipment. Civil and structural features were inspected by N. Pansic of
Harza on October 9 and 10, 1995. The transmission line and substations were inspect-
ed by Messrs. P.J. Donalek and A. Angelos of Harza on October 9, 10, and 23, 1995.
The inspection on October 9 consisted of a helicopter fly-over of the project, concen-
trating on the reservoir rim. The aerial reconnaissance was done to evaluate the poten-
tial for landslide or avalanche risks to the project structures --particularly the dams,
penstocks, and powerhouse. The inspection on October 10 was done on foot.
Mr. Pansic was accompanied by Mr. John Hunter, CVEA Power Plant Foreman, and
Mr. Remy G. Williams, AEA Consultant.
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On October 9, Messrs. R. Williams, P.J. Donalek and N. Pansic made a helicopter
inspection of the 138-kV transmission line between Meals and Pll substations. On
October 23, Messrs. A. Angelos, Remy Williams, and Mike Easley of CVEA inspect-
ed the transmission line between Meals Substation and Thompson Pass.
3.4.2 Reservoir
Condition Assessment. The valley walls surrounding the reservoir are fairly steep,
with low vegetation. According to the last FERC Part 12 Safety Inspection Report
(see references in Appendix A), snow avalanches are common, but they are small in
volume and occur at times when the reservoir is normally drawn down to minimum
level. Hence, there is little, if any, risk to the project dam, dike or spillway structures
due to snow avalanches into the reservoir.
The Part 12 Safety Inspection Report also addressed the geology and seismicity of the
project area. The report contained the following conclusions: the potential for signifi-
cant landslides into the reservoir is minimal and no evidence of any recent major
slides was noted during the aerial reconnaissance.
No evidence of any conditions that would contradict the conclusions of the Part 12
Safety Inspection Report were noted. Therefore, no risks to the reservoir due to snow
avalanche or landslides are known to exist.
3.4.3 Powerhouse
Condition Assessment. The reinforced concrete powerhouse is founded on sound rock,
and is located near the base of a steep rock face. Remedial work was performed on
the rock face in 1990 to reduce hazards to the powerhouse and exposed penstocks
from rockfalls. Observed from the powerhouse roof, the rock bolting, chain mesh, and
dental concrete appears to be intact and in good condition. No significant risk to the
structure from rockfalls is expected. According to John Hunter, a tree fell from the
slope above the maintenance building east of the powerhouse, dislodging a rock which
then fell and hit a truck parked at the powerhouse. This occurred outside of the area
protected by the rockbolting and wire mesh. A future occurrence could impact the
maintenance building or one of the power poles in this area. No action is recommend-
ed to prevent future occurrences as they are expected to be very infrequent and pro-
duce minimal damage to project structures.
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Because the powerhouse is located at tidewater, it is at risk of flooding due to an
earthquake-induced tsunami. Such an occurrence, similar to that which Valdez experi-
enced in the 1964 earthquake, would potentially flood the powerhouse controls and
force the plant off-line for a considerable amount of time.
The condition of the substation deck and powerhouse roof were noted to be satisfacto-
ry. The roof has recently been replaced. One maintenance item is some minor leak-
age between the precast concrete panels that face the upper powerhouse structure.
The interior of the powerhouse was inspected at all three levels (generator floor, tur-
bine floor, and tailrace) for evidence of settlement or structural problems. Only one
problem was noted as a result of the inspection. At the southeast comer of the power-
house, a hatch through the floor is provided to accommodate the generator rotor shaft
during removal for maintenance. A crack extends from the east wall of the power-
house to the hatch opening, and another crack extends from there to the spherical
valve opening. The cracks have propagated through the generator floor but do not
extend into the sidewall of the hatch below the bottom of the floor. The cracks are
tight. and CVEA has installed crack monitors at nine locations. These cracks appear
to be due to stress concentration between the hatch opening and the comer of the
powerhouse. The stress has apparently been relieved, and no further significant crack-
ing or movement is anticipated.
The inspection noted that the bulkhead system designed to isolate the draft tubes from
tail water did not function properly during a recent attempt to unwater this area. When
CVEA tried to close off a unit to facilitate some work at the fish hatchery down-
stream, they were unable to keep up with the leakage. The bulkheads are steel frames
with a skinplate. and are operated by a chain hoist. An inspection of the bulkhead
seals and sill plate is required to evaluate the reason for the malfunction.
Overall, the powerhouse appears to be maintained in excellent order.
Recommendation. The following two specific recommendations relate to the power-
house:
1. Repair concrete panels to stop minor leakage.
2. Inspect draft tube bulkhead leakage problem, including an inspection of the
bulkhead seals and sill plate. Detennine if any remedial action is needed.
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3. Architectural refurbishment should be anticipated after about 30 years of
service. (Year 2012).
3.4.4 Dam
Condition Assessment. Access to the main dam is by a gravel road from Dayville
Road, west of the powerhouse and Solomon Creek. The total length of access road-
way is 5.2 miles, of which approximately one mile is on the Alyeska Trans-Alaska
Pipeline access road. A light steel bridge structure crosses Solomon Gulch with a
steep approach from the west. This bridge appeared to be adequate, but should be
independently evaluated by a structural engineer as noted in the recommendations
below. The road also crosses the spillway channel near the point where it enters Solo-
mon Gulch. At the time of the inspection, the roadway was in fair condition. Mr.
Hunter indicated that the Alyeska portion needs to be regraded and some additional
gravel surfacing added to improve this portion which has deteriorated in some areas.
The 115-ft high main dam (asphaltic concrete-faced rockfill) was inspected by walking
the crest in both directions, viewing the parapet wall, the downstream face, and the
upper portion of the upstream face. No conditions were observed that would indicate
any structural problems with either the dam or the asphaltic concrete-face protection.
The downstream face of the main dam is somewhat non-uniform, but Remy Williams
reports that it has not really changed much from the original construction. There
appears to be a wide variation in stone size.
The joint between the asphalt facing and the parapet wall base (on both the main dam
and the dike) has recently been sealed in response to a recommendation in the latest
Part 12 Safety Inspection Report.
Seepage from the main dam is monitored via a rectangular weir located about 100ft
downstream of the toe. The recorded seepage flows are clear, have ranged from 5.7
cfs in 1983 to about one cfs currently, gradually reducing with time.
Although most of the upstream face was not visible for inspection, the low seepage
levels recorded would indicate that the facing is intact and functioning according to
design. Survey monuments located along the parapet wall are used to monitor settle-
ment. No significant differential settlement was observed in the field.
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An air bubbler system to inhibit ice accumulation at the intake is used in the winter.
Also in winter, a wash water system is used to wash snow and ice off the dam face.
Ice accumulation is of some concern, since the reservoir is normally drawn down near
the inlet by late winter. Power production is normally reduced and scheduled in ac-
cordance with available water. No episodes of significant ice blockage of the intake
have occurred.
Overall, the main dam is characterized to be in good condition.
Recommendation. Some roadway maintenance in the form of regrading is required.
The light steel bridge must be certified in accordance with the Four Dam Pool "Tech-
nical Standards." Although it was not reviewed by Harza, a recent engineering report
indicates that the bridge components cannot be easily analyzed, and the capacity is
therefore not defined. Although the bridge appears to be adequate, based on loadings
previously sustained, structural engineering evaluation of the bridge's load carrying
capability should be performed.
3.4.5 Dike
Condition Assessment. The 55-ft high dike is identical in construction to the main
dam -asphaltic-concrete faced rockfill with a concrete parapet wall. The latest Part
12 Safety Inspection Report noted the potential for erosion of the dike toe due to
operation of the adjacent spillway. In response to this concern, a concrete guide wall
has recently been constructed at the dike and spillway interface to divert spillway
flows away from the dike.
The inspection noted that the vertical joint between the dike parapet wall and the
spillway end wall is wider than might normally be expected. This vertical joint should
be observed for any change which could be indicative of movement or tilting of the
end wall due to passive loading from the dike fill. The end wall should also be
checked to see if it is vertical or tilted toward the spillway. If continued movement
indicates tilting of the end wall, then the end wall should be reinforced by anchors.
The joint opening may also be the result of contraction of the parapet wall which
would only required addition of joint compound.
In general, the dike is in the same good to excellent condition as the main dam.
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Recommendation. Plant personnel should monitor the vertical joint noted above.
Because of exposure to freeze and thaw and wetting and drying cycles, the concrete
guide wall will likely require some repair after about 30 years.
3.4.6 Spillway
Condition Assessment. The spillway was inspected from each abutment and by walk-
ing along the flip bucket at the toe. The uncontrolled ogee overflow spillway, an-
chored into the rock foundation, is capable of passing the probable maximum flood
with adequate freeboard on the main dam and dike.
The concrete is in excellent condition. No evidence of erosion at the toe of the flip
bucket was noted. One seep was noted, which appears to be coming through the foun-
dation, about one-third of the way in from the left abutment of the spillway. One
vertical crack was noted on the spillway ogee, with a maximum open gap of about
1/8th inch, near this same location. This is not considered to be of major concern.
Some minor headcut erosion was noted at the upstream right spillway abutment. This
erosion is due to surface drainage, and does not endanger the abutment. Minor efflo-
rescence and seepage was noted on the downstream face of the right spillway abut-
ment block.
No conditions were noted which are of civil or structural concern.
3.4.7 Power Intake
Condition Assessment. Two 48-inch-diameter penstocks extend from the intake struc-
ture at the upstream toe of the main dam and connect to twin butterfly valves in a
control building downstream of the dam. The valves and valve house structure are
founded on reinforced concrete tied to rock. The building is a wood frame structure.
A third 48-inch diameter conduit also penetrated the dam and served as a low-level
release as part of the original construction. In response to concerns that this conduit
was under pressure and its failure could endanger the dam, the conduit was plugged
with concrete in April 1990.
Neither the intake nor the initial run of the penstocks up to the valve house was visi-
ble for inspection.
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An overhanging rock slab was cited as a risk to the valve house structure in the last
Part 12 Safety Inspection Report. CVEA has since removed the slab and alleviated
the concern.
No evidence of any conditions which would be of civil or structural concern were
noted at the valve house.
3.4.8 Penstocks
Condition Assessment. Two penstocks, each approximately 3,800 ft long, supply water
for power generation to two units. Water can also be supplied to the Valdez Fisheries
Development Association hatchery located near the plant. A stop log slot with a
trashrack is provided at the entrance of each penstock, but there is no operating gate at
the intake. Two butterfly type penstock valves are installed in a valve house located
downstream of the dam to shut off the flow to each penstock.
During the winter months, the plant operates, but generation is limited due to low
water supply. To minimize the formation of ice inside the penstocks, units are operat-
ed on alternate days, so that each of the two units typically operates every other day.
Approximately 2,300 feet of the penstock is exposed, and the remainder is buried.
The exposed portions were inspected by walking the penstock right-of-way from up-
stream to downstream.
The initial reach of exposed penstock crosses over the spillway outlet channel about
370 feet downstream of the valve house. The penstock is constructed of 48-inch di-
ameter pipe, reportedly the same as that used on the Trans-Alaska Pipeline. It has a
nominal wall thickness of 0.5 inches, with the exception of one 12-inch long "pup
joint" section at Station 26+60, where the wall is nominally 0.375 inches thick. Pen-
stock stationing begins at 1 +00, at the back exterior wall of the powerhouse, and in-
creases in the upstream direction to 37+37.70 at the downstream face of the intake
structure at the upstream toe of the main dam. The appearance of the exterior pen-
stock surface is somewhat ragged, with remains of asphaltic coating and uniform sur-
face rust.
A program of ultrasonic testing was implemented in August 1990, with readings taken
on one or both penstocks at 12 stations along the penstock. Thickness measurements
were taken on the external exposed penstock surfaces at one to nine locations at each
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station. The testing was repeated at the same locations in August of 1995 to evaluate
the loss of wall thickness due to corrosion. A total of 120 comparison measurements
were taken. In 22 percent of the measurements no loss of material was observed, in
46 percent of the measurements, zero to three percent loss was observed, and in 34
percent of the measurements, a loss greater than three percent was observed. Three of
the measurements taken indicated a loss of up to 10 percent (stations 13+00, 15+80,
and 34+05), or about 2.0 percent per year. The average loss of all readings taken was
2.36 percent, or about 0.5 percent per year.
Based on data for welded steel pipe presented by the American Iron and Steel Insti-
tute, 48-inch ID steel pipe with a 0.5-inch wall thickness, and 35,000 psi design
strength can safely withstand 842 ft of head at 50 percent of the yield point. With the
top of dam at El. 695, and the tailwater at tidewater level, the penstock pipe at origi-
nal design is satisfactory.
The design strength at 50 percent of yield drops to 631 ft of head for a wall thickness
of 0.375 inches, representative of a 25 percent loss of wall thickness from a 0.5-inch
wall. Note that the pipe used in the 12-inch long pup joint section has a wall thick-
ness of only 0.375 inches. However, its location at Station 26+60 means that it is
subjected to only 530 feet of head under nonnal flow conditions.
At a projected average annual wall thickness loss rate of 0.5 percent per year, the
penstock should continue to perform safely for a period of 50 years. The selected
locations where the maximum annual loss rate of 2.0 percent per year were noted have
heads of 99 ft, 227 ft, and 257 ft, or only 14 to 37 percent of the maximum head.
These locations could lose up to 50 percent of the steel thickness and still be below
the safe head (421 ft) at 50 percent of the yield point. They could continue to perform
safely for a period of 100 years. However, the corrosion of steel tends to accelerate
with time so the actual serviceable time of the penstocks could be less.
Further analyses would be required to evaluate the bending stresses in the pipe sup-
ported on saddles. The projected life for the saddle supported pipe may be different
than the calculated life based on internal pressure. Even so, it is anticipated that prob-
lems with insufficient wall thickness would be evidenced by local leaks or bulges
which could be repaired as part of a normal maintenance program. It is imperative,
however, that the current program of routine visual inspection of the penstock, supple-
mented by periodic ultrasonic testing, be continued, especially in the first 300 ft up-
stream of the powerhouse where thickness losses would be more critical.
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In addition, some ultrasonic readings are recommended to be taken from inside the
penstocks in the vicinity of the two steel manholes at Station 16+00. This can be
done when the tunnel is shut down for installation of the replacement valves that are
described below. Also, the exposed portions of the penstock should be properly
cleaned and coated with a polyurethane paint or tar coating which will inhibit corro-
sion and minimize the loss of wall integrity. This is especially recommended for the
pup joint section. An improvement to the pup joint is also recommended to increase
the wall thickness of the section to the nominal thickness of the pipe.
The spherical valve is designed to close against turbine discharge in case of emergen-
cy. In accordance with R.W. Beck's Periodic Safety Inspection Report dated Septem-
ber 1992, the penstock butterfly valve can close against maximum turbine discharge of
approximately 150 cfs. However, the valve is not suitable for emergency closure in
the event of a penstock rupture when discharges exceed approximately 370 cfs. A
new penstock valve designed to close against high velocity and discharge is recom-
mended.
The penstock crosses the Trans-Alaska Pipeline at about station 17+50. At this loca-
tion, the penstock is exposed about 30 ft above the ground with steel supports at sta-
tions 16+68 and 17+38. The Trans-Alaska Pipeline is buried about 5 ft deep. A pen-
stock rupture at this location could wash away cover material from the top of the
pipeline and possibly undermine it. The installation of a new valve at the valve house
which can close under a penstock rupture condition would help reduce the potential
for damage, should a rupture occur.
Recommendation. There are four important recommendations relating to the penstock:
1. Ultrasonic testing should be continued at 5-year intervals and some testing
should also be performed from inside the pipe at the manholes to monitor
wall thickness.
2. The above-ground portions of the penstock should be painted to inhibit future
corrosion.
3. The penstock butterfly valve should be replaced so that emergency closure is
possible. To replace the penstock butterfly valves, the intake stoplogs will
need to be utilized. Plant personnel report that the bulkheads do not work,
and this condition, therefore, will need to be corrected before the valves can
be replaced.
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4. The wall thickness of the pup joint should be improved to equal the 0.5-inch
nominal wall thickness. The joint should also be painted.
3.4.9 Turbines
Condition Assessment. The overall condition of both Francis turbines is considered to
be good to excellent. According to the operating personnel, the stainless steel runners
show no signs of cavitation and/or erosion. Runner wearing ring clearances and the
clearances on closed wicket gates were measured every year with satisfactory results.
Every year when the reservoir is drawn down near the penstock intake, debris enters
the turbine water passage. The shear pin in the operating mechanism of the turbine
breaks if foreign materials are jammed between the closed wicket gates. The operat-
ing personnel indicate that replacing the shear pin is simple and does not affect the
unit operation.
Each Francis turbine is protected by a spherical inlet valve in the powerhouse.
The Francis turbine has an inherent rough operating range normally from 20 to 50
percent of the wicket gate opening and requires air admission for smooth operation.
Each Solomon Gulch turbine is provided with aeration piping in the draft tube for
atmospheric air supply to smooth out the flow at partial gate operation. The turbine
runner centerline is set at El. 20 ft above mean sea level and the minimum tailwater
level is controlled by a weir at El. 15 ft. Therefore, the turbine runner centerline is
normally above the tailwater and atmospheric aeration in the draft tube should be
sufficient.
The output tests were performed on both units in 1982. The curves showing the gen-
erator output in kW versus the wicket gate opening in percentage open are for a gross
head of under 666ft (see turbine performance curves included in Appendix B). On
October 5, 1995, the gross head on the turbine was approximately 668 ft or 2 feet
above 666 feet. The generator output for various wicket gate openings on both units
were still in close agreement with performance information indicated on the original
output curves. Based on the expected turbine performance curves and current turbine
conditions, the estimated turbine output is 8,770 hp (6.5 MW) under a net head of 620
ft and 10,100 hp (7.5 MW) under a net head of 673ft.
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A maximum turbine efficiency of 89.2 percent is shown on the expected performance
curve for the net head of 645 ft. The turbine efficiency is on the low side, because
the 30-inch-diameter runner, although an appropriate size for this application, is small,
and this causes more frictional losses in the narrow water passages between runner
blades. In accordance with the turbine performance curves, the best turbine efficiency
range is approximately from 60 to 90 percent of the wicket gate opening for all oper-
ating net heads. No modifications or upgrades appear to be warranted at this time.
3.4.10 Governors
Condition Assessment. Each Francis turbine is controlled by a gate shaft type gover-
nor for maintaining the operating speed and positioning the wicket gates. The gover-
nors are manufactured by Woodward Governor Company. The normal operating pres-
sure of the governing system is 450 psi. Instead of compressed air, high pressure
nitrogen in cylinders is used to charge the governor oil pressure tank. The same oil
pressure system serves to open and close the turbine spherical valve. Both governing
systems were completely overhauled in December 1994 and were reported to be in
good operating condition. One governor is normally set at 0 percent droop, and the
other is set at 5 percent droop, both for load regulation.
3.4.11 Spherical Valves
Condition Assessment. Each turbine inlet is guarded by a spherical type valve manu-
factured by Fuji Electric. A 450 psi pressure oil system common to the governing
system is used to operate the valve rotor. The spherical valve is designed to close
against full turbine discharge for protection of the unit under runaway conditions. The
valve closing time is 116 seconds and is satisfactory. The valves, in the closed posi-
tion, are without any noticeable leaks. Both spherical valves are reported to be in
good operating condition.
3.4.12 Generators
Condition Assessment. The generators are suspended-type with combined thrust and
guide bearings located above the rotor and a guide bearing located below. Other ma-
jor features include a self-ventilated cooling system where cooling air is circulated in a
closed loop through air-to-water heat exchangers located within the air housing. The
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air brake system is capable of stopping the unit from one-half the rated speed within
seven minutes.
Each unit was generating with an output of approximately 5 MW and 0.0 MY AR at
the time of the inspection on October 5, 1995. A 5-MW output on each unit at unity
power factor represents 67 percent of the rated generator output.
Both generators are considered to be in good condition with no major outages since
their installation. There have been no problems with the stator and rotor windings.
However, carbon dust that had accumulated on the stator windings is scheduled for
cleanup during the next maintenance outage. The combination of mild steel collector
rings and material of the field brushes caused a carbon dust problem. CVEA reduced
this problem by changing brush material and adding a dust collection system to the air
housing.
The bearing oil samples taken during the last scheduled outage were good and the
bearing surfaces were reported in good condition.
Brake pads, brake rings, generator cooling equipment and the air housing are all in
good condition.
3.4.13 Powerhouse Auxiliary Mechanical Equipment
Condition Assessment. The cooling water supply for the bearings, shaft seals and gen-
erator air coolers is withdrawn from the inlet valve by-pass line of each unit. The
water from the penstock that is withdrawn for the cooling water passes through two
parallel pressure reducing valves. The operating personnel indicate that the cooling
water system operates satisfactorily with two pressure reducing valves working simul-
taneously. There were problems of maintaining a stable cooling water pressure with
only one pressure reducing valve working for the cooling water system, possibly due
to the fact that the flow through the pressure reducing valve exceeded its rated flow
capacity. Two pressure reducing valves should be used in normal operating condition.
There is only one sump pump installed for the station drainage system. The sump
pump has a rated capacity of 400 gpm at 20ft head with a 5 hp motor. A spare sump
pump has been ordered.
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Other auxiliary mechanical equipment such as the powerhouse crane, potable water
system and compressed air system are in good operating condition.
Although the sewage treatment plant for the powerhouse is working properly, operat-
ing personnel report that the operating procedure is tedious. Since the system appears
to be operating correctly, no modifications appear to be warranted.
3.4.14 Station Service Transformer and Switchgear
Condition Assessment. One station service transformer is located on the control room
roof in a special enclosure that also houses its disconnecting switch. The switchgear is
located on the turbine floor. The location of the transformer and disconnecting switch
on the roof will require a mobile crane for equipment replacement. The arrangement
of the equipment will also necessitate that the powerplant be out of service for approx-
imately 2 weeks in good weather.
3.4.15 Battery and Battery Charger System
Condition Assessment. Lead cadmium batteries were provided for the 125-V DC sys-
tem. Two battery chargers maintain a full charge on the batteries and provide DC
power for controls.
3.4.16 SCADA System
Condition Assessment. The Solomon Gulch generating units are controlled from the
powerhouse control room by a Landis & Gyr SCADA system. This system has been
upgraded and includes the latest software development.
3.4.17 Communications
Condition Assessment. The project has a 450-MHz VHF radio, leases microwave cir-
cuits from the Department of Administration, Division of Information and telephone
lines from the CVEA. These lines provide communication from the power plant to
Meals Substation, P12 Substation, and Pll Substation. A new 900-MHz radio system
is being installed for the SCADA system. The communication system has been very
reliable.
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7176/G 2028SOLO.WP 3-19
3.4.18 Emergency Generator
Condition Assessment. A 250-kW, 480-V Cummins diesel standby generator is pro-
vided in a separate building adjacent to the powerhouse. The generator has provisions
for automatic startup, auto transfer, and is intended to carry the total station load. The
generator appears to be in good condition. It is exercised once a month. The moni-
toring circuit of the fuel line does not operate correctly, hence it has been disconnect-
ed. Fuel line monitoring provides pertinent fuel consumption data to the plant opera-
tor but is not crucial for operation.
Recommendation. The fuel line monitoring circuit should be repaired.
3.4.19 Powerhouse Switchyard
Condition Assessment. The Solomon Gulch substation is located on the powerhouse
control room roof. Equipment in the switchyard includes two generator step-up trans-
formers, two unit oil circuit breakers, a station service cubicle, two line circuit break-
ers, and 25-kV bus work. The equipment is located in a restricted area with no acces-
sibility for equipment replacement. The only method of replacing any equipment will
either be by helicopter or mobile crane. Due to their weight, the transformers will
require the use of a large capacity crane. Estimated total plant outage for a generator
step-up transformer replacement is four weeks2 , excluding manufacturing and delivery
time.
The generator step-up transformers are three phase 7.5 MV A OA with a 55°C temper-
ature rise and 10.5 MV A with a 65°C temperature rise. These transformers were
reported to be in good condition.
3.4.20 Transmission Line from the Solomon Gulch Powerhouse to Meals
Substation
Condition Assessment. The transmission line from the Solomon Gulch powerhouse to
Meals substation is a double-circuit, 25-kV line, four miles in length, and is supported
2 Note that this description refers to the generator step-up transformer, not the smaller
station service transformer discussed above with a replacement time of two weeks.
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on single shaft wood poles. The support structures are located mostly next to the
arterial road that runs along the coast. The pole configuration is illustrated in Figure
3-2.
After the line was constructed, the support structure configuration was modified to
eliminate phase-to-phase interference under ice conditions by offsetting the center arm
as shown in Figure 3-2.
The concerns for this section of line are noted below:
Avalanche. In some areas, the line is exposed to a the risk of avalanche damage.
However, the risk for avalanches in these section is believed to be low, and there-
fore no immediate actions are recommended.
Tsunami. The line is located along the coastal area and could be at risk of tsunami
damage. The tsunami risk is considered low, and cost for relocating the line does
not appear to justify the reduction in expected damage cost. Therefore no action is
recommended.
Insulator Contamination. This line section is located in a marine environment and
is therefore at risk of salt contamination. However, no problems have been experi-
enced with this line section to date. The insulators should be monitored and pollu-
tion type insulators installed if flashovers begin to occur as a result of salt contam-
ination.
3.4.21 Transmission Line from Meals Substation to Pl2 Substation, and from
the P12 Substation to the Pll Substation
Condition Assessment. The transmission line from Meals substation to the P12 substa-
tion is a single-circuit, 138-kV line, 62 miles in length. The transmission line from
the Pl2 substation to the Pll substation is a single-circuit, 138-kV line, 49.5 miles in
length. The supporting structures for this line section from the Valdez Arm through
various glacial valleys are a combination of wood pole H-frame structures, guyed X-
frame steel pole structures, three legged X-frame type steel pole structures, single shaft
steel pole and single shaft wood pole structures. The configurations of the H-frame
and guyed X-frame structures are shown in Figure 3-3.
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7176/G 2028SOLO.WP 3-21
The significant elements of risk to this line are described below.
Avalanche. A significant portion of this line is exposed to potential avalanches.
CVEA staff indicated that about 40 miles of this line is vulnerable. During the
inspection, evidence of past avalanches was visible from damage to the trees and
vegetation. Two avalanches since 1987 have taken this line out of service. The
avalanche on December 16, 1988 took the line out of service for nine months, and
the cost to reconstruct one mile of the line was about $1.7 million.
Danger Trees. Along the edge of the right-of-way, there are many spruce trees
that could fall on conductors. The spruce trees are beetle infested and are dead.
As the roots decompose, the probability that trees will fall and damage the line
increases. In addition, the dead trees increase the risk of line damage due to forest
fires. A right-of-way clearing program is recommended to remove trees that im-
pose a danger to the line.
Flooding. Several structures are located next to creeks and rivers. These struc-
tures could sustain damage due to erosion caused by flooding. Riprap protection
was recently constructed for one of the towers. Regular monitoring should be
continued. Structure which are at risk now should be protected.
Aircraft. The line is constructed parallel to the Trans-Alaskan Pipeline, and the
pipeline is inspected by helicopter. The helicopter inspection of the pipeline in-
creases the probability of an aircraft accident, especially when these inspections are
done in bad weather. Although several spans are marked with aircraft warning ball
markers, one accident has occurred since the line was constructed and was attribut-
ed to bad weather conditions. Maintenance/replacement of the marker balls is time
consuming.
Structure Fatigue. Steel poles are subjected to severe vibration and failures have
been reported on the bolts of the X-frame steel pole structure waist member and on
the foundation bolts where the X-frame leg is attached to the concrete and H-pile.
An analysis of the failures (by others) did not reveal any material defects on the
bolts. It is recommended that a monitoring program be implemented at the loca-
tions where failures have been experienced to evaluate the level of structure vibra-
tion and its contribution to the failures. In addition it was reported during the
interviews with CVEA staff that some poles have developed cracks. The fabricator
attributed the cracks to freezing water expansion. If cracks are small and in non-
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critical areas, they can be repaired. However large cracks will indicate structure
failure and require that the structure be replaced.
Ice. Differential ice loading (ice on one span only) could create clearance prob-
lems on the line. This is not a frequently occurring event and therefore no correc-
tive measures are recommended.
Foundation Damage. CVEA staff indicated that foundation piles are subject to
"jacking" due to permafrost action. In locations where this has occurred, the pile
has been lengthened and driven deeper.
Since, it is not possible to identify in advance the locations where the piles will be
subjected to "jacking," this will always be a problem for this line.
Insulator Contamination. Due to prevalent increase in volcanic activity in the
area, the line is subjected to higher risk of dust contamination and increased outag-
es.
Recommendation. The following actions are recommended to reduce the risk of dam-
age due to natural events or equipment failure:
1. Perform a detailed investigation to determine the design criteria for replacing
overhead transmission line with un underground alternative. Consider imple-
mentation of an underground alternate if extensive avalanche damage occurs
in the future.
2. Implement a right-of-way clearing program to remove dead trees that endan-
ger the line.
3. Evaluate which structures are at risk due to flooding now end protect with
riprap. Continue monitoring potential for damage to other structures.
4. Implement a monitoring program at locations that have experienced fatigue
failures to evaluate structural vibration and its contribution to the failures.
5. Monitor insulator contamination to determine the need to install pollution
type insulators.
960208
7176/G 2028SOLO.WP 3-23
3.4.22 Meals Substation
Condition Assessment. The substation has one 138-kV, 24.9/14.4-kV, 15/20/25-MVA,
ONFNFA with load tap changer transformer. The access road to the substation was
in relatively good condition at the time of the inspection.
There is obvious soil settling, particularly at the comers of the substation. The trans-
former pad has settled, and leveling shoes have been installed to level the transformer.
Most of the transformer pad settlement occurred shortly after installation.
There are no transformer mounting bolts to prevent the transformer from vibrating off
the leveling shoes or the transformer pad during ground movement and normal trans-
former vibration. There are no oil recovery facilities currently in place, but are
planned for installation in 1996.
Recommendation. The transformer should be secured by clamping, welding, or bolt-
ing, or a combination of the above.
3.4.23 P12 Substation
Condition Assessment. Power is provided to the Alyeska Pumping Station No. 12 and
a CVEA distribution line from the P12 substation. The substation has one 138-kV,
24.9114.4-kV, 12/16/20-MVA, ONFAIFA, with load tap changer transformer. The
one-line diagram is presented in Figure 3-5. The substation has no oil recovery facili-
ties to mitigate the potential for oil spill contamination. Oil recovery facilities are
planned to be installed during 1996.
3.4.24 Pll Substation
Condition Assessment. Power is provided to the Alyeska Pumping Station No. 11 by
tapping the Solomon Feeder which interconnects with the Glennallen diesel generating
station. The substation has one 138-kV, 24.9/14.4-kV, 12/16/20-MVA, ONFA/FA,
with load tap changer transformer. The one-line diagram is presented in Figure 3-6.
The control building foundations are sinking due to a reported problem of deterioration
of the permafrost. All control cables from the substation equipment are connected to
the control switchboards and relays located inside the control building. A sinking
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control building could shear and break the control cables and conduits, causing a ma-
jor interruption.
The substation has no oil recovery facilities to mitigate the potential for oil spill con-
tamination. Oil recovery facilities are planned to be installed during 1996.
Recommendation. Operating personnel should monitor the control building settlement.
If the control building continues to sink, then steps should be taken to correct the
problem. Some of the solutions include relocating the control building to a new loca-
tion, driving piles into the permafrost and reinforcing the control building foundations
or grouting under the foundations. Cost could vary depending on the extent of the
work from $50,000 to $300,000.
3.4.25 Mile 26 Tap
Condition Assessment. The tap provides power at utilization voltage to an Alaska
Department of Transportation maintenance facility. It was reported that the tap con-
sists of an open delta potential transformer assembly, and is direct connected to the
138-kV phase conductors. This is a practical solution to the need for electric service
at the DOT maintenance facility, but it exposes the entire line to a forced outage.
Recommendation. Breakers with disconnect switches and/or circuit switcher with a
relay panel should be installed to isolate this tap in the event of a fault.
3.4.26 Rolling Stock
Condition Assessment. The rolling stock at the powerhouse is owned by AEA and
consists of the following:
1. One %-ton, four-wheel-drive pickup truck,
2. Two snowmobiles,
3. One snowcat and trailer, and
4. One mid-size, front-end loader.
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7176/G 2028SOLO.WP 3-25
The line crew uses CVEA equipment.
Recommendation. The snowmobiles and front-end loader are in poor condition, and
should be replaced. A forklift should be acquired to facilitate movement of equipment
and spares.
3.4.27 Infrastructure
The infrastructure consists of storage facilities and other items. These facilities have
varying service lines and replacement costs. The storage and other facilities are esti-
mated to have a service life of 30 years. At the end of the service lives of these facil-
ities, an estimated 75 percent of the replacement value is included to replace or to
upgrade these facilities to current standards. An estimate of the typical service life,
replacement cost and schedule for replacement has been included as part of the infor-
mation provided in Table 3-5 and 3-4.
3.4.28 Documentation
Condition Assessment. Marked up construction drawings were sent to AEA to incor-
porate field changes onto the original tracings. Copies of the marked up prints are
maintained in the plant.
Recommendation. As-built conditions should be incorporated onto the existing project
drawings. The effort would only involve transferring information from marked-up
drawings to the original tracings.
General Comment. Drawings and records for the project are stored in a rented storage
facility in Anchorage. It is important that these records be preserved and transferred
to the new project owners after transfer of ownership.
3.4.29 Conclusions
Table 3-3 lists the major project equipment, provides an assessment of the condition of
each item, its remaining service life and the expected replacement cost of each item.
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All structural components are considered to be in good shape, and are expected to
perform well beyond the remaining 36 years of the nominal 50 year life of the project,
with one exception. Raveling of the penstock coating and corrosion of the penstock
walls appears to be more severe than would ordinarily be expected. Based on the rate
of corrosion indicated by recent testing, the penstock should perform adequately for
the next 36 years. However, there is the possibility that the rate of corrosion will
accelerate with time and that the corrosion rate could be locally higher, hence there
may be a need for continued painting or other maintenance.
Table 3-3 presents the schedule for replacements and repairs due to wear and tear. For
equipment items, the replacement schedule is based on the condition assessment and
remaining life that is estimated and presented in Table 3-4. Structural repair items are
identified and discussed in the above sections.
An estimated disbursement schedule for correcting design deficiencies, deferred main-
tenance, other general project improvements, and replacements due to normal wear and
tear is presented in Table 3-4.
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Table 3-3
Page 1 of2
SOLOMON GULCH PROJECT· EXPECTED SERVICE LIFE AND REPLACEMENT COSTS
(where applicable, replacement costs are for both generating units)
Expected Remaining 1995 Price level
Item Condition Service life Service life Replacement Cost
(yearsL (years) ($)
(see note a)
Equipment
Turbine and Other Mechanical Items
Runner Excellent 50 36 800,000
Wicket Gates Excellent 50 36 250,000
Remaining Turbine Parts Excellent 50 36 1,750,000
Governor Good 50 49 b 300,000
Spherical Inlet Valve Good 50 36 160,000
Draft Tube Bulkhead Fair 25 11 40,000
Cooling Water System Good 25 11 64,000
Other Aux Mechanical Equip Good 35 21 173,000
Generator
Stator Excellent 25 11 700,000
Rotor Excellent 35 21 210,000
Bearings Good 30 16 400,000
Cooling System Good 30 16 150,000
RTDs, Sensing Devices Good 30 16 4,000
Fire Protection Good 35 21 5,000
Excitation System Good 25 11 200,000
Electrical System
Battery and Chargers Good 25 11 100,000
Controls and Protective Relaying Good 25 11 180,000
Station Service Excellent 30 25 b 240,000
5-kV Switchgear Good 25 11 60,000
Cable System Good 50 36 250,000
SCADA System Excellent 15 13 b 450,000
Communications Excellent 15 13 b 15,000
Emergency Generator Excellent 30 26 b 125,000
Intake Gate Electrical Controls & DC Good 25 20 b 20,000
Switchyard, Transmission Line and Substation Equipment
Switchyard at Powerhouse
Transformers Good 30 16 350,000
Circuit Breakers Good 25 11 145,000
Disconnect Switches Good 35 21 60,000
Bus Structures Good 40 26 50,000
All Other Good 35 21 150,000
Table 3-3
Page 2 of2
SOLOMON GULCH PROJECT· EXPECTED SERVICE LIFE AND REPLACEMENT COSTS
(where applicable, replacement costs are for both generating units)
Expected Remaining 1995 Price Level
Item Condition Service Life Service Life Replacement Cost
~ (years) ($)
(see note a)
Transmission Line
Insulators Good 40 26 700,000
Hardware Good 40 26 1,200,000
Conductors Good 40 26 10,000,000
Structures Good 80 66 18,436,706
Foundations Good 80 66 24,023,586
Meals Substation
Transformers Good 30 16 350,000
Circuit Breakers Good 25 11 192,000
Disconnect Switches Good 35 21 131,450
PTs, CTs, Wave Traps Good 30 16 100,000
Bus Structures Good 40 26 100,000
All other Good 35 21 1,000,000
P11 Substation
Transformers Good 30 16 300,000
Circuit Breakers Good 25 11 96,000
Disconnect Switches Good 35 21 56,500
PTs, CTs, Wave Traps Good 30 16 100,000
Bus Structures Good 40 26 90,000
All Other Good 35 21 800,000
P12 Substation
Transformers Good 30 16 350,000
Circuit Breakers Good 25 11 192,000
Disconnect Switches Good 35 21 99,000
PTs, CTs, Wave Traps Good 30 16 120,000
Bus Structures Good 40 26 100,000
All Other Good 35 21 1,000,000
Rolling Stock
Pickup Truck (3/4 ton, 4WD) Excellent 10 9 30,000
Snowmobile (2) Poor 10 1 12,000
Snowcat and Trailer Excellent 10 9 115,000
Front-End Loader Poor 10 1 50,000
Infrastructure
Storage and Other Fair 30 16 375,000
Notes:
a Plant was essentially completed in January 1982, and entered commercial service on July 1, 1982.
Actual in-service time is about 14 years.
b Indicates system that was replaced or modified since original construction.
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Table 3-4
Paga1 of3
SOLOMON GULCH PROJECT· PROJECTED MOST UKEL Y REPAIR AND REPLACEMENT COSTS
(In US dolars at 1995 price levels, excludng repairs 0< replacements rue to nallnll even1s, accidents or ~pment falkl'es)
Depredation Depreciation
Used Aveilable
S1rvct\re 1996-2000 2001-05 2006-10 2011-15 2016-20 2021-25 2026-30 Next r!flacement ~2030 Attef 2030
Reme<lal Worlc fO< Items of Deficient Design
None
Reme<lal Wort< FO< Hems of Deferred Maintenance
None
01her Project lrrpovemen1s
Correct leaky nft 1t.t>e 1>\.t<head 20.000
Evaklate stuct\ral capacity of access road bridge 10,000
Paint penstock exterior 360,000
Replace 2-48" penstocl< butle<fty vaNes 300,000
!rrl>r""" '"-"joint wallhldmess end paint 135,000
Inspect and repair Intake stcplogs 200,000
Repair emergency gen fuel ine monitoring circUt 700
lns1al spare slaton ninage slJT'4) PlJT'4l budgeled
Add oil recovery faciities at al slbstations budgeted
Monitor transmssion lne struct\res fati~e a
Monitor transrrission lne Insulators for contamination -a
Meals slbstation • cial!1llnlnstorrners 2,000
Monitor P11 Slilstation conrol btiklng settlement a
Undergrou1d cable study and evakJation 60,000
ROW Clearing (fire and 'Oind) 350,000
Erosion control on transtrisslon ines near fiVers and creeks 250.000
Isolate Mile 26 tap, Instal breakers 'Oith <1scomec1 swilches 300,000
Acquire for1<111 40,000
c~e os-t>uitt tn'Oings 20,000
Replacemen1s <ile to Normal wear and Tear
Slrucues
Powemouse leakage at concrete panels 5.000 5,000 5,000 5,000 Repair at10-yearintervals, 2030
MonitO< <Ike parapet verlical joint a
Repair spilway wal 135,000 2044
MonitO< penstock wallhlcl<ness 20,000 b 20,000 b 20,000 b 20.000 b 20,000 b 20,000 b 20,000 b MonitO< every 5 yrs: replace in 2044
Arc11teellnll relllt>ishment 200,000 2044
Paint penstocl< 360,000 Paint eVE!fY 20 years, 2036
Equipment
Tllt>ine and Other Mechanical Items
Tllt>ine Rli'Vler and Wicl<et Gates Replace n..mer & 'Oicl<et gates in 2031 2,744,000 56,000
Governor 2044 216,000 84,000
lnletvaNe 203t 156,800 3,200
Draft Tlbe BIA<head 40,000 2043 36,400 1,600
Cooing Water System 64.000 2031 61,440 2,560
01her Al.odiary Mechanical Equipment 173,000 2051 69,200 103,800
Generator
Stator 700,000 2031 672,000 28,000
RotC< 210.000 Replace field poles in 2051 84.000 126,000
Bee rings 400,000 2041 253,333 146,667
Cooing System 150,000 204t 95,000 55,000
RTDs, Sensing De-Aces 4.000 204t 2.533 1,467
Fire Protection 5.000 Checl< C02 gas amualy. 205 t 2,000 3.000
Excitation System 200.000 2031 192,000 8,000
Electrical System
Battery and Chargers 100.000 203t 96,000 4.000
Controls and Protective Relaying 180 000 2031 172,800 7.200
Station Service 240,000 2050 80,000 160,000
5-k\1 5\0itc:llgear 60000 2031 57,600 2,400
Cable System 2031 245,000 5,000
Table 3-4
Page 2 of 3
SOLOMON GULCH PROJECT· PROJECTED MOST UKELY REPAIR AND REPLACEMENT COSTS
(in us dolani al1995 price levels, excludng repoirs or replacemenls WE! 1o naual events, accidents or eq<ipmenl faikles)
DepredaUon Depreciation
Used Available
S1ructure f99&-2000 2001-05 2006-10 2011-15 201&-20 2021-25 202&-30 Next replacemenl Throu!jl2030 After 2030
Intake Gale Elec111cal Conlrols 20,000 2040 12,000 8,000
SCADA System 450,000 450,000 2038 210,000 240.000
CoiiVI'K.I'lcations 15,000 15,000 2038 7,000 8,000
Emergency Generator 125,000 2051 37,500 87,500
Svoilchyard, Transmission Una and S!.t>station Eqtipmenl
Powerhouse S'Michyard
Transformers 350,000 (1,3) 2041 221,667 128,333
Clrclil Breakers 145,000 (2} 2031 139,200 5,800
DiscOMect S'Miches 60.000 2051 24,000 36,000
Bus S1ructures 50,000 2061 11,250 38.750
AI 01her 150.000 2051 60,000 90.000
Transmission Une
lnstJators 700,000 2061 157,500 542.500
Hardware 1.200,000 2061 270,000 930,000
ConWctors 10,000.000 2061 2.250,000 7,750,000
S1ructures 2061 11,292.482 7,144,224
Follldations 2061 14,714,446 9,309,140
Meals S<.t>slation
Transformers 350.000 2041 221.667 128,333
Circlil Breakers 192.000 2031 184.320 7,680
Disconnect S'Miches 131,450 2051 52,580 78,870
PTs, CTs, Wave Traps 100,000 2041 63,333 36,667
Bus S1ructures 100,000 2061 22.500 77,500
AI 01her 1,000,000 2051 400,000 600.000
P 11 Sl.bstafion
Transformers 300.000 2041 190,000 110,000
Circlil Breakers 96,000 2031 92,160 3.840
Disconned S'Miches 56,500 2051 22.600 33,900
PTs, CTs. Wave Traps 100,000 2041 63,333 36.667
Bus S1ructures 90,000 2061 20.250 69.750
AI01her 800,000 2051 320.000 480.000
P12 Sl.bstation
Transformers 350,000 2041 221,667 128,333
Circli1 Breakers 192,000 2031 184,320 7,680
DiscOMeC1 S'Miches 99,000 2051 39,600 59,400
PTs, CTs, Wave Traps 120.000 2041 76.000 44.000
Bus S1rucbJres 100.000 2061 22.500 77.500
MOther 1,000.000 2051 400,000 600.000
Rolng stock
Pickup Truck (3141on. 4WD) 30,000 30.000 30.000 Replacemenl eve;y 10 years 18.000 12,000
Snowmobile (2} 12,000 12,000 12,000 12,000 Replacement eve;y 10 years 4.800 7200
Snowcal and Trailer 115,000 115.000 115.000 Replacemenl eve;y 10 years 69.000 46.000
Front-End Loader 50,000 50,000 50,000 50,000 Replacement every 10 years 20.000 30.000
FOI1<lf1 40,000 b 40.000 40,000 Replacemenl every 10 years 16.000 24.000
Infrastructure
storage aM 01her 375.000 2041 ~1.500 __ l3UlQO
5-YR TOTALS OE.PREC~A.TION TOTAlS 37.607.282 29952.960
Remedial Work for nems of Oeflcienl Design
Remedial Work lor Items of Deferred Mairnenance
01her PrOJ"cl ifrVovemen1s 2,047,700
Replacements lAJe to Normal Wear and Tear 87,000 205,000 2.481,000 3.159.000 4,371.950 13.075.000 87,000
Alowances For Replacemenls Af1er 2030 (4) 500,087 500,087 689,205 921.846 1170,715 1.824,810 2,107,806
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Table34
Page 3 of 3
SOLOMON GULCH PROJECT· PROJECTED MOST UKELY REPAIR AND REPLACEMENT COSTS
(in US dolors at t995 price levels, excluding repairs or replacements due to naual events, acdderrts or eQI,Ipment faillles)
Struct!xe 1996-2000 2001-05 2006-10 2011-15 2016-20 2021-25 2026-30
LEVEUZED PAYMENT ANALYSIS
Replacement• due to Nonnal Wear and Tear (5)
Begiming of Period Fllld Balance 3,864,303 8,859,501 12,007,783 14,669.724 15,394,650 (2,724,676)
Annual ContribUtion of $665.113to ReseM> Fllld 3,325,566 3,325,566 3,325,566 3,325,566 3,325,566 3,325,566 3,325,566
Exp""se (92,325) (240,190) (3,209,438) (4,511.830) (6,894,125) (22. 763,891) (167,234)
lnte<est on Average Fllld Balance 631,062 1,909,823 3,032,153 3,848,205 4,293,485 1,319,000 (433,656)
End of Period Fl.lld Balance 3,864,303 8,859,501 12,007,783 14,669,724 15,394,650 (2,724,676) (OJ
Allowance• for Replacements after 2030 (6}
Beglming of Period Fl.lld Balance 761,689 1.715,118 2,632,190 3,352.902 3,687,018 2.567,992
Annual Contribution of $233.409to Reserve Fl.lld 1,167,044 I, 167,044 1,167,044 1,167,044 1.167.044 1,167,044 1,167,044
Expense (530,904J (586.161) (894.309) (1,319,736) (1.849,918) (3, 190,485) (4,053,920)
Interest on Average Fund Balance 125,549 372.545 844,337 873,404 1,016,990 904,415 318,884
End of Period Fund Balance 761,689 1,715.118 2,632,190 3,352,902 3,887,018 2.567,992 (OJ
a tndcate:s that the cost tor hs item is asslll'\oed to be Jndlded as a part of 1he norma~ operations budget and the reqlired ae1ivtties can be carried out by plant perSOJ'Y'lflt as part of da'f'to-day ae1Jvi1ies,
b Indicates an item that is contirlQ""t on ifll'lemenlation of a recommended project ifll"ovemenl
(I) lnclldes $50,000 for hoisting transformers to roof
(2) lnclldes $25,000 for hoisting OCB's to roof
(3) Second lritwil be out or sef'lice for two weeks <bing lnstalation of o1her transformer
(4) Calct*oted in 1995$. using a 4'"-real (lsc<l!R rate
(5) Analysis assunes a 2% escalation rate. a 6% Interest rate on available fl.llds. a 8% borrowong rate, and one Ur4> sun payment in the mid<Je of the five-year period.
(6) Analysis asso.mes a 2% escalation rate, a 6% interest rate on available fl.llds. a 8% borr""'ng rate. and begiming of year payments to replacement f!.flds.
Depreciation
Used
Nex1 replacement TIYOIJ!l! 2030
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----~-~····--·-··---.. --~-----·--------.
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Depredation
Available
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700
600
500
400
300
200
100
-Generalir9 Oiscl14rge
-lake level
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=SpiMy Oi•<herge IIIS!IUSGS Gage 15225996 RectWdod Flow =usGS Gage 15225997 R-d Flow
-<>-USGS Gage 15226000 Recorded Flow ....,._Powerpllnl Hy<hUic Capadly
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·-·--~--L......__tw=J 11!11 19.81 DH. 19lii 19.9.2. 1!93. .1Ui I 1995=::J
Figure 3-1 Solomon Gulch Project -Measured Historical Flows and Lake Levels
700
600
500
400 .... .. . .... . < I.
.!!
300
200
100
0
Figure 3-2 Solomon Gulch Project -Transmission Structure Configuration -Powerhouse to Meals Substation
I I
Guying
System
I
Figure 3-3 Solomon Gulch Project· Transmission Structure Configuration -Meals to P12 Substation
............................. -.............. _______ .... .,..,. _____ .................... .. .
@-------<1D--o-
"--0--'~}
~~
@-------<1D--o-
To Stalioo Savkle TransCIX!Del"
To Meals
Subitatioo
·---......................... _ .................................. _ .... _ .. _________ ,
Figure 3-4 Solomon Gulch Project • Main One-Line Diagram
[T~ Pils~ ~ . . . . . . . . - . . . . . . . . . . . . . . . . . . . . . . . . : I North Feeder I
r · · r :,~~ ~~~:
IToMahS""""'ool• : I ~~'-(1))~~---:J : •IToA-.PSN0.}2]
138 tV· 24.9 tV
Transformer
Figure 3-5 Solomon Gulch Project -One-Line Diagram -P12 Substation
................................... 1(=:=1
Genenua: Plant)
J ToP12S"""""' I 4 : I ~~ I ~--:J : I..--_., __ __,
' I ToAiyeskaPS No. 11 I 138 kV • 24.9 tV
Transformer
Figure 3-6 • Solomon Gulch Project -One-Line Diagram -P11 Substation
,. .................... ,. ......... -........... ..
To Valdez Diesel
GeoeJ:at(X" Plant
~ IT·~~~I {.._ .. --_ :I ~
.
'---0----'~ : ,.,ToP12 Substation'
Figure 3-7 Solomon Gulch Project -One-Line Diagram -Meals Substation
Chapter 4
Terror Lake
Chapter 4
TERROR LAKE
4.1 Project Description
This project is located on Kodiak Island, approximately 25 miles southwest of the City
of Kodiak between the head of Terror Bay and the head of Kizhuyak Bay. The pro-
ject consists of a 193-foot high concrete-faced rockfill dam, ungated side channel spill-
way, low level outlet works, submerged concrete intake, a 26,740-foot long power
tunnel with intermediate drainage basin diversions through small dams and separate
conveyance facilities at Shotgun Creek, Falls Creek, and Rolling Rock Creeks, pen-
stock, powerhouse and switchyard, 17 miles of 138-kV transmission line to Kodiak
(Airport substation), 1.6 miles of 138-kV transmission to Swampy Acres substation,
and 13 miles of 12.47-kV distribution line to the community of Port Lions. The pro-
ject general arrangement and sections of major project features are illustrated on the
project drawings included in Appendix B. Table 4-1 presents pertinent project data.
The primary source of water for generation is the surface runoff that flows into Terror
Lake. However, surface runoff collected at the three diversions between Terror Lake
and the powerhouse can provide additional water for operation. Water can be deliv-
ered to the power tunnel at two points. The Shotgun Creek facility diverts flows into
the Falls Creek diversion works. From the Falls Creek diversion, collected surface
runoff enters the power tunnel via connecting shafts and tunnels. At a second point
between Falls Creek and the powerhouse, the Rolling Rock Creek facility can divert
surface runoff into the power tunnel via connecting shafts and tunnels.
Terror Lake was initially investigated in the early 1960's by the Kodiak Electric Asso-
ciation (KEA). The project was constructed in 1984 by the Alaska Power Authority
(now known as the Alaska Energy Authority or AEA), under the Energy Program for
Alaska. The project is operated by KEA under an agreement with AEA. The project
went into commercial service on April 1, 1985.
The Terror Lake powerhouse has two generating units with provisions for installation
of a third unit. The turbines are vertical-shaft, 6-jet, Pelton type, with a rated speed of
720 rpm. The two generators are each rated at 12.5 MVA. The turbines were manu-
factured by Fuji Electric and the generators by Mitsubishi.
Access to the project is by boat or amphibious plane. There are 16 miles of project
roads that provide access to the project facilities only.
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7176/G 22028TERR.WP 4-1
Table 4-1
TERROR LAKE PROJECT -SIGNIFICANT DATA
RESERVOIR
Normal Max Pool Elevation
Normal Min Pool Elevation
Maximum Active Storage
Drainage Area
DAMS and DIKES
Type
Crest Elevation
Height
Length
SPILLWAY
Type
Length
Crest Elevation
POWER TUNNEL AND SHAFTS
Lining
Length
Diameter
I)ENSTOCK
Number
Length
Diameter
Type
EQUIPMENT
Nominal Plant Generating Capacity
Number of Units
Type of Turbines
Maximum Gross Head
Turbine Power Output (each, at 1,136 ft net
Generator Rating (each)
Speed
TRANSMISSION LINE
Length, Port Lions
Voltage, Port Lions
Length, Kodiak City
Voltage, Kodiak City
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7176/G 22028TERR.WP
Shotgun
Creek
1,925 ft
1.9 sq mi
Concrete
faced rockfill
1,930.5 ft
40ft
275ft
Open
channel
100ft
1,925 ft
4-2
Falls
Creek
1,645 ft
4.5 sq mi
Concrete
faced rockfill
1,650 ft
20ft
480ft
Ungated
concrete
ogee
200ft
1,645 ft
Shot crete
(partial)
2,000 ft
9ft
Rolling
Rock
1.6 sq mi
Rock:.till
1,485 ft
20ft
130ft
Overtopping
130ft
1,485 ft
Shotcrete
(partial)
1,600 ft
9ft
Terror
Lake
I ,420 ft
1,250 ft
112,000 ac-ft
15.1 sq mi
Concrete
faced rockt111
1,425 ft
193ft
2,400 ft
Ungated
concrete ogee
side channel
625ft
1,420 ft
Shot crete
(partial)
26,690 ft
9 to 12.5 ft
1
3,100 ft
63 to 96 inches
Steel
22.5 MW at 90 percent power factor
2
Vertical shaft Pelton
1,316.5 ft
15,666 hp
12.5 MVA
720rpm
2mi
2.47 kV
18.6 mi
138 kV
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4.2 Installed Capacity and Energy Generation
4.2.1 Monthly Flows
Historical flow data from the Terror Lake project operating records and flow records
from the U.S. Geological Survey gaging station located about 8 miles downstream of
Terror Lake dam were reviewed. The information from project operating records
includes recorded Terror Lake powerplant discharges and releases from the reservoir to
Terror Bay. Powerplant and reservoir release data, along with reservoir levels were
obtained from project operating records for the period from January 1991 to December
1994. The data is provided in Figure 4-1.
In addition to the runoff into Terror Lake, the flow data plotted in Figure 4-1 includes
the contribution of runoff from three diversions: Shotgun Creek, Falls Creek, and
Rolling Rock Creek. The contributing drainage areas for these diversions are listed in
Table 4-1, and amount to a significant portion of the total drainage area contributing
to the project water supply.
Releases from the reservoir are made primarily for maintaining aquatic habitat in Ter-
ror River, and are mandated as a condition of the FERC license. The required
streamflow maintenance quantities are:
January through March
April
May through October
November 1 through November 15
November 16 through December
00 ~
100 ~
1~ ~
100 ~
00 ~
Based on the flow information presented in Figure 4-1, the total average flow, includ-
ing the powerplant discharge and downstream release at the dam, equals approximate-
ly 168 cfs. The portion of the 168 cfs that is utilized for generation is approximately
equal to a continuous release of 129 cfs, while the portion that is spilled or intention-
ally released downstream to the Terror River is about 39 cfs. The difference between
the required minimum flows and the 35 cfs is the contribution of intervening area flow
below the dam. The maximum powerplant discharge capacity is approximately 270
cfs. The average historical flow for the period analyzed is about 62 percent of the
hydraulic capacity of the plant.
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7176/G 22028TERR.WP 4-3
Table 4-2
TERROR LAKE PROJECT-ANNUAL GENERATION
Year Ending Actual kWh
6/30/86 54,739,800
6/30/87 91,909,793
6/30/88 102,671,415
6/30/89 107,567,000
6/30/90 111,528,987
6/30/91 91,391,717
6/30/92 99,364,109
6/30/93 107,873,266
6/30/94 118,189,728
6/30/95 100,744,220
Total 985,980,035
Average
10 years 98,598,004
Last 3 years 108,935,738
4.2.2 Energy Generation Potential
The plant has two units, with a total installed capacity of 25 MY A. At a power factor
of 90 percent, the maximum nominal power output of the units is 22.5 MW.
Based on data for the 10 most recent fiscal operating years (period ending June 30,
1995) the historical average annual generation has been about 98.6 GWh. In the last
three years production averaged 108.9 GWh per year. Historical production, as fur-
nished by AEA, listed in Table 4-2.
Based on limited flow data gathered for this study, preliminary estimate of the energy
generation potential of the existing project, assuming that all of the available energy
could be utilized, is 117 GWh per year. The actual annual energy production appears
to be trending upward, approaching the estimated average annual energy generation
potential.
4.2.3 Effects of Drought
The potential impact of drought on energy generation can be investigated by analyzing
the long-term streamflow. The actual streamflow and release data available for the
plant is too short to draw definite conclusions about the impact of drought. However,
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7176/G 22028TERR.WP 4-4
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it is possible to infer the magnitude of the reduction in generation that might occur in
water short years by investigating the characteristics of streamflow in nearby rivers
that have long-term streamflow records.
A streamflow gaging station on Myrtle Creek near Kodiak, is located about 25 miles
east of the project site. This gage measures a runoff from an area of about 5 square
miles, which is about 22 percent of the drainage area of the Terror Lake Project. The
streamflow record contains data over a period of 23 years. Total annual flow for each
year was tabulated, and the distribution of years with lower than average flow are indi-
cated below:
Number of years with annual flow:
less than 80 percent of average flow
between 80 and 85 percent of average flow
between 85 and 90 percent of average flow
between 90 and 95 percent of average flow
between 95 and 100 percent of average flow
above 100 percent of average flow
2 out of 23 years
0 out of 23 years
2 out of 23 years
1 out of 23 years
3 out of 23 years
15 out of 23 years
Because of its preliminary nature, the above analysis is not conclusive. However, it
can be inferred that 9 percent of the time, the annual generation might be 20 percent
less than average. A detailed hydrologic analysis is required to provide more defini-
tion of the characteristics of generation under drought conditions.
4.2.4 Potential for Expansion
The available record of project outflows is scant, consisting only of monthly average
downstream releases and spills and generating discharges for the four-year period from
1991 through 1994, as shown in Figure 4-1. Also shown in the figure is the hydraulic
capacity of the powerplant.
It is evident from Figure 4-1 that the hydraulic capacity of the powerplant, approxi-
mately 270 cfs, exceeds the average monthly outflows for all months, and furthermore,
that the differences between plant hydraulic capacity and these flows are substantial
for all but a few months. Figure 4-1 indicates that a substantial amount of water is
released at the dam to the Terror River. This release is not available for generation, as
it contributes to meeting downstream flow requirements.
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7176/G 22028TERR. WP
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The plant hydraulic capacity is not in itself, necessarily, an indication that additional
capacity cannot be utilized. Daily! hourly inflows may at times exceed the capacity of
the plant, while the average inflow for the month may be less. Unless the storage
capacity of the reservoir is sufficient to store excess daily flow volume and release it
to the powerplant at a later time, this flow is spilled and represents lost energy that
additional plant capacity would be able to generate. In the case of Terror Lake, how-
ever, the active storage capacity of 112,000 acre feet is very large, equivalent to over
six month's release at full gate output. It is likely that daily flow volumes in excess of
the current plant hydraulic capacity can be stored for later release through the plant.
From the above considerations, it does not appear that any significant incremental
energy can be extracted from the available resource with the installation of additional
generating capacity.
From the standpoint of production capacity alone, additional generating capacity could
be utilized if peak-period production was a critical function of the facility. In this
case, provided the inflows and/or reservoir storage were sufficient, the additional ca-
pacity could be utilized in the critical on-peak periods, and off-peak production would
be curtailed accordingly to impound water.
Based on current peak period electrical demands on Kodiak Island that appear to fully
require the generating capacity of Terror Lake, the installation of additional capacity
may merit consideration at this project. To some extent, additional capacity could be
attained through demand management directed at improving the system power factor,
thereby reducing the amount of reactive power that must be supplied by the units.
However, it is quite likely that additional hydroelectric generating capacity could be
installed at Terror Lake at a cost that is competitive with alternative peaking genera-
tion. The cost to install a 12.5-MVA unit in an existing empty bay in the Terror Lake
powerhouse, including the cost of turbine, governor, inlet valve, generator, exciter, and
ancillary equipment, is expected to be about $5 million.
A system demand, project operation, and construction cost study would be required to
investigate capacity addition potential in further detail.
4.3 Generating Unit and Transmission System Availability
Plant operation personnel were interviewed, and FERC operation reports were re-
viewed to characterize the history of unit and transmission system availability.
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7176/G 22028TERR.WP 4-6
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4.3.1 Generating Unit Availability
Two FERC operation reports for the period September 27, 1988, through September
16, 1992 (each report covering two years) reported no unscheduled outage events.
Based on discussions with plant personnel, the plant has been off-line during summer
months in recent years to permit inspections and work in the power tunnel. The tun-
nel was dewatered from August 2, 1994 to October 1, 1994.
4.3.2 Transmission System A vailabillty
Significant outages have occurred due to damage to the conductors caused by heavy
ice loading conditions, ice dropping and conductor slapping. The largest of these
outages are as follows:
• December 1, 1985 December 16, 1985: damaged conductors between struc-
tures 62 and 63, phases B and C; and
• July 15, 1986 -July 19, 1986: damaged condutors between structures 26 and
27.
4.4 Condition Assessment, Recommendations, and Costs
The following section describes the condition assessment and recommendations for
replacements and improvements. At the conclusion of this section, the costs for rec-
ommended improvements and replacements are summarized in tabular form.
4.4.1 Site Inspection Dates
Two teams visited the project facilities during the period of October 2 through October
12, 1995. The first team performed the electrical and mechanical inspection; the sec-
ond team performed the transmission line, civil, and structural inspection.
On October 2 and 3, 1995, J.H.T. Sun and J.J. Quinn of Harza and Stan Sieczkowski
of AEA inspected the Terror Lake electrical and mechanical generating equipment.
On October 11 and 12, 1995, N. Pansic and P.J. Donalek of Harza and Remy Wil-
960208
7l761G 22028TERR.WP 4-7
Iiams, consultant to AEA, inspected the transmission line and the civil and structural
features.
The inspection on October 11 by Pansic, Donalek and Williams consisted of a heli-
copter fly-over of the project, and on-ground inspections of the main dam and the
Falls Creek diversion. The helicopter fly-over included the 138-kV transmission line
and the powerhouse and Airport substations.
Wes Hillman, KEA Electric Maintenance Superintendent, provided photos and other
information about transmission line issues.
For the inspection on October 12 by Pansic and Williams were met in Kodiak by
Mike Downing of KEA. They flew to Kizhuyak Bay, and were met by Bill Pappert,
the Terror Lake Project Foreman. The group inspected the Terror Lake Project, driv-
ing by truck along the project access road to the following facilities:
• Terror Lake dam and spillway;
• Main dam low-level outlet works;
• Main tunnel intake gatehouse;
• Shotgun Creek diversion;
• Falls Creek diversion;
• Penstock intake portal; and
• Powerhouse and miscellaneous facilities.
In addition, Pansic and Williams hiked up to the Rolling Rock Creek diversion.
4.4.2 Reservoir
Condition Assessment. An aerial reconnaissance of the reservoir rim was conducted
by helicopter. The reservoir rim is of moderate steepness, with scrub (alders, etc.)
vegetation and visible rock outcroppings. While the possibility exists of a major land-
slide occurring, the resulting flood wave would probably not overtop the dam parapet
wall and endanger the rockfill dam. This is because the dam has a freeboard of five
feet above normal water level. A concrete parapet wall provides an additional three
feet of freeboard. The 1995 Periodic Safety Inspection Report indicates that there are
no undercut areas at the reservoir level which could trigger large slides.
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7176/G 22028TERR.WP 4-8
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4.4.3 Dam and Spillway
Condition Assessment. A detailed visual inspection of the main dam at Terror Lake
was made by walking across the crest of the dam along the parapet wall from the right
abutment to the left abutment, and then across the downstream face of the dam along
the uppermost berm. The 193-ft high rockfill dam has a concrete upstream face for
seepage control.
The dam appeared to be in very good condition, with no evidence of crest settlement
or downstream slope instability. Although the most recent Part 12 Safety Inspection
Report noted a missing segment of parapet wall at the left dam abutment, this did not
appear to be the case. The parapet wall is partly buried at this location to permit
vehicle access from the dam crest to the left reservoir rim, but still connects uniformly
to the abutment.
Terror Lake Dam is designed to withstand a 100-year design basis earthquake acceler-
ation of 0.35g.
The ungated side-channel overflow spillway was inspected on foot on October 12. It
is designed to pass the probable maximum flood with three feet of freeboard below the
crest of the parapet wall. The spillway is constructed in a rock cut adjacent to the
right abutment of the main dam. The spillway crest is formed by a nominally 20-foot
wide concrete slab, extending some 625 feet in length from the knob at the right dam
abutment to the end of the spillway cut. The crest slab appeared to be in good condi-
tion.
The downstream face of the spillway has a shotcrete facing, designed to prevent ero-
sion of the underlying rock material when the spillway operates. Because of the high-
ly fractured nature of the underlying rock, the spillway has been grouted extensively.
The horizontal joint between the concrete surface slab and the shotcrete facing has
been repaired in numerous areas where spillway flows have tended to lift up the
shotcrete. The most recent flooding was large enough to induce spill over the spill-
way, but there was no evidence of significant damage to the shotcrete or the joint.
The shotcrete will continue to deteriorate with time. The facing should be replaced
with reinforced concrete anchored to the rock.
The wooden bridge crossing the spillway channel provides the only vehicle access to
the main dam and outlet works valve house. Originally designed for expected vehicle
loads, it was subsequently strengthened to withstand snow loadings. However, the
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7176/G 22028TERR.WP 4-9
bridge is too narrow to permit access by construction equipment (e.g., loader, dozer)
for any routine or emergency work at the dam. It did not appear that the recent flood-
ing caused spillway channel flows up to the bridge deck. However, it is likely that
spillway flows approaching the design discharge would wash out the bridge, cutting
off road access to the dam and low-level outlet works. The August 1995 Part 12
Safety Inspection Report indicates that a plan has been developed to install temporary
culverts across the spillway chute with rockfill over the culverts to form a suitable
access road for construction equipment in the event of a need to make emergency
repairs to the main dam and outlet works. This is an acceptable plan for emergency
repairs and would be less expensive than construction of a new access bridge.1
Recommendation. The shotcrete on the downstream face of the side channel spillway
should be removed and replaced with eight inches of reinforced concrete anchored to
the rock.
4.4.4 Main Dam Low-Level Outlet Works
Condition Assessment. A reinforced-concrete outlet conduit passes through the base of
the dam. Inside the concrete outlet conduit, a steel conduit extends from a concrete
plug under the central portion of the dam to a valve house located at the downstream
toe of the dam. The outlet pipe was visually inspected from within the outlet tunnel.
No significant seepage or problems with the outlet pipe were noted. The moderate
seepage flow is handled by the gutter and drain system in the tunnel floor. No visible
signs of corrosion, cracking, or leakage from the outlet pipe were noted at the time of
the inspection.
Releases are controlled by a 36-inch polyjet valve, which was operating at the time of
the inspection. It was apparent by observing the pulsing discharge from the polyjet
valve that some imbalance in the valve flow is occurring. Mr. W.E. Larson of Larson
Engineering, Inc. inspected the polyjet valve installation on November 2, 1995. He
concluded in his November 16, 1995 report that the vibration problem appears to be
caused by vortexing in the discharge pipe with two short-radius miter pipe bends in-
stead of the polyjet valve itself. Mr. Larson recommends the following on the existing
installation:
No cost is include for this item in Table 4-4 since it would only be required in the event
of an emergency. Such costs are considered to be included in the risk-related costs
described in Chapter 6.
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1. Replace the motor-operator for the polyjet valve;
2. Check the valve stem for straightness and for perpendicularity to the ma-
chined top or bottom surlace of the valve;
3. Eliminate the single maximum open limit switch and provide flexibility of
the maximum valve opening to accommodate lower reservoir levels while
maintaining the concept of a safe discharge limit;
4. Install a low weir at the entrance to the intake structure to serve as a trap for
the rocks and stones;
5. Replace the 0-ring seal on the valve to stop the present closed-position leak-
age;
6. Install a manhole on each side of the valve body to provide access to the
water distribution annulus for debris removal.
Recommendation. Replace the polyjet valve operator, and implement other recommen-
dations made by Larson.
4.4.5 Main Tunnel Intake Gatehouse
Condition Assessment. Flow through the 11-foot diameter power tunnel is controlled
by means of a 5-foot wide by 10-foot high hydraulically-operated sluice gate. The
gatehouse floor is about 225 ft above the gate sill. Only the interior of the gatehouse
was inspected. However, AEA staff provided a report and videotape of the detailed
inspection of the gateshaft and gate conducted by the U.S. Bureau of Reclamation
(USBR) in July 1995. The USBR inspection noted significant leakage and erosion of
the concrete around the gate sill and leakage through the bottom gate seal, along with
substantial leakage through the concrete divider wall in the gateshaft throughout its
height. Leakage through the latter is such that the USBR inspection was conducted
using a remotely-operated vehicle (ROV) instead of by divers.
The gate house is not heated, due to limited ( 4 months per year) access. As a result, the
electric control panel is significantly corroded. A propane generator in the gatehouse
provides the power for the hydraulically operated gate, as well as for the electric mo-
tor for the bridge crane. The continued corrosion will create shorting out of the con-
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71 76/G 22028TERR. WP 4-11
trol panel in the future. Therefore, higher than normal maintenance costs can be ex-
pected and the panel will require replacement over the project life.
Due to concern for snow avalanches, the originally-proposed steel building structure
for the gatehouse was changed to a concrete building. Also, stones have been placed
upslope of the structure in an attempt to divert avalanches around the structure. While
the avalanche hazard exists, it is doubtful that an avalanche would cause failure of the
gate mechanism.
In general, routine inspection and maintenance of the intake gate system is inhibited
by poor access. The access road is free of snow only about four months out of the
year. The intake itself, located about 2,400 feet upstream of the gatehouse and gate
well, is submerged in the reservoir and has never been inspected. In order to pull the
trashrack or install the bulkhead at the intake, a crane working from a barge would be
required to permit inspection of the tunnel and shaft upstream of the gate and the gate
itself.
Recommendation. USBR's recommendations for repairs to the gate sill and shaft struc-
tures should be carried out. During the unwatering of the tunnel, the tunnel section
between the gate and the intake structure should be inspected at the same time. The
electrical controls at the gatehouse should be replaced.
4.4.6 Main Tunnel
Condition Assessment. As the project was operating at the time of the inspection,
there was no opportunity to inspect the main power tunnel. The tunnel was dewatered
and inspected for the first time in August 1994. The inspection report indicated that
some minor small localized rockfalls have occurred within the mostly unlined tunnel.
The potential for future rockfalls certainly exists. If a subsequent rockfall were severe
enough to close off the tunnel, the project could be out of service for a considerable
amount of time (i.e., a year or more). However, the tunnel has been in service 13
years with minor deterioration. Large rockfalls are more likely to occur during large
earthquake events.
Sediment has caused difficulties with the turbine and its related components. It is
believed that the sand and sediment originate primarily from the Rolling Rock diver-
sion. Construction of a sediment discharge system, located inside the tunnel near its
downstream portal, was started, but was not finished. The purpose of the sediment
960208
7176/G 22028TERR.WP 4-12
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discharge system is to collect and remove sand and sediment that enters the tunnel.
The facility is a local enlargement of the tunnel with collection hoppers in the tunnel
invert, and a conveyance system to remove accumulated sediment. The system was
not completed due to difficulties with the construction contractor and the contractor's
ability to complete the system. When the work was stopped, the project was put back
into operation. Thus, in its current unfinished state, the sediment discharge system is
not operational.
Drawings of the sediment discharge system were reviewed. The system appears to be
well designed, and facilities of this type have operated effectively at other projects.
However, the effectiveness of the system depends on the amount and size distribution
of the sediment transported, flow velocity in the settling basin, and efficiency of the
sediment conveyance system connected to the collection "hoppers.'1
Recommendation. Preparation of an emergency response plan in the event of a major
rockfall in the main tunnel is recommended to minimize cost and outage impacts. A
recommendation to study the overall function of Rolling Rock diversion and the sedi-
ment sluicing system is provided in 4.4.8 Rolling Rock Creek Diversion.
4.4.7 Shotgun Creek Diversion
Condition Assessment. Shotgun Creek diversion diverts flows into the Falls Creek
reservoir where it is then diverted into the Falls Creek auxiliary tunnel to augment the
flow of the main power tunnel. The diversion from Shotgun into the Falls Creek
drainage was originally constructed as an open channel. However, due to anticipated
problems with snow and ice clogging the channel, an 84-inch diameter corrugated
metal pipe culvert was constructed to replace the channel. Reportedly, the culvert was
not bedded properly and has a uneven vertical alignment throughout its length from
the overburden loads. The uneven vertical alignment can result in reduction in flow
capacity and increased tendency for blockage of flow.
The recent flood caused the emergency spillway at Shotgun Creek diversion to operate
for the first time. At the time of the inspection, road repair work near the diversion
culvert was underway.
The design of the 40-ft high diversion dam is similar to the main dam. The diversion
dam appeared to be in good condition, with no particular problems with settlement or
upstream face treatment noted.
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Some erosion was noted at the exit of the low-level outlet of Shotgun Creek diversion
dam. This erosion should be observed in the future and remedial measures taken if it
begins to threaten the toe of the dam.
Recommendation. The Shotgun to Falls Creek diversion culvert should be removed
and rebuilt to correct the alignment.
4.4.8 Falls Creek Diversion
Condition Assessment. This diversion was impacted by the recent flooding in two
ways -the spillway flow caused some erosion at the spillway toe and washed out the
access road some 50 yards downstream, and a considerable amount of coarse sediment
was deposited in the reservoir. This material had to be excavated to prevent excess
material from entering the tunnel.
The diversion dam did not appear to suffer any damage due to the recent flood.
The foundation of the spillway toe was eroded for about a third of its 200 ft length.
As some erosion of the spillway toe was noted in the August 1995 Part 12 Safety
Inspection Report, it is not apparent how much additional erosion occurred in the
recent flooding. At one location, about 30 ft in length, the erosion has begun to un-
dermine the spillway flip bucket. As a temporary measure, stone will be placed in the
erosion area to prevent further damage should the spillway operate again. A concrete
apron at the base of the spillway, which could then serve as a portion of the access
road, needs to be constructed.
The diversion tunnel intake structure was also inspected. Measures recommended in
the August 1995 Part 12 Safety Inspection Report included riprap protection of the
intake wingwalls, and evaluation of the stability of the berm supporting the access
road to the intake.
The August 1995 Part 12 Safety Inspection Report stated that notable erosion of the
concrete invert had occurred in the upper horizontal diversion tunnel, and that a por-
tion of the vertical shaft had a 240 cubic yard cavity scoured out at about halfway
down the shaft. The scour had deposited rock into the lower horizontal tunnel. The
horizontal tunnel section is partially shotcrete-lined, and some of this lining has eroded
away. The USBR has also investigated problems associated with this tunnel, with
recommendations for repairs (see references in Appendix A). Remedial measures are
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also recommended for implementation by November 1997 (FERC August 1995 Part 12
Safety Inspection Report). Maintenance improvement to the invert of the horizontal
tunnel section is recommended to prevent undercutting of the exposed rock. The
cavity in the shaft should also be repaired in accordance with the USBR recommenda-
tions.
Recommendation. Carry out measures suggested by the Part 12 Safety Inspection Re-
port regarding riprap protection of the intake wingwalls, a evaluation of the stability
of the berm supporting the access road to the intake, and painting the trashracks.
The recommendations outlined in the USBR report regarding the repairs to the 40-foot
long section of the inclined shaft should be implemented. The eroded upper tunnel
invert should be replaced with new concrete anchored to the rock. A more detailed
study of the design, construction, and management is required to determine reasons for
the development of the cavity in the inclined shaft to evaluate the cause of this failure,
and also to prepare specifications for remedial work.
4.4.9 Rolling Rock Creek Diversion
Condition Assessment. The diversion dam and intake portal were inspected by hiking
up the creek bank from the penstock portal, and climbing up the rock rubble which
forms the dam. Although maintenance had recently been done on the diversion dam
and reservoir, the recent floods have brought more material into the reservoir, signifi-
cantly reducing its storage capacity. This diversion was originally designed to be
simply a tunnel surge chamber.
AEA has begun construction of a sediment discharge system from the tunnel upstream
of the portal. The system is designed to use normal tunnel pressures to mobilize sand
in a constructed trap (by enlarging the existing rock trap) and sluice it out of the trap
into the adjacent Rolling Rock Creek drainage channel. Completion of this construc-
tion, which had been halted at the time of the inspection, will require an extended
shutdown of the project.
Recommendation. A detailed engineering review of the Rolling Rock diversion should
be carried out to determine the future course of action. Such a review was presumably
carried out before the decision was made to construct the sediment discharge system.
The circumstances related to the cost of the facility, its expected effectiveness, and the
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cost of alternatives, should be re-evaluated in developing a recommended course of
action.
A preliminary computation indicates that the runoff that is collected by the Rolling
Rock diversion is a measurable contribution to the water supply of the project. How-
ever, it is believed that a substantial portion of the sediment that enters the tunnel and
causes damage to the runner and components enters from Rolling Rock. A more
detailed evaluation of the historical generation contribution of this facility versus the
associated maintenance costs of removing sediment material within the reservoir is
required to determine if the facility should be converted to a surge chamber only or
continue to be operated as a diversion facility.
4.4.10 Penstock and Intake Portal
Condition Assessment. The penstock intake portal building was inspected, with no
particular problems noted. Discussions were held with Mike Downing and Bill
Pappert concerning the emergency closure valve and its mechanical trip mechanism.
The penstock butterfly valve is equipped with a paddle-type trip mechanism to initiate
valve closure on overvelocity. According to plant personnel, this mechanical trip
mechanism is in operating condition. However, the 1995 Part 12 Safety Inspection
Report states that a mechanical trip of this type is not reliable. Current technology
would use an acoustic flow meter to detect excessive velocity and trip the emergency
closure value. The 1995 Part 12 Inspection report also indicated that the existing coal
tar epoxy on the invert of the penstock from the powerhouse to the Rolling Rock
diversion has been scoured away.
Plant personnel report that the internal access to the upper penstock is too small for
personnel and maintenance equipment. The interior of the penstock should also be
inspected and painted at 10 to 15 year intervals.
Recommendation. An acoustic flow meter for closing the valve on overvelocity is rec-
ommended. If the sand sluicing system is installed, the internal access to the upper
penstock should be modified and the penstock interior painted. The interior of the
lower penstock where the existing coating over the invert has been scoured away
should also be painted.
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4.4.11 Powerhouse
Condition Assessment. The Terror Lake powerhouse is a concrete substructure with a
steel superstructure. No structural cracking or distress was noted on the generator
floor and turbine pits during the inspection. The powerhouse location at the base of a
moderately steep slope gives rise to the possibility of landslide or snow avalanche
damage. A landslide occurred in this area during construction after a heavy rainstorm.
The base of the powerhouse is situated about 95 ft above sea level. However, there is
a possibility of damage caused by tsunami. In addition, the recent flooding caused the
Kizhuyak River to change its course near the project warehouse. The river has previ-
ously broken into the tailrace.
Recommendation. Monitor and define drainage characteristics of slope uphill of the
powerhouse to further define potential for damage and determine the need for preven-
tative measures. Architectural refurbishment should be anticipated after about 30
years of service. (Year 2015).
4.4.12 Miscellaneous Facilities
Condition Assessment. As part of the inspection, the group also visited the warehouse,
maintenance shop, and incinerator. Mike Downing pointed out the area where the
Kizhuyak River has changed course near the warehouse. KEA plans to construct a
temporary dike upstream to divert the river back into its original course. Mr.
Downing also expressed concern over possible undermining of transmission tower
foundations located in the Kizhuyak River channel, and the potential flooding of the
main switchyard due to overflow of an adjacent creek.
The jetty at Kizhuyak Bay was inspected. The timber pile fenders are deteriorated at
the waterline due to marine biological activity. These will require replacement within
the next few years.
Recommendation. A foundation investigation should be made to evaluate the possibili-
ty of designing a more permanent structure at the location of the temporary dike to
prolong the time between reconstructions of the dike. The dike should be constructed
using information obtained from the investigation.
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The potential undermining of the transmission towers should be prevented by place-
ment of riprap and bedding material adjacent to the tower foundations.
The creek adjacent to the switchyard should be channelized to increase the carrying
capacity and reduce the potential for flooding the switchyard.
The timber fendering on the Kizhuyak Bay dock should be replaced with new treated
wood timber fendering.
4.4.13 Access Road
Condition Assessment. The Terror Lake Project includes some 16 miles of access
roads. As a result of the recent flood, the road was completely washed out in at least
three locations, with significant erosion at a dozen other places. KEA estimated over
$200,000 in road repair work was required to restore the damaged sections.
KEA reports that the upper access road is clear of snow only a few months out of the
year. This requires advance planning of any scheduled maintenance activities, and
often delays completion of any unscheduled maintenance due to access restrictions by
deep snow.
Future flood events will likely wash out the same or other sections of the road. Con-
tinued maintenance and repairs will be required to maintain the access road in usable
and dependable condition. The costs associated with such flood events are considered
to be included in the risk-related costs presented in Chapter 6.
4.4.14 Turbines
Condition Assessment. Both Pelton turbines are considered to be in good condition.
Because of the sand and silt from the diversion tunnels, erosion appears to be the main
problem on the turbine needles, nozzles and runners. Unit 1 needles and nozzles were
overhauled in early 1992. Unit 2 needles and nozzles were also overhauled in January
1993. Unit 2 stainless steel runner had a wear of more than 0.16 inch in depth and
was repaired by General Electric in March 1993. The repaired Unit 2 runner was then
installed on Unit 1. The spare runner has been on Unit 2 for operation since March
1993. In November 1995 the maintenance personnel discovered a crack on one of the
19 buckets on the Unit 1 runner. This runner has now been removed from Unit 1 for
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repair and the previously repaired Unit 1 nmner has been put back on Unit 1 for oper-
ation. The shaft seal replacement and shaft alignment were perfonned in May 1994
for Unit 1 and in March 1993 for Unit 2. The carbon steel oil tubing for the needle
servomotor controls on both units was replaced with stainless steel tubing around
1990. Both units operate smoothly without noticeable vibrations.
In general, the normal period between major runner repairs is approximately 15 years.
The stainless steel runner can be repaired twice, for a total useful runner life of 45 to
50 years. The actual useful life of the Pelton runner depends on the amount of sand
and silt in the water. After completion of the construction of the sediment discharge
system upstream of the penstock portal, the water quality should be improved.
Review of the Unit 1 output versus needle opening curve measured in November 1984
indicates that the Pelton turbine could deliver a generator rated load of 11.25 MW at
60 percent needle opening under a maximum net head of 1 ,263 ft. At the time of the
inspection on October 2, 1995, both units were generating 9.3 MW each under the
maximum net head. The needle opening on each turbine was around 42 percent which
is consistent with the original Unit 1 output versus needle opening curve. Based on
the expected turbine perfonnance curves and current turbine conditions, the estimated
turbine output is 13,800 hp (10.3 MW) under a net head of 1,046 ft, 15,666 hp (11.7
MW) under a net head of 1,136 ft and 18,336 hp (13.7 MW) under a net head of
1,263 ft.
Each turbine can deliver a full rated load to the generator when the net head on the
turbine exceeds 1, 136 ft.
Based on the expected turbine perfonnance curves, the turbine has a peak efficiency of
90.9 percent at 50 percent needle opening near the rated net head of 1,136 ft. The
best efficiency operating range is from approximately 40 to 60 percent needle opening
for all operating net heads with an average turbine efficiency of 90.8 percent. The
Terror Lake generating units were operating within the best efficiency range during the
inspection. If the needle opening is around 80 percent, the turbine efficiency reduces
to 90.5 percent, representing an additional use of approximately 0.4 cfs of water at
rated load.
The turbine runner centerline is set at El. 103.5 ft above mean sea level and the nor-
mal tailwater in the runner chamber with turbine full discharge is El. 98.7 ft. A blow-
er system is provided to depress the water level in the runner chamber when the
tailwater is above the normal operating level in order to avoid interference between the
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runner and the tailwater. This tailwater depression system has been used several times
in the past years.
4.4.15 Governors
Condition Assessment. Each Pelton turbine is controlled by a UG 8 governor for
maintaining the operating speed and positioning the needle and deflector servomotors.
The governors are manufactured by the Woodward Governor Company. The normal
operating pressure of the governing system is 500 psi. Both governors are working
properly. The maintenance personnel have installed an additional oil filter on the
pressure side of the governor piping to eliminate oil contamination. The routine main-
tenance also includes the repair of worn linkages of the mechanical speed switches in
the permanent magnet generator (PMG) mounted on the top of generator shaft.
Recommendation. The PMG should be replaced with the speed signal generator (SSG)
on each unit in the future.
4.4.16 Spherical Valves
Condition Assessment. Each turbine inlet is guarded by a spherical valve. High pres-
sure water from the penstock is used to operate the valve rotor as well as the upstream
and downstream valve seals. The spherical valve is designed to close against full
turbine discharge for protection of the unit under runaway conditions. The valve clos-
ing time is designed to be between 30 and 120 seconds which is satisfactory for unit
protection.
According to the operating and maintenance personnel, there is no sign of wear on the
valve seals. Both spherical valves are in good condition. The leakage through the
closed valve with the seals applied is reported to be very small.
A water supply is withdrawn through the bypass line of the inlet valve. The piping
and elbow on the high pressure side of the bypass valve and pressure reducing valve
have been replaced with Schedule 80 piping and fittings. The original Schedule 40
piping and fittings were worn out due to erosion and cavitation.
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4.4.17 Powerhouse Auxiliary Mechanical Equipment
Condition Assessment. The galvanized and iron piping for the cooling water, potable
water and fire protection systems have a severe corrosion problem. All galvanized and
iron piping need to be replaced.
The cooling water system was designed to operate one pump for two units. At pres-
ent, operation of two pumps is required to maintain the bearings and generator coolers
at desirable temperature settings for two units when generating approximately 6 MW
each. Operation of three pumps is necessary in the summer with high water and air
temperatures to keep two units operating at a load of approximately 9 MW each. The
shaft seals on all three cooling water pumps are leaking. Although all pumps are still
in operating condition, they should be replaced to improve reliability.
The machine shop adjacent to the powerhouse is spacious. However, the building
structure is not suitable for installation of a permanent hoist or crane. A small capaci-
ty movable hoist to handle the turbine or generator components is desirable.
Other auxiliary mechanical equipment such as the powerhouse crane, station drainage
system, unit unwatering system, heating and ventilation system, and station service air
system are in satisfactory condition.
Recommendation. All galvanized and iron piping for the cooling and potable water
and fire protection should be replaced. Cooling water pumps should be replaced. A
small capacity movable hoist should be acquired for the machine shop.
4.4.18 Generators
Condition Assessment. The generators have a continuous overloading rating of 115
percent without injurious heating. Therefore, each unit could produce 12.94 MW at 90
percent power factor. Each unit's output could be further increased by improving the
distribution system's power factor. The generators are classified as "suspended type"
with a combined thrust and guide bearings located above the rotor and a guide bearing
located below. Other major features include a self-ventilated cooling system where
cooling air is circulated in a closed loop through air-to-water heat exchangers located
within the housing.
The overall condition of both generators is considered to be good.
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Both generators had to be rewedged after one year of service, Unit 1 in September
1985 and Unit 2 in November 1985. The generators have not encountered any wedg-
ing problems since 1985. Another outage due to an internal fault occurred on Unit 1.
The internal fault occurred when the oil level switch covers came off and shorted three
windings on one field pole. The plant's personnel were able to correct this problem.
The bearings on both units were realigned in 1993. The last annual inspection re-
vealed that the bearing surfaces were in good condition.
Oil vapor is accumulating in the main field's collector ring housing. The oil barriers
between the main shaft and the upper oil reservoir may be worn. These barriers will
be replaced when the collector rings are replaced by the end of 1995.
The air coolers appear to be in good condition. However, the plant personnel indicat-
ed that the air coolers had some corrosion and the plant has no spare cooler. New
coolers should be provided. Oil coolers were reported to be in good condition. There
also is a restriction in water flow to the coolers due to a buildup within the steel water
piping. KEA is replacing this steel pipe with PVC.
The existing carbon brushes for the main field last approximately 3-4 months. This
extremely short life is due to the fact that the existing main field collector rings were
manufactured from steel. These rings are being changed to copper rings to improve
the life and reduce the amount of carbon dust created by the present design.
There is no high pressure oil lift pump to force oil to the thrust bearing pads prior to
unit startup or at slow speed. Therefore, manual jacking is required if the unit is at
rest for 24 hours or longer. This procedure does not create a problem under the pres-
ent operating conditions since both units are normally in operation except for annual
maintenance. Addition of oil lift pumps should be considered if and when a third unit
is added.
Recommendation. New generator air coolers should be acquired.
4.4.19 Station Service Transformer and Switchgear
Condition Assessment. There are no reported problems with the station service equip-
ment. The switchgear has adequate spares to accommodate the expansion of the pow-
erhouse with the addition of a third unit.
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4.4.20 DC System
Condition Assessment. The 125-V DC system, including batteries, battery chargers,
and the control wiring, appear to be in good condition. One of the 48-V DC battery
chargers had to be replaced with a type from another manufacturer. Components for
the original model were no longer available.
4.4.21 SCADA System
Condition Assessment. Terror Lake generation is controlled from the load dispatch
office located in Kodiak City through the SCADA system. KEA has been upgrading
the CPU, the monitors and software at the diesel plant. To date, there has been no
replacement of components for the RTUs (remote terminal units) located in the
powerplant and the two substations.
Recommendation. It is recommended that these RTUs be replaced.
4.4.22 Communications
Condition Assessment. The primary communication link between Terror Lake and the
load dispatch office is the State-owned microwave system. A power line carrier (PLC)
system provides a backup system. This backup system was installed during the origi-
nal construction of the plant. Maintenance on the PLC has been increasing over the
last several years and obtaining spare parts is becoming extremely difficult.
Recommendation. It is imperative to maintain a backup communication system since
the plant experiences periodic outages on the microwave system, and the PLC system
should be replaced with a new PLC system.
4.4.23 Emergency Generator
Condition Assessment. The emergency generator is a Marathon Electric Magna One
synchronous generator rated at 156 kVA. This capacity is inadequate to carry the
station load. Therefore, load shedding is required prior to transferring to the emergen-
cy generator. This arrangement will be adequate for outages of short duration but not
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acceptable for periods during the year, i.e. during severe winter conditions, where the
outage may last for several days or weeks.
Recommendation. A 400-kW emergency generator should be provided.
4.4.24 Controls
Condition Assessment. The plant is controlled from the Kodiak City load dispatch
office but must be manually synchronized at the plant. The manual synchronization
requires considerable effort to match the diesel generator load and the hydroplant load
due to the long penstock at the hydroplant and the slow response time. New automat-
ic synchronizing equipment would bring the hydroplant back on line after an outage
more efficiently.
Recommendation. New synchronizing equipment is required at the Kodiak control
center.
4.4.25 Powerhouse Switchyard
Condition Assessment. Two 3-phase transformers with an OA/FA rating of 11.25115
MV A are located in the switchyard. Space is also available for a future transformer.
The cooling fans have never operated automatically because the generators were oper-
ated very conservatively and the transformers are located in a cool ambient tempera-
ture. The transformer for Unit 2 recently had a minor oil leak, but it was repaired
prior to the inspection visit. The transformers had touch-up painting performed last
year. Frequent painting of the transformers is essential due to the atmospheric condi-
tions.
Like the power transformer, equipment and structures in the switchyard require fre-
quent touch-up painting.
The concern for this switchyard is the potential for flooding from the creek that runs
behind the switchyard. The creek channel continues to erode, and under flood condi-
tions could flood the switchyard.
Recommendation. The creek should be channelized and riprap protection provided in
the channel to correct the erosion problems.
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4.4.26 Transmission Line from Terror Lake to Airport Substation
Condition Assessment. The 138-kV line is single circuit, and is supported on single
shaft steel poles. The steel poles are fabricated from "weathering steel.11 The conduc-
tor is 397.5 kcmil 3017 ACSR code name "Lark." The suspension structure configura-
tion is shown in Figure 4-3.
The concerns for this section of line are as follows:
• The steel structures located in the salt sea-air atmosphere continue to weather,
contaminating the insulators. The primary concern is that this weathering, and
the subsequent contamination of the insulators, will result in flashovers.
• There is concern that the metallurgy of the weathering steel structures is flawed
and could lead to premature weakening of the structures and potential failure.
• KEA has experienced broken and damaged conductors due to ice and snow. The
conductor damage is either broken strands or burnt conductor strands.
• There is a risk to the 138-kV lines from trees along the edge of the right-of-way
that could fall on the lines.
• The duration of an outage during winter could be extended because of the lack
of a helicopter with heavy-lift capability.
• Avalanches have been reported to have occurred along the line route, but no
damage to the structures has been reported.
• The supply of steel pole spares stored at the Airport substation is reported to be
insufficient to provide in-kind replacements for each existing tower type.
Additional discussion is presented below:
Insulators
Condition Assessment. KEA is just beginning to use epoxy and composite insulators,
in response to problems of insulator contamination. During the service years of this
line, the following potential contaminants have been observed to accumulate on the
insulator surface which could ultimately reduce the dielectric strength of the insulator
assembly:
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7!76/G 22028TERR.WP 4-25
• Salt deposits,
• Volcanic dust,
• Tree pollen, and
• Rust deposits from weathering steel structures.
Most of these contaminants wash away during periods of rain. During dry periods, a
build up of contaminants could reduce the leakage distance of the insulator assembly
to the point that could cause a phase-to-ground fault. After 11 years of operation, no
flashovers have been attributed to insulator contamination.
The contamination concerns and insulation integrity of this line can be addressed in
two (2) steps.
1. Remove one insulator assembly from the line with significant deposits of weather-
ing steel deposits, and through tests, find the critical flashover voltage of the as-
sembly. Compare this calculated insulator assembly with the anticipated critical
flashover voltage, then the line during normal operation and during switching.
If the calculated critical flashover voltage is less than the anticipated critical
flashover voltage, then the line is degraded and insulators should be replaced with
insulators drawing higher leakage distance considering the test results.
An evaluation should be made to determine the merits of the different insulators
(porcelain, epoxy and composite types), considering the types of contaminants, in-
cluding possibilities of vandalism from rifle shots.
2. Conduct insulator contamination tests to establish the level of contamination (salt
deposits, volcanic dust, and tree pollen) that could be deposited on the insulator
assemblies. The test can be done by placing typical insulator assemblies used in
the line at a few areas considered to be most severe. At appropriate intervals,
remove the test insulators, wash them, and calculate the level of contaminants.
Based on the levels of contaminants calculate the degradation of the dielectric
strength of the insulator assembly and compare the critical flashover strength of the
assembly with the critical flashover voltage of line during normal and switching
operations. If the calculated critical flashover strength of the assembly is less than
the critical flashover voltage, then insulation of the line is inadequate and insulator
assemblies must be replaced with those of higher leakage distance.
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Alternatively this test can be done by removing a number of insulator assemblies
from the line and testing to fmd the level of contaminants and the relative degrada-
tion of the insulator assembly leakage distance.
At this point, an evaluation of the merits of different insulator types (porcelain,
epoxy and polymer) should be made to select the assembly suitable for the antici-
pated critical flashover voltage of the line and anticipated level of contaminant,
including possibilities of vandalism from rifle shots.
Line Structures and Weathering Steel
Condition Assessment. There are approximately 100 steel pole structures in the 138-
kV transmission line between Terror Lake and the Airport substation. These structures
are fabricated with weathering steel that is manufactured by Bethlehem Steel Compa-
ny. The product name is "MAY ARI."
After ten years, the corrosion of the steel structures in the portion of the line that are
exposed to marine salt atmosphere has not stabilized. That is, the weathering process
has continued instead of reaching a steady state. There is concern that the steel will
continue to corrode and that the steel poles may fail. Failure would occur because the
loss of material over time would reduce the thickness of the steel to a point of failure.
A consultant has been retained by KEA to assist in the analysis and evaluation of the
weathering/corrosion problem.
A test rack with samples of the weathering steel has been set up in a substation. Steel
samples are tested at intervals; test years are 2, 4, 8 and 16. The test that is per-
formed is to measure the thickness of the metal.
The two and four year tests have been performed. Data for the two and four year tests
do not indicate that the corrosion is stabilizing. The testing process is not conclusive
at this time, since there are only two data points. KEA may perform a test at the six
year point, and obtain a third data point.
Recommendation. Consultants who have been retained to examine and study the
problem should be requested to provide an interim report with recommendations.
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Vertical Phase Spacing
Recommendation. The configuration of phase conductors should be revised to reduce
the likelihood of flashover. Among the possible solutions to be considered is to re-
place existing I string insulators in the top phase position with an assembly of two
insulator strings.
Plant personnel report that the conductors slap during ice dropping. The upper phase
is directly above the lower phase, and the ice could drop from the upper directly onto
the lower phase, causing the conductors to slap. A modification, illustrated on Figure
4-4, should be investigated.
The steel arm on the transmission line structure has a length of 9.5 ft and the insula-
tors have a length of 5.73 ft. The insulator assembly of the top arm can be moved by
3.5 ft and be restrained by a strut insulator as shown on Figure 4-4 which will provide
a solution to the conductor slapping. With this modification, no additional loadings
will be imposed on the structure or foundations. The arm should be checked at the
new attachment point to ensure that the arm can take the loadings at that cross section.
The mounting on the arm of the suspension string and the mounting on the pole can
be done with special straps that are available from fabricators. The connection of the
post insulator on the pole should have complete freedom to rotate in the longitudinal
direction. The connection between the post insulator and the suspension insulator at
the clamp will require special hardware which is also available from the fabricators.
Right of Way and Danger Trees
Right -of-way maintenance is not required for most of the length of the line because
trees and bmsh do not grow very high. However there are sections within a few miles
of the powerhouse and Airport substations where tall trees are at the edge of the right-
of-way.
KEA has experienced outages that have lasted 2 to 3 days. These outages have oc-
curred in winter and are the result of a tree falling into the line.
Recommendation. Danger trees should be identified and removed. This should be
done on an annual maintenance basis.
Avalanche
Condition Assessment. There have been avalanches along the line route, but to date
they have not damaged line structures. It is not known if a study has been prepared to
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identify the risk from avalanches. Avalanche locations should be identified and evalu-
ated to determine the potential for risk to the line.
The avalanche study could be used to develop an "emergency action" plan that pro-
vides temporary transmission line structures, materials and tools so that if a tower or
towers fail, then the line can be returned to service while permanent equivalent re-
placement poles are fabricated or obtained from spares stored at the Airport substation.
Recommendation. An avalanche study including on emergency action plan should be
prepared for the 138-kV transmission line right of way. If the study indicates that
certain sections are "at risk," then preliminary designs should be prepared considering
the use of underground lines, so that the "at risk" lines can be replaced prior to or
after an avalanche occurrence.
Helicopter
Condition Assessment. The need and availability of a helicopter as part of an emer-
gency action plan should be evaluated. Helicopter service during winter season should
be evaluated and appropriate action taken to make helicopters available to line crews.
The evaluation should be based on an acceptable outage time for repairs. The need
for a heavy lift helicopter should be included in the evaluation. Without a heavy lift
helicopter, the ability to carry out structural repair is limited.
Recommendation. The need for heavy lift helicopter service in winter should be eval-
uated and appropriate action taken to make helicopters available for use by line repair
crew. The evaluation should be based on an acceptable outage time for repairs.
Spare parts
A supply of spare steel structure sections is stored at the Airport substation.
The supply of on-site replacement structures is not complete. That is, the supply of
spares does not include a spare for each steel pole section type.
If a tower fails, and a spare section was not available, then the line could be out of
service for an extended period. This is of great concern if the outage occurs during
the winter.
There is also concern that the spares are not fabricated with the same thickness of
steel as the parts they are intended to replace. Thus it is possible for an existing pole
960208
7176/G 22028TERR.WP 4-29
section to fail and the only replacement would be a section of similar shape but with
thinner steel. An experience was described in which a replacement section had been
found to be fabricated with 114 inch thick steel, and the equivalent existing section is
fabricated from 5/16 inch thick steel.
Recommendation. An emergency action plan should be developed for the possible loss
of a tower. The plan should provide for temporary structures, materials, and tools so
that if a tower then the line can be returned to service while a permanent equivalent
replacement pole is fabricated or obtained from spares located at the Airport substa-
tion.
4.4.27 Airport Substation to Swampy Acres Substation 138-k V Line
Condition Assessment. This 1.6-mile line is supported on H-frame wood pole struc-
tures in a flat configuration. There are no concerns related to this line.
4.4.28 Distribution Line between Terror Lake and Port Lions Diesel Plant
Condition Assessment. This line is about 12 miles in length and is supported on single
shaft wood poles. Under certain system load conditions, the generators at Terror Lake
can not meet voltage regulation requirements at Port Lions. As a result, Port Lions
consumers are subjected to voltage outside of acceptable range.
Recommendation. It is recommended that this problem be resolved by the installation
of a voltage regulator at the Port Lions terminal.
4.4.29 Airport Substation
Condition Assessment. The Airport substation site is very large and can accommodate
several additional transformers and line terminals. The substation has no oil recovery
facilities; but there is a plan to install an oil collection system around the transformers.
The automatic recloser operation on the primary distribution feeders have been discon-
tinued with peak loads greater than 3 MW. Experience has shown that the Terror
Lake governors cannot respond quickly enough to the transient situation when a pri-
mary distribution feeder with more than 3 MW is reclosed following an initial circuit
breaker operation. Because the governor cannot respond quickly enough, the result is
a system black out. This problem is related to the turbine, penstock and governor
960208
7176/G 22028TERR.WP 4-30
\"t-
Ill
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characteristics. There is nothing at this point that can be done at the plant to improve
or correct this problem.
The problem could be addressed by revising the loading of each feeder to be less than
3 MW. Therefore this problem is not related to the plant or transmission system.
K.EA has experienced a problem of condensation freezing in the vertical section of
tubular steel supports in the Airport substation. The problem was determined to be
that grout placed at the base of the structure plugged the drain holes. Several vertical
support structures failed, and were replaced. The grout has been removed and the
problem has not reoccurred.
4.4.30 Swampy Acres Substation
Condition Assessment. Substation equipment at Airport and Swampy Acres is exposed
to salt air, and it is necessary to scrape, prime and paint the exposed metal parts. It
was observed that painting was being done on a regular basis.
The substation has no oil recovery facilities but there is a plan to install an oil collec-
tion system around the transformers.
There were discussions concerning the transformer's capacity in this substation as
being a limiting factor to an increase in Terror Lake's generating capacity. It was
reported that the 20 MV A transformer rated in the Swampy Acres substation was
frequently being loaded to near its maximum rating. If the turbines at Terror Lake are
upgraded to a greater output, then the existing transformer in Swampy Acres may
become a "bottle neck."
Another transformer would be required if a third generating unit is installed at Terror
Lake. However, the existing transformer is suitable to carry an incremental increase in
generation. This transformer is rated for 28 MV A with forced air cooling and 65°C
temperature rise. A new larger transformer is recommended at Shotgun Acres substa-
tion when the existing generator reaches its useful life in year 2014.
960208
717610 22028TERR.WP 4-31
4.4.31 Rolling Stock
Condition Assessment. All the rolling stock at Terror Lake is owned by KEA and
consists of the following:
1. Front-end loader-new and in good condition;
2. Bulldozer -requires replacement
3. Dump truck -old, requires replacement
4. Backhoe -in good condition
5. Road grader-in good condition
6. Four pickup trucks -will require replacement within their normal expected
life.
Recommendation. Replace the dump truck and bulldozer, acquire a forklift to facili-
tate movement of equipment and spares.
4.4.32 Infrastructure
The infrastructure consists of housing units, storage facilities, boatdock, and other
items. These facilities have varying service lives and replacement costs. The housing
units, storage and other facilities are estimated to have a useful life of 30 years. The
boatdock is estimated to have a useful life of 15 years. At the end of the service lives
of these facilities, an estimated 75 percent of the replacement value is included to
replace or upgrade these facilities to current standards. An estimate of the typical
service life replacement cost and schedule for replacement for these items has been
made and included as part of the information provide in Tables 4-5 and 4-6.
960208
71 76/G 22028TERR. WP 4-32
7".,
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4.4.33 Documentation
Condition Assessment. Detailed investigation reveals that the drawings do not include
the field changes and drawings do not represent as-built conditions. Terror Lake is
unique in that the plant personnel were involved during the construction of the plant.
They have a vast knowledge of the plant's peculiarities that are not documented any-
where.
Recommendation. A concerted effort should be made for the drawings to be brought
up to as-built status.
General Comment. Drawings and records for the project are stored in a rented storage
facility in Anchorage. It is important that these records be preserved and transferred
to the new project owners upon completion of the transfer of ownership.
4.4.34 Conclusions
Table 4-3 lists the major project equipment, and provides an assessment of the condi-
tion of each item, its service life, and expected replacement cost of each item.
All structural components are considered to be in fair to good shape and, with appro-
priate maintenance and remedial measures, are expected to perform well beyond the
remaining 39 years of the nominal 50 year life of the project.
An estimated disbursement schedule for general project improvements and replace-
ments due to normal wear and tear is presented in Table 4-4.
There are a number of special topics that merit consideration for future repair and
maintenance work. These are:
• remedial work at the main dam spillway,
• the difficulties associated with the intake,
• rockfalls in the Falls Creek diversion tunnel and shaft, and
• sand and sediment, originating primarily from the Rolling Rock diversion.
It has been suggested that these items mentioned above are deficient in design. As a
conclusion of this study, none of these can be considered design deficiencies, because
960208
7176/G 22028TERR.WP 4-33
(a) it appears that design and construction of the major project features was done in
accordance with acceptable practices and standards, and (b) there does not appear to
be any of the specific unknown events and conditions mentioned above which could
be reasonably foreseen at the time of design. Even if there were evidence that such
conditions could be reasonably foreseen, it is not known what circumstances were
involved in making decisions regarding the implementation of various features. Own-
ers and engineers must often make difficult decisions about accepting risks and work-
ing within funding limits. The engineer is responsible for informing the owner of the
possible risks and associated costs. The owner must make decisions about implemen-
tation. To make determinations on whether the problems mentioned above are actually
"design deficiencies," much more investigation of the design computations and con-
struction records would be required.
960208
7176/G 22028TERR. WP 4-34
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Table4-3
Page 1 of 2
TERROR LAKE PROJECT • EXPECTED SERVICE LIFE AND REPLACEMENT COSTS
(where applicable, replacement costs are for both generating units)
Expected Remaining 1995 Price Level
Item Condition Service Life Service Life Replacement Cost
(yearsl, (years) ($)
(see note a)
Equipment
Turbine and Other Mechanical Items
Runner Fair 50 39 800,000
Needle and Nozzle Fair 50 39 40,000
Remaining Turbine Parts Good 50 39 2,740,000
Governor Good 50 39 300,000
Spherical Inlet Valve Good 50 39 180,000
Intake Gate 25 14 100,000
Penstock Butterfly Valve Good 50 39 350,000
Cooling Water System Fair 25 14 79,000
Other Aux Mechanical Equip Good 35 24 213,000
Generator
Stator Excellent 25 14 1,000,000
Rotor Excellent 35 24 300,000
Bearings Good 30 19 400,000
Cooling System Poor 30 3 150,000
RTDs, Sensing Devices Good 30 19 7,000
Fire Protection Good 35 24 5,000
Excitation System Good 25 14 200,000
Electrical System
Battery and Chargers Good 25 14 100,000
Controls and Protective Relaying Good 25 14 180,000
Station Service Excellent 30 19 270,000
15-kV Switchgear Good 25 14 100,000
Cable System Good 50 39 250,000
SCADA System Excellent 15 13 c 450,000
RTU's Poor 20 3 100,000
Communications
Microwave Excellent 15 13 c 150,000
PLC Poor 15 3 c 120,000
Emergency Generator Excellent 30 19 200,000
Gatehouse Generator d 15 4 25,000
Intake Gate Electrical Controls Poor 20 3 b 20,000
Polyjet Valve d 20 9 400,000
Release Water Generator d 10 20,000
Switchyard, Transmission Line and Substation Equipment
Switchyard at Powerhouse
Transformers Good 30 19 430,000
Circuit Breakers Good 25 14 76,000
Disconnect Switches Good 35 24 48,000
PTs, CTs, Wave Traps Good 30 19 100,000
Bus Structures Good 40 29 100,000
All Other Good 35 24 200,000
Transmission Line
Insulators Good 30 19 328,721
Hardware Good 60 49 547,868
Conductors Good 30 19 2,556,717
Structures Good so 69 3,917,256
Foundations Good 80 69 5,104,303
Table 4-3
Page 2 of2
TERROR LAKE PROJECT • EXPECTED SERVICE LIFE AND REPLACEMENT COSTS
(where applicable, replacement costs are for both generating units)
Item
Airport Substation
Circuit Breakers
Disconnect Switches
PTs, CTs, Wave Traps
Bus Structures
All Other
Swampy Acres Substation
Transformers
Circuit Breakers
Disconnect Switches
PTs, CTs, Wave Traps
Bus Structures
All Other
Rolling Stock
Front-End Loader
Bulldozer (D-8)
Dump Truck
Backhoe
Road Grader
Four Pickup Trucks
2o-Ton Trailer
Infrastructure
Housing
Storage and Other
Docks
Notes:
Condition
Good
Good
Good
Good
Good
Good
Good
Good
Good
Good
Good
Good
Poor
Poor
Good
Good
Fair
Fair
Fair
Fair
Fair
Expected Remaining
Service Life Service Life
<t!!:i (years)
(see note a)
25 14
35 24
30 19
40 29
35 24
30 19
25 14
35 24
30 19
40 29
35 24
10 6
10 2
15 2
10 6
15 5
10 2
10 2
30 18
30 18
15 3
a Plant was essentially completed in December 1984, and entered commercial service on April 1, 1985.
Actual in-service time is about 11 years.
b Indicates that remaining life is less than expected.
c Indicates system that was replaced or modified since original construction.
d Not inspected
~,,
1995 Price Level
Replacement Cost
($)
152,000
60,000
50,000
70,000
180,000
550,000
220,000
100,000
150,000
300,000
500,000
240,000
200,000
100,000
100,000
220,000
100,000
50,000
450,000
525,000
75,000
•
•
•
1
Table 4-4
Pagel o!3
TERROR LAKE PROJECT· PROJECTED MOST LIKELY REPAIR AND REPLACEMENT COSTS
(in US_,. at 1995 price levels, exctu(jng repai" or replacements due to not .. et events, accidents or equipment faiU'"')
Oepreciati011 Oepreciati011
Used Awllable
S.ruct\J'e 1996-2000 2001.()5 2006-10 2011-15 2016-20 2021-25 2026-30 Next Replacemeff Thro!Jg!\2030 After2030
Reme<tat Wori< for Hems of Deficient Dfli!Jl
None
Remedial Wori< FO< Hems of Deferred Maintenance
None
O!hef PTojed Improvements
Slrud ... s
Repair main dam spit.vay 950,000
Repair intake gate 500,000
Rocktrap weir et ertrance to iA:ake of IQw-levei ol.llet wonts 40,000
Prepare emergency response plan for t\Rlet rocttfal a
Rebuild Silo!~ Creek cU\Iert 135,000
Add riprap to intake wing wei ot F ah Creek Divenlon 20,000
Ewluote stabilty of betm s~lng access road to the inake 20,000
Engineenng 51\ldy of Fob creek llnlel callity 80,000
Prepare bid doe\J"f'\ent for Fals Creek repairs 100,000
Repair Fals Creek ttmel caW)! and Invert 785,000
Engineering review of Rolng Rock dverslon system 50,000
MonH:OC' and define ch:inage characteristic! of slope ~I
OfpOW!I1tlouH
Construct permaneni!Weflnlining dike 200,000
Chamelze creek aqacent to -chyard and pro\Ade riprap 50,000
ProCect transmission towef fO\.Jlde:t•ons 50,000
Replacelirrber tendering on jerty 50,000
COft1llo!e se<tment discharge system 1,300,000
Equipment
Replace polyjet wtvo operalO< and other l~s 40,000
Acoustic flow meter for penstock wiYe ovef'V'elocity dostl'e 15,000
Replace governO< PMG .,;II\ SSG 30,000
Replace cooing waler ptrll)s 20,000
Replace gatvaniz'fd and iron ptptng f« cooling, potable water,
and fire protection 20,000
Generator air coolers (fOU") 16,000
Aliomatic synclvorizer 20,000
ROblece Unit 2 colectO< ring 6,000
Intake gate eledricai cortrois 20,000
Replace power lne carrier 120,000
SWilchyard, Tn1nomission Uno, and Sttlstation Equipment
Obtain interim report of transmission tower pole corrosion
tnvestiga1e modification lo conductor to prevert flashover
EvakRite the use of c~osite irrsutetor on transmission ~ne
t~ify and remove danger trees on transmission ROW
Avalanche study !0< 11\e transmission lne ROW 40,000
Undergrot.rld cable study 30,000
Insulator userrbies cmemination tests 25,000
Heavy lft heicopter ser\Ace in ..,;nter study 10,000
Emergency Action Plan fOf tower loss 50,000
Port lions regulator and bus wortc 150,000
Relocate ~arm attactment instal ad<:ltional stnt 150,000
Add 00 recovery fadities budgeted
C~ete As-Buil Ora..;ngs 20,000
Acquire fotktft 40,000
Ac~re one-ton fl'lOW&ble hoist for mactine shop 5,000
Replacements due to Normal Wear and Tear
Structtxes
fals Creek Spihay Maintenance 30,000 30000 30.000 30,000 1 Q..yeat cycle
Roling Rock Creek Diversion-re~er dearing 25,000 25,000 25.000 25,000 25,000 25,000 25,000 5-year cycle
Patnl Trastvacks at Fats Cre8 5,000 5.000 5,000 5,000 10--year cycle
Paint Lower Penstock Invert 30,000 30.000 30,000 30,000 1G-year cycle
Archttectt.nl Refl.l'bishmert 200,000 2045
Pam! Upper Penstock lntefiO< 25,000 25.000 25,000 25.000 10-year cycle
Table 4-4
Page 2 ofl
TERROR LAKE PROJECT· PROJECTED MOST LIKELY REPAIR AND REPLACEMENT COSTS
(in US dolars al1995 price levels, exckJding repairs or replacemerts due to nallJ'BI evenl:s, acciderts or eqlipmert faiUes}
Depreciation Depreciation
Used Available
structl.l'"e 199&-2000 2001-05 200&-10 2011-15 201&-20 2021-25 202&-30 Nex1 Replacemenl Tlrougll2030 After 2030
Eqlipment
Tll'bine and Other Mechanical Items
Tll'bine (n.n1er, nozzle and neecle) 2034 3,293,600 286,400
Governor 2034 276,000 24,000
Inlet Valve 2034 165,600 14,400
lrtake Gate 100,000 2034 84,000 16,000
Penstock Valve 2034 322,000 28,000
Cooing Wa1er System 79,000 2046 28,440 50,560
other Auxihry Mechanical Eqlipmert 213,000 2054 66,943 146,057
Generator
S1ator (Coils) 1,000,000 2034 840,000 160,000
Rotor 300,000 2054 94,286 205,714
Bearings 400,000 2044 213,333 186,667
Cooing System 150,000 2058 10,000 140,000
RTDs, Sensing Devices 7,000 2044 3,733 3,267
Fire Protection 5,000 Check C02 gas amualy, 2054 1,571 3,429
Excitation System 200,000 2034 168,000 32,000
Electrical System
Battery and Chargers 100,000 2034 84,000 16,000
Cortrols and Protective Relaying 180,000 2034 151,200 28,800
Station Service 270,000 2044 144,000 126,000
15-kV Switchgear 100,000 2034 84,000 16,000
Cable System 2033 235,000 15,000
Intake Gate Electncal Controls (1) 20.000 2038 12,000 8.000
SCADA System 450,000 450,000 2038 210,000 240,000
RTUs 100,000 100,000 2038 60,000 40,000
Cortln'l\rications
Microwave 150,000 150,000 2038 70,000 80,000
PLC 120,000 120,000 2043 16,000 104,000
Emergency Generator 200,000 2060 200,000
Gatehouse Generator 25,000 25,000 25,000 2044 1,667 23,333
PoMet Valve 400,000 400,000 2044 120,000 280,000
Release Water Generator 20,000 20,000 20,000 20,000 2036 8,000 12,000
Switchyard. Transmission Line and SLtlstation Equipmenl
Powerflouse Switchyard
Transformers 430,000 2044 229,333 200,667
Circuit Breakers 76,000 2034 63,840 12,160
Oiscomect Switches 48,000 2054 15,086 32,914
PTs, CTs, Wave Traps 100,000 2044 53,333 46,667
Bus Struct11es 100,000 2064 15,000 85,000
.AI others 200.000 2054 62,857 137,143
Transmission Une
lns~Jators 328,721 2044 175,318 153,403
Hard'-Nare 2044 420,032 127.836
Conductors 2,556,717 2044 1,363,582 1,193.135
StructrJes 2064 2,252,422 1.664.834
Foundations 2064 2,934,974 2.169,329
Airport SLtlstation
Transformers (none considered)
Circuit Breakers 152,000 2034 127,680 24,320
Oiscomect S'Nttches 60 000 2054 18,857 41.143
PTs. CTs. Wave Traps 50.000 2044 26.667 23.333
Bus StructrJes 70,000 2064 10,500 59,500
.AI other 180 000 2054 56,571 123,Q9
......
Tablo4-4
Page3of3
TERROR LAKE PROJECT· PROJECTED MOST LtKEL Y REPAIR AND REPLACEMENT COSTS
(in US dolan at 1995 price levels, exc1uding repairs Of replacements due to Rl!ttl'at everts, accidents or ecppment faDes)
Struct!J'e
~Y Acres Substation
TransfOfmet'S
Clrctit Breakero
Discomee! s..;tches
PH, CTs, Wave T111ps
Bus Struc:IU"es
Al~er
RolngStock
FroN~End loader
8\.tdozer (0-8)
Dtrnp Truck
Backhoe
Road Grader
FOU" Pickup Trucks
2(). Ton Trailer
FO!l<lin
lnfrastructtr'e
HoU$ing
Storage and Other
Docks
S.YR TOTALS
Remed'l:ll Work for Items of Deficient Destgn
Remedial Wor11: for ttems of Deferred MainteMnce
Other Projecii~T¥lfovements
Reptecemenls due to Normal Wear and Tear
Alowances For Replacements After 2030 (3)
LEVELIZED PAYMENT ANALYSIS
Replacements due to Normal Wear and Tear (4)
Segiming of Period Food Batance
Annual C~ributloti of $606. 11-' to Reserve Ftr~d
Expense
Interest on Average Fl6ld Balance
End of Period Fund Balance
Allowances for Replacements after 2030 (5)
Beginning of Period Ftnd Balance
Amu&l Contribution of $156,939 to Reserve Fund
Expense
l~efe~ on Average Ftnd Balance
End of Period F tnd Balance
1996'2000
200,000
100,000
100.000
50.000
75.000
5,207,000
785,000
245,959
3,030,568
(833,048)
432,028
2.629,548
784.695
(261,116)
102,850
626,429
2001-05 2006'10
220.000
240,000
200,000
100.000
220,000
100,000
50,000
40.000
985,000 3.253,000
245,959 297.056
2.629 5<18 5.766.116
3.030,568 3,030,568
(1 .154.084) (4.208,102)
1,260,086 1.737,588
5,766.118 6.326,172
626.429 1,432.329
784,695 784,695
(268.293) (387,069)
309.498 572.177
1.432.329 2.402,132
2011-15 2016'20 2021·25 202&30
550,000
100,000
150,000
300,000
500,000
240,000 240,000
200,000 200,000
100,000 100,000
100,000 100,000
220,000
100,000 100,000
50,000 50,000
b 40,000 b 40,000
450,000
525,000
75,000 75,000
6.702,438 2,471,000 1,914,000 1,195,000
622.556 1,085,922 1.353.530 1,705,657
6.326.172 674,268 (161.780) (634,406)
3.030,568 3,030,558 3,030,568 3,030,568
(9,572,732) {3,896.518) (3,332,320) (2,297,007)
890.259 29,902 (170,874) (99,096)
674,268 (161,780) (634,400) 0
2,402,132 3,106.265 3,056,594 2,211.514
784,695 784,595 784,695 784,695
{895,926) (1,714,992) (2,381,324) (3.285,736)
815.365 880,626 751,549 289,527
3,106,265 3,056,594 2,211,5H (0)
a ln!i:cates that the cost for this item is asstmed to be incku.1ed as a part of the normal operat1ons budget and !he reQUired activities can be carried out by plant personn~ es part of day-to-day activities.
b lncl:cates an item that is contingen: on i~ation of • recommended project irnpl'ovement
{1) Upgrade included in project in'4)fovemonls
{2) Reconvnend larger emergency generator
(3) Cok:l.iated in 1995$, using a 4°4 real diS<OU"It 111te
(4) Analysis ustrnes a 2% escalation rete, a 6% interest rate on availa~e flllds, e 8% borrowing rete. and one kwnp $urn paymm in the midcle of the five-year period
(5) Anatysis asSl.ITies a 2% escalation rate, a 6~ interest rete on ave«ab4e foods, 1!1 6% borrO'fMg rete. end beginning of yeer payments to replacement ft11ds.
~ '-\ \
~{~
~ l \3 ( ;')
l/ 1&
3 c_,
~
._::) ~\
b
Depredation
Used
Next Replacemonl Th:ougl\2030
2044 293.333
2034 184,800
2054 31,429
2044 80,000
2064 45,000
2054 157,143
Replacement every 10 years. 215,000
Replacement every 10 years. 60,000
Replacemonlevery 15 years 20,000
Replacernonl every 10 years. 90,000
Replacement every 15 years 205,333
Replacernonl every 10 years 30,000
Replac-every 10 years. 15,000
Rep4a:c:emed every 10 years. 16,000
2044 255,000
20U 297,500
2044 10,000
DEPRECIATION TOTALS" 16,595,965
-7~~
cl '\
<~~~ 5
61uL
& \\_ l \
\ c\ t "i
Depredation
A\lllltable
Aner 2030
256,667
35,200
68,571
70,000
255,000
342,857
24,000
140,000
80,000
10.000
14,667
70,000
35,000
24,000
195,000
227,500
65,000
10,493.900
-~ -D ~ \l
.. \ \
.------···~~-·----···
[ -Generating Discharge =Release to Terror Riller -Lake level ...... Powerplanl Hydraulic Capacity
400 1,600
375 1,500
350 1,400
375 1,300
300 1,200
275 1,100
250 1,000
600 i •
225
"i'
r-~
600 ....
i
700 :e
u
-200 !
175
----· ~ -
~ -~---~ -1-r--r---n
150 -1-1-~ I~ 600
175 r--~ 1-1-500
400 100 1-1-~
_ .. -
75 1-1-,_ -300
50 1--200
100 75 1---1---1--1-1--1---1---1----
-+
A • 0 N D M A M A • o N 0 M A Ill .t .. 0 N D M A II J A 0 N D
1993
Figure 4-1 Terror Lake Project-Measured Historical Flows and Lake Levels
------. --I
I L----
" -
Figure 4-3 Terror Lake Project· Transmission Structure· Terror Lake to Airport Substation
Figure 4--4 Terror Lake Project· Relocation of Transmission Structure Top Arm Insulator Assembly-Terror
Lake to Airport Substation
Chapter 5
Tyee Lake
Chapter 5
TYEE LAKE
5.1 Project Description
This project is located approximately 40 miles southwest of Wrangell, Alaska. The
project water supply is Tyee Lake, a natural lake. There is no dam. This project
includes a "lake tap" intake, a vertical shaft, an unlined tunnel, and a steel penstock to
convey water to the two-unit surface type powerhouse. The project also includes 70.5
and miles of overhead transmission line, 11.4 miles of submarine cable, a powerhouse
and switchyard, the Wrangell Switchyard and substation, and the Petersburg substation.
The project general arrangement and sections of major project features are illustrated
on the project drawings included in Appendix B. Table 5-1 presents pertinent project
data.
The project was originated by the Thomas Bay Power Authority (TBPA) a joint ven-
ture created by the cities of Wrangell and Petersburg. The Alaska Power Authority
(now known as the Alaska Energy Authority, or AEA) designed and constructed the
project. Construction started in 1981, and the project went into commercial service on
May 9, 1984. The project is operated by TBPA under an agreement with AEA.
The Tyee powerhouse has two generating units with provisions for installation of a
third unit. The turbines are vertical-shaft, 6-jet, single-runner, Pelton type, designed to
operate at 720 rpm. The two generators are each rated at 12.5 MV A. The turbines
were manufactured by Sulzer Escher-Wyss and the generators by Meidensha Electric.
Access to the project is by boat or plane only. There is a gravel landing strip for
small planes near the powerhouse area. There is a helicopter landing pad adjacent to
the power tunnel intake gatehouse, located on the shore of Tyee Lake, but no vehicle
access to this structure.
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Table 5-1
TYEE LAKE PROJECT -SIGNIFICANT DATA
RESERVOIR
Normal Maximum Pool Elevation
Normal Minimum Pool Elevation
Maximum Active Storage
Drainage Area
DAM AND SPILLWAY
None
POWER TUNNEL AND SHAFT
Lining
Length
Diameter
PENSTOCK (inside lower tunnel)
Number
Length
Diameter
Type
EQUIPMENT
Nominal Plant Generating Capacity
Number of Units
Type of Turbines
Maximum Gross Head
Turbine Power Output (each, at 1,306 ft net head)
Generator Rating (each)
Speed
TRANSMISSION LINE
Length
Voltage
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7176/G 2028TYEE.WP 5-2
1,396 ft
1,250 ft
52,400 ac-ft
14.2 sq mi
Unlined
8,300 ft
lOft
1
1,350 ft
54 inches
Steel
22.5 MW at 90 percent power factor
2
Vertical shaft Pelton
1,367 ft
16,700 hp
12.5 MVA
720 rpm
70.5 mi overhead
11.4 mi submarine (four crossings)
138 kV operated at 69 kV
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5.2 Installed Capacity and Energy Generation
5.2.1 Monthly Flows
The AEA estimates monthly quantities of water diverted from Tyee Lake for power
generation. For this study, monthly estimates were only readily available for 1994.
These readily available estimates are included in Appendix B.
Monthly Tyee Lake inflows were estimated for use in assessing the generation poten-
tial of the project. There are no long term records of either the lake levels or flow
the outlet from Tyee Lake. To estimate the natural lake inflow, recorded flow data
from the nearby Harding River was used. A U.S. Geological Survey (USGS)
streamflow gaging station is located one mile upstream from the mouth of the Harding
River, on the opposite shore (from Tyee Lake) of Bradfield Canal. The Harding River
gage appears to measure runoff from a basin that has topographic and hydrologic
characteristics similar to the Tyee River. Natural flows into Tyee Lake were estimated
by transposing 1 recorded flow data from the Harding River gage using drainage area
ratios.
The estimated drainage area of the Tyee Lake basin is 14.2 square miles, and the
drainage area of the basin above the Harding River gage is 67.4 square miles. Re-
corded flows at Harding were multiplied by a factor of 0.21 to arrive at estimated
Tyee Lake inflows. The resulting sequence for a recent historical period is shown on
Figure 5-1.
The estimated average lake inflow is approximately 157 cfs. This average is calculat-
ed from the data illustrated on Figure 5-1. The maximum powerplant discharge capac-
ity is approximately 274 cfs. The average historical flow for the period analyzed is
about 57 percent of the hydraulic capacity of the plant.
Streamflow transposition entails the multiplication of a series of streamflow measure-
ments by a factor to obtain an estimated record for an ungaged location. The factor is
usually the ratio of the ungaged drainage area to the gaged drainage area, but may
contain adjustments for other factors. In this case, the transposition factor is based on
the drainage areas only.
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5.2.2 Existing Generation Potential
The plant has two units, with a combined total installed capacity of 25 MV A. At a
power factor of 90 percent, the maximum nominal power output of the plant is 22.5
MW.
Based on data for the 10 most recent fiscal operating years (period ending June 30,
1995) the historical average annual generation has been about 33.1 GWh. In the last
three years, average production averaged 42.5 GWh per year. Historical production,
as furnished by AEA, is listed in Table 5-2.
Table 5-2
TYEE LAKE PROJECT -ANNUAL GENERATION
Year Ending Actual (kWh)
6/30/86 19,935,120
6/30/87 32,837,466
6/30/88 33,802,000
6/30/89 19,594,000
6/30/90 19,311,000
6/30/91 41,476,000
6/30/92 36,579,000
6/30/93 40,997,000
6/30/94 39,516,000
6/30/95 47,097,000
Total 331,144,586
Average
10 years 33.114,459
Last 3 years 42,536,667
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Based on the limited flow data gathered for this study, a preliminary estimate of the
energy generation potential of the existing project is 109.1 GWh per year, assuming
that all of the available energy could be utilized. The total annual energy production
appears to be trending upward, but there is obviously a large difference between the
energy output, which is limited by the demand, and potential generation.
5.2.3 Effects of Drought
The potential impact of drought on energy generation can be investigated by analyzing
the long-term streamflow. The actual streamflow and release data available for the
plant is too short to draw defmite conclusions about the impact of drought. However,
it is possible to infer the magnitude of the reduction in generation that might occur in
water-short years by investigating the characteristics of streamflow in nearby rivers
that have long-term streamflow records.
The Harding River gage mentioned above has a 42-year streamflow record. Total an-
nual flow for each year was tabulated, and the distribution of years with lower than
average flow are indicated below:
Number of years with annual flows that are:
less than 80 percent of average flow
between 80 and 85 percent of average flow
between 85 and 90 percent of average flow
between 90 and 95 percent of average flow
between 95 and 100 percent of average flow
above 100 percent of average flow
1 out of 42 years
2 out of 42 years
4 out of 42 years
8 out of 42 years
8 out of 42 years
19 out of 42 years
Because of its preliminary nature, the above analysis is not conclusive. However, it
can be inferred that 2.5 percent of the time, the annual generation might be 20 percent
less than average. A detailed hydrologic analysis is required to provide more defini-
tion of the characteristics of generation under drought conditions.
5.2.3 Potential for Expansion
Like Terror Lake, the Tyee Lake powerhouse was designed and built to accommodate
the possibility of future expansion of the generating capacity. However, the demand
in the area is limited, and the generating capacity of the existing project is not fully
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utilized. There have been studies carried out considering interconnection of the plant
with other load centers. Unless interconnection is found to be an attractive possibility,
expansion of the generating capacity is probably not warranted at this time.
There does appear to be sufficient streamflow, so that at some time in the future,
additional generation capacity could be installed with some increase in the energy
output. A time series of estimated Tyee Lake monthly inflows was derived from the
Harding River gage as described previously. Figure 5-1 shows the estimated lake
inflow, for the period from 1985 through 1993, as shown in Figure 5-1. Also shown
in the figure is the hydraulic capacity of the powerplant.
It is evident from Figure 5-1 that some additional energy may be generated with addi-
tional production capacity, especially in months when the average inflow exceeds the
hydraulic capacity of the plant. A third unit with a rating of 12.5 MV A (identical to
the existing units) could increase the average annual output potential by about 10.5
GWh per year.
In view of current power and energy demands in relation to the existing plant produc-
tion capacity, however, the installation of additional generating capacity is certainly
not warranted.
At some time in the future, the demand will probably grow, or the interconnection
with other load centers may be implemented, and the installation of additional generat-
ing capacity may be appropriate. At Tyee Lake, the cost to add a 12.5-MVA unit in
the empty bay in the powerhouse, including the cost of turbine, governor, inlet valve,
generator, exciter, and ancillary equipment; is expected to amount to about $5.6 mil-
lion, or about $560 per kW. This cost is competitive with alternative forms of peak-
ing generation.
5.3 Generating Unit and Transmission System Availability
Data furnished for analyzing the availability of the plant is presented in Appendix B.
The data includes a list of outage events from January 1, 1992. This data, however,
does not provide duration of outages, and therefore, an analysis of the average dura-
tion of outages was not possible.
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In addition, plant operation personnel were interviewed. FERC annual operation re-
ports, and reports by various engineering firms that have been hired to assess the con-
dition of the transmission line, were reviewed.
5.3.1 Generating Unit Availability
Two FERC operation reports for the periods July 21, 1988 through August 14, 1990
(two-year period) and August 15, 1990 to June 29, 1993 (three-year period) reported
no outage events.
Other than the outages related to the transmission system described below, no unusual
circumstances affecting generator unit availability are known to exist.
5.3.2 Transmission System Availability
The transmission line is a frequent cause of plant outage. The conditions associated
with the frequent outages are described in the following sections. A significant cause
of line outages is linked to ice and snow loads and the unloading of ice and snow
build-up on the lines. Transmission line design deficiencies cause ground clearance
problems during snow and ice conditions which result in frequent outages and inter-
ruptions.
5.4 Condition Assessment, Recommendations, and Costs
The following section describes the Tyee Lake Project condition assessment and rec-
ommendations for replacements and improvements. At the conclusion of this section,
the costs for recommended improvements and replacements are summarized in tabular
form.
5.4.1 Site Inspection Dates
Two teams visited the project facilities during the period of October 16 through Octo-
ber 20. The first team performed the transmission line, civil, and structural inspection;
the second team performed the electrical and mechanical inspection.
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The project was inspected by N. Pansic and A. Angelos of Harza on October 16 and
17, 1995. N. Pansic inspected the civil and structural components, and A. Angelos
inspected the transmission and substation facilities. The inspection on October 16
consisted of a helicopter fly-over of the project, concentrating on the gatehouse, reser-
voir rim and the transmission and substation facilities.
N. Pansic was accompanied on October 16 by Carl Thrift, TBPA Foreman, and Remy
G. Williams, AEA Consultant, and on October 17, by Dennis Lewis, Petersburg Mu-
nicipal Light and Power Electrical Supervisor, Dan Koszuta, City of Petersburg Engi-
neer, Carl Thrift and Remy G. Williams. N. Pansic's inspection activities on October
16 primarily consisted of the aerial reconnaissance to evaluate the potential for land-
slide or avalanche risks to the project structures. The inspection on October 17 was
done on foot, concentrating on the powerhouse, penstock, and related project facilities.
On October 16, A. Angelos inspected the Petersburg substation and flew along the
transmission line to Tyee powerhouse. He was accompanied by Remy Williams and
Dennis Lewis. On October 17, A. Angelos inspected the Wrangell substation, and
Wrangell switchyard, accompanied by Robert Cooley of TBP A.
On October 18 and 19, 1995, J.H.T. Sun and J.J. Quinn of Harza and Stan
Sieczkowski of AEA inspected the Tyee facilities with Carl Thrift. On October 18,
1995, Dick Olson of TBPA accompanied the tour.
On October 20, Robert Cooley of TBPA conducted a tour of the Wrangell control
center, Wrangell substation and Wrangell switchyard for Sun, Quinn and Sieczkowski.
A list of documents reviewed as part of this inspection and evaluation is provided in
Appendix A. Selected photos taken during the inspection are provided in Appendix C.
5.4.2 Reservoir
Condition Assessment. The valley walls surrounding the reservoir are steep to moder-
ately steep, with spruce trees being the dominant vegetation. However, since the res-
ervoir is a natural lake, and there is no dam at the project, the consequences of any
avalanche or landslide would likely be negligible. The gatehouse is located on the
north shore of the lake, about 50 feet above the reservoir. The gatehouse is not likely
to be affected by landslide-induced waves.
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Under normal operating conditions, the level of Tyee Lake is below its natural outlet.
During these times, the lake level cannot be accurately measured for operational pur-
poses. Plant personnel estimate lake level based on the penstock operating pressure.
5.4.3 Gatehouse
Condition Assessment. Access to the power tunnel gatehouse is by helicopter only,
with a helipad located adjacent to the gatehouse. The gatehouse is a pre-engineered
metal superstructure and is located on the top of the gate shaft. The gatehouse was
inspected from the operating floor only. No inspection of the gate shaft or gate was
made. The gate is a 9 foot wide by 11 foot high slide gate with a hydraulic operator.
It is normally in the open position. Electrical power for gate operation is provided by
a propane generator located outside and adjacent to the gatehouse. The generator is
enclosed in an old transportation container. Neither the generator nor the gate were
test-operated as part of the inspection.
The operation personnel reported that the gate operator hydraulic cylinder and the
electrical controls were rebuilt last year. The hydraulic cylinder and its power unit are
located some 200 feet down the shaft. The location of the hydraulic cylinder caused
accelerated corrosion, leading to the cylinder rebuild. The gatehouse is not normally
heated, potentially contributing to the corrosion of sensitive equipment. Future mois-
ture-related problems with electrical controls in the gatehouse are also expected.
There is no low-cost method to control the moisture in the gatehouse and gate shaft.
Therefore, the electric controls will require replacement periodically, every 15 to 20
years, due to corrosion.
There is no communications or control links from the powerhouse to the gatehouse,
hence gate closure can be done only at the gatehouse. Also, the high ridge between
the powerhouse and gatehouse reportedly complicates the radio communication.
The slope adjacent to the gatehouse is steep and forested. While avalanche, landslide,
and tree falls are potential hazards, only the gatehouse superstructure would likely be
damaged. Even so, the heavy steel framing necessary for bulkhead and gate-removal
hoisting is likely more than adequate to resist expected avalanche loads. It is unlikely
that the gate or its hydraulic operator would malfunction or be damaged as a result of
any of these occurrences.
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The primary concern with the gatehouse is the lack of access and communications.
The original project plans called for a system to initiate an emergency closure of the
gate from the powerhouse control room. As this communication link was never in-
stalled, the time required to effect an emergency closure of the gate, if required, would
be quite long --depending on the availability of a helicopter from Wrangell or Peters-
burg and weather conditions. Also, coordination of such an operation would be diffi-
cult due to the communications limitations. In general, the poor access is not condu-
cive to good maintenance and operational practices, and this could be a factor in some
future outage or emergency scenario. The inspection for this study was the first time
TBP A personnel had been to the gatehouse in a year.
Recommendation. The intake gate latching mechanism should be modified and electri-
cal controls and communication links added to provide remote operation.
5.4.4 Tunnel and Penstock
Condition Assessment. The penstock was inspected from the access tunnel, entering at
the portal located east of the powerhouse and walking from the roll-out section all the
way up to the concrete plug. A minor rock slide was noted at Station 11 +00, as well
as corrosion of the steel penstock just upstream of Dresser coupling C. All of the
penstock supports appeared to be in good condition. The inside of the penstock has
not been inspected since original construction. Seepage through the plug is measured
by a weir, which has been reading a steady flow of 7 gpm. This small amount of
seepage is acceptable. Monitoring of the leakage should be continued.
The power tunnel was not inspected, as the project was operating. The tunnel was
reportedly dewatered shortly after initial construction, and a 15 cubic yard rock fall
occurred. This rockfall was reportedly removed. The tunnel and shaft were construct-
ed using rockbolts; and concrete lining and drain holes were installed where required.
Recommendation. The potential exists for future rockfalls in the tunnel during an
unwatering or during an earthquake. The tunnel should be inspected with a remote
operated vehicle (ROY). Such an inspection could be performed from the gate shaft
to the rock trap (a total distance of 7,500 ft). Continuous sonar imaging can be used
to determine the dimensions of the tunnel along its entire length. It is recommended
that a ROY inspection be carried out in the next five years to verify the internal geom-
etry and investigate the presence of rockfalls which may have occurred.
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5.4.5 Powerhouse
Condition Assessment. The powerhouse is constructed against the base of a steep rock
face. The upstream wall of the powerhouse is the rock face, with shotcreting and
rockbolting of the face for stability. The powerhouse is a steel frame superstructure
with a reinforced concrete substructure, founded on rock.
Some risk of damage to the powerhouse structure from snow avalanches or rockfalls
exists. However, there have been no incidents to date. According to the September 1,
I 993 FERC Operation Report, a 1,600 cubic yard debris slide occurred near the boat
dock, destroying an equipment shed. Most of the structures near the powerhouse are
at some risk. Future occurrences could impact one of the following structures:
• maintenance building,
• warehouse,
• housing, or
• the powerhouse.
The primary concern is the powerhouse. Regular inspection of the slopes above all
the structures at risk is recommended to provide an indication of impending or poten-
tial incidents.
The inspection began at the upper powerhouse level against the back (rock) wall.
Minor leakage, some due to rainwater and some due to seepage through the shotcrete
and anchors, was noted in several places. The seepage through the rock face appeared
to be greater on the east end of the powerhouse, as evidenced by moss growth and
rusting anchors, than at the west end. However, this leakage is still not of serious
concern. The exposed threads and nuts on several rock anchors were noted to be
heavily rusted. Over time, these anchors can be expected to continue to corrode until
they lose their design strength. It is likely that most, if not all, of the anchors will
need to be replaced at some time over the life of the project. The shotcrete will also
likely need replacement. Replacement of all these anchors and the shotcrete in a de-
fined future program is recommended.
The east wall of the powerhouse shows evidence of sustained leakage from the
roof/wall interface. Two areas were noted where water has leaked into the building
and stained the wall and columns. The water appears to leave a tar-like residue,
which reportedly has also shown up on the turbine surfaces. It is not known whether
this residue is corrosive or not. There is no access to the roof for maintenance. Ac-
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cess should be provided to the roof of the powerhouse for inspection and repair of
roof leaks.
Where the Unit 2 penstock penetrates the back wall of the powerhouse, evidence of
seepage through a horizontal lift joint exists (efflorescence, patching). It was dry at
the time of the inspection, as the unit was not operating. Although this is not a major
concern, the seepage through the joint should be considered a maintenance item.
On the other side of the penstock, a concrete cutout with exposed reinforcement was
noted. This reinforcement is corroded and continuously wet. This could lead to fur-
ther corrosion and spalling in the future. The corrosion on the reinforcing steel should
be removed and the cutout filled with concrete.
In general, the moist powerhouse environment, due to the exposed rockface on the
back wall of the powerhouse, creates the potential for malfunction of the electronic
controls and associated electrical systems. However, the majority of the electronic
equipment is in the control room which has a separate heating and ventilation system.
Separate heating and exhaust fans are located throughout the powerhouse. While the
potential for malfunction exists, most of the major electronic controls are protected
against malfunction. Minor electric equipment malfunctions may occur to other elec-
trical equipment in areas where humidity will remain high.
The substructure of the powerhouse was inspected at the generator floor and turbine
floor levels for evidence of settlement or structural problems. None were noted. One
crack was pointed out by operation personnel, but it is not structural.
The tailrace was inspected beneath Unit 2 by walking up from the exit area. The
concrete appeared to be in excellent condition, with some minor concrete erosion due
to the high velocity flow. Minor erosion in the turbine discharge pit will not affect
the turbine operation. Concrete patching is recommended during the next maintenance
outage.
A 350-kW Magna diesel generator provides emergency power to the controls.
exercised once a month.
Overall, the powerhouse appears to be maintained in excellent order.
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Recommendation. The following are recommended:
1. The back wall of the powerhouse is supported by rockbolts. Testing of about
15 to 20 anchors every 5 years is recommended to determine which anchors
have lost strength. Furthermore, installation of additional rockbolts on a
replacement schedule of about 10 to 15 per five-year period is recommended.
2. Access to the powerhouse roof should be installed, and roof leaks should be
fixed.
3. Regularly apply epoxy or otherwise control the seepage areas in the power-
house where the penstock enters the powerhouse.
4. Clean reinforcing steel and fill concrete cutout near penstock.
5. Patch up concrete in the draft tube during the next maintenance outage.
6. Architectural refurbishment should be anticipated after about 30 years of
service. (Year 2114).
5.4.6 Other Facilities
Condition Assessment. The following facilities were also toured and discussed with
Carl Thrift and Remy Williams:
Incinerator -fairly new, in excellent condition.
"Miracle Span" storage building -repair to the supporting structure is required.
Maintenance shop -the interior floor drainage is poor. A simple pseudostatic
earthquake analysis for this interior is required to evaluate the factor of safety for
earthquake loading. Some structural modifications are probably required to make
this section of the shop safe for earthquake loading.
Vehicle garage -pre-engineered metal building with open bays, no problems noted.
Housing -four prefabricated structures. The original three structures do not have
adequate foundation support, but the fourth, a newer structure, is adequate. The
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7176/G 2028TYEE.WP 5-13
foundations of the three buildings require shoring up with new concrete founda-
tions.
Boat dock -adequate, good condition.
Harbor -sediment discharges from the tributary rivers surrounding the upper end
of the Bradfield Canal have created tidal flats which inhibit boat access. Dredging
a 50-foot wide, 15-foot deep channel approximately 3500-feet long from the boat
dock to the west, terminating opposite the point where the transmission towers are
located, is recommended.
Gravel runway -approximately 3000 ft long, repaired in September 1994, in good
condition. Continued routine maintenance of the runway is required.
5.4.7 Turbines
Condition Assessment. The overall conditions of both Pelton turbines are considered to
be excellent. There are no obvious signs of cavitation and/or erosion on the stainless
steel runner reported. The needles, nozzles and deflectors are reported to be in good
operating condition. In 1994, Unit 2 needle servomotors and oil pressure control
piping were overhauled and the runner was checked by 100 percent dye penetrant
method with good results. One of the reasons for the overhaul was to correct water
leakage through the fittings of the oil control piping to the pressure oil system.
During the inspection, the plant operation personnel asked about water leakage into the
oil system. When the unit is operating at speed-no-load or at part-load with a small
needle opening, the water pressure inside the nozzle will be almost equal to the maxi-
mum headwater pressure (approx. 650 psi), and the oil pressure in the needle servomo-
tor control system is approximately 500 psi. The oil pressure in the needle servomotor
control system is smaller than the maximum water pressure of 650 psi, therefore,
possibly allowing for water leakage into the oil system if the seals around the oil pipe
fittings are not in good condition. If water is found in the governor pressure oil sys-
tem, the oil piping seals in the needle servomotor should be checked.
The Unit 2 turbine guide bearing was inspected and overhauled in 1994. A similar
overhaul on Unit 1 needle servomotors and guide bearing is scheduled in the near
future.
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Turbine capacity tests on both Units 1 and 2 were perfonned in 1984. The results
indicated that the outputs exceeded the expected turbine perfonnance at the minimum,
rated, and maximum net heads for both units. Based on the expected turbine perfor-
mance cur;es and current turbine conditions, the estimated turbine output is 13,800 hp
(10.3 MW) under a net head of 1,150 ft, 16,700 hp (12.5 MW) under a net head of
1,306 ft, and 17,800 hp (13.3 MW) under a net head of 1,364 ft.
Each turbine can deliver a full rated load to the generator when the net head on the
turbine exceeds 1 ,306 ft.
Based on the expected turbine perfonnance curves, the turbine has a peak efficiency at
50 percent needle opening near the rated net head of 1 ,306 ft. The best efficiency
operating range is from approximately 40 to 70 percent needle opening for all operat-
ing net heads. The Tyee powerhouse does not have a needle position indicator either
in the control room or in the turbine pit. It is desirable to have a needle position
indicator so that the operating personnel can verify if the unit is operating in the best
efficiency zone.
The turbine runner centerline is set at El. 29 ft above mean sea level and the nonnal
maximum water surface in the runner chamber with turbine at full discharge is El. 24
ft. Therefore, the tailwater will not interfere with the turbine runner under nonnal
conditions.
5.4.8 Generators
Condition Assessment. The generators are classified as .. suspended types" with com-
bined thrust and guide bearings located above the rotor and a guide bearing located
below the rotor. Other major features include a self-ventilated cooling system where
cooling air is circulated in a closed loop through air-to-water heat exchangers located
within the housing and air brake system. The air brake system is capable of stopping
the unit from one-half the rated speed within seven minutes.
Unit 2 was generating with an output of approximately 7.6 MW at the time of the
inspection on October 18, 1995. This output from Unit 2 represents 61 percent of the
rated generator output. Unit 1 was shut down because there was no demand from the
system.
The overall condition of both generators is considered to be good.
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Annual electrical tests have not routinely been performed on these generators. Howev-
er, AEA performed an annual visual inspection of the electrical and mechanical com-
ponents, with the last one occurring in April 1995. Also, TBPA's consultant per-
formed electrical tests in September 1995. These tests included stator winding resis-
tance measurement, stator winding insulation measurement, and the collector ring
resistance measurements.
A significant amount of carbon dust in the vicinity of the collector ring housing and
on top of the generator air housing was noted in the inspection. A dust collection
system should be installed to eliminate this problem.
The generator bearings, brakes and coolers were reported by plant personnel to be in
good condition. Bearing temperatures are constant, brake shoes have minimal wear,
and the only reported problem on the cooling water system was a defective water
pressure gauge.
The excitation system has had a number of maintenance problems since its installation.
The equipment is similar to the equipment installed at Swan Lake. The motor operat-
ed potentiometers have been replaced. Power supplies are presently causing frequent
alarms. Device No. 89 relay DC coils occasionally bum out and the 41E breaker
occasionally does not close and requires manual closure.
Recommendation. The following are recommended:
1. Replace the control relays and power supplies with a new microprocessor.
2. There are a number of stator RTDs (resistance temperature detector) that are
inoperative and should be corrected.
3. A system to collect carbon dust should be installed.
5.4.9 Governors
Condition Assessment. Each Pelton turbine is controlled by a gate shaft governor for
maintaining the operating speed and positioning the needle and deflector servomotors.
The governors are manufactured by the Woodward Governor Company. The normal
operating pressure of the governing system is 500 psi. Unit 1 tripped on low governor
oil level or pressure on two occasions in the past, and foreign materials in the gover-
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nor oil system were believed to be the cause. Both governors were serviced by the
Woodward representative in 1992 and they have been operating properly since.
5.4.10 Spherical Valves
Condition Assessment. Each turbine inlet is guarded by a spherical valve. High pres-
sure water from the penstock is used to operate the valve rotor as well as the upstream
and downstream valve seals. The spherical valve is designed to close against full
turbine discharge for protection of the unit under runaway conditions. The valve clos-
ing time is designed to be adjustable between 30 and 120 seconds. The operator's log
indicates that Unit 1 valve closure time is now more than seven minutes and Unit 2
valve closure time is more than eleven minutes. While the longer closure time may be
acceptable for normal operation of the spherical valve, the unit will no longer be pro-
tected under runaway conditions. The valve control system should be checked as
described below.
Review of the valve manufacturer's operation and maintenance manual indicates that
the filtered water from the upstream side of the spherical valve is used to close the
valve rotor. The high pressure water passing through a solenoid controlled-valve
(S445) and check valve (429), enters the operating cylinder of the valve rotor, and
drains through a throttle valve ( 428) and solenoid controlled-valve (S446). The supply
pressure of the penstock water, any restrictions in the water piping, and any restric-
tions for the solenoid controlled-valves, check valve, and throttle valve, should be
checked in order to maintain the proper closure time of the spherical valve. However,
the spherical valve closure time should not be set at a faster rate than the original
timing determined during the commissioning tests, to avoid excessive water hammer in
the penstock. In general, the spherical valves are in very good condition. The leakage
through the closed valve with the seals applied is reported to be negligible.
Recommendation. Perform adjustments so that valve closing time is fast enough to
protect the turbine under runaway conditions, recognizing limitations imposed by
waterhammer considerations.
5.4.11 Powerhouse Auxiliary Mechanical Equipment
Condition Assessment. The heating and ventilation system includes sixteen electrical
heaters located throughout the powerhouse. Each heater has a thermostat for tempera-
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7176/G 2028TYEE.WP 5-17
ture setting, making operation and control of the heating system tedious. The system
also includes a ventilating unit and eight exhaust fans for air circulation in the power-
house. Because the cooling water from the penstock is rather cold, condensation is a
problem in the lower level of the powerhouse where the air compressors are located.
Based on their experience, the operating personnel change the lubricating oil in the air
compressors once a week due to condensation in the summer.
The cooling water supply for the bearings, shaft seals and generator air coolers is
taken from Unit I inlet valve by-pass line. The high pressure water at approximately
600 psi passes through two pressure reducing valves to reduce the pressure to 75 psi.
Pumps are also provided to supply water from the tailrace for the cooling water sys-
tem in case the strainer and/or pressure reducing valves in the high pressure supply
system are out of service.
Other auxiliary mechanical equipment such as the powerhouse crane, station drainage
system, unit unwatering system, fire protection system, raw and potable water systems
and machine shop are in good operating condition.
5.4.12 Station Service, Transformer and Equipment
Condition Assessment. The station service switchgear is a double-ended switchgear
with disconnect switches, 13.8 -0.480-kV transformers and 480-V circuit breakers in
one continuous lineup. The switchgear is arranged so that the main 480-V circuit
breakers and the emergency generator circuit breaker are interlocked, such that only
one circuit breaker can be closed at any one time. All station load is supplied from
one source. An adequate number of feeder circuit breakers are installed in the
switchgear, and the equipment appears to be in good condition.
5.4.13 Battery and Battery Charger System
Condition Assessment. Peculiarities exist in the 125-V DC system such as intermittent
grounds in the circuit switcher's control circuitry and the change in DC voltage when
the generator's air housing door is opened. These problems were discovered by
chance. There may be other peculiarities. A thorough investigation of the complete
DC wiring system is recommended.
960208
7176/G 2028TYEE.WP 5-18
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Plant personnel have indicated that the 125-V DC batteries only maintained their
charge for 25 minutes with the loss of AC voltage. Battery tests should be performed
to determine the condition of the batteries. Components in the battery chargers also
have been failing and replacement parts are becoming difficult to obtain. Problems in
the DC wiring system may be the primary cause of the failures in the battery and
battery charger.
There are two battery chargers. Therefore, it is not imperative to obtain new chargers
if both are still functioning.
Recommendation. The following are recommended:
1. Since the batteries do not maintain a charge for an extended period when AC
voltage is lost, it would appear that the batteries need to be replaced.
2. A thorough investigation of the complete DC wiring system is recommended.
5.4.14 SCADA System
Condition Assessment. A new SCADA system has been purchased and will be in-
stalled in January, 1996. This system includes a hot standby. The number of RTDs
110 points from the plant should be increased to provide the operator with additional
knowledge of the major generating equipment operating status.
Recommendation. The number of RTD 110 points should be increased.
5.4.15 Communications
Condition Assessment. A power line carrier (PLC) system provides the primary com-
munications between the Tyee Powerhouse and the Wrangell Control Center for con-
trol of the plant. Plant personnel have reported that there are frequent interruptions in
the PLC link which impacts the plant controls. This system was recently serviced and
adjusted by an outside contractor. This action has improved the operation and reliabili-
ty of the system. However, under extreme icing conditions, the PLC system will con-
tinue to have outages.
960208
7176/G 2028TYEE.WP 5-19
There is one common telephone line servicing the powerhouse, the residences and the
maintenance buildings. This system is through the PLC. Expansion of the PLC to
include additional telephone circuits is recommended. We also recommend that the
maintenance personnel be factory trained to maintain the system.
A VHF radio system exists which provides voice communications. During our visit,
the VHF voice communication reception was poor due to weather.
No communication link exists between the powerhouse and the intake gate structure.
Any emergency closure would require the plant personnel to operate the gates locally,
taking several hours to accomplish.
Recommendation. The following are recommended:
1. The PLC should be expanded to include additional phone circuits.
2. The VHF radio should be upgraded and improved to provide a reliable back-
up system to the PLC.
3. A VHF radio link should be installed between the powerhouse and the intake
structure to provide control of the gate and monitoring of the lake level from
the powerhouse.
5.4.16 Emergency Generator
Condition Assessment. One diesel generator provides backup power. This generator is
rated at 350 kW, 240-480 V and appears to be in good condition. The generator has
82 hours of operation, accumulated by exercising it monthly.
5.4.17 15-kV Switchgear
Condition Assessment. The generator main leads, generator circuit breakers, and neu-
tral grounding equipment were reported by the plant personnel to be in good condition.
Our inspection also found the equipment in good condition. Routine tests were per-
formed on the generator switchgear in September 1995 by Integrity Engineering Ser-
vices.
960208
7176/G 2028TYEE.WP 5-20
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5.4.18 Alarm and Temperature Monitoring Panels
Condition Assessment. There are a limited number of alarm windows on the annuncia-
tor panel. Therefore, a number of alarm contacts are grouped together and taken to one
common alarm window. Under this arrangement, the plant personnel require additional
time to diagnose any alarm. Two potential solutions are to add the individual alarm
points to the SCADA system or install an event sequence recorder be installed in the
powerhouse to facilitate trouble-shooting during a forced outage.
Recommendation. Installation of additional alarms to the SCADA is required.
5.4.19 Protective Relaying
Condition Assessment. The relaying at the plant appears to be in good condition. The
relays were calibrated by Integrity Engineering Services in June 1995.
5.5.20 Powerhouse Switchyard
Condition Assessment. Two sets of three-phase transformers with an OAIFA rating of
11.25115 MVA are located in the switchyard. The high voltage winding has a se-
ries/parallel winding with a voltage rating of 138/69 kV. The transformers were re-
ported to be in good condition.
Oil samples are taken annually.
The winding temperature instrument on transformer 2 appears to be 10 degrees off.
The instrument should either be calibrated or replaced.
The electrical demand in the area served by Tyee is limited, and the project generally
operates at reduced load. The transformer cooling fans never operate automatically
since the transformer operating temperatures never reach the cooling fan set point.
The set point is never reached due to the transformer's reduced load and the lower
ambient temperatures. Fans are manually operated monthly to verify their availability.
The Westinghouse oil circuit breaker, the Siemens-Allis circuit switcher and discon-
nect switches, wave trap, and bus structures were reported to be in good condition.
The equipment requires touch-up painting annually. Some of the switchyard area
960208
7176/G 2028TYEE.WP 5-21
lighting standards are installed in locations that make bulb replacement virtually im-
possible. New area lighting standards mounted 10 to 12 feet above grade on existing
poles should be installed to facilitate personnel safety during routine inspections.
Portable lighting is required for maintenance and emergency repairs.
Other maintenance items were noted in the inspection. Some problems had been en-
countered with the circuit switcher CST-20 and CST-21 relays. These should be re-
placed. The oil recovery facilities are in place.
Recommendation. The following are recommended:
1. Install new lighting standards that permit bulb replacement.
2. Calibrate or replace the transformer winding temperature instrument.
3. Replace circuit switcher relays.
5.4.21 Transmission Line from Powerhouse Switchyard to Wrangell Switchyard
The transmission line from the Tyee powerhouse to Wrangell switchyard is designed
for 138 kV, but it has been operated at 69 kV. The line configuration is single circuit
overhead flat configuration with no shield wires. For the overhead line, two conductor
sizes are used in different sections. High strength 37 #8 A W (Alumoweld) for what
are referred to as "high altitude" areas, and 556.5 kcmil 2617 ACSR code name
"Dove" for what are referred to as "low altitude" sections. At the Bradfield Canal
crossing, a submarine cable is used instead of an overhead line.
The support structures are guyed X-frame type weathering steel poles, guyed single
shaft weathering steel poles, and four-leg, self-supported weathering steel poles.
The concerns for this line section are discussed below.
Ground Clearances
Condition Assessment. Ever since the line was placed into service, many outages have
occurred each winter due to ice accumulation on the conductors. This problem is
more critical on the line sections utilizing the Dove conductor. The line sections with
the Dove conductor were spotted to maintain minimum ground clearance when the
conductors reach l20°F. The line also was designed for NESC heavy loading district,
which is 0.5 inch of ice and 4 pound wind at 0°F. The line has not been designed for
any heavy ice condition. Furthermore, the line design is based on a flexible system
960208
7176/G 2028TYEE.WP 5-22
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without addressing the larger sags that should be expected from such a system. The
conductor sags at 32°F temperature with 0.5 inch ice and no wind will be approxi-
mately equal to the sags when the conductor is at l20°F temperature, no ice, and no
wind, which is the condition at which the line is spotted for maintaining minimum
ground clearances. Therefore, conductor ice loadings with more than 0.5 inch ice at
32°F temperature will violate the minimum ground clearances required under the
NESC at the critical point of the span. This condition will not necessarily cause an
outage but it will certainly create a safety problem. The reported outages occur only
when the conductors have sagged to the point where there is a phase to ground fault.
From January 1984 through the spring of 1990, the Wrangell to Petersburg line, as
reported in the line evaluation report by Dryden & LaRue on August 28, 1992, was
out of service 215 hours due to wet snow which amounts to an average of 33 hours
per year. The outage reports do not reflect the times at which the clearances to
ground are in violation of NESC. Clearance problems are experienced every year
during wet snow conditions.
The impact of the above concerns are as follows:
a. Line out of service and loss of revenue because there is no other connection
to Tyee Lake Project.
b. Liability potential since the line doesn't meet NESC ground clearance re-
quirements.
Recommendation. Conduct a detailed investigation to evaluate what has to be done to
correct the ground clearance problems, and assess the relative cost of alternatives. A
detailed investigation is in progress by Power Engineers. The study is expected to be
complete in the spring of 1996.
Side Slope Ground Clearances
Condition Assessment. On sections of the line where the structures are spotted on the
side of the hills, the line appears to have insufficient ground clearance for the conduc-
tor on the outside phase closest to the hill. The impact of this concern is liability
potential since clearances might not meet minimum NESC code requirements.
Recommendation. It is recommended that a program be undertaken to check the
ground clearances at the side slopes at locations where clearances appear to be mini-
mal to check if the line meets NESC code requirements.
960208
7176/G 2028TYEE.WP 5-23
Hardware Failures
Condition Assessment. Brittle failures were experienced on the dead-end compression
fittings in the higher altitude sections. After testing, the dead compression fittings
used with the 37 #8 conductor AW were found to be defective and all were replaced.
Depending on their composition, metals could become brittle in cold temperatures. To
test the ductility of plates and hardware and ensure quality, the Charpy V-Notch tests
are conducted during fabrication. The general values used for the tests are 15 foot-
pounds at -20°F. If tests do not meet the stated requirements, the potential impact
could be brittle failures of hardware and/or compression fittings. No tests were done
for the dead-end compression fittings using the Dove conductor.
Recommendation. Although no failures have been experienced on the hardware used
with the Dove conductor, it is recommended that Charpy V -Notch test be conducted to
ensure that the hardware and compression fitting are appropriate for the cold environ-
ment of Alaska.
I nsulaJor Strings
The line is designed to operate at 138 kV. However, at several structures where
ground clearance is a problem, the 138-kV suspension insulator assemblies have been
replaced with 69-kV suspension insulator assemblies. Hence, this line cannot be ener-
gized at 138 kV until insulators are restored at these locations.
Right-of-Way Clearing
Condition Assessment. For many line sections, the right-of-way has not been properly
cleared. Many stems and tree trunks still remain within the ROW making mainte-
nance difficult. The impact of this concern is that it takes longer and it is more costly
to provide maintenance of the line, especially under emergency conditions.
Recommendation. It is recommended that selective clearing be undertaken to facilitate
maintenance during normal and emergency conditions.
Rust Tracking on the Insulators
Condition Assessment. There appears to be rust washed down from the weathering
steel structure to the insulator disks. No flashovers have been experienced, but this
might be due to the fact that the line is insulated at 138 kV and is operating at 69 kV.
Similar conditions exist on other transmission lines of the Four Dam Pool Hydroelec-
tric Projects utilizing weathering steel.
960208
7176/G 2028TYEE. WI' 5-24
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Recommendation. It is recommended that conductor insulator tests be performed to
establish the level of leakage strength degradation of the insulator string due to rust
deposits.
Submarine Cable Disconnect Switches
Recommendation. At the submarine cable terminations it is extremely difficult to
operate the bypass disconnect switches the way the disconnect switches are placed.
These switches should be modified to improve the operations.
5.4.22 Transmission Line from Wrangell Switchyard to Petersburg Substation
Condition Assessment. For the overhead line, three conductor sizes are used in differ-
ent sections: high strength 37 #8 A W (Alumoweld) for what are referred to as "high
altitude" areas; 556.5 kcmil 2617 ACSR code name Dove for what are referred to as
"low altitude" sections; and 556.5 kcmil AA all aluminum 19 strand, code name
"Dahlia" is used in the section supported with wood poles. This section also includes
three submarine cable crossings.
The overhead lines are supported on guyed X-frame type weathering steel poles, guyed
single shaft weathering steel poles, four-leg, self supported weathering steel pole struc-
tures, single shaft wood pole structures and single shaft wood pole structures with low
voltage underbuild. With the wood pole structures, the horizontal station post insula-
tors are used to support the conductors. Flat configuration is used with the steel pole
structures, and delta configuration is used with the wood pole structures.
The single shaft wood pole structures support the conductor on horizontal post insula-
tors. However, in several locations the upper phase is supported on post insulators
mounted on top of the pole. This arrangement is done on even small angle locations.
In small angles, this arrangement could cause the station post insulator to fail during
ice conditions because the actual loads could exceed the cantilever strength of the
struts.
For this line section there are three (3) submarine cable crossings: between Wrangell
and Woronkofski Islands, Woronkofski and Vank Islands, and Vank and S. Mitkof
Islands. Again at the submarine cable terminations it is difficult to operate the bypass
disconnect switches the way that the disconnect switches are installed.
%0208
7176/G 2028TYEE.WP 5-25
The concerns for this line section are the same as the ones described for the section
between the Tyee powerhouse and Wrangell switchyard. The predominant concern is
ice loading and its effects on the clearances and loading capacity of structures and
station post insulators (for the wood pole structures).
The design of the entire 138-kV transmission line from Tyee to Wrangell and
Wrangell to Petersburg is deficient. Under a contract with Alaska Energy Authority
on August 1992, Dryden & LaRue, Inc. prepared an analysis of the Tyee transmission
line loading. The conclusions of the analysis are summarized as follows:
1. The actual loading conditions on the line are significantly more severe than
the loadings used for the design of the line.
2. The low altitude sections of the line do not have sufficient strength to sup-
port the loads associated with 1 in 10 year return period events. (Transmis-
sion lines are usually designed for loadings associated with 1 in 50 year
return period events.)
3. For the high altitude sections, the 37 #8 Alumoweld conductor is marginally
able to support the estimated loads caused by the 25-year return period
stonn. One-third of the STX-E30A structures, which comprise 33 percent of
the total number of structures used in the line, are strong enough to support
the loads from a 25-year return period stonn. For a 50-year return period
storm, only a few structures will be able to support the loads.
Based on the above it is reasonable to conclude that the Tyee transmission line is
under designed.
The potential effects of an under designed line are as follows:
1. Inadequate ground clearances during ice and snow conditions; when the
conductor touches the ground;
2. Inadequate clearances from other underbuilt lines;
3. Foundation failures due to excessive loads;
4. Structure failures due to excessive loads; and
5. Conductor failures.
96020!1
7176/G 2028TYEE.WP 5-26
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In addition to the liability exposure imposed by inadequate clearances, this line pro-
vides the only connection to the Tyee powerhouse. It is therefore imperative that all
design deficiencies be corrected as soon as possible. A detailed investigation is cur-
rently underway on that will address the specific corrective measures that must be
taken to correct the design deficiencies. The steps could include the following:
1. Place additional structures in between the existing structures;
2. Replace conductors with a new conductor design and restring sections of the
line; and
3. Replace the entire line.
Preliminary conclusions of the ongoing study by Power Engineers is that the estimated
cost to correct design deficiencies is $17 million.
5.4.23 Transmission Line between Wrangell Switchyard and Wrangell Substation
Condition Assessment. The section of line between the Wrangell switchyard and the
Wrangell substation is about 2.2 miles in length. The line is supported with station
post insulators on wood poles, as shown in Figure 5-3. For about 0.5 miles, the struc-
tures support a 12.4-kV underbuild distribution line.
The concerns for this line are clearances during snow and ice conditions and the
integrity of the top mounted station post insulators used at small angle locations during
icing conditions.
Recommendation. The recommendation for the concerns on this line section are:
1. Replace the structures at the angle locations having vertically mounted sta-
tion post insulators with dead end poles, with strain insulators.
2. Remove the 12.4-kV underbuild from the structures since they contribute to
clearance problems during icing.
960208
7176/G 2028TYEE.WP 5-27
5.4.24 Petersburg Substation
Condition Assessment. Two 24.9-kV feeders connect this substation with the Crystal
Lake hydroelectric plant and the Main Street substation and diesel generating plant.
The main concerns are as follows:
1. The take-off wood pole structure in front of the substation has to be relocat-
ed because it was placed incorrectly inside the road ROW.
2. Lighting fixtures inside the substation are located where there is not suffi-
cient electrical clearance to do maintenance work and replace burned out
light bulbs. It is recommended that light fixtures be relocated so that they
can be maintained.
3. There is no emergency lighting on the outside substation. For emergency
work portable lights have to be utilized. Only the control house emergency
lighting is connected to the battery rack. It is recommended that some man-
ually operated flood lights be installed outside the control building to facili-
tate maintenance during dark periods.
4. The grounding pads at the disconnect switches are not properly installed due
to conflict with the foundation concrete, and it is difficult to operate the dis-
connect switches while standing on the grounding pad. Special grounding
pads should be fabricated to accommodate field conditions.
5. There are relaying coordination problems with this substation and the Crystal
Lake Hydro and the Petersburg Main Substation and Diesel Generation plant.
When the transformer distribution fuses trip they cause the high voltage
recloser to open. It is recommended that a relaying coordination study be
conducted define measures and protocols to coordinate all relay settings.
6. There are no oil recovery facilities in this substation. The oil recovery facili-
ties are scheduled to be installed in 1996.
Recommendation. The six items listed above are safety and operational problems that
should be corrected.
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7176/G 2028TYEE.WP 5-28
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5.4.25 Wrangell Switchyard
Condition Assessment. The main concerns are as follows:
1. Lighting fixtures inside the substation are located where there is not suffi-
cient electrical clearance to do maintenance work and replace burned
lightbulbs. It is recommended that lighting fixtures be relocated so they can
be maintained.
2. The grounding pads at the disconnect switches are not properly installed due
to conflict with the foundation concrete, and it is difficult to operate the dis-
connect switches while standing on the grounding pad. Special grounding
pads must be fabricated to accommodate field conditions.
3. The switchyard is not properly graded and does not drain well. There are
surface depressions inside the switchyard that hold water. The exterior
drained ditches are clogged up or do not have sufficient depth to intercept
and divert the runoff water from the outside areas that are at higher elevation
than the substation. As a result of improper drainage the control cable man-
holes are filled with water. It is recommended that appropriate ditch work
be done to intercept and divert the runoff from the perimeter of the substa-
tion.
Recommendation. The items listed above are safety and operational problems that
should be corrected, including:
1. Install new lighting so that it can be maintained,
2 Correct grounding pads, and
3. Improve grading and drainage.
5.4.26 Wrangell Substation
Condition Assessment. The concerns are as follows:
1. The control building is very small, and it is difficult to pull out the main
breaker without running the risk of pulling out the cables.
960208
7176/G 2028TYEE.WP 5-29
2. No oil recovery facilities are in place. Oil recovery facilities are scheduled
to be installed in 1996.
Recommendation. The control building in the Wrangell Substation is a narrow prefab
building which houses the 15-kV switchgear, battery, battery charger, and miscella-
neous equipment. Interior space is inadequate to perform any type of maintenance on
any of the equipment. It would be desirable to relocate the battery, battery charger,
eye wash, and RTU (remote terminal unit) into a second building adjacent to the exist-
ing one.
The general risks for the Tyee system substation are as follows:
Earthquake. The general area is in earthquake zone and some damage could be
sustained in a major earthquake primarily on the bus work and bushings of major
equipment.
Fire. There is a very small risk of electrical fires inside the control house.
Snow. In excessive snow storms there is some risk that outdoor equipment could
be shorted out and sustain minor damage. The risk is very low.
Tsunami. All substations are located below El. 75 ft, and are therefore at-risk to
damage by tsunami.
Contamination. There is a potential problem due to salt contamination deposits on
the insulation of outdoor electrical equipment and therefore there is increased risk
of outages due to contamination.
5.4.27 Rolling Stock
Condition Assessment. All the rolling stock at Tyee Lake is owned by AEA and con-
sists of the following:
1.
2.
3.
4.
5.
960208
Road grader -new;
Dump truck -new;
Fuel tmck (tanker) -28 years old, in poor condition;
Front -end loader - 5 years old, good condition;
Cat D-4 bulldozer -new;
7176/G 2028TYEE.WP 5-30
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6. Backhoe -poor condition,
7. Boom truck -good condition;
8. Pickup trucks -good condition
Recommendation. The fuel truck and backhoe should be replaced. A forklift should
be acquired to facilitate movement of equipment and spares.
5.4.28 Infrastructure
The infrastructure consists of housing, storage and other facilities and a dock. These
facilities have varying service lives and replacement costs. The housing units, storage
and other facilities are estimated to have a useful life of 30 years. The dock facility is
estimated to have a useful life of 15 years. At the end of the service lives of these
facilities, an estimated 75 percent of the replacement cost is included to replace or
upgrade these facilities to current standards. An estimate of the typical service life,
replacement cost and schedule for replacement has been included as part of the infor-
mation provided in Table 5-3 and 5-4.
5.4.29 Documentation
Condition Assessment. It appears that all the documentation are available at the plant.
However, our preliminary investigation reveals that the drawings do not include all the
field changes and are not as-built drawings.
Recommendation. Drawings should be corrected to reflect actual installed conditions.
The effort would involve a considerable amount of field checking. Correcting the
drawings will require that a technician or plant personnel physically check each unit,
each terminal block and each wiring device. This activity will be time consuming and
more costly than required actions at other plants.
General Comment. Drawings and records for the project are stored in a rented storage
facility in Anchorage. It is important that these records be preserved and transferred
to the new project owners after transfer of ownership.
960208
7176/G 2028TYEE.WP 5-31
5.4.30 Conclusions
Table 5-3 lists the major project equipment, and provides an assessment of the condi-
tion of each item. Table 5-3 also indicates the expected service life, assuming (a) the
conditions prevailing at the project site, (b) no deferred maintenance, and (c) no defi-
cient design. Lastly Table 5-3 indicates the replacement cost of each equipment item.
All structural components are considered to be in good shape, and are expected to
perform well beyond the remaining 38 years of the nominal 50 year life of the project.
The transmission line is deficient. The estimated cost to correct the deficiency, based
on an on-going study by Power Engineers, is estimated at $17 million.
Several items of deferred maintenance have been identified:
1. Installation of additional bracing for the storage building.
2. Correction of foundation problems with the on-site housing.
3. Clearing of the transmission line right-of-way.
An estimated disbursement schedule for correcting design deficiencies, deferred main-
tenance, other general project improvements, and replacements due to normal wear and
tear has been developed, and is presented in Table 5-4. In several sections above, it is
noted that oil recovery facilities are to be installed. The installation of the oil recov-
ery facilities is planned and budgeted by AEA, and therefore is not shown on Table 5-
4.
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7176iG 2028TYEE. WP 5-32
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Table 5-3
Page 1 of2
TYEE LAKE PROJECT· EXPECTED SERVICE LIFE AND REPLACEMENT COSTS
(where applicable, replacement costs are for both generating units)
Expected Remaining
Item Condition Service Life Service Life
~ (years)
(see note a)
Equipment
Turbine and other Mechanical Items
Runner Excellent 50 38
Needle and Nozzle Excellent so 38
Remaining Turbine Parts Excellent 50 38
Governor Good 50 38
Spherical Inlet Valve Good 50 38
Intake Gates 25 13
Cooling Water System Good 25 13
Other Aux Mechanical Equip Good 35 23
Generator
Stator Excellent 25 13
Rotor Excellent 35 23
Bearings Good 30 18
Cooling System Good 30 18
RTDs, Sensing Devices Poor 30 3
Fire Protection Good 35 23
Excitation System Poor 25 13
Electrical System
Battery and Chargers Poor 25 3
Controls and Protective Relaying Poor/Good 25 3/13 b
Station Service Excellent 30 18
15-kV Switchgear Good 25 13
Cable System Good 50 38
SCADA System Excellent 15 13 c
Communications
Wrangell Fair 15 3
Intake Gate Non-Existent
Emergency Generator Excellent 30 18
Intake Gate Electrical Controls Good 20 18 c
Switchyard, Transmission Line and Substation Equipment
Switchyard at Powerhouse
Transformers Good 30 18
Circuit Breakers Good 25 13
Disconnect Switches Good 35 23
PTs, CTs, Wave Traps Good 30 18
Bus Structures Good 40 28
Circuit Switchers Poor 20 3
All other Good 35 23
Transmission Line
Insulators Good 35 23
Hardware Good 40 28
Conductors Good 40 28
Structures Good 80 68
Foundations Good 80 68
Submarine Cable Good 35 23
1995 Price Level
Replacement Cost
($)
750,000
520,000
2,610,000
300,000
180,000
100,000
75,000
203,000
1,000,000
300,000
400,000
150,000
7,500
5,000
200,000
100,000
20,000/180,000
270,000
100,000
250,000
450,000
150,000
100,000
175,000
20,000
700,000
76,000
50,000
100,000
90,000
Replace
800,000
852,344
1,420,573
4,545,835
12,188,520
15,882,010
16,000,000
Table 5-3
Page 2 of2
TYEE LAKE PROJECT • EXPECTED SERVICE LIFE AND REPLACEMENT COSTS
(where applicable, replacement costs are for both generating units)
Item
Wrangell Switchyard
Circuit Swticher
Disconnect Switches
PTs, CTs, Wave Traps
Bus Structures
All Other
Wrangell Substation
Transformers
Circuit Switcher
PTs, CTs, Wave Traps
Bus Structures
All Other
Petersburg Substation
Transformers
Circuit Breakers
Disconnect Switches
PTs. CTs, Wave Traps
Bus Structures
All Other
Rolling Stock
Road Grader
Dump Truck
Fuel Truck
Front-End Loader
Cat D-4 Bulldozer
Backhoe
Boom Truck
Pickup Trucks (4)
Infrastructure
Housing
Storage and Other
Docks
Notes:
Condition
Good
Good
Good
Good
Good
Good
Good
Good
Good
Good
Good
Good
Good
Good
Good
Good
Good
Good
Poor
Good
Good
Poor
Good
Good
Fair
Fair
Fair
Expected Remaining
Service Life Service Life
(years) (years)
(see note a)
25 13
35 23
30 18
40 28
35 23
30 18
25 13
30 18
40 28
35 23
30 18
25 13
35 23
30 18
40 28
35 23
15 10
15 12
15 2
10 6
10 6
10 2
10 6
10 6
30 18
30 18
15 3
a Plant was essentially completed in February 1984, and entered commercial service on May 9, 1984.
Actual in·service time is about 12 years.
b Indicates that remaining life is less than expected.
c Indicates system that was replaced or modified since original construction.
·~t
"
1995 Price Level It
Replacement Cost
($)
" 120,000
19,000
150,000
120,000 " 400,000
350,000
60,000
100,000
100,000
200,000
350,000
228,000
95,000
130,000
170,000
900,000
200,000
100,000
170,000
240,000
100,000
100,000
90,000
100,000
300,000
375,000
75,000
'
!
j
l
' l
'
Table 54
Paget of3
TYEE lAKE PROJECT· PROJECTED MOST UKEL Y REPAIR AND REPLACEMENT COSTS
(in US dolars at 1995 price levels, excUling repairs or replacements <1Je to nall.nl events, accidents, or~ faihres)
Depreciation Depreciation
Used Available
Slructl.ce 1996-2000 2001-05 20()6..10 2011-15 2016-20 2021-25 2026-30 Next r!!l!!cement ~2030 After2030
Reme<ial W011< for Items of Defldent Design
Correcttnmsmlssion ine design deficiencies, lnclldng ~O!.I'ld 17,000,000
problems and side slope clealing problems, and selective
right of way dearing
Reme<ial W011< for Items of Deferred Maintenance
Bnldng for S1orage Btildng 15,000
Shore ._., Housing 30,000
Maintenance shop. mezzanine section-simple pseudostatic analysis
and~~ modifications 20,000
Sele<:Uve Transmission Line ROW Clearing 500,000
Otiler Pnojectlnvovements
Slructl.ces
Dfedgehl!rbor 600,000
Eq\iprnent
lnsllll remote control Intake gstelatcling system 15,000
lnsllll conm.rlcation system for gete remote control 100,000
Replace contol relays and power Sl4lllks will\ a ,_
mlaoprocessor 40,000
Replace RTOs In generators 7500
tartJon rust colection system 15,000
Perlorrn ·~ 1o spherical valve dosing time a
Replace 125-V ba1!ely system 60,000
lnvestigete lhe DC Yo!ring system a
Increase lhe rurber of R TU 110 points in SCADA system 10,000
Expand lhe power ine carrier system (PLC) 25,000
Ugrade 1he VHF radio 30.000
Instal a VHF ratio ink betWeen lhe powemouse and Intake 30,000
struc!lre
Instal additional al3nns 1o SCADA 15.000
S>Mtcllyard, Transmission Line and S!.t>station Eqlipment
Instal new ightlng stancl3rds that permit b<.tl replacement 30,000
Calbrate or replace transformer wlndng ternpera!lrelnstn.ment " •
Repl3ce drCiit .,.;tcher relays 20,000
COI'l<llct tie Chl!rpy V-Notctl test on hl!rdware 20,000
Perlonn insUator asserrt>ly test for rust contamlnetion 13,000
Tr$smlssion Line btMl Wranget S'Oilctlysrd & Wranget S!.t>slation
Repl3ce tie struc!lres at tie angle locations having ver11caly
rnDI.I1ted station post inst.iators will\ dead end poles 50.000
Remove tie 12.4-W li'lde!tlUid from 1he struc!lres 120,000
Petersbu'g Slt>siBtion
Relocate lhe teke-o1f wood pole struc!lreln front of tie Sl.bstation 25,000
Instal new ightlng so lhllt it can be maintained and
emergency lghtlng on lhe outside of the 5\t>station 30,000
Correct!Totnling pads 10,000
COI'l<llct a rela;ing coorlination si!.Jdy 30,000
Wranget S>Mtctlyard
Instal new ighting so lhllt H can be maintained 30.000
Correct ~otnlng pads 10.000
lfr¥ove ~ling and drainage 30.000
'Nranget S!.t>station
Retocatelhe battery, ba1!e!y chl!rger, eye wash, and RTU Into
a second bU!ding 10.000
Add oil recovery !aditios at al sU:lstations budgeted
Correct switdl problems at st.IJmarine cable termlnetions 240.000
C~lete As-Blift drawings 30.000
Acq\ire !orl<l!! 40.000
Replacement aue to Normal Weer and Tear
Struct.res
Tlfl'ellnspection will\ ROY 200,000 200,000 20-year cycle
Test and repl3ce selected p~e rock anchors 90.000 90.000 90.000 90,000 90,000 90,000 90.000 5· year cycle 72.000 18,000
Repeir leaks from powemouse roof 45.000 45,000 45.000 17 ~year cycle 45,000
Repair seepage In powemouse and Ill conaete CIJ1out 10,000 10,000 10,000 17-year cycle 10.000
StrucUe
Concrete Repairs in <Taft tile
Arct1terual rehabiltalon
Eq.ipmenl
Tll:bine and 01her Mechallcal nems
Tll:bine {nroner, nee<Je and nozzle)
Gov<rnor
lrletVallle
Intake Gates
Cooing Water System
01her Al.odtary Mechanical Eq.ipmenl
Genenator
Stator(co41s)
R01or (poles)
Bearings
Cooing System
RTOs, Sensing Devices
Fire Pro1eclon
Exdta•on Sys1em
Elec1rical System
Battery and Chargers
Con!rols and Protective Relaying
Sta•on Sernce
15-kV SW!tchgeor
Cable System
Intake Gate Elec1rical Con!l'ols
SCAOA Sys1em
Cornl'l'Ulications
Wrangel
Intake Gate
Emergency Generotor
SW!tchyard, Tl'llM!Tission Line and Sl.i:>sta1ion E(Jipment
Powemouse SW!Ichyafd
Transformers
Circtit Breakers
Disconnect SWitches
PTs.CTs, Wave Trops
Bus Strucll.fes
AI 01her
Transmission Line
Insulators
HardWare
Conductor
Str\lell.l'es
FOI.Jldations
Slilmarine Cable
Wrangel s..1tchyard
Circuit Switcher
DiscOI"W'\Ect s'Nitches
PTs, CTs. Wave Traps
Bus S1rucll.fes
AI 01her
Wrangel Stilstation
Transforme<s
Omit SW!Icl1er
PTs, CTs, Wave Trops
Bus structl.res
AI Other --·~ ... ..,.__ .............. ...... ...
Table 5-4 Page2of3
TYEE LAKE PROJECT· PROJECTED MOST liKElY REPAIR AND REPLACEMENT COSTS
(in us dolars at 1995 prtce levels. exck.iding rOf>Sirs or replacements we to na1Lnl even1s. acddents, or e<Ppment tabes)
1996-2000 2001-05 2006-10 2011-15 2016-20 2021-25 2026-30
20,000 20,000 20,000 20,000
200,000
100,000
75,000
203.000
1,000,000
300,000
400,000
150,000
7,500
5,000
200,000
100,000
20,000 180,000 20,000
270.000
100.000
20,000
450,000 450,000
150,000 150,000 150,000
100,000 b 100,000
175,000
700,000
76,000
50,000
100,000
90,000
800,000
852.344
1.420,573
4 545,835
16.000,000
120.000
19,000
150,000
120.000
400,000
350,000
60,000
100.000
100.000
200.000
Oepredalon Oepredaton
Used Available
Next <!:E!!!Cemen! Thr~2030 M«2030
1Cl-yearcyde 8,000 12.000
20.45 100,000 100,000
2033 3,647,200 232,800
2033 282,000 18,000
2033 169,200 10,800
2033 88,000 12,000
2033 66,000 9,000
2053 59,500 133,400
2033 660,000 120,000
2053 102,857 197,143
2043 225,667 173,333
20.43 85,000 65,000
2058 500 7,000
Ched< C02 gas am.oaly; 2053 1,714 3,286
2033 175,000 24,000
2048 28,000 72.000
2033 165,500 34,400
2043 153,000 117,000
2033 88,000 12,000
2033 235,000 15,000
2033 17,000 3,000
2038 210,000 240,000
2043 20.000 130,000
b 2040 13,333 86,667
2043 99,167 75,833
2043 396,667 303,333
2043 66,880 9,120
2053 17,143 32.857
2043 56,667 43,333
2063 15.750 74,250
2053 274,285 525,714
2053 292,232 560.112
2053 248,600 1.171.973
2063 795.521 3.750.314
2063 7.160.755 5027,765
2063 9.330,681 6.5~1.329
2063 5.485,714 10.514.286
2033 105.600 14.400
2055 6,514 12,486
2043 85.000 65.000
2055 21000 99.000
2053 137,143 21''2.857
2043 198,333 1~1.667
2033 52.800 7200
2043 56.667 43,333
2063 17.500 82500
2053 68,571 131.429
Table 5-4
Pog• 3 of 3
TYU LAKE PROJECT-PROJECTED MOST UKEL Y REPAIR AND REPLACEMENT COSTS
(in us dolars at 1995 price levels. exQ.Jdog r~an or replacements u to flllllnl events. acclaems. or eq.ipment laikres)
Slructlre
Petersb\rg Sltlstaton
Transle<men~
ClrC\it Breakers
Discomecl s...;tches
PTs. CTs, Wave Traps
Bus Slructlres
AI other
Rolngstod<
Road Grader
Dtltl> Truck
Fuel Trud<
Froni-End Loader
Cal D-4 Bt*mer
Bacl<lloe
Boom Truck
Pickup Trud<s (4)
FOII<Ift
lnfraslru<:uo
Housing
storage and other
Docks
5-YRTOTALS
Remedal Work lor nems of Deficient Design
Remedal Work lor nems of Deferred Maintenence
other Project fnllrovements
Replacemenls <lJe to Norm~~l Wear and Tear
-nces For Replacements After 2030 (3)
LEVELIZED PAYMENT ANALYSIS
R•placement• due to Normal Wear and Tear (4)
B~ng of Pooiod Fll'ld Balance
Arlnllal Con!ribution of 51.175,440 to Reserve Fll'ld
El<pense
Interest on Average Fll'ld Balance
End ol Pooiod Fll'ld Balance
Allowance• tor Replacements after 2030 (5)
Begimng of Period Fll'ld Balance
Arlnllal Conllibution or 5263,024 to Reserve Fll'ld
El<pense
Interest on Average Fll'ld Balance
End of Pooiod Fll'ld Balance
~
170,000
100,000
75.000
17.000,000
565.000
1.685,500
880.000
405,592
5,877.200
(933,863)
968.046
5.911,383
1,315,122
(430,587)
173,726
1 058,261
~
200.000
100.000
240,000
100,000
90.000
100,000
920,000
405.592
5,911,383
5,877.200
(1,077,927)
2.939,908
13,650,565
1,058.261
1,315.122
(475,403)
523.038
2.421.018
~
228.000
100,000
40,000
2.839,000
505,316
13,650,565
5.877.200
(3.672,549)
5.081.883
20.917,099
2,421,018
1.315,122
(661.779)
961,918
4,036,279
b
2011-15
350,000
130,000
170,000
240,000
100,000
90,000
100,000
300.000
375,000
75.000
4,940,000
790.337
20,917,099
5.877.200
(7,055.536)
6,873.406
26,612.170
4.036,279
1.315.122
(1.134.686)
1.422,472
5.639.187
2016-20
95,000
900,000
200,000
100,000
100,000
40,000
20,574,344
1.535,548
26,612,170
5.877.200
(32,443,668)
3,950,085
3,995.787
5,639,187
1.315,122
(2.448, 124)
1.782.868
6,289,053
b
2021-25
170,000
240,000
100,000
90,000
100,000 -
7,636,408
2.765.926
3,995,787
5,877.200
(13.295,171)
(315.700)
(3,737,684)
6,289.053
1,315.122
(4,830.120)
1,499,249
4.273,304
~
170,000
100,000
40.000
75.000
807.500
3.183.308
(3,737,884)
5.877.200
( 1,552.202)
(587,115)
0
4,273.304
1.315.122
(6.125,068)
536.832
(0)
a Indicates ltlallhe cost lor tis item is assllllOd to be incllded as a part of !he normal operahons budget and !he re,..red acti.;ties can be c3!Tied out by plant pen;omelas part of day-to-day activities
b lnacates an item ltlat Is contingent on implementation ol a recommended project improvement
( 1) Upgrade irlWded in project improvements
(2) ReconYrlerld larger emergency generator
(3) Calc!Jated in 1995$, using a 4% real <JscOU'\t rate
b
Depredation
Used
NeX1 replacement T!!oug12030
2043
2033
20S3
2043
2()63
2053
Replacement every 15 years
Replacement ""ery 15 years
Replacement every 15 years
Replacement every 10 years
Replacement every 10 years
Replacement every 10 years
Replacement every 10 years
Replacement every 10 years
Replacement every 10 years
2044
2044
2044
tla'R£C1ATMJN TOTALS:
1...
()>?u
c-1 '"\ ·--......
i., I ~L)
d ~61
~9'-\L~
~c)Sl~
.lG36
198.333
200.640
32.571
73,667
29,750
308,571
133,333
86,667
34.000
216,000
90,000
30,000
81,000
90,000
16,000
170,000
212,500
~
33.906.896
'8ol
(4) Afllliysls assunes a 2% escalation rate. a 6% interest rate on available ltllds. a 8% borro..,ng rate. and one Ur1p S!JTl payment in 1he md<Je ollhe flv.,.year period.
(5) Afllliysis ass"""'s a 2% escalation rate. a 6% Interest rate on available lll'lds. a 8% borrOWing rate. and begimng of year pa~ts to ~Ia cement ltllds. )'\ @10
\ f
Depredation
Availat>le
~
151,667
27,350
62,429
56.333
140.250
591.429
66.667
13,333
136.000
24,000
10.000
70,000
9,000
10.000
24.000
130,000
162,500
65QOO
33,160,886
-Estimated Inflow into Tyee Lake -+-Powerplant Hydraulic Capacity
400
350
300
250 -
i"
.!!.200 -~
150
100
50
0 I .I J I u l l I
Jl , ., A .. 1Ja85 I 0 " PI Jl f .. A 1!1 1Ja86 s 0 N PI Jl f .. A .. 1 J987" I 0 N Dl1 f M A M 198a"' • Q N J 1 , .. ;., M 198a"' I 0 H J 1 f M A M 1 Ja90 I 0 " PI 1 f M A M 1991 A I 0 " PI r , M A "'1992 A ' g " l r f M A "'1993 ... I 0 " l
Figure 5-1 Tyee Lake Project -Estimated Historical Flows
Tyee tab
--------., ---~---I .-----~ : ! @)-(ID...J '--Q-1.1 I
: @)-(ID...J
I -------1 I ,......, __ ........... ·------
Pda'si:Jtq Maio 1111 ,
SUeet Subtltlltioa
Petenburs substai:IOII r -
I
I
I
I
I -
r
I
: ~ ,...----...~. I f __ j ____ l I
wmnsen switcbyant -r-----'-~1 : ~--j---I
1 • 'I I .. ·-' -. .. .
I
I ________ _..., i ____ ¢ ___ i
I I
I I
I I
I I
I I
I I
WJ2D8ell Plxe:st
Producls Sawmill
- - - - - - - - - -WmuseU Substalial
• .. SubmariDe Cable
Ovemead LiDe
Figure 5-2 Tyee Lake Project -Transmission and Substation System
I I
Figure 5-3 Tyee Lake Project ·Transmission Line Support Structure-Wrangell SWitchyard to Wrangell
Substation
Chapter 6
Estimation of Annual Costs
and Analysis of Risks
Chapter 6
ESTIMATION OF ANNUAL COSTS AND ANALYSIS OF RISK
This chapter covers three main topics:
• Analysis of historical operation and maintenance costs,
• Evaluation of risk, and
• Presentation of the total expected annual costs for continued operation of the
projects.
6.1 Analysis of Historical Operation and. Maintenance Costs
Historical operation and maintenance costs taken from the financial reports of the Four
Dam Pool Management Committee were reviewed and are summarized on Table 6-1.
These historical costs were used as a guide in estimating future costs related to the
day-to-day normal operation, management and maintenance of the hydroelectric pro-
jects.
The historical costs were escalated to a common 1995 price level, averaged over the
period analyzed, and reported on Table 6-20 presented later in this chapter.
The estimated average annual operation and maintenance cost for all four projects,
excluding fixed charges for debt service and equipment replacement fund contribu-
tions, is $6.8 million at the 1995 price level.
6.2 Risk Evaluation
6.2.1 Methodology
Events that occur unexpectedly with a relatively low degree of frequency causing
damage to the project, as well as outages, are characterized as project risks. Risk eval-
uation can involve objective or subjective analysis. Risk-related events that can be
characterized because they have an adequate recorded history, or can be described by
the application of theory or experiment, can be addressed in an objective analysis.
960208
7176/G 202HCHA6.WP 6-1
Table 6-1
OPERATION AND MAINTENANCE COSTS AND ALLOCATED REVENUE REQUIREMENTS
Year ending
Item 6/30/87 6/30/88 6/30/89 6/30/90 6/30191 6/30/92 6/30193 6130/94
ProductiOn Costs
Facility Operating Costs
Solomon Gulch 602,855 771,385 580,116 690,984 683,379 969,893 940,906 1,069,951
Terror Lake 1,053,676 663,304 670,168 732,064 777,441 804,000 720,415 792,493
Swan Lake 587,702 989.259 938,696 989,264 996,191 1.111,189 1,086,298 992,813
Lake Tyee 774,916 737,253 832,186 968,142 1,093,793 1,036,354 1,072,781 1,045,955
Subtotal 3,019,149 3,161,201 3,021,166 3,380,454 3,550,804 3,921,436 3,820,400 3,901,212
Joint Costs
Alaska Power Authonty
Admimstratton 375,636 379.882 396,635 414,165 433,424 459,912 474,000 487,750
Studies, Survey, etc
Insurance 1 344,738 1,201,506 913.492 1,013,625 1,034,400 1,085,704 1,052,784 1 '100,000
License ReqUlrements 190,565 123,825 110,871 150,611 163,328 166,261 210,203 295,090
Travel 3,269 7,896 2,517 2,821
ProJect Management Committee 248,268 355,799
Expenses 323,998 288,994 387,819 180,652 273,690 357,929
Fund Insurance Reserve 920,000 80,000 34,400
FERC Fees 482.207 161,648 134,923 134.859 197,018 185,676
Insurance Losses 73,597 121,518 470,488 18,257
Subtotal 5,178,356 5,222,213 6,168,369 5,566,363 5,868,512 6,421,829 6,049,173 6,327,657
Ftxed Contributton to Renewal
and Replacement Fund 500,000 500.000 500,000 500,000 500,000 500,000 500,000 500.000
TOTAL PRODUCTION COSTS 5,678,356 5,722,213 6,668,369 6,066,363 6,368,512 6,921,829 6,549,173 6,827,657
Fact/tty Charge for State of Alaska
Debt Servtce 5,688,813 6,755,887 7,867,644 9,266,793 9,437,592 9,265,826 10,205,361 10,734,405
COST OF POWER 11,367,169 12,478,100 14,536,013 15,333,156 15,806,104 16,187,655 16,754,534 17,562,062
Less Credits
Investment Income 124,129 223,178 302,472 402,132 417,940 307,500 213,530 268,858
Interruptible Sales 207,621 236,655 142,573 73,545 159,069 126,721 63,377
Insurance Settlement 75,000
Excess revenue collected--prior year 741,100 1 ,660,155 1 739,596 692,599 1,129,454 1,258,396 463,717 779,126
REVENUE REQUIREMENTS 10,501,940 10,387,146 12,257,290 14,095,852 14,185,165 14,462,690 15,950,566 16,375,701
Energy Production
Solomon Gulch 40,584,034 38,582,126 36,686,771 39,388,355 39,147,589 40,159,656 41,304,151 50,311,427
Terror Lake 91,909,793 102,671,415 107,567,000 111,528,987 91 ,391,717 99,364,109 107,873,266 118,189,728
Swan Lake 44,360,000 41,493,400 50,419,590 48,369,074 69,290,320 57,122,422 71,226,980 67,832.000
Lake Tyee 32,837,466 33,802,000 19,594,000 19,311,000 41,476,000 36,579,000 40,997,000 39,516,000
Total Energy Production (kWh} 209,691,293 216,548,941 214,267,361 218,597,416 241,305,626 233,225,187 261,401,397 275,849,155
NET COST PER kWH 0.0501 0.0480 0.0572 0.0645 0.0588 0.0620 0.0610 0.0594
Allocated Revenue
Solomon Gulch 2,032,565 1 850,659 2.098,688 2.539,886 2.301.293 2,490,368 2.520.356 2.986,723
Terror Lake 4,603,105 4,924,813 6.153.433 7,191 741 5,372,467 6,161 '737 6,582,366 7,016,297
Swan Lake 2,221,676 1,990,303 2.884,282 3,118,991 4,073,235 3,542,258 4,346,230 4,026,826
Lake Tyee 1,644,594 1,621,372 1,120,886 1,245,234 2438,169 2,268,326 2,501,614 2.345,855
Source AEA
6-2
The consequences of these events can be estimated based on design standards and
expected performance when structures and equipment are subjected to these events.
One example of this type of event is an earthquake, where the expected frequency and
magnitude of events can be characterized. Design standards dictate the level of toler-
ance that a particular stmcture or piece of equipment should exhibit.
Other risks can only be evaluated subjectively. An example of a situation that would
be evaluated subjectively is the potential for rockfalls. The potential for occurrence of
such an event, and its consequences, can only be characterized based on observations
of conditions at the site and an implicit knowledge of past history and performance of
the structures involved.
The risk evaluation performed for this study relies heavily on the condition assess-
ment, and the opinions of those that inspected the projects. Based on the prevailing
conditions, a list of events that could be potentially damaging to various project com-
ponents was developed. These events are described in the following sections 6.2.3
through 6.2.15. Next, each project was broken down into major features (dam and
spillway, penstock, tunnel, etc.), so that the applicability of each risk element could be
evaluated. For example, the occurrence of an earthquake will affect virtually every
structure, whereas the occurrence of a rockfall will only affect certain stmctures. For
each project, a matrix was developed to illustrate events that would be expected to
impact various components of the pro jed.
The next step was to estimate (a) the probability of occurrence of the possible events,
(b) the expected costs associated with the occurrence of an event, and (c) the expected
outage duration. The costs and outage duration were estimated by postulating the
likely failure mode or consequence resulting from the possible event. A likely range
of repair cost and outage duration was also established.2
In establishing the range of possible consequences, consideration was given to the
"skew" of the distribution of possible consequences. For example, in some cases, the
consequences of an event might be expected to be normally distributed between the
high and low, where in other cases, the likely event might be expected to be skewed
toward the lower end of the estimated range. This situation occurs where the expected
The correspondence between events and project structures is illustrated on Tables 6-4, 6-
8, 6-12, and 6-16.
The probabilities, range of costs and range of outage duration established for each
project are summarized on Tables 6-5, 6-9, 6-13, and 6-17.
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repair cost is low, but the maximum possible cost is the cost associated with the re-
construction of the facility.
With the estimated probability of occurrence and the estimated costs and outage dura-
tion, a computer model was used to simulate several thousand hypothetical years of
project life. Using the probability distributions assigned to each event, the occurrences
of events were determined by simulation, and when events occurred, the repair cost
and outage duration was also detennined. The simulation utilized random numbers to
generate the occurrences of events in the several thousand years analyzed, so that the
number of events is consistent with the estimated probability of occurrence of each
event. The simulation also randomly picked from the given range the cost and outage
time associated with each event, when an event occurred. @Risk, a commercially
available software product, was used to perform the simulation.
One product or result of the simulation is an annual repair cost and outage duration for
each of the several thousand years simulated. This series of annual repair costs and
outage duration is used to generate cumulative distribution curves showing the range
and likelihood of cost and outage duration associated with each project.3
The average cost and outage duration is established for each project. The cumulative
distribution curve will indicate a percentage exceedance for a range of possible costs
and outage time. The 50 percent exceedance probability from the cumulative distribu-
tion curve is not the average or expected cost or outage duration, because the distribu-
tion of costs and outage duration may be skewed above or below the 50 percent
exceedance probability.
Additional detail and example calculations for a sample situation are presented
Appendix D.
6.2.2 Structures and Equipment Categories
The analysis was carried out for each of the following major structures and equipment
categories as applicable (not all categories apply to all projects):
1. Dams, spillways and outlet works -in general, all of the risks associated with
the reservoir or lake, the dam, the internal components of the dam, the spill-
~ The cumulative distribution curves are presented as Figures 6-1 to 6-8.
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7176/G 2028CIIA6.WP 6-4
way, and other items in close proximity to the dam and reservoir are includ-
ed in this category.
2. Intake and power tunnel -includes the gate structure and gate house, the
electrical and mechanical components of the intake gate, and the power tun-
nel.
3. Penstocks -includes the penstock intake, valves and controls, and supports.
4. Powerhouse -includes the powerhouse substructure and superstructure, ac-
cess facilities, rolling stock, and all of the miscellaneous structures in the
vicinity of the powerhouse, with the exception of the switchyard.
5. Machinery -includes the mechanical and electrical equipment in and around
the powerhouse, excluding the switchyard.
6. Switchyard, with separate categories for substations -includes equipment and
civil structures in and around the switchyard or substation.
7. Transmission line, with a separate category for the submarine cable -in-
cludes the foundations, structures, insulators, conductors and other miscella-
neous items associated with the transmission line.
6.2.3 Earthquake
All structures are exposed to possible earthquake damage. The potential for earth-
quake is evaluated in terms of the possible events the once in 10 year event, once in
100 year, once in 1000 year, or maximum credible earthquake (MCE), which for the
purpose of this analysis is assumed to have a recurrence interval of once in 10,000
years, and the range of damage and outage that could occur. Table 6-2 outlines the
guidelines that were applied in estimating the expected repair cost for various struc-
tures and associated project outage time.
6.2.4 Flood
Structures are designed for an appropriate level of flood protection, depending on
importance. Although major structures are generally designed to resist failure under
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7176/G 2028CHA6.Wl' 6-5
probable maximum flood conditions, some damage can be expected to occur because
of the catastrophic nature of the event. Table 6-3 presents the criteria for estimating
flood damages for those structures determined to be at risk. Damages to downstream
structures and potential liability risks are not included.
6.2.5 Fire
Fire is a potential hazard to powerhouse superstructures, equipment and wooden pole
transmission lines. Based on information from the Generating Availability Data Sys-
tem (GADS), the number of reported fires is relatively small, less than one in 200
years of unit operation. When fires do occur, the magnitudes of losses should be
relatively small due to the presence and protection provided by fire suppression sys-
tems.
Because of oil storage, there is a small possibility of fire damage at the submarine
cable terminations.
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717610 2021iCHA6.WI' 6-6
Table 6-2
CHARACTERIZATION OF EARTHQUAKE DAMAGE
Frequency 0.1 (Once in 10 0.01 (Once in 0.001 (Once in 0.0001 (MCE -
years) 100 years) 1,000 years) assumed to be
once in 10,000
Dam, spillway, No damage or No significant No major dam-Significant
power tunnel, outage damage or out-age; outage may damage; outage
substructures age be on the order may be on the
(heavy and mas-of several days order of several
sive civil struc-days to a few
tures) months
Penstock, power-No damage or No significant Significant Major architec-
house superstruc-outage damage or out-architectural tural damage;
ture, transmis-age damage; outage outage may be
sion lines may be on the on the order of
order of several a few months
days
Powerhouse, No damage or No significant Significant Major equip-
switchyard and outage damage or out-equipment dam-ment damage;
substation equip-age age; outage may outage may be
ment be on the order on the order of
of several days a few months
6.2.6 Landslide or Rockfall
Landslides and rockfalls can pose an outage risk if such features exist in close prox-
imity to important and critical structures and equipment. Where steep slopes are close
to structures or equipment, a likely annual probability for an occurrence of an event
was established based on an understanding of the situation. For each structure or
facility where landslides or rockfalls posed a threat, a most likely damage scenario
was established based on judgement. In some cases, damage assessment is augmented
by operations personnel observations and reports of actual occurrences.
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Table 6-3
CHARACTERIZATION OF FLOOD DAMAGE
Frequency 0.1 (Once in 10 0.01 (Once in 0.001 (Once in 0.0001 (PMF -
years) 100 years) 1,000 years) assumed to be
once in 10,000
Dam, spillway, No damage or No significant No significant No major dam-
power tunnel, outage damage or out-damage, outage age, outage may
substructures age for cleanup be several days
(heavy and mas-probably not for inspection
sive civil struc-necessary and cleanup
tures)
Penstock, pow-No damage or No significant Possible minor No major dam-
erhouse super-outage damage or out-damage and age, outage may
structure, trans-age at most short duration be on the order
mission lines locations, some (few days) out-of several days
minor damage at age for cleanup for cleanup and
improtected and minor repair minor repair
locations
Powerhouse, No damage or No significant Some equipment Some equipment
switchyard and outage damage or out-damage at un-damage, even at
substation age protected loca-protected loca-
equipment tions, outage tions, outage
may be a few may range from
days a few days to
weeks
6.2. 7 Avalanche
Potential damages to structures and equipment from snow avalanches is determined on
a case-by-case basis from operating history and at-site conditions.
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6.2.8 Tsunami
A number of tsunamis have occurred in recent history that have affected the southern
coast of Alaska:
I. The 1946 Aleutian Tsunami occurred on April 1, after an earthquake had
occurred in the Aleutian Islands. A Pacific-wide tsunami was triggered by
this earthquake. One of the well known consequences of this tsunami was
the destruction of the Scotch Cap Lighthouse on Unimak Island, where the
run-up reached 35 m.
2. In 1957, another earthquake occurred south of Andreanof Island, in the Aleu-
tian Islands of Alaska, triggering a tsunami. The extent of damage to struc-
tures and communities in southern Alaska is not known.
3. The most well known event is the 1964 Prince William Sound Tsunami. An
earthquake triggered a Pacific-wide tsunami, as well as local landslides that
triggered destructive localized waves. Run-up measurements varied from
27.4 m at Chenega, 24.2 m at Blackstone Bay, 9.1 m at Valdez, and 6.1 m at
Kodiak. One of the tsunami waves reached 31.7 m above low tide at
Whittier. At the Valdez Inlet, a large landslide was triggered by the earth-
quake, and generated a tsunami that had a nm-up measured at 67 m in the
inlet.
Small tsunamis may occur largely unnoticed. In the late 1980's two tsunamis occurred
with a run-up of only a few inches.
The powerhouse, generating equipment. and in some cases, the switchyard and trans-
mission line are exposed to possible flooding due to tsunami. Where the potential for
tsunami exists, a once in 25 or 50 year recurrence interval is assigned. However. the
level of expected repair cost and corresponding outage is highly variable. The damag-
es can range from zero to the cost for complete rebuilding of the facility, with the
most likely cost in the event of a tsunami to be close to the low end of the range.
Solomon Gulch is the most susceptible to tsunami damage, both from the earthquake
induced wave and from waves generated by landslides. The powerhouse, switchyard
and portions of the transmission line are near sea level. Damage costs are expected to
be highest for Solomon Gulch.
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7!76/G 2028CIIA6.WP 6-9
Kodiak Island is also at risk to tsunami damage, although the base of the Terror Lake
Hydro powerhouse structure is over 90 feet above sea level. A tsunami wave could
travel up Kizhuyak Bay to the powerhouse, but because of its elevation, the potential
for damage is considered to be somewhat less than at Solomon Gulch.
Swan Lake and Tyee Lake projects seem to be farther away from the area most sus-
ceptible to earthquake induced tsunami damage. Furthermore, these projects seem to
be more protected from the open ocean than are Solomon Gulch and Terror Lake
(although these later two projects are also somewhat protected). However, Swan and
Tyee could be susceptible to landslide induced waves.
6.2.9 Volcanic Activity
There over 40 active volcanoes in Alaska. Most of these are located in the Aluetian
arc, and therefore pose the greatest risk to Terror Lake and Solomon Gulch. The
eruption of a volcano and the distribution of ash can cause difficulties related to trans-
mission line and electrical equipment insulators and problems with air handling sys-
tems. In addition, volcanic ash could contaminate reservoir water, and cause addition-
al wear and tear on the turbine runner, or in the case of Pelton-type units, damage to
the needle valves.
The possibility that a volcanic eruption and its associated ash-fall will affect and con-
taminate insulators is covered in a separate section below.
The probability that a volcanic eruption will occur that affects either Solomon Gulch
or Terror Lake is assigned at once in 25 years. If an eruption does occur, the most
likely costs and outage duration is expected to be low. However, there is a possibility
that there could be significant damages and costs, and such a possibility is reflected in
the high estimate of the damage and cost.
Volcanic activity is not expected to affect Tyee Lake a Swan Lake projects.
6.2.10 Wind
Transmission lines are particularly susceptible to damage due to snow and ice com-
bined with wind. Estimates of the expected costs and outage durations are based on
an assessment of operating history of each facility.
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7176/G 2028CIL\6.WP 6-10
6.2.11 Snow
· Like wind, transmission lines are particularly susceptible to damage due to snow and
ice. Estimates of the expected costs and outage durations are based on an assessment
of operating history of each facility.
6.2.12 Spills
Spills of oil or other environmentally damaging substances are potential occurrences,
particularly at switchyards and substations. All switchyards and substations will have
spill containment facilities, so the costs associated with spills should be moderate.
In addition to possible spills in the switchyards and substations, there is a potential for
spills in the powerhouse.
Oil may be stored at the submarine cable terminations, and therefore, a smal1 provision
for the potential occurrence of spill is associated with the submarine cable.
6.2.13 Contamination
Contamination includes the possibility that dust or salt interferes with the normal oper-
ation of equipment, primarily insulators.
6.2.14 Accident
The cost and consequences associated with accidents can be highly variable. The
potential for and cost associated with accidents has been estimated on a case by case
basis for each component of each project.
6.2.15 Internal Failure
Internal failures are unforeseen and unanticipated events that lead to equipment break-
down or structural failure. The cause of these events can usually be traced to design
deficiencies or defects in materials. Internal failures can cause catastrophic losses (i.e.
dam failure) or may be relatively minor in nature.
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7176/G 20l8CHA6.WP 6-ll
An internal failure is also an event that indicates a problem that necessitates an outage.
For example, if an increase in seepage or cracking of the dam indicates a potential
problem, FERC may mandate that the project be removed from service even though
there is no obvious structural failure and the project may be physically capable of
operating.
6.2.16 Swan Lake Project
Table 6-4 presents a matrix showing pertinent risk factors. Table 6-5 presents a tabu-
lation of the estimated repair costs associated with various outage events.
The expected annual risk related costs are $159,529. Corresponding outage time is
expected to be 13.4 days per year. The cumulative distribution of costs and outage
time, illustrating the possible range for these items, are illustrated on Figures 6-1 and
6-2 respectively. A breakdown of the repair cost and outage duration assigned to
various structures and events is listed in Tables 6-6 and 6-7.
6.2.17 Solomon Gulch Project
Table 6-8 presents a matrix showing pertinent risk factors. Table 6-9 presents a tabu-
lation of the estimated repair costs associated with various outage events.
The expected annual risk related costs are $291.464. Corresponding outage time is
expected to be 22.8 days per year. The cumulative distribution of costs and outage
time, illustrating the possible range for these items, are illustrated on Figure 6-3 and 6-
4 respectively. A breakdown of the repair cost and outage duration assigned to vari-
ous structures and events is listed in Tables 6-10 and 6-11.
6.2; 18 Terror Lake Project
Table 6-12 presents a matrix showing pertinent risk factors. Table 6-13 presents a
tabulation of the estimated repair costs associated with various outage events.
The expected annual risk related costs are $349,308. Corresponding outage time is
expected to be 18.9 days per year. The cumulative distribution of costs and outage
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7176/G 2028CHA6.WP 6-12
time, illustrating the possible range for these items, are illustrated on Figure 6-5 and 6-
6 respectively. A breakdown of the repair cost and outage duration assigned to vari-
ous structures and events is listed in Tables 6-14 and 6-15.
6.2.19 Tyee Lake Project
Table 6-16 presents a matrix showing pertinent risk factors. Table 6-17 presents a
tabulation of the estimated repair costs associated with various outage events.
The expected annual risk related costs are $312,387. Corresponding outage time is
expected to be 23.5 days per year. The cumulative distribution of costs and outage
time, illustrating the possible range for these items, are illustrated on Figure 6-7 and 6-
8 respectively. A breakdown of the repair cost and outage duration assigned to various
structures and events is listed in Tables 6-18 and 6-19.
6.3 Summary of Costs
A summary of projected project and composite costs for the Four Dam Pool Projects
are presented in Table 6-20. The costs are presented in five-year increments for the
future 35-year planning horizon.
The definitions of each of the items appearing in Table 6-20 are provided below:
• Deficient Design -defined as a condition that does not meet the minimum gener-
accepted standards for safety and reliability.
• Deferred Maintenance -defined as a condition where either regularly scheduled
maintenance or maintenance to repair a damaged structure or malfunctioning
component was not carried out in a timely manner.
• Other Project Improvements -project structures or equipment requiring attention
that do not conveniently fit the definition of deficient design or deferred mainte-
nance are classified as 110ther Project Improvements.~~ Such items include equip-
ment that is planned for replacement for reasons including obsolescence, unavail-
960208
of spare parts, premature failure, or changing operating conditions. Also
placed in the Other Project Improvements category are (I) equipment and struc-
tural repairs or modifications that have not been deferred, but are now required
7176/0 2028CHA6.WP 6-13
to correct a malfunction, or to improve functionality or safety, or (2) studies that
should be carried out to clearly characterize a problem or project need.
• Replacements due to Normal Wear and Tear -involves the replacement of
equipment or infrastructure item when it reaches the end of its normal life. A
schedule for expenditures to replace equipment or to carry out major structural
rehabilitation was developed. For equipment, the typical service life (adjusted
for at-site conditions) was used as the basis for establishing the replacement and
expenditure schedule. For structures, the existing condition and expected perfor-
mance were used to establish an appropriate rehabilitation and expenditure
schedule.
• Risk-Related costs -are the expected annual costs to repair or replace damage
due to natural events, accidents or unforeseen equipment failures.
• Operation and Maintenance Costs -based on an analysis of historical costs that
are described in Section 6.1 above. Historical costs reported in the audited fi-
nancial statements of the Four Dam Pool were brought to a common 1995 price
level using labor rate indices, and averaged for the period. Joint costs were
allocated to projects by prorating on the basis of at-site costs in proportion to the
at-site costs for all four projects.
• Allowances for Replacements after Year 2030 -based on the expected cost of
the next replacement to be made after the 35-year planning horizon (1996-
2030). The fund is calculated on an annual basis by determining the annual
payments to be made for each item in the "Replacements due to Normal Wear
and Tear" category so that sufficient funds have been accumulated for each item
to be replaced in the year at the time of next replacement (after year 2030). The
annual allowances are. determined so that the correct proportion of the total pay-
ments are made during the 35-year planning horizon. For example, if a replace-
ment was made in year 2020 and the next replacement is expected to be in year
2050, annual payments are calculated based on the complete 30-year period, but
the fund only includes those payments to be made during years 2021 through
2030, or one-third of the total payments. Once each individual item's fund has
been determined, all the items' funds are summed and lumped together in five
year increments. This analysis assumes a 4% real discount rate on annual pay-
ments with prices at the 1995 price level.
lJ6020~
7176/G 2028CIIA6.WP 6-14
Table 6-21 presents the results of the levelized payment analysis that was performed
for the two replacements funds: (1) the replacements due to normal wear and tear, and
(2) the allowances for replacements after 2030. The analysis was performed assuming
a 6 percent annual return on the average fund balance for the period, a 2 percent esca-
lation rate, and a 8 percent borrowing rate. The levelized amount was determined
using a repetitive trial and error approach so that the amount remaining in each fund at
the end of the 35-year planning horizon is zero. The actual accounting process used to
determine these values is presented on the 11Projected Most Likely Repair and Replace-
ment Costs 11 tables found in each of the four project chapters.
Table 6-22 presents a summary of expected costs for the remedial work items, the
project improvements, the two replacements funds, and the risk costs for each of the
four projects. In the case of the two replacement funds, the levelized costs are pre-
sented.
Also in the year 2030 time frame, the projects will be facing FERC relicensing issues,
and the associated costs can be considerable. These costs are difficult to predict,
because the regulatory framework and environmental policies will evolve over time.
Therefore, residual values associated with structures on regulatory requirements have
not been determined.
%02015
7176/G 2028CHA6.WP 6-15
Table 6-4
SWAN LAKE PROJECT· RISKS TO PROJECT COMPONENTS
Landslide or Volcanic Internal
Item Earthquake Flood Fire Rockfall ____1\\i_alanch e Tsunami Activity ~ ~ ~ Contamination Accidents ~
Dam and
SpillWay • • • •
Intake and
Tunnel • • •
Powerhouse Structures
(substructure, superstructure • • • • •
and roadways, docks and runways)
Powerhouse Mechanical • • • • • • •
and Electrical
Sw~chyard
at Powerhouse • • • • • • • •
T ransrnission
Line • • • • • • • • •
Bailey
Substation • • • • • • • •
Structure
Dam and
Spillway
Intake and
Tunnel
Table 6-5
Page 1 of 4
SWAN LAKE PROJECT-ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Condition of Occurrence Most Likely Estimate Low Likely High Low Likely High
Earthquake
No Damage 1 0.1
Minor 0.1
Moderate 0.01
Major 0.001 50,000 100,000 150,000 5
MCE 0.0001 150,000 300,000 34,200,000 15 30 1,100
Flood
No Damage 1 0.1
Minor 0.1
Moderate 0.01 1,500 3,000 4,500
Major 0.001 15,000 30,000 45,000 5
PMF 0.0001 150,000 300,000 34,200,000 15 30 1,100
Landslide/Rockfalls 0.02 0.5 35,000 50,000 100,000
Internal Failure 0.0001 0.1 500,000 1,000,000 34,200,000 60 180 365
Earthquake
No Damage 1 0.1
Minor 0.1
Moderate 0.01
Major 0.001 20,000 100,000 0 15
MCE 0.0001 100,000 200,000 15,400,000 15 30 1,100
Landslide/Rockfalls 0.02 0.5 35,000 50,000 100,000
Internal Failure 0.0001 0.1 500,000 1,000,000 15,400,000 60 180 360
Table6-5
Page 2 of4
SWAN LAKE PROJECT· ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Structure Condition of Occurrence Most Likely Estimate Low Likely High Low Likely High
Powerhouse Earthquake
Structures No Damage 1 0.1
(substructure, superstructure, Minor 0.1
and roadways, docks and runways) Moderate O.D1 20,000 40,000 60,000
Major 0.001 200,000 400,000 600,000 10 30 60
MCE 0.0001 3,450,000 6,900,000 13,800,000 120 240 360
Flood
No Damage 1 0.1
Minor 0.1
Moderate 0.01 10,000 20,000 30,000
Major 0.001 100,000 200,000 300,000 0 10
PMF 0.0001 500,000 1,000,000 1,500,000 10 30
Fire 0.005 0.1 5,000 10,000 9,867,000 7 30 360
Tsunami 0.02 0.1 100,000 200,000 1,000,000 7 14 120
Internal Failure 0.00001 0.1 600.000 1,200,000 13,800,000 60 90 180
Powerhouse Mechanical Earthquake
and Electrical No Damage 1 0.1
Minor 0.1
Moderate 0.01 20,000 40,000 60,000
Major 0.001 200,000 400,000 600,000 30 60
MCE 0.0001 1,342,500 2,685,000 5,370,000 120 180 360
Flood
No Damage 1 0.5
Minor 0.1
Moderate 0.01 20,000 40,000 60,000
Major 0.001 100.000 200,000 300,000 15 30
PMF 0.0001 671,250 1,342,500 2,685,000 30 60 90
Fire 0.005 0.1 10,000 50,000 1,000,000 2 7 30
Tsunami 0.02 0.1 100,000 200,000 300,000 7 14 30
Spills 0.01 0.1 2,000 10,000 20,000 0 0
Accidents 0.1 0.1 2,000 10,000 1,000,000 1.0 2
Internal Failure 0.02 0.1 100.000 200,000 1,000,000 30 60 90
Table 6-5
Page 3 of4
SWAN LAKE PROJECT-ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Structure Condition of Occurrence Most Likely Estimate Low Likely High Low Likely High
Switchyard Earthquake
at Powerhouse No Damage 1 0.5
Minor 0.1
Moderate 0.01 -10,000 40,000 -15 30
Major 0.001 40,000 100,000 200,000 30 90 150
MCE 0.0001 200,000 500,000 900,000 90 240 360
Fire 0.01 0.5 5,000 10,000 100,000 1 2 7
Tsunami 0.02 0.1 100,000 150,000 -7 30
Spills 0.01 0.1 5,000 30,000 60,000 2 7
Contamination 0.1 0.5 5,000 10,000 20,000 0 1
Snow 0.02 0.5 -2,000 5,000 0 2
Accidents 0.5 0.5 1,000 2,000 4,000 0.0 1
Internal Failure 0.5 0.5 20,000 40,000 60,000 1 7
Transmission Earthquake
Line No Damage 1 0.5
Minor 0.1
Moderate 0.01 -50,000 0 30
Major 0.001 50,000 600,000 600000 30 60 120
MCE 0.0001 1,000,000 2,000,000 7,500,000 90 135 180
Fire 0.01 0.5 10,000 30,000 60,000 4 10 30
Landslide/Rockfalls 0.01 0.5 100,000 500,000 1,200,000 5 20 60
Tsunami 0.02 0.1 200,000 300,000 30 90 150
Wind 0.25 0.5 25,000 40,000 100,000 2 3 6
Snow 0.5 0.5 15,000 45,000 120,000 4 6 12
Contamination 0.1 0.5 5,000 10,000 20,000 0 1
Accidents 0.01 0.1 1,000 100,000 1,000,000 1 30
Internal Failure 0.5 0.1 5,000 10,000 300,000 1 3 30
Structure
Bailey
Substation
Table6-5
Page 4 of4
SWAN LAKE PROJECT-ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Condition of Occurrence Most likely Estimate Low likely High Low likely ____!:!!2h
Earthquake
No Damage 1 0.5
Minor 0.1
Moderate O.o1 10,000 40,000 -15 30
Major 0.001 40,000 100,000 200,000 30 90 150
MCE 0.0001 200,000 500,000 900,000 90 240 360
Fire 0.01 0.5 5,000 10,000 100,000 1 2 7
Tsunami 0.02 0.1 100,000 150,000 7 30
Snow 0.02 0.5 2,000 5,000 0 2
Spills 0.01 0.5 5,000 30,000 60,000 -2 7
Contamination 0.1 0.5 5,000 10,000 20,000 0
Accidents 0.5 0.5 1,000 2,000 4,000 0 1
Internal F allure 0.5 0.5 20,000 40,000 60,000 1 7
Table 6-6
SWAN LAKE PROJECT-MEAN ANNUAL REPAIR COSTS
Landslide or Volcanic Internal
Item Earthquake Flood Fire Rockfall Avalanche Tsunami ~ 'Mnd Snow ~ Contamination Accidents Failure I TOTAL
Dam and
Spillway 468 1.760 t,171 140 I 3,539
Intake and
Tunnel 1,122 1.140 I 2.262
Powerhouse Structures
(substructure, superstructure 5,702 1,786 3,237 3,801 I 14,526
and roadways, docks and runways)
Powerhouse Mechanical 3,855 3,031 188 3,144 75 6,575 3,288 I 20,156
and Electrical
Switchyard
at Powerhouse 1,511 339 1,153 218 1,116 42 1,113 19,937 I 25,429
Transmission
line 4,806 313 5,831 2,238 12,576 28,112 1,138 933 11,794 I 67,741
Baily
Substation 1,478 270 1,249 46 302 1,146 1,123 20,262 25,876
SWAN TOTAL 18,942 6,577 4,347 8,142 11,585 12,576 28,376 1,493 2,326 9,744 55,421 159,529
Table fi~7
SWAN LAKE PROJECT· MEAN ANNUAL OUTAGE DAYS
Landslide or Volcanic lntemaf
"•m Earthquak-e Flood Fife ~ockfalt Avalanche Tsunami ~ Wind Snow ~ Contamination Accijenls Failure I TOTAL
Dam and
Sptllway 0.01 0.01 0.02 I 004
Intake tnd
Tunnel 0.01 I 0.01
Powemous,e Structures
(substruc:ture, super5tructure 0.18 • 027 0.41 I 0.88
and roadways, docks and runways)
Powemouse Mecttaotcal 0.21 0 09 0 02 0.24 o.oe U2 I 1.54
and Electrical
Swkcllyan:l
at Powertlouse 2.28 0.03 009 0.01 0.03 0.01 0.13 1.14 I 372
Transmission
Line 1.50 012 0.25 1.32 0.88 3.<9 0.03 0.03 1.75 I 9.37
Bolly
Substation 2.22 0.03 0 26 0.22 I 2.73
SWAN TOTAL 2.28 0.09 o.•7 0.25 1.32 0.88 3.50 0 03 0.04 o.•e 4.05 I 1339
Tobie 6_.
SOLOMON GULCH PROJECT • RISKS TO PROJECT COMPONENTS
landslide or Volcanic Internal
Item Eorth.!l!!!!l!_ ~ --B!!_ Rod<fall ~ ~ ~ ~ ~ ~ Contamination ~ ~
Dam. sp;11way,
Outlet and Penstock
through Oam • • • •
Penstock. Valves
and Valvehouse • • (ind_ loss of water to VFDA)
Powerhouse Structures
(substrudure, superstructure • • • • •
and roadways, docks and runways:)
Powerhouse Mechanicaf • • • • • • • •
and Electrical
Switchyard
at Powerhouse • • • • • • • •
Transmlsslon
Une • • • • • • • • • •
Meals
Substation • • • • • • •
PII
Substation • • • • • • •
P12
Substation • • • • • • •
Structure
Dam, Spillway,
Outlet and Penstock
through Dam
Penstock, Valves
and Valvehouse
Table 6-9
Page 1 of4
SOLOMON GULCH PROJECT. ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Condition of Occurrence Most Likely Estimate Low Likely High Low Likely
Earthquake
No Damage 1 0.1
Minor 0.1
Moderate 0.01 5,000 10,000 15,000
Major 0 001 50,000 100,000 150,000 5 10
MCE 0.0001 500,000 1,000,000 9,920,000 65 90
Flood
No Damage 1 0.1
Minor 0.1
Moderate 0.01 40.000 80,000 150,000
Major 0.001 70,000 150,000 250,000
PMF 0.0001 100,000 200,000 9,920,000 15 30
Landslide/Rockfalls 0.1 0.5 35,000 50,000 100,000
Internal Failure 0 0001 0.1 500,000 1,000,000 9,920,000 60 180
Earthquake
No Damage 1 0.1
Minor 0.1
Moderate 0.01
Major 0.001 100,000 200,000 300,000 10 20
MCE 0.0001 300,000 600,000 4,390,000 30 60
Internal Failure 0.00001 0.1 500,000 1,000,000 4,829,000 180 270
High
30
1,100
5
1,100
365
30
1,100
1,100
Table 6·9
Page2of4
SOLOMON GULCH PROJECT. ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Structure Condition of Occurrence Most Likely Estimate Low Likely High Low Likely
Powerhouse Earthquake
Structures No Damage 1 0.1
(substructure, superstructure, Minor 0.1
and roadways, docks, and runways) Moderate 0.01 20,000 40,000 60,000
Major 0.001 200,000 400,000 6,000,000 10 30
MCE 0.0001 2,285,500 4,405,000 8,810,000 120 240
Flood
No Damage 1 0.5
Minor 0.1
Moderate 0.01 10,000 20,000 30,000
Major 0.001 100,000 200,000 300,000 . 0
PMF 0.0001 500,000 1,000,000 1,500,000 10
Fire 0.005 0.1 5,000 10,000 6,299,150 7 30
Tsunami 0.04 0.1 100,000 400,000 8,810,000 7 14
Internal Failure 0.00001 0.1 600,000 1,200,000 8,810,000 60 90
Powerhouse Mechanical Earthquake
and Electrical No Damage 1 0.1
Minor 0.1
Moderate 0.01 20,000 40,000 60,000
Major 0.001 200,000 400,000 600,000 30
MCE 0.0001 852,500 1,705,000 3,410,000 120 180
Flood
No Damage 1 0.1
Minor 0.1
Moderate 0.01 20,000 40,000 60,000
Major 0.001 100,000 200,000 300,000 15
PMF 0.0001 426,000 852,000 1,705.000 30 60
Fire 0.005 0.1 10,000 50,000 1,000,000 2 7
Tsunami 0.02 0.1 100,000 200,000 300,000 7 14
Volcanic Activity 0.04 0.1 5,000 10,000 100,000 1
Spills 001 0.1 2,000 10,000 20.000 0
Accidents 0.1 0.1 2,000 10,000 1.000,000 1.0
Internal Failure 0 02 0.1 100,000 200,000 1,000,000 30 60
High
60
360
10
30
360
120
180
60
360
30
90
30
30
5
0
2
90
Structure
Switch yard
at Powerhouse
Transmission
Line
Table 6-9
Page 3 of 4
SOLOMON GULCH PROJECT· ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Condition of Occurrence Most Likely Estimate low likely High Low Likely
Earthquake
No Damage 1 0.5
Minor 0.1
Moderate 0.01 20,000 50,000 15
Major 0.001 45,000 90,000 150,000 30 90
MCE 0.0001 150,000 300,000 600,000 90 150
Fire 0 01 0.5 5,000 10,000 100,000 1 2
Tsunami 0.02 0.1 100,000 150,000 7
Spills 0.01 0.5 5,000 30,000 60,000 2
Contamination 0.1 0.5 5,000 10,000 20,000 0
Snow 0.02 0.5 2,000 5,000 0.0
Accidents 0.5 0.5 1,000 2,000 4,000 0.0
Internal Failure 0.5 0.5 20,000 40,000 60,000 1
Earthquake
No Damage 1 0.5
Minor 0.1
Moderate 0.01 100,000 0
Major 0.001 100,000 1,200,000 1,200,000 60 120
MCE 0.0001 2,000,000 4,000,000 15,000,000 180 270
Flood
No Damage 1 0.1
Minor 0.1
Moderate 0.01 20.000 50,000 100,000 0
Major 0.001 50,000 100,000 200,000 . 5
MCE 0.0001 100,000 200,000 300,000 5 10
Fire 0.01 0.5 10.000 30,000 60,000 4 10
Avalanche 0.02 0.1 100,000 400,000 1.700,000 30 120
Tsunami 0.02 0.1 200,000 300,000 30
Wind 0.5 0.5 25,000 40,000 100,000 2 3
Snow 1 0.5 15,000 45,000 120,000 4 6
Contamination 0.1 0.5 5,000 10,000 20,000 0
Accidents 0.01 0 1 1,000 10,000 1,000,000 1
Internal Failure 0.5 0.1 5,000 10,000 300,000 3
High
30
180
240
7.00
30
7
1
2
7
60
240
360
5
10
15
30
270
60
6
12
30
30
Structure
Meals
Substation
P11
Substation
P12
Substation
Table 6-9
Page 4 of4
SOLOMON GULCH PROJECT-ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Condition of Occurrence Most Likely Estimate Low Likely High Low Likely
Earthquake
No Damage 1 0.5
Minor 0.1
Moderate 0.01 20,000 50,000 15
Major 0.001 50,000 200,000 500,000 30 120
MCE 0 0001 500,000 1,000,000 2,100.000 120 240
Fire 0.01 0.5 5,000 10,000 100.000 1 2
Snow 0.02 0.5 2,000 5,000 0.0
Spills 0.01 0.5 5,000 30,000 60,000 2
Contamination 0.1 0.5 5,000 10,000 20,000 -' 0
Accidents 0.5 0.5 1,000 2,000 4,000 0.0
Internal Failure 0.5 0.5 20,000 40,000 60,000 1
Earthquake
No Damage 1 0.5
Minor 0.1
Moderate 0.01 20,000 50,000 15
Major 0.001 50,000 150,000 300,000 30 120
MCE 0.0001 350,000 800,000 1,800,000 120 240
Fire 0.01 0.5 5,000 10.000 100,000 1 2
Snow 0.02 0.5 2,000 5,000 00
Spills 0.01 0.5 5,000 30,000 60,000 2
Contamination 0.1 0.5 5.000 10,000 20,000 0
Accidents 0.5 0.5 1,000 2,000 4,000 0.0
Internal Failure 0.5 0.5 20,000 40,000 60,000 1
Earthquake
No Damage 1 0.5
Minor 0.1
Moderate 0.01 20,000 50,000 15
Major 0.001 50,000 200,000 500,000 30 120
MCE 0.0001 500,000 1,000,000 2,800,000 120 240
Fire 0.01 0.5 5,000 10.000 100,000 1 2
Snow 0.02 05 2,000 5,000 00
Spills 0 01 05 5,000 30,000 60,000 2
Contamination 0.1 0.5 5,000 10,000 20,000 0
Accidents 0.5 0.5 1,000 2,000 4,000 0.0
Internal Failure 05 0.5 20,000 40,000 60.000 1
High
30
180
360
7
2
7
7
30
180
360
7
2
7
7
30
180
360
7
2
7
7
Table 6-10
SOLOMON GULCH PROJECT-MEAN ANNUAL REPAIR COSTS
Landslide or Volcanic Internal
Item Earthquake Flood Fire Rod<fall Avalanche Tsunami ~ Wind Snow ~ Contamination Accidents Failure I TOTAL
Dam. Spillway,
OuUet and Penstock
through Dam 987 3,965 5,900 I 10.852
Penstock, Valves
and Valvehouse 897 I 897
Powerhouse Strudures
(substructure, superstructure 6,291 2.434 2.399 30,403 154 I 41,681
and roadways. docks and runways)
Powerhouse Mechanical 3.542 2,531 351 3,176 462 66 6,844 3,871 I 20,843
and Electrical
Sw~chyard
at Powerhouse 1,662 218 1,191 309 1,099 45 1,130 20,087 I 25,741
Transmission
Line 8.816 2.445 309 6,334 2,365 25,410 56,729 1,151 334 11,153 I 115,046
Meals
Substation 2,419 351 45 288 1,110 1,116 20,034 I 25,363
P11
Substation 2.077 355 45 329 1,135 1,115 20,181 I 25,237
P12
Substation 2.835 355 44 322 1,104 1.125 20019 25,804
SOLOMON GULCH TOTAL 29,526 11,375 4.338 5,900 6,334 37,135 462 25,410 57.172 2,104 4,545 11.664 95,499 291,464
Table 6-11
SOLOMON GULCH PROJECT· MEAN ANNUAL OUTAGE DAYS
Landslide or Volcanic Internal
Item Earthquake Flood Fire Rockfall Avalanche Tsunami ~ Wind Snow ~ Contamination Accidents Failure I TOTAL
Dam. Spillway,
Outlet and Penstock
lhrough Dam 0.29 0.02 I 0.31
Penstock. Valves
and Valve-house 0.10 I 0.10
Powerhouse Stnu::.turas
(substructure, superstructure 024 0.01 0.11 066 0.02 I 1.04
and roadways, docks and runways)
Powerhouse Mechanical 0.18 0.09 0.04 0.23 0.03 0.06 0.94 I 1.57
and Electrical
Switchyard
at PowerhOuse 2.23 003 0.09 0.03 003 0.01 013 116 I 3.71
Transmission
Line 3.20 0.05 0.16 176 0.36 1.74 702 0.03 0.02 150 I 15.64
Meals
Substation 2.34 0.03 0,01 003 0.03 0.13 1.09 I 3.66
P11
SubSiatlon 212 0.03 0.01 0.03 0.03 013 1.12 I 3.47
P12
Substation 2.41 0.03 001 0.02 003 013 110 I 3.73
SOLOMON GULCH TOTAL 3.20 0.09 043 1 76 066 003 174 7.08 0.11 013 060 6.93 I 22.76
Table 6·12
TERROR LAKE PROJECT· RISKS OF PROJECT FAILURE
Landslide or Volcanic Internal
Item Earthquake Flood Fire Rockfall Avalanche Tsunami Activity Wind Snow Spms Contamination Accidents Failure
Main Dam, Spillway
and Outlet Works • • • •
Intake, Gate and
Power Tunnel • • • •
Penstock, Valve and
Valvehouse • • • •
Powerhouse Structures
(substructure, superstructure • • • • • • and roadways, docks and runways)
Powerhouse Mechanical • • • • • • • • and Electrical
Switchyard
at Powerhouse • • • • • • • • • •
Transmission
Line • • • • • • • • •
Airport
Substation • • • • • • • •
Swampy Acres
Substation • • • • • • •
Table 6-13 Page 1 of 4
TERROR LAKE PROJECT· ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Structure Condition of Occurrence Most Likely Estimate LOW Likely High Low Likely High
Main Dam, Spillway Earthquake
and Outlet Works No Damage 1 0.1
Minor 0.1
Moderate 0.01 50,000 100,000 150,000 15
Major 0.001 500,000 1,000,000 1,500,000 15 90 365
MCE 0.0001 5,000,000 10,000,000 85,900,000 180 365 1,100
Flood
No Damage 1 0.1
Minor 0.1 26,000 45,000 70,000
Moderate 0.01 64,000 110,000 170,000 15
Major 0.001 290,000 515,000 790,000 15 90 365
PMF 0.0001 1,270,000 2.450,000 85,900,000 180 365 1,100
Landslide/Rockfalls 0.02 0.5 140,000 200,000 400,000
Internal Failure 0 0.1 500,000 1,000,000 85,900,000 60 180 360
Intake and Earthquake
Power Tunnel No Damage 1 0.1
Minor 0.1
Moderate 0.01
Major 0.001 225,000 450,000 675,000 10 20 60
MCE 0.0001 450,000 ~00,000 79,900,000 60 90 1,100
Landslide/Rockfalls 0.02 0.5 35,000 50,000 100,000 15 30
Avalanche 0.01 0.5 50,000 75,000 115,000 15 30
Internal Failure 0.02 0.1 500,000 1,000,000 79,900,000 60 180 360
Penstock, Valve and Earthquake
Valvehouse No Damage 1 0.1
Minor 0.1
Moderate 0.01
Major 0.001 50,000 100,000 150,000 10 20 30
MCE 0.0001 155,000 310,000 12,700,000 30 60 360
Landslide/Rockfalls 0.02 0.5 35,000 50,000 100,000 15 30
Avalanche 0.01 0.1 50,000 75,000 1,000,000 15 30
Internal Failure 0.00001 0.1 500.000 1,000,000 13,970,000 180 270 360
Table 6-13 Page 2of4
TERROR LAKE PROJECT· ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time {days)
Structure Condition of Occurrence Most Likely Estimate Low Likely High Low Likely High
Powerhouse Structures Earthquake
(substructure, superstructure, No Damage 1 0.1
and roadways, docks and runways) Minor 0.1
Moderate 0.01 20,000 40,000 60,000
Major 0.001 200,000 400,000 600,000 10 30 60
MCE 0.0001 3,850,000 7,700,000 15.400.000 120 240 360
Flood
No Damage 1 0.5
Minor 0.1
Moderate 0.01 100,000 200,000 500,000
Major 0.001 300,000 500,000 800,000 10
PMF 0.0001 1,000,000 2,000,000 3,000,000 10 30
Fire 0.005 0.1 5,000 10,000 11,011,000 7 30 360
landslidetRockfalls 0.02 0.5 35,000 50,000 100,000 15 30
Tsunami 0.02 0.1 100,000 200,000 1,000,000 7 14 120
Internal Failure 0.00001 0.1 600,000 1,220,000 15,400,000 60 90 180
Powerhouse Mechanical Earthquake
and Electrical No Damage 1 0.1
Minor 0.1
Moderate 0.01 20,000 40,000 60.000
Major 0.001 200,000 400,000 600.000 30 60
MCE 0.0001 1,067,500 2,135,000 4,270,000 120 180 360
Flood
No Damage 1 0.1
Minor 0.1
Moderate 0.01 20,000 40,000 60,000
Major 0001 100,000 200,000 300,000 15 30
PMF 0.0001 533,750 1,067,500 2,135,000 30 60 90
Fire 0.005 0.1 10,000 50,000 1,000,000 2 7 30
Tsunami 0.02 0.1 100,000 200,000 300,000 7 14 30
Volcanic Activity 0.04 0.1 5,000 10,000 100,000 1 5
Spills 0.01 0.1 2,000 10,000 20,000 0 0
Accidents 0.1 0.1 2,000 10,000 1,000,000 1.0 2
Internal Failure 0.02 0.1 100.000 200,000 1.000,000 30 60 90
Table 6-13 Page 3 of 4
TERROR LAKE PROJECT· ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Structure Condition of Occurrence Most likely Estimate Low Likely High Low Likely High
Switch yard Earthquake
at Powerhouse No Damage 1 0.5
Minor 0.1
Moderate 0.01 . 10,000 40,000 15 30
Major 0.001 40,000 100,000 200,000 30 90 150
MCE 0.0001 200,000 500,000 900,000 90 240 360
Flood
No Damage 1 0.1
Minor 0.1
Moderate 0.01 10,000 50,000 200,000 '2 7 90
Major 0.001 20,000 100.000 400,000 4 14 180
PMF 0.0001 40,000 200,000 800,000 8 28 360
Fire 001 0.5 5,000 10,000 100,000 1 2 7
Landslides 0.02 0.5 35,000 50,000 100,000 15 30
Tsunami 0.02 0.1 100,000 150,000 7 30
Contamination 0.1 0.5 5,000 10,000 20,000 0 1
Snow 0.02 05 2,000 5,000 0 2
Spills 0.01 0.5 5,000 30,000 60,000 2 7
Accidents 0.5 0.5 1,000 2,000 4,000 0.0 1
Internal Failure 0.5 0.5 20,000 40,000 60,000 1 7
Transmission Earthquake
line No Damage 1 0.5
Minor 0.1
Moderate 0.01 50,000 0 30
Major 0.001 50,000 600,000 1,000,000 30 60 120
MCE 0.0001 1,000,000 2,000,000 7,500,000 90 135 210
Flood
No Damage 1 0.1
Minor 0.1
Moderate 0.01 20.000 50,000 100,000 0 5
Major 0.001 50,000 100,000 200,000 5 10
MCE 0.0001 100,000 200,000 300,000 5 10 15
Fire 0.01 0.5 10,000 30,000 60,000 4 10 30
Tsunami 0.02 0.1 ' 200,000 300.000 30 60
Wind 0.25 0.5 25,000 40,000 100,000 2 3 6
Snow 0.5 0.5 15,000 45,000 120,0!)0 4 6 12
Contamination 0.1 0.5 5,000 10,000 20,000 0 1
Accidents 0.01 0.1 1,000 10,000 1,000,000 1 30
Internal Failure 0.5 0.1 5,000 10,000 300,000 3 30
Table 6-13
Page4 of4
TERROR LAKE PROJECT· ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Structure Condition of Occurrence Most Likely Estimate Low Likely High Low Likely High
Airport Earthquake
Substation No Damage 1 0.5
Minor 0.1
Moderate 0.01 10,000 20,000 15 30
Major 0.001 30.000 80,000 200,000 30 60 120
MCE 0.0001 100,000 200,000 500,000 90 240 360
Fire 0.01 0.5 5,000 10,000 100,000 1 2 7
Tsunami 0.02 0.1 100,000 150,000 7 30
Snow 0.02 0.5 2,000 5,000 0 2
Spills 0.01 0.5 5,000 30,000 60,000 2 7
Contamination 0.1 05 5,000 10,000 20,000 0
Accidents 0.5 0.5 1,000 2,000 4,000 0.0 1
Internal Failure 0.5 0.5 20,000 40,000 60,000 1 7
Swampy Acres Earthquake
Substation No Damage 1 0.5
Mmor 0.1
Moderate 0.01 10,000 40,000 15 30
Major 0 001 40,000 100,000 200,000 30 90 150
MCE 0.0001 200,000 800,000 1,500,000 90 240 360
Fire 0.01 0.5 5,000 10,000 100,000 1 2 7
Snow 0.02 0.5 2,000 5,000 0 2
Spills 0.01 0.5 5,000 30,000 60,000 1 2 7
Contamination 0.1 0.5 5,000 10,000 20,000 0
Accidents 0.5 0.5 1,000 2,000 4,000 0
Internal Failure 0.5 0.5 20,000 40,000 60,000 1 7
Table 6-14
TERROR LAKE PROJECT· MEAN ANNUAL REPAIR COSTS
Landslide or Volcanic Internal
Item Earthquake Flood Fire Rockfall Avalanche Tsunami ~ Wind Snow Spills Contamination Accidents Failure I TOTAL
Main Dam, Spillway
and Outlet Works 12,128 27,417 4,532 I 44,077
Intake, Gate and
Power Tunnel 2,024 1,207 827 106,606 I 110,664
Penstock. Valve and
Valvehouse 491 1,204 843 I 2,538
Powerhouse Structures
(substructure, superstructure 6,802 15,278 5,127 1,112 4,034 297 I 32,650
and roadways, docks and runways)
Powemouse Mechanical 3,952 2,799 147 3,329 538 77 4,738 3,435 I 19,015
and Electrical
Switchyard
at Powemouse 1,677 370 1,168 1,054 1,103 43 342 1,113 20,021 I 26,891
Transmission
line 5,080 2,378 290 2,202 12,501 28,216 1,134 611 10,946 I 63,358
Airport
Substation 1,105 387 1,121 51 282 1,096 1,110 20,117 I 25,269
Swampy Acres
Subslation 1,931 263 48 301 1,105 1,115 20,083 24,846
TERROR LAKE TOTAL 35.190 47,872 6,584 9,223 1,670 11,740 538 12,501 29.418 703 3,677 8,687 181,505 349,308
Table 6-15
TERROR LAKE PROJECT· MEAN ANNUAL OUTAGE DAYS
Landslide or Volcanic lntemal
Item Earth~ Flood Fire Rockfall Avalanche Tsunami ~ Wtnd Snow ~ Contamination Accidents Failure I TOTAL
Main Dam, Spillway
and Outlet Works 0.97 0 75 I 1.72
Intake, Gate and
Power Tunnel 0.15 028 0.16 2.57 I 316
Penstock, Vatve and
Valvehouse 012 031 0.09 I 052
Powerhouse Structures
(substructure, superstructure 027 0.22 0.29 0.36 0.03 I 1.17
and roadways, docks and runways)
Powerhouse Mechanical 0 26 0 08 0.04 023 0.03 006 0.94 I 164
and Eleclncal
Switchyard
at Powerhouse 2.33 0.03 0.32 0.11 0.03 0.01 0.03 0.13 1.16 I 415
Transmission
Line 189 0.05 0.12 0.34 0.87 350 0.03 0.01 1.49 I 830
Airport
Subs! alton 203 003 0.10 0.01 0.03 003 013 1 14 I 3.50
Swampy Acres
Substation 2 33 0.03 0.01 0.03 0.03 0.13 112 368
TERROR LAKE TOTAL 2.33 075 047 1 20 0.25 0.36 003 087 355 0.07 0.12 0.46 845 1891
Table 6-16
TYEE LAKE PROJECT -RISKS OF PROJECT FAILURE
Landslide or Volcanic Internal
Item Earthquake Flood Fire Rockfall Avalanche Tsunami Activity Wind Snow ~ Contamination ~ Failure
Intake and
Power Tunnel • • • • • Recognize potential rockfall
Penstock • •
Powerhouse Structures
(substructure, superstructure • • • • • • •
and roadways, docks and runways)
Powerhouse Mechanical • • • • • • •
and Electncal
Switchyard at
Powerhouse • • • • • • • • • •
Transmission
line • • • • • • • • • •
Submanne
Cable • • • • • •
Wrangell
Sw1tchyard • • • • • • • •
Wrangell
Substation • • • • • • • •
Petersburg
Substation • • • • • • • •
Table 6-17
Page 1 of 5
TYEE LAKE PROJECT· ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Structure Condition of Occurrence Most Likely Estimate low Likely High Low likely High
Intake and Earthquake
Power Tunnel No Damage 1 0.1
Minor 0.1
Moderate 0.01
Major 0.001 72,500 145,000 217,500 5 10 15
MCE 0.0001 145,000 290,000 53,600,000 25 35 1,100
landslide/Rockfalls 0.1 0.5 35,000 50,000 100,000 15 30
Avalanche 0.01 0.5 35,000 50,000 100,000 15 30
Accidents 0.01 0.5 . 30,000 1,000,000
Internal Failure 0.02 0.1 500,000 1,000,000 53,600,000 60 180 360
Penstock Earthquake
No Damage 1 0.1
Minor 0.1
Moderate 0.01
Major 0.001 72,500 145,000 217.500 5 10 15
MCE 0.0001 145,000 290,000 3,078,000 15 30 360
Internal Failure 0.00001 0.1 70,000 175,000 3,388,000 30 150 360
Powerhouse Structures Earthquake
(superstructure. superstructure, No Damage 1 0.1
and roadwayss. docks, and runways) Minor 0.1
Moderate 0.01 20,000 40,000 60,000
Major 0.001 200,000 400,000 600,000 10 30-60
MCE 0.0001 4,625,000 9,250,000 18,500,000 120 240 360
Flood
No Damage 1 0.5
Minor 0.1
Moderate 0.01 10,000 20,000 30,000
Major 0.001 100,000 200,000 300,000 10
PMF 0.0001 500,000 1.000.000 1,500,000 10 30
Fire 0.005 0.1 5,000 10,000 13,227,500 7 30 360
Tsunami 0.02 0.1 100,000 200,000 1,000,000 7 14 120
landslide/Rockfalls 0.02 0.5 35,000 50,000 100.000 15 30
Avalanche 0.02 0.1 35,000 50,000 300,000 15 90
Internal Failure 0.00001 0.1 600,000 1,200.000 18,500,000 60 90 180
Table 6-17 Page 2 of5 TYEE LAKE PROJECT· ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Structure Condition of Occurrence Most Likely Estimate Low Likely High Low Likely High
Powerhouse Mechanical Earthquake
and Electrical No Damage 1 0.1
Minor 0.1
Moderate O.o1 20,000 40,000 60,000
Major 0.001 200,000 400,000 600,000 30 60
MCE 0.0001 966,250 1,972,500 3,945,000 120 160 360
Flood
No Damage 1 0.1
Minor 0.1
Moderate 0.01 20,000 40,000 60,000
Major 0.001 100,000 200,000 300,000 15 30
PMF 0.0001 493,125 966,250 1,972,500 30 60 90
Fire 0.005 0.1 100,000 500,000 1,000,000 2 7 30
Tsunami 0.02 0.1 100,000 200,000 300,000 7 14 30
Spills 0.01 0.1 2,000 10,000 20,000 0.0 0
Accidents 0.1 0.1 2,000 10,000 1,000,000 1.0 2
Internal Failure 0.02 0.1 100,000 200,000 1,000,000 30 60 90
Switchyard at Earthquake
Powerhouse No Damage 1 OS
Minor 0.1
Moderate 0.01 20,000 50.000 15 30
Major 0.001 50,000 150,000 350,000 30 90 150
MCE 0.0001 500,000 1,000,000 1,900,000 90 240 360
Fire 0.01 0.5 5,000 10,000 100,000 1 2 7
Landslide 0.02 0.5 35,000 50,000 100,000 15 30
Avalanche 0.02 0.1 35,000 50,000 300,000 15 90
Tsunami 002 0.1 100,000 150,000 7 30
Snow 0.02 0.5 2,000 5,000 0.0 2
Spills 0.01 0.5 5,000 30,000 60,000 2.0 7
Contamination 0.1 0.5 5,000 10,000 20,000 0.1
Accidents 0.5 0.5 1,000 2,000 4,000 0.0 1
Internal Failure 0.5 0.5 20,000 40,000 60,000 1 7
Table 6-17
Page 3 of 5
TYEE LAKE PROJECT· ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Structure Condition of Occurrence Most Likely Estimate Low Likely High Low Likely ~h
Transmission Earthquake
Line No Damage 1 0.1
Minor 0.1
Moderate 0.01 40,000 200,000 30 60
Major 0.001 1,000,000 1,500,000 5.000,000 60 120 240
MCE 0.0001 4,000,000 8,000,000 18,000,000 180 270 360
Fire 0.01 0.5 10,000 30,000 60,000 4 10 30
Landslide 0.02 0.5 35,000 50,000 100,000 15 30
Avalanche 0.02 0.1 35,000 50,000 300,000 15 90
Tsunami 0.02 0.1 200,000 300,000 . 30 60
Wind 0.5 0.5 25,000 40,000 100,000 2 3 6
Snow 1 0.5 15,000 45,000 120,000 4 6 12
Contamination 0.1 0.5 5,000 10,000 20,000 0.1
Accidents 0.01 0.1 1,000 10,000 1,000,000 1 30
Internal Failure 0.5 0.1 5,000 10,000 300,000 3 30
Submarine Earthquake (included in the transmission line earthquake risk analysis)
Cable No 08/Tlage 1 0.1
Minor 0.1
Moderate 0.01
Major 0.001
MCE 0.0001
Fire 0.01 0.5 10,000 30,000 60,000 0
Tsunami 0.02 0.1 200,000 300,000 7 30
Spills 0.01 0.1 5,000 30,000 60,000 2.0 7
Accidents 0.01 0.1 50,000 200,000 1,000,000 0.5 1
Internal Failure 0.01 0.1 20,000 100,000 1,000,000 7 30
Table 6-17 Page4of 5 TYEE LAKE PROJECT· ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Structure Condition of Occurrence Most Likely Estimate Low Likely High Low likely High
Wrangell Earthquake
Switch yard No Damage 1 0.5
Minor 0.1
Moderate O.Q1 10,000 40,000 15 30
Major 0.001 40,000 120,000 300,000 30 90 150
MCE 0.0001 200,000 450,000 800,000 90 240 360
Fire 0.01 0.5 5,000 10,000 100,000 1 2 7
Tsunami 0.02 0.1 100,000 150,000 7 30
Snow 0.02 0.5 2,000 5,000 0.0 2
Spills 0.01 0.5 5,000 30,000 60,000 1 14 30
Contamination 0.1 0.5 5,000 10,000 20,000 0
Accidents 0.5 0.5 1,000 2,000 4,000 0.0 1
Internal Failure 0.5 0.5 20,000 40,000 60,000 1 7
Wrangell Earthquake
Substation No Damage 1 0.5
Minor 0.1
Moderate 0.01 10,000 40,000 15 30
Major 0.001 40,000 120,000 300,000 30 90 150
MCE 0.0001 150,000 350,000 700,000 90 240 360
Fire 0.01 0.5 5,000 10,000 100,000 1 2 7
Tsunami 0.02 0.1 100,000 150,000 7 30
Snow 0.04 0.5 2,000 5,000 00 2
Spills 0.01 0.5 5,000 30,000 60,000 2 7
Contamination 0.1 0.5 5,000 10,000 20,000 0
Accidents 0.5 0.5 1,000 2,000 4,000 0.0 1
Internal Failure 0.5 0.5 20,000 40.000 60,000 1 7
Structure
Petersburg
Substation
Table6-17
Page 5 of 5
TYEE LAKE PROJECT· ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$)
Condition of Occurrence Most Likely Estimate Low Likely High
Earthquake
No Damage 1 0.5
Minor 0.1
Moderate 0.01 20,000 50,000
Major 0.001 50,000 200,000 500,000
MCE 0.0001 500,000 1,000,000 2,100,000
Fire 0.01 0.5 5,000 10,000 100,000
Tsunami 0.02 0.1 100,000 150,000
Snow 0.02 0.5 2,000 5,000
Spills 0 01 0.5 5,000 30,000 60,000
Contamination 0.1 0.5 5,000 10,000 20,000
Accidents 0.5 0.5 1,000 2,000 4,000
Internal Failure 05 0.5 20,000 40,000 60,000
Expected Outage Time (days)
Low Likely ___!:!!2h
15 30
30 120 180
120 240 360
1 2 7
7 30
0.0 2
2 7
0
0.0 1
1 7
Table 6-18
TYEE LAKE PROJECT-MEAN ANNUAL REPAIR COSTS
Landslide or Volcanic Internal
Item Eart~ Flood Fire Rockfall Avalancile Tsunami Activity Vliind Snow ~ills Contamination Accidents Failure l TOTAL
Intake and Power Tunnel 57 5,823 592 3,090 67,734 77,296
Penstock 41 41
Powerhouse Structures 1,591 221 6,196 3,607 1,128 1,078 13,821
(substructure, superstructure,
and roadways, docks and runways)
Powerhouse Mecilanical 254 188 1,680 3,191 68 4,888 4,565 l 14,834
and Electrical
Switcilyard at Powerhouse 207 339 1,125 987 1,136 47 333 1,127 1,150 19,957 I 26,408
Transmissfon Line 1,180 321 1,096 1,041 2,340 26,013 56,112 1,146 562 10,752 100,563
Submanne Cable 322 2,618 178 1,979 1,446 6,543
Wrangell Switchyard 115 399 1,289 45 334 1,114 1,128 20,070 24,494
Wrangell Substation 36 364 1,136 85 323 1,097 1,119 19,841 I 24,003
Petersburg Substation 337 326 1,085 50 344 1,127 1,121 19,994 I 24,384
TYEE LAKE TOTAL 3,820 409 9,947 11,651 3.748 13,873 26,013 56,339 1,580 5,611 15,037 164,359 I 312,387
Table 6-19
TYEE LAKE PROJECT-MEAN ANNUAL OUTAGE DAYS
Landslide or Volcanic Internal
Item Earthquake Flood Fire Rockfall Avalanche Tsunami ~ Wind Snow SDIIIS Contamination Accidents Failure I TOTAL
Intake and Power Tunnel O.Q1 1.48 0 .14 2.62 4 .25
Penstock 0.01 0 .01
Powerhouse Structures 0 .08 0 .12 0 .25 0 .31 0 .28 1.02
(substructure, superstructure,
and roadways, docks and runways)
Powerhouse Mechanical 0 .04 0.02 0.03 0.24 0 .08 1.01 I 1.40
and Electrical
Swilchyard al Powerhouse 0 .03 0.03 0.30 0 .21 0.10 0.01 0 .02 0 .03 0 .13 1.13 I 1.99
Transmission Line 0.05 0.12 0.30 0 .22 0 .39 1.73 7.02 0 .03 0 .01 1.50 I 11 .37
Submarine Cable 0.11 0.01 0.04 I 0.18
Wrangell Switchyard 0 .08 0.03 0.13 0 .01 0.15 0 .03 0 .12 1.10 I 1.63
wrangell Substation 0.08 0.03 0.10 0.02 0.02 0 .03 0 .13 1.15 I 1.58
Petersburg Substation 0.04 0 .03 0 .10 0 .01 0.03 0 .03 0 .13 1.10 1.47
TYEE LAKE TOTAL 0 .08 0.02 0.39 2.33 0.88 0.39 1.73 7 .07 0.23 0.15 0 .58 9.65 ~b d--~l)>
Table 6-20
PROJECTED COSTS
(IN US DOLLARS, AT 1995 PRICE LEVELS, FOR FIVE-YEAR PERIODS INDICATED}
Year
ttem 1996-2000 2001-05 2006-10 201 f:15 2016-20 2026-30
SWAN LAKE
Remedial Work for Items of Deficient Design
Remed•al Work for Items of Deferred Maintenance 20,000
Other Project Improvements 2,067,000
Replacements due to Normal Wear and Tear 284.400 2,143.600 2.846,400 2,576,600 4,935,126 396,600
Allowances For Replacements After 2030 359,309 373,252 408,645 544.895 716,926 960,453 1,291,170
Normal Operation and Mamtenance Costs 6.643,730 6,643,730 6,643,730 6,643,730 6,643,730 6,643,730 6,643,730
R1sk Costs -~-~ _llfLg§ . .l!lJ~ _lllL!l42 ___l97.M.5 .
TOTAL SWAN LAKE 8,099,027 9,993,620 10,734,901 13,336,956 9, 129,145
SOLOMON GULCH
Remedial Work for Items of Deficient Design
Remed1al Work for Items of Deferred Maintenance
Other Project Improvements 2,047,700
Replacements due to Normal Wear and Tear 87,000 205,000 2,481.000 3.159.000 4,371,950 13,075,000 87,000
Allowances For Replacements After 2030 500,087 500,087 689,205 921,846 1.170,715 1,824,810 2,107,806
Normal Operation and Mamtenance Costs 6,815,030 6,815,030 6,815,030 6,815,030 6,815,030 6,815,030 6,815,030
Risk Costs _ l 4iiZ :l2ll 1 457 Q2J) 1 457 ~2Q l 4;iZ ~2Q l 457 32Q l 427 ~2Q --.l.A&32Jl
TOTAL SOLOMAN GULCH 10,907,137 8,977,437 11.442555 12,353,196 13,815,015 23,172,160 10,467,158
TERROR LAKE
Remedial Work for Items of Deficient DeSign
Remedial Work for ~ems of Deferred Maintenance
Other Project Improvements 5,207,000
Replacements due to Normal Wear and Tear 785,000 985,000 3,253,000 6.702,438 2,471,000 1,914,000 1,195,000
Allowances For Replacements After 2030 245,959 245,959 297,056 622,556 1,085,922 1,363,530 1,705,657
Normal Operation and Maintenance Costs 11,911,380 11,911,380 11,911,380 11,911,380 11,911,380 11,911,380 11,911,380
Risk Costs ~54Q 1 I42 ;\40 _ _J.lliMQ ~~Q _1.1.1~ 1 H2~~o ~4!1
TOTAl • TERROR LAKE 19,895,879 14,888.879 17,207,976 20,982,914 17,214,842 16,935,450 16558,577
TYEE LAKE
Remedial Work for Items of Deficient Design 17,000,000
Remedial Work for Items of Deferred Maintenance 565,000
Other Project Improvements 1,685,500
Replacements due to Normal Wear and Tear 880,000 920,000 2,839,000 4,940,000 20,574,344 7,636,408 807,500
Allowances For Replacements After 2030 405,592 405,592 508,316 790,337 1,535,548 2.765.926 3,183,308
Normal Operation and Maintenance Costs 8 760,110 8,760,110 8,760,110 8,760,110 8,760,110 8,760,110 8,760,110
Risk Costs 1 561 9~5 - 1 581 93~ 1 561 935 _1.561 935 l 561 93~ ,,,.,.1~2. ~3~
TOTAL· TYEE LAKE 30,858,137 11,647,637 13,669,361 16,052,382 32,431,937 20,724,379 14 312,853
All FOUR PROJECTS
Remedial Work for Items of Deficient Design 17,000,000
Remedial Work for Items of Deferred Maintenance 585,000
Other Project Improvements 11,007,200
Replacements due to Normal Wear and Tear 1,752 000 2.394.400 10.716.600 17,647,838 29,993 894 27,560,536 2,486,100
Allowances For Replacements After 2030 1,510,948 1.524.890 1,903,222 2,879,635 4,509,110 6.914,720 8.287.941
Normal Operation and Maintenance Costs 34.130,250 34,130.250 34.130,250 34,130,250 34,130 250 34,130,250 34,130.250
Risk Costs _2563AAQ _..2,5§;H4Q ,,:,;}i63. 440 _2.2'iH41! ·-· 5563 440 -.5.2'i3.44Q 5.5\13.440
TOTAl· All FOUR PROJECTS 71,548,838 43.612980 52 313,512 60,221,163 74,196,694 74,1£8,946 50.467.731
Table 6-21
REPLACEMENT COSTS-WITH ESCALATION AND LEVELIZING
(IN US DOLLARS, FOR FIVE-YEAR PERIODS INDICATED)
Year
Item Annual Contribution 1996-2000 2001-05 2006-10 2011-15 2016-20 2021-25
SWAN LAKE
Replacements due to Normal Wear and Tear 400,667 2,003,337 2,003,337 2,003,337 2,003,337 2,003,337 2,003,337
Allowances Fm Replacements After 2030 144Ji~4 ~.ill..§U __ 72Z.§.~ --~~ _ ... fll.Ei22. 722.622 Z22,6Z2
TOTAL-SWAN LAKE 545,192 2,725,959 2,725,959 2,725,959 2,725,959 2,725,959 2,725,959
SOLOMON GULCH
Replacements due to Normal Wear and Tear 665,113 3,325,566 3,325,566 3,325,566 3,325,566 3,325,566 3,325,566
Allowances For Replacements After 2030 ----~233.409 __ _1,167.044 _..ll§lJlM _l.16LQ.M ___1..16LQM. ___ L1§l.OM. ___ 1.16Ll!M
TOTAL-SOLOMAN GULCH 898,522 4,492,610 4,492,610 4,492,610 4.492,610 4,492,610 4,492,610
TERROR LAKE
Replacements due to Normal Wear and Tear 606,114 3,030,568 3,030,568 3,030,568 3,030,568 3,030,568 3,030,568
Allowances For Replacements After 2030 ____ __12§.lU!!. _ ___.L84.695 ___'llt~ _____1M~ __ .....lll_4~ __ 1!!.4..§.~ __ 1!!.4.§~
TOTAL-TERROR LAKE 763,053 3,815,263 3,815,263 3,815,263 3,815,263 3,815,263 3,815,263
TYEE LAKE
Replacements due to Normal Wear and Tear 1,175,440 5,877,200 5,877,200 5,877,200 5,877,200 5,877,200 5,877,200
Allowances For Replacements After 2030 ____ ....._..j§J..Q~4 _J.3J~m __1.312..m _...Lill.m. _1._312..122 _1.315122. _ __1.:U~22
TOTAL TYEE LAKE 1,438,464 7,192,322 7,192,322 7,192,322 7,192,322 7,192,322 7,192,322
All FOUR PROJECTS
Replacements due to Normal Wear and Tear 2,847,334 14,236,672 14,236,672 14,236,672 14,236,672 14,236,672 14,236,672
Allowances For Replacements Arter 2030 197,897 -3 98!1,483 3 9!!9,483 3 9!!1!. 48;) 3,!!.!!9,483 3,91!9 483 3 91!9,483
TOTAL ·ALL FOUR PROJECTS 3,645,231 18,226,155 18,226,155 18,226,155 18,226,155 18,226,155 18,226,155
Notes: Analysis assumes a 2% escalation rate, a 6% interest rate on available runds, and a 8% borrowing rate.
levelized payments are calculated using a repetitive trial and error approach so that the amount remaining in each lund at the end of the
35-year planning horizon is zero.
The levetized payment analyses for each project are shown on the "Projected Most likely Repair and Replacement Costs" tables in the
appropriate chapters.
2026-30
2,003,337
Z2Z,622
2,725,959
3,325,566
1.l6Z!H4
4,492,610
3,030,568
-~~
3,815,263
5,877,200
.......1..J.~2
7,192,322
14,236,672
3 1!.!!9 4!!3
18,226,155
Table 6-22
SUMMARY OF EXPECTED COSTS
(IN US DOLLARS, AT 1995 PRICE LEVELS)
Item
Period 1996-2000 (Total Cost)
Remedial Work for Items of Deficient Design (1)
Remedial Work for Items of Deferred Maintenance (1)
Other Project Improvements (1)
Subtotal
Period 1996-2030 (Annual Cost)
Replacements due to Normal Wear and Tear (2)
Allowances For Replacements After 2030 (2)
Subtotal
Period 1996-2030 (Annual Cost, not escalated)
Risk Costs (3)
(1)
(2)
(3)
I
I 100%
90% I I I I I I I 1 -----,-------r------,-------r ------,-------r ------,-------~--------------1
80%
I I I I I I I I I
___ J _______ L ______ J _______ L ______ J _______ L------~-------L------~-------1
: : : : : : : : I I
I
I
8 70% c
1 60%
w 50% '15
~ 40% 2! ~ 30% ~
20%
--~-------L------~-------L------~-------L------~-------L------~-------i I
I I I I I I I I I
------~-------L------~-------L------~-------~------~-------~------~-------1
I I I I I I I I :
------'-------~------~-------~------~-------~------~-------~------~-------! -----~------~-------~------~-------~------~-------~------~-------1
I I I I I
I I I I I I I I ---r------,-------r------,-------r------,-------r------,-------
1
I I I I I I I I -------,-------r------,-------r ------,-------r------,-------
1 I I I
10% ~-------~------J _______ L ______ J _______ L------~-------1
I I I I I I
·I 0%
0.0
I
0.7 0.8 0.9 0 .2 0 .3 0.4 0.5 0.6 0.1
Possible damage or repair coat in lilY year (In million$)
I Figure 6-1 Swan Lake Projed ·Expected Annual Costs Due to Natural Occurrences, Accidents or Equipment Failure
I
90%.-----~-------,-------------,-------.------,------,-------.------.-----~--------------,
I I I I I I I I I I I
80% -----~-----~--~---~-----~-----~-----~------~-----~-----~-----~------~-----1
I
I
I
I
I I I I I I I 1· I
___ - -.l. - - - --~ -- -- --'-- - ---L - ----J. - - ---_I---- -_I_ --- --L - - - - -J. - -- - -_I --- -- -'-- -- --
I
I I I I l I I I I . I I ----i ------, - -- ---,-- - ---l ------ - -- ---, - -- - --,---...... - -I - - - - -i' - - -- --,---- - -,--- ---
I I I
70% j
I ~ 60%
i 150%+
i 40% t ----~ -----~------:------~ -----~ -----~------I------~ -----~ -----~-- ----:------
~ 30% --- -J. -- - - --' - -- -- -
1----- - L - -- --J. - - - - --' - - - - - -:- - ----L _ --- _ .J. _____ -~ ______ '-____ _
Q.. I I I I l I I I I I I '
I I I I • I I I I I I I ::I~~~~~~-~~~~~~~~~~ I~~~~~ [ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ J ~~~~~I ~~~~~ [ ~ ~ ~ ~ ~ 1 ~~~~~I ~~~~ I~~~~~:
! I
D%t-----~----~~~~-------------------------------------------------------
I I I l
----T-----,------r-----r-----T-----,------r -----r -----~-----,------r-----
1
0 30 60 90 120 150 180 210 240 270 300 330 360
Possible number ol outage days in any year
Figure 6-2 Swan Lake Project-Expected Number of Outage Days Due to Natural Occurrences, Accidents or Equipment Failure
I
I
I
I
I
100%~~-----r--------.-------,--------,--------.--------r--------.--------------------------
I I I I I
: t ~ ~ ~ ~-~ ~:-~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~: ~ ~ ~ ~ ~ ~ ~ t. ~ ~ ~ ~ ~ ~ t ~ ~ ~ ~ ~ ~ t ~ ~ ~ ~ ~ ~ ~:~ ~ ~ ~ ~ ~ ~ r ~ ~ ~ ~ ~ ~;~ ~ ~ ~ ~ ~ ~ J
I I • I I I 1
~ 70%
• .,
5 60%
I ~ 50% '5
~
:! 40% .z
I e 30% 11.
20%
----L-------'----_--J..------_I_--_---.L. ______ -'-______ 1 ____ -_ -•-______ ..
I
--~------~-------~-------:-------~-------:-------~-------:-------~
I I I I I I I ' .... -------t-------t--------1-------1--------·-------. -------~--... -----
I I I I I
I : ----~-------~------~-------t ------~-------t-------:------1
-------,-------r------,-------r-------,-------r-------,-------r-------, .... ------~
I I
I I I I I . I I 1 I -------,----- --.i" - - - ----,-----I--- - ---,-------I - ------,-- -----I ----- --,--- --- -
I I I I I I I
10%
I 0%
0.0
--- - - -_)-- - -- --L - - --- --:-- -- -- -- ---:----- - -T - - - - ---:-- - - - - -~ - --- ---:-- - -- --i
0.1 0.4 1.0 0.5 0.2 0.3 0.6 0.7 0.8 0 .9
Possible damage or re1111ir cost in any y81r (in million$)
Figure 6-3 Solomon Gulch Project-Expected Annual Costs Due to Natural Occurrences, Accidents or Equipment Failure
I 100%.-----~,------.------------~-------.------------~------.-------,---------------------
1 I I I I t
--- --T - - -- -, ---- --, .... - ----r -----r -----1 ------,-- -- --,------r - -- - -.... -- --------•
I
I I I I I 1 I
-- - -T' -- -- --, - -- - --.- -- ---,-- ----r - -- - -1 - ----' - - ----,----- -r -----T ---- - - - --
I --:... ~-----~------:------:------r-----1------'------------~-----T -----------1
I o
I
60% ---T -- -- -, - -----:--- - --:------~ -----~ ------:------:- --- --~ - - ---I -----~ -- ----J
I I I 1 1 I I l •
50%+---·--~-----~------:------:------~-----~------,------:------~-----T-----~-----.... ,
~ : : : : : : : 1 , : 1 I
40% r -----'-----,------,------,------r-----i------,------,------r-----r -----.,------1
I ' I I I
I 30% _:_ --- -+ -----~ ------:------:------~ -----~ ------,------:------~ -----~ -----~ ------i
-----~-----~------~--~--~-----~-----~------~-----~-----t-----~-----4 20%~-----
I 1o% +------T---~------:------:------~------T------:------:------~-----~-----~------
I 0%~--~----~-=~~~4=~====~~~~--------------~---------J
0 30 60 90 120 150 180 210 240 270 300 330 360
I Possible number of outage days in any year
Flgure6-4 Solomon Gulch Project -Expected Number of Outage Days Due to Natural Occurrences, Accidents or Equipment Failure
I
I
I
I
I
I
I 100%~-------,-------.--------,--------r-------,,-------,--------r--------~----------------
I
90% -------1 -------:-------..;.-------:-------+-------:-------r-------:-------~------...
I I I I I I
I
I
I
80% - - - ---.J -- -----1-- - - - - -.1 - ------1-------l - - - ---· -'- - - - - - -L -- - ----'-- - -- --L -- ---_ -
I I I I I I I I I ~
I I I I I 1 I I I I s 70% - - - ----~---- --~--- - ---:-------~ - ------:-------~ ------~----- - -~ --- ---i 1 60% --- - -:-- - - - --~ -------:-------~ -------:-------~ ---- --~ --- - - - -~ - --- --~
1S 50% -- -~ -- - - - -~ - - - - - --:-- --- --~ - - - -- --:- - - - - - -~ - -- -- -~-- - - ---~ - ---- -~ f : t : : : : : : t:: : : : _ :: : -----; -------:------+ ------:-------f ------i-------f ------J
20% ----1 ~ ~: ~ ~ ~ ::: ~ ~ ~ ~ ~ ~ ~ ~: ~ ~ ~ ~ ::: ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~: r :: ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
I
0.0 0.1 0.2 0.3 0.<4 0.5 0.6 0.7 0.6 0 .9 1.0
Flgure6-5 Terror Lake Project-Expected Annual Costs Due to Natural Occurrences, Accidents or Equipment Failure
100%~-----.-------,------,------r------,------.-------.------,------r------~-------------
I
I
I
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I Figure 6-6 Terror Lake Project· Expected Number of Outage Days Due to Natural Occurrences, Accidents or Equipment Failure
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Possible damage or rept~ir coat In any year (in millionS)
Figure 6-7 Tyee Lake Project -Expected Annual Costs Due to Natural Occurrences, Accidents or Equipment Failure
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0 30 60 90 120 150 180 210 240 270 300 330 360
Possible number ol outage days In any year
Figure 6-8 Tyee Lake Project -Expected Number of Outage Days Due to Natural Occurrences, Accidents or Equipment Failure
---------~---~---·: __ _