risk assessment of the four dam pool hydroelectric projects
TRANSCRIPT
"'0 o·
Risk Assessment of the Four Dam Pool Hydroelectric Projects
Volume 1- Main Report
Prepared for
~
Solomon Gulch Project
the Alaska Energy Authority and the Four Dam Pool Project Management Committee
by
I-IARZA Engineering Company
February 1996
Swan Lake Project
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 Four Dam Pool Hydroelectric Projects Final Report
Gentlemen:
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 cany out this challenging assignment, and are confident that the infonnation 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
....
Mr. Daniel W. Beardsley Mr. Edwin K. Kozak: February 8, 1996 Page 2
Please do not hesitate to call me if you have any further questions.
Enclosure: As Noted cc: w/encl. Jack Quinn
Pat Hartel Dave Carlson Alan Dashen Thomas Friesen Lowell Highbargin Dennis Lewis Terry Nikodym Eric Redman Ron Saxton/Steve Stadum Rich Trimble Clayton Hurless/Robert A. Wilkinson
Very truly yours,
James T. Passage, P.E. President
"'0 o·
Risk Assessment of the Four Dam Pool Hydroelectric Projects
Volume 1- Main Report
Prepared for
~
Solomon Gulch Project
the Alaska Energy Authority and the Four Dam Pool Project Management Committee
by
l-IARZA Engineering Company
February 1996
Swan Lake Project
------.. ---.... Executive Summary
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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:
l. 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).
1
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 PI 1 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 PI 1 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,
3
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:
S wan Lake Proj ect -
Solomon Gulch Project -
Terror Lake Project -
Tyee Lake Project -
Four Dam Pool Total -
70.1 GWh per year
52.9 GWh per year.v:. ,3ctf-. 117.0 GWh per year I'
109.0 GWh per year
349.l GWh per year ~l..\1>J \00 J V
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
5
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 Proj ect 291,464 22.8 ? T error Lake Proj ect 349,308 18.9
Tyee Lake Project 312,387 23.5 -------- --\ 11'"::2)G<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 proj ects. 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.
7
Table 1
PROJECTED COSTS (IN US DOLLARS, AT 1995 PRICE LEVELS, FOR FIVE-YEAR PERIODS INDICATED)
Year
~em 1996-2000 2001-05 2006-10 2011-15 2016-20 2021-25 2026-30
SWANLAKE Remedial Work for Items of 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 After 2030 359,309 373,252 408,645 544,895 716,926 960,453 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 797 6~5 l'iJ.Z §~~ 191 §~5 IfJ.1645 797 §45 IfJ.l §~5 797 6~5 TOTAL - SWAN 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 ~~)3l,\ 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 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 1457320 1 ~~7 32Q 1451 nO 1 ~~7 320 1457320 1457320 1 ~51 32Q 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
~l5~ «:~ 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 F or Replacements After 2030 245,959 245,959 297,056 622,556 1,085,922 1,363,530 1,705,657 lOJ OW 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 1 746540 1 14§ ~~Q 1 7~6 540 l14654Q 1 746 :2~0 1 146540 1 14§ 5~Q 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 of Deficient Design 17,000,000
Remedial Work for Items of Deferred Maintenance 565,000 Other Projecllmprovements 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 1561935 1561935 1 561 93~ 1 5§1 935 1561935 1 :261 §1~5 1 561 9~5 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 r-'I~> _ <
'''' , ~ 'f' 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 )-7, 5::.) I -+ {., 0 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 \ 7 ")
Risk Costs :2 56~ 440 5 ~6~44o 5563440 5563440 ~ 563 440 5563440 5563440 -2] ~(
TOTAL - ALL FOUR PROJECTS 71,548,838 43,612,980 52,313,512 60,221,163 74,196,694 74,168,946 50,467,731
C'?)! ~<
Table 2
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 2067000 2,087,000
400,667 144524 545,192
159,529
2 Q4Z ZQQ 5 2QZ QQQ 2,047,700 5,207,000
665,113 ~06,114 2334Q9 56:ro9 898,522 763,053
291,464 349,308
17,000,000 565,000
16855QQ 19,250,500
1,175,440 263 Q24
1,438,464
312,387
(1) Based a several expenditures to take place in the period 1996-2000, at 1995 price levels
d.})~~7) '3~\1
( i Gt7)Rq7
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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
- \
17,000,000 585,000
11 QQZ 2QQ 28,592,200 2.2c,] ~333\J
~ ~~ 3, , 1
1,112,688 lOY. y' cft~)
Figure 1 - Range of Expected Annual Costs and Outage Days
Range of Expected Annual Costs Range of Expected Number of Outage Days
100% 100%
90% 90%
80% 80%
3 c: .. " ., 60% 8 " UJ 50% '3 ~ :0 .. .0 30% e a.
20%
10%
0%
~ 700/0 .. " 860%
" ~ 50%
\ ~ 40% .0
~ .. 1l30% a. \ 20%
'" 10%
0% "'--
SWAN LAKE SWAN LAKE
•
0.0 0.1 0.2 0.3 0.4 O.S 0.6 0.7 0.8 0.9 1.0 0 30 60 90 120 ISO 180 210 240 270 300 330 360, Possible damage or repair cost in any year (in millionS) Possible number of outage days in any year
100% 100% i
90% 90% ~ ______________________________________________________ ~I I
80% 80%
~70% '" " 860%
" ~SO% 0
SOLOMON GULCH ., g 70% '" " 860%
" I
~ SO%
H----------------:. SOLOMON GULCH ~. -
~40% .0
'" .g300/0~ a: I
~ 40% .0
'" e 30% a.
~~----------------.---------~---
20% 20%
10% 10%
0% I 0% , 0.0 0.1 0.9 1. 0 30 60 90 120 ISO 180 210 240 270 300 330 360 I
Possible number of outage days in any year
100% 100% I
90% 90%
80% 80%
~70% '" " ~60% " ~SO% 0 >-
I ~40% .0
'" 1l30% a.
20%
10%
0% I
TERROR LAKE ., g 70% .. " 860%
" ~50% ~40% .0
'" 1l 3O% a.
20%
10%
0%
i TERROR LAKE f-----
I I
! I
~\ \ I
-------J \ I
I
! '- i 0.0 0.1 0.2 0.3 0.4 O.S 0.6 0.7 0.8 0.9 1.0 o 30 60 90 120 ISO 180 210 240 270 300 330 360 i
Possible damage or repair cost in any year (in millionS) Possible number of outage days in any year
100% 100%
90% 90%
80% 80%
8 70% c: '"
TYEE LAKE ~ 70% J_ c: '"
TYEE LAKE
" 60% ., ~ UJ SO% '3
I ~60% I " ~SO%
~ 40% :0 '" I .0 e 30%L-a.
~40% I .. .0
£30%
20% 20%
10% 10%
0% 0%
0.0 0.1 0.2 0.3 0.4 O.S 0.6 0.7 0.8 0.9 1.0 0 30 60 90 120 ISO 180 210 240 270 300 330 360 Possible damage or repair cost in any year (in millionS) Possible number of outage days in any year
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: SW AN 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
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Page No.
1-1 1-2 1-3 1-3 1-5 1-6 1-7 1-7 1-7 1-8 1-8 1-9
2-1 2-1 2-1 2-3 2-4 2-4 2-6 2-6 2-6
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 3.2.2 Existing Generation Potential 3.2.3 Effects of Drought 3.2.4 Potential for ExpanSion
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2-8 2-8 -2-9 ... ' 2-9 -2-10 ....
2-11 2-13 .. 2-14 .... 2-16 2-16 -2-17 .. 2-18 -2-18 .. 2-18 2-18 ., 2-19 -2-19 2-19 • 2-19 • 2-20 • 2-21 ... 2-22 2-22 • 2-23 • 2-23 2-24 --
• •
3-1 3-1 • 3-1 ... 3-3 • 3-4 3-5 • --
• -• -
TABLE OF CONTENTS (Cont'd)
3.3 Generating Unit and Transmission System Availability 3.3.1 Generating Unit Availability
3-6 3-6 3-7 3-7 3-7 3-8 3-8
3.3.2 Transmission System Availability 3.4 Condition Assessment, Recommendations, and Costs
3.4.1 Site Inspection Dates
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3.4.2 Reservoir 3.4.3 Powerhouse 3.4.4 Dam 3.4.5 Dike 3.4.6 Spillway
3-10 3-11 3-12
3.4.7 Power Intake 3-12 3.4.8 Penstocks 3-13 3.4.9 Turbines 3-16 3.4.10 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 Transfonner 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 3.4.23 P12 Substation 3.4.24 Pll Substation 3.4.25 Mile 26 Tap 3.4.26 Rolling Stock 3.4.27Infrastructure 3.4.28 Documentation 3.4.29 Conclusions
3-24 3-24 3-24 3-25 3-25 3-26 3-26 3-26
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• -•
TABLE OF CONTENTS (Cont'd) ---Chapter 4: TERROR LAKE PROJECT -4.1 Project Description 4-1 ... 4.2 Installed Capacity and Energy Generation 4-3 -4.2.1 Monthly Flows 4-3 -4.2.2 Existing Generation Potential 4-4
4.2.3 Effects of Drought 4-4 -4.2.4 Potential for Expansion 4-5 .. 4.3 Generating Unit and Transmission System Availability 4-6
4.3.1 Generating Unit Availability 4-7 • 4.3.2 Transmission System Availability 4-7 •
4.4 Condition Assessment, Recommendations, and Costs 4-7 • 4.4.1 Site Inspection Dates 4-7 • 4.4.2 Reservoir 4-8 4.4.3 Dam and Spillway 4-9 • 4.4.4 Main Dam Low-Level Outlet Works 4-10 .. 4.4.5 Main Tunnel Intake Gatehouse 4-11
4.4.6 Main Tunnel 4-12 • 4.4.7 Shotgun Creek Diversion 4-13
., 4.4.8 Falls Creek Diversion 4-14 • 4.4.9 Rolling Rock Creek Diversion 4-15 .. 4.4.10 Penstock and Intake Portal 4-16 4.4.11 Powerhouse 4-17 • 4.4.12 Miscellaneous Facilities 4-17 .. 4.4.13 Access Road 4-18 4.4.14 Turbines 4-18 • 4.4.15 Governors 4-20 • 4.4.16 Spherical Valves 4-20 • 4.4.17 Powerhouse Auxiliary Mechanical Equipment 4-21 • 4.4.18 Generators 4-21 4.4.19 Station Service Transformer and Switchgear 4-22 .. 4.4.20 DC System 4-23 • 4.4.21 SCADA System 4-23 .. 4.4.22 Communications 4-23 4.4.23 Emergency Generator 4-23 • 4.4.24 Controls 4-24 -..
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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 5-13 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 5-17 5.4.12 Station Service, Transformer and Equipment 5-18 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
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
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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)
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 Components 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)
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 Equipment Failure
6-4 Solomon Gulch Project - Range of Annual Outage Days due to Natural Events or Equipment Failures
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TABLE OF CONTENTS (Cont'd)
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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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 commissioned jointly by the Alaska Energy Authority and the Four Dam Pool Management Committee. The results of this study will be used to help establish the costs associated 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 operation 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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3.
4.
Identifying the needs and costs of repair and replacement, both in the short term and the long term,
Assessing the probabilities, costs, and outage durations associated with natural 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 improvements 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, licenses 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. Based on industry standards, and considering local conditions, the expected service life, remaining service life, and replacement costs of major mechanical and electrical equipment, were estimated. The analysis performed under this section assumed that there are no items of deferred maintenance, substandard design or design deficiencies.
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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 deferred maintenance were estimated.
4. Other factors requiring remedial action, as well as any factors that may reduce 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 Management Committee. Site visits and inspections were conducted as indicated in Table 1-1.
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Site visits were conducted primarily to assess the condition of each project, as described 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. Assessment of the conditions of the items that could not be physically inspected was based on the observations of related structural elements 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 PERSONNEL
Engineering Discipline
Civil/Structural
N, Pansic
Oct 18 & 19. 1995
Mechan.ical Electrical
1.H.T. Sun J.J. Quinn
Oct 16 & 17, 1995 Oct 16 & 17, 1995
Transmission
A. Angelos
Oct 18 & 19, 1995
N. Pansic
Oct 9 & 10. 1995
1.H.T. Sun
Oct 5 & 6, 1995
1.1. Quinn P. DonaleklA. Angelos
N. Pansic
Oct 11 & 12. 1995
N. Pansic
Oct 16 & 17. 1995
Oct 5 & 6, 1995 Oct 9, 10 and 23, 1995
1.H.T. Sun 1.1. Quinn
Oct 2 & 3. 1995 Oct 2 & 3. 1995
1.H.T. Sun J.J. Quinn
Oct 18 & 19, 1995 Oct 18 & 19. 1995
P. 1. Donalek
Oct 11 and 12, 1995
A. Angelos
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.1. 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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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 nonnally 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 Chapters 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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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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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
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7176/G 2028CHI.WP 1-9
Mr. Edwin K. Kozak
General Manager
Kodiak Electric Association
Harza Personnel:
Project Sponsor:
Project Manager and Electrical Engineer:
Mechanical Engineer:
Transmission Engineers:
James T. Passage
Jack J. Quinn
James H. T. Sun
Andy Angelos
Peter J. Donalek
Civil/Structural Engineers: Nicholas Panslc
W. James Marold
Hydroelectric Planning Engineer: Lee L. Wang
Risk Assessment and Report Production: Patrick G. Hartel
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Kirk Peterson
Joe Moawad
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Chapter 2
SWAN LAKE
2.1 Project Description
This project is located on Revillagigedo Island at the head of Carroll Inlet, approximately 22 air miles northwest of Ketchikan, Alaska. The project consists of a concrete 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 substation in Ketchikan. The project general arrangement and sections of major project features are illustrated on the project drawings included in Appendix B. Table 2-1 presents 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 MV A. The turbines were manufactured 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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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 330 ft 174 ft 480 ft
6 ft 18 ft
Ungated concrete ogee overflow 100 ft 330 ft
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
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The average flow at the project site, based on data shown on Figure 2-1, is approximately 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 increased production to meet electrical demands. The maximum powerplant discharge capacity is approximately 1, 100 cfs. The average historical flow for the period analyzed 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 furnished by AEA, is listed in Table 2-2.
Based on limited flow data gathered for this study, a preliminary estimate of the energy generation potential of the existing project, assuming that all of the available energy 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
6/30/92 57,122,422
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
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7176/02028SWAN.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 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 definition 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 investigation. Also shown in the figure is the hydraulic capacity of the powerplant.
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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 capacity 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 additional 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 obtainable 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-MVA expansion (Le. 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 substantially.
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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 unscheduled maintenance.
Table 2-3 SWAN LAKE PROJECT - ANNUAL OUTAGE TIME
Year
1990 1991 1992 1993 1994 1995 (up to 10/6/95)
Outage Time (hours)
12.3 469.3
1.4 564.5
3182.0 235.3
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 October 1995. Because of this event, the plant was off-line for about 222 hours.
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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
11191
4/93
5/93
7/93
9/93
2/94
4/94
6/94
8/95
10/95
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71761G 2028SW AN .WP
UNIT 1
?
Table 2-4
SW AN LAKE PROJECT - SIGNIFICANT OUT AGE EVENTS
DURATION DESCRIPTION OF OUTAGE DATA SOURCE
UNIT 2 OF OUTAGE
? Almost I year Intake gate removed and inspected. FERC
3 days Unknown. Narrative
153 hours Collector ring insulation repair. Outagf' Rt'cords
153 hours Collector ring insulation repair (schOO- Outage Records
uled maintenance).
Unknown Modification of the collector rings. FERC
156 hours Inspection of burnt windings. Outage Records
32 hours Inspection for possible future rewind. Outage Records
32 hours Insurance inspection. Outage Records
150 hours Scheduled repairs to draft tube. Outage Records
255 hours Scheduled repairs. Outage Rt'cords
122 hours Exciter troublt'. Outage Records
2.950 hours Scheduled generator rt'w indo Outagt' Records
66 hours Tunnel inspection. Outage Records
9 days Unknown. Narratiw
222 hours Transmission line fire. Outagf' 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 recommended 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 ABA, 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 October 18.
On October 18 and 19, 1995, N. Pansic of Harza inspected the civil and stmctural features of the project and A. Angelos of Harza inspected the transmission line and substation equipment.
The transmission line, civil and stmcture 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 stmctures - 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, ABA Consultant, accompanied the site inspection team. On the helicopter reconnaissance, only Remy Williams accompanied the team.
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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 Foreman, and Remy G. Williams accompanied the team.
2.4.2 Reservoir
Condition Assessment. The valley walls surrounding the reservoir are steep to moderately 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 opportunity for any significant landslide which could impact the dam or gatehouse. The consequences of any landslide would likely be minor.
A seismic event could possibly cause one of the rock outcrops to slide into the reservoir, 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 common. Hence, it is unlikely that any significant snow avalanches would endanger project 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
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occurred around the penstock penetrations, but recent epoxy patching seems to have solved the problem. The inspection revealed other minor groundwater seeps. Groundwater 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 constructed atop a concrete gate shaft. The gatehouse was inspected only from the operating 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 powerhouse. 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 closure system uses a hydraulic brake which allows the gate to close in a controlled manner when activated.
The gate is a 15 ft wide by 19 ft high slide gate with a hydraulic operator. It is normally 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.
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•
.. -;w,
.. ... '
-.. ' -.. .. • • • • • • • • • .. • .. • .. • • -• ---.,
2.4.5 Dam
Condition Assessment. The dam has a high hazard! 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 August, 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 abutments. 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 ·jam.
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.
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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 32 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 conservative 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. If 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 acceptable 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 progressive 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 Chapter 6.
Recommendation. Flow measuring weirs are planned for construction on both abutments 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
•
2 No cost has been assigned to this item since soundings could probably be done by plant maintenance personnel using a small boat.
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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 runners do not show any signs of cavitation and/or erosion. Runner wearing ring clearances 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 perfonned in April and November 1994, the measured amplitudes of vibration were within acceptable limits. However, overhauling the Unit 1 guide bearing is recommended if cracks are found in the Babbitt metal.
During the inspection, plant operators asked about the possibility of adding compressed 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 includes piping that permits admission of air at atmospheric pressure. This system usually functions well at low tide, when the pressure in the draft tube is less than atmospheric 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. Modification 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 system3
•
This test should be with the compressed air pressure slightly above the maximum tail water pressure. Installation of such a system could slightly extend the life of the turbines and improve operating characteristics.
Utility personnel indicate that the station compressed air system may not be adequate to provide sufficient air to run the test.
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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 S wan Lake turbines, and could not be supported by the field test results.
Based on the expected turbine perfonnance and current turbine conditions, the estimated 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 304 ft.
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 perfonnance.
2.4.7 Generators
Condition Assessment. The generators have a continuous overload rating of 115 percent 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 transfonners 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.
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•
• .. ----
-•
• lit
• • --., • • • • --.. • -• .. -• •
Unit 2 stator windings were replaced in 1994 after an internal fault. During this outage, 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 specifications. Readjustment of the bearing settings could place undue stress on other generator 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, respectively. 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 induded 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.
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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 thennal 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 Company. 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 perfonned on both governors. The governors are kept very clean and in good operating condition.
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 satisfactory. 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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-...
... -... -.. -.... .. •
• •
-• •
• -• .,
-.. .,
--.. •
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 operating 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 pressure 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 mbber 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. Replacement 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 system supplied from the Unit 2 penstock and connected to the existing cooling water system.
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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 6O-cell battery bank and two battery chargers. The battery chargers normally supply the DC power to the system 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 decreasing 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 reliable 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-
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---
-
-w·
•
.. -.. .. -•
• -.. .. •
--., .. • •
.. ly investigating a dial-up satellite communication system as a backup to the microwave 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, replacement 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 power 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 OAIFA 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 transformers is such that the cooling fans never operate automatically. Plant personnel routinely operate the fans manually to verify their operation.
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The rating of the transformers limits the Swan Lake power output to 25 MV A.
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. Landslides 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.
2.
Conduct a geotechnical investigation of the area to establish the degree of soil stability.
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 insulator assemblies appear to be bonded and connected to ground.
Recommendation. The following are recommended:
1.
2.
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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.
If the utility experiences any additional fires on the wood poles, then a program should be implemented to connect the insulator attachment to ground.
7176/G 2028SWAN.WP 2-20
..
..
.. -. -.. .. .. • .. ., .. • .. ---•
• • -.. .. • .. -.. .. .. • •
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. Another 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 necessary, 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 stmctures.
2.4.20 Bailey Substation
Condition Assessment. Overall, the substation appears to be in good condition. Grading and drainage are adequate. Oil recovery facilities are in place. There is a high
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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. Additional 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:
1. Pickup truck - fairly new and in good condition;
2. Boom tmck - good condition;
3. Backhoe - good condition;
4. Front-end loader - inadequate for application;
5. Forklift - fair operating condition;
960208
7176/G 2028SW AN.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 service lives of these facilities, 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 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.
96020g
7176/02028SWAN.wP 2-23
2.4.25 Conclusions
Table 2-5 lists the major project equipment, and provides an assessment of the condition 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 deficient 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 maintenance, other general project improvements, and replacements due to normal wear and tear is presented in Table 2-6.
960208
7176/G 2U28SWA1-lWP 2-24
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Table 2-5 Page 1 of 2
,<~"lj SWAN 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
(years) (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
l""il 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 2 012
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 2-6
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, acckients or equipment failures)
Structure 1996-2000 2001-05 2006-10 2011-15 2016-20 2021-25 2026-30
Remedial Work tor Items or Deficient Design None
Remedial Work tor Items or Deterred Maintenance Replace corroded cooling radiators at Bailey substation 20,000
Other Project Improvements Structures
Improve reservoir trash handling system 290,000 Construct flow measuring weirs downstream or dam bUdgeted Improve access to left abutment or dam 30,000 Take soundings In plunge pool a Test use at compressed air tor turbine performance a
Equipment OVerhaul unit 1 turbine gukte bearing 10,000 Install coolers on generator unit 1 lower gukte bearing budgeted Replace exc~ation power supply (2 un~) 60,000 Replace 011 reservoir temperature sensing device 400 Replace draft tube gate budgeted Connect cooling water system to unit 2 penstock 35,000 Replace 125 V-battery 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 investtgation of landslide by Carroll Inlet 25,000 Relocate 1 to 2 miles of line to avokf aVCIlanche outage 1,000,000 Test insulator assemblies and eVCIluate wood pole fire potential 20,000 Install groundtng wire and connect to insulator hardware 100,000 b Cost for steel pole spares (6 poles) 20,000 Steel pipe sleeves (spares) for use with existing steel ·can" 20,000 Install brace on suspension H-frame structures 80,000 Install additional guy wires on selected structures 60,000 Bailey substation· paint transformer tanks 5,000
Complete As-Built drawings 20,000
Replacements due to Normal Wear and Tear Structures
Walkway to left abutment 30,000 b Epoxy patching - powerhouse backwall 20,000 20,000 20,000 Architectural refurbishment 200,000
EqUipment Turbine and other Mechanical Items
Tumine Runner and Wicket Gates Governor Inlet Valve Draft Tube Gates Cooling Water Syslem 85,000 other Auxiliary Mechankal Equipment 345,000
Generator Stator 500,000 500,000 Rotor 410,000 Beanngs 400,000 Cooling System 150,000 RTOs, Sensing DeVices 7,000
Depreciation Depreciation Used Available
Next Reelacement Throu2h 2030 Mer 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
Ul 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 3033
Table 2-3
Page 2 of 3
SWAN LAKE PROJECT· PROJECTED MOST LIKELY REPAIR AND REPLACEMENT COSTS (in US dollars, at 1995 price lellels, excluding repairs or replacements due to natural events, accidents or equipment failures)
Depreciation Deprectati(.lfl Used AvaHable
Structure 1996-2000 2001·05 2006-10 2011-15 2016-20 2021-25 2026-30 Next Re~lacement Throuah 2030 After 2030
Fire Protection 5,000 2053; Check C02 gas annually 1,714 3,286
Excitation 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 SWitchgear 100,000 2033 88,000 12,000
Cable System 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
Communk:ations 150,000 150,000 2038 70,000 80,000 Emergency Generator 200,000 2043 113,333 86,667
Swttchyard, Transmission Line and Substation Equipment Powerhouse SWltchyard
Transformers 350,000 2043 198,333 151,667
Circuit Breakers 76,000 2033 66,880 9,120
Disconnect SW~ches 30,000 2053 10,286 19,714
PTs, CT" Wa,e Traps 100,000 2043 56,667 43,333 8us 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 CircuM Breakers 76,000 2033 66,880 9,120
Disconnect SWitches 30,000 2053 10,286 19,714
PTs, CTs, Wa'e 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 Replacement ellery 10 years 12,600 12,600
Boom Truck 91,200 91,200 91,200 Replacement e,ery 10 years 45,600 45,600
Back Hoe 90,000 90,000 90,000 90,000 Replacement e,ery 8 years 33,750 56,250
Front End Loader 231,600 231,600 231,600 Replacement e'ery 10 years 231,600
Forklift 40,000 40,000 40,000 Replacement e,ery 10 years 20,000 20,000
Four-Wheel Vehicle 6,000 6,000 6,000 Replacement e,ery 10 years 3,000 3,000
Skill 12,000 12,000 12,000 Replacement ""ery 12 years 5,000 7,000
Tugboat 40,000 2036 28,000 12,000
Logskidder 25,000 b 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 ~
, , I • I , I , I I • I , II I I I 1 , , , , I I , I
Structure
Table 2~
Page 3 01 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, acck:Jents or equipment failures)
1996-2000 2001·05 200&-10 2011-15 201&-20 2021-25 202&-30
5·YR TOTALS Remedial Work tor Items or Deficient Design
Remedial Work tor Items at Deterred 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 After 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)
Beginning or PerHld Fund Balance 2,394,116 5,201,112 6,051,719 5,650,771 5,116,978 (1,074,131) Annual Conlribulion 01 5400,667 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 Balance 390,778 1,136,879 1,620,245 1,661,076 1,525,908 397,731 (166,850)
End 01 Period Fund Balance 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 $144,524 to Reserve Fund 722,622 722,622 722,622 722,622 722,622 722,622 722,622 Expense (381,898) (437,495) (530,198) (782,090) (1,132,910) (1,680,906) (2,484,013)
Interest on Average Fund Balance 69,092 195.432 344,897 485,772 556,954 522,539 196,473 End of Period Fund Balance 409,816 890,374 1.427,694 1,853,998 2,000,663 1,564,918 (0)
Next Ree;lacement
OEPREClA TION TOTALS:
a Indicates that the cost tor this item is assumed to be included as a part 01 the normal operations budget and the required activities can be carried out by plant personnel as part of day-t~day activities. b Indicates an item that rs contingent on implementation ot a recommended project improvement.
(1) Calculated in 1995$, using a 4% real discount rate (2) Analysis assumes a 2% escalatton rate, a 6% interest rate on available funds, a 8% borrowing rate, and one lump sum payment in the middle 01 the five-year pertod. (3) Analysis assumes a 2% escalation rate, a 6% interest rate on available funds, a 8% borrowing rate, and beginning of year payments to replacement funds.
Depreciation Depreciation Used Available
Throulih 2030 Alter 2030
18,772,945 12,865,202
1.600
1,500
1,400
1,300 ---... r-----..~ '---./
1,200
1,100
1,000
900
i 800 J -
~ 700 r---
600 r--
500 -f--- -
400 - f-=--- -
300 ,--- r-
200
100
_Generating Discharge = Spillway Discharge -I>- Powerplant Hydraulic Capacity
'\. /\. ~
'\ / V"-J~ A /
~ VV
-
-
I
t
-Lake Level
..--...
V \rv\ V "--./
/"../
400
375
350
325
300
275
250
225 rl-.
200 ~ t
175~
150
125
100
75
50
25
119861~1 __ ~1=98~7_~ ~I __ ~19=8=8 __ ~1 LI __ ~1~98~9 __ ~1 LI __ ~1~99~O __ ~1 ~I __ ~19~9~1 __ ~1 1~ __ ~19=9=2 __ ~1 ~I __ ~1=99=3 __ ~1 1~ __ ~19=9~4 __ ~1 ~
Figure 2-1 Swan Lake Project - Measured Historical Flows and Lake Levels
I
Figure 2-2 Swan Lake Project - Fabrication of New Pipe Support for Transmission Structures
FJgure2-3
Figure 2-4
a o
Brace added to the 5UUCture
Swan Lake Project - Reinforcement of H-Frame Transmission Structures
Swan Lake Project - Location of New Guy Wiring on Transmission Structures
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 generating units and a switchyard. The project also includes three substations (Meals, Pll 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 1, 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 MV A. 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 analyzed. 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.
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7176/02028S0LO.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, Pll Substation Voltage, P11 Substation
960208
717610 2028S0LO.WP 3-2
685 ft 618 ft
31,500 ac-ft 19 sq mi
Rockfill with asphaltic-concrete facing 690 ft 115ft 386 ft
Ungated concrete ogee 450 ft 685 ft
2 3,800 ft
48 inches Steel
12 MW at 80 percent power factor 2
Vertical shaft Francis 670 ft
8,770 hp 7.5 MVA 900 rpm
4 mi 25 kV
112 mi 138 kV
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The average flow at the project site, based on data shown on Figure 3-1, is approximately 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 Development 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 furnished by AEA, 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 energy generation potential of the existing project, assuming that all of the available summertime 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.
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7176/02028S0W.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 10 years
39,557,255
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-tenn streamflow records. 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-tenn 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:
960208
7I76/G 2028S0LO.WP 3-4
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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 100 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 definition 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 requirements and economic decision criteria, this spilled water could be used for energy production.
Increasing the plant hydraulic capacity by 50 percent might be accomplished by adding a third 7.5 MV A 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. l
Allison Lake Study by HDR Engineers, September, 1992.
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7176/02028S0LO.wP 3-5
Based on the above information, it is concluded that there is little potential for expansion 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 PERC 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 information 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 PERC 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 unscheduled 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.
960208
7176/G 2028S0LO.WP 3-6
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-., .. .,
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., .. • • • • • .. • • • • • -------
3.3.2 Transmission System Availability
The plant was shut down for extended periods at least twice due to transmission outages 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 include 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 recommended 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.1. Quinn of Harza and Stan Sieczkowski of ABA 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 inspected by Messrs. P.1. 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, concentrating on the reservoir rim. The aerial reconnaissance was done to evaluate the potential 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, ABA Consultant.
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7176/G 2028S0LO.WP 3-7
On October 9, Messrs. R. Williams, PJ. 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 inspected 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 significant 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 recommended to prevent future occurrences as they are expected to be very infrequent and produce 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 experienced 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 satisfactory. The roof has recently been replaced. One maintenance item is some minor leakage between the precast concrete panels that face the upper powerhouse structure.
The interior of the powerhouse was inspected at all three levels (generator floor, turbine 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 powerhouse, 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 powerhouse 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 cracking or movement is anticipated.
The inspection noted that the bulkhead system designed to isolate the draft tubes from tailwater 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 downstream, 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 powerhouse:
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. Determine 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 roadway is S.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 Solomon 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 11S-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 100 ft downstream of the toe. The recorded seepage flows are clear, have ranged from S.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 settlement. 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 accordance 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 "Technical 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 walking along the flip bucket at the toe. The uncontrolled ogee overflow spillway, anchored 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 foundation, 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 1I8th 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 efflorescence and seepage was noted on the downstream face of the right spillway abutment 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 structure 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 visible 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 operated 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 upstream 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 diameter 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. Penstock stationing begins at 1 +00, at the back exterior wall of the powerhouse, and increases 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 penstock surface is somewhat ragged, with remains of asphaltic coating and uniform surface 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 Institute, 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 E1. 695, and the tailwater at tidewater level, the penstock pipe at original 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 thickness of only 0.375 inches. However, its location at Station 26+60 means that it is subjected to only 530 feet of head under normal 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 supported 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 problems 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, supplemented by periodic ultrasonic testing, be continued, especially in the first 300 ft upstream 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 corrosion 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 emergency. In accordance with R.W. Beck's Periodic Safety Inspection Report dated September 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 recommended.
The penstock crosses the Trans-Alaska Pipeline at about station 17+50. At this location, the penstock is exposed about 30 ft above the ground with steel supports at stations 16+68 and 17+38. The Trans-Alaska Pipeline is buried about 5 ft deep. A penstock 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 O.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 operating 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 tail water 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 generator output in kW versus the wicket gate opening in percentage open are for a gross head of under 666 ft (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 673 ft.
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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 operating 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 governor for maintaining the operating speed and positioning the wicket gates. The governors are manufactured by Woodward Governor Company. The normal operating pressure 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 manufactured 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 position, 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 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 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 MV 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 generator 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 simultaneously. 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 20 ft 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, operating 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 approximately 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 system. 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 circuits from the Department of Administration, Division of Information and telephone lines from the CVEA. These lines prov ide communication from the power plant to Meals Substation, P12 Substation, and PI I 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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3.4.18 Emergency Generator
Condition Assessment. A 250-kW, 480-V Cummins diesel standby generator is provided 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 monitoring circuit of the fuel line does not operate correctly, hence it has been disconnected. Fuel line monitoring provides pertinent fuel consumption data to the plant operator 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 transformers, two unit oil circuit breakers, a station service cubicle, two line circuit breakers, and 25-kV bus work. The equipment is located in a restricted area with no accessibility 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 MVA OA with a 55°C temperature 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.
Mter 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:
A valanche. 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 therefore 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 experienced with this line section to date. The insulators should be monitored and pollution type insulators installed if flashovers begin to occur as a result of salt contamination.
3.4.21 Transmission Line from Meals Substation to P12 Substation, and from the P12 Substation to the PH Substation
Condition Assessment. The transmission line from Meals substation to the P12 substation is a single-circuit, 138-kV line, 62 miles in length. The transmission line from the P12 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 Xframe 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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The significant elements of risk to this line are described below.
A valanche. 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 impose a danger to the line.
Flooding. Several structures are located next to creeks and rivers. These structures 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 increases 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 attributed 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 locations where failures have been experienced to evaluate the level of structure vibration 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 problems on the line. This is not a frequently occurring event and therefore no corrective 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 outages.
Recommendation. The following actions are recommended to reduce the risk of damage 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 implementation 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 endanger 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.
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3.4.22 Meals Substation
Condition Assessment. The substation has one 138-kV, 24.9/14.4-kV, 15/20/25-MVA, OAIFAIFA 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 transformer 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 transformer 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 bolting, 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 distributiorl line from the P12 substation. The substation has one 138-kV, 24.9114.4-kV, 12/16/20-MVA, OAIFAlFA, with load tap changer transformer. The one-line diagram is presented in Figure 3-5. The substation has no oil recovery facilities 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, 24.9114.4-kV, 12/16/20-MVA, OAIFAlFA, 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 major interruption.
The substation has no oil recovery facilities to mitigate the potential for oil spill contamination. 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 location, 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 consists 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 ABA 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.
%0208
7176/G 2028S0LO.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 estimated to have a service life of 30 years. At the end of the service lives of these facilities, 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 information provided in Table 3-5 and 3-4.
3.4.28 Documentation
Condition Assessment. Marked up construction drawings were sent to ABA to incorporate 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.
960208
7176/G 2028S0LO.wP 3-26
-.... -..
--
• • •
• • -.. • • • • • • -•
• •• • •
-.. --.
... All structural components are considered to be in good shape, and are expected to peIform 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 peIform 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 maintenance, other general project improvements, and replacements due to normal wear and tear is presented in Table 3-4.
960208
7176/G 2028S0LO.WP 3-27
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
(years) (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 Govemor 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 of 2
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) (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
Pll 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 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.
-
-.. ....
--.. • .. .. • .. .. • .. • .. • .. -.. .. -.. -.. -III
Table 3-4 Page 1013
SOLOMON GULCH PROJECT· PROJECTED MOST LIKELY REPAIR AND REPLACEMENT COSTS (in US dolars at 1995 price levets, excluding repairs or replacements l1Je 10 na1l.nl1 events, accidents or e~pmen1lailures)
Depreciation Depreciation Used Avaiable
struc1l.fe 1996-2000 2001·05 2006-10 2011·15 2016-20 2021·25 2026-30 Next r~cemenl Thr~2030 After 2030
Remedal Work lor 11ems 01 Deficlenl Design None
Remedal Work For nems 01 Delerred Mainlenance None
other Project Improvements Correct leaky draft 1LtJe btJkhead 20,000 Evaluale s1ruc1tra1 capacity 01 access road bridge 10,000 Paint penstock exterior 360,000 Replace 2·48" penstock butterfly va~es 300,000 Improve ~ joint wei thickness and paint 135,000 Inspect and repair Intake stoplogs 200,000 Repair emergency gen fuellne moritor1ng cirwl 700 Inslal spare slalon drainage 5111'4' PIl1'4' budgeled Add oil recovery ladities al al sttlslations budgeted Monitor transmission Ine struc1l.fes latigue a Monitor transmission Ine InsLAators lor contamination a Meals sttlstation • demp transformers 2,000 Monitor Pll sttlslation control bLiking settlement UndergrO\.lld cable study and evaluation 60,000 ROW clearing (fire and wind) 350,000 Erosion control on translTisslon lines near rivers and creeks 250.000 Isolate Mile 26 tap, Inslal breakers with discomect switches 300,000 Acquire lorldift 40,000 Complele as-bLift drawings 20,000
Replacements l1Je to Normal Wear and Tear Structlres
Powerhouse leakage at concrete paneis 5,000 5,000 5,000 5,000 Repair at 100yearintervals, 2030 Monilor dke parapet vertical joinl Repair spilway wei 135,000 2044 Monitor penstock wei thickness 20,000 20,000 20,000 20,000 20,000 20,000 20,000 Monitor every 5 yrs: replace in 2044 Architecllnl rellXllishment 200,000 2044 Paint penstock 360,000 Paint every 20 years, 2036
Equipment T.mIne and Other Mechanicallterns
TlXIline Rlfiler and Wicket Gates Replace rlfiler & wicket gates In 2031 2,744,000 56,000 Governor 2044 216,000 84,000 InletVa~e 2031 156,800 3,200 Draft Tttle BlAkhead 40,000 2043 38,400 1,600 Cooing Water System 64,000 2031 61,440 2,560 Other Auxllary Mechanical Equipment 173,000 2051 69,200 103,800
Generator Stator 700,000 2031 672,000 28,000 Rolor 210,000 Replace field poles in 2051 84,000 126,000 Bearings 400,000 2041 253,333 146,667 Cooing System 150,000 2041 95,000 55,000 RTDs, Sensing Devices 4,000 2041 2,533 1,467 Fire Protection 5,000 Check C02 gas amualy: 2051 2,000 3,000
Excitation System 200.000 2031 192,000 8,000
Electrical System Battery and Chargers 100.000 2031 96,000 4,000 Controls and Protective Relaying 180000 2031 172,800 7,200 Station Service 240,000 2050 80,000 160,000 5-kV Switchgear 60.000 2031 57,600 2,400 Cable System 2031 245,000 5,000
T.ble3-4 Page 2 of 3
SOLOMON GULCH PROJECT· PROJECTED MOST LIKELY REPAIR AND REPLACEMENT COSTS (in US dolars al1995 plice levels, exdJcing repairs or replacements liIe 10 nollnl events, accidents or eql.ipment faiu-es)
Depreciation Depreciation Used Available
S1ructLre 1996-2000 2001-05 2006-10 2011-15 2016-20 2021·25 2026-30 Next replacement TlYou!tl2030 Aner2030
Intake Gale Elec1r1cal Controls 20,000 2040 12,000 8,000 SCADA Syslem 450,000 450,000 2038 210,000 240,000 ColIYIUIicatons 15.000 15,000 2038 7,000 8,000 Emergency Generator 125.000 2051 37,500 87,500
Switcl1yord, Transrrission Line and Slilslation Eql.ipment Powerhouse SWltchyard
Transformers 350,000 (1,3) 2041 221,667 128,333 Clrclit Breakers 145.000 (2) 2031 139,200 5,800 Discomect Switches 60.000 2051 24,000 36,000 Bus struclLres 50.000 2061 11,250 38,750 I>J other 150,000 2051 60,000 90,000
Transmission Line Insliators 700,000 2051 157,500 542,500 HardWare 1.200,000 2061 270,000 930,000 Conlilctors to.OOO,OOO 2061 2,250,000 7,750,000 S1ructLres 2061 11,292,482 7,144,224 Fo~tions 2051 14,714,446 9,309.140
Meals SIilstation Transformers 350,000 2041 221.667 128,333 CirClit Breakers 192,000 2031 184,320 7.680 Discomect SWItches 131.450 2051 52,580 78,870 PTs, CTs, Wave Traps 100,000 2041 63.333 36.667 Bus S1nJcILres 100,000 2061 22,500 77,500 I>J other 1.000,000 2051 400,000 600,000
P 11 Slilstation Transformers 300,000 2041 190.000 110.000 Circlit Breakers 96,000 2031 92,160 3,840 Disconnect SWItches 56,500 2051 22,600 33,900 PTs, CTs, Wove Traps 100,000 2041 63,333 36.667 Bus S1nJcILres 90,000 2061 20.250 69.750 I>J Other 800,000 2051 320.000 480,000
P12 SIilstation Transformers 350,000 2041 221,667 128.333 Circlit Breakers 192,000 2031 184,320 7.680 Disconnect Switches 99,000 2051 39.600 59.400 PTs, CTs, Wave Traps 120.000 2041 76,000 44.000 Bus struclLres 100.000 2061 22.500 77.500 I>J Other 1,000,000 2051 400,000 600.000
Rolng Stock P;c~ Truck (3/4 ton, 4WD) 30,000 30,000 30,000 Replacement every 10 years 18.000 12.000 Snowmobile (2) 12,000 12,000 12.000 12,000 Replacement every 10 years 4.800 7.200 Snowcat and Trailer 115,000 115,000 115,000 Replocemen1 every 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 Foridin 40,000 40,000 40,000 Replacement every 10 years 16.000 24.000
InfrastructLre Storage and Other 375,000 2041 -----.23l.5OO _----13L5llll
5·YR TOTALS DEPRECIATION TOTALS: 37.607.282 29952.960 Remecial Work for "ems of Deficient Design
Remedal Work for Items of Deferred Maintenance O1her Protect l"lM'"ovements 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 l>Jowances For Replacements Aner 2030 (4) 500,087 500,087 689,205 921.846 1.170.715 1.824,810 2,107.806
I • I I I I II I I I I I • J I I I • • I I I I I I , I I I f , I , • •
Tabla 3-4 Paga 3 of 3
SOLOMON GULCH PROJECT - PROJECTED MOST LIKELY REPAIR AND REPLACEMENT COSTS (in US delars at t995 price levels, excbing repairs or replacements rue to na1lnl1 events, acddents or eqUpment faillses)
Structu"e t996-2ooo 2001-05 2006-10 2011-15 2016-20 2021-25 2026-30
LEVELIZED PAYMENT ANALYSIS Replacements due to Normal Wear and Tear (5)
Beglmng of Pertod F<Old Balance 3,864,303 8,859,501 12,007,783 14,669,724 15,394,650 (2,724,676) Amu.1 Contribution of $665,113 to ResOlVe F<Old 3,325,566 3,325,566 3,325,566 3,325,566 3,325,566 3,325,566 3,325,566
Expense (92,325) (240,190) (3,209,438) (4,511,830) (6,894,125) (22,763,891) (167,234) Interest on Average F<Old Balance 631,062 1,909,823 3,032,153 3,848,205 4,293,485 1,319,000 (433,656)
End of Pertod Fund Balance 3,864,303 8,859,501 12,007,783 14,669,724 15,394,650 (2,724,676) (0)
Allowance. for Replacements atter 2030 (6) Begimng of Period Fund Balance 761,689 1,715,118 2,632,190 3,352,902 3,687,018 2,567,992
Amual Contribution of $233.409 to ResOlVe Fund 1,167,044 1,167,044 1,167,044 1,167,044 1,167,044 1,167,044 1,167,044 Expense (530,904) (586,161) (894,309) ( 1,319,736) (1,849,918) (3,190,485) ( 4,053,920)
Interest on Average F<Old Balance 125,549 372,545 644,337 873,404 1,016,990 904,415 318,884 End of Period F<Old Balance 761,689 1,715,118 2,632,190 3,352,902 3,687,018 2,567,992 (0)
a Indcales that the cost for llis item is .sslrned to be included as a part of the norm.1 operations budget and the reqUred activities can be camed out by plant persomelas part of dey-tc>-day activities. b In<icates an item that is contingent on implementation of It reconvnended project Improvement
(1) Includes $50,000 for hoisting transformers to roof (2) Includes $25,000 for hoisting DCB's to roof (3) Second unit wil be out of service for two we""s Iioing inslo.ation of other transformer (4) Calculated in 1995$, using a 4% real discO"" rate (5) Analysis aSSlM'lles 8 2% escalation rate, 86% interest rate on available fll1ds, a 8% borrowing rate, and one Unp SLl11 payment in the midcle of the five-year period (6) Analysis 8SSlM'lleS 8 2% escatatlon rate, 86% Interest rate on available fll1ds. II 8% borrOWIng rate. and begimng of year payments to replacement foods.
Depreciation Used
Next replacement TlTOU!tI2030
3 ?i
do oS-d \{~ t, ~. l:'3 c1 Y~l2-
7 o~ r-~~) ~~G
1.3 ~
Depredation Available
After 2030
700
600
500
400
200
100
o
Figure 3-1
_Generaq Disch8rge
-lokelovel
= Sjlihoy Discharge ..."... USGS Glge 15225996 Recorded Flow = USGS Gage 15225997 Roccrded Flow
--+- USGS Goge 152~OOO Recorded Flow -6- Powerplortl Hy<ntAc C""odly
vv
~
) \
1\ ~ 1\ 1\ I~~ I! 1:-" ~
/ ~ II II
Solomon Gulch Project - Measured Historical Flows and Lake Levels
700
600
500
400 ,... l-. S-I.
~ 300
200
100
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
-------------------------------------------------,
~----L..---+~ }
~-L..---+~
To SIa!ioo Service TransfCOJJer
ToMeab SuImtioo
...... ---------_ ... _----- ... --------------------_ ...... _____ 1
Figure 3-4 Solomon Gulch Project - Main One-Line Diagram
".
I To P11 Substation I ..... _- ......... - ................................ . . I NOOh Feeder I
t J I~~ ~~I' I To Meals Substation I +4 __ ---'-_..J..I_~~ '-@-J ~~----'--'-.. ~ I ToAlyeskaPS No. 12 I
138 tV - 24.9 tV
Transformer
Figure 3-5 Solomon Gulch Project - One-Line Diagram - P12 Substation
• • • - - - • • • - • • • - • - • • • • • • • • • - • - • - - - - -. Solomon Feeder • • (Glennallen Diesel
Generata: Plant)
I ToP12Substation I +-111 __ '---.....L-~~_ ............ I ~,_....L-..L.....-_.....JI_-+~ 138 tV - 24.9 tV
Transformer
Figure 3-6 - Solomon Gulch Project - One-Line Diagram - P11 Substation
p ....................................................... ..
To Valdez Diesel +111 ___ -'/~ Generatcr Plant •
{
+-111 ------"/~.....I......f_-I'T-o-SoI-0m0n--G-ul-ch'l : ~ . . III /~ '--D----'
I To AlyeskaPS No. 11 I
Figure 3-7 Solomon Gulch Project - One-Line Diagram - Meals Substation
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 project consists of a 193-foot high concrete-faced rockfill dam, ungated side channel spillway, 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, penstock, 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 project 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 delivered 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 Association (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 MV A. The turbines were manufactured 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.
960208
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
PENSTOCK Number Length Diameter Type
EQUIPMENT Nominal Plant Generating Capacity Number of Units Type of Turbines Maximum Gross Head
Shotgun Creek
1,925 ft
1.9 sq mi
Concrete faced rockfill
1,930.5 ft 40 ft
275 ft
Open channel
100 ft 1,925 ft
Turbine Power Output (each, at 1,136 ft net head) Generator Rating (each) Speed
TRANSMISSION LINE Length, Port Lions V oltage, Port Lions Length, Kodiak City Voltage, Kodiak City
960208
7176/G 22028TERR.WP 4-2
Falls Creek
1,645 ft
4.5 sq mi
Concrete faced rockfill
1,650 ft 20 ft
480 ft
Ungated concrete
ogee 200 ft
1,645 ft
Shotcrete (partial) 2,000 ft
9 ft
Rolling Rock
1.6 sq mi
Rocktill
1,485 ft 20 ft
130 ft
Overtopping
130 ft 1,485 ft
Shotcrete (partial) 1,600 ft
9 ft
Terror Lake
1,420 ft 1,250 ft
112,000 ac-ft 15.1 sq mi
Concrete faced rockfill
1,425 ft 193 ft
2,400 ft
Ungated concrete ogee
side channel 625 ft
1,420 ft
Shotcrete (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 no rpm
2mi 12.47 kV
18.6 mi 138 kV
.. -.. -.. .. ----•
• ... •
• • • • • -• • •
•
• -.. --
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 Terror 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
60 cfs 100 cfs 150 cfs 100 cfs 60 cfs
Based on the flow information presented in Figure 4-1, the total average flow, including the powerplant discharge and downstream release at the dam, equals approximately 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 intentionally 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.
96020S
7176/G 2202STERR.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 furnished 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,
960208
7176/0 22028TERR. WP 4-4
.. • .. • -.. -
..
.. -.. • • .. !III .. • • .. • .. .. • .. .. .. .. -.. • .. .. ..
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 indicated 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 o out of 23 years 2 out of 23 years lout 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 definition 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, approximately 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.
960208
(~2f- \~ (\000)000 't..?71~ 3btQ
7176/G 22028TERR.WP 4-5
d-I,~ 'f-~ f d-cltSC)O ~6EYf, • b ~
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, however, 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 capacity 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 generation. 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 reviewed to characterize the history of unit and transmission system availability.
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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 tunnel was dewatered from August 2, 1994 to October 1, 1994.
4.3.2 Transmission System Availability
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 structures 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 recommended 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 second team performed the transmission line, civil, and structural inspection.
On October 2 and 3, 1995, J.H.T. Sun and J.1. 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 PJ. Donalek of Harza and Remy Wil-
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liams, consultant to ABA, inspected the transmission line and the civil and structural features.
The inspection on October 11 by Pansic, Donalek and Williams consisted of a helicopter 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, driving 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 landslide 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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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 lOO-year design basis earthquake acceleration 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 condition.
The downstream face of the spillway has a shotcrete facing, designed to prevent erosion of the underlying rock material when the spillway operates. Because of the highly 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 spillway, 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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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 flooding 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 poly jet valve, which was operating at the time of the inspection. It was apparent by observing the pulsing discharge from the poly jet valve that some imbalance in the valve flow is occurring. Mr. W.E. Larson of Larson Engineering, Inc. inspected the poly jet 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 instead of the poly jet 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 poly jet valve;
2. Check the valve stem for straightness and for perpendicularity to the machined top or bottom surface 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 a-ring seal on the valve to stop the present closed-position leakage;
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 poly jet valve operator, and implement other recommendations made by Larson.
4.4.5 Main Tunnel Intake Gatehouse
Condition Assessment. Flow through the II-foot diameter power tunnel is controlled by means of a 5-foot wide by lO-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 gatehouse 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 motor for the bridge crane. The continued corrosion will create shorting out of the con-
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trol panel in the future. Therefore, higher than nonnal maintenance costs can be expected 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 pennit 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 structures 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 (Le., 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 diversion. 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
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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."
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 sediment 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 4O-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 undermine 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 portion 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 recommendations.
Recommendation. Carry out measures suggested by the Part 12 Safety Inspection Report 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 4O-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, significantly 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 construction, 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. However, 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 recommended. 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 previously 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 preventative 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 possibility 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 placement of riprap and bedding material adjacent to the tower foundations.
The creek adjacent to the switch yard should be channelized to increase the carrying capacity and reduce the potential for flooding the switch yard.
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. Continued 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 runner has been put back on Unit 1 for operation. The shaft seal replacement and shaft alignment were performed 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 performance 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 performance 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 normal tailwater in the runner chamber with turbine full discharge is El. 98.7 ft. A blower system is provided to depress the water level in the runner chamber when the tail water 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 DG 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 maintenance 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 pressure 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 closing 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 present, 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 capacity movable hoist to handle the turbine or generator components is desirable.
Other auxiliary mechanical equipment such as the powerhouse crane, station drainage system, unit un watering 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 wedging 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 revealed 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 indicated 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 present 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 equipment. The switchgear has adequate spares to accommodate the expansion of the powerhouse 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 original 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 emergency 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 4OO-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 automatic 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 OAIFA rating of 11.25/15 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 operated very conservatively and the transformers are located in a cool ambient temperature. 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 conditions.
Like the power transformer, equipment and structures in the switchyard require frequent 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 conditions could flood the switch yard.
Recommendation. The creek should be channelized and riprap protection provided in the channel to correct the erosion problems.
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•
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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." The conductor is 397.5 kcmil 3017 ACSR code name "Lark." The suspension structure configuration 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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• 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 weathering steel deposits, and through tests, find the critical flashover voltage of the assembly. 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, including 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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• III
•
--.. -.. .. .. .. • .. • • • • • • • • • ---.. -., ., • • -• •
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 degradation 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 anticipated 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 Company. The product name is "MA Y 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 performed 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 replace 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 insulators 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 brush 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 rightof-way.
KEA has experienced outages that have lasted 2 to 3 days. These outages have occurred 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 evaluated to determine the potential for risk to the line.
The avalanche study could be used to develop an "emergency action" plan that provides 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 replacement 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 emergency action plan should be evaluated. Helicopter serv ice 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 evaluated 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
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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 substation.
4.4.27 Airport Substation to Swampy Acres Substation 138-kV Line
Condition Assessment. This 1.6-mile line is supported on H-frame wood pole structures 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 discontinued 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 primary 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
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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.
KEA 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 collection 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 MY 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 transfonner 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 MY A with forced air cooling and 65°C temperature rise. A new larger transformer is recommended at Shotgun Acres substation when the existing generator reaches its useful life in year 2014.
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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.
6.
Road grader - in good condition
Four pickup trucks - will require replacement within their normal expected life.
Recommendation. Replace the dump truck and bulldozer; acquire a forklift to facilitate 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.
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...
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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 anywhere.
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 condition 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 appropriate 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 replacements 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
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(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. Owners and engineers must often make difficult decisions about accepting risks and working within funding limits. The engineer is responsible for informing the owner of the possible risks and associated costs. The owner must make decisions about implementation. To make determinations on whether the problems mentioned above are actually "design deficiencies," much more investigation of the design computations and construction records would be required.
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Table 4-3 Page 1 of 2
TERROR LAKE PROJECT - EXPECTED SERVICE LIFE AND REPLACEMENT COSTS (where applicable, replacement costs are for both generating units)
Item
Equipment Turbine and Other Mechanical Items
Runner Needle and Nozzle Remaining Turbine Parts Governor Spherical Inlet Valve Intake Gate Penstock Butterfly Valve Cooling Water System Other Aux Mechanical Equip
Generator Stator Rotor Bearings Cooling System RTDs, Sensing Devices Fire Protection
Excitation System
Electrical System Battery and Chargers Controls and Protective Relaying Station Service 15-kV Switchgear Cable System
SCADA System RTU's
Communications Microwave PlC
Emergency Generator Gatehouse Generator Intake Gate Electrical Controls Poly jet Valve Release Water Generator
Condition
Fair Fair
Good Good Good
Good Fair
Good
Excellent Excellent
Good Poor
Good Good
Good
Good Good
Excellent Good Good
Excellent Poor
Excellent Poor
Excellent
Poor
Switchyard, Transmission line and SUbstation Equipment Switchyard at Powerhouse
Transformers Good Circuit Breakers Good Disconnect Switches Good PT's, CT's, Wave Traps Good Bus Structures Good All Other Good
Transmission line Insulators Good Hardware Good
Conductors Good Structures Good Foundations Good
d
d d
Expected Service life
(years)
50 50 50 50 50 25 50 25 35
25 35 30 30 30 35
25
25 25 30 25 50
15 20
15 15 30 15 20 20 10
30 25 35 30 40 35
30 60 30 80 80
Remaining Service life
(years)
(see note a)
39 39 39 39 39 14 39 14 24
14 24 19 3
19 24
14
14 14 19 14 39
13 c 3
13 c 3 c
19 4 3 b 9
19 14 24 19 29 24
19 49 19 69 69
1995 Price level Replacement Cost
($)
800,000 40,000
2,740,000 300,000 180,000 100,000 350,000
79,000 213,000
1,000,000 300,000 400,000 150,000
7,000 5,000
200,000
100,000 180,000 270,000 100,000 250,000
450,000 100,000
150,000 120,000 200,000
25,000 20,000
400,000 20,000
430,000 76,000 48,000
100,000 100,000 200,000
328,721 547,868
2,556,717 3,917,256 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 (0-8) Dump Truck Backhoe Road Grader Four Pickup Trucks 20-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
(years) (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
• • •
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Tablo4-4 Page 1 of3
TERROR LAKE PROJECT - PROJECTED MOST LIKELY REPAIR AND REPLACEMENT COSTS (in US dolars It 1995 price levels, excluding repairs or replacements due to nahnl events, Bcciderts or equipment 'aiues)
Depreciation Depreciation Used Available
Structwe 1996-2000 2001-05 2006-10 2011-15 2016-20 2021-25 2026-30 Next Replacement Tt'lough 2030 Aft ... 2030
Remedial Wortl: for Items of Oeficient Oesign None
Remedial Work For Items of OefetTed Ma.lrtenance None
Oth ... Project Improvements Struchles
Repair main dam spilway 950,000
Repair irtake gate 500,000 Roctd:rap weir .t entrance to Irtake of Iow-level outlet wol1(s 40,000 Prepare emergency response ptan for tl.Dlel rocldel a
RebLiId SI1oI~ Creek cUvOf1 185,000 Add riprap to Intake wing wal It FIls Creek Oivnon 20,000 E ..... luete stabilty of berm s'-"Porting access road to the Inake 20,000 Engineering s1u<1y of Fa .. Creek I\nleI cavity 80,000 Prepare bid docl.l'Tlel'1t for fals Creek repairs 100,000 Repair Fals Creek II.DleI cavity and Invert 785,000 Engineering review of Rolng Rock divoon system 50,000 Monitor and define aainage characteristics of slope l4h1
of powerhouse Construct permanert river training dike 200,000 Channeize creek .~cert to swttctYyard and provide riprap 50,000 Protect tranSfTission tower tOlJ"ldations 50,000
Reptace tirroer tendering on jetty 50,000 COf11)lete sedlmeft: discharge system 1,300,000
Equipmert Replace pol)iet valve op .... tor and other Improvements 40,000 Acoustic now meter for penstock wtve overveklcity closwe 15,000 Replace govemor PMG With SSG 30,000 Replace cooing water pwnps 20,000 Replace gatvanized and Iron piping for cooing, potable water,
and fire protection 20,000
Generator air cooters (f04.l') 16,000
A,,-;omatic synchronizer 20,000 Replace Urit 2 colector ring 6,000 Intake gate eleclrical conrols 20,000 Reptace power Ine canier 120,000
&Mtchyard, Transms~on Une, and Sl.6station EQlipmert Obtain Irterim report of transmission tower p~e corroston Investigate modification to conckJctor to prevert tleshover EvakJate the use of composite insulator on transmission lne Idertify and remove danger trees on transmission ROW Avalanche s1udy for the transmis~on lne ROW 40,000 UndergrolJ'ld cab4e study 30,000 Insulator asserT'dies cortamination tests 25,000 Heavy 1ft helicopter service in Wirter study 10,000 Emergency Action Plan tor tower loss 50,000 Port lions regulator and bus wortl: 150,000 Relocate t41Per arm attactrnenl; instal additional stnA 150,000
Add oi' recovery facilities budgeted Co~lete As-Suil DraWings 20,000
ACQUIre fortcflft 40,000 Acquire one-ton moveable hoist for machine shop 5,000
Replacements due to Normal Wear and Tear StructlJ'es
Fals Creek Spilway Mairtenance 30,000 30.000 30,000 30,000 10-year cycle
Roling Rock Creek Diversion - re~ar cleaning 25,000 25,000 25.000 25,000 25,000 25,000 25,000 ~year cycle
Paint TrastV'BckS at Fals creek 5,000 5.000 5,000 5,000 10-year cycle Paint Lower Penstock Invert 30,000 30.000 30,000 30,000 10-year cycle ArchitectlJ'al Refllbishnert 200,000 2045 PaInt Upper Penstock Irterior 25,000 25.000 25,000 25,000 10-year cycle
Tabl.4-4
Pag.20f3
TERROR LAKE PROJECT· PROJECTED MOST LIKELY REPAIR AND REPLACEMENT COSTS (in US dolar$ at 1995 price tevels, excluding repain or reptBcemeris due to nalIKa' events, sceidel'lls or equipmenl 'aiues)
Oept'edation Depreciation Used AV1l;lable
structlft 1996-2000 2001-05 2006-10 2011-15 2016-20 2021-25 2026-30 Next Rep!acemenl TI'<ough2030 After 2030
EqUpmeni Tlfblne and Other Mechanical ttems
TlIbine ("",,,or, nozzle and neeele) 2034 3,293,600 286,400 Governor 2034 276,000 24,000
'nlet Valve 2034 165,600 14,400 Inlake Gale 100,000 2034 84,000 16,000 Pen$lock VOlve 2034 322,000 28,000 Cooing Wa'er System 79,000 2046 28,440 50,560 Othor AUld'ary Mechanlca' Eqoipmenl 213,000 2054 66,943 146,057
Generator Stator (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 Cooling System 150,000 2058 10,000 140,000 RTOs, Sensing De~ces 7,000 20U 3,733 3,267 Fire Protection 5,000 Check C02 gos amualy, 2054 1,571 3,429
Excitation System 200,000 2034 168,000 32,000
Electrica' System Battery and Chargers 100,000 2034 84,000 16,000 Controls and Protective Retaying 180,000 2034 151,200 28.800 station Service 270,000 2044 144,000 126,000 1~kV SWitchgear 100,000 2034 84,000 16,000 Cable System 2033 235,000 15,000
Inlake Gate Electrical ConCrols (1) 20,000 2038 12,000 8,000
SCAOA System 450,000 450,000 2038 210,000 240.000 RTUs 100,000 100,000 2038 60,000 40,000
CorTVTU'licaUons 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
PotyjetValve 400,000 400,000 2044 120,000 280,000 Release Water Generalor 20,000 20,000 20,000 20,000 2036 8,000 12,000
Switchyard, Transnission line and SLbstation Equipmenl Powerhouse SWilchyard
Transformers 430.000 2044 229,333 200,667
Clrctit Brtekers 76,000 2034 63,840 12,160
OiScOMect SWitches 48.000 2054 15,086 32,914
Pls, Cls, Wave Traps 100,000 2044 53,333 46,667
Bus structlKtS 100,000 2064 15,000 85,000
AI Others 200.000 205. 62,857 137,1.3
Tl1IInsmission line InslJalors 328,721 2044 175,318 153,403
Hardware 2044 420,032 127,836
Conductors 2,556,717 2044 1,363,582 1,193.135
StructlJ"es 2064 2,252,422 1 ,664.83.
FOlrldations 2064 2,934,97C 2,169.329
Airport SLbstalion Transformers (none considered)
Circlit Breakers 152,000 2034 127,680 24,320
Oiscomect S'Nitches 60.000 2054 18.857 41.143
PT., CTs, Wave Traps 50.000 2044 26,667 23.333
Bus Strud\J'"e5 70.000 2064 10,500 59,500
AI Other 180.000 2054 56,571 123.429
, . I • I I I , I • • • I I I I I. I I •• , I I • , I I • , , I I I I , I
Tabl.4-4 Page 3 of 3
TERROR LAKE PROJECT. PROJECTED MOST LIKELY REPAiR AND REPLACEMENT COSTS (in US do.ars at 1995 price levets, exckdng repairs or repAacements d.ie to natU'81 evenls, accidents or eqUpmet'i faiues)
strud1le
Swampy Acres Substalion Transformers Circl.it Breakers Discomect SMtches PTs, Cls, Wave Traps Bus Struct16es MOther
Raing stock Fronl-End loader Buldozer (0-8) D~Truck
Backhoe Road Grader FOLI" Pickup Trucks 20. Ton Trailer For1din
Imra<llUctlJ"e Housing Storage and Other
Docks
5·YR TOTALS Remedial Work for Items of Deficient Design
Remedial Work fOf ttems of Deferred Maintenance other Project Improvemens
Replacements due to Normal Wear and Tear AJowances For Replacements After 2030 (3)
LEVELIZED PAYMENT ANALYSIS Replacements due to Normal WUllnd Tear (.)
Beginning of Period FlJ"Id Balance Annual Contribution of $606,114 to Reserve FlI'Id
Expense Interest on Average FlJ"Id Balance
End of Period F\6\d Balance
Allowances for Replacements after 2030 (5) Beginning of Period Fllld Balance
Annual Contribution of $156.939 to Reserve Fllld Expense
Inerest on Average FLI'Id Balance End of Period Ft.rId Balance
1996-2000
200,000 100,000
100,000 50,000
75,000
5,207,000 785,000 245,959
3,030,568 (833,048) 432,028
2,629,548
784,695 (261,116) 102,850 626,429
2001·05 2006-10
220,000
240,000 200,000
100,000 220,000
100,000 50,000 40,000
985,000 3,253,000 245,959 297,056
2,629,548 5,766,118 3,030,568 3,030,568
(1,154,084) (4,208,102) 1,260,086 1.737,588 5,766,118 6,326,172
626,429 1,432,329 784,695 784,695
(288,293) (387,069) 309,498 572,177
1,432,329 2,402,132
2011-15 2016-20 2021-25 2026-30
550,000
100,000 150,000
300,000 500,000
240,000 240,000 200,000 200,000
100,000 100,000 100,000 100,000
220,000 100,000 100,000
50,000 50,000 40,000 40,000
450,000 525,000
75,000 75,000
6,702,438 2,471,000 1,914,000 1,195,000 622,556 1,085,922 1,363,530 1,705,657
6,326,172 674,268 (161,780) (634,406) 3,030,568 3,030,568 3,030,568 3,030,568
(9,572,732) (3,896,518) (3,332,320) (2,297,067) 890,259 29,902 (170,874) (99,096) 674,268 (161,780) (634,406) 0
2,402,132 3,106,265 3,056,594 2,211,514 784,695 784,695 784,695 784,695
(895,926) (1,714,992) (2,381,324) (3,285,736) 815,365 880,626 751,549 289,527
3,106,265 3,056,594 2,211,514 (0)
a Indicales that the cost for this item is asslrned to be inckJded as a part of the normal operations budget and the reQUired activ\lies can be camed out by pant personnel as part of day-Io-day activities
b Inelcales an item that is contingent on implemmalion of a recommended project impfovement (1) Up!T8de included in project improvements (2) Rec:orrrnend arger emergency generator (3) Cak\iated in 1995$. using a.t% real discolJ'lt rate (4) Anatysis aSSlrnes a 2% escelatlon rate, a 6% inerest rale on available foods, IS 8% borrowing rate, and one lump sum payment in the midde of the five-year period (5) Anatysis aSSlrnes a 2% escelation rate, a 6% interest rate on available foods, IS 8% borrOWIng rate, and beginning of year payments to replacement flllds.
Depredation Used
Nul Replacemenl TIYoug/I2030
2044 293,333 2034 184,800 2054 31,429 2044 80,000 2064 45,000 2054 157,143
Replacemm every 10 years. 216,000 Replacement fNery 10 years. 60,000 RepAacement f/Very 15 years 20,000
RepAacemm every 10 years. 90,000 Replacement every 15 years 205,333
Repacemenl: every 10 years. 30,000 Replacement every 10 years, 15,000 Replacemm every 10 years. 16,000
2044 255,000 2044 297,500 2044 10,000
DEPRECIATION TOTALS: 16,595,965
-7~~
q~~ ~~ 1) 5 61 D'L
& ~I\ \ C\ l \{
Depredation Allllilable
Aller 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
~ \ ('1 S-
\ \l 3 l ____ . -\--------
I _ Generating Discharge = Release to Terror Riller -Lake Level -+- Powerplant Hydraulic Capacity
400 1,600
375
/ 1,500
350
~ 1,400
325 1,300
300 1,200
275 6 6 6 6 • 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 • • • 6 6 6 6 6 6 .. .. 6
1,100 .. 6
250 1,000
225 f- 900
~ i .
200 r- f- eoo .. ~
. c .. ~ 175 f- - f- f- c--- 700
150 t- 600
125 f- f- f- c--- t- - r- r- r- r- 1- - f- 500
100 I- I- 400
75 f- 300
50 f- I- t- t- 1- 200
25 1- - - - - t- - t- - - - - - - - - - ~- I- I- f- - 100
II .. II .. 0 N D II .. II .. 0 N D II .. II .. 0 N D II .. II .. 0 N D
1991 1992 1993 1994
Figure 4-1 Terror Lake Project - Measured Historical Flows and Lake Levels
,----I I I L ________ I
17 miles
r AiIpOrt su~; -I I I I I I r --i I I I
Future·ExpanaiOll ~ ~
I I
· . · . ·1 . · . .. ...
L __________ _
67kVIu
C-YUae
'---------------Rgure 4-2 Tenor Lake Project· Transmission and Substation System
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
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 powemouse 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 venture 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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1,396 ft 1,250 ft
52,400 ac-ft 14.2 sq mi
Unlined 8,300 ft
10 ft
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
.. -• -• -.. -... ----.. • •
• •
• .. .. • • • • • • ., .. • -.. -• •
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 potential of the project. There are no long term records of either the lake levels or flow in 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! 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. Recorded 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 calculated from the data illustrated on Figure 5-1. The maximum powerplant discharge capacity 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 measurements 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 MVA. 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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• • • -• -lIP
---•
.. • • ., Ill;
., -• -• • -• •
.. •
• -• •
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-tenn streamflow records.
The Harding River gage mentioned above has a 42-year streamflow record. Total annual 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
lout 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 definition 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 additional 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 production 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 generating 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 million, or about $560 per kW. This cost is competitive with alternative forms of peaking 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 duration of outages was not possible.
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• -• -• .. --• -.. • • • • .. • • • • • • • • • • • -• • .. III
-• • -• •
In addition, plant operation personnel were interviewed. FERC annual operation reports, and reports by various engineering fInns that have been hired to assess the condition 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 ou tage 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 interruptions.
5.4 Condition Assessment, Recommendations, and Costs
The following section describes the Tyee Lake Project condition assessment and recommendations 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 October 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, reservoir rim and the transmission and substation facilities.
N. Pansic was accompanied on October 16 by Carl Thrift, TBPA Foreman, and Remy G. Williams, ABA Consultant, and on October 17, by Dennis Lewis, Petersburg Municipal Light and Power Electrical Supervisor, Dan Koszuta, City of Petersburg Engineer, 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 landslide 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 TBPA.
On October 18 and 19, 1995, 1.H.T. Sun and 1.1. 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 moderately steep, with spruce trees being the dominant vegetation. However, since the reservoir 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 purposes. 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 moisture-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 installed, 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 Petersburg and weather conditions. Also, coordination of such an operation would be difficult due to the communications limitations. In general, the poor access is not conducive 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 electrical 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 constructed 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 geometry and investigate the presence of rockfalls which may have occurred.
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• -.. -• ------• • • .. • -• • • • • • • • •
• • • -• .. • • • III
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, 1993 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 potential 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 defined 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 further 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. It is exercised once a month.
Overall, the powerhouse appears to be maintained in excellent order.
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•
• ., .. .. -• .. • • • l1li
• .. •
• --• •
• • •
• • • •
• • • • l1li
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 powerhouse 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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foundations of the three buildings require shoring up with new concrete foundations.
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 andlorerosion 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 maximum headwater pressure (approx. 650 psi), and the oil pressure in the needle servomotor 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 system, 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 performed in 1984. The results indicated that the outputs exceeded the expected turbine performance at the minimum, rated, and maximum net heads for both units. Based on the expected turbine performance curves 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 performance 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 operating 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 normal 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 normal conditions.
5.4.8 Generators
Condition Assessment. The generators are classified as "suspended types" with combined 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 perfonned on these generators. However, AEA perfonned an annual visual inspection of the electrical and mechanical components, with the last one occurring in April 1995. Also, TBPA's consultant perfonned electrical tests in September 1995. These tests included stator winding resistance 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 operated potentiometers have been replaced. Power supplies are presently causing frequent alanns. Device No. 89 relay DC coils occasionally burn out and the 41E breaker occasionally does not close and requires manual closure.
Recommendation. The following are recommended:
1.
2.
3.
Replace the control relays and power supplies with a new microprocessor.
There are a number of stator RIDs (resistance temperature detector) that are inoperative and should be corrected.
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 nonnal 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 pressure 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 closing 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 protected 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 restrictions 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 nmaway 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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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 powerhouse. 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 1 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 system 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 anyone 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.
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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 installed in January, 1996. This system includes a hot standby. The number of RIDs 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 I/O points should be increased.
5.4.15 Communications
Condition Assessment. A power line carrier (PLC) system provides the primary communications between the Tyee Powerhouse and the Wrangell Control Center for control 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 reliability of the system. However, under extreme icing conditions, the PLC system will continue to have outages.
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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.
2.
3.
The PLC should be expanded to include additional phone circuits.
The VHF radio should be upgraded and improved to provide a reliable backup system to the PLC.
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 neutral 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 performed on the generator switchgear in September 1995 by Integrity Engineering Services.
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5.4.18 Alarm and Temperature Monitoring Panels
Condition Assessment. There are a limited number of alarm windows on the annunciator panel. Therefore, a number of alarm contacts are grouped together and taken to one common alann 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 SCAD A system or install an event sequence recorder be installed in the powerhouse to facilitate trouble-shooting during a forced outage.
Recommendation. Installation of additional alanns 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 ONFA rating of 11.25/15 MV A are located in the switchyard. The high voltage winding has a series/parallel winding with a voltage rating of 138/69 kV. The transformers were reported 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 disconnect 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
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lighting standards are installed in locations that make bulb replacement virtually impossible. 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 encountered with the circuit switcher CST-20 and CST-21 relays. These should be replaced. The oil recovery facilities are in place.
Recommendation. The following are recommended:
1. Install new lighting standards that permit bulb replacement. 2. 3.
Calibrate or replace the transformer winding temperature instrument. 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 AW (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 120°F. The line also was designed for NESC heavy loading district, which is 0.5 inch of ice and 4 pound wind at OaF. The line has not been designed for any heavy ice condition. Furthermore, the line design is based on a flexible system
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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 approximately equal to the sags when the conductor is at 120°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 requirements.
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 conductor 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 minimal to check if the line meets NESC code requirements.
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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 A W 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 footpounds 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 environment of Alaska.
Insulator 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 energized 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 maintenance 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 Hydroelectric Projects utilizing weathering steel.
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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 different 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 structures, single shaft wood pole structures and single shaft wood pole structures with low voltage underbuild. With the wood pole structures, the horizontal station post insulators 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 insulators. 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 Yank Islands, and Yank 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.
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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 support the loads associated with 1 in 10 year return period events. (Transmission 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 storm. 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 storm. 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.
2.
Inadequate ground clearances during ice and snow conditions; when the conductor touches the ground;
Inadequate clearances from other underbuilt lines;
3. Foundation failures due to excessive loads;
4. Structure failures due to excessive loads; and
5. Conductor failures.
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In addition to the liability exposure imposed by inadequate clearances, this line provides 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 currently 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 structures 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 station 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.
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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.
2.
3.
4.
The take-off wood pole structure in front of the substation has to be relocated because it was placed incorrectly inside the road ROW.
Lighting fixtures inside the substation are located where there is not sufficient 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.
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 manually operated flood lights be installed outside the control building to facilitate maintenance during dark periods.
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 disconnect 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 facilities 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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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 sufficient 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 disconnect 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 switch yard 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 manholes are filled with water. It is recommended that appropriate ditch work be done to intercept and divert the runoff from the perimeter of the substation.
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.
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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 miscellaneous 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 existing 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 E1. 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 consists of the following:
1. 2. 3. 4. 5.
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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 information 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 condition 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 deficient 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. 2. 3.
Installation of additional bracing for the storage building. Correction of foundation problems with the on-site housing. Clearing of the transmission line right-of-way.
An estimated disbursement schedule for correcting design deficiencies, deferred maintenance, 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 recovery facilities is planned and budgeted by AEA, and therefore is not shown on Table 5-4.
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7176/G 2028TYEE.WP 5-32
.. .. .. --.. --. .. • • .. • • .. .. • ---.. .. • -• .. -.. -.. .. • -• ..
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) (years)
(see note a) Equipment
Turbine and other Mechanical Items Runner Excellent 50 38 Needle and Nozzle Excellent 50 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)
Expected Remaining Item Condition Service Life Service Life
(years) (years) (see note a)
Wrangell Switchyard Circuit Swticher 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
Wrangell Substation Transformers Good 30 18 Circuit Switcher Good 25 13 PTs, CTs, Wave Traps Good 30 18 Bus Structures Good 40 28 All other Good 35 23
Petersburg 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 Road Grader Good 15 10 Dump Truck Good 15 12 Fuel Truck Poor 15 2 Front·End Loader Good 10 6 Cat D-4 Bulldozer Good 10 6 Backhoe Poor 10 2 Boom Truck Good 10 6 Pickup Trucks (4) Good 10 6
Infrastructure Housing Fair 30 18 Storage and other Fair 30 18 Docks Fair 15 3
Notes: 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.
1995 Price Level 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
• .. • .. • ----.. •
.. • ...
• .. • • • • • .. • • • .. • • • -• -• ..
Tabl. 5~
Pago' 013
TYEE LAKE PROJECT - PROJECTED MOST UKELY REPAIR AND REPLACEMENT COSTS (in US dolors 01 1995 price levels, excUing repairs or replacements We 10 nollnl events, accidenls, or eqUpmen! lalues)
Depreciation Depredation Used AVIIllabie
S1ruc1Ire 199&-2000 2001-05 200l>-10 2011-15 2016-20 2021-25 2026-30 Nexl r~cemenl Thr~203O Aller 2030
Remelial Wor1< lor lIems 01 Defidenl DeSign Correct IransmIssion ine design deficiencies, InckJCIng grcxm 17,000,000
problems .nd side slope dearing problems, and selective right 01 way de.ring
Remeli., Work lor lIems 01 Del .... ed M.intenance Bracing lor S10rage BLilding 15,000
Shore", Housing 30,000 M.,ntenance shop, mezz.nine section - siR1'fe pseudoslatic analysis
.nd s1ructln1 molifications 20,000 Selectiv. Transmission Line ROW Clearing 500,000
01her Project Improvements S1rucues
Dredge harbor 600,000
Ecpprnenl Ins1aI remole con1rollntake gale lalding sysIem 15,000 Instal cOlTllUic.tion syslem lor gale remole con1rol 100,000 Replace con1rol relays and power '"4'Pies..;th a .-
miaoprocessor 40,000 Replace RTDs In generators 7,500 C.rbon dust colection system 15,000 Perform • .....-,ts to spherical VIIive dosing time Replace 125-V b.ttery sysIem 60,000 Investigate !he DC wiring sysIem Incre.se the ......-ber 01 RTU lit! points In SCADA sysIem 10,000 Expand the power lne carTIer sysIem (PLC) 25,000 Ugrade !he VHF radio 30,000 Instal. VHF ralio lri< between the powert1ouse .nd Intake 30,000
strucue Inslal .dliUonol .larms to SCADA 15,000
SWitchyard, Transmission Line .nd Sltlstation Ecpprnenl Instal.-I{111Ing standards thet permll Id> replacement 30,000
Calbrate or replace transformer wlnling t"""eraue ins1r\l'nent - • Replace circuit .... tcher relays 20,000 ConWct !he Chorpy V-Notch test on hardware 20,000 Portorm Ins<iotor .ssentl!y test lor rust contamination 13,000
Trasmission Une b1Wn WrlIngei SWilchysrd & Wrangel Sltlstation Replace !he s1ruc\u"es .t the .ngIe locations haloing verUcaly
mounted station post InsUators ..;th dead end poles 50,000 Remove !he 12.4-kV underblildlrom!he strucIIses 120,000
Petersbtrg Slbstation Relocate the take-oil wood pole strucIIse In front 01 !he slbstation 25,000 Instal.-I{111Ing so thet it c.n be maintained and
emergency Ig,ting on the outside 01 the slbstation 30,000
Correct grounling p.ds 10.000
Conruct a rel.ying coorlination study 30,000
WrlIngei SWitchyard Instal new Ig,ting so thet II c.n be maintained 30.000
Correct grot.ndng p.ds 10.000
Improve graling .nd drainage 30,000
WrlIngei SltlstaUon ReIoc.te!he b.ttery, battery charger, eye wash, and RTU into
• second widing 10.000
Add oil recovery I.eiities 01.1 slbstaUons budgeted Correct .... ,ch probtems .t sLibmarine c.bIe terminations 240.000
C""l'lele As-BLift drawings 30.000
AcqurelO<ldlIl 40.000
Replacement We to Normal Wear .nd T e.r S1ructl.res
TLOl"Ieilnspection with ROV 200.000 200,000 2G-ye.r cYCle Test .nd repl.ce selected power11ouse rock anchors 90.000 90.000 90,000 90,000 90,000 90,000 90.000 5-year cyc~ 72,000 18,000 Rep.~ Ie.ks Irom powert1ouse rool 45,000 45,000 45.000 1 7 -year cycle 45,000 Repair seep.ge In powemouse .nd III concrete cutout 10,000 10,000 10.000 17 -year cycle 10,000
Tobl.5-4
Pog.2013
TYEE LAKE PROJECT - PROJECTED MOST LIKELY REPAIR AND REPLACEMENT COSTS (in US doIars at t995 pr1celevels, e.cU:lng repairs or replacements 0Je to natlnl events, acddents, or eqlipment lalb-es)
DepredlUon DepreciaUon Used Available
Struc1Ire 1996-2000 2001-05 2006-10 2011-15 2016-20 2021-25 2026-30 Next ree!!cement Thr!!!!ll! 2030 _2030
Concrete Repllrs in draft bile 20,000 20,000 20,000 20,000 100year cyde 8,000 12,000 Archllectlnl rehabiltaUon 200,000 2045 100,000 100,000
E"';pment Tu1>Ine Ind other Mecharicol Hems
Tlltline (n.mer, nee<le and nozzle) 2033 3,647,200 232,800 Governor 2033 282,000 18,000 IrietVllve 2033 169,200 10,800 Intake Gates 100,000 2033 88,000 12,000 Cooing Wlter System 75,000 2033 66,000 9,000 other Auldlll)' Mecharicol E"';pmen1 203,000 2053 69,600 133,400
Generator Stator (coils) 1,000,000 2033 880,000 120,000 Rotor (poles) 300,000 2053 102,857 197,143 Belrlngs 400,000 2043 226,667 173,333 COOing System 150,000 2043 85,000 65,000 RTDs, Sensing Devices 7,500 2058 500 7,000 Fire Protection 5,000 Check C02 gas arrooty; 2053 1,714 3,286
&dtaUon System 200,000 2033 176,000 24,000
EIec1ricol System Battei)' Ind Chargers 100,000 2048 28,000 72,000 Controis Ind Protective Relaying 20,000 180,000 20,000 2033 165,600 34,400 StaUon Ser;ice 270,000 2043 153,000 117,000 15-kV Swttchgelr 100,000 2033 88,000 12,000 ClbIe System 2033 235,000 15,000
Intake Gate Elec1r1cII Controis 20,000 2033 17,000 3,000 SCADA System 450,000 450,000 2038 210,000 240,000 CorrrTU'lications
Wrongel 150,000 150,000 150,000 2043 20,000 130,000 Intake Gate 100,000 100,000 2040 13,333 88,667
Emergency Generator 175,000 2043 99,167 75,833
SlMtchyord, Trlnsmlsslon line and &bsllUon E"';pment Powerhouse SWltchyord
Transformers 700,000 2043 396,667 303,333 ClrcUt Brelkers 76,000 2043 66,880 9,120 Dlscomect SlMtches 50,000 2053 17,143 32,857 PTs,CTs, WIve Traps 100,000 2043 56,667 43,333 Bus Structu"es 90,000 2063 15,750 74,250 AI other 800,000 2053 274,286 525,714
Transmission line Instiators 852,344 2053 292,232 560,112 HaraNare 1,420,573 2053 248,600 1,171,973 CcxnJc10r 4.545,835 2063 795,521 3,750.314 structu"es 2063 7.160,756 5.027.765 FOI.I'1dations 2063 9.330,681 6.551.329 &.t>merlne ClbIe 16.000.000 2053 5.485,714 10.514.286
Wrangel SlMtchyand Circuit SlMtcher 120.000 2033 105.600 14.400 Disconnect swilches 19,000 2055 6.5U 12.486 PTs, CTs, WIve Traps 150.000 2043 85.000 65,000 Bus S1ructu"es 120.000 2065 21.000 99.000 AI other 400.000 2053 137.143 262.857
Wrongel Substation Transfonners 350,000 2043 198.333 151.667 Glrc .. t SlMtcher 60,000 2033 52.800 7.200 PTs, CT., Wove Traps 100,000 2043 56.667 43.333 Bus Struc1Ires 100.000 2063 17.500 82.500 AI Other . 200.000 2053 68.571 131.429
, I I I I I ! I , I I I I I I I I I • I I • • I • I , I , I f I f I • I I •
Tabla 5-4
Poga3013
TYEE LAKE PROJECT. PROJECTED MOST UKEL Y REPAIR AHD REPLACEMENT COSTS (in US dolors 011995 price levels, exWdlng repairs or replacemenls We 10 nall.nl evenls, acddenls, or equipment laikres)
Pelerstug Sl1l.Ia~on Transformers Clrctit Breakers Oiscomect SWllches PTs, CTs, W.ve Traps Bus S1ruc1u"es /IJ 0Iher
Roing Siock Ro.d Grader 0'-"1' Truck Fuel Truck Fronl-End Lo.der Col 0-4 BlAdozer Backhoe Boom Truck Ptck\4> Trucks (4) ForI<ifl
Infras1nJc1lre Housing SIorage .nd 0Iher Docks
5-YR TOTALS Remedl.1 Work lor "ems 01 Defident Design
Remedial Work lor "ems of Deferred M.intenance 0Iher Project Il11"o.emenls
Replacements ckJe to Normal Wear and Te.r _nces For Replacemenls Aller 2030 (3)
LEVELIZED PAYMENT ANALYSIS Replacemante due to Nonna. Wear and Tear
Begiming of Period FInl B.lance ArnJaI Contr1bution of $1,175,440 to Reserve FInl
Expense Interest on Average FInl B.lance
End of Period FInl B.lance
Allowance. for Replacementa aftar 2030 Begiming of Period FInl Bal.nce
ArnJaI Contribution of $263,024 to Reserve Fl6ld Expense
Interest on Average FInl B.lance End of Period FInl B.lance
(4)
(5)
1996-2000
170,000
100,000
75,000
17,000,000 565,000
1,685,500 680,000 405,592
5,877,200 (933,863) 968,046
5,911,383
1,315,122 (430,587) 173,726
1,058,261
2001·05
200,000 100,000
240,000 100,000
90,000 100,000
920,000 405,592
5,911,383 5,877,200
(1,077,927) 2,939,908
13,650,565
1,058,261 1,315,122 (475,403) 523,038
2,421,018
2006-10
228,000
100,000
40,000 b
2,839,000 508,316
13,650,565 5,877,200
(3,672,549) 5,061,883
20,917,099
2,421,018 1,315,122 (661,779) 961,918
4,036,279
2011·15
350,000
130,000
170,000 240,000 100,000
90,000 100,000
300,000 375,000
75,000
4,940,000 790,337
20,917,099 5,877,200
(7,055,536) 6,873,406
26,612,170
4,036,279 1,315,122
(1,134,686) 1,422,472 5,639,187
2016-20
95,000
900,000
200,000 100,000
100,000
40,000
20,574,344 1,535,548
26,612,170 5,877,200
(32,443,668) 3,950,085 3,995,787
5,639,187 1,315,122
(2,448,124) 1,782,868 6,289,053
2021·25
170,000
240,000 100,000
90,000 100,000
7,636,408 2,765,926
3,995,787 5,877,200
(13,295,171 ) (315,700)
(3,737,884)
6,289,053 1,315,122
(4,830,120) 1,499,249 4,273,304
2026-30
170,000
100,000
40,000
75,000
807,500 3,183,308
(3,737,884) 5,877,200
(1,552,202) (587,115)
o
4,273,304 1,315,122
(6,125,058) 536,632
(0)
• Indicates that the cost for llis Item is .ss"""d to be indJded .s • p.rt of 1I1e normal operabons budget .nd the reqLired .ctivities c.n be c.rried out by plant persomet.s p.rt of day-tt>-day .ctivities b Indeates an Item that Is conangent on implementation of a recommended project irT1>f"olJement
(1) Upgnade inckJded In project II11"0vemenls (2) Recommend larger emergency generalor (3) CalclJa1ed in 1995$, using. 4% real dlscot.nt rale (4) Analysis •• .....e •• 2"~ escalation rale,. 6% interest rate on .vailable!\rods, a 8% borrOWIng r.te, .nd one krnp ..... p.yment In the middle of 1I1e lIve-ye.r period, (5) Analysis .s.....es. 2"~ esc.lation rale,. 6% interest rate on .vail.bIe Ilnls, a 8% borrowing rate, .nd begiming ofye.r p.)mMts to replacement It.nds,
Depreda~on
Used Next replacement TITOU!tt 2030
2043 2033 2053 2043 2063 2053
Replacement eve<'( 15 years Replacement every 15 ye.rs Replacement every 15 ye.rs Replacement every 10 ye.rs Replacement every 10 ye.rs Replacement eve<'( 10 ye.rs Replacement every 10 ye.rs Replacement eve<'( 10 years Replacement eve<'( 10 yeo",
2044 2044 2044
OEPREQATIOH TOTALS:
~ C1 a-0 d cS ~1 ~9'-\O
~O:; l'l '{b3b
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
1501
Depreda~on
Available Aller 2030
151,667 27,360 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 65000
33,160,886
I _ Es~mated Inflow into Tyee Lake -+- Powerplant Hydraulic Capacity I 400
350
300
250
I 200
~
150
100
50
0 I I I I II I I I ~I f M A M 1 J985 I Q It PI J1 ' M " M 1J986 Ii 9 It PI J1 f M A M 1 J
9sl' • Q It DI1 f M A M 1 J98S" • Q It J 1 ' M " to! 1 J989" , Q It J 1 ' M A M 1 J
990" • Q It 11 f M A M 1991" • 0 " PI r F M A "'1992" • 0 " 1 r f M " M1993 .... Q " J
Figure 5-1 Tyee Lake Project - Estimated Historical Flows
Tyee Lake
--------------------~
I ®-<ID--'~ ! I '-£J-I. I I ®-([)......I I
: I ~--------------______ I
r I
- - - - - - 1 WmuseU Switcbyud
I
---IL_-+-t-I _--+1 _-.-.....,
I • ~ ...... 1 4f----+_ ....... 1
I I I
....
r--------l I I I I I I I I I I I I I I - - - - - - - - - - WIlIIJ8eU Substalioa
Figure 5-2 Tyee Lake Project - Transmission and Substation System
I
Figure 5-3 Tyee Lake Project -Transmission Line Support Structure - Wrangell Switchyard to Wrangell Substation
Chapter 6
ESTIMA TION 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 projects.
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 contributions, 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 evaluation 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
7176/0 202~CHA6.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 6130190 6130/91 6130/92 6130/93 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 Authoriiy
Administration 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 Requirements 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
Fixed Contribution to Renewal and Replacement Fund 500,000 500,000 500,000 500,000 500,000 500,000 500,000 500,000
TOTAL PRODUCTtON 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
Facility Charge for State of Alaska Debt Service 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 6153,433 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 2,438,169 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 tolerance 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 stmctures involved.
The risk evaluation performed for this study relies heavily on the condition assessment, 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 components 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 stmcture, 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 projectl.
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 stmctures 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.
71 76/G 202~CHA6.wP 6-3
repair cost is low, but the maximum possible cost is the cost associated with the reconstruction of the facility.
With the estimated probability of occurrence and the estimated costs and outage duration, 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 determined. 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 distribution curve is not the average or expected cost or outage duration, because the distribution 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 in 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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way, and other items in close proximity to the dam and reservoir are included 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, access facilities, rolling stock, and all of the miscellaneous structures in the vicinity of the powerhouse, with the exception of the switch yard.
5. Machinery - includes the mechanical and electrical equipment in and around the powerhouse, excluding the switchyard.
6. Switch yard, 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 - includes the foundations, structures, insulators, conductors and other miscellaneous items associated with the transmission line.
6.2.3 Earthquake
All structures are exposed to possible earthquake damage. The potential for earthquake 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 structures 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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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 System (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 systems.
Because of oil storage, there is a small possibility of fire damage at the submarine cable terminations.
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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 proximity to important and critical structures and equipment. Where steep slopes are dose 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 switch yard 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:
1. 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 Aleutian Islands of Alaska, triggering a tsunami. The extent of damage to structures 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 loca11andslides 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 earthquake, and generated a tsunami that had a run-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 switch yard and transmission 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 damages 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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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 susceptible 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 are, 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 transmission line and electrical equipment insulators and problems with air handling systems. In addition, volcanic ash could contaminate reservoir water, and cause additional 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 contaminate 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 combined 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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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 switch yards and substations, there is a potential for spills in the powerhouse.
Oil may be stored at the submarine cable terminations, and therefore, a small 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 operation 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 breakdown 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 (Le. dam failure) or may be relatively minor in nature.
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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 tabulation 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 tabulation 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 various 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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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 various 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 generally 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 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 category are (I) equipment and structural repairs or modifications that have not been deferred, but are now required
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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 nonnal 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 performance 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 financial 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 detennining 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. detennined so that the correct proportion of the total payments are made during the 35-year planning horizon. For example, if a replacement 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 detennined, all the items' funds are summed and lumped together in five year increments. This analysis assumes a 4% real discount rate on annual payments with prices at the 1995 price level.
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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 escalation 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 ''Projected Most Likely Repair and Replacement Costs" 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 presented.
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.
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Table 6-4
SWAN LAKE PROJECT· RISKS TO PROJECT COMPONENTS
Landslide or Volcanic Inlemal
Item Earthquake Flood Fire Rockfall Avalanche Tsunami Activity VVind Snow Spills Contamination Accidents Failure
Dam and
Spillway • • • •
Intake and
Tunnel • • •
Powerhouse Structures
(substructure, superstructure • • • • • and roadways, docks and runways)
Powemouse Mechanical • • • • • • • and Electrical
Switchyard
at Powemouse • • • • • • • •
Transmission
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 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
Table 6-5 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$) Expected Outage Time (days)
Structure Condition of Occurrence Most Likely Estimate Low Likely High Low Likely High
Powerhouse Earthquake
Structures No Damage 0.1 (substructure, superstructure, Minor 0.1 and roadways, docks and runways) Moderate 0.01 20,000 40,000 60,000
Major 0.001 200,000 400,000 600,000 10 30 60
MCE 0.0001 3,450,000 6,900,000 13,800,000 120 240 360
Flood No Damage 1 0.1 Minor 0.1 Moderate 0.01 10,000 20,000 30,000 Major 0.001 100,000 200,000 300,000 0 10 PMF 0.0001 500,000 1,000,000 1,500,000 10 30
Fire 0.005 0.1 5,000 10,000 9,867,000 7 30 360 Tsunami 0.02 0.1 100,000 200,000 1,000,000 7 14 120 Internal Failure 0.00001 0.1 600,000 1,200,000 13,800,000 60 90 180
Powerhouse Mechanical Earthquake and Electrical No Damage 1 0.1
Minor 0.1 Moderate 0.01 20,000 40,000 60,000 Major 0.001 200,000 400,000 600,000 30 60 MCE 0.0001 1,342,500 2,685,000 5,370,000 120 180 360
Flood No Damage 0.5 Minor 0.1 Moderate 0.01 20,000 40,000 60,000 Major 0.001 100,000 200,000 300,000 15 30 PMF 0.0001 671,250 1,342,500 2,685,000 30 60 90
Fire 0.005 0.1 10,000 50,000 1,000,000 2 7 30 Tsunami 0.02 0.1 100,000 200,000 300,000 7 14 30 Spills 0.01 0.1 2,000 10,000 20,000 0 0 Accidents 0.1 0.1 2,000 10,000 1,000,000 1.0 2 Internal Failure 0.02 0.1 100,000 200,000 1,000,000 30 60 90
Table 6-5 Page 3 of 4
SWAN LAKE PROJECT - ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days) 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 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 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 3 30
Structure
Bailey Substation
Table 6-5 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 Earthquake No Damage 0.5 Minor 0.1 Moderate 0.01 10,000 40,000 15 Major 0.001 40,000 100,000 200,000 30 90 MCE 0.0001 200,000 500,000 900,000 90 240
Fire 0.01 0.5 5,000 10,000 100,000 2 Tsunami 0.02 0.1 100,000 150,000 7 Snow 0.02 0.5 2,000 5,000 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 Internal Failure 0.5 0.5 20,000 40,000 60,000 1
High
30 150 360
7 30 2 7
1 7
Table 6-6
SWAN LAKE PROJECT. MEAN ANNUAL REPAIR COSTS
Landslide or Volcanic Internal
Item Earthquake Flood Fire Rockfall Avalanche Tsunami Activily Wnd Snow ~ Contamination Accidenls Failure TOTAL
Dam and
Spillway 468 1,760 1,171 140 3,539
Inlake and
Tunnel 1,122 1,140 2,262
Powerhouse Structures
(substructure, superstructure 5,702 1,786 3,237 3,801 14,526
and roadways, docks and runways)
Powerhouse Mechanical 3,855 3,031 188 3,144 75 6,575 3,288 20,156
and Electrical
Switchyard
at Powerhouse 1,511 339 1,153 218 1,116 42 1,113 19,937 25,429
Transmission
Une 4,806 313 5,831 2,238 12,576 28,112 1,138 933 11,794 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 6-7
SWAN LAKE PROJECT - MEAN ANNUAL OUTAGE DAYS
Landslide or Volcanic Internal
Item Earthquake Flood Fire Rockfall Avalanche Tsunami Adivity Wind Snow ~ Contamination Accidents Failure TOTAL
Dam and
Spdtway 0.01 0.01 0.02 0.04
Intake and
Tunnel 0.01 0.01
Powerhouse Strudures
(substrudure, superstrudure 0.18 . 027 0.41 0.1!6
and roadways, docks and runways)
Powerhouse MechanK:.81 0.21 0.09 002 0.24 0.06 0.92 1.54
and Etedrical
Swilchyan:l
at Powerhouse 2.28 0.03 0.09 0.01 003 0.01 0.13 1.14 3.72
Transmission
Line 1.50 0.12 0.25 1.32 0.88 3.49 0.03 0.03 1.75 9.37
Baily
SubstaUon 222 0.03 028 0.22 2.73
SWAN TOTAL 2.28 0.09 0.47 0.25 1.32 0.88 3.50 003 0.04 048 4.05 13.39
Table , ..
SOLOMON GULCH PROJECT· RISKS TO PROJECT COMPONENTS
Landslide or Volcanic Internal
Ilem Eartnguake Flood Fire Rockfall ~ Tsunami ~ ~ Snow 2E!!!!.... Contamination ~ ~
Dam, Spillway,
OuUet and Penstock
through Dam • • • •
Penstock. Valves
and Vafvehouse • • (incl. losl of water to VFOA)
Powemouse Slrudures
(substructure, superstructure • • • • • and roadways, docks and runways)
Powemouse Mechanical • • • • • • • • and Electrical
Switchyard
at Powerhouse • • • • • • • •
Transmission
line • • • • • • • • • •
Meals
Substation • • • • • • •
Pll
Substation • • • • • • •
P12
Substation • • • • • • •
Structure
Dam, Spillway, Outlet and Pel1stock through Dam
Penstock, Valves and Valve house
Table 6-9 Page 1 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 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 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 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 Page 2 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$) Expected Outage Time (days)
Structure Condition of Occurrence Most Likely Estimate Low Likely High Low Likely
Powerhouse Earthquake
Structures No Damage 0.1 (substructure, superstructure, Minor 0.1 and roadways, docks, and runways) Moderate 0.01 20,000 40,000 60,000
Major 0.001 200,000 400,000 6,000,000 10 30 MCE 0.0001 2,285,500 4,405,000 8,810,000 120 240
Flood No Damage 0.5 Minor 0.1 Moderate 0.01 10,000 20,000 30,000 Major 0.001 100,000 200,000 300,000 0 PMF 0.0001 500,000 1,000,000 1,500,000 10
Fire 0.005 0.1 5,000 10,000 6,299,150 7 30 Tsunami 0.04 0.1 100,000 400,000 8,810,000 7 14 Internal Failure 0.00001 0.1 600,000 1,200,000 8,810,000 60 90
Powerhouse Mechanical Earthquake and Electrical No Damage 0.1
Minor 0.1 Moderate 0.01 20,000 40,000 60,000 Major 0.001 200,000 400,000 600,000 30 MCE 0.0001 852,500 1,705,000 3,410,000 120 180
Flood No Damage 0.1 Minor 0.1 Moderate 0.01 20,000 40,000 60,000 Major 0.001 100,000 200,000 300,000 15 PMF 0.0001 426,000 852,000 1,705,000 30 60
Fire 0.005 0.1 10,000 50,000 1.000,000 2 7 Tsunami 0.02 0.1 100,000 200,000 300.000 7 14 Volcanic Activity 0.04 0.1 5,000 10,000 100,000 1 Spills 0.01 0.1 2,000 10,000 20.000 0 Accidents 0.1 0.1 2,000 10,000 1.000,000 1.0 Internal Failure 002 0.1 100,000 200,000 1.000.000 30 60
High
60 360
10 30
360 120 180
60 360
30 90
30 30
5 0 2
90
Structure
Switchyard at Powerhouse
Transmission Line
Table 6·9 Page 30f4
SOLOMON GULCH PROJECT· ESTIMA TED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Condition of Occurrence Most Likely Estimate Low Likely High Low Likely
Earthquake No Damage 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 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 Intemal 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 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 05 25,000 40,000 100,000 2 3 Snow 1 05 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
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 0.5 Minor 0.1 Moderate 0.01 20,000 SO,OOO 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 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 Intemal Failure 0.5 0.5 20,000 40,000 60,000 1
Earthquake No Damage 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 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 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 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
High
30 180 360
7 2 7
7
30 180 360
7 2 7 1 1 7
30 180 360
7 2 7
1 7
Table 6-10
SOLOMON GULCH PROJECT - MEAN ANNUAL REPAIR COSTS
Land,lideor Volcanic Inlemal
Ilem Earthquake Flood Fire Rocklall Avalanche Tsunami ~ Wind Snow Spills Contamination Accidenls Failure TOTAL
Dam, Spillway,
OuDet and Penslocl<
Ulrough Dam 987 3,965 5,900 10,852
Pen'locI<, Valves
and Valvehouse 897 897
Powert1ouse Structures
(substructure, superstructure 8,291 2,434 2,399 30,403 154 41,881
and roadways, docl<. and runways)
Powert1ouse Mechanical 3,542 2,531 351 3,178 482 8,844 3,871 20,843
and Electrical
Swilchyard
at Powert1ouse 1,882 218 1,191 309 1,099 45 1.130 20,087 25,741
Transmission
Line 8,818 2,445 309 6,334 2,365 25,410 56,729 1,151 334 11,153 115,046
Meals
Substation 2,419 351 45 288 1,110 1,116 20,034 25,363
Pl1
Substation 2,077 355 45 329 1,135 1,115 20,181 25,237
P12
Substation 2.835 355 44 322 1,104 1.125 20.019 25,804
SOLOMON GULCH TOTAL 29,526 11,375 4,336 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
lIem Earthquake Flood Fire Rockfall Avalanclle Tsunami ~ Wind Snow Spills Contamination Accidents Failure TOTAL
Dam, Spillway,
OuUet and PenstOCk
tnrough Dam 0,29 0,02 0,31
PenstOCk, Valves
and ValvehOuse 0.10 0,10
Powemouse Structures
(substructure, superstructure 0.24 0.01 0,11 0.66 0.02 1,04
and roadways, dOckS and ruoways)
Powerhouse Mechanical 0,19 0,09 0.04 0,23 0,03 0,06 0,94 1.57
and Etectrical
SWilchyard
at Powerhouse 2.23 0.03 0,09 0.03 0.03 0.Q1 0,13 1.16 3.71
Transmission
Line 3.20 005 0,16 1.76 0.36 1,74 7,02 003 0,Q2 1,50 15,84
Meats
Substation 2.34 0.Q3 0.Q1 0.03 0,03 0,13 1.09 3,66
Pl1
Substation 2,12 0,03 0,01 0,03 0,03 0,13 1,12 3.47
P12
Substation 2.41 0.03 0,01 0,02 003 0.13 110 3,73
SOLOMON GULCH TOTAL 3.20 009 0.43 176 0.66 0,03 1,74 7,08 0,11 0.13 050 6,93 22,76
Table 6·12
TERROR LAKE PROJECT. RISKS OF PROJECT FAILURE
Landslide or Volcanic Internal Item Earthquake Flood Rockfall Avalanche Tsunami Activity Wind Snow Spills Contamination Accidents Fa~ure
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 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 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 0.1
Minor 0.1
Moderate 0.01
Major 0.001 225,000 450,000 675,000 10 20 60
MCE 0.0001 450,000 900,000 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 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 2 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$) Expected Outage Time (days)
Structure Condition of Occurrence Most likely Estimate Low Likely High Low Likely High
Powerhouse Structures Earthquake (substructure, superstructure, No Damage 1 0.1
and roadways, docks and runways) Minor 0.1 Moderate 0.01 20,000 40,000 60,000 Major 0.001 200,000 400,000 600,000 10 30 60 MCE 0.0001 3,850,000 7,700,000 15,400,000 120 240 360
Flood No Damage 0.5 Minar 0.1 Moderate 0.01 100,000 200,000 500,000 Major 0.001 300,000 500,000 800,000 10 PMF 0.0001 1,000,000 2,000,000 3,000,000 10 30
Fire 0.005 0.1 5,000 10,000 11,011,000 7 30 360 Landslide/Rockfalls 0.02 0.5 35,000 50,000 100,000 15 30 Tsunami 0.02 0.1 100,000 200,000 1,000,000 7 14 120 Internal Failure 0.00001 0.1 600,000 1,220,000 15,400,000 60 90 180
Powerhouse Mechanical Earthquake and Electrical No Damage 0.1
Minor 0.1 Moderate 0.01 20,000 40,000 60,000 Major 0.001 200,000 400,000 600,000 30 60 MCE 0.0001 1,067,500 2,135,000 4,270,000 120 180 360
Flood No Damage 0.1 Minor 0.1 Moderate 0.01 20,000 40,000 60,000 Major 0.001 100,000 200,000 300,000 15 30 PMF 0.0001 533,750 1,067,500 2,135,000 30 60 90
Fire 0.005 0.1 10,000 50,000 1,000,000 2 7 30 Tsunami 0.02 0.1 100,000 200,000 300,000 7 14 30 Volcanic Activity 0.04 0.1 5,000 10,000 100,000 1 5 Spills 0.01 0.1 2,000 10,000 20,000 0 0 ACCidents 0.1 0.1 2,000 10,000 1,000,000 1.0 2 Internal Failure 0.02 0.1 100,000 200,000 1.000,000 30 60 90
Table 6-13 Page 3 of4
TERROR LAKE PROJECT - ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS. OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$) Expected Outage Time (days)
Structure Condition of Occurrence Most Likely Estimate Low Likely High Low Likely High
Switchyard Earthquake
at Powerhouse No Damage 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 0,01 0.5 5,000 10,000 100,000 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 0.5 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 7
Transmission Earthquake
line No Damage 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 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 45,000 120,090 4 6 12 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 30 Internal Failure 0,5 0,1 5,000 10,000 300,000 3 30
Table 6·13 Page4of4
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 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 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 0.0 1 Internal Failure 0.5 0.5 20,000 40,000 60,000 7
Swampy Acres Earthquake
Substation No Damage 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 200,000 800,000 1,500,000 90 240 360
Fire 0.01 0.5 5,000 10,000 100,000 2 7 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 Failure 0.5 0.5 20,000 40,000 60,000 7
Table 6·14
TERROR LAKE PROJECT· MEAN ANNUAL REPAIR COSTS
Landslide or Volcanic Inlernal
lIem Earthquake Flood Fire Rocklall Avalanche Tsunami Activfiy Wind Snow Spills Contam .,ahon Accidenls Failure TOTAL
Main Dam, Spillway
and Oullet Works 12,128 27.417 4,532 44,077
Intake, Gate and
Power Tunnel 2,024 1.207 827 106,606 110,664
Penstock, Valve and
Valvehouse 491 1,204 843 2,538
Powerhouse Structures
(substructure, superstruc1ure 6,802 15,278 5,127 1,112 4,034 297 32,650
and roadways, docks and runways)
Powemouse Mechanical 3,952 2,799 147 3,329 538 77 4,738 3,435 19,015
and Electrical
SwHchyard
at Powerhouse 1,677 370 1,168 1,054 1.103 43 342 1,113 20,021 26.891
Transmission
Line 5,080 2,378 290 2,202 12,501 28,216 1,134 611 10,946 63,358
Airport
Subslatien 1,105 387 1,121 51 282 1,096 1,110 20,117 25,269
Swampy Acres
Substation 1,931 263 48 301 1,105 1,115 20,083 24,846
TERROR LAKE TOTAL 35,190 47872 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 Intemal Item Earthquake flood Fire Rockfall Avalanche Tsunami Aclivrty Wind Snow ~ Contamination Accidents Failure TOTAL
Main Oam, Spillway and Outlet WorI<s 0,97 0,75 1,72
Intake. Gate and Power Tunnel 015 0,28 0,16 2,57 3,16
Penstock. Valve and Villvehouse 0,12 031 0,09 0,52
PowertJouse Structures (substructure. superstructure 027 0,22 0,29 0,36 0,03 1,17
and roadways. docks and runways)
Powerhouse Mechanical 0,26 0,08 0,04 0,23 0,03 0,06 0,94 1.64 and Electrical
Swhchyard at Powerhouse 2,33 0,03 0,32 0,11 0,03 0,01 0,03 0,13 1,16 4,15
T ransm ission Line 1,89 0,05 0,12 0,34 0,87 3,50 0,03 0,01 1.49 8,30
Airport Substation 2,03 0,03 0,10 001 0,03 0,03 0,13 1,14 3,50
Swampy Acres Substation 2,33 0,03 0,01 0,03 0,03 0,13 112 3,68
TERROR LAKE TOTAL 2,33 0,75 047 1,20 0,25 0,36 003 0,87 3,55 0,07 0,12 0.46 8.45 1891
Table 6-16
TYEE LAKE PROJECT - RISKS OF PROJECT FAILURE
Landslide or Volcanic Internal
Item Earthquake Flood Fire Rockfall Avalanche ~ Activity ~ ~ SpillS Contamination Accidents Faiture
Intake and
Power T unoel • • • • • Recognize potential rockfall
Penstock • • Powerhouse Structures
(substructure, superstructure • • • • • • • and roadways, docks and runways)
Powerhouse Mechanical • • • • • • • and Electrical
Switch yard at
Powerhouse • • • • • • • • • •
Transmission
Line • • • • • • • • • •
Submarine
Cable • • • • • •
Wrangell
Switchyard • • • • • • • •
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 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 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 3,076,000 15 30 360
Internal Failure 0,00001 0,1 70,000 175,000 3,366,000 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 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 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$) Expected Outage Time (days)
Structure Condition of Occurrence Most likely Estimate low likely High LOW likely High
Powerhouse Mechanical Earthquake and Electrical No Damage 0.1
Minor 0.1 Moderate 0.Q1 20,000 40,000 60.000 Major 0.001 200,000 400,000 600,000 30 60 MCE 0.0001 986,250 1,972,500 3,945,000 120 180 360
Flood No Damage 0.1
Minor 0.1 Moderate 0.Q1 20,000 40,000 60,000 Major 0.001 100,000 200,000 300,000 15 30 PMF 0.0001 493,125 986,250 1,972,500 30 60 90
Fire 0.005 0.1 100,000 500,000 1,000,000 2 7 30 Tsunami 0.02 0.1 100,000 200,000 300,000 7 14 30 Spills 0.01 0.1 2,000 10,000 20,000 0.0 0 Accidents 0.1 0.1 2,000 10,000 1,000,000 1.0 2 Internal Failure 0.02 0.1 100,000 200,000 1,000,000 30 60 90
Switchyard at Earthquake
Powerhouse No Damage 0.5 Minor 0.1 Moderate 0.01 20,000 50,000 15 30 Major 0.001 50,000 150,000 350,000 30 90 150 MCE 0.0001 500,000 1,000,000 1,900,000 90 240 360
Fire 0.01 0.5 5,000 10,000 100,000 2 7 landslide 0.02 0.5 35,000 50,000 100,000 15 30 Avalanche 0.02 0.1 35,000 50,000 300,000 15 90 Tsunami 0.02 0.1 100,000 150,000 7 30 Snow 0.02 0.5 2,000 5,000 0.0 2 Spills 0.01 0.5 5,000 30,000 60,000 2.0 7 Contamination 0.1 0.5 5,000 10,000 20,000 0.1 Accidents 0.5 0.5 1,000 2,000 4,000 0.0 1 Internal Failure 0.5 0.5 20,000 40,000 60,000 7
Structure
Transmission Line
Submarine Cable
Table 6.17
Page 3 of5
TYEE LAKE PROJECT· ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$)
Condition of Occurrence Most Likely Estimate low Likely High
Earthquake No Damage 0.1
Minor 0.1
Moderate 0.01 40,000 200,000 Major 0.001 1,000,000 1,500,000 5,000,000
MCE 0.0001 4,000,000 8,000,000 18,000,000
Fire 0.01 0.5 10,000 30,000 60,000
landslide 0.02 0.5 35,000 50,000 100,000 Avalanche 0.02 0.1 35,000 50,000 300,000 Tsunami 0.02 0.1 200,000 300,000 Wind 0.5 0.5 25,000 40,000 100,000
Snow 0.5 15,000 45,000 120,000 Contamination 0.1 0.5 5,000 10,000 20,000 Accidents 0.01 0.1 1,000 10,000 1,000,000 Internal Failure 0.5 0.1 5,000 10,000 300,000
Earthquake (included in the transmission Une earthquake risk analysis)
No Damage 1 0.1 Minor 0.1
Moderate 0.01
Major 0.001
MCE 0.0001
Fire 0.Q1 0.5 10,000 30,000 60,000 Tsunami 0.02 0.1 200,000 300,000 Spills 0.01 0.1 5,000 30,000 60,000 Accidents 0.01 0.1 50,000 200,000 1,000,000 Internal Failure 0.01 0.1 20,000 100,000 1,000,000
Expected Outage Time (days)
low Likely High
30 60 60 120 240
180 270 360
4 10 30 15 30 15 90 30 60
2 3 6 4 6 12
0.1 1 1 30 3 30
0 7 30
2.0 7 0.5
7 30
Table 6·17 Page4of5
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$) Expected Outage Time (days)
Structure Condition of Occurrence Most likely Estimate Low Likely High Low likely High
Wrangell Earthquake Switchyard No Damage 1 0.5
Minor 0.1 Moderate 0.01 10,000 40,000 15 30 Major 0.001 40,000 120,000 300,000 30 90 150 Mer: 0.0001 200,000 450,000 800,000 90 240 360
Fire 0.01 0.5 5,000 10,000 100,000 2 7 Tsunami 0.02 0.1 100,000 150,000 7 30 Snow 0.02 0.5 2,000 5,000 0.0 2 Spills 0.Q1 0.5 5,000 30,000 60,000 14 30 Contamination 0.1 0.5 5,000 10,000 20,000 0 Accidents 0.5 0.5 1,000 2,000 4,000 0.0 1 Internal Failure 0.5 0.5 20,000 40,000 60,000 7
Wrangell Earthquake
Substation No Damage 1 0.5 Minor 0.1 Moderate 0.01 10,000 40,000 15 30 Major 0.001 40,000 120,000 300,000 30 90 150 Mer: 0.0001 150,000 350,000 700,000 90 240 360
Fire 0.01 0.5 5,000 10,000 100,000 2 7 Tsunami 0.02 0.1 100,000 150,000 7 30 Snow 0.04 0.5 2,000 5,000 0.0 2 Spills 0.01 0.5 5,000 30,000 60,000 2 7 Contamination 0.1 0.5 5,000 10,000 20,000 0 1 Accidents 0.5 0.5 1,000 2,000 4,000 0.0 1 Internal Failure 0.5 0.5 20,000 40,000 60,000 7
Structure
Petersburg Substation
Table 6-17 Page 5 of5
TYEE LAKE PROJECT - ESTIMATED REPAIR COSTS AND OUTAGE TIMES DUE TO NATURAL EVENTS, ACCIDENTS, OR EQUIPMENT FAILURES
Probability Probability of Exceeding Repair or Replacement Cost (1995$)
Condition of Occurrence Most likely Estimate low likely High
Earthquake No Damage 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 Inlemal Failure 0.5 0.5 20,000 40,000 60,000
Expected Outage Time (days)
low likely High
15 30 30 120 180
120 240 360
2 7 7 30
0.0 2 2 7 0
0.0 1 7
Table 6-18
TYEE LAKE PROJECT - MEAN ANNUAL REPAIR COSTS
Landslide or Volcanic Internal
Item Earthquake Flood Fire Rockfall Avatanche Tsunami Activity Wind Snow Spills Contamination Accidents Failure 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 Mechanical 254 188 1,680 3,191 68 4,888 4,565 14,834
and Electrical
Switchyard at Powerhouse 207 339 1,125 987 1,136 47 333 1,127 1,150 19,957 26,408
Transmission Une 1,180 321 1,096 1,041 2,340 26,013 56,112 1,146 562 10.752 100,563
Submarine Cable 322 2.618 178 1.979 1.446 6.543
Wrangell Swilchyard 115 399 1,289 45 334 1.114 1,128 20.070 24,494
Wrangell Substation 38 384 1.138 85 323 1.097 1,119 19.841 24.003
Petersburg Substation 337 326 1.085 50 344 1.127 1.121 19,994 24,384
TYEE LAKE TOTAL 3,820 409 9.947 11.651 3.748 13.873 26,013 56.339 1,560 5.611 15,037 164.359 312.387
Table 6·19
TYEE LAKE PROJECT· MEAN ANNUAL OUTAGE DAYS
landslide or Volcanic Inlemal
Item Earthquake flood Fire Rockfall Avalanche Tsunami Activity \Mnd Snow Spills Contamination Accidenls Failure TOTAL
Intake and Power Tunnel 001 1.48 0.14 2,62 4,25
Penstock 0.Q1 0.01
Powerhouse Structures 0.06 0.12 0.25 0.31 0,28 1,02
(substructure, superstructure,
and roadways, docks and runways)
Powerhouse Mechanical 0.04 0.02 0.03 024 0,06 1.01 1.40
and Electrical
Switchyard at Powerhouse 0.03 0,03 0.30 0,21 0.10 0.01 0.02 0.03 0.13 1,13 1.99
Transmission line 0.05 0,12 0.30 0.22 0,39 1.73 7.02 0.03 0.01 1.50 11,37
Submarine Cable 0.11 0.Q1 0.04 0,16
Wrangell Switchyard 0.06 0,03 0,13 0.Q1 0.15 0.03 0.12 1.10 1.63
Wrangell Substation 0,08 0.03 0,10 0.02 0.02 0,03 0.13 1.15 1.56
Petersburg Substation 0.04 0.03 0.10 0.01 0.03 0.03 0.13 1.10 147
TYEE LAKE TOTAL 0,08 0.02 0,39 2.33 0,86 0.39 1.73 707 0.23 0,15 0.56 9,65 <;b J-.
Table 6-20
PROJECTED COSTS (IN US DOLLARS, AT 1995 PRICE LEVELS, FOR FIVE-YEAR PERIODS INDICATED)
Year
Item 1996-2000 2001-05 2006-10 2011-15 2016-20 2021-25 2026-30
SWANLAKE Remedial Work for ~ems of 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 After 2030 359.309 373.252 406.645 544,895 716.926 960.453 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 797645 797645 Z97!l4:i 797645 79764:i 797645 TOTAL -SWAN LAKE 9,887.684 8.099.027 10.832,670 10,734.901 13.336.956 9.129,145
SOLOMON GULCH Remedial Work for Items of Deficient Design
Remedial Work for Rems 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 Maintenance Costs 6.815.030 6.815.030 6,815.030 6.815,030 6,815.030 6.815,030
Risk Costs 1 4~7 32Q 1457320 1457320 1 4:iJ 32Q -1..4~ 1 457 ~20 TOTAL - SOLOMAN GULCH 10.907.137 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
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 1 742 ~4Q 1 746540 1 7411540 1746540 1 74254Q 1 Z4!i 54!) TOTAL - TERROR LAKE 19,895,879 17.207,976 20,982,914 17.214,842 16,935,450 16,558,577
TYEE LAKE Remedial Work for ttems 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 405,592 405,592 508.316 780,337 1.535,548 2.765.926 3.183,308 Normal Operation and Maintenance Costs 8.780,110 8,760,110 8,760,110 8,760,110 8,760,110 8,760,110 8.760.110
Risk Costs 1 :i!l1 !!3~ 1 521 935 .......J.,5~ 156193S 1 521 !l~5 1 561 9~5 TOTAL- TYEE LAKE 30,858,137 11.647.637 13,669,361 16.052,382 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 Mamtenance 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 2486100 Allowances For Replacements After 2030 1,510,948 1,524,890 1.903.222 2.879.635 4.509.110 6.914,720 8.287941 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 ......... M.!I.M.4.Q 5563440 .. ....2.S§M4.!l 5563440 2223440 .........2.~MQ ~556H~Q TOTAL .. ALL FOUR PROJECTS 71.548.838 43.612.980 52.313.512 60,221,163 74,196,694 74.1.68.946 50.467731
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 For Replacements After 2030 144524 72Z,62;Z 722622 122622 122622 122622 722622 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 233409 1 167044 j 1670<1<1 1 167044 1 167044 1 161044 11670<1<1 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 156939 18<1695 18<16!;!5 18<1695 18<1695 18<16!;!5 18<1695 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 263024 1315122 1315122 1315122 1 3j5 122 j 315 122 1 315 12, 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 After 2030 197897 3989483 3989483 3989483 3989483 3989483 3989483 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 funds, and a 8% borrowing rate. Levelized payments are calculated 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 levelized payment analyses for each project are shown on the "Projected Most Likely Repair and Replacement Costs" tables in the
appropriate chapters.
2026-30
2,003,337 122 622
2,725,959
3,325,566 1167044 4,492,610
3,030,568 18<1695
3,815,263
5,877,200 1 315122 7,192,322
14,236,672 J 989 483
18,226,155
Table 6-22
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
20,000 2067000 2,087,000
400,667 144,524 545,192
2041 zoo 2,047,700
665,113 233409 898,522
5,20Z OOQ 5,207,000
606,114 156,939 763,053
17,000,000 565,000
1,685,500 19,250,500
1,175,440 263024
1,438,464 y Period 1996-2030 (Ann~-c-o-st-.-n-ot-e-s-c-a-Ia-te-d-)-----~---~'---'--'----------,----,- -----"- ""---"-",,,,-
\ Risk Costs (3) 159,529 291,464 349,308 312,387
(1) Based a several expenditures to take place in the period 1996-2000, at 1995 price levels (2) Annuallevelized cost (actual cost remains constant throughout the entire 35-year planning horizon) (3) Annual cost at a 1995 price level
17,000,000 585,000
11,007,200 28,592,200
2,847,334 Z9Z,89Z
3,645,231
1,112,688
100% ---.----------,------~-------------- ...... ---.--.--
90%
80%
tl 70% r::: co al 60% tl )(
LIJ 50% T-'0
~ 1
I 40%-'-----
! e 30% a. - , - -
20% I -------,
100/. I ------
0%
0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
Possible damage or repair cost in any year (in million$)
Figure 6-1 Swan Lake Project - Expected Annual Costs Due to Natural Occurrences. Accidents or Equipment Failure
90% -----------------,------------------------------------------,----------------,------------........ -----------
80%
70%
I 60% +. tl
r:::
'" ~ j;( 50%-'-
LIJ
'15 I ,?!i' 40% ~ -:l'l ~ 30%
10:.
20%
10% 1_ .
O%~------~~~~~~-------------------------------------------------------------o 30 60 90 120 150 180 210 240 270 300 330 360
Possible number of outage days in any year -----_ ....... _---_.
Figure 6-2 Swan Lake Project - Expected Number of Outage Days Due to Natural Occurrences. Accidents or Equipment Failure
100%
90%
80% + 8 70% c: III ."
~ 60%~--->< w
50% '0 ?;
40% :is III ..0
i e 30% ;-Q. i I
20% ~-
10%
0%
0,0 0,1 0,2 0,3 0.4 0,5 0,6 0,7 0,8 0,9 1.0
Possible damage or repair cost in any year (in million$)
Figure 6-3 Solomon Gulch Project - Expected Annual Costs Due to Natural Occurrences, Accidents or Equipment Failure
100% ----- ---_ ...... _--
>~ :is 40% 11 £ 30%
10%
o 30 60 90 120 150 180 210 240 270 300 330 360
Possible number ot outage days in any year
Figure 6-4 Solomon Gulch Project - Expected Number of Outage Days Due to Natural Occurrences, Accidents or Equipment Failure
,,--" .... ---~~ ..
100"'" --=~~~~ .. ~~~---~---~----,------r-----:----------~~ ... ~--.. ----
90% ... - I -
80% + --~ 70% .l. __ _ ... -1- _
c:: <II ."
60% ~ )(
w 50% '15
~ ii 40% <II e
30% t a.
20%
10%
0%
0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 O.S 0.9 1.0
Possible damage or repair cost in any year (in millionS) -----------------------------------.. ---.... -.~- .. ----
Figure 6·5 Terror Lake Project· Expected Annual Costs Due to Natural Occurrences. Accidents or Equipment Failure
----------------------------_ ... _-- .... _ ... _-- .... _ ... _-- ........ _-100%
90%
80%
~ ...!.. - - -
c:: to ."
'" ~ )(
w 50"'" '15
, ~ ~ i .0 2 a.
20% , r - - - 1 - - -
10"A>
0% -
0 30 60 90 120 150 180 210 240 270 300 330 360
Possible number of outage days in any year ~~--.... -~--~------------- ---------------.... _-_ .. _--
Figure 6·6 Terror Lake Project - Expected Number of Outage Days Due to Natural Occurrences. Accidents or Equipment Failure
-
-
100%
80%
B 70% c: til a: 60%
~ w 50% 'Is
~ ::s 40% :- - - - - -til
~ 30% n.
20%
10%
... ____ l __
._1-,
-~--~-,--
----'--
, -'
, T ~------
'-
O%L---~----~- --------~---=::::==================~~~ 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
Possible damage or repair cost in any year (in million$)
Figure 6·7 Tyee Lake Project· Expected Annual Costs Due to Natural Occurrences. Accidents or Equipment Failure
100%
80%
B 70% c: til a: 60%
~ w 50% 'Is
~ :is 40% .l! e 30% n.
I -~----
20%
10%
0%
0 30 60 90 120 150 180 210 240 270 300 330 360
Possible number of outage days in any year
Figure 6-8 Tyee Lake Project· Expected Number of Outage Days Due to Natural Occurrences. Accidents or Equipment Failure