HomeMy WebLinkAboutSalmon Creek Final Feasibility Study 1978\
''
RECEIVED
JUN 2 81978
AlASKA POWER AUTHORITY
FiNAL
FEASI B! UTY STUDY
of
ALTEf{Nf\TIVES roR F~E!lABiLIT/\TION
OF SAU<"iON CREEl<. HYDHOELECTRIC PROJECT
(FPC No 0 2307)
Submitted to
Alaska Electric Light and Powet' Company
Juneau, Alaska
f~<bn.:h 1973
ROBERT Wo RETHERFORD ASSOCIATES
Po Oo Rox 6410
Anchot'age, Al<'lska 99502
I nternat ion iii Engineering Cornpany, Inc 0
220 f'.1orltr;:J'A·•:·:'t"y Stn::et
San Francisco 1 California 941 OtJ.
rc W )l ~OBER_~~-RETHERF?RD ASSOCIATE? u D \J CONSULTING ENGINEERS
March 16, 1978
TELEPHONE 344-2585
P. 0. BOX 6410
ANCHORAGE. ALASKA 99502
TELEX: 626-380
Mr. William A. Corbus, Assistant Manager
Alaska Electric Light and Power Co.
134 N. Franklin Street
Juneau, Alaska 99801
Dear Mr. Corbus:
204-710
We are pleased to submit twenty-five (25) copies of a feasibility study of
alternatives for the rehabilitation of Salmon Creek Hydroelectric project (FPC
No. 2307).
Presented in the study are an update on the hydrology 1 a hydraulic analysis
of the waterways, capital cost estimates of alternatives, power cost estimates
of alternatives, and capacity and energy requirements forecasts for the Juneau
area assuming the capital does and does not move. Our conclusions are that
(1) the projected load growth for the AELP system will justify the rehabilitation
of the Salmon Creek hydroelectr-ic project; (2) power from the rehabilitated
project will be significantly less than diesel generation and competitive with
Snettisham power in the near future; and (3) AELP should initiate methods of
financing and construction design as soon as possible. A possible source of
financing may be through the Alaska Power Authority.
The study was prepared by the joint venture of Robert W. Retherford Asso-
ciates and International Engineering Company, Inc. Contributions were made
by Kent Miller 1 Consulting Economist, who contributed the projected population
and power requirements forecasts.
Comments received as a result of the review of the preliminary report dated
January 6, 1978 have been incorporated into this report.
This has been a most inter~sting and challenging assignment. We will be
very happy to assist you in future phases of development of this important
project.
Sincerely 1
ROBERT W. RETHERFORD ASSOCIATES
G cv,£, fl.' ~,4(
Carl H. Steeby, P.E.
Principal Civil Engineer
CHS:ngl1
A DIVISION OF ARKANSAS GLASS CONTAINER CORPORATION
TABLE OF CONTENTS
SECTION Page
I. SUMMARY AND RECOMMENDATIONS
1.1 Summary
A. Hydrology
B. Hydraulics
C. Capital Cost Estimates
D. Power Cost Estimates
E. Load and Energy Requirements Forecast
F. Transmission
1. 2 Recommendations
II. EXISTING SYSTEM
2.1 General
2.2 Upper Salmon Creek Stage
2.3 Lower Salmon Creek Stage
2.4 1977 Investigations
Salmon Creek No. 2 Power Plant
Salmon Creek No. 1 Power Plant
Dams and Waterways
Inspection of Chatanika Powerhouse Equipment
Ill. PROJECTED POPULATION & POWER REQUIREMENTS
3.1 Employment in Juneau, 1975-2000
3.2 Juneau•s Population, 1975-2000
3. 3 Power and Energy Forecasts, 1975-2000
IV. HYDROLOGY
1
1
1
2
3
4
4
5
7
7
8
9
14
21
23
31
36
37
45
SECTION
V. HYDRAULICS
VI.
VII.
5.1 A. Existing System from Dam
to Powerhouse No. 2
B. Replacing 30 11 , 32 11 and 34 11
Diameter Penstock
C. Powerhouse No. 2 to Powerhouse No. 1
0. New Penstock from Dam to
Powerhouse No. 1
E. Hydraulic Recommendations
CAPITAL COST ESTIMATE
6.1 Installation of New Automated 5000 kW
Unit at Powerhouse No. 2
6.2 Upgrade Equipment and Automate Upper
Salmon Creek Powerhouse No. 2
6.3 Upgrade Equipment and Automate Lower
Salmon Creek Powerhouse No. " I
6.4 New Automated Equipment At Powerhouse
6.5 Ne\.v Automated Equipment At Powerhouse
No .. 1 (2-4500 kW Units & Eliminate
Powerhouse No. 2)
6.6 New Automated Equipment At Powerhouse
No.
No. 1 (one 9000 kW unit and Eliminate
Powerhouse No. 2)
POWER COST ESTIMAT
1
51
52
53
54
58
60
61
63
65
67
69
71
73
TABLES
TABLE
3-1 Employment in Alaska, the Southeast Region and
Juneau, 1975-2000
3-2 Juneau Area Population 1960-2000
3-3 Sales of Electricity 1960-2000
3-4 Sales of Electricity 1 Generation and
Peak Demand 1960-2000
3-5 Residential Hookup Saturation 1975-1976
4-1 Synthetic Inflow -Salmon Creek Reservoir
7-1 Power Cost Estimate -New Automated 5000 kW
Unit at Powerhouse No. 2
7-2 Power Cost Estimate -Rehabilitate and /-\utomate
Existing Powerhouse No. 2
7-3 Power Cost Estimate -Rehabilitate and Automate
Existing Powerhouse No. 1
7-4 Power cost Estimate -New Automated 3000 kW Unit
at Powerhouse No. 1
7-5 Power Cost Estimate -New Automated Plant at
Powerhouse No. 1 with 2··4500 k\N Units
7-6 Power cost Estimate -new Automated Plant at
Powerhouse No. 2 with one 9000 kW Unit
7-7 Combination Power Cost Estimate
40
41
42
43
44
46
74
75
76
77
78
19
80
FIGURE
1.
2.
3.
APPENDIX
A.
B.
FIGURES
Salmon Creek Hydroelectric Project
Penstock Plan and Profile -
Dam to Powerhouse No. 2
Sheet 1 of 2
Sheet 2 of 2
Existing Flume Detail and Suggested Rehabilitation
APPENDICES
Safety Inspection, Project No. 2307 -Alaska (1977)
Thickness Survey of the Upper and Lower
Salmon Creek Penstock and Annex Creek (1976)
10
11
12
13
A-1
B-1
SECTION I
SUMMARY AND RECOMMENDATIONS
Alaska Electric Light and Power Company (AELP) recognizes the need to
(1) add reliable backup generating capacity when energy from the
Snettisham Project is not available; (2) rehabilitate the Lower Salmon
facility, and (3) reduce operating expenses at the Upper Salmon Plant
for economic production. These requirements have led to the author-
ization of this study, which has the objectives of providing AELP with a
current estimate of the costs of alternatives and a recommendation of
the most favorable course of development. The study is summarized in
the following paragraphs and recommendations presented.
1.1 Summary
A. Hydrology (Section IV)
This is essentially an update of the hydrologic data included in the
1966 Bechtel Report.
The regulated flow from the Salmon Reservoir was determined to be
54.2 cfs from the 28-year synthetic mass hydrograph. The mean
annual flow for the 28-year pedod was 66.1 cfs.
B. Hydraulics (Section V)
The hydraulics of the existing system were analyzed and the
hydraulic characteristics, diameters, wall thicknesses, and weights
of alternate waterways were computed.
The hydraulic recommendations are shown on page 58, Section V.
Page 1
SECTION I -SUMMARY & RECOMMENDATIONS
C. Capital Cost Estimate (Section VI)
The estimate of costs are provided for six alternates:
1. A new 5000 kW automated unit at Powerhouse No. 2
(Upper Salmon Creek). This includes replacing the
existing 30", 32" and 34" sections of the penstock with
new 36 11 to reduce friction losses.
2. The upgrading and automation of the existing equipment
at powerhouse no. 2. This includes the replacement of
the penstock sections enumerated in 1.
3. The upgrading and automation of the existing equipment
at powerhouse no. 1. This includes replacing the flume
with low-pressure conduit, a new 48'' penstock and a
surge tank.
4. A new automated 3000 kW unit at powerhouse no. 1 with
waterway improvements as in 3 above.
5. The installation of two new automated 4500 kW units in
powerhouse no. 1 with a new penstock from the darn.
6. The installation of one new automated 9000 kW unit in
powerhouse no. 1 with a new penstock from the dam.
The construction costs are current (1978) costs based upon the
latest labor rates, construction equipment costs and recent costs
for mechanical/ electrical equipment and permanent materials. In
Section 7 of this t·eport, the total costs are escalated at the rate
of 7% per year through the assumed construction period for each
alternate in order to provide a realistic basis for power costs.
Page 2
1
2
3
SECTION I -SUMMARY & RECOMMENDATIONS
The 1978 capital cost estimates for the above alternates in respec-
tive order are:
1 . $3,074/000
2 2,441,000
3. 4/017/000
4. 4,459,000
5. 14,804/100
6. 14/106,900
D. Power Cost Estimates (Section VII)
Utilizing the capital cost estimates (escalated to reflect costs
through the assumed construction period) and estimates of other
annual costs, costs of power were estimated for the six alter-
natives and combinations of the first four alternatives. The cost
estimates assume financing at 10.5% interest and 20 year maturity.
The cost of power for the six alternatives and combinations thereof
are as follows:
Item Sales (kWh) 1 Cost (mills/kWh) 2
1 26/600/000 17.6
2 25,270,000 3 14.9
3 15/623,0003 36.1
4 16/445,000 34.4
5 43,167,000 45.8
6 43,167,000 43.6
2 & 3 40,893,0003 23.0
2 & 4 41,715,000 3 22.5
1 & 3 42,223,000 3 24.5
1 & 4 43,045,000 24.0
Bus bar sales --does not include transmission losses
Does not include amortization costs of existing Salmon Creek
facilities.
New units are expected to be at least 5% more efficient than
rehabilitated units.
Page 3
1
SECTION I -SUMMARY & RECOMMENDATIONS
As a comparison, an article appearing in the Dec. 22, 1977 Anch-
orage Times states 11 lf rates at Snetti sham remained the same for
the first ten years of the 60-year repayment period, they would
have to be lifted from the present 15.6 mills to at least 27.1 mills
for the last 50 years. In addition, the accounting office said, a
possible loss of customers for the Snettisham project caused by
moving the capital from Juneau might require even greater rate
increases for the remaining customers. 11 1
E. Load and Energy Requirements Forecast (Section Ill)
The basis for the electrical load growth forecasts developed for
this report are essentially forecasts of employment for the City and
Borough of Juneau. Because of the dominance of state and federal
employment in Juneau's economy, the major criteria for population
and power forecasting are projection of such employment, (1)
assuming the state capital will remain in Juneau and (2) assuming
it will be moved to Willow.
These forecasts indicate a rapid increase in electricity sales
through the year 2000, under the assumption that the capital
remains in Juneau, resulting in an overall increase of 270% in sales
over 1976. A much more modest rate of 170% increase in sales
through 2000 over 1976 is projected under the assumption that the
capital is moved.
F. Transmission
Although the transmission system was not recognized as a part of
this study, AELP should be aware of the need to rehabilitate the
transmission line between the Upper and Lower Salmon Creek
power plants in the near future. If AELP plans include a 69 kV
The accounting office referred to in this quote is the U.S. General
Accounting Office<
I' Page 4
SECTION I -SUMMARY & RECOMMENDATIONS
transmission system, an auto-transformer to step up the generator
voltage to 23,000 for present transmission from powerhouse no. 1
and a second step-up from 23,000 volts to 69 kV for the total
output of both the upper and lower powerhouses (10 MVA) for
future transmission should be included in the recommended
rehabilitation plan.
1. 2 Recommendations
The recommendations of your Engineer are to rehabilitate the
Salmon Creek Hydroelectric Project in accordance with Items and
IV of Section VI, namely: install a new automated 5,000 kW
horizontal Francis turbine-generator unit at Powerhouse No. 2,
install a new automated 3,000 kW horizontal Francis turbine-
generator unit at Powerhouse No. 1, and make the proposed
waterway changes shown in the Capital Cost Estimate (pages 61
and 67). The following are the reasons for these recommenda-
tions:
In general, the rehabilitation of the existing units is not
recommended because of the age and condition of the
equipment.
The dependable capacity of the recommended plan of 8000 kW
is 2400 kW greatet· than the plan of rehabilitating the existing
units.
The power costs of the recommended plan are considerably
less than those of a single powerhouse at tidewater even
though the recommended plan allows $52,000 per year for a
caretaker at powerhouse no. 2.
Page 5
SECTION I -SUMMARY & RECOMMENDATIONS
The anticipated power cost from Snettisham in 1984 is greater
than the recommended plan if the capital remains in Juneau
and even greater savings are likely if the capital is moved.
AELP will require an additional 2500 kW generating unit for
standby capacity before the year 1979. This capacity in a
diesel engine driven unit is estimated to cost $600,000.
Your Engineer further recommends that AELP proceed with the
engineering to implement the recommended plan and contact
Alyeska Pipeline Company for surplus 36 11 and 48 11 diameter pipe.
The contact for Alyeska surplus materials is:
Mr. R. J. Egan, Sales Specialist
ALYESKA PIPELINE SERVICE COMPANY
P. 0. Box 4-A
Anchorage, Alaska 99509
Phone (907) 265-8855
Page 6
2.1 General
SECTION II
EXISTING SYSTEM
The Salmon creek Hydroelectric Project (FPC License No. 2307)
was constructed by the Alaska Gastineau Mining Company between
1913 and 1915, developing the full head above high tide in two
stages. The project was developed to supply power for gold
mining operations.
The ownership passed to the Alaska Juneau Gold Mining Company
in 1935. In 1973 1 Alaska Electric Light and Power acquired the
electric properties located in the vicinity of Juneau from A-J
Industries, Inc., the sole surviving entity resulting from the
amalgamation of all the gold mines in the area. Included in the
electric properties was the Salmon Creek scheme.
The two stages of the Salmon Creek project consists of a lower
powerhouse (powerhouse no. I) which is located about 3. 5 miles
northwest of downtown Juneau near the mouth of Salmon Creek,
and the upper powerhouse (powerhouse no. 2) which is located
approximately 1.8 miles east from powerhouse no. I and about 2. 5
miles due north of Juneau. Regulation is provided from a reser··
voir approximately 4300 feet east of powerhouse no. 2. (See
Figure No. I.)
2.2 Upper Salmon Creek Stage
The Salmon Creek reservoir was formed by a constant angle con-
crete arch dam 167 feet high and a crest length of 648 feet, V.thich
provides 18000 acre-feet of storage at elevation 1172. The thick-
ness of the arch is 6 feet at the crest and 47.5 feet maximum at
the base. The spillway located at the north end of the dam leads
Page 7
SECTION II -EXISTING SYSTEM
through a concrete lined channel a short distance to a rock cliff,
where the discharge returns to the bed of the creek without
disturbing the foundation of the dam. The spillway has 10 water-
ways each 5 feet wide and with lips 3. 3 feet below the dam crest.
The spillway is reported to be capable of passing I ,800 cubic feet
per second before overtopping the dam.
Water flows from the dam to powerhouse no. 2 through 4447 feet of
riveted steel penstock which varies in diameter from 40 inches to
30 inches. The penstock, for the most part, lies on or partially
buried in the ground. It crosses Salmon Creek six times 1 three
times supported by bridges and three times on trestles, and passes
through a tunnel approximately 150 feet in length about lOOO feet
downstream from the dam. (See Figure No. 2 for penstock details.)
The static head varies from 560 to 725 feet.
Powerhouse No. 2 contains two units, each with a 2500 H. P. im-
pulse wheel operating at 257 RPM, direct connected to a 1400 kW,
three phase, 60 cycle, 2300 volt, 0.80 power factor, generator.
There are two exciter units i one connected to a 75 h. p., 900 RPM
impulse wheel connected to a 50 kW, 125 volt 1 d. c. motor-generator
set and one 50 kW, 125 volt, :notor-generatm-~ cl. The voltage is
stepped up to 23,000 volts by 6-600 kVA, single phase transformers
for transmission.
2.3 Lower Salmon Creek Stage
The water from the tailrace of powerhouse no. 2 can be discharged
into a conduit leading to powerhouse no. I. The flow of the South
Fork of Salmon Creek can be intercepted just below powerhouse
no. 2. The pr-esent conduit is a 4 by 5 foot timber' flume, 9876
feet long. It was constructed in 1935 and replaced an original
4 by 6 foot flume. It is laid on a 0.25 per~ cent grade and ter~
minates in a timber forebay. Approximately 2000 feet of the flume
Page 8
SECTION II -EXISTING SYSTEM
is supported by trestles where the flume traverses over ravines
and small streams. (See Figure No. 3 for flume details.) The
timber forebay is provided with an overflow flume which conveys
surges and excess water away from the forebay to a channel
leading to Salmon Creek.
There are two riveted steel penstocks, varying from 42 to 30
inches in diameter, 1625 feet long, which convey the water from
the forebay to powerhouse no. I. The static head is estimated at
400 feet.
Powerhouse no. I contains two units, each with a 2500 H. P. im-
pulse wheel operating at 257 RPM, direct connected to a 1400 kW,
three phase, 60 cycle, 2300 volt, 0.80 power factor, generator.
The voltage is stepped up to 23,000 volts by the use of three
1,250 kVA, single phase transformers for transmission. Power-
house no. I was partially destroyed by fire in 1922 and was recon-
structed in 1936. This plant has not operated since 1974 for
economic reasons.
2. 4 1977 Investigations
A. Study Group
The study group for the 1977 investigations consisted of
Mr. Delancey Smith 1 Senior Mechanical Engineer, and Mr. William
Untiedt, Senior Electrical Engineer, both of International Engi-
neering Company 1 and Mr. Carl Steeby, Principal Civil Engineer,
and Mr. Robert Edbrooke, Senior Civil Engineer r both of_
Robert W. Retherford Associates, and Mr. Kent Miller 1 Economic
Consultant.
Messrs. Smith 1 Untiedt and Edbrooke visited the project site
during the week of October 10, 1977, and Carl Steeby visited the
site during the week of November 14, 1977. The purposes of the
Page 9
N
TAKEN FROM:
U.S. GEOLOGICAL SURVEY
SHEET JUNEAU ( 8-2) 5~a ROBERT W. RETHERFORD ASSOCIATES
CONSULTING ENGINEERS
ANCHORAGE , ALASKA====~==========ss
ALASKA ELECTRIC LIGHT AND POWER COMPANY
JUNEAU, ALASKA
SALMON CREEK HYDROELECTRIC PROJECT
DATE: NOVEMBER 1977
CONTRACT N0.204-710
FIGURE NO.I
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DESIGNED CHS 121 I ,77 f(VV)l ROBERT W. RETHERFORD ASSOCIATES u !J u CONSULTING ENGINEERS
ANCHORAGE , ALASKA==============~
ALASKA ELECTRIC LiGHT AND POWER COMPANY JUNEAU, ALASKA I DATE NOVEMBER !977
DRAWN RNW 12/ I 177 PENSTOCK PLAN AND PROFILE CONTRACT NO. 204-710
CHECKED I I POWERHOUSE N0.2-DAM FIGURE N0.2
APPROVED I I SALMON CREEK HYDROELECTRIC PROJECT SCALE: GRAPHIC SHT I OF 2
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Page 13
SECTION II -EXISTING SYSTEM
visits were to obtain information on the conditon of the existing
system, collect maps, reports and data, and to study alternative
rehabilitation plans. Mr. Smith proceeded to Fairbanks from
Juneau to explore the suitability of installing the Chatanika hydro-
electric unit in powerhouse no. 2.
Field reports as a result of these visits follow:
SALMON CREEK NO. 2 POWER PLANT (UPPER)
Mechanical Equipment
This plant has two single nozzle, single overhung (SNSOH) horizontal
shaft Pelton turbines. They were manufactured in 1913 by the Joshua
Hendy I ron Works of San Francisco to the design of Geo. J. Henry, Jr.
of San Francisco. The original turbine rating was 2,500 H. P. at 257
RPM under 653 ft. effective head.
These turbines were partially reconstructed by the Pelton Water Wheel
Co. (Pelton Div. B L H) about 1937 ('n Pelton Sales order No. 31476.
The reconstruction consisted of new waterwheels and new needle nozzles
of the most modern type available in 1937. There has been very little
improvement in the state of the art since 1937, so it can be assumed
that the present design of the waterwheels and nozzles could only be
slightly improved as far as efficiency goes. It might be possible to
gain 1% or 2% but to secure any substantial increase such as 5% it would
be necessary to install completely new turbines.
Tests in April 1965 indicated that the turbine efficiency was a maximum
of 58%, whereas Pelton W. W. Co. had expected approximately 84% or
higher at the time of the 1937 reconstruction. Observations made by
Smith on October 12, 1977 at the site (and calculations later) support
the previous finding that the efficiency is approximately 58%.
Page 14
SECTION II -EXISTING SYSTEM
Since all indications are that the water entering the turbines has suf-
ficient pressure, velocity and volume to generate approximately 1900 kW
per turbine at 80% turbine efficiency, it becomes a question why the
units cannot produce more than approximately 1400 kW.
Smith has discussed the 1965 tests with Messrs. D. J. Guild, Hiam
Barmack, and Ben Hilyard, all engineers who participated in the 1965
tests. Mr. Guild (formerly of BLH) recalls that he was doubtful of the
housing design at that time. Mr. Hilyard clearly recalls that records
showed that the turbines had not reached anywhere near the level of
output and efficiency predicted by the Pelton W. W. Co. in 1937, after
installation of new wheels and nozzles. Mr. Franz Nagel, Manager of
AEL&P Co., recalls that when he came with the company about 1947, he
was told that the units never produced much more than the 1400 kW
that they produce today. A 1938 annual report indicates the maximum
load at Salmon Creek no. 2 was 3400 kW or 1700 kW per turbine
generator unit.
Some of the possible causes of the present low efficiency are listed
below in the order of probability:
I. The \Vater·wheel lower housing design is such that it
redirects the water discharged from the buckets against
the wheel in such a way as to act as a brake. The
housing could be checked and modeled in a hydraulic
laboratory to determine its exact effect on the turbine
performance. Major reconstruction of the substructure
is required to correct the housings.
2. The discharge passage from the wheel housing to the
tail race may be choking up due to poor design, poor
construction, obstructions which have blocked it or
excessively high tail water relative to the wheel elevation.
These points should be checked and the findings re-
Page 15
1
SECTION II -EXISTING SYSTEM
viewed by an expert. Corrections should be made if
required and possible.
3. There appears to be no air vent in the water wheel
housing and the shaft enters through a stuffing box.
Since admission of air equal to 30-50% of the water
volume is required for turbines of this type, it may be
that the supply through the discharge p~ssage is inade-
quate. Such a condition could cause the wheel housing
to remain partially filled with water during operation. A
hole or holes could be cut in the sides of the wheel
housings to test the air requirement and possibly im-
prove performance,
4. The turbine nozzles could be misaligned with the wheel
buckets or they could be obstructed in some way to
cause a badly distorted jet, or the needles and seat
rings could be badly deteriorated. These appear very
remote possibilities since the nozzles were inspected at
the time of the 1965 tests and reported to be in fair
shape. It would be almost impossible for the nozzle
conditon alone to cause a 25% foss i!·; efficiency, but
their condition could be one contributing cause to an
accumulation of other-efficiency losses. 1
5. The buckets could be in poor condition but the same
inspection was made and the same comments apply as
under 4 above. 1
6. The jet deflectors may be improperly adjusted and are
continuously diverting a substant;al portion of the jet
and/ or distorting the jet. This should be checked and
the adjustment corrected, if necessary. 1
An October 28, 1977 inspection report states that items listed in
4, 5 and 6 above are in satisfactory condition.
Page 16
SECTION II -EXISTING SYSTEM
7. The Pelton W. W. Co. could have made an error of some
kind in their wheel design or manufacture. This seems
very unlikely, but it could be checked by an expert
examination of the wheel or wheels. What is more likely
is that Pelton W. W. Co. overlooked the effect of the
original housing, lack of air venting and discharge
passage configuration, and that this was such as to
negate the expected improvement in performance from the
1937 wheels and nozzles.
It would not appear to be prudent to recommend a second wheel and
nozzle reconstruction until the cause of the failure of the first recon-
struction to improve the performance is established. Time and normal
wear and tear would degrade the initial efficiency and output achieved
in 1937, but not to the extent of 25%. Also, there is evidence available
that the expected efficiencies above 80% were not achieved initially in
1937 before wear and tear occurred.
Since it appears that these turbines have not performed up to expecta-
tions, even in 1913 1 it seems most likely that the housing is the basic
cause, and of course the most difficult to correct, since it is largely
embedded in the substructure of the powerhouse. This would imply
that either a new turbine should be installed or the site abandoned in
favor of a new location at tidewater" It is possible, but unlikely 1 that
the present units can be made to produce substantially more power.
Even if they could, the turbine shaft would constitute a possible point
of fatigue failure and should be replaced or given an ultrasonic inspec-
tion combined with a stress review before investing in any uprating of
the units.
Based on Mr. Smith's own experience, records and judgment, the exist-
ing lower water wheel housings appear to be approximately I. 5' too
narrow, 3' too short in the downstream dit'ection, and should have their
full width carried to a level about 2' higher than the existing design
Page 17
SECTION II -EXISTING SYSTEM
for optimum performance. Unfortunately, it is impossible to estimate
exactly the lost efficiency due to the inadequate housing without lab-
oratory tests.
The best guess, based on D. C. Smith's observations, experience and
judgment, as to the cause of the short fall in efficiency, and therefore
output, is as follows:
I. The original design embodies an inadequate waterwheel
lower housing which has never been altered. Pelton
W. W. Co. in 1937, to Smith's certain knowledge, had not
yet realized the effect on efficiency of even a slightly
inadequate housing 1 and consequently may have pre-
dicted an improvement in efficiency which could not be
obtained. This housing deficiency could easily reduce
the turbine efficiency 10% and perhaps as much as the
full 25%.
2. There has been a deterioration of the needle, nozzle,
and buckets which reduces the efficiency perhaps 5% to
10%.
3. There may be mis-adjustment of the deflector which
could reduce the efficiency anywhere from !% to the full
25%, but which is easily checked and corrected. It is
possible that maladjustment existed at the time of the
1965 test. The adjustment was not checked and, there-
fore, the loss incurred at that time, if any, is not
known.
4. The lack of air vents and possible i:1adequate or blocked
discharge passages to the tailrace could reduce efficiency
by a substantial but unknown amount.
Page 18
o SECTION II -EXISTING SYSTEM
Taking 84% efficiency from the P. W. W. Co. Curve Sheet PF-5910-01 of
1937 as the maximum expected efficiency of one reconstructed unit
operating alone and deducting 7. 5% for loss of efficiency due to wear
and tear between 1937 and 1965, a period of 28 years, there should have
been a test effiCiency of 76.5% in 1965. Since an efficiency of 58% was
measured for each unit alone in 1965, there is a loss of approximately
20% which is not accounted for by wear and tear. Inherent housing
design deficiency appears to be the cause of this deficiency although
choking of the discharge passage or maladjustment may account for some
of it.
It does not appear possible to substantially increase the output of the
turbines by merely replacing the wheel and nozzle. If another attempt
at such an upgrading is undertaken, it should be based either on
laboratory model tests which include the present housing design or on a
reputable turbine manufacturer•s firm guarantee. Alternatively, the
housing and discharge passages could be modified to match a new
modern wheel and nozzle, in which case an initial efficiency of approx-
imately 88% could be expected. Unfortunately, the turbine shaft may
not prove adequate, after 65 years of service, to transmit 40% more
power, and will introduce an unknown degree of risk.
Taking everything into account it would appear that (I) the present
units should be maintained at approximately their present output and
efficiency, with the addition of new governors for unattended operation
or (2) a single new high performance turbine-generator unit (the Chat-
anika unit perhaps) should be installed at this site or (3) a new high
performance turbine-generator unit should be installed at tidewater,
combining the upper and lower plant heads, and the upper plant aban-
doned.
Page 19
. SECTION II -EXISTING SYSTEM
Electrical Equipment
The generators are General Electric Type ATB 1 Serial Nos. 659950 and
659951 1 rated 1750 kVA 1 0.8 PF 1 2300 volts and 257 RPM.
If it is decided to keep the units in operation 1 maintaining the present
output, but under remote supervisory control 1 the following should be
done:
I. The two generators should have their stators and rotors
cleaned and reinsulated and a new static excitation
system added.
2. Temperature type Remote Temperature Detectors (RTD's)
and bearing thermocouples (as a minimum) could be
installed, which would provide the remote operator some
indication of unit temperature.
3. Cable ground protective relays could also be installed.
4. The switchgear (5 kV and low voltage), and the lighting
and conduit systems are obsolete and should all be
replaced.
5. A 125 volt d.c. battery system would be required for
control and protection of the units.
If the 1400 kW generators were rewound using the same size conductors
and Class F type insulation, it would be possible to realize an increased
unit capacity of approximately 25 per cent. However 1 this work would
only be feasible if the turbine and penstock were of compatible capa
bility. If the units were rewound, generator protective relays should
be installed. The existing transformer banks appear to be in satis-
factory condition. However 1 the transformers should be replaced if the
generation capacities are increased.
Page 20
, SECTION II -EXISTING SYSTEM
If the existing 5 kV generator, line, and transformer breaker equipment
is replaced, it is suggested that it would be desirable to size the new
5 kV metal-clad switchgear to match the rating of the combined upper
and lower plant unit output, so that it could be reused in a future
combined installation. The cost of the increased capacity would be
minimal. It would also be possible to relocate and reuse the low voltage
station service lighting, 125 volt d. c. battery system, and the super-
visory control equipment as well.
SALMON CREEK NO. I POWER PLANT (LOWER)
This plant was closed down in 1974 because it was no longer econom-
ically feasible to operate under conditions requiring full time operators
and one generator being badly damaged requiring major repairs. With
the reduced capacity of one unit, power could be purchased from
Snettisham for less cost. Maintenance on the flume and penstock were
discontinued and consequently have deteriorated to the point of being
inoperative without major repairs or replacement.
Mechanical Equipment
The powerhouse contains one Yuba Mfg. Co. double nozzle double
overhung ( DN DOH) horizontal shaft Pelton turbine and one Pelton
W. W. Co., single nozzle, double overhung (SNDOH) horizontal Pelton
turbine. Each turbine is fed by a separate penstock and has a bifur-
cation followed by water wheel or hand operated gate valves for shut ..
off.
The Yuba turbine has a handwheel control on the two upper needle
nozzles and simple fixed orifice lower nozzles. There is a Lombard
Governor (Type M, No. 2064) controlling deflectors on all four nozzles.
The turbine rating is said to be 2,500 H.P., 257 RPM with a head said
to be about 350 feet.
Page 21
. SECT ION II -EXISTING SYSTEM
The Pelton W. W. Co. turbine has the same rating with hand control on
both needle nozzles and with deflectors on both nozzles controlled by a
Pelton 0-3 Governor No. 919.
This plant normally was limited to an output of about 1200 kW by the
quantity of water available which was restricted by the capacity of the
flume and the turbines at the upper powerhouse. Mr. Franz Nagel does
recall that the plant once produced 3200 kW with water diverted from
side streams and released at the dam. This corresponds to 2 1 250 H.P.
per turbine and approaches their rating. The turbines appear to have
a better housing design than those at the upper plant and probably
could reach their rated capacity if reconditioned and supplied with
adequate water at the proper head. It is guessed that the turbine
efficiency would be in the neighborhood of 70%, but this is based on
speculation, and it could easily vary 5% or even more.
The turbines could have new Woodward Governors installed for un-
attended operation very easily. The turbines could probably be up-
graded to improve their efficiency to at least 80% by replacing the water
wheels and nozzles. It would be necessary to partly dismantle the
turbines and closely inspect the wheels and nozzle parts before definite
assurances could be given. The turbine shutoff valve~, would require
modification for unattended operation of the plant since they are manu-
ally operated or controlled.
Electrical Equipment
The generators are General Electric Type ATB, Serial Nos. 559331 and
695419, rated 1750 kVA, 0.8 PF, 2300 volts and 257 RPM.
If the plant is reactivated, it will be necessary to completely rehabil-
itate the generators, switchgear 1 and electrical auxiliary equipment 1
including conduit grounding and lighting systems.
Page 22
, SECTION II -EXISTING SYSTEM
The two generator stators need to be removed and rewound, new wedges
and lashing rings made, and all reinsulated. The rotor coils appear to
be in good condition; however, field coils need to be cleaned, dried
out, and reinsulated after the long period of shutdown.
The electrical switchgear 1 lighting, and conduit system should all be
replaced. The grounding system should be checked 1 and items not
grounded should be grounded.
The total extent of the electrical work should be determined after a
thorough review of the entire plant 1 and electrical work should be
compatible with mechanical and civil features.
DAM AND WATERWAYS
Salmon Creek Dam
The Bechtel Corporation reports of 1959 and 1966 and a May, 1977 Safety
Inspection by James M. Montgomery, Consulting Engineers, Inc. were
reviewed and a personal inspection of the dam was made on November 14,
1977 by Carl Steeby. The report on Safety Inspection, Project No. 2307 ·
Alaska, 1977 is included in Appendix A.
The Salmon Creek Reservoir water surface was 6.0 feet below the
spillway crest on 11-14-77. The temperature was 34°F and snowing
heavily. A thin veneer of ice covered the downstream face of the dam
with occasional release of large areas of ice making the toe inspection
hazardous. The dam inspection revealed the Safety Inspection Report
to be essentially correct with the following exceptions:
a. Ice on the downstream face of the dam. This could have
formed from freezing rain 1 sweat or from leaching.
Page 23
SECTION II -EXISTING SYSTEM
b. The spillway area was clear of debris.
Penstock -Dam to Powerhouse No. 2
The penstock, bridges and trestles were visionally inspected and appear
to be in good condition. Two leaks were observed; one near the pen-
stock station 9+30 and another near station 23+15 as shown on Figure
No. 2.
An ultrasonic thickness survey of the penstock was made in 1976 by
James Montgomery, Consulting Engineers 1 Inc. and is incorporated in
Appendix B of this report.
Flume -Powerhouse No. 2 to Forebay above Powerhouse No. I
The condition of the flume from powerhouse no. 2 to the forebay above
powerhouse no. I is not good. The vertical alignment is extremely poor
and the 2xl2 timber lining is deteriorating rapidly due to alternate
wetting and drying from inoperation. The structural supports in the
trestle areas are generally good. The timber cribbing under the sup-
ports are in various stages of decay and should be replaced with con-
crete. See figure No. 3 1 page 1!·7 for trestle details. The flume is
considered inoperable in its present condition.
Penstock -Forebay to Powerhouse No. I
There are two penstocks leading from the forebay to powerhouse no.
varying in diameter from 42 to 30 inches and each approximately 1625
feet in length. The south penstock is considered unsuitable for use
and the north penstock could be put in service with considerable repair.
Should it be desirable to rehabilitate powerhouse no. I, we recommend
the installation of a new penstock of a diameter large enough for the
installed capacity of the plant. An ultrasonic thickness survey was
made on these penstocks by James Montgomery 1 Consulting Engineers,
Inc. and is incorporated in Appendix B of this report.
Page 24
SECTION II -EXISTING SYSTEM
Fore bay
The entrance to the interior of the fore bay was locked, however 1 a
visual inspection of the exterior revealed the forebay to be in relatively
good condition. Serious consideration should be given to replacing the
flume with a low pressure conduit and the forebay with a surge tank if
powerhouse no. I is rehabilitated.
INSPECTION OF CHATANIKA POWERHOUSE EQUIPMENT
The powerhouse is about 30 miles north of Fairbanks next to a paved
highway. The single unit was installed in 1959/1960 and operated until
about 1966 1 according to Mr. Robert Hanson. Operation was only during
the warm season as the water freezes in winter. About 1966 the water
supply pipeline evidently collapsed and, since the operation was econ-
omically marginal, it was not repaired and the penstock has since been
scrapped. It would appear that this installation was based on question-
able site conditions, although the circumstances are obscure. Mr.
Robert Hanson's father is said to be part owner. His address is:
Mr. Arnold Hanson
P. 0. Box 943
APO San Francisco 96555
Telephone: c/o Martin-Zachary Co., Kwajalein
Mr. Robert Hanson resides at 508 Lignite St., Fairbanks/ /\Iaska 99701,
Telephone (home) 452-3438.
The small concrete powerhouse contains one double nozzle 1 double
overhung (DNDOH)1 horizontal shaft Pelton turbine, rated 6900 H.P. at
360 RPM under 529 ft. effective head, manufactured by the Pelton
Divison of BLH Corp. in San Francisco under Serial No. 35352-1, and
shipped in 1959. The successor company to B LH, with the records 1
drawings, and manufacturing rights is VOEST -ALPINE of Linz 1 Austria.
An attempt will be made to obtain assembly drawings of this turbine.
Page 25
SECTION II -EXISTING SYSTEM
The turbine is fed by two pipes of 30 11 diameter, entering horizontally
through the side wall of the powerhouse above the units and with two
manually operated 3011 Darling Gate Valves. The four nozzles have
needles controlled by motor operators (Pelton) and with four deflectors,
governed by a centrally located Woodward Governor Company gate shaft
governor type LR-10500, No. 518605, size 8-~ x 12. The nozzles have
stainless seat rings with an orifice diameter of approximately 7'17.11 and
stainless steel needles of the modern 60° type. The wheels have 51zu
No. 10 Pelton Buckets, which are of high efficiency. The buckets are
19\t11 wide inside and have been weld repaired to a minor degree on the
entrance lip surface with stainless steel. The buckets and needle show
slight erosion. The seat ring and deflector edges are smooth and in
good shape. The inspection of buckets and nozzles was confined to the
lower nozzle and bottom buckets of the left hand wheel {looking down-
stream) 1 which is the only one accessible in a short period of inspection
and without dismantling the turbine. It is reasonable to assume that
the condition of these parts is representative of all the buckets and
nozzles.
The external appearance of the shaft, bearings, housing and linkage is
very good. The shaft is greased, all parts are painted and the local
climate is very dry.
It is Smith's opmton that this turbine would probably, (but not cer-
tainly) be capable of being dismantled and reinstalled without any major
problems or reconstruction. There is a possibility that a major com-
ponent such as the waterwheel, the shaft or the generator rotor is
flawed, but this is highly unlikely. It would require sophisticated
non-destructive testing (NDT) techniques to determine that no such
flaws exist.
The governor can be easily converted for unattended operation by
Woodward Governor Company.
Page 26
SECTION II -EXISTING SYSTEM
The generator was made by Elliot Co. of Ridgeway 1 Pa. and carries the
following nameplate data; which seems to contain an error since
6 1 250 kVA x .8PF = 5,000 kW, not 5,625 kW.
6250 kVA
4160 Volts
868 Amps
3 Phase
60° c Rise Status by
60° c Rise Rotor by
145 Exc. Amps
Serial No. IS-10949
5625 kW
360 RPM
.8 P.F.
60 Cycles
Detector
Resistance
250 Exc Volts
The generator, switchgear and transformers appear to be in good
condition 1 but no close inspection was made.
The turbine has a relatively high specific speed for a Pelton type and
the efficiency would probably be 87% at peak with efficiencies exceeding
85% from about 40% rated capacity to 100% capacity. The turbine will
require a flow of approximately 135 cfs to develop 6900 H. P. (5, 000
Generator kW) under an effective head of 529 feet.
Records which are in Smith's possession indicate that the shaft design
was very conservative and that the turbine could be operated at as
high an output as 8,500 H. P. without exceeding the Pelton Div. design
stress limits.
Operation at 8,500 H. P. would require an effective head of 607 ft. and
a flow of 148 cfs. Such an uprating would be the maximum which could
be recommended and would involve some risk of shaft fatigue failure
unless ultra-sonic shaft inspection was made to give assurance of its
freedom from flaws. The risk should be considered minimal but cannot
be ignored. There will also be a small drop in efficiency at the higher
head because the unit will no longer be operating at design or optimum
Page 27
SECTION II -EXISTING SYSTEM
relative speed (phi) of the wheel peripheral velocity to the jet velocity.
This efficiency drop should be in the order of 2%, for the change in
head, plus the usual change in efficiency due to change in load.
The two turbine wheels are integral castings, including wheel disc and
buckets, apparently of mild steel, and presumably were given the
normal high standard of inspection and workmanship for which Pelton
Div. had a very high reputation. Normally, these wheels are expected
to have a life of approximately 10-20 years of operation with clean
water, of which perhaps five years has been expended, allowing for
start-up in 1960, shut-down in 1966 and operation only in the warmer
months of spring, summer and fall.
Additional information received subsequent to the field inspection
includes an up rating design report on the Chatani ka turbine by the
Pelton Division of Baldwin-Lima-Hamilton and the Chatanika turbine
assembly drawing from VOEST-Aipine; successors to B-L-H. With this
additional information, it was possible to identify several modifications
which will be necessary to safely relocate this turbine as follows:
1. The runaway speed at 725 ft. static head may reach 760 RPM,
which exceeds the generator :Jesign maximum ~-afe runavvay sreed
of 720 RPM. This is considered unsafe design practice, and the
generator rotor should be modified or replaced.
2. The inlet valves are 30 11 size, of cast iron, manually operated.
The valves were originally given a hydrostatic shell test of 400 psi
(924 ft.) and seat test of 350 psi (808 ft.). These test pressures
are considered too low for safe design practice and should be at
least 150% of the 725ft. max. static head or 1088 ft. (471 psi). It
is very doubtful that the de~>ign is adequate for this higher pres-
sure and since remote operation would have to be added in any
case, one large ( 42 11 or 36 11 ) or two smaller (30 11 ) valves with
proper rating should be purchased to replace these valves. Care
Page 28
SECTION II -EXISTING SYSTEM
must be taken to check the adequacy and match the downstream
companion flanges if the smaller valves (3011 ) are chosen.
3. The turbine has two inlet wye pipes (bifurcations) and these are
inadequately designed for the new higher head. They will require
reinforcement at the crotch section. They were originally tested
at 355 psi (820 ft.) and were designed for 547 ft. head. After
reinforcement, they should be tested at 741 psi. This will repre-
sent an increase of 33% over the design and there is a possibility
of leaks or even failure at test.
4. The four needle nozzles are of cast steel construction, heavier
than was originally necessary due to either an existing pattern or
design being adopted. They should be able to stand the higher
test pressure except that the nozzle seat ring bolts are inadequate
and the nozzle tips must be drilled and tapped for additional bolts.
The seat rings must be drilled correspondingly.
5. The governor capacity is stated to be 11 marginal but should be
adequate.11 The possibility that it will be inadequate is remote but
does increase the risk of runaway speed, mentioned in No. 1
above.
The turbine rotating parts and bearings present no problems if the
generator is limited to 6,000 kW, corresponding to the original overload
design rating of the turbine and generator. Of course all the usual
risks of operating used machines at higher outputs than previously
obtained do apply. Ultrasonic inspection of the shaft is recommended
as well as regular periodic wheel inspections.
Page 29
SECTION II -EXISTING SYSTEM
An estimate of the comparative costs of a new horizontal Francis turbine 1
and the Chatanika turbine follow:
1
2
1. New Turbine/Generator (5000 kW)
New Francis turbine and generator
Installation
Foundation
2. Chatanika Turbine
Purchase turbine
Dismantle and ship
Reinstall
Foundations
Modify turbine and test
Contingencies
Rebuild and install generator2
New inlet valve
$750,000
35,000
65,000
$850,000
$400,000
70,000
50,000
100,000
25,000
60,000
200,000
50,000
$955,000
Such a unit would have a peak efficiency about 3-5% higher and
would be designed and guaranteed for this application.
Assuming rebuilding to handle increased runaway speed is feasible.
Page 30
SECTION Ill
PROJECTED POPULATION & POWER REQUIREMENTS
3.1 Employment In Juneau, 1975-2000
The basis for the electrical load growth forecasts developed for this
report are forecasts of employment for the State of Alaska as a whole,
the Southeast region and the City and Borough of Juneau. These
forecasts are summarized in Table 3-1.
Base year totals fat~ aggregative statewide and regional employment, and
for state and federal government employment have been compiled from
Alaska Department of Labor data. Data for 1975 are used because more
consistent supplementary data series are available for that year, and
because 1975, versus 1976, reflects lesser transient impacts of Alyeska
Pipeline construction. Employment forecasts from 1975 through 1990 are
based on forecasts prepared by the University of Alaska 1 Institute for
Social and Economic Research, 11 Man in the Arctic Progt~am 11 (MAP)
econometric model. Forecasts from 1990 through 2000 are linear extra-
polations of trends established by MAP. These extrapolations, by their
nature, assume successively declining annual growth rates. These base
data assume that Juneau will remain the capital of Alaska.
For purposes of this study, state and federal employment in Alaska and
the Southeast region are assumed to remain ln their 1975 ratios to the
total statewide and regional labor forces.
Juneau's total employment, and state and federal government employment,
are projected from the 1975 base year. Ur:der the assumption that the
capital will remain in Juneau, the city's state and federal employment is
projected to increase irl direct proportion to forecast growth of total
statewide employment, with its corollary increase in the state and federal
Page 31
SECTION Ill -PROJECTED POPULATION
& POWER REQUIREMENTS
work force. For this forecast, it is assumed that Juneau's percentage
share of state and federal employment in Alaska will remain at its 1975
level. This forecast, assuming no capital move, is similar in result to
one prepared for the City and Borough of Juneau by Homan Associates
in 1972~
Under the assumption that the capital will be removed from Juneau,
state and federal employment in Juneau are nevertheless projected to
increase by about 20% through 1980. Beyond 1980, such employment in
Juneau is held constant at its 1980 level. As a result, this projection
indicates that from 1980 through 1985 a total of 1000 state and federal
jobs, which, with the capital, would have been located in Juneau, will
instead be located elsewher·e. By 1990, 1200 such jobs will be displaced
from Juneau, with the figure increasing to 4000 jobs by 2000. State
and federal employment in Juneau in 1975 comprised 12.9% of total state
and federal employment in Alaska. The 11 no-growth 11 assumption for
Juneau 1 s government labor force beyond 1980 results in 7. 2% of such
jobs being located in Juneau in 2000.
Because Juneau 1 s state and federal labor force is the key variable in
determining total employment in the community, the assumption that this
labor force will not decline with the removal of the capital is of critical
importance to the succeeding projections of population and electrical
load. According to a recent study of state and federal employment in
Juneau, prepared for the City and Borough of Juneau by Homan-
McDowell Associates, 75% of all state and government jobs in Juneau in
1975 were based on 11 central 11 or statewide functions, the remaining 25%
had regional or local functions. It is reasonable to assume that these
jobs would be optimally located in the new capital city rather than Juneau r
assuming the capital were moved. However, the ability to relocate
these positions depends on the development of new facilities to ilccorn-
modate them, plus infrastructure to support related population, at the
new capital site. Development of the new capital site has not begun in
early 1978, and major funding for such development cannot be author-
Page 32
SECTION Ill -PROJECTED POPULATION
& POWER REQUIREMENTS
ized prior to the 1978 legislative session, with subsequent approval of
bond issues as required in the fall of 1978. The capital move initiative
requires relocation of key government functions to the new capital site
by the end of 1980, however. It is considered virtually impossible that
development of the capital site, facilities and infrastructure can advance
sufficiently to accommodate more than a skeleton force of state govern-
ment personnel in the two years of development time available through
1980. On the other hand growth of state and federal employment is
projected to continue through 1980 1 with the addition of approximately
6200 positions over the 1975 level. Over 900 of these positions had
been added to the Juneau labor force through the end of 1976i this
study projects the addition of another 800 through 1980. Therefore,
although key legislative 1 executive and judicial functions may vacate
Juneau by the end of 1980, it is expected that facilities will be unavail-
able to accommodate a sufficient number by that time to significantly
affect normal growth of Juneau•s labor force.
The long term assumption made for this study, that state and federal
employment in Juneau will not decline after 1980 is defensible partly on
the same grounds as the short term projection. The initial forecast of
new capital site development, prepared in 1974 1 , projected that the site
would accommodate a state and federal labor force of 'lpproximate!y 3000
by 1985, following at least seven years of development. This projection
is considered reasonable, although long term projections by the same
group are unduly low. However 1 through 1985, state and federal
employment in Alaska, at a constant ratio of total employment, is
expected to increase by 8200 positions over its 1980 !eve! and 14400
positions over 1975. Therefore, additional facilities must be developed
to accommodate 11400 new positions in permanent or interim state and
1 Boeing Computer Services, Naramore Bain, Brady and Johanson "Alaska
Capital Site Relocation Study", 1974.
Page 33
SECTION Ill -PROJECTED POPULATION
& POWER REQUIREMENTS
federal facilities in additon to the labor force housed at the new capital
site, assuming Juneau's facilities are fully utilized. The fiscal require-
ments for providing new facilities will be very substantial; therefore, it
is probable that the vacating of existing facilities at Juneau in favor of
interim facilities at a point nearer the new capital, say Anchorage, will
be regarded as an undue expense, and a possible retardant to develop-
ment of the new capital site itself. From 1985 through 2000 this same
factor is expected to be present and to deter a net relocation of state
and federal employment from Juneau.
From 1975 through 2000, substantial growth is expected in the popu-
lation of Southeast Alaska, resulting in the expectation that increasing
numbers of the Juneau government work force will be identified with
regional functions. Based on the 1975 total of about 1100 Juneau positions
which had local or regional functions in 1975, total involvement of
Juneau personnel in such functions could be expected to total 2300 in
2000, assuming the capital were moved and that no greater central-
ization of Southeast governmental functions were to take place in Juneau.
Centralization could add substantial numbers of personnel from the
11,100 person state and federal labor force projected for southeast
Alaska in 2000. If Juneau's state and federal employment were identified
primarily with regional functions in 2000, Juneau's goven1rnent employ··
ment, at the 5,100 level constant since 1980, would make up 46% of the
government work force in southeast Alaska. This is consistent with the
precedent of Anchorage's present role as a regional government center;
in 1975, 38% of all state employment excluding that in southeast Alaska,
was located in Anchorage. The expectation of similar< regional central~
ization is not unreasonable for Juneau.
In addition to the demand for Juneau's government facilities to accom-
modate state and federal employment in general, and expected orowth
and centralization of southeast regional government in Juneau, the
political influence of the southeast region's legislative delegation is
expected to be a significant force in maintaining a constant !<:wei of
Page 34
SECTION Ill -PROJECTED POPULATION
& POWER REQUIREMENTS
state employment in Juneau beyond 1980. This influence is expected to
be particularly strong in the legislative bargaining for appropriations
and bond authorizations to develop the new capital site. It is con-
sidered virtually certain that southeast legislators' votes will be required
for this purpose and that part of their price will be maintenance of
Juneau as a viable segment of the regional economy.
Beyond the government sector in Juneau 1 s economy, a growth rate
averaging 2. 5% annually is forecast for non-government employment in
Juneau from 1985 through 2000. This is consistent with the forecast
increase in total southeast region employment for the period 1975-2000.
However, no net growth is forecast in Juneau's private sector from 1980
through 1985 due to the expected adverse impact of the capital move on
business expectations. It is expected that the timber industry, in the
form of logging in largely unharvested northern portions of Tongass
National Forest and on A. N.C. S. A. -selected timberlands, will be a
modest stimulus to Juneau 1s resident labor force and commerce in the
1980 1 s and 1990's. It is also expected that timber milling and other
small to mid-scale industrial and commercial ventures by Sealaska Corp-
oration will at least partly center on Juneau during the same period.
Although Juneau is no longer one of Alaska's major fishing ports, it is
expected that her fishing industry will benefit from r·ecovery of coastal
fish stocks, which should follow controlled harvesting of the 200 mile
coastal fishing zone. Continued growth of tourism is also expected to
be a noticeable factor in Juneau's economy in the 1980's and 1990's. It
is expected that these elements will be sufficient to maintain the pro-
jected stow rate of growth in Juneau's relatively small private sector
through 2000. Certainly there are major developments which could
contribute to substantial redevelopment of Juneau's economy after a
capital move. Of these 1 the most probable is a surface connection to
the Haines and/or Skagway Highway termini with a short ferry link
across Lynn Canal. Although much more speculative, it is not incon-
ceivable that consolidation of major tracts of ANCSA-selected timber
could form the 4-6 billion board foot raw materials base for development
Page 35
SECTION II I -PROJECTED POPULATION
& POWER REQUIREMENTS
of the southeast region's third pulp mill at a site near Juneau. Develop-
ment of the Klukwan iron deposits, for which incentive will increase in
the 1980's with depletion of Japan's alternative iron ore sources, could
also strengthen Juneau's economy via its role as the transportation,
trading and administrative center of northern southeast Alaska. Finally,
a major hydroelectric-industrial scheme in the Yukon, on the Pelly or
upper Yukon Rivers --in which there is continuing Canadian and
American interest --could similarly reinforce Juneau's secondary economy.
Therefore, the employment forecast used for the forecasts in this report
is considered a conservative base line for future development.
3.2 Juneau's Population, 1975-2000
Population forecasts for the City and Borough of Juneau through 2000
are summarized in Table 3-2.
Because of the dominance of state and federal employment in Juneau's
economy, the major criterion for ~population forecasting in this study has
been the projection of such employment. This is consistent with the
overall characteristics of population growth forecasting in Alaska. The
state's population as a whole, except for isolated native centers, is
centered on major labor markets. Alaska's small mobile population,
immature economy, and its relatively unattractive subsistence lifestyles
render other population growth factors, such as natural increase,
almost insignificant.
For the purpose of estimating Juneau's population based on employment
projections, a labor force participation rate of 50% was used through
2000. This corresponds to the present rate in Juneau, and is higher
than the average 46% rate for Alaska's other· major population centers
due to the very high participation of women in government labor force.
The use of this rate through 2000 may somewhat understate population
relative to projected employment after 1985 1 as state and federal employ-
Page 36
SECTION Ill -PROJECTED POPULATION
& POWER REQUIREMENTS
ment diminishes as a percentage of total labor force. However, such
employment is still projected at 38% of Juneau's total in 2000 versus 47%
in 1975, about 180% of the average rate for the state as a whole.
Therefore, the resulting forecasting error in population should be quite
small. The resulting population forecasts show increases of 12.5%
through 1985, and 39.5% through 2000.
3.3 Power and Energy Forecasts, 1975-2000
Power and energy forecasts for the AELP system through 2000 are
summarized in Table 3-3. These forecasts are based on population
projections in the preceding section of this reporL Recent system
history has been provided by AELP and for earlier years beginning in
1960 has been extracted from AELP's annual reports to the Federal
Power Commission. 1 The forecasting methodology uses residential
electricity sales as a base line, with residential hookup saturation set at
27% for reported total area population, which is consistent with AELP's
recent experience (see Table 3-5), and also with forecasting guidelines
for southeast Alaska set out in the University of Alaska's 1976 report
11 Electric Power in Alaska 11 • 2 ~ Total area population is used instead of
the population of the AELP service <-lre<l,. reflecting the assumption that
the GHEA service area will remain a relatively small percentage of total
population and electrical load. Annual electricity consumption per
residential customer is also based on trends in consumption in southeast
Alaska established by the University of Alaska study cited above.
Guideline data from that study are adjusted to reflect the somewhat
lower historical consumption of AELP's residential customers, this charac-
teristic is believed to result from a relatively high pe1~centage of multi-
1
2
Federal Power Commission, For 12A "Power System Statement,
1960-1974.
University of Alaska, Institute for Social and Economic Research,
Anchorage, "Electric Power in Alaska", 1975, prepared for the
Alaska State Legislature.
Page 37
SECTION Ill -PROJECTED POPULATION
& POWER REQUIREMENTS
family residential buildings in AELP's service area, and the high labor
force participation of residents which restricts household electricity
used during much of the day. However, consistent with the guideline
trend, which has a broad base of comparative system experience, per-
customer consumption is expected to increase about 49% through 2000.
Commercial sales are forecast as two-thirds of residential sales, corres-
ponding to AELP's historical ratio. This is a somewhat more rapid
increase than would be obtained from forecasting this load as a function
of private sector employment for the period of record; however, it is
believed it better reflects the probability of increasing energy use per
job which is common in private firms as new appliances improve prod-
uctivity.
Industrial load is forecast as constant at its 1975 level. This forecast
is probably unduly conservative, but because the data reflects one
customer in one industry and because it is relatively small, it was not
considered worthwhile to speculate on future changes.
Government load is forecast as directly proportional to employment.
This is more conservative than the forecast used for the commercial
sector, and reflects the assumpticms both that energy conservation will
be more strictly practiced in government than in business, and that
government will be less sensitive to potential energy-related increases
in productivity. Therefore, under the capital move assumption, govern-
ment sales are constant from 1980 through 2000.
Street lighting is forecast as a constant rate per unit population.
These forecasts indicate a rapid increase in electricity sales through
2000, under the assumption that the capital remains in Juneau, resulting
in an overall 270% increase in sales over 1976 by the year 2000. A
much more modest rate of increase is projected under the assumption
that the capital is moved, reaching 170% of the 1976 level in 2000.
Page 38
SECTION Ill -PROJECTED POPULATION
& POWER REQUIREMENTS
Net energy for system and peak demand are projected based on sales,
as summarized in Table 3-4. Net energy for system is based on a
continuing ratio of 6.8% system losses and non-revenue uses through
2000, representing average AELP losses since 1960. Peak demand is
based on net energy for system, which is assumed equal to net energy
for load during the forecast period, using a system load factor of 53%
which again corresponds to recent AELP experience and is consistent
with system load factors for other utilities which serve only minor
industrial loads.
Page 39
v
Q)
(Q
CD
.j::>.
0
-------···--·-~-·---· ----
TABLE 3-1
EMPLOYMENT IN ALASKA, THE SOUTHEAST REGION AND JUNEAU
1975 -2000
SOUTHEAST JU!';f'4U
Statewide With Capital Without Ca~itill With CapH_~
~ ~ Government Total Government ~ Govnrnment Total Government
1975 1 157,350 33,025 22,337 6,615 22,337 6,615 9,148 4,266
-,geo '18G,700 2 39,200 29,500 2 8,700 29,500 8,700 10,800 5,100
1385 225,600 47,400 35,200 10' 400 33,700 9,400 13' 100 6,100
1990 255,800 55,800 39,100 11,600 35,900 ~. :-.·,c 15,500 7,200
1 ()95 299,900 62,900 45,500 13,500 41,000 10,500 17,400 8,100
2000 336,400 70,700 51 '100 15,100 45,100 11,100 19,GC~ 9,100
Source: Ala~kil Department or Labor·, Juneau.
Sour~e: university of Alaska, Institute for Social and Economic Re~..::.t•ch, An<:horaoc.
V/i il:!§ll!_£.~.~
Total Government
9,148 4,266
10,800 5,100
10,800 5,100
11,500 5,100
12,400 s, 100
13,400 5,100
(/I
m
()
~
0 z
!(c-o
:::0 ,o
0'-:Em mo
:::0~
':::o g;
m .o, co -,
:::Oc mr
3\::p
m~ z_
~0 (flz
1 Source:
2 Source:
3 Source:
SECTION Ill -PROJECTED POPULATION
& POWER REQUIREMENTS
TABLE 3-2
JUNEAU AREA POPULATION
1960-2000
Juneau Area
Year , Population 1
--Record--
1960 9,745
1961 10,462
1962 10,298
1963 10,598
1964 11,908
1965 12,415
1966 13,227
1967 13,710
1968 13,200
1969 13,300
1970 13,556
1971 14,564
1972 15,079
1973 16,593
1974 17,195
1975 '18,310
1976 19,193
--FORECAST--
No Capital Capital
Move 2 Move 3
1980 21,600 21,600
1985 26,200 21,600
1990 31,000 23,000
1995 34,800 24,800
2000 39,200 26,800
Alaska Department of Laoor, City and Borough of Juneau.
1980-1995 City and Borough of .Juneau
2000 by Kent Miller.
1980 City and Borough of Juneau
1985-2000 by Kent Miller.
Page 41
TABLE 3-3 SECTION III
ALASKA ELECTRIC LIGHT & POWER co.
SALES OF ELECTRICITY 1
1960-2000
RESIDENTIAL
Annual Sales
Year Customers Total Per Customer Commercial Industrial Government
(No.} (Megawatt Hours -MWh -except as noted}
1960 2,619 2 13,116 2 4,637 6,390 4,982
1961 2,966 14,179 4,764 9,129 5,449
1962 3,079 1.S,639 5,144 10,089 5,132
1963 3,233 16,599 5,134 10,983 5,800
1964 3,330 171193 5,163 12,507 6,803
1965 3,442 18,107 5,261 13,287 6,329
1966 3,523 19,000 5,393 14,005 7,889
1967 3,584 19,263 5,375 13,680 9,511
1968 3,588 20,047 5,587 14,181 11,301
1969 3,725 21,363 5,735 13,341 1,107 12,577
1970 3,843 23,034 5,994 14,502 1,211 13,542
1971 4,214 24,563 5,629 16,133 11189 13,927
1972 4,442 26,009 6,305 17,498 1,013 15,327
1973 4,678 30,296 6,477 22,039 1,143 16,398
1974 4,743 31,875 6,720 20,224 1,143 17,545
1975 5,065 4 33,864 6,666 24,532 1,145 22,006
1976 5,330 36,166 6,785 25,476 1,081 25,754
Forecast 1976-2000, assuming capital is not moved 7
1980 5,800 s 42,900 7,400 6 28,600 1,100 29,800
1985 7,100 57,500 6,100 36,300 1,100 35,200
1990 8,400 73,100 6,700 48,700 1,100 42,?00
1995 9,~00 8S,40G 9,400 53,980 1,100 50,6('0
2000 10,600 107,100 10,100 711400 1,100 61,3QO
Forecast 1976·2000, assuming capital is moved 1
1980 5,800 42,900 7,400 26,600 1 '100 29,800
1985 5,800 47,000 8,100 31,300 1,100 29,800
1990 6,200 53,900 6,700 35,900 1,100 29,600
1985 6,700 63,000 9,400 42,000 1,100 29,800
2000 7,200 72,700 10,100 48,5CO '1, 100 29,800
1 Source: 1960-1974 Federal Power Commission, Form 12A, 197':>·1976 AELP Annual Budget Dcta.
2 1960·61 residential customers and sales include rural.
3 Prior to 1965 street lighting is included wltr1 government.
4 1975-76 hookup saturation is computed In ,;ppendix A.
-PROJECTED POPULATION
& POWER REQUIREMENTS
Street Total
Lighting ~
26,490
28,757
31,060
33,382
36,503
889 36,612
899 41,793
899 43,353
817 46,346
836 49,224
782 53,071
741 56,553
734 62,581
715 69,451 -
695 71,482
787 82,336
705 88,902
800 103,1::00
1,000 133,100
1,200 166,300
'i,~OO 1S5,soo
1,500 241::,400
800 103,200
600 110,000
900 121,600
900 136,800
1,000 153,100
5 Residential customers based on population forecast included in this report, and hookup sacur<>tion rates projected ln Universitv of Al~ska,
Alaska Power Study, 1976.
6 Projected sales per customer based on Alaska Power Study-
7 These projections are considered extremely conservative as AELP sales in 1977 were 96,658 MWh and the utility is forecasting a total sales
in 1976 of 106,000 MWh.
Page 42
SECTION Ill -PROJECTED POPULATION
& POWER REQUIREMENTS
TABLE 3-4
ALASKA ELECTRIC LIGHT & POWER CO
SALES OF ELECTRICITY, GENERATION AND PEAK DEMAND
1960-2000
Year
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
Total
Sales
MWh
26,490
28,757
31,060
33,382
36,503
38,612
41,793
43,353
46,346
49,224
53,071
56,553
62,581
69,451
71,482
82,336
88,902
Net Energy
for System
MWh
27,541
30,374
32,792
34,487
38,674
40,638
45,011
46,320
49,293
52,126
55,836
59,787
66,496
70,295
80,043
88,300 1
95,400 1
Peak
Losses g
0
3.5
5.3
5.3
3.2
5.6
5.6
7.1
6.4
5.9
5.6
5.0
5.4
5.9
1.2
10.7
6.8 2
6.8
Forecast 1976-2000, assuming capital is not moved
1980
1985
1990
1995
2000
103,200
133,100
166,300
195,300
242,500
110,700
142,800
178,400
209,500
260,000
6.8
6.8
6.8
6.8
6.8
Forecast 1976-2000 1 assuming capita! is moved
1980
1985
1990
1995
2000
103,200
110,000
121,600
136,800
153,100
110,700
118,000
130,500
146,800
164,300
1 Estimated, data source incomplete.
6.8
6.8
6.8
6.8
6.8
2 Based on 1960-1976 trend in system losses.
3 Based on 1960-1976 trend in system load factor.
System Load
Demand Factor
MW %
5,837
7,750
7,056
91044
9,424
10,023
11,370
10,510
11 145
11,820
13,010
14,420
15,400
16,220
16,870
19,000 1
19,400 1
23,800
30;800
38r400
45,100
561000
23,800
25;400
28,100
31,600
35,400
52.9
51.1
53.2
53.3
57.1
53.1
56.1
53.0 3
53.0
53.0
53.0
53.0
53.0
53.0
53.0
53.0
53.0
Page 43
SECTION Ill -PROJECTED POPULATION
& POWER REQUIREMENTS
TABLE 3-5
AEL&P SERVICE AREA
RESIDENTIAL HOOKUP SATURATION
1975-1976
1975 1976
Total Population 18,310 19,193
(Less) Auke Bay (1,292) (1,318)
Lynn Canal (466) (479)
Total AELP Area: 16,552 17,396
AELP Customers 4,743 5,065
Saturation
(Service Area) 28.7% 29.6%
(Total Population) 25.9% 26.4%
Page 44
SECTION IV
HYDROLOGY
The basic hydrologic data and methodology used in the 1966 Bechtel
Report was used to update the natural inflow into the Salmon Creek
Reservoir. Since only 23 months of natural flow records were available
at the Salmon Creek damsite prior to the construction of the dam, a
synthetic flow was developed for the period between 1946 and 1964.
Because Sheep Creek has a drainage basin similar in size and physical
characteristics to Salmon Creek, and because it has the longest period
of recorded unregulated flows in the vicinity, it was chosen to provide
a basis for synthesizing Salmon Creek flow.
To determine the conversion factors to be applied to Sheep Creek flows
to obtain Upper Salmon Creek flows, a nondimensional plot in cfs/sq. mi.
was made by Bechtel allowing a comparison of Sheep Creek against all
other data available which might assist in their determination. For the
final determination of the conversion factors to determine the Salmon
Creek flows, the ratio of drainage areas was used for flows iess than
700 cfs at Sheep Creek and a somewhat greater conversion was used for
greater flows.
The methodology used by Bechtel was reviewed and adopted to extend
the synthetic flow record of Salmon Creek through the 1972-1973 water
year. The Sheep Creek gage was removed in 1973 and no attempt was
made to extend the synthetic record beyond 1973 by correlation with
another gaged stream. The adopted flows for Salmon Creek are shown
on Table 4-1.
A mass hydrograph was drawn fr-om the lnformaticn an Table 4-1 and
the regulated flow was determined to be 54.2 cfs during the 28 year
study period. The mean annual flow for the period is 66.1 cfs.
Page 45
-··---··-··--·--· -··
SYNTHETIC INFLOW* ·SALMON CREEK RESERVOIR
ACRE·FECT
W~ter
~ .Q£1 ~ Dec Jan Feb !1!!.::. ~ t:.'!!!1. ~ ~ ~ §!2.! I.2!!!!
1947 5,500 6,100 650 620 280 3,080 3,280 7,630 7,500 4,900 4,250 12,900 56,690 78.3
19,8 6,300 6,240 1, 770 1,300 650 200 0 7,830 G,990 8,250 3,720 9,20~ 52,450 72.4
1949 5,9SC 8,000 750 630 240 7~0 1,700 7,300 12,100 8,300 700 4,900 51,310 70.9
1950 7.150 7,100 1,080 230 10 0 140 3,830 5,530 5,580 3,680 5,050 39,380 54.4
1951 2, 770 430 440 30 so 120 10' 700 5,350 3,050 2,G20 34,540 47.7
1 952 2,320 950 230 110 140 900 9,800 8,000 4,700 9,000 44,280 61.2
1953 8,050 1,480 580 450 120 1,500 7,400 5,550 5, 10il 5,650 48,610 67.
1!)54 ::,:.90 1, 720 820 1,240 340 z.;o 6,250 4,810 2,170 3,090 34,350 47.4
19S5 4,000 4, 3,500 990 540 360 3GO 7,600 6,470 8,500 4,810 44,210 til. 1
1956 3,550 1 t 84~ 350 70 10 0 270 8,3130 5,500 4,650 7,850 3,890 35,360 50.2
1%7 4,100 5,100 3,850 1,450 330 70 660 5,100 7,690 5,000 2,430 4,400 40,100 55.5
195& 2,9~0 4,220 1,120 1 '700 420 280 1,480 5,900 5,390 3,900 4,280 3,080 34,810 48.. 1
1%!) 7,250 2,G?O 1, 7[;0 790 420 510 1,070 5,280 8,800 9,100 6,840 3,780 49,2~0 ee.o
1;)G0 4,290 3,000 1,930 ')20 550 soo 1,670 5,750 7,401J 91G::,o 9,100 9,000 53,71;.0 74 '3
''361 'J 1 G50 5,140 3,000 1,490 1 ,0~0 S,GOO 2,270 7,700 8,500 1,3U5 12,C30 5,120 64,425 80' 0 '::c2 ::J,480 2, 720 sao -:In so 1,1-<0 590 1,570 4,910 11, soo 5,590 5,800 11,050 58,090 80.2
i9G3 5,750 4,120 4,000 2,500 3,320 2,020 1,310 5,G30 e,.:so 8,380 3,800 4,~80 54,260 74. ~ 1se4 7,B20 2,250 3,280 1,920 1,750 790 2,250 7,400 181 :·10 13,770 S, 100 3,100 67,570 93.3
3,9CO 4,000 2,1350 4,120 930 1,470 1,990 3,~00 91590 7,470 3,810 3,960 4~,~90 G9.0
1::lCG 7,C80 1,e4o , ,280 GOO 420 e5o 2,340 9,700 7,000 5,650 50,9~0 70.4 (f)
1957 5,700 2,310 leO 800 St.O 500 520 9,020 G,620 5,930 44,630 ~1.6 m
)%3 1, 7!)0 5, 31C· 2,230 7,050 •100 2,820 1,820 5,510 4,130 7,380 45,0t.O 62.2 n
1%9 S,310 2,200 1,390 600 330 1,410 7,5GO 9,0GO <;, 150 45,720 63.2 -I
1970 3 .. 790 5,6><0 3,630 1,060 ,970 1,660 1,500 9,120 8,980 7,730 5G,430 77.9 -0
1971 9.060 2,720 940 1.350 960 820 830 4,6CO 9,070 8,630 5,840 5,490 50,320 69. s z
1972 4,850 2,830 730 420 280 soo 530 5,330 8,930 8,420 7,110 €.440 4G,370 6~.0
1973 5,050 2,020 1,000 670 550 520 1,330 4,590 5,590 5,540 6,880 <ago 38,860 53.7 < Avg.
AC/Ft: 5,913 3,753 1,754 1,082 778 954 1,227 5,396 8,494 6,835 5,370 5,825 47,8.:S2
Avg.
cfs: 96.1 S3.1 2G.5 17.6 14.0 15.5 20.6 95.9 142.8 111.2 87.3 97.9 B6.1 :c -<
A Correlation wlth Sheep Creek~ 0 ., Sh.:~p c,-~cl.. o~oc removtd In Octo!>c:-1973. TABLE NO. <1-1 ;::o
0.1 0 c.o r f!) 0
~ G)
Q) -<
SECTION IV -HYDROLOGY
A mass hydrograph is a cumulative plotting of net reservoir inflow for
the period of years of record. The slope of the curve at any time is a
measure of the inflow rate at that time. If the curve is horizontal, the
inflow is zero. The slope of a line connecting any two points on the
curve is a measure of the average flow during that period.
Demand curves representing a uniform rate of demand are straight lines
having a slope equal to the demand rate. Demand lines drawn tangent
to the high points of the mass curve represent rates of withdrawal from
the reservoir. Assuming the reservoir to be full wherever a demand
line intersects the mass curve, the maximum departure between the
demand line and the mass curve represents the reservoir capacity to
satisfy demand. If the demand is not uniform, the demand line becomes
a curve but the analysis is not changed.
Knowing the Salmon Creek reservoir capacity, the mass hydrograph may
be used to determine the yield which may be expected. in this case
tangents are drawn to the high points of the mass curve (11-1-53 to
1-1-59) in such a manner that the maximum departure from the mass
curve does not exceed the reservoit~ capacity of 18,000 acre-feet. The
slope of the resulting line indicates a yield of 54.2 cfs can be attained.
The slope of the line from the beginning (12-1-46) to the r'nd of record
period (10-1-73) indicates a uniform rate of demand or average inflow of
66.1 cfs and a reservoir capacity of 70,535 acre-feet 'Vou!d be required
to satisfy this demand.
Firm power, or primary power, is theoretically the power which a
hydroelectric plant may be depended upon to produce at all times.
Firm power is not necessarily produced continuously. However·, the
total amount of primary power in kilowatt-hours which can be produced
by the hydro plant is limited to the minimum flow as regulated by
available storage. Secondary power is all of the available power in
excess of the firm pov,/er.
Page 47
405t)(JtJ
J 6 5t)(JO
......
llt
~
la....
3 ~51)()()
7..850M
~ .-f/5C(Jti
, ~0 5 000
lU
~
<..J
~
/6 !JOO()
1~.501)()
85000
4 sooo
5000
MASS HYPROGRAPH
SAirMON CREEK RESERVOIR.
SHE 1!1 I tJF' 3
r:> J F MA 1t1 J JAsON r:>IJ F MA M J JAsoN ojv f M A MJ JAsoN DIJ F MA M J J As oND JF M AM JJA soN oiJ F MAMJ JAsoN olu F' MAM J J As DN DIJ F /'II A MJ JA s ori DIJ F MA M J JA.s I l'f-17 /'r-18 1'1-1'1 1950 I 1'151 J'15X. 1'153 /Cf54 1'155
1-
LJ
Lu u_
8osooo
76SOO()
71-.SODO
685000
6"15"000
'605000
kJ
~ u
oq::
S6SOOO
51..$000
.f/8 50(}()
~J/sooa
"13AJ,S'S'I
18,ooo Ac.-Fr.
5-rDRAG£
MASS HYDROGRAPH
SALMON CREE.f< RESERVOIR
SHEE.T :< OF 3
4 o s ooo O':'N D J F ~AM J J A S D H D J F lr\ A M J J AS 0 N D J F M A II\ J v A o o N D u P h\A Nl J J AS D N D J PM AM J J A S 0 N P J F' M AM J J jJ. 5 0 N I 1156 I lt:t57 I llf.SS I lq5q I 1960 I 1961
8 8SODO
...... 8'5,~'16 ~ 1.(
' 84SODO
"" ~
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5.1 A.
I.
SECTION V
HYDRAULICS
Existing System From Dam to Powerhouse No. 2.
Head Loss at average flow of 66 .I cfs.
Using the formula:
Where:
v 2 X n 2 X L
hf = 2. 21 X R 1 • 333
hf = head toss in ft.
v = velocity in ft. per sec.
n = Coefficient 0. 014
R = Hydraulic Radius
L = Length of section in ft.
Pipe Dia. L. v
40 11 687.15 7.574
38 11 543.35 8.393
36 11 992.19 9.351
34" 577.25 10.484
32" 998.31 11.835
30 11 680.87 13.465
R
0.834
0.792
0.750
0.708
0.667
0.62S
hf
4.45
4.63
11.29
8.92
21.28
20.49
TOTAL HEAD LOSS; 71.06'
2. Head loss in existing penstock for maximum power output and
limiting velocity to 20 ft. per sec. Flow rn 3QH pipe @ 20 fps
= 20 x 4.909 = 98.12 cfs.
Pipe Dia. L. v R hf
40 11 687.15 11.25 0.834 9.82
38 11 543.35 . 12.46 0.792 10.21
36 11 992.19 13.88 0.750 24.88
34 11 577.25 '15.56 0.708 19.64
32 11 998.31 '17.57 0 667 46.90
30 11 680.87 20.00 0.625 r:ls. 20
TOTAL HEAD LOSS~ 156. 6f}
Page 51
SECTION V -HYDRAULICS
B. Replacing the 30", 32" and 34" dia. penstock sections with 36"
dia.
1. Head loss with 120 cfs flow.
Pipe Dia. L v R hf
40 11 687.15 13.75 0.834 14.68
38 11 543.35 15.24 0.792 15.27
36 11 3,248.62 16.98 0.750 121.90
TOTAL HEAD LOSS: 151. 85'
An increase of 22% maximum flow with 4" 8 feet less friction
loss.
2. Head loss with 66. 1 cfs flow.
40 11 687.15 7.574 0.834 4.45
38" 543.35 8.393 0.792 4.63
36 11 3,248.62 9.351 0.750 36.97
TOTAL HEAD LOSS: 46.05'
3. Pipe wall thickness and weight required. Design for 900 ft.
of surge pressure or 390 psi.
a. t = PR
sc P = 390 psi. R = 18 11 S = 20,000 psi. C = 90%
3go x 18 t = = 0.39 11 7/16 11 = 0.4375 OK 20,000 X 0.9
b. weight of 2256 ft. of 36 11 dia. 7 /16'1 pipe
wt. = 0.4375 x1;i8 x 113 x 490 x 2256 = 379,515 lbs.
Page 52
SECTION V -HYDRAULICS
C. Powerhouse No. 2 to Powerhouse No. 1 .
I. Flume Section
The flume section should have at least the flow capacity of
powerhouse no. Z when operating at maximum flow or slightly
greater than 120 cfs.
Problem: What diameter lower pressure pipe is required for a
flow of +120 cfs at a slope of 0.25%?
Try: 54 11 diameter pipe"
Velocity of flow in 54 11 diameter pipe at 0.25% grade.
v = 1.318 ch Ro.s3so.s4
ch = 145, R 15.9 7 14.1 = 1.13, s = o.0025.
V. = 1.318 x 145 x 1.13°·63 x 0.0025°·54 = 8.05 ft. per sec.
Q = 8.05 X 15.9 = 128 (a good choice.)
2. Penstock Section For·ebay to P. H No. I
Assume a 48 11 dia. penstock. Length is 1625 fL
a. Head loss at 66.1 cfs. (average flow)
hf = 5.252 X 0.0142 ~_1625 3.99 ft.
2.21
b. Head loss at 128 cfs. (capacity of 54" dia. flume.)
1 .22 X 0.014 2 X 1625
2.21
Page
SECTION V -HYDRAULICS
3. Pipe wall thickness required for 48 11 dia. penstock static head
approx. 400 ft. plus 25% surge = approx. 500 ft. of head or
approx. 216 psi. Design for 250 psi or 577ft. of head.
PR t = P = 250 psi. R = 24 11
Se S = 20,000 psi. e = 90%
t = 250 X 24 = 0.33311
20000 X 0.9
3/8 11 = 0.375 11 OK (Add 1/16 11 for corrosion)
4. Weight of 1625 feet of 48 11 dia. 7/16 11 wall thickness penstock.
wt. = 0. 4375 X rt-2; 150 .. 8 X 490 X 1625 = 364 r 810 I bs.
D. New penstock from dam to powerhouse no. 1 and eliminate power-
house no. 2.
Use a maximum draft of 120 cfs.
Length = approximately 15,980 feet.
Limit velocity to 14 ft. per sec.
1. Size required to limit velocity to 14 ft./sec.1
D = ~(8.57 X 4) 7 n) = 3.3 ft. dia. Say 3'-61! minimum
diameter pipe to consider.
2. Head loss in 42 11 , 48 11 and 54 11 penstock 15,980 feet in fength
flowing 120 cfs.
42 11 12.52 X 0.0142 X 15980 263.4 feet a. = = hf 2.21 X 0.8751.333 (very high)
b. 48 11 hf 9.552 X 0.0142 X 15980 129.3 feei· = = 2.21
c. 54u hf = 7.552 x 0.0142 ?.J~i80 = 69.0 feeL
2. 21 X 1.125
1 Velocity limited to 14 fps for this installation to minimize head loss
and excessive pressure fluctuations.
Page 54
SECTION V -HYDRAULICS
3. Head loss in 42 11 , 48 11 and 54 11 penstock 15,980 feet in length
flowing 66. 1 cfs.
a. 42 11
hf = 6.87 2 X 0.0142 X 15980 79.9 feet X 0.8751.333 .;:::
2.21
b. 48 11
hf = 5.262 X 0.0142 X 15980 39.2 feet = 2.21
c. 54 11 hf = 4.162 X 0.0142 X 15980 20.9 feet. 1.1251.333 = 2.21 X
4: Allowable head for various wall thickness of 42 11 , 48 11 and 54 11
diameter pipe. (Design for maximum pressure of 635 psi.)
42 11 Piee 48 11 Piee 54 11 Piee
Thickness Allowable Allowable Allowable
Inches ~ head-ft* ~ head-ft* ~ head-ft*
5/16 11 267 493 234 432 208 384
3/8 11 321 593 281 519 250 461
7/16 11 375 693 328 605 291 537
1/211 428 790 375 692 333 615
9/16 11 482 895 421 777 375 692
5/8 11 535 988 468 864 416 768
11/16 11 589 1088 515 951 458 846
3/411 642 1186 562 1038 500 923
13/1611 609 1125 541 999
7/8 11 656 1211 583 1077
15/16 11 625 1154
111 666 1230
* Allows for 255 psi surge pressure.
Page 55
SECTION V -HYDRAULICS
5. Required thickness, length and weights for 42 11 penstock.
Length Weight
Thickness Feet Per Foot Weight
5/16 11 2,195 140.3 307,958
3/8 11 514 168.4 86,558
7/16 11 1,373 196.4 269,657
1/2 11 10,300 224.5 2,312,350
9/16 11 400 252.6 101,000
5/8 11 400 280.6 112,240
11/16 11 400 308.7 123,480
3/411 400 336.7 134,695
TOTAL WEIGHT: 3,447,978 lbs.
6. Required thickness, length and weights for 481i penstock.
Length Weight
Thickness feet per foot Weight
5/16 11 1,100 160.4 176,440
3/811 1,100 192.4 211,640
7/16 11 630 224.5 141,435
1/2 11 1,016 256.6 260,706
9/16 11 10,536 288.6 ~i 1040,690
5/8 11 320 320.7 102,624
11/1611 320 352.8 112,896
3/411 320 384.9 123,168
1-3/1611 320 416.9 133,408
7/8 11 320 449.0 143,680
~--~~.--~·~
TOTAL WEIGHT: 4,446,687 lbs.
Page ~)()
SECTION V -HYDRAULICS
7. Required length, thickness and weights for 54 11 penstock.
Length Weight
Thickness feet Per Foot Weight
5/16 11 737 180.4 132,955
3/8 11 1,345 216.5 291,193
7/1611 120 252.6 30,312
1/211 740 288.6 213,564
9/1611 904 324.7 293,529
5/811 10,536 360.8 3,801,389
11/1611 266 396.9 105,575
3/411 266 433.0 115,178
13/1611 266 469.0 124,754
7/8 11 266 505.1 134,357
15/16 11 266 541.2 143,959
1" 270 577 3 155,871
TOTAL WEIGHT: 5,542,636 lbs.
8. Best Apparent Penstock Design
Starting from dam to powerhouse no. I.
Dia. Thickness Length Per Foot Weight
54 11 5/16 11 720 1 180.4 129,888
54 11 3/8 11 1/3601 216.5 294,440
48 11 7/16" 720' 224.5 161,640
48 11 1/211 1, 760 1 256.6 451/616
48 11 9/1611 9,8001 288.6 2,828,280
42 11 9/1611 400 252.6 101 f 040
42 11 5/8 11 400 280.6 112,240
42 11 11/1611 400 308.7 123,480
42 11 3/411 400 336.7 134,680
T01AL EIGHT: 4,337,304 !bs.
Page 57
9.
SECTION V -HYDRAULICS
Head loss in best apparent penstock design.
66.1 cfs 120 cfs
5411 dia. = 2. 7 1 54 11 dia. = 8.991
48 11 dia. = 30.1 1 48 11 dia. = 99.33 1
42 11 dia. = 8.0 1 42 11 dia. = 26.49 1
Total: 48.8 1 Total: 134.81 1
This design utilizes 109,383 fewer pounds of steel than an all
48 11 diameter penstock with nearly identical head losses.
E. Hydraulics Recommendations
1. Replace the 30 11 , 32 11 and 34 11 diameter penstock sections
between the dam and powerhouse no. 2 with 36 11 diameter
7/16 11 wall thickness pipe.
2. Replace the approximately 10,000 feet of wood flume between
powerhouse no. 2 and the forebay above powerhouse no. 1
with 5411 diameter CMP with a 0.138 11 wall thickness. Utilize
the existing flume suppor·ts and t"P.pair as required. /-\ppr·ox~
imately 450 concrete footings will be required in the trestle
sections of the flume.
3. Replace the existing penstocks between the forebay and
powerhouse no. 1 with one 48 11 diameter pipe. If available,
we recommend surplus pipe from the Alyeska Pipeline Com-
pany. Contact: R. J. Egan, Surplus Management Depart-
ment, P.O. Box 4-Z, Anchorage,. Ak. 99509; office at 3301
11 C 11 Str~eet in Anchorage.
If the Alyeska surplus pipe is unavailable, 162~j feet of 48 11
diameter, 7/16 11 wall thickness pipe is recommended.
Page 58
SECTION V -HYDRAULICS
4. Replace the forebay with a surge tank to protect the low
pressure pipe replacing the flume and to protect the pen-
stock. It will also improve governing stability and prevent
spill when rapidly shutting down powerhouse no. 1.
5. Should AELP desire to eliminate powerhouse no. 2 and have a
single penstock extending from the dam to powerhouse no. 1,
the penstock design should be approximately as shown in
section D. 8. above.
If approximately 14,000 feet of Alyeska surplus 48-inch pipe
is available, it is recommended that all of the 48 11 and 42 11
pipe length be substituted with A!yeska pipe. Thls pipe has
been pressure tested to 1150 psi.
Page 59
SECTION VI
CAPITAL COST ESTIMATE
The estimate of costs are provided for six alternates:
1. The installation of a new automated 5000 kW Francis turbine unit
at powerhouse no. 2. This includes replacing the existing 30 11 ,
32 11 and 34 11 sections of the penstock with new 36 11 to reduce
friction losses and excessive pressure fluctuations.
2. The upgrading and automation of the existing equipment at
powerhouse no. 2. This includes the replacement of the penstock
sections enumerated in 1,
3. The upgrading and automation of the existing equipment at
powerhouse no. 1. This includes replacing the flume with low-
pressure conduit, a new 48 11 penstock and a surge tank.
4. A new automated 3000 kW unit at powerhouse no. 1 with waterway
improvements as in 3 above.
5. The installation of two new automated 4500 kW units ln powerhouse
no, 1 with a new penstock from the dam.
6. The installation of one new automated 9000 kW unit in power-
house no. 1 with a new penstock from the darn.
The construction costs are current (1978) costs based upon the latest labor
rates, construction equipment costs and recent costs for mechanical/electrical
equipment and permanent materials. In Section 7 of thlc :·epor't,. the total
costs are escalated through the assumed construction period for each alternate
in order to provide a realistic basis for power costs.
The project cost estimates are presented in the following ;)ages.
Page 60
SECTION VI -CAPITAL COST ESTIMATE
Cost Estimate
Item I: Installation of a new automated 5000 kW Francis Turbine unit
at Powerhouse No. 2.
A. Direct Costs Labor
1. One horizontal Francis turbine
including valve and governor 90 1 000
2. Generator 1 Exciter 1 etc.
5 MW I 0. 8 pf 30 I 000
3. Unit switchgear and Relaying 25 1 000
4. Line Relay Panel 5 1000
5. Remote Supervisory Control 30 1 000
6. Auto Synchronizing Equipment 5 1000
7. 125 Volt d. c. Battery 1 Charger
and Distribution Panel 9, 000
8. Low Voltage Station Service 5 1000
9. Lighting System 5 1000
10. Grounding System 5,000
11. Conduit and Cables 20£000
12. Foundations 64,000
13. Change out 30 11 1 32 11 and 3411
Penstock with new 36 11 Penstock 240 1 000
14. 6250 kVA 1 3 phse 1 4 kV-24kV
Transformer and Accessories 10,000
Material
3401000
3401000
1001000
351000
601000
30{000
21,000
20,000
51000
5{000
360,000
70,000
Tota! i~)jrect Costs:
Total
4301000
3701000
1251000
401000
901000
351000
301000
251000
101000
101000
40,000
80,000
600,000
801000
~' 1 r 965 1 000
Page 61
1
SECTION VI -CAPITAL COST ESTIMATE
B. Indirect Costs
1 . Indirect Construction Costs 1
2. Contingency
3. Engineering
4. Owner•s Administration
and Legal Expense
5. Interest During Construction
Assume Expense Year 1978
Assume Expense Year 1979
Assume Expense Year· 1980
Then @ 10% Interest
300,000 X 5% + 10% + 10%
1,055,000 X 5% + 10%
1,415,000 X 5%
Year 1
15,000
15,000
Total Interest During Construction:
Total Indirect Costs:
GRAND TOTAL -ITEM i:
Year 2
30,000
52,750
82,750
390,000
100,000
295,000
20,000
300,000
1,055,000
1,415,000
Year 3
30,000
105,500
70,750
206,250
$304,000
$1,109,000
$3,074,000
Indirect construction costs include such things CJS construction 8quip-
ment depreciation, supervision, office expense, insurance, cons1Tuclors 1
profit, etc.
Page 62
SECTION VI -CAPITAL COST ESTIMATE
Item I I: Upgrade Equipment and Automate Upper Salmon Creek
Powerhouse (No. 2)
A. General
In general, this option is not r·ecommended because of the age and
condition of the equipment.
B. Costs
1. Upgrade mechanical equipment
2.
3.
4.
5.
6.
7.
Rewind each generator stator at
$25,000/stator
Rewind each generator field at
$12,000/field
New static excitation system at
$20,000/set
Replace existing low voltage station
service equipment including transformer
and incoming fuse disconnect
Upgrade lightning system
Upgrade or replace conduits and
cables system
8. Provide additional gr·ounding mat :md
connectors
9.
10.
11.
Generator breaker and control
protection equipment
Contingencies
Change out the 30 11 , 32 11 and 34u
penstock with new 36 11 penstock
Modify turbine pits and tailrace
~3UBTOTAL:
$250/000
50,000
24,000
40,000
25,000
5,000
20,000
5,000
70,000
50,000
600,000
60,000
$1,199,000
Page 63
SECTION VI -CAPITAL COST ESTIMATE
C. Automation of Equipment at Powerhouse No. 2.
1.
2.
3.
4.
5.
Automation of upgraded mechanical
equipment - 2 units @ $50,000
Furnish, install, and connect generator
relaying and additional controls for
two units
Furnish, install and connect automatic
synchronizing system
Furnish, install, and connect line relay
panel
Furnish, install, and connect remote
supervisory control system
SUBTOTAL:
TOTAL direct costs for REHABILITATING
AND AUTOMATING POWERHOUSE NO. 2
D. Indirect Costs
1. Indirect Construction Costs
2. Contingency
3. Engineering
4. Owner's Administration & Legal Expense
5. Interest During Construction
Assumes bid in 1978 @ 10%
$100,000
170,000
35,000
40,000
90,000
$435,000
$1,634,000
300,000
165,000
160,000
165,000
Total Indirect Cost: 807,000
GRAND TOTAL-ITEM If: $2,441,000
Page 64
SECTION VI -CAPITAL COST ESTIMATE
Item Ill -Upgrade Equipment and Automate Lower Salmon Creek Powerhouse
(No. 1)
A. General
B.
In general, this option is not recommended because of the
age and condition of the equipment.
Costs
1.
2.
3.
4.
5.
6.
7.
Upgrade mechanical equipment
Rewind each generator stator
@ $25,000/stator
Rewind each generator field
@ $12,000/field
New static excitation system
@ $20,000/set
Replace existing low voltage station
service equipment including trans-
former and incoming fuse disconnect
Upgrade lighting system
Upgrade or replace conduits and
cables system
8. Provide additional grounding mat and
connectors
9.
10.
12.
13.
Generator breaker and control pro-
tection equipment
Contingencies
Replace flume with 54" CMP
48" diameter· penstock
Surge tank
SUBTOT.b.L:
$250,000
50,000
24,000
40,000 '
25,000
5,000
20,000
5,000
70,000
50{000
1/100,000
485{000
150 1 000
$2,274 1 000
Page 65
SECTION VI -CAPITAL COST ESTIMATE
C. Automation of Equipment at Powerhouse No. 1.
1.
2.
3.
4.
5.
Automation of upgraded mechanical
equipment -2 unis @ $50,000
Furnish, install, and connect generator
relaying and additional controls for
two units
Furnish, install and connect automatic
synchronizing system
Furnish, install, and connect line relay
panel
Furnish, install, and connect remote
supervisory control system
SUBTOTAL:
TOTAL direct costs to REHABILITATE AND
AUTOMATE POWERHOUSE NO. 1:
D. Indirect Costs.
1. Indirect Construction Costs
2. Contingency
3. Engineering
4. Owner's Administration & Legal Exrense
5. Interest During Construction
Assumes bid in 1978 and 21 months Canst. @ 10%
Total Indirect Costs:
GRAND TOTAL ~ ITEM Ill
$100,000
170,000
35,000
40,000
90,000
$435,000
$2,709,000
500,000
250{000
278,000
30{000
250,000
1,308,000
$4,017,000
Page 66
SECTION VI -CAPITAL COST ESTIMATE
Item IV -New Automated Equipment at Powerhouse No. 1
(One 3,000 kW Unit)
A. Direct Costs. Labor Material
1. One horizontal Francis turbine
including valve & governor 53,500 201,500
2. Misc. mechanical equipment 30,000 170,000
3. Generator, 3, 333 kVA I 0.9 p.L
600 RPM, 4,160 volts, 3 phase 20,000 220,000
4. Static excitation system 2,000 231000
5. Transformer, 3 phase, 3,333 kVA 7,500 52,500
6. Unit switchgear and relaying 25,000 100,000
7. Line relay panel 5,000 35,000
8. Remote supervisory controi 30,000 60,000
9. Auto synchronizing equipment 5,000 30,000
10. 125 volt d .c. battery, charger
and distribution panel 9,000 ?'1,000
11. Low voltage station service 5,000 20,000
12. Lighting system 5,000 5,000
13. Grounding system 5,000 5,000
14. Conduit and cables 20,000 20,000
15. Replacement of flume
with 54 11 CMP 600,000 500,000
16. 48" diameter penstock 3021000 1831000
17. Surge tank 75,000 75,000
Total Direct Costs:
Total
255,000
200,000
240,000
25,000
60,000
125,000
40,000
90,000
351000
30,000
25,000
10,000
10,000
40,000
1,100,000
485,000
150,000
$2,920,000
Page 67
SECTION, VI -CAPITAL COST ESTIMATE
B. Indirect Costs
Note:
1. Indirect construction
2. Contingency
3. Engineering
4. Owner•s Administration & Legal Costs
5. Interest During Construction
Assume expense 1978
Assume expense 1979
Then @ 1 O% Interest
1,960,000 X 5% + 10%
2,100,000 X 5%
Total Interest During Construction
1,960,000
2,100,000
Year 1
98,000
98,000
Year· 2
196,000
105,000
301,000
Total Indirect Costs:
GRAND TOTAL -ITEM IV:
540,000
150,000
420 1 000
30,000
399{000
$1,539,000
$4,459,000
Under direct costs itern 5; add $60,000 for an auto-transformer
with 4.16 kV, 3.3 MVA to 23 kV, 6.6 MVA and 23 kV to
69 kV, 10 MVA for future conversion to f-\ELP 69 kV trans-
mission system.
Page 68
SECTION VI -CAPITAL COST ESTIMATE
Item V: New Automated Equipment at Powerhouse No. 1
(2 4500 kW Units)
(Eliminate Powerhouse No. 2)
A. Direct Costs.
1.
2.
3.
4.
5.
6.
7.
Two 4500 kW double nozzle single
overhung horizontal Pelton turbines;
1,050 foot head, 720 RPM, with valves
and governors
Miscellaneous mechanical equipment
(pumps, monorail, compressor, etc.)
Two generators, 5000 kVA, 0.9 PF,
720 RPM, 4260 volts, 3 phase
Static excitation equipment @ $30,000
Transformer bank 3 -single phase
kVA, OA-FA, 4.16 kV -24 kV
Unit switchgear and relaying furnished,
installed and connected per unit $125,000
Line relay panel -furnished, installed
and connected
8. Line breaker -furnished, installed and
connected
9.
10.
11.
12.
13.
Remote supervisory control system -
furnished 1 installed and connected
Automatic synchronizing equipment -
furnished, installed and connected
125 volt d. c. battery, chargers and
distribution panel -furnished, installed
and connected
Low voltage station service system,
including transformers and fuse
disconnect -furnished 1 ins tailed
and connected
Lighting system -furnished, installed
and connected
$648,000
200,000
702,000
60,000
122,000
250,000
40,000
35,000
120,000
35,000
35,000
30,000
15,000
Page 69
SECTION VI -CAPITAL COST ESTIMATE
14. Grounding system -furnished, installed
and connected
15. Conduit and cables -furnished, installed
and connected
16. Installation of new penstock from dam
to powerhouse no. 1
TOTAL direct costs:
B. Indirect Costs
1. Indirect Construction Costs
2. Contingency
3. Engineering
4. Owner 1 s administration & Legal Expense
5. Interest during construction
Assume expenses 1978
Assume expenses 1979
Assume expenses 1980
Then @ 1 O% Interest
2,000,000 X 5% +10% +10%
5,000,000 X 5% + 10%
6,242,000 X 5%
2,0001000
5,000,000
6,242,000
Year 2
200,000
2501000
12,000
60,000
7,157,000
$9,521/000
$1,750,000
900,000
975/000
96,000
Year 3
200,000
500,000
312,100
450,000 1,012,100
Total interest During Construction: $1,562,100
Total Indirect Costs:
GRAND TOTAL -!TEiv1 V; $14,804/000
Page 70
SECTION VI -CAPITAL COST ESTIMATE
Item VI: New Automated Equipment at Powerhouse No. 1
(One 9000 kW Unit)
A. Direct Costs.
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11 <
12.
13.
14.
15.
One 9000 kW double nozzle single
overhung horizontal Pelton turbine,
1050 foot head, 516 RPM, including
valve and governor
Miscellaneous mechanical equipment
Generator, 10,000 kVA, .9 PF,
514 RPM, 4160 volts, 3 phase
Static excitation system
Transformer bank
Unit switchgear and relaying
Line relay panel
Remote supervisory control
Auto synchronizing equipment
125 volt d. c. battery, chargers and
distribution panel
Low voltage station service system
Lighting system
Grounding system
Conduit and cables
Installation of new penstock from darn
to powerhouse no. 1
TOTAL direct costs:
$578,000
200,000
546,000
40,000
122,000
125,000
40,000
90,000
35,000
30,000
25,000
10,000
10,000
40,000
7,157,000
$9,048,000
Page 71
SECTION VI -CAPITAL COST ESTIMATE
B. Indirect Costs
1. Indirect Construction Cost
2. Contingency
3. Engineering
4. Owner1 s Administrative & Legal Expense
5. Interest During Construction
Assume expenses 1978
Assume expenses 1979
Assume expenses 1980
Then @ 10% Interest
1,000,000 X 5% + 10% + 10%
5,000,000 X 5% + 10%
5,578,000 X 5%
2,000,000
5,000,000
5,578,000
Year 1
100,000
100,000
Year 2
200,000
250;000
450,000
1,640,000
875,000
925,000
90,000
Year 3
200,000
500,000
278,900
978,900
Total Interest During Construction 1,528,900
Total Indirect Costs: 5,058, 900
GRAND TOTAL -ITEM VI: $14,106,900
Page 72
SECTION VII
POWER COST ESTIMATES
The following power cost estimates utilizes the capital cost data from
Section 6 and assumes financing at 10.5% interest and 20-year maturity.
The power cost estimates include annual operation and maintenance costs
as well as insurance costsj these costs have been estimated based on
the experience of other Alaskan utilities• hydroelectric projects, and are
considered conservative. However, debt service makes up to over 93%
of the total annual cost of the recommended development and therefore
potential economies in the cost of financing are most capable of signif-
icantly influencing power cost.
Table 7-7 combines the alternatives of a two powerhouse scheme as
developed in Section 6, Items 1 through 4,
Note: Amortization costs of the existing Salmon Creek facilities are not
included in these estimates.
Page 73
SECTION VII -POWER COST ESTIMATES
TABLE 7-1
POWER COST ESTIMATE
New 5000 kW Horizontal Francis Unit
At Upper Salmon Creek Powerhouse No. 2
Installed capacity
Primary energy
Secondary energy
Total Annual Ave. Energy
Capital Investment (escalated @ 7%)
315,000
1,137,750 X 1.07
1,621,250 X 1.07 X 1.07
5,000
21,810,000
4!790,000
26,600"000
315,000
1,217,390
1,856[ 170
kW
kWh
kWh
kWh
Total Capital Investment: $3,388,560
Annual Costs
Operations: 2080 man hr. @ 25.00
Maintenance 5000 kW @ 1.25
Insurance @ $1/1000
Total Annual Cost:
Debt Service
$3,388,560, 20 yrs. 10.5%-0.1202
Total Annual Cost of Power
Power Cost
Assuming 26,600,000 kWh sales
52,000
6,250
3,400
$61,650
407,300
$468,950
17.6 mills/kWh
SECTION VII -POWER COST ESTIMATES
TABLE 7-2
POWER COST ESTIMATE
Rehabilitate and Automate Existing
Upper Salmon Creek Powerhouse No. 2
Installed capacity 2,800
Primary energy 20,720;000
Secondary Energy 4,550,000
Total Annual Ave. Energy 25,270;000
Capital Investment (escalated to end of 1978)
Annual Costs
Operation 2080 man hr. @ 25.00
Maintenance, 2800 kW @ 2. 50
Insurance @ $1/1000
kW
kWh
kWh
kWh
$2,612,000
TOTAL:
52,000
7,000
~600
$61,600
Debt Service
$2,612,000, 20 yrs. 10.5%-0.1202 313,962
Total Annual Cost of Power $375,562
Power cost @ 25,270,000 kWh sales 14.9 mi lis/kWh
Page 75
SECTION VII -POWER COST ESTIMATES
TABLE 7-3
POWER COST ESTIMATE
Rehabilitate and Automate
Lower Salmon Creek Powerhouse No. 1
Installed capacity 2,800 kW
Primary energy 12,806,000 kWh
Secondary energy 2£817,000 kWh
Total Annual Ave. Energy 15,623,000 kWh
Capital Investment (escalated to end of 1979) $4,599,000
Annual Costs
Maintenance, 2800 kW @ 2.50
Insurance @ $1/100
Debt Service
4,599,000, 20 yrs. 10.5% -0.1202
Total Annual Costs of Power
Power cost @ 15,623,000 kWh sales
TOTAL:
7,000
4,600
$11{600
552,800
$564/400
36.1 mills/kWh
Page 76
SECTION VII -POWER COST ESTIMATES
TABLE 7-4
POWER COST ESTIMATE
New Automated 3000 kW Unit
Lower Salmon Creek Powerhouse No. 1
Installed capacity
Primary Energy
Secondary Energy
Total Annual Ave, Energy
Capital Investment (escalated @ 7%)
2/058/000
2,401,000 X 1.07
3,000 kW
13,480 1 000 kWh
_2,965t000 kWh
16 1 445,000 kWh
2,058,000
2,569/070
Total Capital Investment:
Annual Costs
Maintenance 1 3,000 kW@ 1.25
Insurance @ $1/1000
TOTAL:
Debt Service
$4,627,070, 20 yrs. -10~5%-0,1202
Total Annual Cost of Power
3,750
51000
$8,750
5561175
$564,925
Assuming 16,445,000 kWh &ales 34.4 mills/kWh
Page 77
SECTION VII -POWER COST ESTIMATES
TABLE 7-5
POWER COST ESTIMATE
New Automated Plant at Powerhouse No. 1
With New Penstock From Dam
(2-4500 kW Units)
Installed capacity
Primary energy
Secondary energy
Total Annual Ave. Energy
Capital Investment (escalated @ 7%)
2,100,000
5 1 450,000 to 1979
7,254,100 to 1980
9 1 000 kW
35' 396 I 000 kWh
7,771,000 kWh
43,167,000 kWh
2,100,000
5,831,500
8,3051200
Total Capital Investment: $16/236,700
Annual Costs
Maintenance, 9 1 000 kW @ $1.25
Insurance $1/1000
TOTAL:
Debt Service
$16,236,700, 20 yrs. 10.5%-0.1202
Total Annual Cost of Power
Power Cost@ 43,167,000 kWh sales
111250
16,240
27,490
1,951,650
1 1 979 r 140
45.8 mills/kWh
Page 78
SECTION VII -POWER COST ESTIMATES
TABLE 7-6
POWER COST ESTIMATE
New Automated Plant at Powerhouse No. 1
With New Penstock From Dam
(1 -9000 kW Unit)
Installed capacity
Primary energy
Secondary energy
Total Annual Ave. Energy
9,000 kW
35,396,000 kWh
7 I 771,000 kWh
43,167 1 000 kWh
Capital Investment (escalated @ 7%)
2,100,000
5,450,000 X 1.07
6,556,900 X 1.07 X 1.07
2,100,000
5,831,500
7,506,995
Total Capital Investment:
Annual Costs
Maintenance 1 9,000 kW @ 1, ?5
Insurances $1/1000
TOTAL:
Debt Service
$15,438,495, 20 yrs.10.5% -0.1202
Total Annual Cost of Power
Power Cost @ 43,167,000 kWh sales
$15,438,495
11,250
J_h440
26,690
$1,855,700
$1,882,390
Ll3.6 mills/kWh
F>age 79
1.
2.
3.
SECTION VII -POWER COST ESTIMATES
TABLE 7-7
COMBINATION POWER COST ESTIMATE
Rehabilitate and automate existing equipment at Powerhouse No. 1
and No. 2.
kWh Annual Cost
Powerhouse 1: (Table 7-3) 15,623r000 $564,400
Powerhouse 2: (Table 7-2) 25!270,000 375,562
TOTAL: 40,893,000 $939,962
Cost of power; 23.0 mills/kWh
Rehabilitate and automate existing equipment at Powerhouse No. 2
and new 3, 000 kW unit at Powerhouse No. 1.
kWh Annual Cost
Powerhouse 1: (Table 7-4) 16,445{000 564,925
Powerhouse 2: (Table 7-2) 25,270,000 375,562
TOTAL: 41,715,000 $940,487
Cost of power: 22.5 mills/kWh
Install new automated 5000 kW unit at Powerhouse No. 2 and
rehabilitate and automate existing equipment in Powerhouse No. 1.
kWh Annual Cost
Powerhouse 1: (Table 7-3) 15,623,000 $564,400
Powerhouse 2: (Table 7-1)
TOTAL:
Cost of power: 24.5 mills/kWh.
26,600,000
42,223;000
468,950
$1,033,350
Page 80
SECTION VII -POWER COST ESTIMATES
4. Install new automated 5000 kW unit at Powerhouse No. 2 and
install new automated 3,000 kW unit at Powerhouse No. 1,
kWh Annual Cost
Powerhouse 1: (Table 7-4) 16,445,000 564,925
Powerhouse 2: (Table 7-1) 26,600l000 468l950
TOTAL: 43,045,000 $1,033,875
Cost of power: 24.0 mills/kWh
Note: The above combination (item 4) would add approximately
5,200 kW capacity to the AELP system. AELP will require
another 2500 kW diesel unit by 1980 for standby capacity if
additional hydro capacity is not added. This unit may be
expected to cost $240.00 per kW installed or a total of $600,000.
If this amount were credited to the r·ehabi!itation of the Salmon
Creek Project, the hydro would be even more attractive.
Page 81
APPENDIX A
·r _. •'
JAMES M. MONTGOMERY. CONSUL:riNG ENGINEERS, INC. 2255 A•enida De La Playa, La Jolla;" Caltlornia 9Z037 I (714) 459-2931
INTRODUCTION
REPORT ON
SAFETY INSPECTION
PROJECT NO. 2307 -ALASKA
A safety inspection of Salmon Creek and Annex Creek Project (Pro-
ject No. 2307 -Alaska} has been made. This inspection was made
to fulfill the requirements of Section 12.2 of Part 12 of the
Regulations under the Federal Power Commission. The inspection
consisted of a visual inspection of each darn and other project
facilities and an analysis of potential earthquakes that could
affect Salmon Creek Dam to determine if the latest information
substantiates the assumptions made in the stress analysis performed
in November 1972.
SALMON CREEK DAM
The inspection of Salmon Creek Darn was made on May 17, 1977. Water
surface at Salmon Creek Dam at the time of the inspection was
approximately 50 feet below the spillway crest so that the area
that was repaired in the summer of 1967 was visible. ·The gunite
repair on the upstream face of the dam was in very good condition
as shown on the attached photos. Only small areas showed evidence
of spalling of the gunite and these were the areas where the gunite
was only a relatively thin layer over sound concrete and generally
near the bottom of the repair.
The gunite repair of the spillway was in excellent condition as
shown on the attached photo. There was no evidence of any spalling
on either the spillway floor or the left wall that was repaired.
Debris has collected in front of the spillway as shown on the photo
and should be removed or burned to prevent it accumulating against
the spillway piers and stopping any flood flows that could possibly
cause overtopping of the darn.
The weather during the inspection was clear and dry so it was possible
to determine whether there was appreciable leakage through the dam.
The downstream face was essentially dry with no evidence of any
noticeable wetness on the downstream face. There is some evidence
of a continued deposit of the carbonate material on the downstream
face caused by leaching of the lime added to the concrete during
construction. The build-up is only very slight since the face of
-1-
JAMES M. MO!'I.-rGOM::ERY.CO!'I.i"SUl!!''NG ENGINEERS, INC. 2255 Avenida De La Playa, La Jolla. Califo.nia 92037 I (714) 459·2931
the dam was scaled in 1967 indicating that the dam is a pretty tight
structure. There was no evidence of water flowing along the abut-
ments on the downstream-face.
To evaluate the static seismic coefficient of 0.1 which was used in
the stress analysis performed in November, 1972, in light of current
information regarding faulting and seismicity, a review of faulting
and seismicity in the Juneau area was made. In order to secure the
most recent data on seismicity in the Juneau area, the U. S. Geolog-
ical Survey was contacted both in Juneau and in Denver. The data
provided by U. S. G. s. and used in the review included (1) pages
7 through 22 of an open file report entitled "Surficial Geology of
the Juneau Urban Area and Vicinity, with Emphasis on Earthquakes
and Other Geologic Hazards" which we received from Mr. Robert D.
Miller of U. S. G. S. in response to our request for information;
and {2) a paper entitled "Separation and History of the Chatham Fault,
Southeast Alaska, North America", which we received from Mr. John C.
Lohr of U. S. G. S.
Page 11 of (1) above points out that historical record dictates that
earthquakes strong enough to affect Juneau most likely would occur
along the Fairweather -Owen Charlotte Islands Fault which is
located approximately 100 miles west of the dam site.· An evept of
magnitude 8 apparently occurred 9n this fault on July 10, 1958. Our
consulting geologist has computed the maximum acceleration at the
site due to an event of this magnitude on the Fairweather -Owen
Charlotte Fault. This computation was made using a method presented
by Schnabel and Seed in "Acceleration in Rock for Eathquakes in the
Western United States 11
• This computation produced an estimated
maximum bedrock acceleration at the dam site on the order of 0.04g.
There is another fault having some potential for affecting the
Juneau area is the Chatham Strait Fault. Mr. Lohr points out in
his letter that some geologists consider the fauJt to be active.
However, although this fault is a major structural feature there
is apparently no general agreement regarding the activity of the
fault and as Mr. Lohr points out, no specific estimates of maxi-
mum credible or maximum probable events along the fault have been
made.
Nr. Lohr points out that two earthquakes of magnitude class 6
occurred in 1944 and 1952 on a possible northern extension of
the Chatham Strait Fault. Even if an event of this magnitude
were to occur on that portion of the Chatham Strait Fault located
closest to Juneau area (approximately 25 miles west of Juneau),
our geologist has estimated that the maximum bedrock acceleration
at the dam site would be on the order of 0.09g.
-2-
JAMES M. MONTGO!'<fER'( CONSULTING ENGINEERS, INC. 2255 Avenida De La Playa. La Jolla. Calilornia 92037 I (71ot) ot59;2931
On the basis of the review, it appears that there is no conclusive
evidence presently available to indicate that the dam site will be
subject to maximum bedrock acceleration in excess of O.lg so no
additional stress analysis of the darn is required. However, as
pointed out by Mr. Lohr, because seismic records in southeast
Alaska is very short, " •..•.••••. care should be taken in drawing
a firm conclusion from the low level of seismic activity there."
ANNEX CREEK DAM
An inspection of Annex Creek Darn was made on October 12, 1976. At
the time of the inspection, water was flowing over the spillway.
The general condition of the dam is good. There appears to be no
deterioration or rotting of the treated timber from which the dam
was built. There is, however, appreciable leakage which in no
way endangers the safety of the dam. The greatest amount of leak-
age appears to be coming through the end joints of the decking
where the decking was spliced between the stringers. Deflection
produced by the water load opens these joints sufficient to cause
leakage. The main adverse effect of the leakage is its ice pro-
ducing capability should the lake level be high during the freez-
ing period. Review of historic lake levels indicates that such a
condition is a rare possibility, at best.
Structural design calculations of the reconstructed da~ have not
been made as it is presumed that they were submitted to the Fed-
eral Power Commission for approval when the darn was reconstructed ..
PENSTOCKS AND FLUME
On October 11 -14, 1976, a thickness survey of Upper and Lower
Salmon Creek Project penstocks was made. This survey included a
visual inspection as well as determination of the thickness of the
metal by means of non-destructive ultrasonic thickness measuring
equipment. Thickness readings were generally taken in the upper
half of the pipe above the centerlinei however, at approximately
one-fourth to one-third of the locations, thickness readings were
taken in the lower half of the pipe. There were no appreciable
differences between the upper and lower half readings. l~t a given
location, thickness measurements were taken over an area of nne i:o
two square inches.
The Upper Salmon Creek and Annex Creek penstocks appear to be in
good condition from the ultrasonic survey. In most cases generally
uniform and steady readings were indicated as the transducer was
moved around the surfac~ of the pipe. Excessive scale or pitting
would have been indicated by widely varying readings caused by re~
flection and scattering of the ultrasonic waves from the rough
interior of the pipe.
-3-
4 .. JA:'>IES M. MONTGOMERY. CONSULTING ENGINEERS. INC. 2255 Avenida De La Playa. La Jolla. Cahlo•!'•a 92037/(7UJ4~9-29J1
The flume and penstock from Upper Salmon Creek Powerhouse to LOYler
Salmon Creek Powerhouse were not operating. Management of Alaska
Electric Light and Power Company has elected not to op~rate the ·
Lower Salmon Creek Powerhouse because its small generating capacity
makes it an uneconomic source of power compared to alternate avail-
able hydro-power sources. In the past several years the flume and
penstock have deteriorated to a point where they are no longer safe
to operate. Management of Alaska Light and Power Company is aware
of their unsafe condition and will not operate Lower Salmori Creek
Powerhouse until the flume and penstock are rehabilitated and the
plant has been automated so that it can be economically operated as
a source of power.
The Annex Creek Penstock appears generally to be in good condition.
As the pipe is almost entirely exposed, the exterior has suffered
more corrosion than the Upper Salmon Creek penstock. The original
coating has deteriorated to some extent from the last survey made
approximately 12 years ago. There is less of the coating on the
exposed sides and bottom of the pipe and consequently a little more
surface pitting. Condition of some of the supports in the supported
sections of the penstock is not too good.
Pm·lERHOUSES
Upper Salmon Creek Powerhouse was inspected on May 17, 1977 .. The
powerhouse is well maintained. All equipment is clean and in good
state of repair. Lower Salmon Creek Powerhouse was not inspected
as it bas not been operating for approximately two years due to
unfavorable economics.
Annex Creek Powerhouse was inspected on October 12, 1976. The same
general comments apply as for Upper Salmon Creek Powerhouse. The
plant is currently undergoing modifications and repair.
-4-
~ .. I
OVER-ALL VIEW OF RIGHT ABUTMENT
CLOSE-UP VIEW OF RIGHT ABUTMENT
..
OVER-ALL VIEW OF .LEFT ABUTMENT
CLOSE-UP VIEW OF LEFT ABUTMENT
I
:.f
I
I
i
I
!
!
t
I
I . .....
LEFT SPILLWAY WALL AND FLOOR
DEBRIS IN FRONT OF SPILLWAY
...
·~
.-... · i.
. i
~
: ! .,
'
. '
JAMES M. MONTGO!IolERY. CONSULTING ENGil'liEERS. INC. 2255 A•enida De La Plsya, La Jolla. California 92037 I (7\4) 4!>9·2931
CERTIFICATE
I certify that the inspection of Licensed Project No. 2307 -
Alaska for the Salmon Creek and Annex Creek Projects near
Juneau, Alaska, as required by Section 12.2 of Part 12 of
Regulations under the Federal Power Act (FPC Order No. 315}
has been made by me, and is approved by me.
Approved for
JAMES M. MONTGOMERY{
CONSULTING ENGINEERS, INC.
B. . Hild ard
Vice President
Registered Engi'neer-State of Alaska
Registration No. 1330-E
-6-
APPENDIX B
'· .. •'
·).·•-
'" . , .JAMES M. MONTGOMERY, CONSULTING
2255 Avenida De La Playa, La Jolla, California 9202 7 I {714) 459-2931
October 18, 1976
Mr. Franz Naegle
Alaska Electric Light and Power
134 Franklin Street
Juneau, Alaska 99801
Dear Mr. Naegle:
ENGINEERS, INC •
B. G. Hli..DYARD
K-ENNETH G. FERGUSOM.
!'ESTOP. G, RAMOS
EDUARDO ARGUELLES
WIL.L.V.Iol H. loiOSitR
At your request, during the period of October 11 -14, 1976, we performed
a thickness survey of the Upper and Lower Salmon Creek Penstocks and the
Annex: Creek Penstock. This survey included a visual inspection as well as
determination of the thickness of the metal by means of non-destructive ultra-
sonic thickness measuring equipment. The results of the thickness survey are
given in the attached tables. The column headed "Design Thickness" was taken
from data in your files. ~
The thickness readings were generally taken in the upper half of the pipe above
the centerline. However, at approximately one-fourth to one-third of the loca-
tions, thickness readings were taken in the lower half of the pipe. There was
no appreciable or consistent differences between the upper half and lower half
readings. Sometimes the upper readings were 10 to 15 thousandths of an inch
higher and sometimes the same amount lower. The difference was generally
the same regardless of the metal thickness.
At a given location, the thickness measurement was taken over an area of one
to two square inches. The values in the table for a given location are the aver-
age for all readings at that location. In general, the readings at a given location
did not vary more than 20 thousandths of an inch. This variation is probably
caused by shallow surface pitting both on the inside and outside surfaces.
The Upper Salmon Creek and Annex penstocks appear. to be in good condition
from the ultrasonic survey. In most cases generally uniform and steady
readings were indicated as the transducer was moved around the surface of
the pipe. Excessive scale or pitting would have been indicated by widely
varying readings caused by reflection and scattering of the ultrasonic waves
from the rough interior of the pipe.
::> 1 tJ. N N 1 N (; .•.• R E S E A R C H ..• E N V I R 0 N M E N T A l . ENGINEERING
\
: ------------------------------------------~----------------~-------------------------
Alaska Electric Light & Power -2-~ October 18, 1976
LOWER SALMON CREEK PENSTOCK. .. '
Reference to left and right penstocks will be made looking from the powerhouse
toward the flume upstream. Exterior of the right penstock was extremely
pitted with large more or less connected pits of a depth of 1/16 inch or greater.
Very heavy rust scale was encountered over most of the penstock making the
taking of accurate thickness readings difficult. A circumferential split was found
approximately 950 feet above the powerhouse. This split extended over most of
the top half of the pipe. ·Visual inspection of the plate at this point indicated metal
thickness of 1/8 inch or less. This was verified by ultrasonic readings in this
area of 0. 100 to 0.140 inches. As can be seen from the table, the penstock
appears to have a thickness of 1/8 inch or less. However, it should be noted
that these measurements are somewhat in question because of the condition of
the surface but they are considered sufficiently accurate to determine that the
penstock is appreciably thinner than its design thickness of 1/4 inch. It is our
recommendation that this penstock be replaced if the decision is made to use
the lower powerhouse facility.
Condition of the left pensto,ck was somewhat better in general than that of the
right penstock. The coating was in somewhat better condition but there were
extensive areas of exterior rusting. Except for two areas where the metal thick-
ness is appreciably less than the 1/4 inch design thickness, the penstock is not
appreciably thinner than its design. Should it be desireable to put this penstock
back in service it could, with some repair, be used.
Condition of the flume from Powerhouse No. 2 to the head of the penstock is not
good. Probably the worst feature is the extremely poor vertical alignment. A
casual observation indicates a large number of sags. When the flume is operat--
ing, the water depth at these low points i.s appreciably greater than the nonnal
depth and this added load puts undo strains on the supports. Bef'?re the flume
could be considered a reliable conveyance structure, appreciable maintenance
work would have to be performed. The fact that the flume has not operated
for approximately two years has further lead to its general deterioration. The
same is true of the penstocks. Empty penstocks with the very humid interior
atmosphere ~ends to rust more rapidly than if they are full of water. For the
amount of power that has historically been produced at Powerhouse No. ] s it
would hardly seem economical to try to repair this water conveying systern.
However, such an economic study is not a part of this report. It is just an
observation based on the writers long association with this prc1ject.
. . ...
Alaska Electric Light &:: Power -3-~ October 18, 1976
UPPER SALMON CREEK PENSTOCK.
This penstock is generally in good condition. The bridges and supports appear
to be in good condition as they were replaced almost in their entirety approxi-
mately 10 years ago. The exterior paint appears to be in about the same con-
dition as it was 12 years ago at the last inspection. The only apparent exterior
distress is some heavy rusting adjacent to the circumferential joints on the up-
hill side of the section that is lapped over the adjacent section and adjacent to
the longitudinal joint where water tends to be trapped. Several of these areas
were chipped to sound metal and thickness readings taken. At those areas ex-
amined, there does not appear to be excessive deterioration of the penstock •
. In those areas where the pipe was uncovered along the sfdes and bottom, the
coating appears in excellent condition with only small patches of visible rust.
The coating is well bonded.
There has not been appreciable change in thickness from the original survey
performed in May, 1964. We are at a loss to explain why the measured thick-
nesses at the lower end of the penstock are greater than the reported design
thickness. The design thi<;:kness was taken from a table accompanying a letter
from J. A. Wilcox, Assistant Engineer, Alaska Gastineau Mining Co., dated
April 8, 1916. Perhaps the pipe as actually installed was thicker than the
reported design thickness. During the original survey the same thing occurred.
Thickness as great as 0. 425 inches were measured where design thickness was
0.375 inches; 0.440 measured, 0.407 design; and 0.455 measured, 0.435 design.
During the first inspection, the bypass valve in the bottom of Salmon Creek Dam
was open and the entire valley was full of spray and water so it was impossible
to make thicknes-s measurements above the tunnel. During this inspection, it
was possible to get access to this portion of the penstock and several measure~
ments were taken. The measured thickness indicated no reduction frorn the
design thickness of 0. 25 inches. There are several leaks that should be repaired.
It is our opinion, from the data taken, that the penstock is in generally good
condition and should have appreciable life remaining without excessive main-
tenance assuming that the penstock is operated in the proper manner without
. introducing waterhammer surges. It was reported by the operators that
occasionally during start up that the penstock is subjected to extremely bad
surging with pressures going from the normal 300 + psi operating pressure
to as low as 0 and against the peg on the pressure gauge a.t 500 psi. This is
extremely hard on the pipe. If the pressures are really going as low as 0,
it is quite possible that a column separation is occuring and pressures in ex-
cess o£ 500 psi could be experienced. Some method o£ surge control should
defintely be incorporated in the automation design. If waterhammer is intro-
duced in the pipeline under careful manual operation, it could certainly be
introduced during unattended remote control.
JA!'.lES M .. MO:~iTGO:"\.tER~ CO:'I:SULTING ENGI:>:E£RS. INC.
Alaska Electric Light &: Power -4-• October 18, 1976
ANNEX CREEK PENSTOCK.
This penstock like the Upper Salmon Creek penstock is generally in good con-
dition. As the pipe is almost entirely exposed the exterior has suffered more
corrosion than the Upper Salmon Creek pipe. The original coating has deter-
iorated to some extent from the last survey. There is less of the coating on
the exposed sides and bottom of the pipe and consequently a little more sur-
face pitting. However, this surface pitting is quite shallow. The same condi-
tion at some of the joints as were described for the Upper Salmon Creek pen-
stock exists on this pen~tock. Condition of the supports in the supported sec-
tions is not too good.
For this penstock it is our opm10n, from. the data taken. that the penstock is
in generally good condition and should have appreciable life remaining without
excessive maintenance assuming that the penstock is operated in the proper
manner without introducing waterhammer surges. It is possible that some re-
placement of the wooden suppo:r:ts will have to be made from time to time as
required. The same comments concerning surge control as made for Upper
Salmon Creek penstock apply for this penstock. Same provision for surge
control should definitely be incorporated in tbe automation design.
\
'Vhile at the Annex Creek Powerhouse an attempt was made to determine the
condition of the high pressure cooling water line for the transformers. Be-
cause the transducer was for the large size penstocks, it was not possible
to obtain a measurement. It is not known when these lines were replaced but
s.hould this pipe rupture it could be serious as the high voltage bus i.s just
above it.
It was a pleasure talking to you while I was in Juneau, We sincerely appreciate
your making arrangements for us in Juneau and your invaluable assistance in
making arrangements for the replacen'lent ultra sonic equipment,
v t;;/J~7A(r;s:.;
B. G. Hildyar
Vice Presiden
/ab
LOWER SALMON CREEK PENSTOCK
(Flume to Powerhouse No. 1}
Left Penstock (Facing Downstream)
Station
0 + 00 Powerhouse
0 + 75
1 + 75
3 + 00
4 + 00
5 + 00
6 + 00
7 + 00
8 + 00
9 + 00
' \
Measured Thickness
(Inches)
• 095 -• 100
-110 -.. 130
• 100 -• 140
9 + 40 Circumferential Split
• 075 -<> 100
.100-.180
.215-.230
.100-.180
.125-.150
.100-.130
• 100 -• 140
11 + 82 (Bottom of Drop from Headworks)
Right Penstock
Station
0 + 00 Powerhouse
2 + 00
3 + 00
4 + 00
5 + 00
6 + 00
7 + 00
8 + 00
9 + 00
9 + 38
Measured Thickness
(Inches)
.250
e280
• 110 -. 220 (Heavy PitHng
• 115 ..:.. • 140 {Heavy Pitting
.250
• 125 -• 240 (Heavy itting
.240-.250
.250
• 235 -~250
• .• .J.-\_'1.\ES M. MO:-.:TGO::'>tERY,CO:.'IISULTI!\:G E:-.:GI:\iEERS. INC. 2255 Aven1da De La Playa, La Jolla, Car.rom•a 92037117Hl.C:5S·2931
UPPER SALMON CREEK PENSTOCK
(Dam to Powerhouse No. 2)
Station Measured Thickness
(Inches)
Valve House .235
V /S of 1st Bridge .275
D/S Tunnel Portal .345
3 + 35 Below Portal .360
0 + 00 (D/S of Bridge) .340
3 + 12 • 325
3 + 89 .325
4 + 45 (MH)
5 + 93 (Leak at Top of Stair) .330
8 + 83 (Bend D/S of Bridge) .445
11 + 28 . .450
13 + 11 (Bend -Repaired Leak)
14 + 35 (Leak -D/S end of Bridge)
14 + 80 .435
17 + 25 (D/S end of Bridge)
18 + 10 .470
21 + 85 {D/S end of Bridge) .445
23 + 91 (Bend)
25 + 76 .510
29 + 25 (Power House)
Design Thickness
(Inches)
.250
.250
.344
.344
r344
.344
.344
.344
. 406
.406
. 406
. 438
. 438
.469
' ! • :
JA.'\tES l'>L ~to:-;TGO:'>tER'\:CO::"SULTlJ:'I,;G ENGIJS'EERS, INC 2255 A•enica De La P!aya. La Jolla. Cahf:>m•a 92037/ (714) 45~·2931
ANNEX CREEK PENSTOCK •-.,"""' " ~· ..
~
Station Measured Thickness Design Thickness
(Inches) (Inches)
0 + 00 (Valve House) • 260 0.250
1 + 6 9 (Anchor) .260 0.250
4 + 70 (U /S Bridge) .255 0.250
6 + 99 (MH) .220 0.250
8 + 89 .240 0.250
10 + 88 (MH) .245 0.250
14 + 35 .245 0.250
14 + 42 (Bend -Open Vent)
15 + 72 .255 0.250
17 + 89 .250 0.250
19 + 24 .240 0.250
20 + 14 (MH)
21 + 56 (Open Vent) '
22 + 85
... .250 0.250
23 + 90 {Anchor)
26 + 72 .250 0.250
28 + 23 ·• 250 0.250
29 + 15 (Bend)
30 + 11 .240 0.250
31 + 22 (Bend)
32 + 77 .260 0.250
35 + 30 ,235 0, 250
35 + 36 (MH)
36 + 19 (AV)
38 +57 (AV at Top of Slope) .250 0.250
39 + 23 {Bottom of Slope)
40 + 34 (MH) .245 0,250
41 + 77 (D/S Supported Section) .245 0.250
44 + 67 (AV at Top of Slope
at D/S Collapse) .295 .312
45 + 93 (Bottom of Slope) .370 .375
46 + 19 (Repaired Section) .375 .375
47 +51 .365 .375
48 + 81 (Top of Ladder) .395 ~375
50+ 14 .465 • 438
..
.JAll>lES M. !'-lO~"TGO:'o':..t.;J;U:;.co;:.,;slJLTING E:-.:GI~EERS. INC. 2155 Aven;da D~ La Play&. La Jolla. Caiolomoa 92037/(71~1 459-2'931
ANNEX CREEK PENSTOCK
(Continued)
Station
·51 + 15 (MH)
51 + 43 (Top of Ladder)
52 + 10 (Bottom of Ladder)
52+ 72
55 + 22 (Anchor)
55+ 72
56+ 82 {Air Vent Top of Pipe)
59+ 98
60 + 38 (MH)
61 + 02 {Anchor)
61 + 42 (Top of Ladder)
61 + 92 •
63 + 66 {Top of Long Stair) "
65 + 19 (Top of Steep Slope)
65 + 73 (Bottom of Stair)
66 + 20
68 + 59 {Top of Stair)
70 + 31
70 + 91 (Power H~use)
Measured Thickness
(Inches)
• 435
.450
.430
.460
0 485
.480
.550
.560
.550
.635
• 625
Design Thickness
(Inches)
.438
.438
.438
.soo
.500
.500
~562
• 562
~562
• 625
0 625