HomeMy WebLinkAboutAPA1371·-_,1
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Prepared by:
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SUSITNA HYDROELECTRIC PROJECT
FERC LICENSE APPLICATION
EXHIBIT B
FIRST DRAFT
SEPTEMBER 17, 1982
'------ALASKA POWER AUTHORITY __ __.
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EXHIBIT B -STATEMENT OF PROJECT OPERATION AND RESOURCE UTILIZAiiON
List of Tables
List of Figures
1 -DAMSITE SELECTION
•)
1.1 -Previous Studies
(a) Early Studies of Hydroelectric Potential
(b) U.S. Bureau of Reclamation -1953 Study
. (c) U .. S. Bureau of Reclamation -1961 Study
(d) Alaska Power Administration -1974 Study
(e) Kaiser Proposal for Development
. (f) U .. S. Army Corps Engineers -1975 and 1979 Studies
1.2 .. Plan Formulation and Selection f~ethodology
1.3 -Damsite Selection
{a) Site Screening
(b) Engineering Layouts
(c) Capita 1 Costs
1.4 -Formulation of Susitna. Basin Development Plans
{a) Tunnel Alternatives
(b) Selected Basin Development Plans
1.5 -Evaluation of Basin Development Plans
(a) Evaluation Methodology
(b) Evaluation ~riteria
{c) Results of Evaluation Process
1.6 -Preferred Susitna Basin Development Plan
2 -ALTERNATIVE FACILITY DESIGN, PROCESSES AND OPERATIONS
2.1 -Susitna Hydroelectric Development
2.2 -Watana Project Formulation
(a) Selection of Reservoir Level
{b) Selection of Installed Capacity
(c) Selection of Spillway Design Floods
(d) Main Drun Alternatives
(e) Diversion Scheme Alternatives
(f) Spillway Facilities Alternatives
{g) Power Facilities Alternatives
2.3 -Selection of Watana General Arrangement
(a) Selection Methodology
(b) Design Data and Criteria
(c) Evaluation Criteria
(d) Preliminary Review
(e) Intermediate Review
(f) Final Review
2.4 -Devil Canyon Project Formulation
(a) Selection of Reservoir Level
(b) Selection of Installed Capacity
(c) Selection of Spillway Capacity
(d) Main Dam Alternatives
(e) Diversion Scheme Alternatives
(f) Spillway Alternatives
(g) Power Facilities Alternatives
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Table of Contents (Continued)
2.5 -Selection of Devil Canyon General Arrangements
(a) Selection Methodology
(b) Design Data Criteria
(c) Preliminary Review
(d) Final Review
2.6 -Selection of Access Road Corridor
2.7 -Selection of Transmission Line Corridor
2.8 -Selection of Project Operation
3 ... DESCRIPTION OF PROJECT OPERATION
3.1 -Operation within Railbelt Power System
3.2 -Plant and System Operation Requirements
3.3 -General Power Plant and System Railbelt Cr-iteria
(.a) Installed Generat·ing Capacity
(b) Transmission System· Capability
(c) Sunmary
3.4 -Economic Operation of Units
(a) f4erit-Order Schedule
(b) Optimum Load Dispatching
{c) Operating Limits of Units
(d) Optimum Maintenance Program
3.5-Unit Operation Reliability Criteria
(a) Power System Analyses
(b) System Response and Load-Frequency Control
(c) Protective Relaying System and Devices
3.6 -Dispatch Control Centers
4 -ENERGY PRODUCTION AND SUPPORTING DATA
4.1 -Hydrology
(a) Historical Streamflow Data
(b) Water Resources
(c) St reamf1 ow Extension
(d) Critica.l Streamflow Used for Dependable Capacity (e) Floods · ·
(f) Flow Adjustments
4.2 -Reservoir Data
(a) Reservoir Storage
(b) Rule Curves
4.3-Operating Capabilities of Susitna Units
(a) Watana
(b) Devil Canyon
4.4 -Tailwater Rating Curve
5 -STATEMENT OF POWER NEEDS AND UTILIZATION
5.1 -Railbelt Load Forecasts
(a) Scope of Studies
(b) Electricity Demand Profiles
(c) Battelle Load Forecasts
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Table of Contents (Continued)
5.2 -Marketing and Price for Watana Output in 1994
(a) Contractual Preconditions for Susitna Energy
Sale
(b) M~rket Price for Watana Output 1995-2001
(c) Market Price for Watana and Devil Canyon Output
in 2003
(d) Potential Impact of State Appropriations
{e) Conclusions
5.3 -Sale of Power
6 -FUTURE SUS ITNA BASIN DEVELOPMENT
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·.. . \,. ·, ..... . \ . ' .
Exhibit B -Statement of Project Operation and Resource Utilization
LIST OF FIGURES
Number
8.1
8.2
B. 3"
B.4
8.5
6.6
8.7
B.8
8.9
B.lO
B.ll
8.12
8,.13
8.14
8.15
8.16
8.17
8.18
8.19
8.20
8 .. 21
B.22
B.23
8.24
8.25
8.26
B.27
B.28
B.29
8.30
8.31
B.32
8.33
B.34
8.35
8.36
8.37
8.38
T i t 1 e f..~.9.~.
Location Map ····························~·············""'•
Damsites Proposed by Others o••···~····················
Susitna Basin Plan Formulation and Selection Process ••
Profi 1 e Through A1 tern at i.ve Sites •••••••••••••••••••••
Mutua·ny Exclusive Development Alternatives •••••••••••
Dev i 1 Canyon Hydl"O Development F111 Dam •••••••••••••••
Watana Hydro Development Fill Dam ....... ~·············
Watana Staged Fi 11 Dam ................................ ., •
High Devil Canyon Hydro Development •••••••••••••••••••
Susitna III Hydro Development ····~·········••o•·······
Vee Hydro Development .................... ~ ........... eo •••••
Den a 1 i and t'l:ac 1 aren h\yd ro Dev e 1 oprnent s ••••••••• o ••••••
Schematic Representat·ion of Conceptual Tunnel Schenes •
Preferred Tunnel Scheme 3 Plan Views • ~ .................. .
Preferred Tunnel Scheme 3 Sections .................... .
Generation Scenario with Susitna Plan El.3 ••••••••••••
Generation Scenario with Susi.tna Plan E2.3 ............ .
Generation Scenario with Susitna Plan E3.1 •• ., .......... .
Watana Re.servoir -Dam Crest Elevation/Present Worth
of Product Costs •••••••••••••••••••• ~~~··~··········
Watana -Arch Dam Alternatives .......................... .
Watana -Alternative Dam Axes •••• s .................... .
Watana Diversion -Headwater Elevation/Tunnel Diameter.
Watana Diversion -Upstream Cofferdam Costs ........... .
Watana Diversion ... Tunnel and Cofferdam Cost/Tunnel
Di ameter .. e •••••••• $ ••••• 9 .............. .,. •••••••••• , ••
Watana Diversion ... Total Cost/Tunnel Diameter .••.••.•.
Watana -Preliminary Schemes ••••••••••••••••• H •••••••
Watana -Scheme WPl -Plan ••••••••••••••••••••••••••••
Watana-Scheme WP3-Sections •••••••••••••• oo••······
Watana -Scheme WP2 and WP 3 . eo •• .; •••••• H ••• H •••••• \)
Watana-Scheme WP2-Sections ........................ .
Watana -Scheme WP4 -Plan ............................. .
Watana-Scheme WP4-Sections ••••••••••••••••••••••••
Watana -Schene WP3A •••••••••• ,, ....................... .
Watana -Scheme WP4A ..................... o ••••••••••••••
Devil Canyon Diversion -Headwater Elevation Tunnel
Di arneter ................ ~ •••.•••.•.•...•••.. 41 •••••••••••
Devil Canyon Diversion -Total Cost Tunnel Diameter •••
Devi 1 Canyon -Scheme DCl o ............................... .
Devil Canyon -Scheme DC2 ·····~·······················
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LIST OF FIGURES
Number
8.39
8.40
8.41
8 .. 42
B.43
8.44
Title
Devi 1 Canyon -Scheme DC3 ............................. .
Dev i 1 Canyon -Scheme DC4 •.•••..•..••..••••..•..•.•.••
Dev i 1 Canyon -Se 1 ected Scheme ........................ .,.
Typical Load Variation in Alaska Rail belt System .•••..
Data Collection Stations ••. , ........................... .
Avet'"age Annual Flow Distribution Within t;1e Susitna
B.45 Monthly Average Flows in the Susitna River at Gold Creek
8.46 Flow Duration Curve Mean Monthly Inflow at Watana
River Basin ••••••••••••a••••··~ ...................... .
Pre-Project ....................... ., .•••• , ............ .
8.47 Flow Dur·ation Curve Mean ~1onthly Inflow at· Devil
Canyon Pre-Project ..................................... .
8.,48 Frequency Analysis of Average Annual Energy for
Sus itna Deve 1 opm.ents •••••••••...•••..•......••.••••.
8.49 Hydrological Data.-Sheet 2 ················••e••••••e•
8.50 Hydrological Data -Sheet 2 •••••.•••••.•.•.•••••••••••
B.51 Hydrological Data-Sheet 1 ............................ .
8.52 Hydrological Data-Sheet 1 ···················~···u~··
B.53 Monthly Target Minimum Reservoir Levels ................ .
8.54 Watana-Unit Output •..••..•••...••...•••••••..••.•••.
8.55 Watana-Turbine Performance (at Rated Head) ••.•••••..
8.56 Watana-Unit Efficiency (at Rated Head) ••••....••.•••
8.57 Oevi 1 Canyon ... Unit Output ................................ .
8.58 Devi 1 Canyon -Turbine Performance (at Rated Head) • ~ ••
8 .. 59 Devil Canyon -Unit Efficiency (at Rated Head) ........ .
B.60 Railbelt Area of Alaska Showing Electrical Load Centers
B .. 61 Historical Total Railbelt Utility Sales to Final
Customers ................ o •••••• ~ •••••••••• o ........ .. 8.62
8.63
8.64
B.65
8.66
8.67
ISER 1980 Energy Forecasts Used for Development
Selection Studies ······~····························
Electric Power Forecasting Process ••••••••••••••••••••
December 1981 Batte 11 e Load and Energy Forecasts
Used for Generation Planning Studies •••••••.••••••••
Energy Pricing Comparisons-1994 s••·a···············~
System Costs Avoided by Developing Susitna •••••••••••.
Energy Cost Comparison -100% Debt Financing and 7%
Inflation ••••••••••••••••••.•••.•••••••.•••..•..•••••
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I Exhibit B -Statement of Project Operation and Resource Utilization
I' . LIST OF TABLES
Number Title Page I
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B.l Potential Hydroelectric Development ······~············
8.2 Cost Comparisons •.•.•• ~ ............... , ..... e •••••• .-••••
B.3 Dam Crest and Full Supply Levels ·················~····
BQ4 Capital Cost Est·imate Summaries -Susitna Basin Dam
Schemes -Cost in $ Mi 11 ion 1980 , •••• e ............ · •••
8.5 Results of Screening Model ........................... .
8.6 Information on the Devil Canyon Dam and Tunnel Schemes.
8.7 Tunnel Schemes Power Output and Average Annual Energy •
8.8 Capital Cost Estimate Sunmaries for Scheme 3 Tunnel
Alternative Costs in$ Million 1980 ................. ..
8.9 Susitna Development Plans ············~···· .. ••••••••••·
B.lO Susitna Environmental Development Plans ............... ;
B.ll Results of Economic Analyses of Susitna Plans .. ao .. o ...
8.12 Results of Economic Analyses of Susitna Plans -
Low and High Load Forecast ·········~~··••a•••••••••a
B .13 Economic Parameters ~ ............................ ~ ••••.••
8.14 Economic Backup Data for Evaluation of Plans .......... .
6.15 Economic Evaluation of Devil Canyon Dam and
Tunnel Schemes and Watana/Devi 1 Canyon and
High Devil Canyon/Vee Plans ••.••.• .-................. .
8.16 Environmental Evaluation of Devil Canyon Darn and
Tunne 1 Schenes ..................... o ...................... .
8.17 Social Evaluation of Susitna Basin Development
Schemes/Plans ••••••••••.••••••••••••••• ~ •.•••••.••••
8.18 Energy Contribution Evaluation of the Devil Canyon
Dam and Tu nne 1 Sc hanes ................................. .
8 .. 19 Overall Evaluation of Tunnel Scheme and Devil Canyon
Dam Schane •••••••• " .................................. .
8.20 Environmental Evaluation of Watana/Devil Canyon and
High Devil Canyon/Vee Development Plans •••••.•••••••
8.21 Energy Contribution Evaluation of the Watana/Devil ·
Canyon and High Devil Canyon/Vee Plans ••••••••••••••
B.22 Overall Evaluation of the High Devil Canyon/Vee and
Watana/Dev i 1 Canyon Dam Plans ••••• ~'\ ••.•.•••••• o ••••
8.23 Combined Watana and Devil Canyon Operation .••••••.••••
8.24 Present Worth of Production Costs ..................... ..
8.25 Design Data and Design Criteria for Final Review
of Layouts .............................................. .
8.26 Evaluation Criteria ••••s•····························· 8.27 Summary of Comparative Cost Estimates ••.•••.•••••.••••
8.28 Design Data and Design Criteria for Review of
A 1 tern at ive Layouts .................................. .
8.29 Sumnary of Comparative Cost Estimates •••••••••••••••••
8.30 Energy Potential of Watana -Devil Canyon Developm·ents
for Different Reservoir Operating Rules ···~····4·•··
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I LIST OF TABLES (Continued)
Number Title Page .I
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8 .. 31 Average Annual and Monthly Flow at Gage in the
' "t B . ~us1 na as1n •••••••••••••••.••..••.•••• ,w ••••••••••
B .. 32 L4atana Estimated Natura 1 Flows •. "" .•.•.••• ~ ........... .
B.33 Devil Canyon Estimated Natural Flows ••.•••••..•.•.•.••
8 .. 34 Peak Flows of Record ···········~···········~··········
8.35 Estimated Flow Peaks in Susftna River •.••••• s. •••••••
8.36 Estimated Evaporation Losses .., WatarH~ and Devil
Canyon Reservoirs ..................................... .
8.37 Monthly Flow Requirements ••.••••••.. H ......... ~ •••••••
8.38 Minimum Releases at Watana ............................ .
8. 39 Minimum Re 1 eases at Dev i 1 Canyon H .................... ..
8.40 Water Appropriations Within One Mile of the
Susitna River ........................... ~········-c·····
8.41 Turbine Operating Conditions ............................ .
8.42 ~istorical Annual Growth Rates of Electric Utility
Sa 1 es ......... o e ...................................... .
Bo43 Armual Growth Rates in Utility Customers and
Consumption Per Customer •.....•...••••.•.•••••..•••.
8.44 Utility Sales by Railbelt Reg1ons ..••••••••••..••.••••
8.45 Summary of Railbelt Electricity Projections .••••..•••.
8.46 Forecast Total Generation and Peak Loads -Total
Railbelt Region ····························~········ 8.47 ISER 1980 Railbelt Region load and Energy Forecasts
Used for Generation Planning Studies for
Development Selection ................................ .
8.48 December 1981 Battelle PNL Railbelt Region Load and
Energy Forecasts Used for Generation Planning Studies
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EXHIBIT B -PROJECT OPERATION AND RESOURCE UTILIZATION
1 -DAMSITE SELECTION
This section summarizes th•a previous site selection studies and the
studies done during the Al asl<a Power Authority Susitna Hydroelectric
Project Feasibility Study. Additional detail, on this topic can be
found in the DeveloJlTient Selection Report, Refe.r·ence 1,
1.1-Previous Studies
Prior to the undertaking of the Susitna Hydroelectric Project Feasi-
bility Study by the applicant, the hydroe'tectt"ic develollTJent potential
of the Alaskan Railbelt had been studied by severa.l entities.
(a) Ear,ly Studies of Hydroelectric Pote:1tial ------.
Shortly after World War II ended, the United States Bureau of
Reclanation (USSR) conducted an initial investigation of hydro-
electric potential in Alaska and issued a report of the results in
1948. Responding to a. recommendation made in 1949 by the nine-
teenth Alaska territorial legislature that Alaska. be included in
the Bureau of Reel amation program, the Secretary of Interior pro-
vided funds to update the 1948 t,rtork. The resulting report, issued
in 1952, recognized the vast hydroelectric potential within the
territory and placed particular emphasis on the strategic location
of· the Susitna River between Anchorage and Fairbanks as well as
its proximity to the connecting Railbelt (see Figure 8.1).
A series of studies was commissioned over the years to identify
damsites and conduct geotechnical investigations. By 1961, the
Department of the Interior proposed authorization of a two-dan
power system an the Susitna River involving the Devil Canyon and
the Denali sites (Figure 8.2). The definitive 1961 report was
subsequently updated by the Alaska Power Administration (an agency
of the USBR) in 1974, at vklich time the desirability of proceeding
with hydroelectric development was reaffirmed.
The Corps of Engineers (COE) was also active in hydropower invest-
igations in Al etska during the 1950s and 1960s, but focused its
attention on a more anbitious development at Rampart on the Yukon
River. This pr•oject was capable of generating five times as much
annual electric energy as the prior Susitna proposal. The sheer
s i ze and the tee hno 1 og i cal cha 11 eng es as soc i a ted with Rampart cap~
tured the imagination ·of supporters and effectively diverted
attention fr·om the Susitna Basin for more than a decade. The
Rampart report was finally shelved in the ea~ly 1970s because of
strong environmental concerns and the uncertainty of marketing
prospects for so much energy, particularly in 1 ight of abundant
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(b)
. natural gas which had been discovered a:1d developed in Cook
In 1 et.
The energy cr1s1s precipitated by the OPEC oi.l boycott in 1973
provided some further impetus for seeking dev e 1 opment of renewab 1 e
resources. Federal funding was made available both to. complete
the Alaska Power Administration• s update report on Susitna in 1974
and to 1 aunch a prefeasibil ity investigation by the COE. The
State of Alaska itself commissioned a reassessment of the Susitna
Project by the Henry J. Kaiser Company in 1974.
Although the gestation period for a possible Susitna Project has
been lengthy, federal, state, .and private organizations have been
virtually unanimous over the years in recommending that the proj-ect proceed.
Salient features of the various reports to date are outlined in
the following sections ..
U.S. Bureau of Reel amation -1953 Study
The USBR 1952 report to the Congress on Alaska's overall hydro-
electric potential was fo11owed shortly by the first major study
of. the Susitna Basin in 1953. Ten damsites were identified above
the railroad crossing at Gold Creek. These sites are identified
on Figure B. 2.
-Go 1 d Creek ;
-01 son;
-Dev i 1 Canyon;
-Devil Creek;
-Watana;
-Vee;
-Maclaren;
-Denali;
-Butte Creek; and
-Tyone (on the Tyone River).
Fifteen more sites \fjere considered below Gold Creek. However,
more attention has been focused over the years on the Upp.(· ,~
Susitna Basin where· the topography is better suited to dam catt-
struction and where less impact on anadromous fisheries is ex-
pected. Field reconnaissance eliminated half the original Upper
Basin list, and further USBR consideration centered on Olson,
Devil Canyon, Watana, Vee, and Denali. All of the USBR studies
since 1953 have regarded these sites as the most appr·opriate for
further investigation.
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(c) U.S. Bureau of Reclamation = 1961 Study
In 1961 a more detailed feasibility study resulted in a recom-
mended five-stage development plan to match the load growth curve
as it was then projected. Devil Canyon was to be the first
develoJlllent--a 635-foot-high arch dcm with an installed capacity
of about 220 MW. The reservoir formed, by the Devil Canyon dam
a 1 one waul d not store enough water to permit higher capacities .to
be economically installed, since long periods of relatively low
f1 ow occur in the winter mor1ths. The second stage would have
increased storage capacity by adding an earthfi 11 dan at Denali in
the upper reaches of the basin. Subsequent stages involved adding
generating capacity to the Devil Canyon dam. Geotechn ica1 invest-
igations at Devil Canyon were more thorough than at Denali. At
Denali, test pits were dug, but no drilling' occurred.
(d) Alaska Power Administration -1974
Little change from the basic USBR-1961, five-stage concept
appeared in the 1974 report by the Alaska Power Administration.
This 1 ater effort offered a more sophisticated design, provided
new cost and schedule estimates, and addressed marketing, eco-
nomics, and environmental considerations.
(e) Kaiser Proposal for Development
The Kaiser study, commissioned by the Office of the Governor in
1974, proposed that the initial Susitna development consist of a
single dcm known as High Devil Canyon located on Figure B. 2. No
field investigations were made to confirm the technical feasibil-
ity of the High Devil Canyon location because the funding level
was insufficient for such efforts. Visual obs~rvations suggested
the site was probably favorable. The USBR had always been uneasy
about foundation conditions at Denali, but had to rely upon the
Denali reservoir to provide storage during long periods of low
flow. Kaiser chose to avoid the perceived uncertainty at Denali
by proposing to build a rockfill dan at High Devil Canyon which,
at a height of 810 feet, waul d create a 1 arge enough reservoir to
overcome the storage prob 1 em. -Although the selected sites were
different, the COE reached a similar conclusion when it 1 ater
chose the high dam at Watana as the first to be constructed.
Subsequent devel opnents suggested by Kaiser included a downstream
dan at the 01 son site and an upstream dam at a site known as
Susitna III {see Figure 8.2). The infonnation developed for these
additional dans was confined to estimating energy potential. As
in the CO~ study, future development of Denali remained a possi-
bility if foundation conditions were found to be adequate and if
the value of additional firm energy provided economic justifica-
tion at some 1 ater date.
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(f) U.S. Army CorEs of Engineers -1975 and 1979 Studies
The most comprehensive study of the Upper Susitna Basin prior to
the current study was completed in 1975 by the COE. A total of 23
alternative developnents were analyzed, including those proposed
by the USSR, as well as consideration of coal as the primary
energy source for Ra i1 belt electrical needs. The COE agreed that
an arch dam at Devil Canyon was appropriate, but found that a high
dam at the Watana site would form a 1 arge enough reservoir for
seasonal storage and would permit cant inued generation during low flow. periods.
The CPE recommended an earthfi 11 dcm · at Watana with a height of
810 feet. In the longer term, development of the Denali site re-
mained a possibi1 ity which, if constructed, would increase the
amount of firm energy av ai 1 ab 1 e in dry years.
An ad :hoc task force was created by Governor Jay Hammond upon com-
pletion of the 1975 COE Study. This task force recommended en-
dorsement of the COE request for Congressional authorization, but
pointed out that extensive further studies, particularly those
dedling with environmental and socioeconomic questions, were
necessary before any construction decision could be made.
At the federal level, concern was expressed at the Office of Man-
agement and Budget regarding the adequacy of geotechnical data at
the Watana site as well as the validity of the economics. The
apparent ambitiousness of the schedule and the feasibility of a
thin arch dam at Devil Canyon were also questioned. Further in-
vestigations were funded and the COE produced an updated report in
1979. Devil Canyon and Watana were reaffirmed as appropriate
sites, but alternative dam types were investigated. A concrete
gravity dan was analyzed as art alternative for the thin arch dam
at Dev.il Canyon and the Watana dam was changed from earthfill to
rockfil1. Subsequent cost and schedule estimates still indicated
economic justification for' the project •
1. 2 -Plan Formul ~tion and Selection Methodolo9_l
The proposed plan which is the subject of this 1 icense application was
selected after a review and reassessment of all pl .. eviously considered
sites. Additional detail in support of the findings in this Exhibit is found in Reference 5.
Thi.s section of the report outlines· the engineering and planning
studies carried out as a basis for fonnul at ion of Susitna Basin devel-
opnent plans and selection of the preferred plan.
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In the description of the planning process, certain plan componen~s and,
processes are frequently discussed. It is appropriate that three par-
ticular terms be clearly defined:
Damsite -An individual potential dansite in the Susitna
Basin, referred to in the generic process as
11 candid ate. 11
Basin Development -A plan for developing energy within the Upper
Plan Susitna Basin involving one or more dCills, each of
specified height, and corresponding power p1 ants
of specified capacity. Each plan is identified by
a plan nunber and subnunber indicating the staging
sequence to be fa 11 owed in developing the full
potential of the plan over a period of time.
Generation - A specified sequence of implementation of power
Scenario generation sources capable of providing sufficient
power and energy to satisfy an electric load
growth forecast for the 1980-2010 period in the
Railbelt area. This sequence may include dif-
ferent types of generation sources such as hydro-
electric and coal~ gas or oil-fired thermal. c
These generation scenarios were developed for the
comparative evaluations of Susitna Basin genera-
tion versus alternative methods of generation.
In applying the generic plan fonnul at ion and selection methodology,
five basic steps are required; defining the objectives, selecting can-
didates, screening, formulation of development plans, and, finally,, a
detailed evaluation of the plans (see Figure 8.3). The objective is to
determine the optimum Sus itna Basin development plan. The various
steps required are outlined in subsections of ~his section.
Throughout the planning process, engineering 1 ayout studies were marie
to refine the cost estimates for power generation 'facilities or water
storage develoJlllent at several damsites within the basin. These data
were fed into the screening and plan formulation and , evaluation
studies.
The second objective, the detailed evaluation of the variou':t plans~ is
satisfied tJ} comparing generation scenarios that inc1 ude 'the selected
Susitna BasH1 develor.ment plan with alternative generat~on scenarios,
including a11-thermal 6 .and a mix of thermal plus alternr:'l:ive hydropower
devel opnents.
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1.3 -Darnsite Selection
In previous Susitna Ba~irt studies, twelve damsites were identified in
the upper portion of the basin, i.e., upstream from Gold Creek. These si~es are list~d in Table 8.1 with relevant data concerning facilitGfes,
cost capacity, and energy.
The longitudinal profile of the Susitna River and typical reservoir
1 eve 1 s associated with these sites are sho.wn in Figure 8.4. Figure B .5
illustrates which sites are mutually exclusive, i.e .. , those which can-
not be developed jointly, since the downstream site would inundate the
upstream site.
All re1evant data concerning dam type, capital cost, power, and energy
output were assembled and are summarized in Table B.l. For the Devil
Canyon, High Devil Canyon, Watana, Susitna III, Vee, Maclaren, and
Denali sites., conceptual engineering layouts were produced and capital
costs were estimated based on calculated quantities and unit rates.
Detailed analyses were a 1 so undertaken to assess the power capability
and energy yields. At the Gold Creek, Devi 1 Creek, Maclaren, Butte
Creek, and Tyone sites, no detailed engineering or energy studies were
undertaken; data from pr·evious studies were used with capital cost
estimates updated in 1980 levels. Approximate estimates of the poten-
tial average energy yield at the Butte Creek and Tyone sites were
undertaken to assess the re 1 at i ve i mportt.tnce of these sites as energy prqducers.
The data presented in Table B.l show that Devil Canyon, High Devil C~n
yon, and Watana are the most economic 1 arge energy producers in the
basin. Sites such as Vee and Susitna III have only medium energy pro-
duction, and slightly more costly that the preyiously mentioned dam-
sites.. Other sites such as Olson and Gold Creek are competitive pro-
vided they have additional upstream regulation. Sites such as Denali
and Maclaren produce substantially higher cost energy than the other
sites but can also be used to increase regulation of flow for down-
stream use.
(a) Site Screeni n_g,
The objective of this screening process was to eliminate sites
which would obviously not feature in the initial stages of the
Susitna Basin development plan and which, therefore, did not de-
serve further study at this stage. Three basic screening criteria
were used: environmental, alternative sites, and energy contribu-
tion. .
The screening process involved eliminating all sites falling in
the unacceptable environmental impact and alternative site cate--
gories. Those failing to meet the energy contribution criteria
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were also e.liminated unless they had some potential for upstream
regulation. The results of this process, described in detail in
Reference 5, are as follows:
-The 11 unacceptable site11 environmental category eliminated the
Gold Creek, Olson, and Tyone sites.
-The alternative sites category eliminated the Devil Creek and
Butte Creek sites ..
-No additional sites wer~e eli.minated for failing to meet the
energy contribution criteria. The remaining sites upstream from
Vee, i.e., Maclaren and Denali, were retained to insure that
further study be directed toward determining the need and viabi-
lity of providing flow regulation in the headwaters of the
Susitna ..
(b) Engineering Layouts
In order to obtain a uniform and reliable data base for studying
the seven sites remaining, it is necessary to develop engineering
1 ayouts and reevaluate the costs. In addition, staged develop-
ments at several of the 1 arger dams were studied.
The basic objective of these 1 ayout studies was to estab 1 ish a
uniform and consistent development cost for each site. These lay-
outs are consequently conceptual in nature and do not necessarily
represent optimum project arrangements at the sites. Also, be-
cause of the lack of geotechnical information at several of the
sites, judgmental decisions had to made on the appropriate founda-
tion and abutment treatment. The accuracy of cost estimates made
in these studies is of the order of plus or minus 30 percent.
(i) Design Assumptions
In order to maximize standardization of the layouts, a set
of basic design assumptions was developede These assump-
tions covered geotechni ca 1, hydrologic, hydraulic) civi 1~
mechanical, and electrical considerations and were used as
guidelines to determine the type and si.ze of the various
components within the overall project layouts.. As stated
previously, other than at Watana, Devil Canyon., and Denali,
little information regarding site conditions was available,.
Broad assumptions were made on the basis of the limited
data, and those assumptions and the interpretation of data
have been conservative •
It w.as assumed that the re 1 ati ve cost differences between
rockfi 11 and concrete dams at the site would either be
margi na 1 or greatly in favor of the rockfi 11. The more
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detailed studies carried out subsequently for the Watana and
Devi 1 Canyon sites support this assumption. Therefore, a
rockfi 11 dam has been assumed at a 11 developments in order
to eliminate cost discrepancies that might result from a
consideration of dam-fi 11 unit costs compar~d to concrete
unit costs at alternative sites.
(ii) General Arrangements
A brief description of the general arrangements developed
for the various sites ls given below. Descriptions of
Watana and Devil Canyon in this section are of the prelim-
1 nary 1 ayouts and should not be confused with the proposed
layouts in Exhibit A and Exhibit F. Figures 8.6 to 8 .. 12
illustrate the layout details. Table 8.2 summarizes the
crest levels and dam heights considered.
In laying out the developments, conservative arrangements
have been adopted, and whenever possible there has been a
general standardization of the component structures ..
-Devil Canyon (Figure 8.6)
The development at Devil Canyon, located at the upper end
of the canyon at its narrowest point, consists of a rock-
fill dam, single spillway, power facilities incorporating
an underground powerhouse, and a tunnel dive~sion.
The rockfill dam would rise above the valley on the left
abutment and terminate in an adjoining saddle dam of simi-
1 ar construct; on. The dam would be 675 feet above the
lowes.t foundation level with a crest elevation of 1470 and
a volume of 20·million cubic yards. ·
The spillway would be located on the right bank and would
consist of a gated overflow structure and a concrete-lined
chute 1 inking the overflow structure \'lith intermediate and
terminal stilling basins. Sufficient spillway capacity
would be provided to pass the Probable Maximum Flood
safetly.
The power facilities would be located on the right abut-
ment. The massive intake structure would be founded with-·
in the rock at the end of a deep approach channe 1 and
would consist of four integrated units, each ~erving
individual tunnel penstocks.. The powerhouse would house
four 150-MW vertically mounted Francis tj1)e turbines driv-
ing overhead 165 MVA umbrella type generator-s.
As an alternative to the full power development in the
first phase of construction, a staged powerhouse
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alternative was also investigated. The dam would be com-
pleted ·to its full height but w1th a initial plant
1 nstal1 ed capacity in 300-MW range. The comp 1 ete power-
house would· be constucted together with penstocks and a
tailrace tunnel for the initia1 two 150-MW units, together
111ith concrete foundations for the future units.
-Watana (Figure B.7 and 8.8)
For initial comparative stt:~y purposes,the dam at Watana
is assumed to be a rockfi ! 1 structure 1 ocated on a simi 1 ar
alignment to that proposed in the previous COE studies.
It would be simi 1 ar in construction to the dam at De vi 1
Canyon with an impervious core founded on sound bedrock
and an outer shell composed of blasted rock excavated from
a single quarry located on the left abutment. The dam
would rise 880 feet from the lowest point on the founda-
t'ion and have an overall volume of approximately 63
million cubic yards for a crest elevation of'2225 •.
The spillway would be located on the right bank and would
be similar. in concept to that at Devil Canyon with an
intermediate and terminal stilling basin.
The power facilities located within the left abutment with
similar 1 ntake, underground powerhouse, and water passage
concepts to those at Dev·ll Canyon would incorporate four
200-MW turbine/generator units giving a total output of
800-MW.
As an alternative to the initial full development at
Watana, staging alternatives were investigated. These
inc 1 uded staging of both dam and powerhouse construction ..
Staging of the powerhouse would be stmilar to that at
Devi_l Canyon, with a Stage I installation of 400-MW and a
further ~00-MW in Stage II.
In order to study the alternative dam staging concept it
was assumed that the dam would be constructed for a maxi-
mum operating water surface elevation some 200 feet lower
than that in the final stage (see Figure 8 .. 8).
The powerhouse would be completely excavated to its final
size during the first stage. Three oversized 135-MW units
would be installed together with base concrete for an
additional· unito A low level control structure and twin
concrete-lined tunnels leading into a downstream sti 11ing
basin would form the first stage spillway.
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For the second stage, the dam would be camp leted to its
full height, the impervious core would be appropriately
raised, and additional rockfill would be placed on the
downstream face. It was assumed that before construction
commences the top 400 feet of the first stage dam would be
removed to ensure the complete integrity of the impervious
core for the raised dam.. A second spillway control struc-
ture would be constructed at a higher level and would in-
corporate a downstream chute leading to the Stage I spi 11-
way structure. TI1e original spillway tunnels would be
c 1 osed with concrete p 1 ugs. A new intake. structure wou 1 d
be constructed utilizing existing gates and hoists, and
new penstocks would be driven to connect with the existing
ones. The existing intake would be sealed off. One addi-
tional 200 MW unit would be installed and the required
additional penstock and tailrace tunnel constructed. The
existing 135-MW .units would be u·pgraded to 200 MW.
-High Devil Canyon (Figure 8.9}
The development would be located between Devil Canyon and
Watana. The 855 feet high rockfill dam would be similar
in design to Devil Canyon, containing an estimated 48
million cubic yards of rockfi11 with a crest elevation of
1775. The 1 eft bank spillway and the right bank power-
house facilities would also be similar in concept to Devil
Canyon, with an installed capacity of 800-MW.
Two stages of 400-MW were envisaged in each which would be
undertaken in the same manner as at Devil Canyon, with the
dam initially constructed to its full height.
-Susitna III (Figure 8.10)
The development would involve a rockfill dam with an
impervious core approximately 670 feet high, a crest ele-
vatlon of 2360, and a volume of approximately 55 milli.on
cubic yards. A concrete-lined spillway chute and a single
stilling basin and would be located underground and the
two diversion tunnels on the left bank.
-Vee (Figure 8 .. 11}
A 610-feet high rockfill dam founded on bedrock with a
crest elevation of 2350 and total volume fo 10 million
cubic yards was considered.
Since Vee is located further upstream than the other major
sites the flood flows are correspondingly lower, thus
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allowing for a reduction in size of the spillway f~cili
t1es. A spillway utilizing a gated overflow structure,
chute, and flip bucket was adoptede
The power facilities would consist of a 400-MW undergrou~d
powerhouse located in the left bank with a tailrace out'let
we 11 downstream of the main dam. A secondary rockfi 11 dam
would also be required tn this vicinity to seal off a low
point. Two diversion tunnels would be provided on the
right bank.
-Macl aren ( Fi gure B .12)
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The development would consist of a 185 feet high earthfill
dam founded on per·vious riverbed materials. The crest
elevation of the dam would be 2405. This reservoir would
essentially be used for reglating purposes. Diversion
would occur through three conduits located in a open cut
on the left bank and floods would be discharged via a side
chute spi 11way and stilling basin on the right bank.
Denali (Figure 8.12)
Denali is simi-lar in concept to Maclaren. The dam would
be 230 feet high,· of earthf111 construction, and wotild
have a crest e 1 ev at ion of 2555. As for Mac1 aren, no
generating capacity would be included. A combined diver-
sion and spillway facility would be provideti by twin con-
cret~ conduits founded in open cut excavation in the right
bank and discharging into a common stilling basin.
( c) Cap i t a 1 Costs
For purposes of initial comparisons of alternatives, construction
quantities were determined for items comprising the major· works
and structures at the site. Where detail or data were not suffi-
cient for c,ertain work~ quantity estimates were made on the bas1s
of previous Acres• experience and the general knowledge of site
conditions reported in the 1 i terature. In order to determine
total capital costs for various structures, unl,t costs have been
developed for the items measured. These have been estimated on
the basis of review of rates used in previous studies, and of
rates used on similar works in Alaska and elsewhere. Where appli-
cable, adjustment factors based on geography, climate~ manpower
and accessibility were usede Technical publications have also
been reviewed for basic rates and escalation factors.
The total capital costs developed are shown in Table B.l and 8.2~
It should be noted that the capital costs for Maclaren and Denali
shown in Table 8.1 have been adjusted to incorporate the costs of
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generation plants with capacitie~ of 55-MW and 60-MW, respec-
tively. Additional data on the projects are summarized in Table
8.3.
1~4 -Formulation of Susitna Basin Development Plans
The results of the site screening process described above indicate that
the Susitna Basin development plan should incorporate a combination of
sever a 1 major dams and powerhouses 1 ocated at one or more of the fo 1-
1 owing sites:
-Devil Canyon;
... Hi gh De vi 1 Canyon;
·· Watana; ·
-Susitna III; or
-Vee. o
Supplementary upstream flow regulation could be provided by structures
at:
-Maclaren; and
-Denali.
·Cost estimates of these projects are itemized on Table 8.4.
A computer assisted screening process identified the plans that are
most economic as those of Oevi 1 Canyon/Watana or High Devi 1 Canyon/Vee ..
In addition to these two basic development plans, a tunnel scheme wh·ich
provides potential environmental advantages by replacing the Devil Can-
yon dam with a long power tunnel and a development plan involvi.ng
Watana Dam was also introduced.
The criteria used at this stage of the process for selection of pre-
ferred Susitna Basin development plans are mainly economic (see Figure
B.3). Environmental considerations are incorporated into the further
assessment of the p 1 ans fin a 11y se lee ted.
The results of the screening process are shown in Table B.S.. Because
of the simp 1 i fyi ng assumptions that \'/ere made in the screening model~
the three best solutions from an economic point of view are included 'in
the table.
The most important conclusions that can be drawn are as follows:.
-For energy requi rernents of up to 1,150 Gwh, the High Oevi 1 Canyon,
Devil Canyon or the Watana sites individually provided the most eco-
nomic energy. The difference between the costs shown on Table B.4 is
around 10 percent, which is simi 1 ar to the accuracy that can be
expected --::rom the screening mode 1.
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-For energy requirements of between 1, 750 and 3,500 Gwh, the High
Devil Canyon site is the most economic.
-For energy requirements of between 3,500 and 5,250 Gwh the combina-
tions of either Watana and De vi 1 Canyon or High De vi 1 Canyon and Vee
are most economic.
-The total energy production capability of the Watana/Devi 1 Canyon
developments is :considerably larger than that of the High Devil Can-
yon/Vee alternative and is the only plan capable of meeting energy
demands i~ the 6,000 Gwh range •
(a) Tunnel A lternati,re
A scheme involving a long power tunnel could conceivably be used
to rep 1 ace the Devil Canyon dam is· the Watana/Devi 1 Canyon
development plan. It cou 1 d deve1 op similar head for power genera-
tion and may provide some environmental advantages by avoiding
inundation of Devil Canyon. Obviously, because of the low winter
flows in the river, a tunnel alternative could be considered only
as a second stage to the Watana development.
Conceptually, the tunnel alternatives would comprise the following
major components in some combination, in addition to the Watana
dam reservoir and associated powerhouse:
-Power tunnel intake works;
-One· or two pov1er tunne 1 s of up to forty feet in diameter and up
to thirty miles in length;
- A surface or underground powerhouse with a capacity of up to
1200 MW;
A re-regul at ion dam if the intake works are located downstream
from Watana; and
-Arrangements for compensation flow in the bypassed river reach.
Four basic alternative schemes were developed and studied. Figure
B.l3 is a schematic illustration of these schemes. All schemes
assumed an initial Watana development with full reservoir supply
level at Elevation 2200 and the associated powerhouse with an
installed capacity of 800 MW. Table B.6 lists all the pertinent
technical information. Table 8.7 lists the power and energy
yields for the four schemes. Table B.8 itemizes the capital cost
estimate.
Based on the . foregoing economic information, Scheme 3 (Figures
8.14 and B.l5) produces the lowest cost energy by a factor of
nearly 2.
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A review of the en vi ronmentaJ impacts associated with the four
tunnel schemes indicates that Scheme 3 would have the least
impact, primarily because it offers the best opportunities for
regulating daily flows downstream from the project. Based on this
assessment, and because of its almost 2. to 1 eeonomi c advantage,
Scheme 3 was selected as the only scheme worth further study (see
Development Selection Report for detailed analysis). The capital
cost estimate for Scheme 3 appears in Table 8.8. The estimates.
also incorporate single and double t.unnel options. For purposes
of these studies, the daub 1 e tunne 1 option has been se lee ted
because of its superior reliability~ It should also be recognized
that the cost estimates associated with the tunnels are probably
subject to more variation than those associated with the dam
schemes due to geotechnical uncertainties. In an attempt to com-
pensate for these uncertainties, economic sensitivity analyses
using both higher and iower tunnel costs have been conducted.
(b) Additional Basin Development Plan
' As noted, the Watana and High De vi 1 Canyon dam sites appear. _to be
individually superior in economic terms to all others. An addi-
tional plan was therefore developed to assess the potential for
developing these two sites together.. For this scheme, the Watana
dam \-Jould be developed to its full potential. The High Devi 1 Can-
yon dam would be constructed to a crest elevation of 1470 feet to
fully utilize the head downstream from Watana •
(c) Selected Basin Development Plans
The essential objectives of this step in the development selection
pr9cess is defined as the ident i fi cation of those p 1 ans which
appear to warrant further, more detailed evaluation. The resul.ts
of fi na 1 sereeni ng process indicate that the Watana/Devi l Canyon
and the High Devil Canyon/Vee plans are~clearly superior to all
other dam combinations. In addition, .it was decided to study
further tunne 1 Scheme 3 as an a lterrtati ve to the High De vi 1 Can-
yon dam and a plan combining a Watana,'High Devil Canyon.
Associated with each of these p 1 ans are sever a 1 opt 1 ons for staged
development. For this more detailed analysis of these basic
plans, a range of different approaches to staging the developments
was considered. In order to keep the total options to a reason.
able number and also to maintain reasonably large staging steps
consistent with the· total. developme'.)i: size,_ stagin~ of only the
two larger developments, 1 .e., Watana and H1 gh Dev1l Canyon, was
considered. The. basic staging concepts adopted for these develop ...
ments involved staging both dam and powerhouse construction, or
alternatively just sta9ing powerhouse construction. Powerhouse
stages were considered in 400 MW increments.
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Four basic plans and associated subplans are briefly described
below .. Plan 1 involves the Watana-Devil Canyon sites, Plan 2 the
High Devi 1 Canyon-Vee sites, Plan 3 the Watana-tunnel concept, and
Plan 4 the Watana-Hi gh De vi 1 Canyon sites. Under each p 1 an
severa1 alternative subplans were identified, each involving ·a
different staging concept. Summaries of these plans are given in Table 8.9.
( i) Plan 1
-Subplan 1.1: The first stage involves constructing
Watana dam to its full height and installing 800 MW .•
Stage 2 involves constructing Devil Canyon dam and
installing 600 MW •
-Subelan 1.2: For this Subplan, construction of the
Watana dam is staaed from a crest elevation of 2060 feet ..,
to 2225 feet. The powerhouse is a 1 so staged from 400 MW
to 800 MW. As for Subplan 1.1, the final stage involves
Devil Canyon with an installed capacity of 600 MW.
-Subplan 1.3: This Subplan is similar to Subplan 1.2
except that only the powerhouse and not the dam at Watana
is staged.
· ( i 1) P 1 an 2
-Subelan 2.1: This Subplan involves constructing the High
Dev1l Canyon dam first with an installed capacity of 800
MW. The second stage i nvo 1 ves constructing the Vee dam
with an installed capacity of 400 MW.
-Subp lan 2. 2: For this Subp 1 an, the construction of Hi gh
Devi 1 Canyon is staged from a crest elevation of 1630 to
1775 feet. The installed capacity is also staged from
400 to 800 MW. As for Subplan 2.1, Vee follows with 400 MW of installed capacity.
"" Subplan 2.3: This Subplan is similar to Subplan 2.2
except that only the powerhouse and not the dam at High
De vi 1 Canyon is staged.
(iii) Plan 3
-Subplan 3:..!.: This Subplan involves initial construction
of Watana and installation of 800 MW capacity. The next
stage invo 1 ves the construction of the downstream re-
regulation dam to a crest elevation of 1500 fe~t and a 15
mile long tunnel. A total of 300 MW would be installed
at the end of the tunne 1 and a further 30 MW at the re-
regulation dam. An additional 50 MW of capacity would be
installed at the Watana powerhouse to facilitate peaking operations.
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-Subplan 3.2: This Subplan is essentially the same as
Subplan 3.1 except that construction of the initial 800
MW powerhouse at Watana is staged.
( i v) P1 an 4
This single plan was developed to evaluate the development
of the two most economic dam sites, Watana and High Oevi 1
Canyon, jointly. Stage 1 involves constructing Watana to
its full height with an installed capacity of 400 MW. Stage
2 involves increasing the capacity at Watana to 800 MW.
Stage 3 involves constructing High Deveil Canyon to a crest
elevation of 1470 feet so that the reservoir extends to
just downstream of Watana. In order to deve·lop the full
head . between Watana and Portage Creek, an additi anal
smaller dam is added downstream of High Devil Canyon .. <? This
dam would be located just upstream from Portage Creek so as
not to interfere with the anadromous fisheries and would
have a crest elevation of 1030 feet and an installed capa-
city of 150 MW.. For purposes of these studies !j this site
i.s referred to as the Portage Creek site.
1.5 -iYaluation of Basin Development Plan
The overall objective of th1s step in the evaluation process was to
select the preferred basin development plan. A preliminary evaluation
of p 1 ans was i nit i a 11 y undertaken to determine broad comparisons of the
available alternatives. This w1s followed by appropriate adjustments
to the plans and a more detailed evaluation and comparison.
In the process of initially evaluating the final four schemes, it
became apparent that· there would be environmental problems associated
with allowing daily peaking operations from the most downstream reser-
voir in each of the plans described above. In order to avoid these
potential problems while still maintaining operational flexibility to
peak on a daily basis, re-regulation facilities were incorporated in
the four basic plans.. These facilities incorporate both structural
measures such a,s re-regulation dams and modified operational pro-
cedures. Details of these modified .plans, referred to as El to E4, are
listed in Table BelO.
The plans listed in Table 8.10 were subjected to a more detailed
analysis as described in the following section.
{a) Evaluation Methodology
The approach to evaluating the various basin development plans
described above is twofold:
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-For determining the optimum staging concept associated with each
basic plan (i.e., the .optimum subplan), only economic criteria
are used and the least cost staging concept is adopted.
-For assessing whi c·h p 1 an is the most appropriate') a more
detailed evaluation process incorporating economic, environmen-
tal, social and energy contribution aspects is taken into
account. ·
Economic evaluation of any Susitna Basin development plan requires
that the impact of the plan on the cost of energy to the Railbelt
area consumer be assessed on a systemwide basis. Si nee the con-
sumer is supplied by a large number of different generating
sources, it is necessary to determine the total Railbelt system
cost in each case to comp~re the various Susitna Basin development
options ..
The pr'imary tool used for system costs was the mathematical model
developed by the Electricity Utility Systems Engineering Depart-
ment of the General Electric Company. The model is commonly known
as OGP5 or Opt1mi zed Gener.at ion Planning Model, Version 5. The
following 1nformation is paraphrased from GE literature on the
program.
The OGPS program was developed over ten years to combine the three
main e 1ements of generat 1 on expansion p 1 anni ng {system rel i abi 1-
ity, operating and investment costs) and automate generation addi-
tion decision analysis. OGP5 will automatically develop optimum
generation expansion patterns in terms of economics, reliability
and operation. Many utilities use OGP5 to study load management,
unit size, capital and fuel costsi energy st.orage, forced outage
rates, and forecast uncertainty.
The OGP5 program requires an extensive system of specific data to
perform its planning function. In developing an optimal plan~ the
program considers the existing and committed units (planned and
under tonstructi on) avai 1 ab 1 e to the system and the characteri s-
ties of these units including age, heat rate, size and outage
rates as the base generation plan. The program then considers the
given 1 oad forecast and operation criteria to determine the need
for additional system capacity bas,ed on given· reliability cri-
teria.. This determines 11 how much 11 capacity to add and ''whenu it
should be installed. If a .need exists during any monthly itera-
tion, the program will consider additions from a list of alterna-
tive~ and select the available unit best fittin~ the system needs.
Unit selection is made by computing production costs for the sys-
tem for each alternative included and comparing the results.
The unit resulting in the lowest system production cost is select-
ed and added to the system. Finally, an investment cost analysis
of the capital costs is completed to answer the question of uwhat
ki nd 11 of generation to add to the system~
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The model is then further used to compare alternative plans for
meeting variable electrical demands, based on system reliability
and production costs for the study period.
A minor limitation inherent in the use of the OGPS model is that
the number of years of simulation is limited to 20. To overcome
this, the study period of 1980 to 2040 has been broken into three
separate segments for study purposes. These segments are common
to a 11 system generation plans.
The first segment has been assumed to be from 1980 to 1990. The
model of this time period included all committed generation units
and is assumed to be common to all generation scenarios.
The end point of this model becomes the beginning of each 1990-2010 model.
The model of the first two time periods considered (1980 to 1990,
and 1990-to 2010) provides the total production costs on a year-
to-year basis. These total costs include, for the period of
modeling, all costs of fuel and operation and maintenance of all
generating units included as part of the system. In addition, the
completed production costs includes the annualized investm~nt
costs of any production plans added during the period of study. A
number of factors which contribute to the ultimate cost of power
to the consumer, are not included in this model. These are common
to all scenarios and include:
-All investment costs to plants in service prior to 1981;
-Costs of transmission systems in service both at the transmi s-
sion and distribution level; and
-Administrative costs of utilities for providing electric service to the public.· ·
Thus, it should be~ recognized that the production .costs modeled
represent only a portion of ultimate consumer costs and in effect
are only a portion, albeit major, of total costs.
The third period, 2010 to 2040, was modeled by assuming that pro-
duction costs of 2010 would recur for the additional 30 years to
2040. This assumption is believed to be reasonable given the
1imitations on forecasting energy and load requirements for this
period. The additional period to 2040 is required to at least
take into account the benefit derived or value of the addition of
hydroelectric power plant which has a useful life of fifty years
or more.
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The selection of ~he preferred generation plan is based on numer-
ous factors. One of these is the cost of the generation plan. To
provide a consistent means of assessing the production cost of a
given generation scenario, each production cost total has been
converted to a 1980 present worth basis. The prest:nt worth cost
of any generation scenario 1 s made up of three cost amounts. The
first is present worth cost (PWC) of the first ten years of study
(1981 to 1990), the second is the PWC of the scenario assumed
during 1990 to 2010 and the third the PWC of the scenario in 2010
assumed to recur for the peri ad 2010 to 2040. In this way the
1 ong-term ( 60 years) PWC of e.ach generation scenario in 1980
dollars can be compared.
A summary of the input data to the model and a discussion of the
results follow.
(i) .Initi-al Economic Analyses
Table B.ll lists the results of the first series of economic
analyses undertaken for the basic Susitna Basin development
plans listed in Table 8.10. The information provided
includes the specified on-line dates for the various stages
of the plans, the OGP5 run index number~ the total installed
capacity at year 2010 by category, and the total system
present-worth cost in 1980 for the peri ad 1980 to 2040.
Matching of the Susitna development to the load growth for
Plans El~ E2, and E3 is shown in Figure 8.16, 8.17 and B.l8
respectively. After 2010, steady state conditions are
assumed and the then-existing generation mix and annual
costs for 2010 are applied to the years 2011 to 2040. This
extended period of t 1me is necessary to ensure that the
hydroelectric options being studied, many of which only come
en-line around 2000, are simulated as operating for periods
approaching their economic lives and that their full impact
on the cost of the generation system is taken into account.
-Plan E1 -Watana/Oevi 1 Canyon
• Staging the dam at Watana (Plan E1.2) is not as economic
as constructing it to its full height (Plan El.l and
E1.3). The present worth advantage of not staging the
dam amounts to $180 million in 1980 dollars.·
The results indicate that, with the level of analysis
performed, there is no discernible benefit in staging
construction of the Watana. powerhouse (P 1 an El.l and
E1 .. 3). However, Plan E1.4 results indicates that,
should the powerhouse size at Watana be restricted to
400 MW~ the overall system present worth would
increase.
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Additional runs performed for variations of Plan El.3
indicated that system present worth wou 1 d increase by
.$1,110 mi 11 ion if the De vi 1 Canyon dam was not con-
structed. A five year delay in construction of the
Watana dam would increase system present worth by $220
million.
-Plan E2 -High Devil Canyon/Vee
• The results for Plan E2.3 indicate that the system pre-
sent worth is $520 million more than Plan E1.3. Present
worth increases also occur if the Vee dam stage is not
constructed. A reduction in present worth of appro xi-
mately $160 million is possible if the Chakachamna
hydroelectric project is constructed instead of the Vee
dam •
• The results of Plan E2 .. 1 indicate that total system
present worth wou 1 d increase by $250 mi 11 ion if the
total capacity at High Devil Canyon were limited to 400 MW.
-Plan E3 -Watana/Tunnel
The results for Plan E3.1 illustrate that the tunnel
scheme versus the Devi 1 Canyon dam scheme (El.3) adds
approximately $680 mi 11 ion to the tot a 1 system present
worth cost. The availability of reliable geotechnical
data would undoubtedly have improved the accuracy of the
cost estimates for the tunnel alternative. For this
reason~ a sensitivity analysis was made as a check to
determine the effect of halving the tunnel ·costs. This
analysis indicates that the tunnel scheme" is still more
costly than constructing the De vi 1 Canyon dam.
-Plan E4 -Watana/High Devil Canyon/Portage Creek
The results indicate that system present worth associated
with Plan E4.1, excluding the Portage Creek site develop-
ment, are $200 million more than the equivalent El.3 plan.
If the Portage Creek development is included, the present
worth difference would be even greater.
Load Forecast Sensitivity Analyses
The plans with the lowest present-worth cost were subjected
to further sensitivity analyses to assess the economic
impacts of various load growths. These results are sum•
marized in Table 8 .. 12.
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The results for low load forecasts. illustrate that the most
viable Susitna Basin development plan is the Watana-Devil
Canyon plan with a capacity of 800 MW, which has a present
worth cost of $210 million less than its closest competitor,
the High Devil Canyon-Vee plan.·
For the high load forecasts, the results indicate that the
P 1 an El. 3 has a present worth cost of $1040 mi 11 ion 1 ess
than E2. 3.
(b) Evaluation Criteria
The following criteria were used to evaluate the shortlisted basin
development plans. These criteria generally contain the require-
ments of the generic process with the exception that an additional
criterion, energy contribution, is added in order to ensure that
full ·consideration is given to the total basin energy potential
developed.by the various plans.
(i) Economic
(ii)
{iii)
( i v)
Plans were compared using long-term present worth costs,
calculated using the OGP5 generation planning model. The
parameters used in calculating the total present-worth cost
of the total Railbelt generating system for the period 1980
to 2040 are listed in Table B.l3 and 8.14. Load forecasts
used in the analysis are presented in Section 5.1(b).
E nvi ronment a 1 ·
A qualitative assessment of the environmental impact on the
ecological, cultural, and aesthetic resources is undertaken
for each plan~ Emphasis is placed on identifying major
concerns so that these cou 1 d be combined with the other
evaluation attributes in an overall assessment of the
plan.
Soci a1
This attribute includes· determination of the potential non-
renewable resource displacement, the impact on the state
and local economy, and the risks and consequences of major
structural failures due to seismic events. Impacts on the
economy refer to the effects of an investment plan on eco-
nomic variables.
Energx Contribution
The parameter used is the total amount of energy produced
from the specific development p 1 an. ·An assessment of the
energy development foregone is also undertaken. The energy
1 ass that is inherent to the p 1 an and cannot easi 1 y be
recovered by subsequent staged developments is of greatest
concern.
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{c) Results of Evaluation Process
The various attributes outlined above have been determined for
each plan and are summarized in Tables 8.15 through 8 .. 23. Some of
the attributes are quantitative while others are qualitative.
Over a 11 eva 1 uati on is based on a comparison of simi 1 ar types of
attributes for each p 1 an. In cases where the attributes associ-
ated with one plan all indicate equality or superiority with
respect to another plan, the decision as to the best plan is clear
cut. In other cases where some attributes indicate superiority
and others inferiority,· differences are highlighted and trade-off
decisions are made to determine the preferred deve 1 opment p 1 an ...
In cases where these trade-offs have had to be made, they were
relatively straightforward, and the decision-making pr9cess can,
therefore, be regarded as effective and consistent~ In addition,
these trade-offs are clearly identified so the recorder can inde-
pendently assess the judgment decisions made.
The overall evaluation proc~ss is conducted in a series of steps.
At each step, only two plans are compared. The superior plan is
then taken to the next step for evaluation against a third plan.
(1) Devil Canyon Dam Versus Tunnel
The first-step in the process involves the comparison of the
~~atana-Devil Canyon dam plan (El .. 3) and the Watana-Tunne1
plan (E3.1). Since \~atana is common to both plans, the
evaluation is based on a comparison of the Devil Canyon dam
and Scheme 3 tunnel alternative.
In order to assist in the evaluation in terms of economic
criteria, additional information obtained by analyzing the
results of the OGPS comouter runs is shown in Table 8.15. . '
This information i 11 ustrates the breakdown of the total
system present worth cost in terms of capita 1 investment~
fuel, and operation and maintenance costs.
-Economic Comparison
From an economic point of view, the Watana-Devi 1 Can_yon
dam scheme is superior. As summarized in Tables 8.15 and
B .16, on a. present worth basi's the tunnel scheme is $680
mi 11 ion more expensive than the dam scheme. For a 1 ow
demand growth rate, this cost difference would be reduced
s 1 i ght ly to $650 mi 11 ion. Even if the tunnel scheme costs
are halved, the total cost difference would still amount
to $380 million. As highlighted in Table 8.16 considera-
tion of the sensitivity of the basic econopmic evaluation
to potential changes in capital cost estimate, the per·iod
of economic analysis, the ·discount rate, fuel costs, fuel
cost escalation, and economic plant life do not change ·the
basic economic superi-ority of the dam scheme over the tun-
nel scheme.
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-Environmental Comparis~
The environmental comparison of the two schemes is sum-
marized in-Table 8.17. Overall, the tunnel scheme is
judged to be superior because:
• It offers the potentia 1 for enhancing anadromous ti sh
populations downstream of the re-regul ati on dam due to
the more uniform flow distribution that will be achieved
in this reach;
• It wou 1 d inundate 13 mi 1 es 1 ess of resident fisheries
habitat in river and major tributaries;
• It has a lower potential for inundating archeological
sites due to smaller reservoir involved; and Q
• It wou 1 d preserve mur.h of the characteristics of the
Devil Canyon gorge which is considered to be an aesthe-
tic and recreational resource.
-Social Comparison
Tab 1 e B .1a· summarizes the evaluation in terms of the
social criteria of the two schemes. In terms of impact on
state and local economics and risks because of seismic
exposure, the two schemes are rated equa 1. However, the
dam scheme has, due to its higher energy yield, more po-
tential for displacing nonrenewable energy resources, and
therefore has a slight overall advantage in terms of the
social evaluation criteria.
-Energy Comparison
Table 8.19 summarizes the evaluation in terms of the
energy contribution criteria. The results shown that the
darn scheme has a greater potential for energy production
and develops a larger portion of the basin•s potential.
'The dam scheme is therefore judged to be superior from the
energy contribution standpoint.
-Overall Comparison ..
The overall evaluation of the two schemes is summarized in
Table Bo20. The estimated cost saving of $680 million in
favor of the dam scheme plus the additional energy pro-
duced are considered to outweigh the reduction in the
overall environmental impact of the tunnel scheme. The
dam scheiie is therefore judged to be superior avera 11.
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( i i) Watana-Devi1 Canyon Versus High Devil Canyon-Vee .
The second step in the development selection process
involves an evaluation of the Watana-Devil Canyon (Elo3} and
the High Devil Canyon-Vee (E2.3) development plans.
-Economic Comparison
In terms of the economic criteria (see Table 8.15 and
B.16) the 14atana-Devil Canyon plan is less costly by $520
,:e~illion. Consideration of the sensitivity of this deci-
sion to potential changes in the various parameters con-
sidered {ioe., load forecast, discounted rates, etc.) does
not change the basic superiority of the Watana-Devi 1 Canyon Plan.
-·Environmental Comparison
The evaluation in terms of the environmental criteria is
summarized in Table 8.21. In assessing these plans, a
.reach-by-reach comparison was made for the section of the
Susitna River between Portage Creek and the Tyone River.
The Watana-Devi 1 Canyon s.cheme wo.u 1 d create more potentia 1
environmental impacts in the Watana Creek area. However,
it is judgep that the potential environmental impacts
which waul d occur above the Vee Canyon dam with a High
De vi 1 Canyon-Vee deve 1 opment are more severe in over a 11 comparison.
Of the seven environmental factors considered in Table 8.17~ except for the increased loss of river valley~ bird
and black bear habitat the Watana-Devi 1 Canyon development
plan is judged to be more environmentally acceptable than
the High Canyon-Vee plan.
-Energy Comparison
The evaluation of the two plans in terms of energy contri-
bution criteria is summarized in Table 8.22. The Watana-
.Devil Canyon scheme is assessed to be superior because of
its higher energy potential and the fact that it develops
a higher proportion of the basin's energy potential.
-Social Comparison
Table 8.18 summarizes the evaluation in terms of the
social criteria. As in the case of the dam versus tunnel
comparison, the Watana-Devi 1 Canyon p 1 an is judged to have
a s 1 i ght advantage over the High De vi 1 Canyon-Vee plan.
This is because of its greater potentia 1 for di spl acing
·nonrenewable resources.
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1.6 -Preferred Susitna Basin Development Plan
One-on-one comparisons of the Watana-Devi 1 Canyon p 1 an with the Watana-
tunnel plan and the High Devil Canyon-Vee plans are judged to favor the
Watana-Devi 1 Canyon plan in each case.
The Watana-Devi 1 Canyon p 1 an was therefore se 1 ected as the , preferred
Susitna Basin development plan, and the basis for continuation of more
detailed design optimization and environmental studies.
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2 -ALTERNATIVE FACILITY DESIGNS~ PROCESSES AND OPERATIONS
2.1 -Susitna Hydroelectric Development
As originally conceived. the Watana project initially comprised an
earthfill dam~ with a crest elevation of 2225 and 400 MW of generating
capacity scheduled to commence operation in 1993-.. An additional 400 MW
would be brought on ... line in 1996. At Devil Canyon an additional 400 MW
would be installed to commence operation in the year 2000. Detailed
studies of each project have led to refinement and optimization of
designs in terms of a number of key factors, including updated load
forecasts and economics. Geotechnical and environmental constraints
identified as a result of continuing field work have also greatly
influenced the curr_ently recommended design concepts.
Plan formulation and alternative facility designs considered for the
Watana and Devil Canyon developments are discussed in this section.
This section includes the alternatives studied and the reason for sel-
ecting the proposed plan. Background information on the site charac-
teristics as well as additional detail on the plan formulation process
are included in the Design Report of Exhibit F and the referenced
reports.
2e 2 -Watana Project Formulation --------~------------
This section describes the evolution of the general arrangement of the
Watana project which~ together with the Devil Canyon project, comprises
the deve 1 opment p 1 an proposed. The process by which reservoir operat-
ing levels and the installed generating capacity of the power facil-
ities were established is presented, together with the means of hand-
1 ing floods expected during construction and subsequent project opera-
tion.
The main components of the Watana development are as follows:
-Main dam;
-Diversion facilities;
-Spillway facilities;
-Outlet facilities;
-Emergency release f~cilities; and
-Power facilities.
A number of alternatives are available for each of these components and
they can be combined in a number of ways. The following paragraphs
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describe the various components and methodology for the preliminary,
intermediate, and final screening and review of alternative general
arrangenent of the components, together with a brief description of the
selected scheme. This section presents the alternative Jrrangements
studied for the Watana projecto
(a) Selection of Reservoir Levels
The selected elevation of the Watana dam crest is based on consid-
erations of the value of the hydroelectric energy produced from
the associated reservoir, geotechnical constraints on reservoir
levels, and freeboard requirements. Firm· energy, average annual
energy, construction ·casts, and operation and~ maintenance costs
were determined for the Watana development with dam crest eleva-
tions of 2240, 2190, and 2140. The relative value of energy pro-
duced in terms of the present worth of the i ong-term production
costs (LTPW) for each of these three dam elevations was determined
by means of the OGP5 generation planning model described in
Section 1 of this Exhibit. The physical constraints imposed on
dam height and reservoir elevation by geotechnical considerations
were reviewed and incorporated into the crest elevation selection
process. Finally, freeboard requirements for the PMF and settle-
ment of the dan after construction or as a result of seismic
activity were taken into account.
( i) .Methode 1 o9y
Firm and average annual energy produced by the Susitna
developnent are based on 32 years of hydrological records ..
The energy produced was determined by using a multi-
reservoir simulation of the' operation of the Watana and
Devil Canyon reservoirs. A variety of reservoir drawdowns
were examined, and drawdowns producing the maximllll firm
energy consistent with engineet"ing feasibility and cost of
the intake structure were selected. Minimtm flow require-
ments were established at both project sites based on down-
stream fisheries considerationso
To meet system demand the required maximum generating capa-
bility at Watana in the period 1993 and 2010 ranges from
665 MW to 908 MW. For the reservoir level determinations~
energy estimates were made on· the basis of assumed average
annual capacity requirements of 680 MW at Watana in 1993,
increasing to 1020 MW at Watana in 2007, with an additional
600 MW at Devil Canyon coming online in the year 2002. The
1 ong term present worth costs of the generation system
required to meet the Ra i 1 be 1 t energy den and were · then
determined for each of the three crest e 1 ev at ions of the
Watana dan using the OGP5 model.
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The construction cost estimates used in the OGPS modeling
process for the Watana and Devil Canyon ·projects were based
on preliminary conceptual 1 ayouts and construction sche-
dules. Further refinement of these layouts has taken place
during the optimization process. These refinements have no
significant impact on the reservoir 1eve1 selection~
(ii) Economic Optimization
Economic optimization of the Watana reservoir level was
based on an evaluation of three dan crest elevations of
2240, 2190, and 2140. These crest elevations apply to the
central portion of the embankment with appropriate allow-
ances for freeboard and seismic settlement, and correspond
to maximum operating levels of the reservoir of 2215, 2165,
and 2115 feet, respectively. Average annual energy cal-
culated for each case using the reservoir simulation model
are given in Table 8.24, together with corresponding proj-
ect construction costs.
In the determination of LTPW, the Susitna capital costs
were adjusted to include an allowance for interest duri.ng
construction and then used as input to the OGP5 model.
Simulated annual energy yields were distributed on a
monthly basis by the reservoir operation model to match as
closely as possible the projected monthly energy demand of
the Railbelt and then input to the OGP5 model. The LTPW of
meeting the Railbelt energy demand using the Susitna devel-
opment as the primary source of energy was then determined
for each of the three reservoir levels.
The results of these evaluations are shown in Table 8.25~
and plots showing the variation of the LTPW with dam crest
elevation are shown in Figure 8.19. This figure indicates
that on the basis of the assumptions used, the minimum LTPW
occurs at a Watana crest elevation ranging from approxi-
mately 2160 to 2200 (reservoir levels 2140 to 2180 feet).
A higher dam crest will still result in a developnent which
has an overall net economic benefit relative to thermal
energy sources. However, it is also clear that as the
height of the Watana dan is increased, the unit costs of
additional energy produced at Watana is somewhat greater
than for the displaced thermal energy source. Hence, the
LTPW of the overall system would increase. Conversely, as
the height of the dam is lowered, and thus Watana produces
1 ess energy, the unit cost of the energy produced by a
thermal generation sour,~e to replace the lost Susitna
energy is more expensive than Susitna energy. In this case
also, the LTPW increases.
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(iii) Geotechnical Considerations
On the north side of the reservoir created by the Watana·~
dam a relict channel of considerable depth connects the
reservoir to Tsusena Creek. As the water surface elevation
of the reservoir is increased up to and beyond 2200 feet~ a
low area in the relict channel would require costly water
retaining structures to be built and other measures to be
taken. In addition to the cost the technical feasibility
of these measures is not as certain as desired on a project
of this magnitude. Because of the considerations relating
to seismic stability, seepage problems and permafrost con-
ditions in the relict channel area, the hydraulic head at
the upstream end of the relict channel should be limited
wherever possible.. By comparing normal reservoir levels
plus flood surcharge to ground surface contours, it was
determined that with normal reservoir levels of 2185 and a
small freeboard dike the following conditions waul~ exist:
.
-For flood magnitudes up to the 1:10,000-year event, there
would be no danger of overtopping the lowest point in the
relict channel.
-for the PMF a freeboard dike in the low .area of up to 10
feet in height would provide adequate protection. This
dike would be wetted only a few days during a Pt4F event.
-If seismic settlement or settlement due to permafrost
melting did occur, the combination of the 10 feet free-
board dike constructed on a suitable foundation plus
normal reservoir level of 2185 feet would ensure that
breakthrough in the re 1 i ct channe 1 area would not occur.
With this approach, the Watana project will develop the
maximum energy reasonably available without incurring the
need for costly water retaining structures in the relict
channel area.
(iv) Conclusions
It is important to establish clearly the overall objective
used as a basis for setting the Watana reservoir level. An
objective which would minimize the LTPW energy cost would
lead to selection of a slightly lower reservoir level than
an objective which would maximize the amount of energy
which can be obtained from the available resource, while
doing so with a technically sound project.
The three values of LTPW developed by the OGP5 computer
runs defined a relationship between LTPW and Watana dam
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height which is relatively insensitive to dan he_ight. This
is highlighted by the curve of LTPW versus dam height in
Figure 8.19 .. This figure shows there is only a slight var-
iation in the LT.PW for the range of dam heights included in
the analysis. Thus, from an economic standpoint the opti-
mtlll crest elevation could be considered as varying over a
rang a of elevations from 2140 to 2220 with 1 ittl e effect on
project economics. The main factors in establishing the
upper 1 imit of dam height were :onsequently the ,geotech-
nical considerations discussed in (c) above.
The normal maximum operating level of the reservoir was
therefore set at Elevation 2185, allowing the. objective of
maximizing the economic use of the Susitna resource still
to be satisfied.
(b) Selection of Installed Capacity
lhe generating capacity to be installed at both vlatana and Devil
Canyon was determined on the basis of generation pl anrling stud.ies
described in Sections 6 and 8 of Reference 4 together with appro-
priate consideration of the following:
-Avail able firm and average energy from Watana and Devil Canyon;
-The forecast energy dan and and peak 1 oad den and of the system;
-Avail able firm and average energy from other existing and C0!11-
mitted plant;
-Capital cost and annual operating costs for Watana and Devi1
Canyon;
-Capital cost and annual operating costs for alternative sources
of energy and capacity;
-r.nvironmental constraints on reservoir operation; and
-Turbine and generator operating characteristics.
(i) Methodology
The following procedure was used to select the installed
capacity at Watana:
-The firm and average energy available at both Watana and
Devil Canyon was determined using a reservoir simulation
progran.
- A determination was then made of the generating capacity
required to utilize the avail able energy from the Susitna
Project in the hydrological years of record, based on the
following assumptions:
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• In a wet year, energy developed at either Watana or
Devil Canyon displaces excess thermal energy (from
coal, gas turbine, combined cycle, or diesel plants) •
• In an av,erage year where thermal energy is required to
· meet system energy den and, hydro. energy is used either
to satisfy peak demand with thermal energy supplying
base load (Option 1)· or to supply base load require-
ments with thermal energy at peak demand (Option 2}.
The actual choice is based on dispatching the most eco-
nomic energy first •
• Devil Canyon energy is used predominantly as base load
energy because of environmental constraints on down-
strean flow v ar i at ions it
• The maximum insta 11 ed capacity was determined on the
basis of the estab1 ished peak generating capacity
requirt;d' plus any hydro standby or spinning reserve
equi r.:ment.
(ii) Watana Installed Capacity
The required total cape:.city at Watana in a wet ye.ar:, ex-
cluding standby and spinning reserve capacity, 1s sum-
marized below. The capacities are based on the medium load
forecast ..
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Capacity {ftlt:JJ -·
Opt1on .1 Opt1on ~
UeV1l Devil t~atana Thermal Canyon Watana Thermal Canyon Demand Year Peak Base Base Base Peak Base
1993 801 0 0 801 0 0
1995 839 0 0 839 0 0
2000 374 66 0 742 198 0
2002 (Including
Devil Canyon) 660 0 354 660 0 354
2005 (Including
Devil Canyon) 750 0 376 750 0 376
2010 (Including
Devil Canyon) -900 0 493 900 0 493
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On the basis of this evaluation, the ultimate power genera-
tion capability at Watana was selected as 1020 MW for
design purposes to allm'l a margin for hydro spinning
reserve and standby for forced outage. This installation
also provides a small margin in the event that the load
growth exceeds the medium load forecast •
(iii) Unit Capacity
Selection of ·the unit size for a given total capacity is a
compromise between the initial least cost solution, gener-
ally involving a scheme with a Slilall er nunber of 1 arge
capacity units, and the improved plant efficiency and
security of operation provided by a 1 arger nlJTlber of
smaller capacity units. Other factors include the size of
each unit as a proportion of the total system load and the
minimllll anticipated load on the station. fllly requirement
for a minimt.m downstre5io flow would also affect the selec-
tion. Growth of the actual load demand is also a signifi-
cant factor, since the instal:ation of units may be phased
to match the actual load growth. The niJTlber of units and
their individual ratings were determined by the need to
deliver the required peak capacity in the peak demand month
of December at the minimun December reservoir 1 evel with
the turbine wicket gates fully open.
An exc.mination was made of the economic impact on power
plant production costs of various combinations of a number
of units and rated capac.ity which would provide the sel-
ected total capacity of 1020 MW. For any given installed
capacity, plant efficiency inereases as the nt.mber of units
increases. The assumed capitalized value used in this
evaluation was $1.00 per average annual kWh over project
life, based on the economic analysis completed for-the
thennal generation system. Variations in the nllllber of
units and capacity will affect the cost of the power
intakes, penstocks, powerhouse, and tailrace. The differ-
ences in these capital costs were estimated and included in
the evaluation. The results of this analysis are presented
below •
Capitalized
Rated Value of
Capacity . Additional Additional
Nunber of Unit Energy Capital Cost Net Benefi.t
of Units (MW) ( $ Mi 11 ions) ($ Millions} ($ Millions)
4 250 0 0 0
6 170 40 31 9
8 125 50 58 -8
..... /
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(c)
It is apparent from this analysis that a six-unit scheme
with a net benefit of approximately $9 million is the most
economic alternative. This scheme also offers a higher
degree of flexibility and security of operation compared to
the four-unit alternative, as well as advantages if unit
installation is phased to match actual load growth. The
net economic benefit of the six unit scheme is $17 mill ion
greater than that of the eight-unit scheme, whi 1 e at the
same time no significant operational or scheduling· advan-
tages are associated with the eight-unit scheme.
A scheme incorporating six units each with a rated capacity
of 170 MW, for a total of 1020 MW, has been adopted for all
Watana alternatives.
Selection of th_e Spillway Design Flood
Normal design practice for projects of this magnitude, together
with applicable design regulations, require that the project be
capable of passing the Probable Maximtiil Flood (PMF) routed through
the reservoir without endangering the dam.
In addition to this requirement, the project should have suffic-
ient spillway capacity to safely pass a major flood of lesser mag-
nitude than the PMF without damaging the main dan. or ancillary
structures.. The frequency of occurrence of this flood, known as
the spillway design flood or Standard Project Flood (SPF), is gen-
erally selected on the basis of an evaluation of the risks to the
project if the spillway design flood is exceeded, compared to the
costs of the structures required to safely discharge the flood ..
For this study, a· spillway design flood with a return frequency of
1:10,000 years was selected for Watana. A 1 ist of ·spillway desigr-
flood frequencies and magnitudes for several major projects is
presented below.
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(d)
Splllway
Spillway Design Flood Basin Capacity
Peak R4F After Routing
Project Frequency Inflow (cfs) (cfs) (cfs)*
Mica, Canada PMF 250,000 250,000 150,000
Churchill Falls, 0
Canada 1:10,000 600,000 1,000,000 230,000
New Bullards, USA PMF 226,000 226,000 170,000
Oroville, USA 1:10,000 440,500 711,400 440,500
Gur i , Venezue 1 a
(final stage) PMF 1,000,000 1,000,000 1,000,000
Itaipu, Brazil PMF 2,195,000 2,1959 000 2~105,000
Sayano, USSR 1:10,000 480,000 N/A 680~000
*All spillways except c:-':J.yc· J l-)ave capacity to pass PMF with surcharge.
The flood frequency analysis produced the following va.lues:
Flood Frequency
Prob ab 1 e Max imliO
Spi 11 way Design 1:10,000 year-s
Inflow Peak
326,000 cfs
156,000 cfs
Additional capacity required to pass the PMF will be provided by
an emergency spillway consisting of a fuse plug and rock channel
on the right bank.
Main Dam Alternatives
This section describes the alternative types of dans considered at
the Watvana site and the basis for the selected alternative.
( i) Comparison of Embankment and Concrete Type Dams
The selection between an embankment type or a concrete tJPe
dam is usually based on the configuration of the valley,
the condition of the foundation rock., depth of the over-
burden, and the relative avail ab i 1 ity of construction
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materials. Previous studies by the COE envisaged an
embankment dam at Watana. Initial studies completed as
part of this current evaluation included comparison of an
earthfill dam with a concrete arch dam at the Watana site .
An arrangement for a concrete arch dam alternative at
Watana is presented in Figure 8.20. The resul-t;s of this
analysis indicated that the cost of the embankment dam was
somewhat lower than the arch dam, even though the concrete
cost rates used were significantly lower than those used
for the Devil Canyon Dam. This preliminary evaluation did
not indicate any overall cost savings in the project in
spite of some savings in the earthworks and concrete struc-
tures for the concrete dam layout. A review of the overall
construction schedule indicated a minimal savings in time
for the concrete dam project.
Based on the above and the likelihood that the cost of the
arch dam would increase relative to that of the embankment
dam, the arch dam alternative was eliminated from further
consideration •
{ii) Concrete-face Rockfill Type Dam (to be written)
(iii) Selection of Dam Type
Selection of the configuration of the embankment dam
cross-section was undertaken within the context of the
following basic considerations:
-The av a i l ab i 1 it y
within economic
material;
of suitable construction materials
haul distance, particularly core
-The requirement that the dam be capable of withstanding
the effects of a significant earthquake shock {Reference
2) as we 11 as the static 1 oads ill1posed by the reservoir
and its own weight;
-The relatively limited construction season available for
placement of compact~d fill materials.
The main dam would consist of a compacted core protected by
fine and coarse filter zones on both the upstream and down-
stream s 1 opes of the cor,e. The upstream and downstream
outer supporting fill zones would contain relatively free
draining compacted gravel or rockfill, providing stability·
to the overall embankment structure. The location and
inclination of the core is fundamental to the design of the
embankment. Two basic alternatives exist in this regard:
- A vertical core located centrally within the dam; and
-An inclined core withboth faces sloping upstream.
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A central vertical core was chosen for the embankment based
on a review of precedent design and the nature of the
avail able impervious material.
The exploration program undertaken during 1980-81 indicated
that adequate quantities of materials suitable for dam con-
struction were located within reasonable haul distance from
the site. The well-graded silty sand material is consid-
ered the most promising source of impervious fill. Compac-
tion tests indicate a natural moisture content slightly on
the-wet side of optimum moisture content, so that control
of moisture content will be critical in achieving a dense
core with high shear strength.
Potential sources for the upstream and downstream shells
include either river gravel from borrow areas along the
Stis itna River or compacted rockfi 11 from quarries or exca-
vations for spillways.
During the intermediate review process, the upstream slope
of the dam was flattened from 2 .. 5H: lV used du1ing the ini-
tial review to 2.75H:lV. This slope was based on a con-
servative estimate of the effective shear strength para-
meters of the available construction materials, as· well as
a conservative allowance in the design for the effects of
earthquake loadings on the dam.
During the final review stage, the exterior upstream s1ope
of the dam was steepened from 2.75H:1V to 2 .. 4H:lV, reflect-
ing the results of the prel_iminary static and dynamic
design analyses being undertaken at the same time as the
general arranganent studies.. As part .of the final review~
the \lolume of the dam with an upstream slope of 2.4H:1V was
computed for four a 1 tern at i ve dan axes. The location of
these alternative axes are shown on Figure 8.21. The: dam
volume associated with each of the four alternative axes is
listed below:
Alternative
Axis Number
1
2
3
4
Tot a 1 Vo 1 ume
(million yd3)
69.2
71.7
69.3
71.9
A section with a 2 .. 4H: lV upstream slope and a 2H: lV down-
stream slope located on alternative axis number 3 was used
for the final review of alternative schemes.
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(e) Diversion.Scheme Alternatives
The topography of the site generally dictates that diversion o.f
the river during construction be accompiished using diversion tun-
nels with upstream and down-stream cofferdams protecting the main
construction area.
The configuration of the river in the vicinity of the site favors
location of the diversion tunnels on. the right banks since the
tunnel length for a tunnel on the left bank would· be approximately
2,000 feet greater.. In ·addition, rock conditions on the right
bank are more favorable for tunneling and excavation of intake and
outlet portals ..
(i)
( i i )
Design Flood for Diversion -
The recurrence interval of the design flood for diversion
is generally established based on the characteristics of
the f1 ow regime of the river, the 1 ength of the construc-
tion period for which diversion is required and the pro-
bable consequences of overtopping of the cofferdans.
Design criteria and experience from other projects similar
in scope and nature have been used in selecting the diver-
sion design flood.
At Watana, damage to the partially completed dam could be·
significant, or more importantly would probably result in
at least a one-year delay in the completion schedule. A
preliminary evaluation of the construction schedule indi-
cates that the diversion scheme would be required for 4 or
5 years until the dam is of sufficient height to permit
initial filling of the reservoir. A des,ign flood with a
return frequenc.>' of 1:50 years was selected based on exper-
ience and practice with other major hydroelectric projects.
This approxi1nates a 90 percent probability that the coffer-
dam wi 11 not be overtopped during the 5-year construction
period. The diversion design flood together with average
flow characteristics of the river significant to diversion
are presented below:
Average annual flow
Maximum average monthly flow
Minimum average monthly flow
Design flood inflow (1:50 years)
Cofferdams
7, 940 cfs
23,100 cfs (June)
890 cfs (March)
81,100 cfs
For the purposes of establishing the overall general
arrangenent of the project and for subsequent diversion
optimization studies, the upstream cofferdam section
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adopted comprises an initial closure dam structure approxi-
mately 30 feet high placed in the wet.
(iii) Diversion Tunnels
Concrete-lined tunnels and unlined rock tunnels were com-
pared. Preliminary hydraulic studies indicated that the
design fluod routed through the diversion scheme would re-
sult in a design discharge of approximately 80,500 cfso
For concrete-lined tunnels, design velocities of the order
of 50 ft/s have been used in several projects. For unlined
tunnels, maximum 'design velocities ranging from 10 ft/s in
good quality rock to 4ft/sin less competent material are
typical.·. Thus, the volume of material to be excavated
using an unlined tunnel would be at least 5 times that for
a lined tunnel. The reliability of an unlined tunnel is
more dependent on rock conditions than is a lined tunnel,
particularly given the extended period during which the
diversion scheme is required to operate. Based on these
considerations, given a considerably higher cost, together
with the somewhat questionable feasibility of four unlined
tunnels with diameters approaching 50 feet in this type of
. rock, the unlined tunnels have been eliminated ..
The following alternative 1 ined tunnel
examined as part of this analysis:
-Pressure tunnel with a free outlet;
schemes. were
-Pressure tunnel with a submerged outlet; and
-Free flow tunnel.
(iv) Emergency Release Facilities
The emergency release facilities influenced the number,
type, and arrangement of the diversion tunnels selected for
the final scheme.
At an early stage of the study, it was established that
some for·m of low level release facility was required to
· permit lowering of the reservoir in the event of an extreme
emergency, and to meet instream flow requirements during
filling of the reservoir. The most economical alternative
available would involve converting one of the diversion
tunnels to permanent use as a low level outlet facility .•
Since it would be necessary to maintain the. diversion
scheme in service during construction of the emergency
facilities outlet works, twa or more diversion tunnels
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would be required.. The use of two diversion tunnels also
provides an additional measure of security to the diversion
scheme in case of the loss of service of one tunnel.
The low level release facilities· will be operated for
approximately three years during filling of the reservoir.
Discharge at high heads usually requires some form of
energy dissipation prior to returning the flow to the
river.. Given the space restrictions imposed by the size of
the diversion tunnel, it was decided to utilize a double
e:~xpansion system constructed within the upper tunnel.
{v) Optimization of Diversion Scheme
.
Given the considerations described above relative to design
flows, cofferdan configuration, and alternative types of
tunnels~ an economic study was undertaken to determine the
optimum combination of upstream cofferdan height and tunnel
diameter.
Capita 1 costs were developed for three heights of upstream
cofferdan embankment with a 30-foot-wide crest and exterior
slopes of 2H: 1 V. A freeboard allowance of 5 feet for set-
tl anent and wave run up and 10 feet for the effects of down-
stream ice j anming on ta i 1 water el ev at ions was adopted.
Capital costs for the 4, 700 foot long tunnel alternatives
included allowances for excavation, concrete liner, rock
bolts, and steel supports. Costs were a1so developed for
the upstr·eam and downstream portals, including excavation
and support. The cost of intake gate structures and as so ...
ciated gates was determined not to vary significantly with
tunnel diameter and was excluded from the analysis.
Curves of headwater elevation versus tunnel diameter fo'Y'
the various tunnel alternatives with submerged and free
outlets are presented in Figure 8.22. The relationship
between capital cost and crest elevation for the upstrean
cofferdan is shown in Figure B. 23. The capital cost for
various tunnel diameters with free and submerged outlets fs
given in Figure 8.24.
The results of the opt im i zat ian study are. presented in
Figure B.25 and indicate the following optimtm solutions
for each alternative.
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Diameter Cofferdam Crest
Type of Tunnel (feet) Elevation (ft) Total Cost {$)
Two
Two
Two
pressure tunnels 30 1595 66,000,000
free flow tunnels 32.5 1580 68~000,000
free flow tunnels 35 1555 69,000,000
The cost studies indicate that a relatively small cost dif-
ferentiai {4 to 5 percent) separates the various alterna-
tives for tunnel diameter from 30 to 35 feet.
(vi) Selected Diversion Scheme
An important consideration at this point is ease of coffer-
dan closure. For the pressure tunnel scheme, the invert of
the tunnel entrance is below riverbed elevation, and once
the tunnel ·;s complete diversion can be accomp1 ished with a
closure dam section approximately 10 feet high. The free
flow tunnel scheme, howe\/er, requires a tunnel invert
approximately 30 feet above the riverbed level, and diver-
sion would involve an end-dt.mped closure section 50 feet
high. The velocities of flows which w:Juld overtop the cof-
ferdan before the water 1 evel s were raised to reach the
tunnel invert level YK~uld be prohi_bitively higher resulting
in complete erosion of the cofferdan and hence the dual
free flow tunnel scheme was dropped from consideration.
Based on the preceeding considerations, a combination of
one pressure tunnel and one free flow tunnel (or pressure
tunnel with free outlet) was adopted. This wi 11 permit
initial diversion to be made using the lower pressure tun-
nel, thereby simplifying the critical closure operation and
avoiding potentially serious delays in the schedule. Two
alternatives were re-evaluated as follows:
Tunnel Diameter
(feet)
30
35
Upstream Coffer dam
Crest Elevation APproximate Height
{feet) (feet)
1595
1555
150
.110
More detailed layout studies indicated that the higher cof-
ferdan associated with the 30 foot diameter tunnel alterna-
tive would require locating the inlet portal further up-
strec.m into uThe Fi ns 11 shear zone. Since good rock
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conditions for portal construction are essential and the 35
fo<Jt diameter tunnel alternative would permit a portal
location downstrean of 11 The Fins 11 , this latter alternative
was adopted. As noted in (v), the overall cost difference
was not significant in the range of tunnel diameters con-
sidered, and the scheme incorporating two 35 foot diameter
tunnels with an upstream cofferdam crest elevation of 1555
was incorporated as part of the selected general arrange-ment. ·
Spillway F acil it ies Alternatives
As discussed in Subsection (c) above, the project has been
designed to safely pass floods with the following return fre-
quencies:
Flood Total Spillway
Discharge (cfs)
Spillway Design
Prob ab 1 e Maximum
Frequency
1:10,000 years 145,000
310,000 .
Discharge of the spillway design flood will require a gated ser-
vice spillway on either the left or right bank. Three basic al-
ternative spillway types were examined:
-Chute spillway with~flip bucket;
-Chute spillway with stilling basin; and
-Cascade spillwayo
Consideration was also given to combinations of these alternatives
with or without supplemental facilities such as valved tunnels and
an emergency spillway fu~e plug for handling the PMF discharge.
Clearly, the selected spillway alternatives will greatly influence
and be influenced by the project general arranganent.
(i) Energy Dissipation
The two chute spillway alternatives considered achieved
effective energy dissipation either by means of a flip
·bucket which directs the spillway discharge in .the fonn of
a free-fall jet into a plunge pool \E 11 downstrean from the
dam or a stilling basin at the end of the chute \'Alich dis-
sipates energy in a hydraulic jump. The cascade type
spillway 1 imits the free fall height of the discharge by
utilizing a series of 20 to 50 foot steps down to river
1 evel, with energy d i ssi pati on at each step.
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(g)
All spillway alternatives were assumed to incorporate a
concrete agee type contra 1 section contra 11 ed by fixed
r.oll er vertical 1 ift gates. Chute spillway sections were
asslJlled to be concrete-lined, with ample provision for air
entrainment in the chute to prevent cavitation, and with
pressure relief drains and rock anchors in the foundation.
( i i) E nviromnenta,l Mitigation
During development of the general arrangements for both the
Watana and Devil Canyon dans, a restriction was imposed on
the cmount. of excess dissolved nitrogen permitted in the
spillway discharges D Supersaturation occurs ~'/hen aerated
flows are subjected to pressures greater than 30 to 40 feet
of head which forces excess nitrogen into solution. This
occurs when water is subjected to the high pressures that
occur in deep plunge pools or at large hydraulic jumps.
The excess nitrogen would not be dissipated within the
downstreCitl Devil Canyon reservoir and a bui 1 dup of nitrogen
concentration caul d occur throughout the body of water. It
would eventually be discharged downstream from Devil Canyon
with harmful effects on the fish popu1 at ion. On the basis
of an evaluation of the related impacts and discussions
with interested federal and state agencies, spillway facil-
ities were designed to 1 imit discharges of water from
either Watana or Devil Canyon that may become supersat-
urated with nitrogen to a recurrence period of not less
than 1: 50 years.
Power Facilities Alternative .
Selection of the optimum power plant devel opnent involved consid-
eration of the following:
-Location, type and size of the power plant;
-Geotechnical considerations;
-Number, type, size and setting of generating units;
-Arranganent of intake and water passages; and
-Environmental constraints .
(i) Comparison of Surface and Underground Powerhouse
Studies were carried out to compare the construction costs
of a surface powerhouse and of an underground powerhouse at
Watana. These studies were undertaken on the basis of pre-
1 iminary conceptual 1 ayouts assuning six units and a total
installed capacity of 840 MW. The comparative cost est i-
mates for powerhouse civil works and electrical and mechan-
ical equillllent (excluding common items) indicated an
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advantage in favor of the underground poNerhouse of
$16,300,000. The additiqnal cost for the surface power-
house arrangenent is primarily associated with the longer
penstocks and the steel 1 inings required. Although con-
struction cost estimates for a 1020 MW p1 ant would be some-
what higher, the overall conclusion favoring the under-
ground location would not change.
The underground powerhouse arr.angenent is o.l so better
suited to the severe winter conditions in Alaska, is less
affected by river flood f1 ows in summer, and is aesthet-
ically less obtrusive. This arrangenent has therefore been
adopted for further development.
(ii) Comparison of Alternative Locations
Preliminary studies were undertaken during the developnent
of conceptual project 1 ayouts at Watana to investigate both
right and left bank locations for power facilities. The
configuration of the site is such that left bank locations
required longer penstock and/or tai 1 race tunnels and were
therefore more expensive.
The location on the left bank was further rejected because
of indications that the underground facilities \\Ould be
located in relatively poor quality rock. The underground
powerhouse. was therefore 1 ocated on the right bank such
that the major openings 1 ay between the two major shear
features ( uThe Fins" and the "Fingerbuster 11 ).
(iii) Underground Openings
Because no construction ad its or extensive dri 11 ing in the
powerhouse and tunnel locations nave been completed, it has
been assumed that full concrete-1 ining of the penstocks and
tailrace tunnels would be. required. This assunption is
conservative and is for preliminary design only; in prac-
tice, a large proportion of the tailrace tunnels would pro-
bably be unlined, depending on the actual rock quality en-
countered.
The min imt.."D center-to-center spacing of rock tunnels and
caverns has been assumed for 1 a}{)ut studies to be 2. 5 times
the width or diameter of the 1 arger excavation~
..
(iv) Selection of Turbines
The selection of turbine type is governed by the available
head and flow. For the design head and specific speed,
Francis type turbines have been selected. Francis turbines
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have a reasonably flat load-efficiency curve over a range
from about 50 percent to 115 percent of rated output with ·
peak efficiency of about 92 percent.
The nllllber and rating of individual units is discussed in
detail in Subsection (b) above. l11e final selected
arranganent comprised six units producing 170 MW each,
rated at minimum reservoir level (from reser·voir simulation
studies) in the peak danand month (December) at full gate.
The unit output at best effie iency and a rated head of 680
feet is 181 MW.
(v) Tt""ansformers
The selection of transformer type, size, location and
step-up rating is summarized below:
-Single phase transformers are required because of trans-
port 1 imitations on Alaskan roads and railways;
Direct transformation from 15 kV to 345 kV is preferred
for overall system transient stability;
-An underground transformer gal Jery has been selected for
minimum total cost of transformers, cab 1 es, bus, and
transformer 1 asses; and
- A grouped arrangenent of three sets of three single-phase
transfonners for each set of two units has been selected
(a total of nine transfonners) to reduce the physical
size of the transformer gallery and to provide a trans-
former spacing comparable with the unit spacing.
(vi) Power Intake and Water Pas sages
The power intake and approach channel are significant items
in the cost of the overall power facilities arrangenent.
The size of the intake is controll.ed by the number and min-
imum spacing between the penstocks, wh1ch in turn is d ic-
tated by geotechnical considerations.
The preferred penstock arrangement comprises six individual
penstocks, one for each turbine. With this arrangement, no
inlet valve is required in the powerhouse since turbine
dewatering can be performed by closing the control gate at
the intake and draining the penstocks and scroll case
through a valved bypass to the tailrace. flt1 alternative
a\ :--anganent with three penstocks was considered in detail
to \S.sess any possible advantages. This scheme would
requ1 ·'"e a bifurcation and two inlet valves on each penstock
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Item
and extra space in the. powerhouse to accommodate the inlet
valves. Estimates of relative cost differences are sum-
marized bel ow:
Cost Difference ($ x 106)
6 Penstocks 3 Penstocks
Intake
Penstocks
Bifurcations
Valves
Powerhouse
Capitalized Value of Extra Head Loss
Base Case
0
0
0
0
0
-20.0
-3.0
+ 3.0
+ 4.0
+ 8 .. 0
+ 6.0
Total
(vii)
0 -2.0
Despite a marginal saving of $2 mill ion (or less than 2
perce,,t in a total estimated cost of $120 mill ion) in favor
of three penstocks lt the arranganent of six indi\:1dual pen-
stocks has been retained. This arranganent provides im-
proved flexibility and security of operation . ..
The preliminary design of the power facilities involves t.10
ta i 1 race tunne 1 s 1 ead ing from a common surge chamber. fllt
alternative arrangenent with a single tailrace tunnel was
also considered, but no significant cost saving was
apparent.
Optimization studies on all water passages were carried out
to determine the min imun total cost of initial construction
plus the capitalized value of anticipated energy losses
caused by conduit friction, bends and changes of section.
For the penstock optimization, the construction costs of
the intake and approach channel were 1ncl uded as a function .
of the penstock diameter and spacing~ Similarly, in the
optimization studies for the tailrace tunnels the costs of
the surge chamber were included as a function .of tailrace
tunnel diameter.
Environmental Constraints
·Apart from the potential nitrogen supersaturation prob1an
discussed, the major environmental constraints. on the
design of the power facilities are:
-Control of down stream river temperatures; and
-Control of downstream flows.
The intake design has beeJ:l modified to enable power plant
flows to be drawn from the reservoir at four different
1 evel s throughout the anticipated range of reservoir
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drawdown for energy production in order to control the
downstream river temperatures within acceptable 1 imits.
Minimlll1 flows at Gold Creek during the critical summer
months have been studied to mitigate the project impacts on
s·almon spawning downstream of Devil Can.yon. These min imllll
flows represent a constraint on the reservoir operation and
influence the computation of average and firm energy pro-
duced by the Sus i tn a d eve 1 o flll en t •
The Watana deve1or:ment wi 11 be operated as a daily peaking
plant far load following. The actual extent of daily peak-
ing will be dictated by unit availability, unit ·size, sys-
tem danand, system stability~ generating costs, etc.
2. 3 -Selection of Watana General Arrangement
Preliminary alternative arrangenents of the Watana Project \\ere devel-
oped and subjected to a series of review and screening processes. The
1 ayouts selected from each screening process were developed in greater
detail prior to the next review and, where necessary, additional lay-
outs were prepared combining the features of two or more of the altern-
atives. Assunptions and criteria were evaluated at each stage and add-
itional data incorporated as necessary. The selection process followed
the general selection methodology established for the Susitna project
and is outlined belowo
(a) Selection Methodology
The determination of the project general arrangenent at Watana was
undertaken in three distinct revie,w stages: preliminary, inter-
mediate, and final.
(i) Preliminary Review (completed early in 1981)
This comprised four steps:
-Step 1: Assemble available data;
Detennine design criteria; ~nd
Establish evaluation criter1a.
-Step 2: Deve1op preliminary layouts and design criteria
based on the above duta including all plausible
alternatives for the -~!lrlStituent facilities and
structures.
-Step 3: Review all 1 ayouts on the basis of technical
feasib fl ity, readily apparent cost differences,
safety, and env ironmenta 1 impact.
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-Step 4: Select those layouts that can be identified as
most favorable, based on the evaluation criteria
established in Step 1, and taking into account
the preliminary nature of the work · at this
stage.
(ii) Int·ermediate Review {completed by mid-1981)
This involved a series of 5 steps:
-Step 1: Review all data, incot'"porating additional data
from other work tasks.
Review and expand design criteria to a greater
1 evel of detail.
Review evaluation criteria and modify, if neces-
sary.
-Step 2: Revise selected layouts on basis of the revised
criteria and additional data. Prepare p1 ans and
principal sections of layouts.
-Step 3: · Prepare quantity estimates for major structures
based on drawings prepared under Step 2.
Develop a preliminary construction schedule to
eva 1 uate whether or not the se 1 ected 1 ayo ut wi 11
allow completion of the project within the re-
quired time frame.
Prepare a preliminary contractor• s type estimate
to determine the overall cost of each scheme.
-Step 4: Review all layouts on the basis (}f technical
feasibility~ co.st impact of possible unknown
conditions and uncertainty of assumptions, safe-
ty, and environment a 1 impact.
-Step 5: Select the t\\0 most favorable layouts based on
the evaluation criteria determined under Step 1.
(iii) Final Review (completed early in 1982)
-Step 1: Assemble and review any additional data from
other work tasks.
Revise design criteria in accordance with addi-
tional available data.
Finalize overall evaluation criteria.
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-Step 2: Revise or_ further develop the two layouts on the
basis of input from Step 1 and determine overall
dimensions of structures, water passages, gates,
and other key i terns.
-Step 3: Prepare quantity take-offs for all major struc-
tures.
Review cost components within a preliminary con-
tractor• s type estimate using the most recent
data and criteria, and develop a construction
schedule.
Determine overall direct cost of schemes.
-Step 4: Review all layouts on the basis of practicabil-
ity, technical feasibility, cost, impact of pos-
sible unknown conditions, safety, and environ-
menta 1 impact.
-Step 5: Se 1 ect the final 1 ayout on the basis of the
evaluation criteria developed under Step 1.
(b) Design Data and Criteria
As discussed above, the review process included assembling rele-
vant design data, estab 1 ishing preliminary design criteria, and
expanding and refining· these data during the intermediate and
final reviews of the project arranganent. The design data and
design criteria which evolved through the final review are pr-e-
sented in Table 8.26.
(c) Evaluation Criteria
The various layouts wev-e evaluated at each stage of the review
process on the basis of the criteria summarized in Table B.27.
The criteria listed in Table B.27 illustrate the progressively
more detailed evaluation process leading to the final selected
arrangenent.
(d) Preliminary Review
The devel opnent selection studies described in Section 8, Vol tme 1
of Reference 4, involved comparisons of hydroelectric schemes at a
number of sites on the Susitna River. As part of these compari-
sons a preliminary conceptual design was developed for Watana in-
corporating a double stilling basin type spillway.
Eight further 1 ayouts were subsequently prepared and exani~ed fo.r
the Watana project during this preliminary review process in
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addition to the scheme shown on Figure 8.7. These eight layouts
are shown in schematic form on Figure B.25o Alternative 1 of
these 1 ayouts was the scheme recommended for further study in the
Deve 1 opment Section Report, Reference l.
This section describes the preliminary review undertaken of al-
ternative Watana layouts.
(i) Basis of Comparison of Alternatives
Although it was recognized that provision would have to be
made for downstream releases of water during filling of the
reservoir and for emergency reservoir drawdown, these fea-
tures were not incorporated in these preliminary 1 ayouts.
These facilities would either be interconnected with the
diversion tunnels or be provided for separately. Since the
system selected would be similar for all layouts with mini-
ma.l cost differences and 1 itt 1 e impact on other structures,
it was decided to exclude these facilities from overall
assessment at this early stage.
Ongoing geotechnical explorations had identified the two
major shear zones crossing the Susitna River and running
roughly parallel in the northwest direction. These zones
enclose a stretch of watercourse approximately 4500 feet in
length.. Preliminary evaluation of the existing geological
data indicated highly fractured and altered material~
within the actttal shear zones which would pose serious pro-
blems for conve~tional tunneling methods and would be un-
. suitable for founding of massive concrete structures. The
originally proposed dam axis<! was located between these
shear zones, and since no apparent major advantage appeared
to be gained from 1 arge changes in the dam location, 1 ay-
outs · generally were kept within the confines of these
bounding zones.
An earth and rockfi 11 dam was used as the basis for all
1 ayouts. The downstream s 1 ope of the dam was assumed as
2H:lV in all alternatives and upstream slopes varying be-
tween 2.5H:lV and 2.25H:1V were examined in order to deter ...
mine the influence of variance in the dam slope on the con-
gestion of the 1 ayout. In all prel imi nary arrangements
except the one shown on Plate 8. 2, cofferdams were incor-
porated within the body of the main dama
Floods greater than the routed 1:10,000 year spillway
design flood and up to the probable maximum flood were
assumed to be passed by surcharging the spillways, except
in cases where an unlinsd cascade or stilling basin type
spillway served as the s.ole discharge facility. In such
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instances, under large surcharges, these spillways would
not act as efficient energy dissipaters but would be
drowned out, acting as steep open channels with the possi-
bility of their· total destruction. In order to avoid such
an occurrence the design flood for these 1 atter spi 11 ways
was considered as the routed probable maximum flood.
On the basis of information existing at the time of the
preliminary review, it appeared that an underground power-
house could be located on either side of the river. A sur-
face powerhouse on the right bank appeared fea.sib1 e but was
precluded from the left bank by the close proximity of the
downstream toe of the dam and the adjacent broad shear
zone. Locating the powerhouse further downstream would
require tunneling across the shear zone, which would be
expensive, and would require excavating a talus slope.
·Furthermore, it was found that a 1 eft bank surface power-
house would either interfere with a 1 eft bank spillway or
would be directly impacted by discharges from a right bank
spillway.
(ii) Description of Alternative
-Doub1_e Stilling Basin Scheme
The scheme as shown on Figure B. 7 has a dan axis loca-
tion similar to that originally proposed by the COE, and
a right bank double stilling basin spillway. The spill-
way fallows the shortest 1 ine to the. river, avoiding
interference with the dam and discharging downstream
almost parallel to the flow into the center of the
r·iver. A substantial amount of excavation is rt::quired
for the chute and stilling basins~ although most of this
material could probably be used in the dan. A large
voltme of concrete is also required for this type of
spillway, resulting in a spillway system that wA>uld be
very costly. The maximum head dissipated within each
stilling basin is approximately 450 feet. Within world
experience, cavitation and erosion of the chute and
basins should not be a problem if the structures are
propel"ly designed. Extensive erosion downstream would
not be expected.
The diversion follows the shortest route, cutting the
bend of the river on the right bank, and has inlet
portals as far upstream as poss ib 1 e without having to
tunnel through "The Fins 11
• It .is possible that the
underground· powerhouse is in the area of 11 The Finger-
buster11, but the powerhouse could be located upstream
almost as far as · the system of drain hales and
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galleries just downstream of the main dan grout
curtain.
... Alternative 1
This alternative is that recommended for further study
in Reference 5 and is similar to the 1 ayout described
above except that the right side of the dam has been
rotated clockwise, the axis relocated upstream, and the
spillway changed to a chute and flip bucket. . The
revised dam alignment resulted in a s1 ight reduction in
total dan volt..me compared to tht~ above alternative. A
1 ocal ized downstream curve was introduced in the dan
close to the right abutment in ord·er to reduce the
length of the spillway. The alignment of the spillway
is almost parallel to the downstream section of the
river and it discharges into a pre-excavated plunge pool
in the river approximately 800 feet downstream from the
flip bucket. This type of spi 1 h,iay should be consider-
ably less costly than one incorporating a sti.lling
basin, provided that excessive pre-excavation .of bedrock
withfn the plunge pool area is not r·equired. Careful
design o.f the bucket wi 11 be required, however, to pre-
vent excessive erosion downstream causing undermining of
the valley sides and/or build up of material downstrean
which could cause elevation of the tailwater levels.
-Alternatives 2 through 20
Alternative 2 consists of a left bank cascade spillway
with the main dam axis curving downstream at the abut-
ments. The cascade spillway would require an extremely
1 arge vollllle of rock excavation but it is probable that
most of this material, with careful sched~l ing, could be
used in the dan. The excavation would cross •rTne
Fingerbustern and extensive dental concrete would be
required in that at"ea. In the upstrean portion of tbe
spillway, velocities \\()Uld be relatively high because of
the narrow· configuration of the channel, and erosion
could take place in this area in proximity to the dam ..
The discharge from the spillv1ay enters the river perpen-
dicular to the general flow but velocities would be rel-
atively low and should not cause substantial erosion
problems.. The powerhouse is in the most suitable loca-
tion for a surface alternative where the bedrock is
close to the surface and the overall rock slope is
approximately 2H:lV.
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Alternative 2A is similar to Alternative 2 except that
the upper end of the channel is divided and separate
control structures a\"'e provided. This division would
a 11 ow the use of one structure or upstream channe 1 whi 1 e
maintenance or remedial work is being performed on the
other.
Alternative 2B is similar to Alternative 2 except that
the cascade spillway is replaced by a daub 1 e st i 11 ing
basin type structure. This spillway is somewhat longer
than the simi 1 ar type of structure on the right bank in
the alternative described above. However, the slope of
the ground is less than the rather steep right bank and
may be easier to construct, a factor which may partly
mitigate the cost of the longer structure. The dis-
charge is at a sharp angle to the river and more concen-
trated than the cascade, which could cause erosion of
the opposite bank.
Alternat~ve 2C is a derivative of 2B with a similar
arrangenent, except that the double stilling basin
spillway is reduced in size and augmented by an addi-
tional emergency spi 1 hvay in the form of an inclined~
unlined rock channel. Under this arrangenent the con-
crete spillway acts as the main spillway, passing the
1:10,000 year design flood with greater flows passed
down the unl ined3 channel which is closed at its upstream
e:nd by an erodable fuse plug. The problems of erosion
of the opposite bank st i 11 remain, although these could
be overcome by excavation and/or slope protection.
Erosion of the chute would be extreme for significant
flows, although it i ~ highly un1 ikely that this emerg-
ency spillway would ever be used.
Alternat -ive 20 replaces th~ .r :ter ~<ig (".~ • n 1 t~"""" .,.~ ,;~~~ ~ . .. ._.,_ ,...,...,.;,. .. ,.. .. ...,. vr n1 I;OIIltl'-'IVC ·;c:;.
with a 1 ined chute and f1 ip bucket. The conments rel a-
t ive to the flip bucket are the same as for Alternative
1 except that the left bank location in this instance
requires a longer chute~ partly offset by lower con-
struction costs because of the flatter slope. The flip
bucket discharges· into the river at an angle which may
cause erosion of the opposite bank. The underground
powerhouse is located on the right bank, an arranganent
which provides an overall reduction of the length of the
water passages.
-Alternative 3
This arrangenent has a dan axis location slightly
upstream from Alternative ?, but retains the downstrean
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curve at the abutments. The main spillway is an unlined
rock. cascade on the left bank which passes the design
flood. Discharges beyond the 1: 10,000 year flood v.oul d
be discharged through the auxiliary concrete-1 ined chute
and flip bucket spillway on the right bank. A gated
control structure is provided for this auxiliary spill-
way which gives it the f1 ex ib il ity to be used as a back,-
up if maintenance should be required on the main spi 11-
way. Erosion of the cascade may be a prob1 em, as
mentioned previously, but erosion downstream should be a
1 ess important consideration because of the 1 ow unit
discharge and the infrequent operation of the spillway.
The diversion tunnels· are situated in the right abut-
mentS' as with previous arrangements, and are of similar
cost for all these alternatives.
-Alternative 4
This alternative involves rotating the axis of the main
dan so that the left abutment is relocated approximately
1000 feet downstream from its Alternative 2 location.
The relocation results in a reduction in the overall dam
quantities but would require siting the impervious core
of the dam directly over the ·uFingerbuster 11 shear zone
at maximlln dam height. The left bank spillway, consist-
ing of chute and flip bucket, is reduced in length com-
pared to other left bank locations, as are the power
facility water passages. The diversion tunnels are sit-
uated on the left bank; there is no advantage to a right
bank location, since the tunnels are of similar length
owing to the overall downstream relocation of the dan ..
Spillways and power fac i 1 ities would also be· 1 engthened
by a right bank location with this dan configuration.
' ... Selection of-Schemes for Further Study
A basic consideration during design develo}l11ent was that
the main dam core should not cross the major shear zones
because of the obvious problems with treatment· of tbe
foundationo Accordingly~ there is very little scope for
realigning the main dan apart from a slight rotation to
place it more at right angles to the river.
Location of the spillway on the right bank resu1ts in a
shorter distance to the river and allows discharges
almost parallel to the general direction of river flow.
The double stilling basin arrangement would be extremely
expensive, particularly if it must be designed to pass
the probable maximum flood. An alternative such as 2C
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would reduce the magnitude of design flood to be passed
by. the spillway b!.it would only be acceptable if an
emergency spillway with a high degree of op-erational
predictability could be constructed. A flip bucket
spillway an the. right bank, discharging directly down
the river, would appear to be an economic arrangement,
although some scour might occur in the plunge pool area ..
A cascade spillway on the left bank could be an accept-
able solution providing most of the excavated material
could be used in the dan~ and adequate rock conditions
existo
The length of diversion tunnels can be decreased if they
are located on tha right bank. In addition, the tunnels
would be accessible by a preliminary access road from
the north, which is the most 1 ikely route. This 'loca-
tion would also avoid the area of "The Fingerbustern and
the steep cliffs which would be encountered on the left
side close to the downstream dam toe~
The underground configuration assumed for the powerhouse
in. these preliminary studies allows for location on
either side of the river with a minimun of interferencs
with the surface structures.
Four of the preceding layouts~ or variations of them,
were se 1 ected fo.r further study:
• A variation of the double stilling basin scheme, but
with a-single sti 11 ing basin main spillway on the
right bank, a rock channel and fuse plug emet'gency
spillway, a left bank underground powerhouse and a
right bank d i v er s ion scheme;
. Alternative 1 with a right bank flip bucket spillway,
an underground powerhouse on the 1 eft bank, and right
bank diversion ;
• A variation of Alternative 2 with a reduced capacity
main spillway •and a right bank ro~k channel wi.th a
fuse plug serving as an emergency spillway; and
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• Alternative 4 with a left bank rock cascade spillway,
a right bank underground powerhouse, and a right bank
diversion.
(e) Intermediate Review
For the intermediate review process, the four schemes selected as
a result of the preliminary review were ex ani ned in more detail
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and modified. A description of each of the schemes is given below
and shown on Figures B. 27 through B. 32. The general locations of
the upstream and downstream shear zones ~hown on these plates are
approximate and have been refined on the b,asis of subsequent field
investigations for the proposed project.
( i) Description of A 1ternative Sche!fleS
The four schemes are shown on Figures B. 27 through B. 32.
Scheme WPl! (Figure 8 .. 27)
This scheme is a refinement of Alternative 1. The up-
str~an s'iope of the dam is flattened from 2.5:1 to
2. 7o~ 1.. This conserv at iv~ ·approach was adopted to pro-
vide an assessment of the possible impacts on project
1 ayout of conceivable measures which prove necessary in
dealing with severe earthquake design conditions. Un-
certainty wi·th regard to the nature of river alluvitm
also led to the location of the cofferdans outside the
1 imits of the main dam embankment. As a result of these
conditions,· the intake portals of the diversion tunnels
on the right bank are also _moved upstream from 11 The
Fins11 • A chute spillway with a flip bucket is located
· on the right bank. The underground powerhouse ts
located on the left bank.
-Scheme WP2 (Figures 8.29 and 8.30)
This scheme is derivsd from the double stilling basin
1 ayout. The main dam and diversion facilities are sim-
11 ar to Scheme WP! except that the do\"6\stream cofferdan
is relocated further downstream from the spillway outlet
and the diversion tunnels are correspondingly extended ..
The main spillway is 1 ocated on the r·ight bank, but the
two· sti 1 i ing basins of the preliminary DSR scheme are
combined into a sing 1 e stilling basin at the river
level. M emergency spillway is also located on the
right bank and consists of a channel excavated in rock~
discharging downstream from the ·area of the relict
channel. The channel is closed at its upstream end by a
compacted earthfill fuse plug and is capable of dis-
charging the flow differential between the probable
maximun flood and the 1: 10,000-year design flood of the
main spi 11way. The underground powerhouse .is 1 ocated on
the left bank.
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-Scheme WP3 (Figures 8.28 and 8.29)
This scheme is similar to Scheme WPl in all respects
except that an anergency spillway is added consisting of
right bank rock channel and fuse plug.
-Scheme WP4 (Figures B.31 and 8.32)
The dam 1ocation and geometry for Scheme WP4 are simi 1 ar
to that for the other schemes. The diversion is on the
right bank and discharges downstream from the powerhouse
tailrace outlet. A rock cascade spillway is located on
the· left bank and is served by two separate control
structures with downstream stilling basins. The under-
ground powerhouse is located on the right bank.
( i i) Compa~_i son of Schemes .
The main dam is in the same location and has the same con-
figuration for each of the four ·layouts considered. The
cofferdams have been located outside the limits of the main
dam in order to allow more extensive excavation of the
alluvial material and to ensure a sound rock foundation
beneath the complete area of the dam.. The overall design
of the dam is conservative, and it was recognized during
the evaluation that savings in both fill and excavation
costs can probably be made after more detailed study.
The diversion tunnels are located on the right bank. The
upstream flattening of the dam slope necessitates the loca-
tion of the diversion inlets upstream from "The Fins" shear
zone which would require extensive excavation and support
where the tunnels pass through this extremely poor rock
zone and could cause delays in the construction schedule.
A low-lying area exists on the right bank in the area of
the relict channel and requir.es approximately a 50-foot
high saddle dam for closure, given the reservoir :nperating
level assumed for the comparison study. However, the fin-
ally selected reservoir operating level will require only a
nominal freeboard structure at this location.
A summary of capital cost estimates for the four alterna-
tive schemes is g~ven in Table 8.28.
The results of this ;,~t .lrmediate analysis indicate that the
chute spillway with flip bucket (Scheme WPl) is the least
costly spillway alternative.
The scheme has the additional advantage of relatively
simple operating characteristics. The control structure
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has prov1s1on for surcharging to pass the design flood.
The probable maximum· flood can be passed by additional sur-
charging up to the crest level of the dam. In Scheme WP3 a
similar spillway is provided, except that the control
structure is reduced in size and discharges above the
routed design flood are passed tf,rough the rock channel
emergency spillway. The arrangement in Scheme WPl does not
provide a backup facility to the main spillway, so that if
repairs caused by excessive p1 unge poo 1 erosion or damage
to the structure itse.lf require removal of the spillway
from service. for any length of time, no alternative dis-
charge facility would be avail able. The additional spill-
way of Scheme WP3 would permit emergency discharge if it
were required under extreme circumstances.
The stilling basin sp.illway (Scheme WP2) 'llould reduce the
potential for extensive erosion do'lmstrearn, but high veloc-
ities in the lower part of the chute could cause cavitation
even with the provision for aeration of the discharge.
This type of spillway would be very costly, as can be seen
from Table 8.28.
The feasibility of the rock cascade spillway is entirely
dependent on the quality of the rock, which dictates the
amount of treatment required for the rack surface and a1 so
"the proportion of the excavated material which can be used
in the dam. For determining the capital cost of Scheme
WP4, conservative assumptions were made regarding surface
treatment and the portion of material that would have to be
wasted.
The diversion tunnels are located on the right bank for all
alternatives examined in the intermediate review. For
Scheme WP2, the downstream portals must be located down-
stream from the stilling basin, resulting in an increase of
approximately 800 feet in the length of the tunnels. The
left bank location of the powerhouse requires its placement
close to a suspected shear zone, with the tailrace tunnels
passing through this shear zone to reach the river. A
1 anger ac-cess tunne 1 is a 1 so required, together with an
additional 1,000 feet in the length of the tailrace. Th~
left-side location is remote from the main access road~
which will probably be on the north side of the river, as
will the transmission corridor.
Selet:tion of Schemes for Further Study
Examination of the technical and economic aspects of Scheme
WPl through l~P4 indicates there is 1 ittle scope for adjust-
ment of the dam axis owing to t~e confinement imposed by
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the upstream and downstream shear zones. In add it ion, pas-
sage of the diversion tunnels through the upstream shear
zone could result in significant delays in construction and
additional cost •
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From a comparison of costs \n Table Bs28, it can be seen
that the flip bucket type spillway is the most economical,
but because of the potential for erosion under extensive
operation it is undesirable to use it as the on1y discharge
faci 1 ity. A m i d-1 eve 1 re 1 ease wi 1 1 be required for emer-
gency drawdown of the reservoir, and use of this release as
the first-stage service spillway with the flip bucket as a
backup facility would combine flexibility and safety of
operation with reasonable cost.. The emergency rock channel
spillway would be retained for discharge of flows above the
r'outed 1: 10,000-year flood.
The stilling basin spillway is very costly and the operat-
ing head of 800 feet is beyond precedent experience. Ero-
sion downstream should not be a problem but cavitation of
the chute caul d occur. Scheme WP2 was therefore eliminated
from further consideration •
The cascade spillway was also not favored for technical and
economic reasons. However, this arrangement does have an
advantage in that it provides a means of preventing nitro-
gen supersaturation in the downstream discharges from the
project which could be harmful to the fish P.opul ation. A
cascade configuration would redu~e the dissolved nitrogen
content; hence, this alternative was retained for further
evaluation. The capacity of the cascade was reduced and
the emergency rock channel spillway was included to take
the extreme floods.
The results of the intermediate review indicated that the
follm'ling components should be incorporated into any scheme
carried forward for final review:
-Two diversion tunnels located on the right bank of the
river;
-·An underground powerhouse also located on the right
bank;
An emergency spillway, compr1 s 1ng a rock channel exca-
vated on the right bank and discharging well downstream
from the right abutment. The channel is sealed by an
erodible fuse plug of impervious material designed to
fail if overtopped by the reservoir; and
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- A compacted earthfill and rockfill dam situated between
the two major shear zones which traverse the project
site.
As discussed above, two specific alternative methods exist
with respect to routing of the spillway design flood and
minimizing the adverse effects of nitrogen supersaturation
on the downstream fish population. These alternatives
are:
- A chute spillway with flip bucket on the right bank to
pass the spillway design flood, with a mid-level release
system designed to operate for floods with a frequency of
up to about 1:50 years; or
- A cascade .spillway on the 1 eft bank ..
Accordingly, two schemes were developed for further evalua-
tion as part of the final review process. These schemes
are described separately in the paragraphs below.
(f) Final Review
The two schemes considered in the final review process were essen-
tially derivations of Schemes WP3 and WP4.
(i) Scheme WP3A (Figure 8.33)
This scheme is a modified version of Scheme WP3 described
above.. Because of scheduling and cost considerations, it
is extremely important to maintain the diversion tunnels
downstream from "The Fins.11 It is also important to keep
the dam axis as far upstream as possible to avoid conges-
tion of the do\'mstream structures. For thes·e reasons, the
inlet portals to the diversion tunnels wet"e located in the
sound bedrock forming the downstream boundary of uThe
Fins." The upstream cofferdam and main dam are maintained
in the upstream locations as shown on Figure 8.33. As
mentioned previously, additional criteria have necessitated
modifications in the spillway configuration, and low-level
and emergency drawdown outlets have been introduced.
The main modifications to the scheme are as follows:
-Main Dam
Continuing preliminary design studies and review of world
practice suggest that an upstream slope of 2.4H:lV wou'ld
be acceptable for the rock shell. Adoption of this slope
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results not only in a reduction in dam fill volume but
also in a reduction in the base \'Jidth of the dam which
permits the main project components to be located between
the major shear zones.
The downstream slope of. the dam is retained as 2H:lV.
The cofferdams remain outside the 1 imits of the dam in
order to allow complete excavation of the riverbed allu-
vium ..
-Diversion
In the intermediate review arrangements, diversion tun-
ne 1 s passed through the broad structure of 11 The Fins," an
intensely sheared area of breccia, gouge, and infi lls ..
Tunneling of this material would be difficult, and might
even require excavation in open cut from the surface.
High cost would be involved, bu: more important would be
the time taken for construction in this area and the pos-
sibi 1 ity of unexpected delays. For this reason, the
in·let portals have. been relocated downstream from this
zone with the tunnels located closer to the river and
crossing the main system of jointing at approximately
45t\ ~ This arrangement allows for shorter tunnels with a
more favorable orientation of the inlet and outlet
portals with respect to the river flow directions.
A separate low-level inlet and concrete-lined tunnel is
provided, 1 ead ing from the reservoir at approximate E1 e-
vation 1550 to downstream of the diversion plug where it
merges with the diversion tunnel closest to the river.
This low-level tunnel is designed to pass flows up to
6000 cfs ·during reservoir filling. It would also pass up
to 30,000 cfs under 500-foot head to allow emergency
draining of the reservoir.
Initial closure is made by lowering the gates to the tun-
nel located closest to the river and constructing a con-
crete closure plug in the tunnel at the location of the
grout curtain underlying the core of the main dam.. On
completion of the plug, the low-level release is opened
and controlled discharges are passed downstream. The
closure gates within the second diversion tunnel portal
are then closed and a concl"'ete closure plug constructed
in line with the grout curtain. After closure of the·
gates, filling of the reservoir would commence.
-Outle.t Facilities
As a provision for drawing down the reservoir in case of
emergency, a mid-level release is provided. The intake
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to these facilities is located at depth adjacent to the
power facilities intake structures. Flows would then be
passed downstream through a concrete-lined tunnel, dis-
charging beneath the downstream end of the main spillway
f1 ip bucket. In order to overcome potential nitrogen
supersaturation problems, Scheme WP3A also incorporates a
system of fixed cone valves at the downstream end of the
vutlet facilities. The valves were sized to discharge in
ccr:junction with the powerhouse operating at 7000 cfs
capacity (flows up to the equivalent routed 50-year
flood). Six cone valves are required, located on
branches off a steel manifold and protected by individual
upstream closure gates. The valves are partly incor-
porated into the mass concrete block forming the flip
bucket of the main spillway. The rock downstream is pro-
tected from erosion by a concrete facing slab anchored
back to the sound bedrock.
-Spillways·
As discussed above, the designed operation of the main
spillway facilities was arranged to limit discharges of
potentially nitrogen-supersaturated water from Watana to
flows having an equivalent return period greater than
1:50 years ..
The main chute spillway and flip bucket discharge into an
excavated plunge pool in the downstream river bed. Re-
1 eases are contra lled by a three-gated ogee structure
located adjacent to the outlet faci1 it'ies and power
intake structure just upstream from the da11 centerline.
The design discharge is approximately 114,000 cfs, cor-
responding to the rou~ed 1:10,000-year flood (145,000
cfs) reduced by the 31,000 cfs flows attri butab 1 e to out-
let and power facilities discharges. The plunge pool is
formed by excavating the alluvial river deposits to bed-
. rock. Si nee the excavated p 1 unge poo 1 approaches the
limits of the calculated maximum scour hole, it is not
anticipated that, given the infrequent discharges, sig-
nificant downstream erosion will occur.
An emergency spillway is provided by means of a ci'lannel
excavated in· rock on the right bank, discharging ~~11
downstream from the right abutment in the direction of
Tsusen~ Creek. The channel is sealed by an erodible fuse
plug of impervious material designed to fail if over ...
topped by the reservoir, although some preliminary exca-
vation may be necessary.. The crest level of the plug
wi"ll be set at Elevation 2230, well below that of the
main dam. The channel will be capable of passing the
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excess discharge of floods ·greater than the 1:10,000-
year flood up to the· probable maximum floqd of 310:.000
cfs.
-Power Facilities
The power intake is set slightly upstream from the dam
axis deep within sound bedrock at the downstream end of
the approach channel. The intake consists of six units
with provision in each unit for drawing flows from a
variety of depths covering the complete drawdown range
of the reservoir. This facility also provides for draw-
ing water from the different temperature strata within
the upper part of the reservoir and thus regulating the
temperature of the downstream discharges close to the
natural temperatures of the river. For this preliminary
conceptual arrangement, flow withdrawals from different
levels are achieved by a series of upstream vertical
shutters moving in .a single set of guides and operated
to form openings at the required level. Downstream fram
these shutters each unit has a pair of wheel-mounted
closure gates which will isolate the individual pen-
stocks.
The si.x penstocks are 18-foot-di ameter, concrete ... 1 ined
tunnels inclined at 55° immediately downstream from the
intake to a nearly horizontal portion leading to the
powerhouse. This horizontal portion· is steel-lined for
150 feet upstream from the turbine units to extend the
seepage path to the powerhouse and reduce the flow with-
in the fractured rock area caused by b1 asting in the
adjacent powerhouse cavern.
The six 170 MW turbine/generator units are housed within
the major powerhouse cavern and are serviced by an over-
head crane which runs the 1 ength of the powerhouse and
into the service area adjacent to the units. Switch-
gear, maintenance rooriT and offices are located within
the main cavern, with the transformers situated down-
stream in a separate gallery excavated above the ta.il-
race. tunnels. Six inclined tunnels carry the connecting
bus ducts from the main power ha11 to the transformer
gallery. A vertical elevator and vent shaft run from
the power cavern to the main office building and control
room located at the surface. Vertical cable shafts, one
for each pair of transformers., connect the transformer
gallery to the switchyard directly -overhead. Downstream
from the transformer gallery, thu underlying draft tube
tunne 1 s merge into two surge chambers (one chamber for
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three draft tubes) which also house the draft tube gates
for iso1atif1g the units from the tailrace.. The gates
are operated by an overhead traveling gantry located in
the upper part of each of the surge chambers. Emerging
from the ends of the chambers, two concrete-1 ined, low-
pressure tai 1 race tunne 1 s carry the discharges to the
river. Because of space restrictions at the river, one
of these tunnels has been merged with the downstream end
of the diversion tunnel. The other tunnel emerges in a
separate portal with provision for the installation of
bulkhead gates.
The orientation of water passages and underground cav-
erns is such as to avoid 51 as far as possible, alignment
of the main excavations with the major joint sets.
Access
Access is assumed to be from the north (right) side of
the river. Permanent access to structures close to the
river is by a road along the right downstream river bank
and then via a tunnel passing through the concrete form-
ing the flip bucket. A tunnel from this point to the
power cavern provides fof vehicular access. A secondary
access road across the crest of the dam passes down the
left bank of the valley and across the lower part of the
dam.
(ii) Scheme WP4A (Figure 8.34)
This scheme is similar in most respects to Scheme WP3A pre-
viously discussed, except for the spillway arranganents.
-Main Dam
The main dam axis is similar to that of Scheme WP3A!t
except for a slight downstream rotation at the left
abutment at the spillway control structures ..
-Diversion
The diversion and low level releases are the same for
the two schemes.
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Outlet Facilities
The outlet facilities used for emergency drawdown are
separate from the main spi 11 way for this scheme. The
outlet facilities consists of a low-level gated inlet
structure discharging up to 30,000 cfs into the river
through a concrete-lined~ free-fiow tunnel with a ski
j tmp f1 ip bucket. This facility may also be operated as
an auxiliary outlet to augment the main left bank spi.ll-
way.
-Spillways
The main left bank spillway is capable of passing a
design flow equivalent to the 1:10,000-year flood
through a series of 50-foot drops into shallow pre-
excavated plunge pools. The emergency spillway is
designed to operate during floods of greater magnitude
up to and including the ~4F.
Main spillway discharges are controlled by a broad
multi-gated control structure discharging into a shallow
stilling basin. The feasibility of this arrangenent is
governed by the quality of the rock in the area, requir-
ing both durability to withsta,nd erosion caused by
spillway flows and a high percentage of sound rockfi11
material that can be used from the excavation directly
in the main dam. ·
On the basis of the site information developed concur-
rently with the general arrangenent studies, it beccme
apparent that the major shear zone known to exist in the
1 eft bank area extended further downstrecm than initial
studies have indicated. The cascade spill\'Jay channel
was therl:fore 1 engthened to avoid the shear area at the
1 ower end of the cascade. The arrangan~nt shown on
Figure B.34 for Scheme WP4A does not reflect this relo-
cation, \\thich would increase the overall cost of the
scheme.
The emergency spillway consisting of rock channel and
fuse plug is similar to that of the right bank spillway
scheme.
-Power Facilities
The power facilities are similar to those in Scheme
WP3A.
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(iii} Evaluation of Final A lternnt ive Schemes
An evaluation of the dissimilar features for each arrange-
ment (the main spillways and the discharge arrangenents at
the downstream end of the outlets) indicates a saving in
capital cost of $197,000,000, excluding contingencies and
indirect cost, in favor of Scheme WP3A. If this difference
is adjusted for the savings associated with using a.'l appro-
priate proportion of excavated material from .the cascade
spillway as rockfi 11 in the main dam, this represents a net
overall cost difference of approxiMately $110,000,000 in-
cluding contingencies, engineering, and administration costs ..
As discussed above, although limited information exists
regarding the quality of the rock in the downstream area on
the left bank, it is known that a major shear zone runs
through and is adjacent to the area presently a 11 ocated to
the spillway in Scheme WP4. This would require relocating
the left bank cascade spillway several hundred feet farther
downstrean into an area where the rock quality is unknown
and the topography less suited to the ·gentle overall slope
of the cascadeo The cost of the excavation \\Ould substan-
tially increase compared to previous assumptions, irrespec-
tive of the rock quality. In addition, the resistance of
the rock to erosion and the sui tab i 1 ity for use as exca-
vated material in the main dam would become less certain.
The economic feasibility of this scheme is largely predi-
cated on this last factor, since the ability to use the
material as a source of rockfi 11 for the main dam repre-
sents a major cost saving. ·
In conjunction with the main chute spillway, the problem of
the occurrence of nitrogen supersaturation can be overcome
by the use of a regularly operated dispersion type valve
outlet facility in conjunction with the main chute spill-
way. Since this scheme presents a more economic solution
with fewer potential problems concerning the geotechnical
aspects of its design, the right bank chute arrangenent
(Scheme WP3A) has been adopted as the final selected
scheme.
2.4-Selection of Devil Canyon General Arrangement
This section describes the develolltlent of the general arrangenent of
tbe Devil Canyon project. The method of handling floods during con-
struction and subsequent project operation is also outlined iVl this section.
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The reserva·fr level fluctuations and inflow for Devil Canyon will es-
sentially be controlled by operation of the upstream Watana project.
This aspect is also briefly discussed in this section.
(a) Selection of Reservoir Level
(b)
The selected normal maximum operating level at Devil Canyon dam is
El ev at ion 1455. Studies by the USBR and COE o ~ the Dev i 1 Canyon
Project were essentially based on a similar reservoir level which
corresponds to the tailwater level selected at the Watana site.
Although the narrow configuration of the Devil Canyon site and the
relatively low costs involved in increasing the dam height suggest
that it might be economic to do so, it is clear that the upper
economic 1 imit of reservoir level at Devil Canyon is the Watana tailrace level.
Although significantly lower re~ervoir levels at Devil Canyon
would lead to lower dam costs, the location of adequate spillway
facilities in the narrow gorge would become extremely difficult
and lead to offsetting incr·eases in cost. In the extreme case, a
spillway discJ-.arging over the dam would raise concerns regarding
safety from scouring at the toe of the dam which have already led
to rejection of such schemes.
Selection of Installed Capacity
--------------~----~-----
The methodology used for the preliminary selection of installed
capacity at Watana and Deviil Canyon is described in Section 2.2 (b).
The . deci sian to operate Devil Canyon primarily as a base-loaded
plant was governed by the following main considerations:
-Daily peaking is more effectively performed at Watana than at
Devil Canyon; and
-Excessive fluctuations in discharge from the Devi 1 Canyon dan
may have an undesirable impact on mitigation measures incorpor-
ated in the final design to pt-oject the downstream fisheries.
Given this mode of operation, the required installed capacity at
Devil Canyon has been determined as the maximum capacity needed to
utilize the available energy from the hydrological flows of
record, as modified by the reservoir operation rule curves. In
·years where the energy from Wat<tna and Devil Canyon exceeds the
system demand, the usable energy has been reduced at both stations
in proportion to the average net head available, assuming that
flows used to generate energy at i~atana will also be used to gen-
erate energy at De vi 1 Canyon.
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(c)
The total capacity required at Devil Canyon in a wet year, exclud-
ing standby and spinning reserve capacity, is summarized below.
The capacity shown is based on the December 1981 ·medium load
growth forecast.
Demand Year
2002
2005
2010
Capacity friW
370
410
507
The selected total installed capa.city at Devil Canyon has been
established as 600 MW for design purposes. This will provide some
margin for standby during forced outage and possible accelerated
growth in demand.
The major factors governing the selection of the unit size at
Devi 1 Canyon are the rate of growth of system demand, the minimum
station output, and the requirement of standby capacity under
forced outage conditions. The above tabulation indicates that
station maximum load in December will increase by about 50 percent
from 2002 to 2010 (from 370 MW to 507 MW). Station minimum output
in Ju 1 y , during the same period wi 11 vary from about 150 MW to 202 ·
MW. ~
The power facilities at Devil Canyon have been developed us.ing
four units at 150 MW each. This arrangement will provide for
efficient station operation during low load periods as well as
·during peak December loads. During final design, consideration of
phasing of installed capacity to match the system demand may be
desirable. However, the uncertainty of load forecasts and the
additional contractual costs of mobilization for equipment instal-
lation are such that for this study it has been assumed that all
units will be commissioned by 2002.
The Oev i 1 Canyon reservoir wi 11 usually be full in December;
hence, any forced outage could result in spilling and a loss of
. available energy. The units have been rated to deliver 150 MW at
maximum December-drawdown occuring during an extremely dry year;
this means that in an average year, with higher reservoir le• ·als
~ the full s:tation output can be maintained even with one unit on
forced outage ..
Selection of Spillway Capacity
A flood frequency of 1:10,000 years was selected for the spillway
design on the same basis as described for Watana. An emergency
spillway with. an erodible fuse plug will also be provided to
safely discharge the probable maximum flood. The development plan
envisages completion of the Watana project prior to construction
at Devil Canyon. Accordingly, the inflow flood peaks at Devil
Canyon will be ·less than pre-project flood peaks because of rout-
ing through the Watana reservoir. Spillway design floods are:
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(d)
Flood
1:10,000 years
Probable Maximum
Inflow Peak (cfs)
165,000
346,000
The avoidance of nitrogen supersaturation in the do.wnstrearn flow
for Watana also will apply to Devil Canyon •. Thus, the discharge
of water possibly supersaturated with nitrogen from Devil Canyon
will be limited to a recurrence period of not less than 1:50 years
by the use of solid cone valves similar to Watana.
Main Dam Alternatives
The location of the Devil Canyon. damsite wa-s -ex-am-ined during pre-
vious studies by the USBR and COE. These studies focused on the
·narrow entrance to the canyon and led to the recommendation of a
concrete arch dam. Notwithstanding this initial appraisal, a com-
parative analysis was undertaken as part of this feasibi 1 ity study
to evaluate the re1ative merits of the following types of struc-
tures at the same 1 ocati on: ·
-Thick concrete arch;
-Thin concrete arch; and
-Fill embankment •
( i) Gompari son of Embankment and Concrete Type Dams
The geometry was developed for both the thin concrete arch
and the thick concrete arch dam and the dams were analyzed
and their behavior compared under static, hydrostatic, and
seismic loading conditions. The project layouts for these
arch dams were compared to a 1 ayout for a rockfi 11 dam with
its associated structures.
Consideration of the central core rockfi11 dan layout indi-
cated relatively small cost differences from an arch dan
cost estimate, based on a cross-section significantly
thicker than the finally selected design'" Furthermore, no
information was available to indicate that impervious core
material in the necessary quantities could be found within
a reasonabJe distance of the damsite. The rockfill dam was
accordingly dropped from further consideration. [It is
further noted that since this alternative dam study~ seis-
mic analysis of the rockfill dam at Watana has resulted in
an upstream slope 1:2.4, thus indicating the requirement to
flatten the 1:1.25 slope adopted for the rockfill dam
alternative at.Devil Canyon.]
Neither of the concrete arch dam 1 ayouts were intended as
the final site arrangement, but were sufficiently repre-
serttative of the most suitable ar~angemsnt associated with
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each dam type to provide an adequate basis for comparison.
Each type of dam was located just downstream from where the
river enters Devil Canyon and close to the canyon's narrow-
est point, which is the optimum location for all types of
dams. A brief description of each dam type and configura-
tion is given below.
-Rockfi 11 Dam
For this arrangement the dam axis is .some 625 feet down-
stream of the crown sect ion of the concrete dams. The
assumed embankment slopes are 2.25 H:lV on the upstream
face and 2H:lV on the downstream face. The main dam is
continuous with the left bank saddle dam, and therefPre
no thrust b 1 ocks are required. The crest 1 ength is 2200
feet at Elevation 1470; the crest width is 50 feet.
The dam is constructed with a central impervious core~
inclined upstream, supported on the downstream side by a
semi-pervious zone. These two zones are protected up-
stream and downstream by filter and transition materials.
The shell sections are constructed of rockfill obtained
from blasted bedrock. For preliminary design all -dam
sections are assumed to be founded on rock; external cof-
ferdams are founded on the river alluvium, and are not
incorporated into the main dam. The approximate volume
of material in the main dam is 20 million cubic yards.
A sing 1 e spi 11 way is provided on the right abutment to
control all flood flows. It consists of a gate control
structure and a daub 1 e sti 11 ing bas in excavated into
rock; the chute sections and stilling basins are
concrete-lined, with mass concrete gravity retaining
walls. The design capacity is sufficient to pass the
1-in-10,000 year flood without damage; excess capacity is
provided to pass the PMF, without damage to the main dam~
by surcharging the reservoir and spillway •
The powerhouse is located underground in the right abut-
ment. The multi-level power intake is constructed in a
rock cut in the right abutment on the dam centerline,
with four independent penstocks to the 150 MW Francis
turbines. Twin concrete-lined tailrace tunnels connect
the powerhouse to the 'river via an intermediate draft
tube manifold.
-Thick Arch Dam
The main concrete dam waul d be a single center arch
structure, acting partly as a gravity dam, with ;. a
vertical cylindrical upstream face and a slopi.ng
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downstrea11 face inclined at 1V:0.4H. The maximum height
of the dam would be 635 feet with a uniform crest width
of 30 feet, a crest length of approximately 1~400 feet,
and a maximum fa und at ion width of 225 feet. The crest
elevation would be 1460. The center portion of tlu~ dam
would be founded on a massive mass concrete pad con-
structed in the excavated river bed. This central
section would fncorporate the main spillway with sidt:-
walls anchored into solid bedrock and gated orifice
spil iways discharging down the steeply inclined. down-
stream face of the dam into a single large stilling
basin set below river level and spanning the valley.
The main dam would terminate in thrust blocks high on
the abutments. The left abutment thrust block would
incorporate an emergency gated control spillway struc-
ture which would discharge into a rock channel running
well downstream and terminating at a level high above
the river valley.
Beyond the control structure and thrust block, a low-
lying saddle on the left abutment would be closed by
means of a rockfi11 dike founded on bedrock. The power-
house would house four 150 MW units and will be located
underground within the right abutment. The intake would
be constructed integrally with the dam and conn~cted to
the powerhouse by vertical steel-lined penstocks.
The main spillway would be designed to pass the
1:10,000-year routed flood with larger floods discharged
downstream via the emergency spillway.
-Thin Arch Dam
The main dam waul d be a two-center, doub 1 e-curved arch
structure of similar height to the thick arch dam, but
with a 20-foot uniform crest and a maximum base width of
90 feet. The crest elevation would be 1460.. The center
section would be founded on a concrete pad, and the
extreme upper portion of the dam would terminate in con-
crete thrust blocks located on the abutments.
The main spillway would be located on the right abutment
and would consist of a conventional gated control struc-
ture discharging down a concrete-lined chute terminating
in a flip bucket. The bucket would discharge into an
unlined plunge pool excavated in the riverbed alluvium
and located sufficiently downstream to prevent under-
mining of the dam and associated structures.
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The main spillway would be supplemented by orifice type
spillways located high in the center portion of the dam
which would discharge into a concrete-lined plunge pool
immediately downstream from the dam. An emergency
spillway·, consisting of a fuse plug discharging into an
unlined rock channel terminating well downstream, would
be located beyond the saddle dam on the left abutment.
The concrete dam would terminate in a massive thrust
b 1 ock on each· abutment which, on the 1 eft abutment~
would adjoin a rockfill saddle dam.
The main and auxiliary spillways would be designed to
discharge the 1: 10,000-year flood. Larger floods for
storms up to the probable maximum flood would be. dis-
charged through the emergency left abutment spillway ..
-Comparison of Arch Dam JYE~.
Sand and gravel for concrete aggregates are believed to
be available in sufficient quantities within economic
distance from the damsite. The gravel and sands are
formed from the granitic and metamorphic rocks of the
area; at this time it is anticipated that they will be
suitable for the production of aggregates after screen-
ing and washing •
The bedrock geology of the site is discussea in Re-fer-
ence 3. At this time it appears that there are no geo-
logical or geotechnical concerns that would preclude
either of the dam types from consideration.
Under hydrostatic and temperature loadings, stresses
within the thick arch darn would be generally lower than
for the thin arch alternative. However, finite element
analysis has shown that the additional mass of the dam
under seismic .loading would produce stresses of a
greater magnitude in the thick arch dam than in the thin
arch dam. If the surface stresses approach the maximum
allowable at a particular section~ the remaining under-
stressed area of concrete will be greater for the thick
arch, and the factor of safety for the dam would be cor-
respondingly higher. The thin arch is, however, a more
efficient design and better utilizes the inherent pro-
perties of the concrete. It is designed around accept-
able predetermined factors of safety and requires a much
smaller volume of concrete for the actual dam struc-
ture.
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(iii) Cofferda~s
As at Watana, the considerable depth of riverbed alluvium
at both cofferdarn sites indicates that anbankment-type cof-
ferdan structures would be the only technically and econom-
ically feasible alternative at Devil Canyon. For the pur-
poses of establishing the overall general arranganent of
the project and for subsequent diversion optimization
studies, the upstream cofferdam section adopted wi 11 com-
prise an initial closure section approximately 20 feet high
constructed in the wet, with a zoned embankment constructed
in the dry. The downstream cofferdan will comprise a clos-
ure dam structure approximately 30 feet high placed in the
wet.. Control of underseepage through the alluvium material
may be required and could be achieved by means of a grouted
zone. The coarse natur.:: of the alluvium at Devil Canyon
led to the selection of a grouted zone rather than a slurry
wall.
( iv) Diver·sion Tunnels
Although studies for the Watana project indicated that
concrete-lined tunnels were the most. economically and tech-
nically feasible solution, this aspect was reexamined at
Devil Canyon.. Preliminary hydraulic studies indicated that
the design flood routed through the diversion scheme would
result in a design discharge of approximately 37,800 cfs.
For concrete-lined tunnels, design velocities of approxi-
mately 50 ft/s would permit the use of one concrete-lined
tunnel with an equivalent diameter of 30 feet. Alterna-
tively, for unlined tunnels a maximum design velocity of 10
ft/s in good quality rock would require four unlined tun-
nels, each with an equivalent diameter of 35 feet, to pass
the design flow. As was the case for the Watana diversion
scheme, considerations of reliability and cost were
considered sufficient to eliminate consideration of unlined
tunnels for the diversion scheme.
For the purposes of optimization studies, only a pressure
tunnel was considered, since previous studies indicated
that cofferdam closure problems associated with free-flow
tunnels would more than offset their other advantages.
(iii) Optimization of Diversion Scheme
Given the considerations described above relative to design
flows, cofferdan configuration, and alternative types of
tunnels!t an economic study was undertaken to determine the
optimum combination of upstream cofferdam elevation
(height) and tunnel diameter.
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(e)
The thick arch arrangement did not appear to . have a
distinct technical advantage compared to a thin arch dam
and would be more expensive because of the larger volume
of concrete needed. Studies, therefore, continued on
refining the feasibility of the thin arch alternative.
(ii) Concrete--face Rockfill Dam Alternative (to be written)
Diversion Scheme Alternatives
In this section the selection of general arrangement and the basis
for sizing of the diversion schema are presented.
(i) General Arrangements
The steep walled valley at the site essentially dictated
that diversion of the ~river during construction be accom-
plished using one or two diversion tunnels, with upstream
and downstream cofferdams protecting the main construction
area.
The selection process for establishing the final general
arrangement included examination of tunnel locations on
both banks of the river. Rock conditions for tunneling did
not favor one bank over the other. Access and ease of con-..
struction strongly favored the left bank or abutment~ the
obvious approach being via the alluvial fan. The total
length of tunnel required for the left bank is approxi-
mately 300 feet greater; however, access to the right ba.nk
could not be achieved without great difficulty.
(ii} Design Flood for Qiversion
The recurrence interval of the design flood for diversion·
was established in the same manner as for Watana dam.
Accordingly, at Devil Canyon a risk of exceedence of 10
percent per annum has been adopted, equivalent to a design
flood with a 1:10-year return period for each year of cr:it-
i cal construction exposure. The critical construction
time is estimated at 2.5 years. The main dam could be
subjected to overtopping during construction without caus-
ing serious damage, and the existence of the Watana facil-·
ity upstream will offer considerable assistance in flow
regulation in case of an emergency. These considerations.
led to the selection of the design flood with a return fre-
quency of 1:25 years.
The equivalent inflow, together with average flow charac-
teristics of the river significant to diver-?ion, are pre-
sented below:
-Average annual flow: 9,040 cfs
-Design flood inflow (1:25 years routed
through Watana reservoir): 37,800 cfs
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Capital costs were developed for a range of pressure tunnel
diameters and corresponding upstream cofferdam embankment
crest elevations with a 30-foot wide crest and exterior
s 1 opes of 2H :TV. A freeboard a 11 owance of 5 feet was
included for settlenent and wave runup.
Capital costs for the tunnel alternatives included allow-
ances for excavation, concrete liner, rock bolts, and steel
supports. Costs were also developed for the upstream and
downstream portals, including excavation and support. The,
cost of en intake gate $'Ci""I.Jcture and associ a ted gates was
determined not to vary significantly with tunnel dia'lleter
and was excluded from the analysis.
The centerline tunnel length in all cases was estimated to
be 2,000 feet.
Rating curves for the single-pressure tunnel altern~tives
are presented in Figure 8:35. The relationship between
capital costs for the upstream cofferdam and various tunnel
diameters is given in Figure 8.36.
The results of the optimization , study indicated that a
single 30-foot-diameter pressure tunrel results in the
overall least cost (Figure 8.36). An upstre.am cofferdam 60
feet high, with a crest elevation of 945, was carried for-
ward as part of the selected general ·arrangement.
(f) Spillway Alternatives
The project spillways have been designed to safely pass floods
with the following return frequencies:
Inflow Peak
Flood
Spillway Design
Probable Maximum.
Discharge
Frequency
1:~0,000 years
(cfs)
165,000
346,000
(cfs)
165,000
365,000
A number of alternatives were considered singly and in combination
for Devil Canyon spillway facilities~ These included gated ori-
fices in the main dam discharging into a plunge pool, chute or
tunnel spillways with either a flip bucket or stilling basin for
energy dissipation, and open channel spillways. As described for
Watana, the seJection of the type of spillway was influenced by
the general arrangement of the major structures. The main spi 11-
way facilities will discharge the spillway design flood thr·ough a
gated spillway control structure with energy dissipation by a flip
bucket which directs the spillway discharge in a free fall jet
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into a plunge pool in the river. As noted above, restrictions
with respect to limiting nitrogen supersaturation in selecting
acceptable spillway discharge structures have been applied. The
various spillway arrangements developed in accordance with these
considerations are discussed in Section 2.5&
(g) Power Faci 1 ities Alternatives
The selection of the optimum arrangements for the power facilities
involved consideration of the same factors as described for
Watana.
(i) Comparison of Surface and Underground Powerhouses
A surface powerhouse at Devil Canyon would be located
either at the downstream toe of the dam or along the side
of the canyon wall. As determined for Watana, costs fav-
ored an underground arrangement. In addition to cost, the
underground powerhouse layout has been selected based on
the fallowing:
-Insufficient space is available in the steep-sided canyon
for a surface powerhouse at the base of the dam;
-The provision of an extensive intake at the crest of the
· arch da.rn \'loul d be detriment a 1 to stress conditions in the
arch dam, particularly under earthquake loading, and
would require signfficant changes in the arch dam geo-
metry; and
-The outlet facilities located in the arch dam are
designed to discharge directly into the river valley;
these would cause significant winter icing and spray
problems to any surface structure below the dam.
(ii) Comparison of Alternative Locations
The underground powerhouse and related facilities have been
located on the ri~ht bank for the following reasons:
-Genera11y superior rock quality at depth;
-The left bank area behind the main dam thrust block is
unsuitable for the construction of the power intake; and
-The river turns north downstream from the dam, and hence
the right bank power development is more suitable for
extending the tailrace tunnel to develop extra head.
{iii) Selection of Units
The turbine type selected for the Devil Canyon development
is governed by the design head and specific speed and, -by
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economic considerations. Francis turbines have been
adopted for reasons similar to those discussed for Watana
)n Section 2e2(g).
The selection of the number and rating of individual uniis
is discussed in detail in Section 2.4(b). The four units
will be rated to deliver 150 MW each at full gate opening
and minimum reservoir level in December (the peak demand month}. ·
(iv) Transformers
Transformer selection is similar to Watana.
( v) f. ower Intake and Water Pas sages
For flexibility of operation, individual penstocks are pro-
vided to each of the four units. Detailed cost studies
showed that there is no significant cost advantage in using
two 1 arger diameter penstocks with bifurcation at the pow-
erhouse compared to four separate penstocks •
A single tailrace tunnel with a length of 6,800 feet to
develop 30 feet of additional head downstream from the dam
has been incorporated in the design. Detail~d design may
indicate that two smaller tail race tunnels for improved
reliability may be superior to one large tunnel since the
extra cnst involved is relatively small. The surge chamber
design l;/Ould be essentially the same with one or two tun-
nels.
The overall dimensions of the intake structure are governed
by the se 1 ected diameter and number of the· penstocks and
the minimum penstock spacing. Det_ailed studies comparing
construction cost to the value of energy lost or gained
were carried out to determine the optimum diameter of the
penstocks and the tailrace tunnel.
(vi) Environmental Constraints
In addition to potential nitrogen-saturation problems
caused by spillway operation, the major impacts of the
Devil Canyon power facilities development are:
-Changes in the temperature regime of the river; and
-Fluctuations in downstream river flows and levels.
Temperature modeling has indicated that a multiple level
varying the intake design at Devil Canyon would not signif-
icantly affect downstream water temperatures, since these
are effectively controlled by the water released from
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Watanao Consequently, the intake design at Devil Canyon
incorporates a single level draw-off about 75 feet below
maximum reservoir operating level (El 1455).
The Devil Canyon station 'llill normally be operated as a
base-loaded plant throughout the year, to satisfy the re-
quirement of no signific.ant daily variation in power flow.
2.5 General Arrangement S~lection -Devil Cany9n
The approach to selection of a general arrangement for Devil Canyon was
a similar but simplified version of that used 'for Watana.
(a) Selection Methodology
Preliminary alternative arrangements of the Devil Canyon project
were developed and selected using two rather than three review
stages. Topographic conditions at this site limited the develop-
ment of reasonably feasible layouts, and four schemes \vere ini-
tially developed and evaluated. During the final review, the sel-
ected 1 ayout was refined based on technical, operational and envi-
ronmental considerations identified during the preliminary
review.
(b) Design Data and Criteria
The design data and design criteria on which the alternative lay-
outs were based are presented in Table 8.29. Subsequent to selec-
tion of the preferred Devi-l Canyon scheme, the information was
refined and updated as part of the on-going study program. ·
(c) Preliminary Review
Consideration of the options avail able for types and locations of
various stru~tures led to the development of four primary layouts
for examination at Devil Canyon in the preliminary review phase.
Previous studies had Jed to the selection of a thin concrete arch
structure for· the main dam, and indicated that the most acceptable
technical and economic location was at the upstream entrance to
the canyon. The dam axis has been fixed in this location for all
alternatives.
(i} Description of Alternative Schemes
The schemes evaluated during the preliminary review are
described below. In each of the alternatives evaluated,
the dam is founded on the sound bedrock underlying the
riverbed. The structure is 635 feet high, has a crest
width of 20 feet, and a maximum base width of 90 feet.
Mass concrete thrust blocks are founded high on the abut-
mentss the left block extending approximately 100 feet
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above the existing bedrock surface and supporting the upper
arches of the dama The thrust block on the right abutment
makes the cross-river profi 1 e of the dam more sj1llmetri cal
and contributes to a more uniform stress distribution.
Scheme DCl (Figure·B.37)
In this scheme, diversion facilities comprise upstream
and downstream earthfi 11 and rockfi 11 cofferdams and two
24-foot-d i-ameter tunne 1 s beneath the 1 eft abutment.
A rockfill saddle dam occupies the lower lying area
beyond the left abutment running from the thrust block
to the higher ground beyond. The impervious fill cut-
off for the saddle dam is founded on bedrock approxi-
mately 80 feet beneath the existing ground surface. The
maximum height of this dam above the foundation is
approximately 200 feet.
The routed 1:10,000-year design flood of 135,000 cfs is
passed by two spillways. The main spillway is located
on the right abutment. It has a design discharge of
90,000 cfs, and flows are controlled by a three-gated
agee control structure. This discharges down a
concrete-lined chute and over a flip bucket which ejects
the water in a diverging jet into a pre-excavated plunge
pool in the riverbed.. The flip bucket is set at E1 eva-
tion 925, approximately 35 feet above the riv.er level.
An auxiliary spiliway discharging a total of 35,000 cfs
is located in the center of the dam, 100 feet below the
dam crest, and is controlled by three wheel-mounted
gates. The orifices are designed to direct the flow
into a concrete-1 ined plunge pool just downstream from
the dam.
An emergency spillway is located in the sound rock south
of the saddle dam. This is designed to pass discharges
in excess of the 1:10, 000-year flood up .to a probable
maximum flood of 270,"000 cfs, if such an event should
ever occur. The spillway is an· unlined rock channel
which discharges into a valley downstream from the dam
leading into the Susitna River.
The upstrejln end of the channel is closed by an earth-
fi 11 fuse plug. The p 1 ug is designed to be eroded if
overtopped by the reservoir. Si nee the crest is 1 ower
than either the main or saddle dams, the plug would be
washed out prior to overtopping of either of these
structures.
The underground power facilities are located on the
right bank of the river, within the bedrock forming the
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dam abutment. The rock within this abutment is of
better qua 1 ity with fewer shear zones and a 1 esser
degree of jointing than the rock on the left side of the
canyon, and hence more su itab 1 e for underground excavation.
The power intake is located just upstream from the bend
in the valley before it turns sharply to the right into
Devil Canyon. The intake structure is set deep into the
rock at the downstream end of the approach channel.
Separate penstocks for each unit lead to the power-house •
The powerhouse contains four 150 MW turbine/generator
units. The turbines are Francis type units coupled to
overhead umbrel1 a type generators. The units are
serviced by an overhead crane running the length of the
powerhouse and into the end service bay. Offices, the
control room~ switchgear room, maintenance room, etc.,
are located beyond the service bay. The transformers
are housed in a separate upstream gallery located above
the lower horizontal section of the penstocks. Two
vertical cable shafts connect the gallery to the sur-
face. The draft tube gates are housed above the draft
tubes in separate annexes off the main powerhall e The
draft tubes converge in two bifurcations at the tail race
tunnels which discharge, under free-flow conditions, to
the river. Access to the powerhouse is by means of an
unlined tunnel leading from an access portal on ·the
right side of the canyon.
The switchyard is located on the left bank of the river
just downstream from the saddle dam, and the power
cab 1 es from the transformers are carried to it across the top. of the dam •
-Scheme DC2 (Figure B.38)
The layout is generally similar to Scheme DCl except
that the chute spillway is located on the left side of
the canyon. The concrete-1 ined chute terminates in a
fl ip bucket high on the 1 eft side of the canyon which
drops the discharges into the river below. The design
flow is 90,000 cfs, and discharges are controlled by a 3-gated~ ogee ... crested-contro 1 structure similar· to that
for Scheme DCl which abuts the left side thrust block.
The saddle dam axis is straight, following the shortest
route between the centro l structure at one end and the
rising ground beyond the low-lying area at the other.
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.. Scheme DC3 (See Figure 8.39)
The layout is similar to Scheme DC1 except that the
right side main spillway takes the form of a single
tunnel r·ather than an open chute. A 2-gated, agee--
contra 1 structure is 1 ocated at the head of the tunnel
and discharges into an inclined shaft 45 feet diameter
at its upper end. The structure wi 11 discharge up to a
maximum of 90,000 cfs.
The concrete-lined tunnel narrows to 35 feet diameter
and discharges into a flip bucket which directs the
flows in a jet into the river below as in Scheme DCl.
An auxiliary spillway is located in the center of the
dam and an emergency spillway is excavated on the left
abutment.
The layout of dcms and power facilities are the same as
for Scheme DCl.
-Scheme DC4 (See Figure 8.40)
The dam, power facilities, and saddle dam for this
scheme are the same as those for Scheme DCl. The major
difference is the substitution of a stilling-basin type
spillway on the right bank for the chute and flip
bucket. A 3-gated, agee-control structure_ is located at
the end of the dan thrust block and controls the dis-
charges up to a maximum of 90,000 cfs.
The coocrete~lined chute is built into the face of the
canyon and discharges into a 500-feet-long by 115-feet-
wi de by 100-feet-high concrete sti 11 ing basin formed
below river level and deep within the right side of the
canyon. Central orifices in the dam and the left bank
rock channe 1 and fuse p 1 ug form the aux i 1 i ary and emer-.
gency spillways, respectively, as in the other alterna-
tive schemes ..
The concrete-lined chute is built into the face of the
canyon and discharges into. a 500-feet-long by 115-feet-
wide by 100-feet-high concrete sti 11 ing basin formed
below river level and deep within the right side of the
canyon. Central orifices in the dam and the left bc.nk
rock channel and fuse plug form the auxiliary and emerg-
ency spillways, respectively., as in the other alterna-
tive schemes.
The downstream cofferdam is located beyond the stilling
basin, and the diversion tunnel outlets are located
farther downstream to enable construction of the still-
ing basin.
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{ii) Comparison of Alternatives
The arch dam, saddle dan, power facfl it·ies, and diversion
vary only in a minor degree among the four alternatives •
Thus, the comparison of the schemes rests sol ely on a com-
parison of the spil1way facilities.
As can be seen from a comparison of the costs in Table
8.30, the flip bucket spillways are substantially less
costly to construct than the stilling-basin type of Scheme
DC4. The left side spillway of Sch~e DC2 runs at a sharp
angle to the river and ejects the discharge jet from high
on the canyon face toward the opposite side of the canyon.
Over a longer period of operation, scour of the heavily
jointed rock caul d cause undermining of the canyon sides
and their subsequent instability. The possibility also
exists of deposition of material in the downstream riverbed
with a corresponding elevation of the tailrace. Construc-
tion of a spillway. on the steep left side of the river
could be more difficult than on the right side because of
the presence of daep fissures and large unstable blocks of
rock which are present on the left side close to the top of
the canyon. ..
The two-right side flip bucket spillway schemes, based on
either an open chute ·or a tunnel., take advantage o_f a down-
stream bend in the river to discharge parallel to the
course of the rivero This will reduce the effects of
erosion but could still present a problem if the estimated
maximwn possible scour hole would occur.
The tunnel type spillway could prove difficult to construct
because of the large diameter inclined shaft and tunnel
paralleling the bedding planes. The high velocities en-
countered in the tunnel spillway could cause problems with
the possibility of spiraling flows and severe cavitation
both occuring.
The stilling basin type spillway of Scheme DC4 reduces
downstream erosion problems within the canyon. However,
cavitation could be a problem under the high-flow veloci-
ties experienced at the base of the chute. This would be
somewhat alleviated by aeration of the flows. There is,
however, little precedent for stilling basin operation at
heads of over 500~ feet; and even where floods of much less
than the design capacity have been discharged, severe dam-
age has occurred.
(iii) Selection of Final Scheme
The chute and flip bucket spillway of Scheme-DC2 could gen-
erate downstream erosion problems which could require con-
siderable maintenance costs and cau:;e reduced efficiency in
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operation of the project at a future date. Hydraulic
design problems exist with Scheme DC3 which may also have
severe cavitation problems. Also, there is no cost
advantage in Scheme DC3 over the open chute Scheme OCl. In
Scheme DC4, the operating characteristics of a high head
stilling basin are little known, ,and there are few exanples
of successful operation. Scheme DC4 also costs
considerably more than any other scheme (Table 8.30}.
All spillways operating at the required heads and dis-
charges will eventually cause some erosion. For all
schemes, the use of solid cone valve outlet facilities in
the lower portion of the dam to handle floods up to
1:50-year frequency is considered a more reasonable
approach to reduce erosion and eliminate nitrogen super-
saturation problems than the gated high level orifice out-
1 ets in the darn. Si nee the cost of the flip bucket type
spillway in the scheme is considerably less than that of
the stilling basin in Scheme DC4, and since the latter
offers no relative operational advantage, Scheme DCl has
been selected for further study as the selected scheme.
(d) Final Rewiew
The layout selected in the previous section was further developed
in accordance with updated engineering studies and criteria. The
major change compared to Scheme DCl is the elimination of the high
level gated orifices and introduction of low level solid cone
valves, but other modifications that were introduced are described
below •.
The revised layout is shown on Figure 8.41. A description of the
structures is as follows.
(i) Main Dam
The maximum operat1ng level of the reservoir was raised to
Elevation 1455 in accordance with updated information rel a-
tive to the Watana tailwater level. This requires raising
the dam crest to Elevation 1463 with the concrete parapet
wall crest at Elevation 1466. The saddle dam was raised to
E1 ev at ion 1472 ..
(ii) Spillways and Outlet Facilities
To "eliminate the potential for nitrogen supersaturation
problems, the outlet facilities were designed to restrict
supersaturated flow to an average recurrence interval of
greater than 50 years. This led to the replacement of high
level gated orifice spillway by outlet facilities incorpor-
ating 7 fixed-cone valves, 3 with a diameter of 90 inches
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and 4 with a diameter of 102 inches,· capable of passing a
design flow of 38,500 cfs.
The chute spillway and flip bucket are located on the right
bank, ?,s in Scheme DCl; however, the chute length was
decreased and the elevation of the flip bucket raised com-
pared to S~heme DCl.
More recent site surveys indicated that the ground surface
in the vicinity of the saddle dam was lower than originally
estimated. The emergency spillway channel was relocated
slightly to the south to accommodate the larger dam.
(iii) Diversion
The previous twin diversion tunnels were replaced by a
single-tunnel scheme., This was determined to provide all
necessary security and will cost approximately one-half as
much as the two-tunnel alternative.
(iv) Power Facilities
..
The dr.iwdown range of the reservoir was reduced, allowing a
reduction in height of the power intake. In order to
locate the intake within solid rock, it has been moved into
the side of the valley~ requiring a slight rotatio-n of the
water passages, powerhouse, and caverns comprising the
power facilities.
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3 -DESCRIPTION OF PROJECT OPER~TION
Note: Adjustments may be made to this section due to operation studies
currently underway in Anchorage.
3.1 -Operation Within Railbelt Power System
A staged development is planned for implementation of Susitna power
generation. Th~ following schedule for unit start-up is proposed:
No. and Size of Tot a 1 Susi tna
Start-up Units (MW) On-line Capaci t.Y*
Date Dam Site Brought On-line (MW)
1993 Watana 4 X 170 680
1994 Watana 2 X 170 1020
2002 Devil Canyon 4 X 150 1620
* Installed generating capacity.
As shown above, the first four units are scheduled to be on line at
Watana in early 1993, followed by the remaining two Watana units in
early 1994. Startup of all four units at Devil Canyon is planned for
2002.
Of the total project installed capacity of 1620 MW, 1280 MW were
utilized as the basis for generation planning.. The remaining 340 MW
are planned t.o meet the needs for spinning reserve capacity.
This section describes the operation of the Watana and De vi 1 Canyon
power plants in the Rai lbelt electrical system. Under current condi-
tions in the Railbelt, a total of nine utilities share responsibility
for generation and distribution of electric power, with limited inter-
connections. The proposed arrangements for optimization and control of
the dispatch of Susitna power to Railbelt load centers is based on the
expectation that a single entity will eventually be set up for this
purpose. In the year 2010 the projected Railbelt system, with Susitna
on line, is projected to comprise:
Coal-fired Steam: 13 MW
Natura 1 Gas GT: 326 MW
Diesel: 6 MW
Natural Gas CC: 317 MW
Hydropower: 1680 MW
TOTAL 2482 MW
It is important to note that the Susitna proj(~ct wi 11 be the single
most significant power source in the system. The dispatch and distri-
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buti on of power from a 11 sources by the most economic a 1 and tel i ab 1 e
means is therefore essential. The general principles of reliability of
p 1 ant and system operat 1 on, reservoir regu 1 ati on, stationary and spin-
n·ing reserve requirements, and maintenance programming are discussed in
this section. Estimates of dependable capacity and annual energy pro-
duction for both Watana and Devi 1 Canyon ara presented. Operating and
maintenance procedures are described, and the proposed performance
monitoring system for the two projects is also outlined.
3.2 -Plant and System Operation Requirements
The main function of sy~)tem planning and operation control is the allo-
cation of generating plant on a short-term operational basis $0 that
the total system demand is met by the available generation at ·minimum
cost consistent with the security of supply. The objectives are gener-
ally the same for long-term planning or short-term operational load
dispatching, but with important differences in the latter case. In the
short-term case, the actual state of the system dictates system relia-
bility requirements, overriding economic considerations in load dis-
patching. An important factor arising from economic and reliability
considerations in system p 1 anni ng and operation is the provision of
stationary reserve and spinning reserve capacity~ Figure B .42 shows
the daily variation in demand for the Railbelt system during typical
winter and summer weekdays and the seasonal variation in monthly peak
demands for estimated loads in a typical year (the year 2000).
3.3 -General Power Plant and System Railbelt Criteria·
The following are basi·c reliability standards and criteria have been
adopted for planning the Susitna project.
(a) Installed Generating Capacity
Sufficient generating capacity is installed in the system to in-
sure that the probability of occurrence of load exceeding the
available generating capacity sh.all not be greater than one day in
ten years (loss-of-load probability -LOLP -of 0.1).
(b) Transmission System Capability
The high-voltage transmission system should be operable at all
load levels to Jleet the following unscheduled single or double
contingencies without instability, cascading or interruption of
load.
-The single contingency situation is the loss of any single gen-
erating unit, transmission line, transformer, or bus (in addi-
tion to normal scheduled or maintenance outages) without exceed-
ing the applicable emergency rating of any facility; and
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-The double contingency situation is the subsequent outage of any
remaining equipment, line or subsystem without exceeding the
short time emergency rating of any facility. ·
In the single contingency situation, the power system must be cap-
able of readjustment so that all equipment will be loaded within
normal ratings, and in the double contingency situation, within
emergency ratings for the probable duration of the outage.,
.
During any contingency:
-Sufficient reactive power (MVAR) capacity with adequate controls
is installed to maintain acceptable transmission voltage pro-files ..
-The stability of the power system is maintained without loss of
load or generation during and after a three-phase fault, cleared
in normal time, at the most critical location.
(c) ~ummar,x
Operational reliability criteria thus fall into four main cate-gories:
-LDLP of 0.1, or one day in ten years~ t~ !'!:.:intained for the
recorrmended plan of operation;
-The single and double contingency requirements are maintained
for any of the more probable outages in the plant or transmis~ sian system;
-System stability and voltage regulation are assured from the
electrical system studies. Detailed studies for load frequency
contra 1 have not been performed, but it is expected that the
stipulated criteria will be met with the more than adequate
spinning reserve capacity with six units at Watana and four
units at Devil Canyon; and
... The. loss of all Susitna transmission. lines on a single right-
of-way has a low level of probability. In the event of the loss
of a 11 1 i nes, the hydro p 1 ants at Wat ana and Devil Canyon are
best suited to restore power supply quickly after the first line
is restored since they are designed for 11 black start" operation.
In this respect, hydro p 1 ans are superior to therma 1 ., plants
because of their inherent b 1 ack start capability for restoration
of supply to a large system.
3.4 -Economic Dispatch of Units
A Susitna Area Contro 1 Center wi 11 be 1 ocated at Watana. to contra 1 both
the Watana and the Devil Canyon power plants as shown in Plate 34. The
control center wi 11 be linked through the supervisory system to the
Central Dispatch Control Center at Willow.
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The supervisory control of the entire Alaska Railbelt system will be
done at the Central Dispatch Center at ~~i llow. A high level of control
automation with the aid of digital computers will be sought, but not a
complete computerized direct digital control of the Watana and Devil
Canyon power plants. Independent operator controlled local-manual and
local-auto operations will still be possible at Watana and Devil Canyon
power plants for testing/commissioning or during emergencies.. The con-
trol system will be designed to perform the following functions at both
power plants:
-Start/stop and loading of units by operator;
-Load~frequency control of units;
-Reservoir/water flow control;
-Continuous monitoring and data logging;
-Alarm annunciation; and
-Man-machine communicat"ion through visual display units (VDU) and con-
sole.
In addition, the computer system will be capable of retrieval of tech-
ni ca 1 data, design criteria, equipment characteristics and operating
limitations, schematic diagrams, and operating/maintenance records of
the units.
The Susitna Area Control Center will be capable of completely indepen-
dent centro 1 of the Centra 1 Dispatch Center in case of system emer-
gencies. Similarly it wi 11 be possible to operate the Susitna units
in an emergency situation from the Central Dispatch Center, although
this should be an unlikely operation considering the size~ complexity,
and impact of the Susi tna generating p 1 ants on the system.
The Central Dispatch Control Engineer decides which generating units
should be operated at any given time. Decisions are made on the basis
of known information, including an "ord-er-of-merit 11 schedule, short-
term demand forecasts, limits of operation of units, and unit mainten-
ance schedules.
(a} Merit-Order Schedule
In order to decide which generating unit should run to meet the
system demand in the most economic manner, the Control Engineer is
provided with information of the running cost of each unit in the
form of an .. order-of-merit" schedule. The schedule gives the cap-
acity and fuel costs for thermal uni.t·s, and reservoir regulation
limits for hydro p 1 ~nts. ~ •
(b) Optimum Load Dispatching
One of the most important functions of the Control Center is the
accurate forecasting of the load demands 1n the various areas of the system.
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Based on the anticipated demar.d, basic power transfers between
areas, and an allowance for reserve, the planned generating capa-
city to be used is determined by taking into consideration the
reservoir regu 1 ati on p 1 ans of the hydt~o p 1 ants. The type and size
of the units should also be taken into consideration for effective 1 oad dispatching.
In a hydro-dominated power system such as the Rai lbelt system
wou 1 d be if Susitna is deve 1 oped, the hydro unit wi 11 take up a
much greater part of base 1 oad operation than in a therma 1 domi n-
ated power system,. The planned hydro units at Watana typically
are well suited to load following and frequency regulation of the
system and providing spinning reserve. Greater flexibility of
operation was a significant factor in the selection of six units
of 170 MW capacity at Watana, rather than fewer larger-size units.
(c) Operating Limits of Units
There are strict constraints on the minimum load and the loading
rates of machines: to dispatch load to these machines requires a
systemwide dispatch program taking these constraints into consid-
eration. In general, hydro units have excellent startup and load
following characteristics; thermal units have good part-loading characteristics. ·
Typical plant loading limitations are given below:
(i)
( i 1)
Hydro Units -
-Reservoir regulation constraints resulting in not-to-
exceed maximum and minimum reservoir levels~ daily or seasonally.
-Part loading of units is impossible in the zone of rough
turbine operation (typically from above speed-no-load to
50 percent load) due to vibrations arising from hydraulic surges.
Steam Units
-Loading rates are slow {10 percent per minute).
-The units may not be able to meet a sudden steep rate of rise of load demand.
-The units have a minimum economic shutdown period (about 3 hours) .
-The total cost of using conventional units includes bank-
; ng, ~ 'ai sfng pressure and part-1 oad operations prior to
maximum economic operation •.
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(iii) Gas Turbines
Cannot be used as spinning reserve because of very poor
efficiency and reduced service life.
-Require 8 to 10 m·inutes for normal start-up from cold.
Emergency start up times are of the order of 5 to 7
minutes.
(d) Optimum J.l~intenance Program
An important part of operational planning which can have a signif-
icant effect on operating costs is maintenance programming. The
program specifies the times in the year and the sequercc~ in which
plant is released for maintenance.
3.5 -.Unit Operation Reliability Criter-ia
During the operational load dispatching conditions of the power system,
the reliability criteria often override economic considerations in
scheduling of various units in the system. Also. important in consider-
ing O{:lerational reliability are system response, load-frequency con-
tro15 and spinning reserve capabilities.
(a) Power System ~alyses
La ad-fr-equency response studies determine the dynamic stabi 1 i ty of
the system due to the sudden forced outage of the largest unit (or
generation block) in the system. The generation and load are not
balanced, and if the pick..:up rate of new generation is not ade-
quate, loss of load wi 11 eventually result from under-voltage and
under-frequency relay operation, or load-shedding. The aim of a
well-designed high security system is to avoid load-shedding by
maintaining frequency and voltage within the specified statutory
~imits.
(b) System-Response and Load-Frequency Control
To meet the frequency requirements, it is necessary that ·the
effective capacity of generating plant supplying the system at any
given instant should be in excess of the load demand. In the
absence of detailed studies, an empirical factor of 1-2/3 times
the capacity of the largest unit in the system is normally taken
as a design criterion to maintain system freque:ncy within accept-
able limits in the event of the instantaneous lo5s of the largest
unit. It is recommended that a factor of 1-1/2 times the largest
unit size be considered as a minimum for the Alaska Railbelt
system:. with 2 times the largest unit size as a fairly conserva-
tive value (i.e., 300 to 340 MW).
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The quickest response in system generation wi 11 come· from the
hydro units. The large hydro units at Watana and Devil Canyon on
spinning reserve can respond in the turbining mode within 30
seconds. This is one of the particularly important advantages of
the Susitna hydro units.. Gas turbines can only respond in a
second stage operation within 5 to 10 minutes and would not
strictly qualify as spinning reserve. If thermal units are run
part-loaded (example, 75 percent), this would be another source of
spinning reserve. Ideally, it would be advantageous to provide
spinning reserve in the therma I generation as well, in order to
spread spinning reserves evenly in the system, with a compromise
to economic loading resulting from such an operation.
(c) Protective Relaying System and Device~
The primary protective r-elaying systems provided for the gener ....
ators and transmission system of the Susitna project are designed
to disconnect the faulty equipment from the system in the fastest
possible time.. Independent protective systems are installed to
the extent necessary to provide a fast-clearing backup for the
primary protective system so as to limit equipment damage, to
limit the shock to the system and to speed restoration of service.
The relaying systems are designed so as not to restrict the normal
or necessary network transfer capabilities of the power system.
3.6 -Dispatch Control Centers
The operation of the Watana and Devil Canyon power plant in relation to
the Central Dispatch Ce~ter can be considered to be the second tier of
a three-tier control structure as follows:
-Central Dispatch Control Center (345 kV network) at Willow: manages
the main system energy transfers, advises system configuration and
checks overall security.
-Area Contra 1 Center (Generation connected to 345 kV system, for ex-
ample, Watana and Devil Canyon): deals wfth the loading of genera-
tors connected directly to the 345 kV network, switching and safety
precautions of local systems, checks security of interconnections to
main system. ·
-District or Load Centers (138 kV and lower voltage networks): gener-
ation and distribution at lower voltage levels.
For the Anchorage and Fairbanks areas, the district center functions
are incorporated in the respective area control centers.
Each generating unit at Watana and De vi 1 Canyon is started up, loaded
and operated and shut down from the Area Contra 1 Center at Watana
according to the loading demands from the Central Dispatch Control
Center with due consideration to:
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-Watana reservoir regulation criteria;
-Devil Canyon reservoir regulation criteria;
-Turbine loading and de-loading rates;
-Part loading and maximum loading characteristics of turbines and generators;
-Hydraulic transient characterjstics of waterways and turbines;
-Load-frequency control of demands of the system; and
Voltage regulation requirements of the system.
The Watana Area Control Center is equipped with a computer-aided con-
trol system to efficiently carry out these functionso The computer-
aided contra l system allows a minimum of highly trained and ski 11 ed
operators to perform the contra 1 and supervision of Watana and De vi 1
Canyon plants from a single control room«> The data information and
retrieval system will enable the pe.rformance and alarm monitoring of
each unit individually as well as the plant/reservoir and project oper-ation as a who"l e •.
3. 7 -Susitna eroject Operation
Substantia 1 season a 1 as we 11 as over ... the-year regu 1 at 1 on of the river
flow is achieved with the two reservoirs. The simulation of the reser-
voirs and the power facilities at the two developments was carried out
on a month1y basis to assess the energy potential of the schemes, river
flows downstream and flood contra 1 possi b i 1 it i es with the reservoirs.
The following paragraphs summarize the main features of reservoir oper-ation.
An optimum reservoir operation was established by an iterative process
to minimize net system operating costs while maximizing firm and usable
energy production. Four alternative operating cases for the Watana
reservoir (A, B, C, and D) were selected for study, to define the pos-
s i b 1 e range of operation. Case A represents an optimum power and
energy scenario, while Case 0 reflects a case of "no impact on down-
stream fisheries". Case.) B and C are intermediate leve 1 s of power
operation and downstream impact. These essentially define monthly min-
imum flows at Gold Creek that must be maintained while providing energy
consistent with other project constraints. For feasibility report pur-
poses, operation model 11 A11 was adopted for project design. Studies
with appropriate fisheries mitigation .measures were developed based on
Case A flows at Gold Creek. Table 8.31 presents a summary of potential
energy generation with different ·operating rules for.Watana and Devil Canyon developments.
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Average annual energy potential of Watana development is 3460 GWh, and
that of Devil Canyon development is 3340 GWh. A frequency analysis of
the river hyd-ro 1 ogy was made to derive the firm annua 1 energy potentia 1
(or the rlependable capacity) of the hydro development.
The Federal Energy Regulatory Commission (FERC) defines the dependable
capacity of hydroelectric plants as: 11 the capacity which, under the
most adverse flow conditions of record can be relied upon to carry
system load, provide dependable reserve. capacity, and meet firm power
obligations taking into account seasonal variations and other charac-
teristics of the load to be supplied" (1). Based on the Railbelt sys-
tem studies and previous experience on 1 arge hydroe·l ectri c projects, it
was assumed that a dry hydrological sequence with a recurrence period
of the order of 1:50 years \"lould constitute an adequate reliability for
the Railbelt electrical system.
An analysis of annual energy potential of the reservoirs showed that
the lowest annual energy generation has a recurrence ffequency of 1 in
300 years.. The second lowest annua 1 energy of 5400 GWh has a recur-
rence frequency of 1 in 70 years. This 1 atter figure has been adopted
as the firm energy from the development.
Expressed another way, the firm energy as· defined may fall short of its
v a 1 ue by about 5 percent once in 300 years. This is a conservative
interpretation of the FERC definition.
The monthly distribution of firm annual energy as simulated in the
reservoir simulation has been used in -system generation planning
studies. Average monthly energy based on the recorded sequence hydro-
logy is used in the economic analysis.
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4 -DEPENDABLE CAPACITY AND ENERGY PRODUCTION
4.1 -Hydrology
(a) Historical Streamflow Records
Historical streamflow data are available for several gaging sta-
tions on the Susitna River and its main tributaries.. Continuous
gaging records were available for the following eight stations on_
the river and its tributaries: Maclaren River near Paxson,
Denali, Cantwell~ Gold Creek and Susitna stations on the Susitna
River, Chulitna Station on the Chulitna River, Talkeetna on the
Talkeetna River, and Skwentna on the Skwentna River. The longest
period of record avai lab1e is for the station at Gold Creek (32
years from 1949 to 1981). At other stations, record length varies
from 6 to 23 years.. Gaging was cant i nued at a 11 these stations as
part of the project study program. A gaging station was estab-
1 ished at the Watana damsi te in 1980, and streamflow records are
available for the study period. Partial streamflow records are
available at several other stat·ions on the river for varying
periods; the station locations are shown in Figure 8.43. It
should be noted that gaging wi 11 continue as the project pro-
gresses in order to improve the streamflow record, as well as
after project completion at selected sites required for project
operation.
(b) Water Resources
Above its confluence with the Chulitna Rive~, the Susitna contri-
butes approximately 20 percent of the mean annual flow measured at
Susitna Station near Cook Inlet. Figure 8.44 shows how the mean
annual flow of the Susi tna increases towards the mouth of the
river at Cook Inlet.
Seasonal variation of flow in the river is extreme and ranges from
very low values in winter (October to April) to high summer values
(May to September) .. For the Susi tna River at Go 1 d Creek, the
average winter and summer flows are 2,100 and 20,250 cfs respec-
tively, i.e., a 1 to 10 ratio. This large seasonal difference is
mainly due to effects of glacial and snow melt in the summer.
The monthly average flows in the Susitna River at Gold Creek are
~iven in Figure 8.45. Some 40 percent of the streamflow at Gold
Creek originates above the Denali and Maclaren gages. This catch-
ment generally comprises the gl~ciers and associated high moun-
tains. On the average, approximately 88 percent of the streamflow
recorded at Gold Creek station occurs during the summer months ..
At higher elevations in the basin, the distribution of flows is
concentrated even more i.n the summer months. For the Mac 1 aren
River near ?axson (Elevation 4520), the average winter and summer
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flows are 144 and 2,100 cfs respectively, i.e. a 1 to 15 ratio.
The monthly percent of annual discharge and mean monthly dis-
charges for the Susitna River and tributaries at the gaging sta-
tions above the Chulitna confluence are given in Table 8.32~
(c) Streamflow Extension
Synthesized flows at the Watana and Devil Canyon dan1sites are pre-
sented in Tables 8.33 and 8 .. 34.. Flow duration curves based on
these monthly estimates are presented for Watana and Devil Canyon
damsites in Figures 8.46 and 8.47 •
The inhouse FILLIN computer program developed by the Texas Water
Development Board was used to fill in gaps in historical stream-
flow records at the eight continuous gaging stution~. The·32 year
record (up to 1981) at Gold Creek was used as the base record.
The procedure adopted for filling in the data gaps uses a multi-
site regression technique which analyzes monthly time-series data.
Flow sequences for the 32-year period were generated at the
remaining seven stations. Using these flows at Cantwell station
and observed Gold Creek flows, 32-year monthly flow sequences at
the Watana and Devil Canyon damsites were generated on the basis
of prorated drain age areas. Recorded streamfl ows at Watana and
Devil Canyon were included in the historical record where avail-able.
(d) Critical Stre~low Used for Dependable Caeacity
[Note: This section is subject to revision after selection of
minimum downstream flow in October.] ·
Average annual energy potential of Watana development is 3460 GWh:s
and that of Devil Canyon development is 3340 GWh. A frequency
analysis of the river hydrology was made to derive the firm annual
energy potential (or the dependable capacity) of the hydro devel-
opment. Based on the Railbelt system studies and previous experi-
ence on 1 arge hydroe 1 ectri c projects, it was assumed that a dry
hydrological sequence with a recurrence period of the order of
1:50 years would constitute an adequate reliability for the Rail-
belt electrical system.
An analysis of annual energy potential of the reservoirs showed
that the lowest annual energy generation has a recurrence fre-
quency of l in 300 years (see Figure 8.48). The second lowest
annua 1 t::i'lergy of 5400 GWh has a recurrence frequency of 1 in 70
years. This latter figure has been adopted as the firm energy
from the develorxnent.
Expressed another way_, the firm energy, as defined~ may fall short
of its value by about 5 percent once in 300 years. This is
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a conservative interpretation of the FERC definition of dependable
capacity.
(e) Floods
The most common causes of flood peaks in the Susitna River Basin
are sno'lmlelt or a combination of sno\'mlelt and rainfall over a
large area. Annual maximum peak discharges generally occur be-
tween May and October w1th the majority (approximately 60 percent)
occurring in June. Some of the annual maximum flood peaks have
a 1 so occurred in August or 1 ater and are the result of heavy rains
over 1 arge areas augmented by si gni fi cant snownelt from higher
elevations and glacial runoff. Table B~35 presents selected flood
peaks recorded at different gaging stations.
A regional flood peak and volume frequency analysis was carried
out using the recorded floods in the Susitna River and its princi-
pal tributari.es. These analyses were conducted for two different
time periods. The first period, after the ice breakup and before
freezeup (May through October), contains the largest floods which
must be accommodated by the ptoject. The second period represents
that portion of time during which ice conditions occur in the
river (October through May). These floods, although smaller~ can
be accompanied by ice· jamming and must be considered during the
construction phase of the project in planning the design of
cofferdams for river diversion. ·
A set of multiple linear regression equations were developed using
physiographic basin parameters such as catchment area, stream
length, precipitation, snowfall amounts, etc., to estimate flood
peaks at ungaged sites in the basin. In conjunction with the
analy~~s of shapes and volumes of recorded large floods at Gold
Creek, a set of project design· flood hydrographs of different
recurrence· intervals were developed (see Figures 8.4.9 and 8.50) •
The results of the above analysis were used for estimating flood
hydrographs at the damsites and ungaged streams and rivers along
the access road alignments for design of spillways, culverts, e.tc.
Table 8.36 lists mean annual, 50-, 100-, and 10,000-year flooqs at
the \4atana and Devil Canyon damsites and at the Gold Creek gage.
The proposed r·eservoirs at Watana and Devi 1 Canyon would be class-
ified as "largeu and with "high hazard potential" according to the
guidelines for safety i·nspection of dams laid out by the Corps of
Engineers. This would indicate the need for the probable maximum
flood (PMF) to be considered in the evaluation of the proposed
projects. Estimated peak d1 scharges during the PMF at selected
locations are included in Table 8.36, and the PMF hydrograph is
presented in Figure 8.50.
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(f) Flow Adjustments
Evaporation from the proposed Watana and Devil Canyon Reservoirs
,has been evaluated to determine its significance. Evaporation is
influenced by air and water temperatures, wind, atmospheric pres-
sure, and dissolved solids within the water. However, the evalua-
tion of these factors• effects on evaporation is difficult because
of their interdependence on each other. Consequently, more sim-
P 1 ifi ed methods were preferred and have been uti 1 ized to estimate
evaporation losses from the two reservoirs.
The monthly evaporation estimates for the reservoirs are presented
in Table 8.37. The estimates indicate that evaporation losses
will be less than or equal to additions due to precipitation on
the reservoir surfaceo Therefore, a conservative approach was
taken, with evaporation losses and precipitation gains neglected
in the energy calculations.
Leakage is not, expected to result in significant flow losses.
Seepage through the relict channe 1 is estimated as less than one-
ha 1 f of one percent of the average flow and therefore' has been
neglected in the energy calculations to date. This approach will
be reviewed when further investigations of the relict channel are
completed. ·
Minimum flow releases are required throughout the year to maintain
downstream river stages. The most significant factor in determin-
ing the minimum flow value is the maintenance of downstream fish-
eries. The monthly flow requirements that were used in determina-
tion of project energy potential are given in Table B.38.
The nllllbers shown in Table 8.38 represent the minimum stream flow
required at Gold Creek. These requirements would remain constant
for all phases of project development. The actual flows released
from the project at Watana (when Watana is operating alone) and at
Devil Canyon (for combined operation of both dams) will be less
than the required Gold Creek flows, prorated on the basis of
streamflow contributions from the intervening basin area. Tables
8·.39 and 8.40 give the typical minimum required flow releases at
Watana and Devil Canyon for a 32-year period of record.
After completion of Devil Canyon, flow releases from Watana will
be regulated by system operation requirements. ..Because the tail-
water of the Oev i 1 Canyon reservoir wi 11 eh~afrd upstream to the
Watana tailrace, there will be no release requirements for stream-
flow maintenance of Watana for the Watana/Devil Canyon combined
operating configuration.
Existi.ng water rights in the Susitna Basin were investigated to
determ\ne impacts on downstream flow requirements.. Based on
invento"ry information provided by the Alaska Department of Natural
Resources, it was determined that existing water users will not be
affected by the project. A listing of all water appropriations
'located within one mile of the Susitna River is provided jn Table
-8~41.
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4.2 ca Reservoir Data
(a) Reservoir Storage
Gross storage volume of the Watana .reservoir at its normal maximum
operating level of 2185 feet is 9.47 million ac/ft~ which is about
1.6 times the mean annual flow (MAF) at the damsite. Live storage
in the reservoir is about 4.3 million ac/ft (75 percent of ~1AF).
De vi 1 Canyon reservoir has a gross storage of about 1.1 mi 11 ion
ac/ft and live storage of 0.34 millie~ ac/ft.
The area-capacity curves for the Watana and De vi 1 Canyon reser-
voirs are provided in Figure-B.Sl and Figure 8.52, respectively.
(b) Rule Curves
Operation of the reservoirs far eneryy production is based on tar-
get water surface 1 eve 1 s set for the end of each month. The tar-
get le¥el represents that level below whirh no energy beyond firm
energy can be produced. In other words, if the reservoir level
drops. below the target only firm energy will be produced. In
wetter years when the reservoir level surpasses the target level~
energies greater than firm energy can be produced, but only as
great as the system energy demand allows.
With a reservoir rule curve which establishes minimum reservoir
levels at different times during the year, it \'lill be possible to
produce more energy in wetter years during winter than by follow-
ing a set energy pattern. At the same time, the ru1e curve
ensures that low flow sequences do not m!=\teri a11y reduce the
energy potential below a set minimum or firm annual energy.
The rule curves for Watana and Devil Canyon under combined opera-
tion are shown in Figure 8.53~
4.3 -Operatin~ Capabilities of Susitna Units
The operating conditions of both the Watana and Devil Canyon turbines
are summarized in Table 8 .. 42.
(a) Watana
The Watana powerhouse wi 11 have six generating units with a nomin-
al capacity of 170 NW corresponding to the minimum December reset"-
voir level (Elevation 2117).
The gross head on the p 1 ant wi 11 vary from 590 feet to approx.i-
mately 735 feet. The maximum unit output will change with head,
as shown on Figure 8.54 •
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The rated head for the turbine has been established at 680 feet,
which is the weighted average operating head on the station.
Allowing for generator losses, the rated turbine output is 250,000
hp (186.5 MW) at full gate. ·
The rated output of the turbines wi 11 be 250,000 hp at 680 feet
rated net head. Maximum and minimum heads on the units will be
728 feet and 576 feet~ respectively. The full gate output of the
turbines will be about 275,000 hp at 728 feet net head and 195,000
hp at 576 feet net head. Overgati ng of the turbines may be pos-
sible, providing approximately 5 percent additional power; how·-·
ever, at high heads the turbine output will be restricted to avoid
overloading the generators. The best efficiency point of the tur-
bines will be established at the time of preparation of bid docu-
ments for the generating equipment and will be based on a detailed
analysis of the anticipated operating range of the turbines. For
preliminary design purposes, the best efficiency (best gate) out-
put of the units has been assuiiled as 85 percent of the full gate
turbine output. This percentage may vary from about 80 percent to
90 percent; in general, a lower percentage reduces turbine cost.
The full gate and best gate efficiencies of the turbines will be
about 91 percent and-94 percent respectively at rated head. The
efficiency will be about~o.5 percent lower at maximum head and 1
percent lower at minimum head. The preliminary performance curve
for the turbine is shown on Figure 8.55.
The Wat ana p 1 ant output may vary from zero, with the units at
standstill or at spinning reserve, to approximately 1200 when all
six units are operat 1 ng under maximum output at maximum head. A
graph of plant efficiency versus output and the number of on-line
units is shown in Figure 8.56. The load following requirements of
the plant results in widely varying loading, but because of the
multiple unit installation the total plant efficiency varies only
slightly.
(b) Devil Canyon
The Devil Canyon powerhouse will have four generating units with a
nominai capacity of 150 MW based on the minimum December reservoir
level (Elevation 1405) and a corresponding gross head of 555 feet
in the station.
The gross head on the plant wi 11 vary from 555 feet to 605 feet·.
The maximum unit output wi 11 change with head as shown in Figure
B.57.
The rated average operating head for the turbine has been estab-
lished at 575 feet. Allowing for generator losses, this results
in a rated turbine output of 225,000 hp (168 MW) at full gate.
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The generator rating has been selected as 180 MVA with a 90 per-
cent power factor. The generators wi 11 be capable of continuous
· operation at 115 percent rated power. Because of the high capa-
city factor for the Devil Canyon station, the gener.ators will
therefore be sized on the basis of maximum turbine output at maxi-.
. mum head, allowing for a possible 5 percent addition in power from
the turbine. This maximum turbine output (250,000 hp) is within
the continuous overload rating of the generator.
Maximum and minimum heads on the units wi 11 be 542 feet and 600
feet, respectively. The full gate output of the turbines will be
about 240,000 hp at maximum net head and 205,000 hp at minimum net
head. Overgating of the turbines may be possible, providing
approximately 5 percent additional~. power. For preliminary design
purposes, the best efficiency (best gate) output of the units has
been assumed at 85 percent of the full gate turbine output.
The full gate and best gate efficiencies of the turbines wi 11 be
about 91 percent and 94 percent, respectively, at rated head. The
. efficiency wi 11 be about 0.2 percent lower at maximum head and 0.5
percent lower at minimum head. The preliminary performance curve
for the turbine is shown in Figure 8.58.
The De vi 1 Canyon p 1 ant output may · ., .... Y from zero to 700 MW with
all four units operating at maximun1 output. The combined plant
efficiency varies with output and number of units operating as
shown in Figure 8.59. As with Watana, the plant efficiency varies
only slightly with loading due to the load fol1owing capabilities of multiple ~nitsa
4.4 -Tai lwater Rating Curve
The tai lwater rating curve for the Watana deve·lopment is shown on
Figure 8.51 and for the Devil Canyon development on Figure 8.52.
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5 -STATEMENT OF POWER NEEDS AND UTILIZATION
5.1 -Railbelt Load Forecasts
In this section of the report, the electrical demand forecasts for the
Rai lbelt region are described. Historical and projected trends are
identified and discussed, and the forecasts used in Susitna generation
planning studies are presentedo ·
The feasibility of a major hydroelectric project depends in part upon
the extent the available capacity and energy are ·consistent with the
needs of the market to be served by the time the project comes on line.
The Alaska Power Authority and the State of Alaska authorized load
fnrecasts for the Alaska Railbelt region to be prepared independently
of the Susitna feasibility study.
The Railbelt region, shown in Figure B.60~ contains three electrical
load centers: the Anchorage-Cook-Inlet area~ the Fairbanks-Tanana
Valley area, and the Glennallen-Valdez area. These areas are repre-
sented by the shaded areas in the figure. Because of the relatively
small electrical requirements of the Glennallen-Valdez load center
(approximate iy 2 percent of the demand of the Anchorage-Cook In let
area} it is not specifically analyzed as an ind1viduai load center.
For this study the Glennallen-Valdez load center is considered to be
part of the Anchorage-Cook Inlet load center. The electrical demands
for the Glennallen-Valdez area are determined as part of this study but
are combined with the Anchorage-Cook Inlet loads. Future electrical
requirements in excess of generating capacity are assumed to be served
from the Anchorage area.
(a) Scope of Studies
There have been two forecasts developed and used during the feasi-
bi 1i ty study. In 1980, the Institute for Socia 1 and Economic
Research (ISER) prepared economic and accompanying end use energy
demand projections for the Rai 1 belt. The end use forecasts were
further r~fined as part of the feasibility study to estimate capa-
city demands and demand patterns. Also estimated was the poten-
tial impact on these forecasts of additional load management and
energy conservation efforts. These forecasts were used in several
portions of the feasibility study, including the development
selection study, and initial economic, financial and sensitivity
analyses. These forecasts are discussed in more detail in section
(b) below ..
In December 1981, Battelle Pacific Northwest Laboratories produced
a series of revised load forecasts for the Railbelt. These fore-
casts were developed as a part of the. Rai lbelt Alternatives Study,
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completed by Battelle under contract to the State of Alaska.
Battelle's forecasts were a result of further updating of economic
projections by ISER and some revised end-use models developed by
Batte 11 e, which took into account price sensitivity and sever a 1
. other factors not included in the 1980 projections. The December
1981 Batte 11 e forecasts were used in the fi na 1 project staging~
economic, financial and sensitivity analyses. The December 1981
Battelle forecasts are presented in section {c) below.
(b) Electricity Demand Profiles
This section reviews the historical growth of electricity consump-
tion in the Railbelt and compares it to the national trend.
Earlier forecasts of Rai lbelt electricity consumption by ISER,
which were used in Susitna development selection studies, are also described.
(i) Historical Trends
Between 1940 and 19789 electricity sales in the Railbelt
grew at an average annual rate of 15.2 percent. This
growth was roughly twice that for the nation as a whole.
Table 8.43 shows U.S.· and Alaskan annual growth rates for
different periods between 1940 and 1978.. The historical
growth of Railbelt utility sales from 1965 is illustrated
in Figure 8.61.
Although the Railbelt growth rates consistently exceeded
the national average, the gap has been narrowing in later
years due to the. gradual maturing of the Alaskan economy.
Growth in the Railbelt has exceeded the national average
for two reasons: popu 1 at ion growth in the Ra i 1 be 1 t has
been higher than the national rate, and the proportion of
Alaskan households served by electric utilities was lower
than the U.S .. average·so that some growth· in the number of
customers occurred independently of population growth.
Table 8.44 compares U.S .. and Alask~n growth rates in the
residential and commercial sectors.
The distribution of electricity consumption between resi-
denti a 1 and commercia 1-industria 1-government sectors has
been fairly stable. By 1978, the commercial-industrial-
government and residential sectors accounted for 52 percent
and 47 percent respectively. In contrast, the 1978 nation-
wide shares were 65 percent and 34 percent, respectively.
Historical electricity demand in the Railbelt, disaggre-
gated by regions, is shown in Table 8.45. During the
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peri ad from 1965· to 1978, Greater Anchorage accounted for
about 75 percent of Railbelt electricity consumption fol-
lowed by Greater Fairbanks with 24 percent and Glennallen-
Valdez with 1 percent. The pattern of regional sharing
during this period has been quite stable and no discernible
trend in region a 1 shift has emerged. This is mainly a
result of the uniform rate of economic development in the
Alaskan Railbelt.
ISER Electricitx Consumption Forecasts
The methodology used by ISER to estimate electric. energy
sales for the Railbelt is summarized in this section and
th~ results obtained are disc4ssed.
-Methodolog,x
The ISER electricity demand forecasting model concep--
tualized in computer logic the linkage between economic
growth scenarios and electricity consumption. Tne out-
put from the model is in the form of projected values of
electricity consumption for each of the three geographi-
cal areas of the Rai lbelt (Greater Anchorage, Greater
Fairbanks and Glennallen-Valdez) and is classified by
final use (i.e., heating, washing, cooling, etc.) and
consuming sector (commercial, residential, etc). The
model produces output on a five-year time basis from
1985 to 2010, inclusive.
The ISER mode 1 consists of sever a 1 submode 1 s 1 inked by
key variables and driven by policy and technical assump-
tions and state and national trends. These submodels
are grouped into four economic mode 1 s which forecast
future levels of economic activity and four electricity
consumption models which forecast the asc-ociated elec-
tricity requirements by consuming sectors. For two of
the consuming sectors it was not possible to set up com-
puter models and simplifying assumptions were made.
-Forecasting Uncertainty
To adequately address the uncertainty associated with
the prediction of future. demands, a number of different
economic growth scenarios were considered. These were
formulated by alternatively combining high, moderate and
1 ow growth rates in the area of speci a1 projects and
industry with State government fiscal policies aimed at
stimulating either high, moderate or low growth. This
resulted in a total of nine potential growth scenarios
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for the state. In addition ta these scenarios, ISER
a 1 so considered the potenti a·I impact of a price reduced
shift towards increased elf:ctricity demand. A short
list of six future scenarios was selected.. These con-
centrated around the mid-range or 11 base case,. estimate
of the upper and lower and extremes (see Table 8.46).
-Demand Forecasts
An important+"actor to be considered in generation plan-
ning studies is the peak power demand associated wi tl:l ~a
forecast of electric energy demand. The ·overall
approach to derivation of the peak demand forecasts for
the Railbelt region was to examine the available histor-
fcal data with regard to the generation of electrical
energy and to apply the observed generation patterns to
existing sales forecasts. Information routinely sup-
plied by the Railbelt utilities to the Federal Energy
Regulatory Commission was uti 1 i zed to determine these
·1 oad patterns.
The first step involved an adjustment to the allocated
sales to reflect losses and energy unaccounted for. The
adjustment was made by increasing the energy a 11 ocated
to each utility by a factor computed from historical
sales and 3eneration levels. This resulted in a grass
energy generation for each utility.
The factors determined for the monthly distribution of
total annual generation were then used to distribute the
gross generation for each year. The resulting hour-ly
loads for each utility were added together to obtain the
total Rai lbelt system load pattern for each forecast
year. Table 8 .. 47 summarizes the total energy generat1on
and the peak loads for each of the low, medium, and high
ISER sales forecasts, assuming moderate government
expenditure ..
Adjusted ISER Forecasts
Three of the initial ISER energy forecasts were con-
sidered in generation p 1 anni ng studies for development
selection studies. These included the base case
(MES-GM) or medi urn forecast, a .lpw forecast and a high
forecast.. The law forecast waSthat corresponding to
the low economic growth as proposed by ISER with an
adjustment for low government expenditure (LES-GL). The
high forecast corresponded to the ISER high economic
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growth scenario with an adjustment for high. government
expend.iture (HES-GH).
The electricity forecasts summarized in Table 8.47 rep-
resent tot a 1 uti 1 i ty generation and inc 1 ude projections
for self-supP.lied industrial and military generation
sectors.. Inc·l uded in these forecasts are transmission
and distribution losses in the range of 9 to 13 percent
depending. upon the generation scenario assumed. These
forecasts, ranging from 2.71 to 4.76 percent average
annual growth, were adjusted for use in generation plan-
ning studies ..
The self-supplied industrial energy primarily involves
dri 11 i ng and offshore operations and other activities
which are not likely to be connected into the Railbelt
supply system. This component, which varies depending
upon generation scenario, was therefore omitted from the
forecasts used for p 1 anning purposes.
The military is likely to continue purchasing energy
from the general market as long as it remains economic.
However, much of their gener.ating capacity is tied to
district heating systems which would prestmably co.ntinue
operation. For study purposes·, it was therefore assumed
that 30 percent of the estimated military generation
would be supplied from the grid system.
-The adjustments made to power and energy forecasts for
use in self-supplied industrial and military s~ctors are
reflected in Table 8.47 and in Figure 8.62. The power
and energy values given in Table 8.48 are those develop-
ed by ISER and used in the development: selection
studies. Annual growth rates range from 1.99 to 5 .. 96
percent for very low and high forecasts with a mediur-
generation forecast of 3.96 percent.
(c) Battelle Load Forecasts
As part of its study of Alaska Rai lbelt Electric Energy Alterna-
tives, Reference 6, Battelle did extensive work in reviewing the
1980 ISER forecasts, methodology, and data, and produced a new
series of forecasts. These forecasts built on the base of infor-
mation andmodellng established by ISER's 1980 work and, with the
assistance of ISER, developed new models for forecasting Rai lbelt.
economic activity and resulting e 1 ectric a 1 energy demands.. The
resulting forecasts were adopted directly for use in final genera-
tion planning studies under this feasibility study.
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These revised forecasts included both an energy and peak capacity
projection for each year of the study period (1982&2010). The pro-
jection left out portions of electrical demand which would be
self-supplied~ such as much of the military demand and some of the
industria 1 demand. In addition, these forecasts took into account
the conservation technology and market penetration likely to take
place. Details of the Battelle forecasts and methodology are
available in a report produced by Battelle in early 1982 (8). The
demand forecasting process is summarized in the following three
paragraphs.
Figure 8.63 shows the electricity demand forecasting process used
by Battelle. The forecasting process contains two steps. The
first step combines sets of consistent economic and policy assump-
tions (scenarios) with economic models from the ISER to produce
forecasts of future economic activity, population,· and households
in the Railbelt region and its three load centers. In the second
step, these forecasts are combined with data on current end uses
of electricity in the residential sector, data on the size of the
Railbelt commercial building stock, data on the cost and perfor-
mance of conservation, assumptions concerning the futu~'e prices of
electricity and other fuels, and future uses of electricity to
produce demand forecasts.
The economic and population forecasts, energy use data, and other
assumptions are all entered into a computer-based electricity·
demand forecasting model called the Railbelt Electricity Demand
(RED) Model. The RED model generates forecasts of housing stock
and commercial building stock and the price-adjusted intensity of
energy use in both the residential and commercial (including
government) sectors. It also adds estimates of major industrial
electrical energy demand and miscellaneous uses such as street
1 i ghting. These forecasts are adjusted for specific energy con-
servation policies, and then the major end-use sector forecasts
are combined by the model into forecasts of future annual demand
for electric energy for each of the Railbelt's load centers. ·The
combined annual loads are adjusted by an annual load factor to
estimate future annual peak demand by load center. Finally~ the
peak loads are added together and multiplied by a diversity facto,-
( to adjust for the fact that peak loads for djfferent load centers
do not coincide) to derive peak demand for the Railbelt. More
detai·l on the REO model can be found in Reference 7.
.~
The . projected cost of power affects these forecasts. Because the
size of demand for power affects the size, number, and cost of
generating facilities that may have to be built to meet the
demand (which in turn affects· the cost of power), several passes
through the Rf:'O ~•adel with constant economic assumptions and vary-
ing costs of power are required to produce a final forecast.
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Th.e Battelle study produced numerous load forecasts which corres:..
ponded to different development plans. The plans vari~d due to
different f~conomic scenarios and costs of power. from these sep-
arate forecasts, a high, medium and low forecast were selected for
project planning and economic and financial feasibility studies.
The Battelle forecasts are based on enet~gy sales, and have the·reo
fore been ildjusted by an addition of an estimated 8 percent for
transmission losses to arrive at the suppl_y forecast to be used in
generation planning. Table 8.49 and Figure B.64 present the three
Battelle forecasts which were prepared to bracket the range of
electrical demand for the future.
It should be noted that the loiid forecast figures vary in absolute
v a 1 ues of peak demand and energy from those figures in the refer-
enced Battelle studies. This minor variance (approximately 5-8
percent in the project development years) is due to the revision
in the Battelle forecasts in 1982 after the feasibility work on
Susitna proceeded using December 1981 numbers. ·
The Battelle forecasts were used in second stage generation plan-
ning studies. The second stage studies focused on the economic·
and financial -feasibility of the selected Susitna project and the
sensitivity of the analyses to variation of key study assumptions ..
The differences between the earlier ISER forecasts used in
development selection studies and the revised Battelle forecasts
are not ·considered to be significant enough to have altered ~he
conclusions of the earlier studies. The Railbelt generation plan-
nil'lg studies undertaken for Susitna feasibility assessment were
based on the Battelle medium forecast. The high and low Battelle
forecast~ were used as a basis for sensitivity testing.
No additional information on load patterns relative to monthly and
daily shifting of load shapes was developed in the Battelle fore-
casts.. Thus, the historical data developed to use with the 1980
ISER forecasts were also used with the Battelle forecasts •
5.2 -Market and Price for Watana Output in 1994
It has been p 1 an ned that Watana energy wi 11 be supplied at a single
wholesale rate on a free market basis.. Th)s requires, in effect~ that
Susitna energy be prjced so that it is attractive even to !Jtilities
with the lowest cost alternative source of energy. On this basis it is
estimated that for the marketable 3315 GWh of energy generated by
Watana in 1994 to be attractive, a price of 145 mills per kWh in 1994
dollars is required. Justification for this price is illustrated in
Figure B.65.. Note that the assumption is made that the only capital
costs which would be avoided in the early 1990s would be those due to
the addition of new coal-fired generating plants (i.e., the alternative
2 x 200 MW coal-fired Beluga station).
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The financing considerations under which it would be appropriate for
Watana energy to be sold at approximately 145 mills/.kWh price are pre-
sented in Exhibit D; however., it should be noted that some of the
energy which would be displaced by Watanats 3315 GWh would have been
rtenerated at a lower cost than 145 mills, and utilities might wish to
·aeiay accepting it at this price until the escalating cost of natural
gas or other fuels made it more attractive. A number of approaches to
the resolution of this problem can. be postulated, 1nc1uding pre..,con-
tract arrangements ..
{a) Contractual Preconditions for Susitna Energy Sale
It will be necessary to contract with Railbelt Utilities for the
purchase of Sus i tna capacity and energy on a basis appropriate to
support financing of the project •
Pricing policies far Susitna output are assumed to be constrained
by both cost {as defined by State of A 1 ask a Senate Bi 11 25) and by
the price of energy from the best thermal option.
Marketing Susi tna• s output · within these twin constraints would
ensure that all state. support for Susitna flowed through to con-
sumers and under no circumstances were prices to consumers higher
than they would have been under the best thermal option. In addi-
tion~ consumers would also obtain the long-term economic benefits
of Susitna•s low cost energy.
(b) Market Price for Watana Output f995-200J:.
After its initial entry into the system in 1994~ the price and
market for the 3315 Gwh of Wataria output is consistently upheld
over the years to 2001 by the projected 20 percent increase in
total demand over this periodo
There would, as a result, be a 70 percent increase in cost savings
compared with the best thermal alternative. The increasing cost
per unit of output from a system without Susitna is illustrated in
Figure B.66.
(c) Market and Price for Watana and Devil Canyon Output in 2003
A diagramatic analysis of the total cost savings which the com-
bi ned Watana and De vi 1 Canyon output wi 11 confer on the system
compared with the present thermal option in the year 2003 is shown
in Figure B.67. These total savings are divided by the energy
contributed by Susitna to indicate a p'rice of 250 mills per kWh as
the maximum price which can be charged for Susitna output. Here
again, the prqblem of competing with lower cost comb·ined cycle,
gas turbines, etc., wi 11 have to be addressed; however 1 this prob-
1 em is likely to be short term in nature, since by this time
period these therma 1 power faci 1 it i es wi 11 be approaching retire-
ment.
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Only about 90 percent of the total Susitna output will be absorbed
by the system in 2002; the balance of the output will be progress-
; vely absorbed over the following . decade. This wi 11 provide
increasing total sav-ings to the system from Susitna with no asso-
ciated increase in costs.
(d) Potential Impact of State Appropriations
In the preceding paragraphs the maximum price at which Susi tna
energy could be sold has been identified.. Sale of the energy at
these prices wi 11 depend upon the magnitude of any proposed state,
appropriation designed to reduce the cost of Susitna energy in the
earlier years. At significantly lower prices it is likely that
the total system demand will be higher than assumed. This, com-
hi ned with a state appropriation to reduce the energy cost of
Watana energy, would make it correspondingly easier to market the
output from the Susitna development; however, as the preceding
ana1ysi s shows, a viable and strengthening market exists for the
energy from the development that would make it possible to price
the output up to the cost of the best thermal alternative.
(e) Conclusions
Based on the assessment of the market for power and energy output
from the Susitna Hydroelectric Project, it has been concluded
that, with the appropriate level of state appropriation and with
pricing as defined in Senate Bill 25, an attractive. basis exists~
particularly in the long term, for the Railbelt utilities to
derive benefit from the project. It should be recognized that
contractual arrangements covering purchase of Susitna output wi 11
be an essent i a 1 precondition for the actua 1 commencement of pro-
ject construction. These contractual arrangements will be pursued
during the licensing and design phase of the project.
5.3 -Sale of Power
Electrical energy from the Susitna Hydroelectric Project will be sold
to ut1lities serving the Anchorage/Fairbanks net.
The potential customers for Susitna power utilities in the Railbe,lt
include:
-Fairbanks Municipal Utility System;
-Homer Electric Association;
Anchorage Municipal Light & Power Department;
-Chugach Electric Association;
-Golden Valley Electric Association;
-~atanuska Electric Association;
-Seward Electric System; and
-Copper Valley Electric Association •
A more detailed discussion of marketing can be found in Reference 8.
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6 -FUTURE SUSITNA BASIN DEVELOPMENT
The Alaska Power Authority has no current plans for further development
of th~ Watana/Devi 1 Canyon system and no p 1 ans for further water power
projects in the Susitna River Basin at this time.
Deva lopment of the proposed projects wou 1 d prec 1 ude further major
hydroelectric development in the Susitna basin, with the exception of
major storage projects in the Susitna basin headwaters. Although these
type ·of p 1 ans have been considered in the past, they · are neither
active nor anticipated to be so in the foreseeable future ..
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EXHIBIT B ... STATEMENT OF PROJECT OPERATION AND RESOURCES UTILIZATION __________________________ " ____________________________ __
LIST OF REFERENCES
1. Acres American Inc., Susitna Hydroelectric Project, Development
Selection Report, prepared for the Alaska Power Authority,
December 1981..
2 •. Woodward-Clyde Consultants~ Final Report on Seismic Studies for:
Susitna Hydroelectric Project, prepared for Acres American
Inc., February 1982.
3. Acres American Inc., Susitna Hydroelectric Project, 1980-81 Geo-
t~chnical Report, prepared for the Alaska Power Authority,
"F'ebruary 19827-
4. Acres American Inc., Susitna Hydroelectric Project, Feasibility
E_eport, prepared for the Alaska Power Authority, March 1992 ..
5. General Electric Company, OGPS User's Manual, May 1979.
6. B;lttelle Pacific Northwest Laboratories, Raflbelt Electric Power
Alternatives Study: Evaluation of Railbelt Electric Energy
Plans, preparea for the Office of the Governor, State of
Alaska, August 1982,. ·
7. Battelle Pacific Northwest Laboratories, The Railbelt Electricity
Demand (RED) Model Specifications Report, prepared for tlie
Office of the Governor, State of Alaska~ August 1982.
8. Acres American Inc..., Susitna Hydroelectric Project Referenc(~
Report, Economic, Maf"ketfng and Financial Eva.luation, prepared
for the Alaska Power Authority, April 1982.
------------------
TABLE 8.1: POTENTIAL HYDROELECTRIC DEVELOPMENT
Capital Average Economic1
Dam Cost Installed Annual Cost of Source
Proposed Height Upstream $ million Capacity Energy Energy. of
Site Type ft. Regulation (1980) (MW) Gwh $/1000 kWh Data
Gold Creek2 fill 190 Yes 900 260 1,140 37 USBR 1953
Olson
(Susitna II) Concrete 160 Yes 600 200 915 31 USBR 1953
KAiS-ER 1974
COE 1975
Devil Canyon Concrete; 675 No 830 250 1,420 27 This Study
Yes 1,000 600 2,980 17 n
High Devil Canyon u
(Susitna I) fill 855 No 1,500 800 3,540 21 !I
Devil Creek2 fill Approx No 0-
850.
Watana fill 8BO No 1,860 BOO 3,250 28 II
Susitna III fill 670 No 1,390 350 1,580 41 II
Vee fill 610 No 1,060 400 1,370 37 II
t-taclaren 2 Fill 185 No 530 4 55 180 124 • H
Denali Fill 230 No 480 4 60 245 '81 "
Butte Creek2 fill Approx No 40 1303 USBR 1953
150
Tyone2 fill Approx No 6 223 USBR 1953
60
Notes:
(1) Includes AFDC, Insurance, Amortization, and Operation and Maintenance Costs~
(2) No detailed engineering or energy studies undertaken as part of this study.
()) These are approximate estimates and serve only to rep"t"esent the potential of these two damsites in perspective.
(4) Include estimat.ed costs of power generation facility. ·
--- - - - - - - - - - - - - - - - - -
D A· M
Site Type
Gold Creek fill
Olson
(Susitna II) Concrete
Devil Canyon fill
Concrete
Arch
Concrete
Gravity
High !>evil Canyon fill
(Susitna I)
Devil Creek fill
Watana
Susitna III
Vee
Maclaren
Denali
Notes:
fill
fill
fill
fill
fill
TABLE B.2 -COST COMPARISONS
Capital Cost Estimate2 (1980 $)
A c R £ s 1980 o T A E R s
Installed Capital COst Installed Capital Cost Source and
Capacity -MW $ million Capacity -MW $ million Date of Data
800
350
400
55
60
1,860
1,390
1,060
530
480
792
445
None
890
550
630
910
1,480
1,630
770
500
USR6 1968
COE 1975
COE 1975
COE 1978
COE 1975
COE 1978
KAISER 1974
COE 1975
COE 1975
(1) Dependable Capacity
(2} Excluding Anchorage/fairbanks transmission intertie, but including local access and transmission.
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TABLE 8.3: DAM CREST AND FULL SUPPLY LEVELS
Staged Full Dam Average
Dam Supply Crest Tailwatar Site Construction level -Ft. level -Ft. level -ft.
Gold Creek No 870 880 680
Olson No 1,020 1,030 810
Portage Creek No 1,020 Ln3n. 870 ·-,---
Devil Canyon -
intermediate
height No 1,250 1,270 890
Devil Canyon ~
full height No 1,450 1,470 890
High Devil Canyon No 1,610 1,630 1,030.
No 1,750 1,775 1,030
Watana Yes 2,000 2,060 1,465
Stage 2 2,200 2,225 1,465
Susitna Ill No 2,340 2,360 1,810
Vee No 2,330 2,350 1,925
Maclaren No 2,395 2,405 2,300
Denali No 2,540 2,555 2,405
Notes:
(1) To foundation level.
Dam
Heiglit1
ft.
290
310
250
465
675
710
855
680
880
670
610
185
230
------------------
------------------
TABLE 8.5 -RESULTS OF SCREENING MODEL
Total Demand Optimal Solution first Suboptimal Solution Second Suboptimal Soultion
Max. Inst. Total Max.· · Inst. Tot a! Max. Inst. Totat
Cap. Energy Site Water Cap. Cost Site Water Cap .. Cost Site. Water Cap. Co.st
Run MW GWh Names Level MW $ million Names Level MW $ million Names Level MW $ mi.lli:on
1 400 1750 High 1580 400 885 Devil 1450 400 970 W£.tana 1950 400 9aG
Devil Canyon
Canyon
2 aoo 3500 High 1750 800 1500 Watana 1900 450 1130 Watana 2200 800 186klJ
Devil
Canyon
Devil
Canyon 1250 350 710
TOTAL BOO 1840
3 1200 5250 Watana 2110 700 1690 High 1750 800 1500 High 1150 820 1500
Devil Devil
Canyon Canyon
Devil 1350 500 800 Vee 2350 400 1060 Susitna 2.100 380 1260
Canyon III
TOTAL 1200 2490 TOTAL 1200 2560 TOTAL 1200 2160
4 1400 6150 Watana 2150 740 1770
N 0 SOLUTION N 0 S 0 L U T I 0 N
Devil 1450 660 1000
Canyon
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TABLE 8.6: INFORMATION ON THE DEVIL CANYON DAM AND TUNNEL SCMEMES
De.vil Canyon Tunnel Scheme
Item Dam 1 l }
Reservoir Area
(Acres) 7,500 320 0 3,900
River Miles
Flooded 31.6 2.0 0 15.8·
Tunnel Length
(Miles) 0 27 29 13.5
Tunnel v91ume
(1000 Vd ) 0 11,976 12,863 J, 732.
Compensating Flow
Release (cfs) 0 1,000 1,000 1,000
Reservoir Volume
(1000 Acre-feet) 1,100 9.5 -350
Dam Height
(feet) 625 75 --245
Typical Daily C)
~
Range of Discharge
From Devil Canyon 6,000 4,000 4,000 8,300
Powerhouse to to to to
(cfs) 13,000 14,000 14,000 8,900
Approximate
t-1aximum Daily
Fluctuations in
Reservoir (feet) 2 15 --4
Notes:
3 Estimated, above existing rock elevation.
4
0
0 '
29
5,131
1,000
--
--
3,900
to
4,200
--
-----·------·-.. ----·--
TABLE B. 7 -DEVIL CANYON TUNNEL SCHEMES
COSTS, PO\\ER OUTPUT AND AVERAGE ANNUAL ENERGY
Installed Levi! Canyon
CaE!aci~ (MW) Incre~sa 1 in Average Annual
Watanavil canyon Installed Capacity Energy
Stage Tunnel (MW) (Gwh)
STAGE 1:
Watana Dam BOO
STAGE 2i
Tunnel:
-Scheme 1 800 550 550 2,050
-Scheme 2 70 1,150 420 4,750
-Scheme 32 850 330 360 2,240
-Scheme 4 600 365 365 2,490
Notes:
(1) Increase over single Watana, BOO HW development 3250 Gwh/yr
(2) Includes power and energy produ:::ed at :r-e-regulation dam
(3) Energy cost is based on an economic analysis (i.e. using 3 percent interest rate)
. ...
Increase 1 in Tunnel Scheme
Average Total Project
Pnnual fnergy Costs
(Gwh) $ Million
2,050 1960
1,900 2320
2,180 1220
890 1490
3 CO.St or
A!:llitition¥-
~ergy
(&mills/kWh)
-42.6
'52.9
~4 .. 9
73 .. 6
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TABLE 8.8 -CAPITAL COST ESTIMATE SUMMARIES
TUNNEL SCHEMES
COSTS IN. $MILLION 1980 --
Item ~~---------------------------·'~-------
Land and damages, reservoir clearing
Diversion works
Re-regulation dGm
Power system
(a) Main tunnels
(b) Intake 7 powerhouse, tailrace
and switchyard
Secondary power station
Spillway system
Roads and bridges
Transmission lines
Camp facilities and support
Miz~ellaneous*
Mobilization and preparation
TOTAL CONSTRUCTION COST
Contin~encios (20%)
Engineering, .. !!:!!L9wner' s Administration
TOTAL PROJECT COST
!$57
123
Two 3o ft
ai~ tunn~:.s
-~
14
J'5
10~ 0
sao
21
42
42
15
131
8
47
1 '137
227
136
1,500
One 40 ft
dis tunnel
14
35
102.
•'
576
453
123
21
42
42
15
117
8
47
1,015
203
122
1,340
----------·-·· -... -·--
. .
TABLE 8.9. SUSITNA DEVELOPMENT PLANS
Cumulative
Stage/Incremental Data System Data
Annual
Maximum Energy
Capital Cost Ea~liest Reservoir Seasonal Production Plant
$ Millions On-line Full Supply Draw-Firm Avg. Factor
Plan Stage Construction (1980 values) Date 1 level -ft. down-ft GWH GWH. ~
1.1 1 Watana 2225 ft. 800MW 1860 1993 2200 150 2670 3250 46
2 Oevi-:. Canyon 1470 ft
600 MW 1000 1996 1450 100 5500 6230 51
TOTAL SYSTEM 1400 MW 2860
1.2 1 Watana 2060 ft 400 f>1W 1570 1992 2000 100 1710 2110 60
2 Watana raise to
2225 ft 360 1995 2200 150 2670 2990 85
3 Watana add 400 MW
capacity 1302 1995 2200 150 2670 3250 46
4 Devil Canyon 1470 ft
600 MW 1000 1996 1450 100 5500 6230 51
TOTAL SYSTEM 1400 MW 3060
1.3 1 Watana 2225 ft 400 MW 1740 1993 2200 150 2670 2990 85
2 Watana add 400 MW
capacity 150 1993 2200 150 2670 3250 46
3 Devil Canyon 1470 ft
600 MW 1000 19.96 1450 100 5500 6230 51 -TOTAL SYSTEM 1400 MW 2890
0
------
TABLE B~~ (Continued)
Plan
2.1
2.2
2.3
3.1
Stage
1
2
1
2
3
1
2
3
1
2
Construction
High Devil Canyon
1775 ft BOO MW
Vee 2350 ft 400 MW
TOTAL SYSTEM 1200 MW
High Devil Canyon
1630 ft 400 MW
High Devil Canyon
add 400 MW Capacity
raise dam to 1775 ft
Vee 2350 ft 400 MW
TOTAL SYSTEM 1200 MW
High Devil Canyon
1775 ft 400 MW
High Devil Canyon
add 400 MW capacity
Vee 2350 ft 400 f.~W
TOTAL SYSTEM 1200 MW
Watana 2225 ft 800 t4\'!
Wal.ana add :;o MW
tunnel 330 MW
TOTAl SYSTEM 1180 MW
Capital Cost
$ Millions
(1980 values)
1500
1060
2560
1140
500
10JO
2700
1390
-140
1060
2590
1960
Cumulative
Stage/Incremental Data System Data
Annual
Maximum Energy
Earliest Reservoir Seasonal Production Plant
On-line full Supply Draw-firm Avg. factor
1 level -ft. Date down-ft. GWH GWH 01
Ill
19943 1750 150 2460 3400 49
1997 2330 150 3870 4910 47
1993 3 1610 100 1770 2020 58
1996 1750 150 2460 3400 49
1997 2330 150 3870 4910 47
19943 1750 150 2400 2760 79
1994 1750 150 2460. 3400 49
1997 2330 150 387C 4910 47
1.993 2200 150 2670 3250 46
1995-1475 4 4890 5430 53
.. -----------:--·--..
TABlE 8.9 (Continued)
Cumulative
Stage/Incremental Data System Data
Annual
Maximum Energy
Capital Cost Earliest Reservoir Seasonal Production Plant
$ Hillions On-line full Supply Draw-firm Avg. factor
0 Plan Stag~ Construction (1980 values) Date 1 level -ft .. down-ft. GWH GWH %
3.2 1 Watana 2225 ft 400 MW 1740 1993 2200 150 2670 2990 85
2 Watana add 400 MW
capacity 150 1994 2200 150 2670 3250 46
3 Tunnel 330 MW ada
50 MW to Watana 1500 1995 1475 4 4890 5430 53 -3390
4.1 1 Watana
2225 ft 400 KW 1740 1995 3 2200 150 2670 2990 85
2 Watana add 400 MW
capacity 150 1996 2200 150 2670 3250 46
3 High Devil Canyon
1470 ft 400 MW 860 1998 1450 100 4520 5280 50
4 Portage Creek
1030 ft 150 MW 650 2000 1020 50 5110 6000 51
TOTAL SYSTEM 1350 MW 3400
NOTES:
(1) Allowing for a 3 year overlap construction period between major dams.
(2) Plan 1.2 Stage 3 is less expensive than Plan 1.3 Stage 2 due to lower mobilization costs.
(3) Assumes fERC license can be filed by June 1984, ie. 2 years later than for the Watana/Devil Canyon Plan 1.
---~---------------
TABlE 8.10. SUSITNA ENVIRONMENTAL DEVELOPMENT PLANS
Cumulative Stage/Incremental Data System Data
i\rinual
Maximum Energy Capital Cost Earliest Reservoir Seasonal ProdEction Plant $ Millions On-line Full Supply Draw-Firm Avg. Factor Plan Sta e Construction (1980 values} 1 Level -ft. down-ft GWH GWH. DEAta
"'
,..,
10 ..: E1.1 1 Watana 2225 ft BOOMW
and Re-Regulation
2670" 3250
Dam 1960 1993 2200 150 46 2 Devil Canycn 1470 ft
400MW 900 1996 1450 100 5520 6070 58 TOTAl SYSTEM 1200MW "2lf6IT
£1.2 1 Watana 2060 ft 400MW 1570 1992 2000. 100 1710 2110 60 2 Watana raise to
2225 ft 360 1995 2200 150 2670 2990 85 3 Watana add 400MW
capacity and
Re-Regulation Dam 230 2
1995 2200 150 2670 3250 46 4 Devil Canyon 1476 ft
400MW 900 1996 1450 100 5520 6070 58 TOTAl SYSTEM 1200MW Jn6lf
E1.3 1 Watana 2225 ft 400MW 1740 1993 2200 150 2670 2990 85 2 Watana add 400MW
capacity and
Re-Regulat.ion Dam 250 1993 2200 150 2610 3250 46 3 Devil Canyon 1470 ft
400 MW 900 1996 1450 100 5520 6070 58 TOTAl SYSTEM 1200MW E'9rr
---· -· -.• : , .. -..
.J -;--~--
TABLE 8.10 (Continued)
Cumulative
Stage/Incremental Data System Data
Annual
Maximum Energy
Capital Cost Earliest Reservoir Seasonal Production Plant
$ Millions On-line full Supply Draw-firm Avg. Factor
Plan Stage Construction (1980 values) 1 Level -ft .. Date down-ft. GWH GWH "' IQ
E1.4 1 Watana 2225 ft 400MW 1740 1993 2200 150 2670 2990 85
2 Devil Canyon 1470 ft
400MW 900 1996 1450 100 5190 5670 81 -TOTAL SYSTEM 800MW 2640
E2.1 1 High Devil Canyon
1775 ft BOOMW and
Re-Regulation Dam 1600 19943 1750 150 2460 3400 49
2 Vee 2350ft 400MW 1060 1997 2330 150 3870 4910 47
TOTAL SYSTEM 1200MW 2660
E2.2 1 High Devil Canyon
1630 ft 400MW 1140 19933 1610 100 1770 2020 58
2 High Devil Canyon
raise dam to 1775 ft
add 400MW and
Re-Regulation Dam 600 ~976 1750 150 2460 3400 49
3 Vee 2350 ft 400 MW 1060 1997 2330 150 3870 4910 47
TOTAL SYSTEM 1200MW 2800
E2.3 1 High Devil Canyon
1775 ft 400MW 1390 19943 1750 150 2400 2760 19
2 High Devil Canyon
add 400MW capacity
and Re-Regulation
Dam 240 1995 1750 150 2460 3400 49
3 Vee 2350 ft (&00MW 1060 1997 233D 150 3870 4910 47
TOTAl SYSTEM 1200 2690
--: ----~ ----.. M:
' --·---; -"
~
TABLE B.10 (Continued)
Cumulative Stage/Incremental Data S~stem Data
Annual
Maximum Energy Capital Cost Earliest Reservoir Seasonal Production Plant $ Millions On-line Full Supply Draw-firm Avg. factor
Plan Stage Construction. (1980 values) '1 level -ft. down-ft. GWH GWH % Date
£2 .. 4 1 High Devil Canyon
1755 ft 400MW 1390 19943 1750 150 2400 2760 79 2 High D~vil Canyon
add 4COMW capacity
and Portage Creek
Dam 150 ft 790 1995 1750 150 3170 4080 49 3 Vee 2350 ft
400MW 1060 1997 2330 150 4430 5540 47 TOTAl SYSTEM :miT'
E3.2 1 Watana
2225 ft 400MW 1740 . 1993 2200 150 2670 2990 85 2 ~atana add
400 MW capacity
and Re-Regulation
Dam 250 1994 2200 150 2670 3250 46 3 Watana add 50MW
Tunnel Scheme 330MW 1500 1995 1475 4 4890 5430 53 TOTAL SYSTEM 1.180MW 349lf
£4.1 1 Watana
"
1995 3 2225 ft 400MW 1740 2200 150 2670 2990 85 2 Watana
add 400MW capacity
and Re-Regulation
Dam 250 1996 2200 150 2670 3250 46 3 High Devil Canyon
14 70 ft 400MW 860 1998 1450 100 4520 5280 50 4 Portage Creek
1030 ft 150t-tW 650 2000 1020 50 5110 6000 51 TOTAL SYSTEM 1350 MW ;;mr
NOTES:
t1) Allowing for a 3 year overlap construction period between major dams.
(2) Plan 1.2 Stage 3 is less expensive than Plan 1.3 Stage 2 due to lower mobilization costs •.
(3) Assumes f£RC license can be filed by June 1984, ie. 2 years later than for the Watana/Devil Canyon Plan 1.
. . • • ! .' . . . ~ "("" ·.. . .
• • • 4
~ . ~ . . ~ .... -.
# • • ~ • • . . . . ;' . • • • • • •• _. :\ 0 • • • • • . . . . . . . . . " . . . ~. . .
: : .. . . ' . . . . . . : . . ; • .. ·.:., .. -; . ·: : .... J . I
TABLE B.11 -RESULTS Of ECONOMIC ANALYSES Of SUSITNA PLANS -MEDIUM LOAD fORECAST
Susitna Devei~ment Pian Inc-Installed Capacify (MW) by Total System Total System
· line Oates Categor~ in 2010 Installed Present Remarks Pert~ng to
Plan Stages OGP5 Run Thermal -R~dro Capacity In Worth Cos\ the Susitna ff~
No. -r 7 ) 2i Id. No .. i::oai Cas iUI Other ~us~tna 2010-MW $ Million Develoe!!!ent F:Datn
E1.1 1993 2000 LXE7 300 426 0 144 1200 2070 5850
£1.2 19~n 1995 1997 2002 L5Y9 200 501 0 144 1200 2045 6030
£1.3 1993 1996 2000 L8J9 300 426 0 144 1200 2070 5850
1993 1996 L7W7 500 651 0 144 BOO 2095 6960 Stage 3, Oevii il::snyon Dam
not const."ruct~d
199B 2001 2005 LAD7 400 276 30 144 1200 2050 6070 Delayed in~lemerntation
schedule
(1.4 1993 2000 LCK5 200 726 50 144 BOO 1920 5B90 Total develop~~t limited
to BOO MW
l\bdified
£2 .. 1 1994 2000 LB25 400 651 60 144 . BOO 2055 6620 High Devil C~~~ limited
to 400 MW
E2.3~ 1993 1996 2000 L601 300 651 20 144 1200 2315 6310
1993 1996 L£07 500 651 30 144 BOO 2125 6720 Stage 3, Vee ~~, not
constructed
Modifi.ed
£2.3 1993 1996 2000 LEB3 300 726 220 144 1300 2690 6210 Vee dam repla~ by
l' Chakachamna d~
3.1 1993 1996 2000 l607 200 651 30 144 1180 2205 6530
Special
6230 Capital cost o:f tunnel 3.1 199.3 1996 2000 L615 200 651 30 144 11BO 2205
reduced by 50 pt}'teent
£4.1 1995 1996 199'8 LTZ5 200 576 30 144 1200 2150 6050 Stage 4 not constructed
NOTES:
(1) Adj!Jsted to incorporate cost of re-regulation dam
TABLE 8 .. 12-RESULTS Of ECONOMIC ANALYSES Of SUSITNA PLANS-LOW AND HIGH LOAD fORECAST
....
~usitna Deveio~nE Pian Inc. lnotailed ~opacity {MW) by Total System · Total System on :tne Dates Categor~ in 2010 Installed Present Remarks Pertain~T~ tn
. Plan St!9es OGP5 Run -----rfierma.I · R~dro Capacity In WDrth Cost the Susitna Ba~n
No. ,-2 ~ 4 Id. No .. Coai "Gas' llii lither Susi£na 2010-MW $ Million Develo~ment PI~
VERY lOW f01l£CAST1 -
£1.4 '1997 2005 l7B7 0 651 50 144 800 1645 365(!
LOW LOAD fORECAST ----
£1.3 1993 1996 2000 Low energy dem.st!Id does not
warrant plan c~ities
E1 .. 4 1993 2002 LC07 0 351 40 144 800 1335 4350
19~13 LBK7 200 501 80 144 400 1325 4940 Stage 2, Devil ~nyon Oam,
not constructecti
£2.1 199J 2002 LG09 100 426 JO 144 800 1500 4560 High Devil Can~Qn limited
to 400 MW
1993 LBU1 400 501 0 144 400 1445 4850 Stage 2, Vee 0~ not
constructed
£2 .. 3 1993 '1996 2000 low energy dem~ does not
Special
warrant plan c~~cities
3.1 1993 19~16 2000 l613 0 576 20 144 780 1520 4730 Capital cost o~ tQnnel
reduced by 50 pa~~ent
3.2 1993 2002 L609 0 576 20 144 780 1520 5000 Stage 2, 400 MW &ddition
to Watana, not ~structed
HIGH LOAD fORECAST --
E1.J 1993 19'96 2000 LA73 1000 951 0 144 1200 3295 10680
t-bdified
20052 £1.3 1993 1996 2000 LBV7 800 651 60 144 1700 3355 10050 Chakachamna hy<lro&lectric
generating statl.on (480 MW)
brought on lim~ as a fourth
stage
E2.3 1993 1996 2000 LBVJ 1300 951 90 144 1200 3685, 11720
Modified
2003 2 E2.3 1993 1996 4t000 LBY1 1000 876 10 144 1700 3730 11040 Chakachamna hydroel~~tric
genernting station (480 MW)
brought on line as a fourth
stage
NOTE: -
(1) Incorporating load m.anagement and conservation
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TABLE 8.13 -ANNUAL FIXED CARRYING' CHARGES
~conom1c Parameters
Economic Cost of
Life Money Amortization Insurance
Project Tl::ee -Years % %
Thermal -Gas Turbine
(Oil Fired) 20 3.00 3.72
-Diesel, Gas Turbine
(Gas Fired) and
Large Steam
Turbine 30 3.00 2.10
-Small Steam Turbine 35 3.00 1.65
Hydropower
Market Prices
50 3.00
FUEL COSTS AND ESCALATION RATES
Naturat Gas Coal
Base Period (January 1980)
-Prices ($/million Btu)
0.89
Shadow (Opportunity) Values
$1.05
2.00
$1.15
1.15
Real Escalation Rates (Percentage)
-Change Compounded (Annually)
1980 -1985
1986 -1990
1991 -1995
Composite (average) 1980-1995
1996 -2005
2006 -2010
0
1o79%
6D.20
3.99
3.98
3.98
0
9.56%
2.-39
-2.87
2.93
2.93
0
1:11
JO
0.25
0.25
0.25
0.10
DiaEIT!ate
$4.00
4.00
3.38%
3.09
4.27
3.58
3 .. 58
0
----,. . .
TABLE B.14-SUMMARY Of THERMAL GENERATING RESOURCE PLANT PARAMETERS
PLAN T 1 y P E
CDAL-riRED S~R toi'IHNED GAS
Parameter CYClE TURBINE DIESEl
500 MW 250 MW 100 MW 250 MW 75 MW 10 MW
Heat Rate (Btu/kWh) 10,500 10,500 10,500 8t500 12,000 11,500
O&H Costs
Fixed O&H ($/yr/kW) 0.50 1.05 1.30 2.75 2.75 0.50
Variable O&M ($/MWH) 1.40 1.80 2.20 0.30 0.30 5.00
Outages
Planned Outages (%) 11 11 11 14 11 1
Forced Outages (~) 5 5 5 6 3.8 5
Construction Period (yrs} 6 6 5 3 2 1
Sta~t-up Time (yrs) 6 6 6 4 4 1
Total Ca~ital Cost
($ mil ~on)
Railbelt: 175 26 7.7
Beluga: 1,1;o 630 290
· Unit Caeital Cost ($/kW} 1
Railbelt: 728 250 778
Beluga; 2473 2744 3.102
Notes:
(1) Including AFDC at 0 percent ·escalation and J percent interest.
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TABLE 8.15 -ECON~MIC BACKUP DATA FOR EVALUATION OF PLANS
Parameter
Capital Investment
Fuel
Operation and Maintenance
TOTAL:
Total PtesenE worth Cost for 1981 -zo40
Generation Plan
With High Dsvil
Canyon -Vee
2800 (44)
3220 (50)
350 (6)
6370 (100)
Period $ Million (% Total)
i1eneration Plan Generation Plan
With Watana -With Watana -
Devil Canyon Dam Tunnel
2740 (47) 3170 (49)
2780 (4.7) 3020 (46)
330 (6) 340 (5)
5850 (100) 6530 (100}
A!! Th8v.al
Generation Plans
2520 (31)
.5240 (64)
370 (5)
8130 (100)
--.,. ---·~~
~~~ -~·---
TABlE 8.16-ECONOMIC EVALUATION OF DEVIL CANYON DAM AND TUNNEL SCHEMES AND WATANA/DEVIL CANYON AND HIGH DEVIl CANYON/VEE PtA~
ECONOMIC EVAlUATION:
-Base Case
SENSITIVITY ANALYSES:
-load Growth
-Capital Cost Estimate
-Period of Economic
Analysis
-Discount Rate
-fuel Cost
-Fuel Coat Escalation
-Economic Thermal Plant
life
low
High
Period shortened to
(1980 -2010}
5%
8% (interpolated)
9%
80% basic fuel cost
0% fuel escalation
0% coal escalation
50% extension
0% extension
680
650
N.A.
Higher uncertainty assoc-
iated with tunnel scheme.
230
520
210
1040
generation
Higher uncertainty associated with
H.D.Co!Vee plan.
160
As both the capital and fuel costs associated with the tunnel
scheme and H.DoC./Vee Plan are higher than for Watana/Oevil
Canyon plan any changes to these parameters cannot reduce the
Devil Canyon or Watana/Oevil Canyon net benefit to below zero.
Remarks:
Economic ranking: De~iil Canyon
dent scheme is supe~iO'Et' to Tunnel
scheme. Watana/Devin 1tanyon dam
plan is superio~ ~o ~~ High
Devil Canyon dam/Vee, ~ plan.
The net benefit of t~
Watana/Dev il Canyon p-Ji~n remains
positive for the ran~ of load
forecasts considered~ No change
in ranking.
Higher cost uncertaiol~~s associ-
ated with higher cost
schemes/plans. Cost ~r~<::ertainty
therefore does not aft$~l
economic rankinge
Shorter period of evaluation
decreases economic differences.
Ranking remains unch~ed.
Ranking remains unchanged.
-
..
--
£nvironmental
Attribute
Ecological:
-Downstream fisheries
and Wildlife
Resident fisheries:
Wildhfe:
Cultural:
Land Usez
--.. ... •• ---
TABLE 8.17-ENVIRONMENTAl EVALUATION Of DEVIl CANYON DAM AND TUNNEl SCHEME
Com:erns
Effects resulting
from changes in
water quantity and
quality.
Loss of resident
fisheries habitat.
Loss of ~ildlife
habitat.
.,
J\Ppra1sal
(D1fferences in impact
of two schemes)
No signif1c~nt differ-
ence between schemes
regarding effects down-
stream of DevH Canyon.
Difference in reach
between Devil Canyon
dam and tunnel re-
regulat.icn dam.
Minimel d1fference3
between schf'.mes.
Minimal d1fferences
between schemes.
Inundation of Potential dtfferences
archeological sites. between schemes.
Inundation of Dev~l S1gn1f~cant d1fference
Canyon. between schemes.
Identiflcation
of difference
With the tunnel scheme con-
trolled flows between regula-
tion dam and downstream power-
house offers potential for
anadromous fisheries enhance-
ment in this 11 ~ile reach of
the rivet:. .
Devil Canyon dam would inundate
27 ~ilea of the ~itna River
and approximately Z miles of
Devil Creek. The tunnel schema
would inundate 16 miles of the
Susitna River.
The most sensiUve wildlife ha-
bitat in this. teech is upstream
of the tunnel re-regulation dam
where there is no significant
difference het~n the schemes.
The DeVll Canyon dam scheme in
addition inundates the river
valley between the two dam
sites resulting in a moderate
increase in i~scts to wildlife.
Due to lhe larger area inun-
.ated the probability of inun-
dating archeological sites is
increased.
The Devil Canyon is cons1dered
a unique rasource, BD percent
of which ~uld .be inundated by
the Devil Canyoo dBII scheme.
This would result in a loss of
both an aesthetic value plus
the potential fo~ ~ite water
recreation.
SCheme judged to have
Appraisal Judge.ent
the least potential i~ ---.tunnel oc
Not a factor in evaluation of
scheme.
If fisheries ern1ancement oppor-
tunity can be realized the tun-
nel scheme offers a positive
mitigation measure not available
with the Devil Canyon d813
scheme.. This oPPortunity is
considered moderate and favors
the tunnel scheme. However,
there are no current pl&ns for
such enhance111ent and feasibil-
ity is uncertain. Potential
value is therefore not signi-
ficant relntivfl to add1tional
cost of tunnel.
Loss of habitat. with dam scheme is
less than 5~ of total for Suaitna
main stem. 1hia reach of river is
therPfore not considered to be
higUr signific81il: for residUflt
fishe1ies and thus the difference
bet wee l the schemes is 111inor and
favors the tunnel scheme.
Moderate wildlife populationa of
moose, black bear, weasel, fox,
wolverine, other Slllall mammals
and songbirda and some riparian
cliff habitat for ravens and
raptors, in 11 111ilea of river,
would be lost with the dam scheme.
Th~:s, the difference in loss of
wildlife habitat is considered
moderate sod favors the tunnel
scheme.
Significant archeological
sites, if ident1fied, can proba-
bly be excavated. Additional
costs could range from several
hundreds to hundreds of thousands
of dollars, but are still consider-
ably less than th~ additional cost
of the tunnel scheme. This concern
is not considered a factor in scheme
evaluation.
The aesthetic end to some extent
the recreational losses associ-
ated with the de.velopment of the
Devil Canyon :dam is the main
aspect favoring the tunnel scheme.
However, current recreational us~s
of Devil Canyon are low due to
limited accesa. f'uture possibilites
include majot recreational develo~
ment with construction of restau-
rants, marinas, etc. Under such
conditions, neither scheme would be
more favorable.
X
X
X
X
OVERALL EVALUATION: The tunnel scheme has overall a lower impact on the environment.
--
...... •. ----~------.. -
Social
!1spect
Potential
non-renewable
resource
displacement
Impact on
state economy
Impact on
local economy
Seismic
exposure
Overall
Evaluation
TABLE 8.18-SOCIAL EVALUATION OF SUSITNA BASIN DEVELOPMENT SCHEMES/PLANS
Parameter
Million tons
Beluga coal
over 50 years
Risk of major
structural
failure
Potential
i£1llaCt of
failure on
hliilan life.
Tunnel
Schema
Devil Canyon
Dam Scheme
High Devil Canyon/
Vee Plan
Watana/Devil
Canyon Plan
80 110 170 210
All projects woulti have similar impacts on the state and
local economy.
All projects designed to similar levels of safety.
Any dam failures would effect the same downstream
population.
1. Devil Canyon dam superior to tunnel.
2. Watana/Devil Canyon superior to High Devil Canyon/Vee plan~
Remarks
Devil Canyon dam scheme
potential higher than
tunnel scheme. Watana/
Devil Canyon plan higher
then High Devil Canyon/
Vee plan.
Essentially no difference·
between plans/schemes.
--·
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TABLE 8.19 -ENERGY CONTRIBUTION EVALUATION OF THE DEVIL
CANYON DAM AND TUNNEL SCHEMES
Parameter
TotaL~nergy Prcduction
·capa61I1ty
Annual Average Energy GWH
Firm Annual Energy GWH
% Basin P~tential
Developed
Enerly Potential Not
Deve oped GWH "
Notes:
Darn
2850
2590
43
60
Tunnel
2240
2050
32
380
Remarks
Devil Canyon dam annually
develops 610 GWH and 540
GWH more average and firm
energy respectively than
the Tunnel scheme.
Devil Canyon schemes
develops more of the
basin potential.
As currently envisaged,
the Devil Canyon dam does
not develop 15 ft gross
head between the Watana
site and the Devil Canyon
reservsoir. The tunnel
scheme incorporates addi-
tional frict1on losses in
tunnels. Also the compen-
sation flow released from
re-regulation dam is not
used in conjunction with
head between re-regulation
dam and Devil Canyon.
(1) Based on annual average energy. Full potential based on USSR four
dam scheme.
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TABLE 8.20-OVERALL EVALUATION.OF TUNNEL SCHEME AND DEVIL CANYON DAM SCHEME
ATTRIBUTE
Economic
Energy
Contribution
Environmental
Social
Overall
Evaluation
sOPrn!dR PLAN
Devil Canyon Dam
Devil Canyon Dam
Tunnel
Devil Canyon Dam (Marginal)
Devil Canyon dam scheme is superior
Tradeoffs made:
Economic advantage of dam scheme
is judged to outweigh the reduced
environmental impact associated
with the tunnel scheme.
-----·-------
Env1ronmental Attribute
Ecolc;ical:
U J.Stteries
2) Wildlife
a) Moose
b) Cadbou
c) forbearers
d) B~rds and Boars
Cultural:
TABLE B.2t -ENVIRONMENTAL EVALUATION Of WATANA/OEVIL CANYON AND HIGII DEVIL CANYON/VEE DEVElOPMENT PLANS
Plan Comparison
No signiflcant difference in effects on downstream
anadromous fisheties.
HDC/V would inundate approximately 95 miles of the
Susitna River and 28 miles of tributary streams, in-
cluding the Tyone River.
W/DC would lnundnte approximately 84 miles of the
Suaitna River and 24 miles of tributary streams,
including Watana Creek.
Appraisal Judge~~~ent
Due to the avoidance of tho Tyone thvat",
lesser inundation or resident fisheries
habitat end oo oignificont different:-& in the
effects on anadrcmous fisheries, the W/OC plan
ia judged to hove less impact.
HDC/V would inundate 123 miles of critical winter river Due to the lowur potential for dire-ct impact
bottom habitat. .on illOOSe populat1ons Within the Susitna, the
W/OC plan is judged superior.
W/DC would inundate 108 miles of this river bottom
habitat.
HDC/V would 1nandate a large area upstream of Vee
utilized by tt,ree sub-populations of moose that range
in the ~~neast section of the basin.
W/DC would tnundate the Watana Creek area utilized by
moose. The condltion of this sub-population of moose
and the quaUty of the habitat they are using appears
to be decreEning.
The increased length of river flooded, especially up-
at rea. f•om the Vee dam site, would result in the
HDC/V plan ct"eating a greate~ potential division of
the Nelch1na herd's range. In addition, an increase
in range would be directly 'nundated by the Vee res-
ervoir.
The area floocfed by the Vee reservoir is considered
important to some key forbearers, particularly red fox.
This a>ea is judged to be more important than the
Watana Creek area that would be inundated by the W/DC
plan.
forest t.lolbitat, J.lltlOrlant for birds and black bears,
exist along the velley .slopes. The loss of tlua habi-
tat would be greater Wlth the W/OC plan.
There is a high potential for d1scovery of archeologi-
cal sites in the easterly region of the Upper Susitna
Basin. The WC/V plan has a greater potential of
ai'Fecting these sites. For other reaches of the river
the difference between plans is considered minimal.
Due to th~ potenU.al for a greater i~act on
th:t Nelch~na caribou herd, the IDC/V scheme
ir; considered inferior.
Due to the lesser potentl81 for iqJact on fur-
bearers the W/OC is judged to be superior.
The HDC/V plan is judged superior.
The W/OC plan is judged to hs.ve a lower po-
tential effect on archeological sites~
-
Plan judijed to have the
least ~otential i~act
fl)t/ DC
X
X
X
X
X
X
-
----•• .. .. -
TABLE B.21 (Continued)
Plan JUdged to have the
least rtential im7act ~E~nv~l~r~o~n~me~n~t~a~l~A-t~tr~l~b~u~t-e ______________ ~----~P~l~an~-C~~!s~m~n~------------------------------~A~rp~ra=i~s~a=l~Jud~g~~~~n~t--------~------~HOC~~~~------~w~oc~---
Aesthetic/
Land Use
With either sche:ee; the aesthetic quality of both
Dev1l Canyon Blld Vee C8llyon would be impaired. The
ti>C/V pl811 would a!so inundate Tsusena Falls.
Due to construct1oo at Vee Dam s1te and the size of
the Vee Reser~oir, the HD~/V plan would inherently
create access to more wilderness area than wo\lld the
W/DC plan.
Both plans impact the valley aesthetics. The
difference is considered minimal.
As it is easier to extend access than to
limit it, inherent access requirements were
considered detrimental and the W/DC plan is
judged .superior. The ecological sensitivity
of the area opened by the ti>C/V plan rein-
forces this judgement.
OVERALL EVALUATION: The W/DC plan is judged to be tmperial" to the tDC/V plan.
(The lower impact on birds and bears associated with l~/V plan is considered to bo out~eighed by all
the ather 1111pacts which favou•: the W/DC plan.)
!!!.!.§:
W = Watana Dam
DC= Devil Canyon Dam
HOC = High Devil Canyon Dam
V = Vee Dam
X
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TABLE 8.22 -ENERGY CONTRIBUTION EVAlUATION OF' THE WATANA/DEVIL CANYON
AND HIGH DEVIL CANYON/VEE PlANS .
Watana/ High Devil
Parameter Devil Canyon Canyon/Vee Remarks ------------~···--------------~----a---------~----------------~-----Total Energ¥ Prrlduction
. capabi!itx
Annual Average 1::nergy GWH
F'irm Annual Energy GWH
% Basin Potential
Developed (1 1
Enerl¥ Potential Not
Deve oped G~JH (2)
Notes:
6070
5520
91
60
4910
3870
81
650
Watana/Oevil Canyon
plan annually devel-
ops 1160 liifll and
1650 GWH more average
and firm energy re-
pectively than the
High Devil Canyon/Vee
Plan.
Watana/Dev~l Canyon
plan develops more of
the basin potential
As currently con-
ceived, the Watana/-
Devil Canyon Plan
does not develop 15
ft of' 9ross head
between the Watana
site and the Devil
Canyon reservoir.
The High .Devil
CanyonlVee Plan does
not develop 175 ft
gross head between
Vee site and High
Devil reservoir.
(1) Bssed on annual average energy. Full potential based on USBR four
dam schemes.
(2) Includes losses due to unutilized head.
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TABLE 8.2) -OVERALL EVALUATION OF THE HIGH DEVIL CANYON/VEE AND
WATANA/DE:VIL CANYON DAM PlANS
IDR160T£
Economic
Energy
Contribution
Environmental
Social
Overall
Evaluation
su?ER10R PLAN
Watana/Devil Canyon
Watana/Devil Canyon
Watana/Devil Canyon
Watana/Devil Canyon (Marginal)
Plan with Watana/Devil Canyon is
superior ·
Tradeoffs made: None
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TABLE 8.24: COMBINED WATANA AND DEVIL CANYON OPERATION
Watana Dam Watana* Devil Canyon* Total Crest Elevation Average Cost Cost Cost Annual Energy (ft MSL) ($ X 106) ($ X 106) ($ X 106)
2240 (2215
reservoir elevation) 4,076 1 '711 5,787
2190 (2165
reservoir elevation) 3,785 1, 711 5,496
2140 (2115
reservoir elevation) 3,516 1' 711 5,227
Watana Project alone (prior to year 2002)
Crest Elevation
(ft MSL)
2240
2190
2140
Average Annual
Energy (GWh)
3,542
3,322
3,071
* Estimated costs in January 1982 dollars, based on preliminary conceptual
designs, including relict channel drainage blanket and 20 percent contingencies.
TABLE 8.25: PRESENT WORTH OF PRODUCTION COSTS
Watana Dam
Crest Elevation
:::Cft MSL)
2240 (reservolr
elevation 2215)
2190 (reservoir
elevation 2165)
2140 (reservoir
elevation 2.115)
* LTPW in January 1982 dollars.
Present Worth
of Productign Costs
($ X 10
7,123
7,052
7,084
(GWh)
6,809
6,586
6,264
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I TABLE 8.26: DESIGN DATA AND DESIGN CRITERIA fOR fiNAL REVIEW Or LAYOUTS
I fmler flows
Average flow (over 30 years of record):
Probable maximum flood (routed):
Maximum inflow with return period of 1:10,000 years:
Maximum 1:10,000-year routed discharge: I
Maximum flood with return period of 1:500 years:
Maximum flood with return period of 1:50 years:
Reservoir normal maximum operating level:
Reservoir minimum operating leve~: I
I ' 12!!1
Type:
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Crest elevation at point of maximum super elevation:
Height:
Cutofr and foundation treatment:
Upstream slope:
Downstream slope:
Crest Wl.dth:
Diversion
Cofferdam type:
Cutoff and foundation:
Upstream cofferdam crest elevation:
Downstream cofferdam crest elevation:
Maximum pool level during construction:
Tunnels
Final closure:
Releases during impounding:
Spillway
Design floods:
Main spillway -Capacity:
-Control structure:
Emergency spill~ay -Capacity:
-Type:
Power Intake
Type:
Numbar of intakes:
Draw-off requirements:
Drawdown:
7,860 cfs
)26,000 cfs
156,000 cfs
115,-000 cfs
116,000 cfs
87,000 cfs
2215 ft
20jQ ft
Rockfill
2240 ft . .
890 ft above foundation
Core founded on rock; grout curtain and
downstream drains
2.4H :1V
2H:1V
50 ft
Rockfill
Slurry trench to bedrock
1585 ft
1475 ft
1580 ft
Concrete lined,
Mass concrete plugs
6,000 cfs maximum via bypass to outlet
structure
Passes PMF, preserving integrity of dam
with no loss of life
Passes routed 1:10,000-year flood with no
damage to structures
Routed 1:10,000-year flood
with 5 ft surcharge
Gated og~e crests
PMr minus 1:10,000 year flood
ruse plug
Reinforced concrete
6
Multi-level corresponding to temperature
strata
185 feet
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II TABLE 8.26: (Cont'd)
II Penstocks
Type:
I
Nllllber of penstocks:
Powarhousa
I Type:
Transformer area:
Control room and administration:
Access -Vehicle:
I -Personnel:
Power Plant
I Type of turbines:
Nuw~er and rating:
Rated net head:
Design flow:
I Normal maximum gross head:
Type of generator:
Rated output:
Power factor:
Frequency:
I Transformers:
Tailrace
II Water passages:
Surge:
Average tailwater elevation (full generation):
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Concrete-lined tunnels with downstream
steel liners
6
Underground
Separate gallery
Surface
Rock tunnel
Elevator from surface
Francis
6 X 170 MW
690 ft
• 3,500 cfs per unit
745 ft
Vertical synchronous
190 MVA o;9
60 HZ
13.8-345 kV, 3-phase
2 concrete-lined tunnels
Separate surge chambers
1458 ft
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PRELIMINARY REVIEW
Technical feasibility
Compatibility of layout
with known geological
and topographical site
features ·
Ease of construction
Physical dimensions
of component structures
in certain locations
Obvious cost differences
of comparable structures
Environmental accept-
ability
Operating characteristics
TABLE 8.27: EVALUATION CRITIERA
INTERMEDIATE REVIEW
Technical feasibility
Compatibility of layout
with known geological and
topographical site features
Ease of construction
Overall cost
Environmental accept-
ability
Operating characteristics
Impact on construction
schedule
FINAL REVIEW
Technical feasibility
Compatibility of layout
with known geological and
topographical site features
Ease of construction
Overall cost
Environmental impact
Mode of operation of spill-
ways
Impact on construction
schedule
Design and operating limita-
tions for key structures
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INTERMEDIATE REVIEW OF ALTERNATI~E ARRANGEMENTS
(January 1982 $ x 10 )
Diversion
Service Spillway
Eme~gency Spillway
Tailrace Tunnel
Credit for Use of Rock in Dam
Total Non-Common Items
Colllllon Items
Subtotal ·
Camp & Support Costs (16~)
Subtotal
Contingency (20~)
Subtotal
Engineering and
Administration (12.5%)
TOTAL
WP1
101.4
128.2
13.1
( 11. 7)
231.0
1643.0
1874.0
299.8 ._.....,._,_
2173.8
434.8
2608.6
326.1
2934.7
WP2 WP3
112.6 101.4
208.3 122.4
46.9 46.9
13.1 13.1
(31.2) (18.8)
349.7 265.0
1643.0 1643.0
0
1992.7 1908.0
318.8 305 .. 3
2311.5 2213.3
462.3 442.7
1773.8 ·2656.0
346.7 332.0
31.20.5 2988.0
~\
(1
WP4
103.1
267.2
8 .. 0
(72.4)
305.9
1643.0
1948.9
311.8
2260.7
452.1
2712.8
339 .. 1
30$1.9
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TABLE 8.29: DESIGN DATA AND DESIGN CRITERIA tOR
REVIEW OF ALTERNATIVE LAYOUTS
River tlows
Average flow (over 30 years of record):
Probable maximum flood:
Max. flood with return period of 1:10,000 years:
Maximum flood with return period of 1:500 years:
Maximum flood with return period of 1:50 years:
Reservoir
Normal maximum operating level:
Reservoir minimum operating level:
Area of reservoir at maximum operating level:
Reservoir live storage:
Reservoir full storage:
Dam
Type:
Crest elevation:
Crest length:
Maximum height above foundation:
Crest width:
Diversio;,
Cofferdam types:
Upstream cofferdam crest elevation:
Downstream cofferdam crest elevation:
Maximum pool level during construction:
Tunnels:
Outlet structures:
tina! closure:
Releases during impounding:
Spillway
Design floods:
Service spillway -capacity:
-control structure:
-energy dissipation:
Secondary spillway -capacity:
-control structure:
-energy dissipation~
Emergency spillway -capacity:
-type:
8,960 cfs
270,000 cfs
135,000 cfs (after routing
through Watana
42,000 cfs (after routing
through Watana
1455 feet
1430 feet
21,000 acres
180,000 acre feet
1,100,000 acre feet
Concrete arch
1455 feet
635 feet
20 feet
Rockfill
960 feet
900 feet
955 feet
Concrete lined
Low-level atructure with
slide closure gate
t~ass concrete plugs in
line with dam grout curtain
2,.000 cfs min. via fixed-cone
valves
Passes PMt, preserving
integrity of dam with no
loss of life
Passes routed 1:10,000-year
flood with no damage to
structures
45,000 cfs
tixed-cone valves
five 108-inch diameter
fixed-cone valves
90,000 cfs
Gated, ogee crests
Stilling basin
pmf minus routed 1:10,000-year
flood
Fuse plug
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TABLE 8.29: (Cont'd)
Power Intake
Type:
Tr~naformer area:
Access
Type of turbines:
Number and rating:
Rated net head:
Maximum gross he2d:
Type of generator:
Rated output:
Power factor~
,.
•
Underground
Separate gallery
Rock Tunnel
francis
4 x 140 MW
550 feet
565 feet approx.
Vertical synchronous
155 MVA
0.9
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TABLE 8 .. 30: SUMMARY OF COMPARATIVE COST ESTIMATES
PRELIMINARY REV!EW OF ALTERNAT~VE ARRANGEMENTS
(Jsnuery 1982 $ X 10 )
Item OC1 DC2 DC3
Land Acquisition 22.1 22.1 22.1 Reservoir 10 • .$ 10.5 10 .. 5 Main Dam 468.7 468.7 468.7 Emergency Spillway 25.2 25.2 25.2 Power Facilities 211 .. 7 211.7 211.7 Switchyard 7.1 7.1 7.1 Miscellaneous Structures 9 .. 5 9.5 9.5 Access Roads & Site facilities 28.4 28.4 28o4 Common Items -Subtotal 783.2 783.2 Te3:2
Diversion 32.1 32.1 32.1 Service Spillway 46.8 53.3 50.1 Saddle Dam 19.9 18.6 18.6 Non-Common/Items Subtotal 98.8 io4.o 1oo.a
Totel 882.0 887.2 884.0
Camp & Support Costs (16%) 141.1 141.9 141.4 Subtotal io2).1 io29.1 1025.4 Contingency (20~) 204.6 205o8 205.1 Subtotal 1227.7 1234.9 ~23o.5
En{ineering & Administration
12.5~) 153.5 154.3 153.8 Total 1381.2 1389.! 1384.3
OC4
22.1
10.5
468.7
25.2
211.7
7.1
9.5
28.4
7a3 .. 2
34o9
85.2
19.9
14o.o
923.2
147.7
1o7o:-9
214.2
1285 .. 1
160.6
1445.7
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FU
MONTH CASE A
OCT 234-
NOV 270
DEC 322
JAN 283
FEB 228
MAR 235
APR 199
MAY 180
JUN 170
JUL 182
AUG 170
SEP 158
TOTAL 2632
TABLE Bc31: ENERGY POTENTIAL Of WATANA -DEVIL CANYON DEVELOPMENTS
fOR DIFFERENT RESERVOIR OPERATING RULES
E N E R ~ Y P 0 T E N T I A L G W H
WAIAN_A 0 N L Y WAIAN~ & t.Vll. CANYJ.L~! .M FNFR([Y AVE RAGE t.l' .ERGY f"j KM l:.~t.t1 ~.:ar MU .AGE I:.NI:., .IUiY c u A l. u A c D .A c D
200 172 281 214 178 4:?7 399 3,4 511 422 346 -
235 201 348 331 271 502 463 388 543 625 506
276 236 445 397 364 598 547 458 817 751 683
242 208 383 357 325 590 480 403 715 677 618
202 173 318 335 293 452 395 330 599 632 561
201 173 . 276 330 277 470 398 335 532 629 536
165 142 203 214 197 460 332 280 451 419 387
152 131 180 247 174 462 304 286 465 536 399
135 111 175 212 191 492 323 278 478 485 460
209 345 258 267 374 387 471 755 521 579 784
311 531 344 327 545 321 659 1095 598 679 1095
151 155 249 158 166 293 326 390 463 346 395
2479 2578 3459 3389 . 3354 5394 5099 5332 6793 6781 6768
NOTE: Cases B and C were similar and only Case C was analyzed in detail.
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TABLE 8.32: AVERAGE ANNUAL AND MONTHLY FLOW AT GAGE
I IN THE SUSITNA BASIN*
I STATION (USGS Reference Number )
Susitna River Susitna River Susitna River Maclaren River
at Gold Creek Near Cantwell Near Denali Near Paxson
I (2920) (2915) (2910} (2912)
t~ONTH
Drainage Area 6160 4140 950 280
sq. mi. % Mean(cf's) IV ~iean~cfs} Ill Meen(cfs) % Hean(cfs) 10 10
I JANUARY . 1 1,453 1 824 1 244 1 96
FEBRUARY 1 1,235 1 722 1 206 1 t'll.
I. 0'+
MARCH 1 1p114 1 692 1 188 1 76
I APRIL 1 1,367 1 853 1 233 1 87
MAY 12 13,317 10 7,701 6 2,036 7 803
I JUNE 24 27,928 26 19,326 22 7,285 25 2,920
JULY 21 23,853 23 16,892 28 9,350 27 3,181
I AUGUST 19 21,478 20 14,658 24 8,050 22 2,573
SEPTEMBER 12 13,171 10 7,800 10 3,350 10 111149
I OCTOBER 5 5,639 4 3,033 3 1;122 3 409
NOVEMBER z 2,467 2 1,449 2 490 1 177
I DECEMBER 2 1,773 1 998 1 314 1 118
I ANNUAL -cfs 100 9,566 100 6,246 100 2,739 100 973
I Period of Record ~ Gold Cree~ -1950-79
Cantwell -1961-72
Denali -1957-79
Maclaren -1957-79
I * Ref. USGS Streamflow Data
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..w'----
TABLE B. 33: WATANA ESTIMATED NATURAL flOWS
YEAR OCT NU\1 IIEC JAN FEB MAR Af'f~ HAY JUN JUL AUG SEP
1950 4719.91. 2083.6 1168.9 815.1 641.7 569.1 680.1 8655.9 16432.1 19193.4 16913.6 7320.4 1S.31 3299.1 1107.3 906.2 aoa.o 673.0 619.8 130~.2 11649*8 18517.9 19786.6 16478.0 17205.5 1952 4592~9 2170.1 1501.0 1274.5 841.0 735.0 803.9 4216.5 25773~4 22110.9 17356.3 11571.0 1953 6285.7 2756.8 1281.2 818.9 611.7 670.7 1382.0 15037.2 21469.8 17355.3 16681~6 11513.5 1954 4218.9 1599.6 1183.8 1087.8 803.1 638o2 942.6 11696.8 19476.7 16983.6 20420.6 9165~5 1955 3859.2 2051 .. 1 1549.5 1388.3 1050.5 836.1 940.8 6718~1 24081.4"23787.9 23537.0 13447.8 1956 4102.3 1588.1 1038.6 816.9 754.8 694.4 718.3 12953.3 27171.8 25831.3 19153.4 13194t4 1957 4208.0 2276e-6 1707.0 1373.0 1189 .o . 935.0 945,1 10176.2 25275.0 19948.9 17317.7 14841.1 1958 6034 t 9 . 2935.9 2258.5 1480,6 1041.7 973.5 1265.4 9957.8 22097.8 i9752.7 18843.4 5978.7 1959 3668.0 1729.5 1115.1 1081.0 949.0 694.0 885.7 10140.6 18329.6 20493.1 2394~.4 12466.9 1960 5165.5 2213.5 1672.3 1400.4 1138.9 961.1 1069.9 13044.2 13233.4-19506.1 19323.1 160G5.lt 1961 6049.3 2327.8 1973.2 1779.9 1304~8 1331.0 1965.0 13637.9 22784.1 19839.8 19480.2 10146.2
1962 4637.6 2263.4 1760.4 1608.9 1257.4 1176.8 1457.4 11333.5 36017.1 23443.7 19887.1 12746.2
1963 5560.1 2508.9 1?08 .• 9 1308.9 1184.7 883.6 776.6.15299.2 20663.4 28767.4 21011.4 10800.0 1964 5187.1 1789"1 1194.7 852.0 781.6 575.2 609.2 3578.8 42841.9 20032.8 14048.2 7524.2 1965 4759.4 2368.2 1070.3 863.0 772.7 807.3 1232.4 10966.0 21213.0 23235.9 17394.1 16225.6 1966 5221.2 1565.3 1203.6 1060.4 984.7 984.7 1338.4 7094.1 25939.6 16153.5 17390.9 9214.1 1967 3269.8 1202.2 1121.6 1.102.2 1031.3 889.5 849.7 12555.5 24711.9 21987.3 26104.5 13672.9 1968 4019.0 1934.3 1704.2 .1617.6 1560.4 1560.4 1576,7 12826.7 25704t0 22082.8 14147.5 -7163.6
1969 3135.0 1354.9 753~9 619.2 607.5 686.0 1261.6 9313.7 1391~2 .1 14843.5 7771.9 4260.0 1970 2403.1 1020.9 709.3 636.2 602.1 624.1 986.4 9536.4 14399.0 18410.1 16263.8 7224.1 1971 3768.0 2496.4 1687.-4 1097.1 777.4 717.1 813.7 2857.2 27612.8 21126.4 27446.6 12188.9 1972 4979.1 2587.0 1957.4 1670.9 1491.4 1366~0 1305.4 15973.1 27429.~ 19820.3 17509.5 10955.7 1973 4301.2 1977.9 1246.5 1031.5 1000.2 873,9 914.1 7287.0 23859.3 16351.1 18016.7 8099.7 1974 3056.5 1354.7 931.6 786.4 689.9 627.3 871.9 12889.0 14780,6 15971.9 13523.7 9786.2 1975 3088.8 1474.4 1276.7 1215.8 1110t3 1041.4 1211.2 11672.2 26689.2 23430.4 15126.6 13075.3 1976 5679.1 1601.1 876.2 757.8 743.2 690t7 1059.8 8938.8 19994.0 17015.3 18393·5 5711.5 1977 2973.5 1926~7 1687.5 1348.7 1202.9 1110.8 1203.4 8569.4 31352.8 19707.3 16807.3 10613.1 1978 5793.9 2645.3 1979.-7 1577.9 1267.7 1256.7 1408.4 11231.5 17277.2 18305.2 13412.1 7132.6 1979 3773.9~ 1944.93 1312.6 1136.8 1055.4 1101.2 1317.9312369t3122904.8 24911.7 16670.7 9096.7 1980 6150.0 3525.0 2032.0 3 1470.03 1233.03 1177.0 3 1404 • 01 10149 • 01 23400. 0:.. 2674~ tO~ 18000 • Oa 11000 • 02. 1981 645B.oz 3297.02 1385.04 1147. oi 971. o+ 869.04 1103.0 1040o.O 17323.0 27840.0 31435.0 12026.0
AVE 4513o1 2052.4 1404.8 1157.3 978.9 898.3 1112.6 10397.6 22922.4 20778.0 18431.4 10670.4
Notes: (1) Discharges based on Cantwell a1d Gold Creek flows unless specified
(2) Wat ana observed flows
(J) Flows based on Gold Creek
(4) Watana long-term average flows assumed
-..
' --
A,\UE
6~ .. 5
76.Q':'~ 1 ,,~ ..
774G-t5
793S<t7
73~1! .. 4
a~ .... ~ s 0: .• -t· I
9(1\}.ti .s
B3'+~'f4
771~-~4
795'::7,. 7
79Q~ .. 2
85Sll-t6
97~'*1
9'">(.t.'' l .:. ~·'t
S2SS,.4
s-tQ~'Ito
7345~9
904.~.5
799!~t4
48UC-.S
606:S~tl
854~ .. 1
892+I!~~r-~
707t .. '9 6.,..,, 5 .J;:.,f~~ .....
8346'.7
678th-4
82()S~t6
694~.4
3133.-Q
0855~'9
9523:\3
7943,1
. ---. - - - - -.. --· .. --·'··---···· .. ·• ---·-_·L.
TABLE 8.34: DEVIL CANYON ESTIMATED NATURAL fLOWS
YEAR OCT NOV IIEC JAN FEB iiAR APR HAY JUN JUL AUG SEP AVE
1950 5758.2 2404.7 1342.5 951.3 735.7 670.0 802.2 10490.? 18468.6 21383.4 18820.6 7950•8 7481.iit
1951 3652.0 1231 .• 2 1030.8-905.7 767.5 697.1 1504.6 13218.5 19978.5 21575.9 18530.0 19799*1 8574~.~2
1952 5221.7 2539.0 1757.5 1483.7 943.2 828.2 878.5 4989.5 30014.2 24861.7 19647.2 13441.1 8883.,1]3
1953 7517.6 3232.6 1550.4 999.6 745.6 766.7 1531.8 17758.3 25230.7 19104.0 19207.0 13928.4 9304.,4}
1954 5109.3 1921.3 1387.1 1224.2 929.7 729.4 1130.6 15286.0 23188.1 19154.1 24071.6 11579.1 8809.)~
1955 4830.4 2506.8 1868.0 1649.1 1275.2 1023.6 1107.4 8390.1 28081.9 26212.8 24959.6 13989.2 9657.:!E
1956 4647~9 1788.6 1206.6 921.7 893.1 852.3 ~67.3 15979.0 31137.1 29212.0 22609.8 16495.8 1 055() IH!j)
tOC:"J 5235.3 2773.8 1986.6 1583.2 1388.9 1105.4 1109~0 12473.6 28415.4 22109.6 19389.2 18029.0 9633.::3 r~r
1958 7434.5 3590.4 2904.9 1792.0 1212.2 1085.7 1437.4 11849.2 24413.5 21763.1 21219.8 6988.8 8007 ·~tS 1959 4402.8 1999.8 1370.9 1316.9 1179.1 877.9 1119.9 13900.9 21537.7 23390.4 28594.4 15329.6 9585 .t~
1960 6060.7 ?6??.7 .... -. .. , 2011.5 1686.2 1340.2 1112.8 1217.8 14802.9 14709.8 21739.3 22066.1 18929.9 9()1)~ '•· ;:.,.;) .,~'#
1961 7170.9 2759.9 2436.6 2212.0 1593.6 1638.9 2405.4 16030.7 27069.3 22880.6 21164.4 12218.6 9965~"lt 1962 5459.4 2544.1 1978.7 1796.0 1413.4 1320.3 1613.4 12141.2 40679.7 24990.6 22241.8 14767.2 10912~~
1963 6307.7 2696.0 1896.0 1496.0 1387.4 958.4 810.9 17697.6 24094t1 32388t4 22720.5 11777.2 10352 .!$
1964 5998.3 2085.4 1387.1 978~0 900.2 _663.8 696.5 4046.9 47816.4 21926.0 15585.8 8840.0 9243t.h'
1965 . 5744.0 2645.1 1160.8 925.3 828.8 866.9 1314.4 12267.1 24110.3 26195.7 19709.3 18234.2 9506.f$
1966 6496.5 1907.8 1478.4 1278.7 1187.4 1187.4 1619.1 8734.0 30446.3 18536.2 20244.6 10844.3 8663~;4t
1967 3844.0 1457.9 1364.9 1357.9 1268.3 1089.1 1053i7 14435.5 27796.4 25081.2 30293.0 15728.2 10397 .. $
1968 4585.3 2203.5 1929.7 1851.2 1778.7 1.778.7 1791.0 14982.4 29462.1 24871.0 16090.5 8225.9 9129*'~
1969 3576.7 1531.8 836.3 686.6 681.8 769.6 1421.3 10429.9 14950.7 15651.2 8483.6 4795.5 5317 .. 91
1970 2866.5 1145.7 810.0 756.9 708.7 721.8 1046.6 10721.6 17118.9 21142.2 18652.8 8443.5 7011.,:!
1971 4745.2 3081.8 ~074.8 1318.8 943.6 866t8 986.2 3427.9 31031.0 22941.6 30315.9 13636.0 9614t:~l!
1972 5537.0 2912.3 2312.6 2036.1 1836.4 1659.8 1565.5 19776.8 31929.8 21716,5 18654.1 11884.2 10151~~
1973 4638.6 2154.8 1387.0 1139.8 1128.6 955.0 986+7 7896.4 26392.6 17571.8 19478.1 8726.0 7704 .. 1$
1974 3491.4 1462.9 997.4 842.7 745.9 689.5 949.1 15004.6 16766.7 17790.0 15257.0 11370.1 7113 .. 9
1975 3506.8 1619.4 1486.5 1408.8 1342.2 1271.9 1456.7 14036.5 30302.6 26188~0 17031~6 15154.7 9567 .. ll.
1976 7003.3 1853.0 1007.9 896.8 876.2 825.2 1261.2 11305.3 22813.6 18252.6 19297.7 6463.3 76C'4 ""' • .J ~.{!
1977 3552.4 2391.7 2147.5 1657.4 1469.7 1361.0 1509.8 11211.9 35606.7 21740.5 18371.2 11916.1 9411 ... 3
1978 6936.3 3210.8 2371.4 1.867 t 9 1525.0 1480.6 1597.1 11693.4 18416.8 20079.0 15326.5 8000.4 7715~~
197~ 4502.3 2324.3 1549.4 1304.1 1203.6 1164.7 1402.8 13334.0 24052,4 ~7462.8 19106.7 10172.4 8965~'.)
198 6900.0 39.55.0 2279.0 1649.0 1383.0 1321.0 1575.0 11377.0 26255.0 0002.0 20196.0 12342~0 9936,~ 1981~ 7246.0 3699.0 1554.0 1287.0 1089.0 •997t0 1238.0 11676.0 19436.0 31236.0 35270.0 13493.0 10605.,1
AVE 5311.8 2382.9 1652.0 1351.9 1146.9 1041~8 1281.5 12230.2 ~5991.3 23100.9 20709.0 12299.2 9041t~
* Discharges based on Watana flows
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TABLE 6.35! PEAK FLOWS OF RECORD .
Gold Creek Cantwell Denali Maclaren
Peak Peak Peak Peak
3 3 3 3
Date ft /s Date ft /s Date ft /s Date ft /s _ ..
8/25/59 62,300 6/23/61 30,500 8/18/63 17,000 9/13/60 8,900
6/15/62 80,600 6/15/62 47,000 6/07/64 16,000 6/14/62 6,650
6/07/64 90,700 6/07/64 50,500 9/09/65 15,800 7/18/65 7,350
6/06/66 63,600 8/11/70 2Q,500 8/14/67 28,200 8/14/67 7,600
8/15/67 80,200 8/10/71 60,000 7/27/68 19,000 8/10/71 9,300
8/10/71 87,400 6/22/72 45,000 8/08/71 38,200 6/17/72 7 '100
TABLE 8.36: ESTIMATED FLOOD PEAKS IN SUSITNA RIVER
Location Peak Inflow in Cfs for Recurrence Interval in Years
1:2 1:50 1:100 1:10,.000 PMF
Gold Creek 48,000 105,000 118,000 200,000 408,000
Watana Damsite 42,000 92,000 92,000 156,000 326,000
Devil Canyon Oamsite ) 12,600 43,000 61,000 165,000 346,000
(Routed Peak Inflow )
with Watana )
.. -· --------
TABLE 8.37: ESTIMATED EVAPORATION LOSSES -WATANA AND DEVIL CANYON RESERVOIRS
W.B I t\.N A
Pan tmservo1r Evaporation Evaporation Month (inches) (inches) -
January o.o o.o february o.o o.o March o.o o.·o April 0.0 o.o May 3.6 2.5 June 3.4 2.4 July 3.3 2.3 August 2.5 1.8 September 1.5 1.0 October o.o o.o Nove..rnber o.o o.o December o.o o.o --
Annual Evap .. 14.3 10.0
~ Based on data -April 1980-June 1981
Based on data -July 1980-June 1981
3 Based on data -January 1941-December 1980
Q !-_Y_ _! J ..
Pan
Evaporation
(inches)
o.o
0.0 o.o o.o
3.9
3.8
3.7
2.7
1. 7 o.o o.o o.o -
15.8
-~ANY UN Average ,Monthly A1r Temperat.ure ( -c} Heservo1r
Evaporation
Watana1 Devil Canyon2 Talkeetna3 (inches)
o.o -2.5 -4.5 .... 13.0 o.o -7.3 -5.0 -9.3 o.o - 1 .. 8 -4.3 -6.7 o.o -1.8 -2.5 0.7 2.7 8.7 6.1 7.0 2.7 10.0 9.2 12.6 2.6 13.7 11.9 14.4 1.9 12.5 N/A 12.7 1.2 N/A 4.8 7.8 o.o 0.2 -1.8 0.2 o.o -5.1 -7.2 -7.8 o.o -17.9 -21.1 -12.7 -
11.1
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TABLE 8.38: MONTHLY FLOW REQU!.REMENT AT GOLD C,!!EEK
Monthly Flow (cfs)
Case
Month A Band C D
Oct 1000 5500 5500
Nov 900 1200 1200
Dec 900 1200 1200
Jan 900 1200 1200
Feb 900 1200 1200
Mar 900 1200 1200
Apr 900 1200 1200
May 1000 6000 6000
Jun 2000 7000 7000
Jul 2000 9500 7000/1900(1)
Aug 2000 12000" 19000
Sep 1000 12000 12000
(1) Split Month: 7000 cfs to 15th then 19000 cfs to month end.
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TABLE 8.39: REQUIRED FLOW RELEASES AT WATANA
TABLE 8.40: REQUIRED FLOW RELEASES AT DEVIL CANYON
To be included
after selection
of operation
schedule and
scheme
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TABLE 8.41: WATER APPROPRIATIONS WITHIN ONE MILE OF THE SUSITNA RIVER
ADDITIONAL SOURCE
LOCATION* NUMBER TYPE (DEPTH) AMOUNT
CERTIFICATE
T19N RSW 45156 Single-family dwelling well (?) 650 gpd
general crops same source 0.5 ac-ft/yt
T25N R5W 43981 Single-family dwelling well (90 ft) 500 gpd
T26N R5W 7889.5 Single-family dwelling well (20 ft) 500 gpd
200540 Grdde school well (27 ft) 910 gpd
209233 Fire station well (34 ft) 500 gpd
T27N RSW 200180 Single-family dwelling unnamed stream 200 gpd
Lawn & garden irrigation same source 100 gpd
200515 Single-family dwelling unnamed lake 500 gpd
206633 Single-family dwelling unnamed lake 75 gpd
206930 Single-family dwelling unnamed lake .250 gpd
206931 Single-family dwelling unnamed lake 250 gpd .
PERMIT
206929 General crops unnamed creek 1 ac-ft/yr
T30N R3W 206735 Single-family dwelling unnamed stream 250 gpd
PENDING I
209866 Single-family dwelling Sherman Creek 75 gpd
Lawn & garden irrigation same source 50 gpd
*All locations are within the Seward Meridian.
DAYS OF USE
365
91
365
.365
334·
365
365
153
365
165
365
365
153
365
365
183
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TABLE 8 .. 42: lURBINE OPERATING CONDITIONS
Watana Devil Can~on
Ma;(imun net head 728 fest 597 feet
Minimum net head 576 feet 238 feet
Design head 680 feet 575 feet
Rated head 680 feet 575 feet
Turbine flow at rated head, cfs 3550 cfs 3800 cfs
Turbine efficiency at design head 91% 91%
Turbine-generating rating at rated head 181,500 kW 164,000 kW
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TABLE 8.43: HISTORI.CAL ANNUAL GROWTH.RATES OF ELECTRIC UTILITY SALES
Period.
1940 -1950
1950 -1960
1960 -1970
1970 -1978
1970 -1973
1973 -1978
1940 -1978
u.s.
8.8%
8.7%
7 • .3%
4.6%
6.7%
3.5%
7.3%
Anchorage and Fairbank~
Areas
20.5~
15.3~
12.9%
11.1~
13.1%
10.9~
15.2%
--- -.. ------ - - - - - - -!--
.
TABLE 8.44: ANNUAL GROWTH RATES IN UTILITY CUSTOMERS AND CONSUMPTION PER CUSTOMER
Residential
1965
1978
Annual Grow~h
Rate (,_)
Commercial
1965
1978
Annual Growth
Rate (~)
Greater Anchor!9e
Customers Consumption per
(Thousands} Customer (MWh)
27 6.4
77 10.9
8.4 4.2
4.0
10.2
7.5
Greater fairbanks
Customers Consumption per
(Thousands) Customer (MWh)
8.2 4.8
17 .. 5 10.2
6.0 6.0
1.3 -:
2.9
6.4
u.s.
Customers Consumption per
(Millions) Customer (MWh}
57.6 4.9
77.8 8.8
2.3 4~6
7.4
9.1
1.6
0
----------~-------..
TABLE 8.45: UTILITY SALES BY RAILBELT REGIONS
nreater Anchorage Greater Fairbanks Giennaiien-9aidez Railbelt Total
1 1 1 1 Sales No. of Sales No. of Sales No. of Sales No. of
"Regional Customers Regional Customers Regional Customers Customers
Year GWh Share (Thousands) GWh Share (Thousands) GWh Share (Thousands) GWh (Thousands) -
1965 369 78~ 31.0 98 21% 9.5 6 1% .6 473 41.1
1966 415 32.2 108 9.6 NA NA 523 41.8
1967 461 34.4 66 NA NA NA 521 34.4
1968 519 39.2 141 10.8 NA NA 661 30.0
1969 587 42.8 170 11.6 NA NA 758 54.4
1970 684 75% 46.9 213 24~ 12.6 9 1% .. 8 907 60 .. 3
1971 191 49.5 251 13.1 10 .9 1059 63.5
1972 906 54.1 262 13.5 6 .4 1174 68.0
1973 1010 56.1 290 13.9 11 1.0 1311 71.0
1974 1086 61.8 322 15.5 14 1.3 1422 78.6
1975 1270 75% 66.1 413 24% 16.2 24 1% 1.9 1707 84.2
1976 1463 71.2 423 17.9 33 2.2 1920 91.3
1977 1603 81.1 447 20.0 42 2.1 2092 103.2
1978 1747 79~ 87.2 432 19% 20.4 38 2% 2.0 2217 109.6
Annual
Growth 12.7% 8.2% 12.1% 6.Ho 13.9~ 9.7% 12.6% 7.8%
NOTES:
(1) Includes residential and commercial users only, but not miscellaneous users.
Source: federal Energy Regulatory Commission, Power System Statement.
NA: Not Available.
- - - - --- - - - - - - - - -----
TABLE 8.46: SUMMARY Of ISER RAILBELT ELECTRICITY PROJECTIONS
Utilit~ Sales to All Consuming Sectors
MES::CR
LES-GL1
Year Bound
1980 2390
1985 2798
1990 3041
1995 3640
2000 4468
2005 4912
2010 5442
Average Annual
Growth Rate (%)
1980-1990
1990-2000
2000-2010
1980-2010
NOTES:
2.44
3.92
1.99
2.78
_LES-GM
2390
2921
3236
3976
5101
5617
6179
.3.08
4.66
1. 94
3.22
t£5-GH
(Base Case)
2390
J171
3599
4601
5730
6742
7952
4.18
4.76
3.33
4.09
Lower Bound = Etitimstes for L£5-GL
Upper Bound = Estimates for HE5-GH
LES = Law Economic Growth
MES = Medium Economic Growth
l£5 = High Economic Growth
GL = Low Government Expenditure
GM = Moderate Government Expenditure
GH : High Government Expenditure
with Price
Induced Shift
2390
3171
3599
4617
6525
82.19
10142
4.18
6.1J
4. 51
4.94
(1) Results generated by Acres, all others by !SER.
HE5-GM
2390
3561
4282
5789
•719~
9177
11736
6.00
5.32
5.02
5.45
(GWh)
HES-GH1
Bound
2390
3707
4443
6317
8010
10596
14009
6.40
6.07
5.75
6.07
Military tilt
Generation (GWh)
M£5-GM
(Base Case)
334
334
334
334
334
334
33i•
0.0
0.0 o.o o.o
LES-GM
414
414
414
414
414
414
414
o.o o.o o.o o.o
selF-Supplied
Industry Net Generation (GWh)
MES-GM
(Base Case)
414
571
571
571
571
571
571
3.27 o.o o.o
1.08
RES =tiM
with Price
Induced Shift
414
571
571
571
571
571
571
J. 27
0.0
0.0
1.08
HES ... ~
414t
847]
9811
98.1J
981;
981J
9811
-~------------------
.
TABLE 8.47: fORECAST TOTAL GENERATION AND PEAK LOADS -TOTAL RAllBELT REGION1
ISER [ow ([ES-GRJ2 ISER Reoium {MES-G~} ISER R1gn {RES-CR}
Year
1976
1960
1985
1990
19~5
2000
2005
2010
Percent
Growth/Yr.
1978-2010
~
NOTES:
Peak
Generation Load
{GWh) (MW}
3323 606
3522 643
4141 757
4503 824
5331 977
6599 1210
7188 1319
7822 1435
2.71 2.73
Peak
Generation load Generation
(GWh) {MW) (GWh)
3323 606 3323
3522 643 4135
4429 BOB 5526
4922 898 6336
6050 1105 8013
7327 1341 9598
8471 1551 11843
9838 18tl0 14730
3.45 3.46 4.76
(1) Includes net generation from military and self-suppli-ed industr~ .. ourcea.
(2) All forecasts assume moderate government expenditure.
Peak
Load
(MW)
606
753
995
1146
1456
1750
2158
2683
4.76
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Year
1980
1985
1990
1995
2000
2005
2010
TABLE 8.48: ISER 1980 RAILBELT REGION LOAD AND ENERGY FORECASTS USED FOR
GENERATION PLANNING STUDIES FOR DEVELOPMENT SELECTION5
L 0 AD CASE
Low Plus Load·
Management end Low t-1edium High
Conservation
(LES-GL)2 (MES-GM)J (HES-GH)lJ. (LES-GL Adjusted)1
Load toad Load
MW GWh Factor MW GWh Factor t-1W GWh Factor MW GWh
510 2790 62.5 510 2790 62.4 510 2790 62.4 510 2790
560 3090 62 .. 8 580 3160 62.4 650 3570 62.6 695 3860
620 3430 63.2 640 3505 62.4 735 4030 62.6 920 5090
685 3810 63.5 795 4350
J)
62.3 945 5170 62.5 1295 7120
755 4240 63.8 950 5210 62.3 1175 6430 62.4 1670 9170
835 4690 64.1 1045 5700 62.2 1380 7530 62.3 2285 12540
920 5200 64.4 1140 6220 62.2 1635 8940 62.4 2900 15930
Load
Factor
62.4
63.4
63.1
62.8
62.6
62.6
62.7
Notes:
(1) LES-GL: Low economic growth/low government.expendil:ute with load management and coneeevs.tion ..
(2) LES-GL: Low economic growth/low government exp~1diture. ·
(3) MES-GM: Medium economic growth/moderate government expenditure.
(4) HES-GH: High economic growth/high government expenditure.
te) Excludes reserve requirements. Energy figures are fl)r net generation. \J
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TABLE B.49: DECEMBER 1981 BATTELLE PNL RAILBELT REG!ON LOAD AND ENERGY
FORECASTS USED FOR GENERATION PLANNING STUDIES
[ ll 1\: [j C A_S ReClium -L-o=w~ A1gh Load ' load load Year MW GWh Factor MW GWh r'actor-MW GWh F'actor
1981 574 2893 57.5 568 2853 57.3 598 3053 58.3
1985 687 3431 57.8 642 3234 57.5 794 4231 60.8
1990 892 4456 57.0 802 3!J99 56.9 1098 5703 59.3
1995 983 4922 57.1 849 4240 57.0 1248 6464 59.1
2000 1084 5469 57.4 921 4641 57.4 1439 7457 59.0
2005 1270 6428 57.8 1066 5358 57.4 1769 9148 59.0
2010 1537 7791 57.9 1245 6303 57.8 2165 11,435 60.3
Average
Annual
Growth
Rate(%)
1981-1990 5.0 4.9 3.9 3.8 7.0 ..., " I e.&.
1990-2000 2.0 2.1 1.4 1.5 Z.7 2.7
2001-2010 3.6 3.6 3 .. 1 3.1 4.2 4 .. 4
1981-2010 3.5 3.5 2.7 2.8 4.5 4.6
Note: Exclu-des reserve requirements. Energy figures are for net generation.
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LOCATION MAP
LEGENQ
7· PROPOSED
DAM SITES
LOCATION MAP
20 0 20
~ ~ IE I ,-·~ . .-
' . -
SCALE IN NI.ES
- - - - - - - - - - ---- - - --· -
15 ---J
LEGEND
TYONE. ~ DAMSJTE
DAMSITES PROPOSED BY OTHERS
_, J_..._, ....... ...__..v
SI.JSITNE
lAKE
--./ ,-----/
I
-------------------
PREVIOUS
STUDIES AND
fiELD
RECONNAISSANCE
12DAM
SITES
GOLD CREEK
DEVJ L .cANYON
HIGH DEV!L CANlON
DEViL CREEl<
WATANA
SUSITNA m
VEE
MACLAREN
DENALI
BUTTE CREEK
TYONE
ENGINEERING
COMPUTE~ MODELS
TO DETERMINE
L~ST COST DAM
COMBINATiONS
LAYOUT AND a--------~
SCREEN
COST STUDIES
7DAM
SITES
3BASIC
· DEVELOP·
MENT
PLANS
CRITERIA DEVIL CANYON OBJECTIVE WATANA I DEVIL
ECONOMICS HIGH DEVIL ECONOMIC CANYON
ENVInONMENTAL ~~~X~~ ....__ ______ HIGH DEVIL
~}f~~NATIVE SUSITNA m ~~~~~~~~EE
ENERGY VEE CANYON l WATANA
CONTRIBUTION MACLAREN
'---------' DENALI ADDITIONAL SITES
PORTAGE CREEK
DATA ON DIFFERENT
THERMAL GENERATING '
SOURCEr-S ____ ......_ __
COMPUTER MODELS
TO EVALUATE
-· -POWER AND
t:"l\IC'Ct!V '\8~ n~ . .......... ,...,. t~
-SYSTEMWlOE.
CRITERIA
ECONOMIC
ENVIRONMENTAL
SOCIAL
ENERGY
CONTRIBUTION
ECONOMICS
WATANA/DEVIL
CANYON
PLUS Tt£RMAL
LEGEND
IllS. HIGH DEVIL CANYON DIS WATANA .
---{\STEP NUMBER IN
STANDARD PROCESS I
(APPENDIX A)
SUSITNA BASIN PLAN FORMULATION ·AND SELECTION PROCESS
----------------·-----
OSHETNA RIVER
P~TAGE CR.
100 120 140 180 180
RIVER MILES --.,
PROFILE THROUGH ALTERNATIVE SITES
..__ _____ ,.._ _______ ..;,_.. _________ .......... _......._.~ ..... w~,.....__--· _.;,FI ...... GU-RE...-a.;;..;..4-=li==l=l::.~l
::.·· .' . . .·: . ·_ .. : " .. ··.: ....... :: ' .. : . .':. · ... ·~· .. -... · ... : ... :
• • ' ' • ~· • '•"'~-' • • '• • ~ " • • ' I> • •
-------------------
GO to
CREEK OLSON DEVIL
CANYON
HIGH
DEVIL
CANYON
DEVIL
C.REEt< WATANA SUSITNA
GOLD CREEK
OLSON
DEVIL CANYON
HIGH DEVIL CANYPN
DEViL CREEK
LEGEND
COMPATIBLE ALTERNATIVES
D
MUTUALLY EXCLUSIVE ALTERNATIVES
WATANA
SUSITNA ln
·VEE
DAM IN COLUMN IS MUTUALL-Y EXCLUSIVE IF FULL
t~~~\f:1~~lJ~~~~ij SUPPLY t..EVEL Of OAM IN ROW EXCEEDS THIS VALUE· FT.
~~i~~~l~~tllf.l~\~t~l VALUE IN BRACKET REFERS TO APPROXiMATE DAM HEIGHT.
..
MACLAREN
YEE MA~LAREN DENALI
JENALi
BUTTE CREEK
TYONE
· MUTUALLY EXCLUSIVE DEVELOPMENT ALTERNATIVES
BUTTE
CREEK TYOt~E
FIGURE B.fi [i]
. .·: : •.• : . • . . • . '' . • . . . : .... : .·.~ . . ~ ' • ~ :· •. : :. :, ~·' ·• : ~ ~-· : •. . ; ~ . • . . ' ·.•. :':~ .. : •. ·. . . J • •· .. -'·; . . : :.: •
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LONGI'iUOINA.L SE.CTION IJ..JRU fi OF DAM
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POWER FAClLlTl'ES PROFILE.
'$PIU.W.o\Y CONTROL S!'RUcrtJR£,
lh4dll401 MlE.E.L MOlJN"Te.O GA.iES
SPILLWAY PROFILE
SCALE~ .e;
FIGURE B.6
ALASKA POWER AUTHORITY
OEVtL CANYON
MYO~O DEVELOPMENT
· rU.t. .DAM
I
f~l
J~l
GENE.RA.L A.RRANGE.MENT
SCA.l...E.~ A
rCRES.T El.., 'i22!i.t
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2!>00~
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1900
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1600
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-=..,;:;.=-=r;-=-=-\:;
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GA.L.I.E:R1E.S . . .
flGURE 8.7
WA.TANA
HYDRO DEVELOPMENT
FILL DAM
ll
f -1 .. ·.· i '
II
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2..'"too
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2100
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~~
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NORMAL. MAX.
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[
C.'2E.!>T EL. '1.2'251
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- -.... ----......, 0~ A A
ORIGINA.l.. GQOUND SUQii:A.-;; 2100
2000 ~----~~~~r.t
SECTION Tl-IRU DAM
'SCAl-E: e>
•
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l;j,goo •t:
7 1&0° ~---~-~--~-~---~~=-~~---------~----~i~~~N~5~FO~RM~!R~-~AN~D~-~~r. r---
2100
2000
1900
Ul
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""' ~1500 w
cl•400
,~oo
LONGlTUOINAL SE.CTlON Tl-I~L! ¢.;,OF ~
SCAt..E.:B
t-IOI<MAL MA)t.OPERA.iiNG
LE.VEL.-EL. '2.2001
'2.· ~5' OIA..CONa<E:lE. LnlE.O
TUNNELs
I~
CWA.IWA.GE. 11-J FEET
SPlLLWA.Y PROFILE.
~ r:roo
h ~tc;..OO
w
jtsoo
t-'00
TU& GATE ~.'r'
PO'V'JE.R F'ACILITIES PROFILE.
SGA.l..E: e.
SCAL..E
A 0 500 1000 FE.ET
eo ... --~. ~ .. ~
FIGURE 8.8
I~ ,, ALASKA POWER AUTHORITY : Mlfu IIUIITNA HYOROELECTIHC PIIO.IECT
WATANA
STAGED FILL DAM~
.... OEC.,I981.
I
fl
II
r _I
I~l
.I
··--.......___ ··--.... ·-
GENERAL ARRANGEME.NT
SCAUL; 'A.
LONGITUDINAL SECTION Tl-4R..U <t OF DAM
SCAl-E.: e.
ti
~
z
z
2
~ :>
11.!
...1
ul
'Soo
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~~
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z )400
z I~
Q
~ 1200
).
~ 1100
II)
1000.
"100
500
~~
1500
i IL
1400
z ·~ z
0 1'200
~ 1100 ~
J
Ul ICXlO
"100
w~Ms.t.. MAl(. w.t..s.t...nso' l
--=5iiiii!i&~-
0
GICOUT GURl'AlN
SECTION T~RU DAM o
SCALE: et
STEEL W'-IEA
1 I
1000 lSOO
CI4A,\NA,c:;E IN FEE1'
POWE.R. FACILITIES PROFILE.
/EXISllNG GROUNP SURFJ..CE.
A.LONG ~OF SPIU.WAY
0
·SCAU:.A o 400 -----FIGUR.E 8.9
,._,~ lt---ALA_._sKA_· -:-PO_. __ W_E_R_A_U_TH_O_R_ITY_. -t
,. !j IOitTNA NYDIIIOIEI.lCTIIIC PIIO.U.CT
HISH DEVIL CANYON
HYDRO DEVELOPMENT
I
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tJ.o:::Lll!:!l-__,.
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SI..OPE.
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LONGITUDINAL SJ::.CT!ON THRU <:fj OF·DAM
SCALE.: e.
________ ......... _________ ...,.._.~ ....... __________________________ ..._ ___ --.....
1-IO~MAL. MAl(., vJ,I...
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~~~----~------------~------~~~~~=-~--~~~~~~------------
'Z.lOO
2000
1900
1800
noo
SE.GTION -n-tRU DAM
E:L. 'Z.?>40 I
SeA.!.£: e.
.2~52 E:
/Eltl.!:>TING GQQUI>.ID SUI'<F~c:.E. --_,..__ ___
-----~~ ' ~ .,., ..... , .............
··~--?=----
"%. •' ~I -. .
... ~t. DIO!A;:T ~ . ._,_,," / I !f =>: -
INTA¥.5./ '2:-16101A ·CONcRE:rE., ~ I I 11 /'TUBE GA~ 7AU.-ER:Y AVG. I~ILWATER
L.I~EC PE'NSTOCK5 I !r /.. 5.1..· 1610'
~ FOWERHOUS.£~ T
1 <--o -1!l I I ---............ ~
CONSTRlJc;;TION AOI'T ............. ~ if .i~' I' i l \' , • 1 ... ......
I I
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1 DIA CON
POWE.Q FAClLlTE.S PROFILfl.
NORMA!., N\AX.W.L.
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C~b..\WA.GE. IN FEET
SPILLWAY PROFILE.
SCAU:.: 6
40::> 800 FEET
t> :· ... <'100 I"E!.T
'f·>~; d
FIGURE B.IO
r~PI~. I~~A~~~s_KA_·~p=o_w~ER=·=AU~T_H=O_R~IT~Y~·
1\!!I!J 5USl1''-'!> H'i'DIIOEL£CTiiiC PIIOJ£-C'T
SUSITNA m
HYDRO DEVELOPMENT
.... , OEC, 1981
il·• . '
r_,_··~-t ' . '
l '
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;
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II
II
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z
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G ENE.RA.L ARRANGEMENt
SCALE.~ A.
rcKE.ST El. '2!50 1
LONGlTUDlNA.L SECTION TJ-IRU q_ OF MAIN DAM
SCALE.:B
t
Ill
1<.
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Ill
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~ '2.100
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~ >' 1900
Ill
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1700
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0 !00-
C>I.I>.I~AGE. IN 'FSE.T
NORMA\. MAX.
W.L. E.J.., a!!l~ 1
~OUT CURTAIN
SECTION 1HRU MAIN DAM
Sc;A.t...E. ; f)
I !XX) 1!()0
POWE.R FACILITIES PROFILE.
'!:>C ..... l-E.: e,
'SCALE A. 0 e
SC::A.L.E. 5 0
' • • • ••• ..r
l-_____ _.._ _____ _...;_ ______ ~-.....::::: ~ -·-·
FIGURE B.ll
ju,~ ~1-----:-A~LA:-::-:S~I<A"'"-:· =P=-=OW~ER::-::-A::-::U-:-:T-::H:-:-0;:-:;RIT:;:Y:::-l
AIIJ IIUSITN'A ~VCIIOELECTRIC •AbJECt
SPILLWAY PROFILE.
SCALE t e. VEE
HYDRO DEVELOPMENT
··~o ·.
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SCALE.: A
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DAM CROSS SE.CTION
Sc:AIL:' C
NORMAL MA,1(.
~ w. 1.. Et.. 'Z.!>95'
j
SECTIOI'-l A-A
'2'200~----------~~--~---------------------~~--------------------------------~--------------------------~
SECTION B·B
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DENALI
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SCA\..E:A
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4· 1<0' >t !1'21 W~E.E.L.
MOUNTED GA.iES
SECTION 0-D
SCALE.:c
SCAL.E A 0 800 FEE.T FlGURE B.l2. . . ~ ~ ~ -· .. ,..
AOO FEE'! 1 £lrf llt----A __ LA ___ S __ KA_· _PO_W_.· _ER_A_U_T __ H_O_RI_TY_. -i
II iiHfilTfU. HYDRO£LECTIIIC PltOJ£C·T
DENALI a MACLAREN
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2200 FT. WATANA 800 MW
_....,._2 MILES
~-14'75 FT.
~Ft
38 FT. DIAMETER
.800 MW-70 MW
38 FT. DIAMETER
DEVIL CANYON
550 MW
...._ ____ RE-REGULATION DAM
30 MW
30 fT. DIAMETER
800 MW
2 NELS 365 MW
24 FT. DIAMETER
SCHEMATIC REPRESENTATION
OF· CONCEPTUAL TUNNEL SCHEMES
TUNNEL
SCHEME
#
l.
~3 .
4.
FlGURE 8.1'5 [il
I
I
~1900
----
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S USITNA
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RE· RE.GULATION OA.tv\
NOR ..Vi.
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CONCEPTUAL. STlJD'i ?UICPOSES ONI..'t.
GEN~'RAL ARRANCi£ME.NT
..Q?v!L CANYON. FOW£1<.1-40USE
SCALE
FIGURE. 9.14
l.nl£t .\J--A ___ LA ___ SKA ___ PO __ W_E-:-R""":"A:-:-U:-TH7.:0::-:-R':":'ITY:::::·. · :--1
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PREFERRED TUNNEL
SCHEME 3
PLAN VtEWS
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------
f l
A A
UNLINED CONC. LINED W/t'TE:El SE.T
SPILLWAY PROFILE
.·, ·.:.;_.
•• v .• ...
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SECTION A·A
TYPICAL TUNNEL SECTIONS (!¥$To scAI...e.)
KiOO -----
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uoo r
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&.
z 1300
·:z;
0
!:( l'lOO >
"" _, ...
1100
1000
ROCK BOLTS ROCK BOLTS 4 SHOTCRETE
TYPICAL TUNNEL SECTIONS
(NOT TO SCAI..E)
---------------. --------------
OISTANC!: IN Mil...~!\.
TUN~E.L ALIGNMaNT
----------------------~
'~-
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TUNNE.I..
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\•,
\\
rTA.tl.ff,At;.E Sll;:)!"\.Qos;S
~~loi.U..
'1;~'"\;.
El "'»'
DEVIL CANYON POWER FACILITIES PROFILE'
DE.TAIL A.
/
GI<OUT AS RE.qUIIa£0
(NP.)
' r
OETAIL•e)
SCAI...e..: A
NOTt.:
ALt. :!>TRUCTUR.At.. AAO SUF~T
DETAILS ARE COI\It:SPTUA.L Af.IO
FOQ. STUOY PURPOSES ONL'(,
$CAI...e A 0 • 100 2.00 F£E.T
P" --I
FIGURE 8.15
~!1EFERRED TUNNEL.
SCHEME 3
SECTIONS
I ...
I
I
I
I
I
I
.~
I
I
I
I
I
I
I
I
I
I
I
I
3
3':
:E 2"
0
0
0 -
I ,....
1--· (.)
~· < (.)
10
8
:::t:
~6
0
0
0
2
715
1980 1990
LEGEND:-
D HYDROELECTRIC
Ht11. COAL FIRED THERMAL
I!:ZJ GAS FIRED THERMAL
2000
-OIL FIRED THERMAL l NOT SHOWN ON ENERGY DIAGRAM
NOTE : RESULTS OBTAINED FROM
OGPS RUN LSJ9
TOTAL DISPATCHED
ENERGY •.
DEVIL CANYON
(400 MW}
WATANA-f { 400 MW)
~XIST.lNG S COMMITTED
0~--~----------------------------------~----~----------------1980' 1990 aooo 20i0 .
TIME
GENERATION SCENARIO WITH SUSITNA .PLAN El.3 •.
.. ________ ... --.------·MEDIUM LOAD FORECAST-. ..,u ... = e.l& Ill
.~
I.
I
I
I
I
I
I
I
I
I
I
1:
I
I
I
-I
I
I'
0
0
0
I
> 1--(.)
<tt 0..
<t
0
10
4
715
1980 199fl
LEGEND:
D HYDROELECTRIC
~D COAL FIRED THERMAL
[21 GAS FIRED THERMAL
2230
2000 2010
OIL FIRED THERMAL{ NOT SHOWN ON ENERGY Of.AGRAM
NOTE.: RESULTS OBTAINED FROM
OGFS RUN L60 I
TOTAL DISPATCHED
ENERGY
VEE(400MW)
HIGH DEVIL CA.vrott·2: {400MW)
HIGH DEVIL CANYON ·t ( 400 MW)
EXISTING AND COMMITTED
0~--~--------------~-----------------------------~=-----------_. 1980 1990 2000
TrME
GENERATION: SCENARIO WITH SUS1TNA PLAN E 2.3
-MEDIUM LOAD FORECAST-
2010
I
I.
I
I
I
••
I
I
' I
I
I
I
I
I
I
I
I
I
·;::
22
0
0
0
5
>-t--(.)
fr
<C
(..)
10
8
:r
3:6 (!)
0
0
Q
I
>-
(!)
ffi4
z
IJJ
715
PEAK
LEGEND:
o· HYDRGEu:eTRIC
-COAL FIRED THERMAL
e:z~· GAS FIRED THERMAL..
--
OIL. FIRED THERMAL ( NOT SHOWN ON ENERGY uU'\~n...,
NOT£.: RESULTS' OBTAINED FROM
OGPS RYN L607
TUNNEL (380 MW)
TOTAL DISPATCHED
ENERGY
WATANA -I ( 400 M W)
EXISTING a COMMITTED ·
0~-------------------------------------------------------~----~ 1980 · f99Qr 2000 2030
TIME
GENERATION SCENARIO WITH SUSITNA PLAN. E3.1
-ME01UM· LOAD FORECAST-.
.~
•.. '
I
I.
1:
_.: -CQO -X
·~-'* -U)
t-
(I)
0
I (.)
z
0
i=
(.)
:;:)
I 0
0 a:
~
1.1..
0
I· :t: ... a:
0
~
I r-z
IJJ
--(I)
w a:
I a.
I
I
-I,
I
I
I
I
7300
72.00
7100
~-
7000
6900
6800
6700
6600
6500
2.140
.
~ .. -
~ V""
.
.
"
t
~
i
l
I
L
I> I
2180 2200 222.0 22.40
DAM CREST ELEVATlON ( FEET J
WATANA RESERVOIR
DAM CREST ELEVATION I PRESENT WORTH OF PRODUCTION COSTS
.
2260
[ii1
-·-----
~2.400
_ .. ..--------
-
• ClOSURE EYBAHKYEHT
EL 22.30
SWITCIIYARO AI!U
--
, ,,, 'l'l'l1l'Ff17 .~<:::• !!ill
-· -
-!':.... I ' . ..::.. PRELIIIlNARY CONCEPTUAL I'!IOJECT LA~OUT •\\"!" J] rt ·--~-· ~ .~'-THIS OIIAWING ILI.USTI!t.TES A
,l;/ I '\;'~.~'\ ' I'REPAREO FOR COIIPAR!SOH OF AllERNI.Tl\IE
.~Ji"' ~ ~· Sll£ tlE\IELOPIIEHTS ONLY
p ..
--...
..... ~-
o 2oo o~oom;r
SCALC ""~ ... --.,1----....i·
""
FI.GURE 8.20
WATANA
ARCH DAM ALTgRNATtYE
~~l.._._,-~··\.. MARCH 19BZ
· ;;;c, •vr~.u~·.,.~.;,.POII.im
----.. -
§ ..
;!
w
Hl,Ul.OOO
' 2~ r·--"'· ~·.~.----~
I
~
--' .. ----
FIGURE 8.21
AL.ASKA POWER AUTHORITY
''SOSiiiiAiivllfiOE(£Cr'rJC"~-
WATANA
ALTERt-IATIVE DAM AXES
MARCH t9S2
I
1.
I·
I
I
I
I
I·
..• l
I
I
li
••
If
I
I
I
I:.
'I L
1600----------~--------~--------~----------------~
\
\
\
\
\ ~ ' I
LESS THAN 3J•
ENTRANCE
SUBMERGED
-1550~------~~--------~-4~-4~~------~--------~ ..,: ..._ -z
0 -!i >
tli
...J
UJ
0
TYPICAL
TUNNEL
SECTION
. u
j
F
1450~------~~--------L-------~~------~~------~
25 30 35 40 4S
TUNNEL DIAMETER {FT.)
NOT£ -FOR 80,000 CFS ·
WATANA DIVERSION
HEADWATER ELEVATION I TUNNEL DIAMETER
FIGURE B~22
I
I
, •
••
I
I
I
I
I
I
I
I
.0
I
I
I
I
I
I
--
z
0 -.....
<t >
l.&J
...I
l.&J
1650r-------~~------,---~~--~------~
AT 1720
COST
50XI06
1600 t--------r+------+---------1--------1
1550 t----f----f------+-----4--------l
1500 .__ ___ __._ ____ ...._ _____ "'-____ ___,
lOX 10 6 20X 10 6 30~10 6 40Xl06
CAPITAL COST $
WATANA DIVERSION
UPSTREAM COFFERDAM COSTS
FIGURE B.23 •
I
I 80
0
I '"' ¢
70 ,~.v
r •• ~ ¢ . -~~;;_ "' I .
so ~ •• ~ ~ '
I ~ -50 \1) ~~~ 0 ~ -X ...,o
I -~ -~<,.,~ • I
.... : "' 40 v •• 0
(,) ,
iii
..J ~ c(
I· t--Q.
<
0 30
I I .
I. 20 1
I
I 10
0
I TYPICAL
TUNNEL
SECTION c
I 15 20 25 30 35 40 45
·---TUNNEL DIAMETER (FT.)
I WATANA. DIVERSION
'I TUNNEL COST I TUNNEL DIAMETER
• I
I
I'
I
••
••
I
I
I
I
I
I·
I
I
I
I
I·
I
'I
I
f'"-
CD
0 -
>c --
Cl') ....
Cl')
0
0
..J
~ .... a:
<t u
..J
<t
t-
0 ....
100~--------.---------,---------.---------~--------~
ao
70
60
0.
TYPIC At.
TUNIVEL
SECTION
50
15 20 25 30 35
TUNNEL DIAMETER (FT.)
WATANA DIVERSION
TOT/~L COST I TUNNEL DIAMETER
40
FIGURE 8.25
--------
ALTERNATIVE 3
-
I'"
(
-· -
ALTERNATIVE 2
ALTERNATIVE 2C
""'-lloAY c.;lf<ffiOI ~
SlRIJCTUid:tl
·""----~-" l·
AL"fERNAnVE 4
WATANA
PREUMINARY SCHEMES
------.. ··· ,. -
All"ERNATI'IE ;r A
FJGURE 8.26
ALASKA POWER AUTHORITY
• · sos&rNi tivilflort.t:Ct~c l'ft0j£Ci • ·" •
WATANA
PRELIMINARY SCHEMES
-----------
------ZlOO
-zzao
---
THIS lliiAWING ILLUSTRATES A
PRELiii!IWIY COiiCEI'TU.lL f'ROJECT LAYOUT
-ED fOR COioiPARISON OF
ALTEIIHATIVE SITE DE.VflOPMEHTS ONI.Y
---
FIGURE 8.27
ALASKA POWER AUTHOfilTY
.. -· SUSiiNA ihooritt.r.t:rt<te tiRo :fECi-· ••.
WATANA
SCHEME WPI
PLAN
tJAACti 1982
--·-
UDO
__ ... --~
2UD
14~0
t400
---
r CONTROL SlRUCfUIIE
I l-!IS'Wa4o"ll FIXED
WIIEE\. $ATES
.:...-;.'---
.. ._PRESSURE RELIEF
ll/U.INS
----ORIGINAl.. GROU~:.,.__.-------
SEC.'r!ON A-A
SCALE l
-
ti ... ...
%
2000
i l!ii~O
2
i ...
;:1900
---
SPILLWAY PROFILE
!CA:L.E A --ORI~NAL GROUND ~~ -------
SECTION D-O
SCALE A.
E
-
•'f\.IP 811CI(£T
1900 t
t::
' 22~0
L-."' t ~ 2200
i ~
1 ::r:
! i ~·50 i a
2100
SECTION
$CAL£ .A
-------
SECTION E-E
SCALE l.
TYPICAL CHUTE WALL SECTION
SCALE .8
--~~-...-~·;/_
ti;200 [~ •• ----. /'• -~· £ L 50 100 fEtT
.---• ~L ·~~~.~.~~.~----·' ... ....
"'
.-·o• • ..-,. . tO ~· /' ; . 0 !I ; I ~ SCAt.EB~
IOfEtT
'7
~2150
I I ~ I ... _,
"'2100
NOTES
SECTION C-C
SCALE l
l TitS ORt.Wiffii lLLUSTR-'l£5 A I'RELIMiiiAR'l' COii«I'TUl\.
PROJECT LA~UT PREPARED FOR. COiolPAAISON OF
.• J.J.TfANATIVE SITE DEVELOPMENTS ONLY
2. SECTiONS fllR SCIIEl:E: WPl ARE S!l.lllAR EXCEPT TIIAf
l;ATE STRUCTIJRE IS 150' WIOE 'IIIITll CREST £\.~0 Mto
3·40'WIOExs3•lllGtl GATES
FIGURE 8.28
ALASKA POWER AUittORlTY
· stistiW. ifyooocu.ciiiieffiiiJ£Ci'-· ·~
WATANA
SCHEME WP!
SECTIONS
~--·'t.. MARCH 1982.
· .ic;£$ ;.;t'ftocJ.il' ;K«;.;.;>1[ci
-
(
0
~
"' '
--·· -
,•
-
' i
' I
I
--
("
--
.....
\
GENERAL ARRANGEMENT
SCAL£:.\
,,
'
\'
---·-
'·:zzoo-
2225
2250
2275 •
___ .......
Q
SCALE A
0
StAlE B
---
200 400l'EET
SO 100 fEET
~
'THIS DRAWING ILLUSTRATES A
l'IIElii.(INARY CONCEPTUAL PROJECT UYOUT
I'IIEI'~RED fDA COioll'l\liiSOtf OF
AL'U:RIIATI\'E SITE DEIIEI.OPIJENTS ONLY
-
SECTION A-A
SCAL£';B
-
FIGURE 8.29
Ill ALASKA POWER AUTHORITY
WATANA
SCHEME WP 2 a WP3
PLAN a SECTIONS
MARCH 191!1~
.. -
2300
2100 '
2000 -· -
... 1900 w
It
';!;
§ lilOO
lC ~ w
1700
1600 -~ •.
1500
-- - -
t
l
I
---------
' ., f
' > t
; -~~~--. .:"""
ELt440
t4ooL---------------Lo----L---~----~--~----500J---~----~--~-----L----~L----L----L----i----~---eo~o---J----~--~~---L---2000-L----L----L----L----L--__J
1700
... w
~1600
i!<
§
i 1500 a
1400
SECTION A~A
SU.T1014iNG Ill fEET
SPILLWAY PROFILE
SECTION B·B
0 ~~~105ii0iiiiiiiiii~200 fEET
rum
THIS DIIAWIIIO IU.USTRATES ...
l'llEUWlHAI!'I' CONCEPTUAL PROJECT LAYOOl'
P1!EPARED fOil COiiPARISOH Of'
A11ERHltiVE SlE DEVELOPMENTS ONLY
- --
. ~.YO~tl!.L --·· EI.J475
FIGURE 8.30
WATANA
SCHEME WP2.
SECTIONS
MARCH 1982.
--------
~ ---------------
----2~
-----
--~.....---· 21~0 --:;;;.-.:::.:_,..----_::~~::;;~::"'~ .--. '~
("~22110 ------zzoo-~.,00~ " NOTE
THIS llRAWII!G ll~USlRAT£5 A
l'lttLIIAINARY CONCEPTUAL I'RQ.IEC1 LAYOUT
l'lttNREO FOR 'COIINIIISON OF
~TERIU.Tlvt $1TE Df:IIELOPUENTS ONLY
--
l't!IO
l?oo--
tno -------_
1800--....._
,-1500 -'"\..
. -----' .\$00 ···---
---·· c~ ~ ... ...::;.
/
FIGURE 8.31
UIR ALASKA POWER AUTHORITY
, ·susirNA ••rllRoELECrRtc ffio.ie:cr · -· ~
WATANA
SCHEME WP4
PLAN
tf~ MARCH I9Ba ~ .. ii .t;.,:;.c;; ;;(cOft~.ini
..
24()0
ti
al ..
J;
! ;::
~ &00 .. ... ..
1®0
1400
2~
... ..
t!
:!l uoo
!
I=
J mo
~ ...
UlO
...
~
a.
:z
0 ;:
~ tlliO
~ ...
- - -
-------
NOiilUL &lAX. W.L COitTIIOL. STRUCTWI£ ·--------=~::w:.:~::Z:.::®.:-ii---------..---/--I:.:Sf:.:::.::E_:E:.:N_I.Aii9::__:::..E::..D:_:D:;:E.:;TAlU...::.. ____ ,.~ ---------~ •<->"-·----~--~~--.. ----·---·---------·-.. -.. " '"'""·-·· ··-~·----· ...... .,_. _ ...
--_:; .. ::::::.:.~.-:---T --;::;:::=-·------·-, _________ .:::::::::
-------------------+
ltDRIIW.. UAX. W.L
EL.UOO
S~LlWAY CONTROL STRUCTURE
SCAl.Et 8
r--:.-::·:.::::-.::l
.... ·t···-·--.. ----·--+-··-···· ..... ---... ._..--........ ~I
liO' W•O'II FIXED
WltEEL GATES
Si::CTtON A·A
SCALE: 0
STATIDitlltG IN FEET
SPilLWAY PROFILE
SCAl.t;; A
SECTION C-C
SCAI.£1 C
SECTION B·B
SCA~.E: a
o ZOO 400 f£ET
Sl:.U A I!P?~!!!!5iiiiiiiiiiiii!o::!
SCM..E a
o so too fEET
!!2!!
THIS DRAWIIIA IU.IJSTIIATU A
MEUMI!IAin' c:cw:EPTIIAI. l'ftGJECT LATOIIT
fii[PJ.R£I) fl)ft CONP~ OF
ALTERI'ATIVE SITE DE:VnOI'WJifS OHLY
FIGURE 8.32
~TANA
SCHEME WP4
SECTiONs
MAftCHI982:
-
.. ---- --- - - -
U:JO-
----- ---
~~~J~~~~~~~~c::;~~==~~~~~:o~~$=~-~_J~~~2~00~~~~oo~rt=·~~1 -F~lG~U~R~E~l8~.~3~3~
1'1115 llAAWIIIG LlUSTRAYE$ A
I'!IEI.IMIIWi'( CON<:~PTUA!. PROJECT LA:rtiUT
I'REP4R£D fOR COI.Y'ARISO!i OF
Al.TEIINATIVE SITE DE'IELOPMEHTS OILY
ALASKA POWER AUTHOR.ITY
~· -susln~i·uvi>Roaf:CTR'K:-pji()j£cr-····-
WATANA
SCHEME WP3A
tl!~~
A(;t,-,;.::.a;;;~;ttb
MARCii 1982
---- -
--- ---,' --
Ttl!$ DIIA\ffia LI.UST!'IAln A
l'!lEL.IUIWit COiictl'lUAL PROJ£CJ LQOUT
PREPARED FO!'I COYPA!liSOtl OF
ALnRH.I.TlVE SITE OEVEL0Pto£KT5 OIU
---
fUT FlGURE 8.34
WATANA
SCHEME WP4A
I
I ,,
I
I,
I
I
I
I
I
I'
I
I
I ,.
I
I
I
I
--,...:
u.. -~
~ ~ ...,
..J
Ill
ILl
~ ·&&. a:
::)
Cl)
1-eea
1000
I -PRESSURE TUNNEL
{36,000 CFS
t
a::
ILl 950 -----~--~--------~------~+-------~--------~ ; 0
9()0
eao
TYP. TUNNEl.
SECTION
20 25 30 35
TUNNEl DIAMETER (FT)
DEVIL CANYON DIVERSION
HEAD-WATER ELEVATION I TUNNEl DIAMETER
I
l
fi]
•• 20
I
I. 18
I
I f6
I t;>
I 14
-I Ulo -
~
~-l2
I -t-en
0
~
I.
10
I.
I a
I 0
TYPICAL
TUNNEL
SECTION
I 6
I
I 4
0
I
I
I
.. ...._--..... "(.'!*.;., • ! . •' . . . ' . : . . . . ... ,... .-. :\ :):~. . . . . . . . '-1 .. ~ . . . . . . . . . . .
• ~ : • ,1, ••• • . • : ·• • . ~ ~ . .
~
-
~
.
.. .
1 --I I
0 l
1.
l
~
I i ~
I j
~ fl Q If ~
~
I
j
~ ~ ___,_.~ v i
<
25 30 35
TUNNEL DIAMETER (FT.)
OEV\L.CANYON DIVE.RSION
TOTAL COST I TUNNEL DIAMETER
<
40
., ----- ----
GENEfiAL ARRANGEMENT
-
\
\
TillS DRAWIIIG IU.USTRATES A
l'ftfLPIUIART ~TIW.. PROJ£CT UYOUT
l'IIEAIIIfD FOR COMI'Nil$011. OF
A.LTERHATIV! SITE ~IIELOI'MENTS OH1Y
--
SECTION A-A
POW£11IIOUSE lOCATION SU!J.!£CT TO
OPTIIIIUTIOil ITUOIE8 Of ~'MISTII£111 l.OCATIOIII.
FIGURE 8.37
ALASKA POWER AUTHORITY
-SiJsiTN'AH"ioiioaECilt~e ff!OJECT
· DEVIL CANYON
SCHEME OCt
MARCH 1982
--
\ .,
0
\
-
ACQ(SS
\
0
0
~
\
f
0
0
!!
-----
\
' '
• \
I
I
I
\
'
/
' I
I
I , ,
-
/
~0
"'
I
)
0 .,
~
\
SWITCHYO.RO
LELI370 I
/'"/
,...,_ / -
~~-\
' i; '
'··,
' ' '
-
'
,>
~
\
1
I
0 0
%
-,
0
'!
--
""'
I
I
/
I
\
l
0
0
~
~~·,=-~=\~'~,----------~\
' '
\
I
\
se~
GENERAL ARRANGEMENT
I
THIS DRAW1Hii llLtJ::Ttuu""" A
l>i'lnlMIHAR'I' rotiCEPTUAL l'ftOJECT LAYOUT
l'llf:I'M£0 FOR COWARISOit OF
AlTEIIIATI\1!: sttE ll£VEl.Cfti£Hl'S ~
. .
l
' '
·-
£1..1457
DEVIL CANYON
SCHEME DC!a
MARCH198l! __ '-'!' _____ ....,.. __
ACftES AM(IIICAit IN-If[!>
----
I COO
1400
... ... ... ... ·~ ~
z ~ ~ 12~
... ...
uoo
-
SECTION 8.-8
!CAL£ ll
-
-
_, __ -
GENERAL ARRANGEMENT
SC:ALE: A
SECTION A-A
SECTION C·C
SCALE: ,8
SCALE! A
-
SECTION D·D
JlCA.I.El li.
.. --
ALUMUII Ill liVER HD
10 lit II£110VEO
c
-----·------·-··--
THIS Oft~ ILUiliTIIAfU A
I'IIEi. ... NAA'! COHC:U1'1IAI. 'J'IIO,IEl;r UYIXIT
PIIEI'MED fOft COIII'MI'OM 'Of'
ALTIIIIIo\'fiV£ ,1(1'£ ~I' ·111U
-
SECTION E-E
SCAlE. I
SECTION F-F
SCALE: I
SECTION G·G
IICAI.El It
FIGURE 8.39
--
I
ALASKA POWER AUTMOfUTY
DEVIL CAN'YON
SCHEME DC~
- -
\
\
-
~
GENERAL ARRANGEMENT
-
I
~
fl a.
""I ~ c
..
I
\
!
•• ----.
-
! ~----
~L-----------c---~--~--~--~~~~~~~~~~--~~~~~~~~----~--~~~--~--~--0 100 200 300 400 soo too 100 coo 100 1000 noo 1200 BOO ..loo ,aoo; •llioo l'too
1100
~1000
i!
~ lim w
d
100
rtii.;<·=-·---
SECTION B·B
1400 ..---------
BOO 1-----
,.;-
~1200
3
SUTIOKOOi Ill FEET
SECTION A·A
(ll!Ml SI'IUlGI.Y)
SECTION C-C
i 1100 1------~---:"---i;;-----.........,...&:-----;;.....:...-
"'
SECTION E-E
S£CTION F·F
.!!!ll!.
lltiS" DIU.WIIIQ IUUStRATd A
~ CQICI:ftUAI.-l'IIO.IECT LArOUT
'PIIDMED -~ COIII'IUISOII. CIF
ALTDIIo\tl'll£ Sttt ~ OHa
SECTION D•O
0~!!!!':!!!~100iiiiiiiiiiiii2~00 f~i.l
$CAL£ c
FIGURE 8.40
DEVIL CANYON
SCiiEM~ OC4
-
8 \
t .. ..
z
-~ .. -
I ) / I
~ I
I \ '\ I ~
(
l
~
\ (.
\
0 100 1t00 FEET
$CAl£ r-3
H2tt
:011 ClfiAll!lll IU.UITJIATU A
PRG,IIIINAIIY CafM:tl'tui:L I'IIOJ¥CT UYOUT
Pr'DAIIED 1'Ca eotlllt.lti&Oit ~ AU"£RIIAltV£
lin: ~NT Ola't
---
p
·' ' {
l
~"1'
I t
f
f
I
I ~:
DEVIl. CAN.VON
SELECTED SCHEME
-
' I
\'-
I
I
I
I
••
I,
I
I
I
I
I
I
I
I
I ,,
I
I
I
Q
<(
0
...J
¥
<t w
D.
b..
0
1-z w
0 a:: w
0.
100
90
80
70
60
50
40
30
20
10
0
~
0
J~ /
I
I('
I
~ ./
4 8 12. 16
HOURS
WINTER_ WEEKOAV
HOURLY LOAD VARIATION
' ' ."
\
20 24
NOTE: PEAK MW DECEMBER 2000 AD = 1084 MW
tOO
90
0 80 < 0
..J 70
~ < w 60
0..
1.1.. 50
0
f-40
z
1rJ 30 (.)
ll: w 20 tl..
10
0
~
-"
0
/ --...
I(
l -I -..... .._,.
4 8 12
HOURS
16
SUMMER WEEKDAY
HOURLY LOAD VARIATION
" ~
c
20 24
NOTE: PEAK MW JULY 2000 AD = 658 MW
TYPICAL LOAD VARIATION
IN ALASKA RAILBELT SYSTEM
-~ :=: . ......
Q
<t
0
..1
~
<t w a..
1100
1000
900
800
700
/ -" ~v
' £
" "' ..., v -..,. -
600
500
400
300
200
100
0 I I I I I 1
F M AM J J AS 0 N 0
MONTH
'·
LOAD VARIATION
IN Y£AR 2000
I
I
I.
I
I,
I
I
I
I
I
I
I
I
I
I
I
I
_-:'ba,. , cOOK INLET
• .. l '. --0&70---,\ •
OM! •
DATA COLLECTION STATIONS
USED IN PMF STUDY
STATION
• (A) SYSil'NA RIVER NEAft 0£tW.I X
I {8) .!liSITNA RIVEtt AT VEE CAtm:IN X
(C) !VSITJM. Rl\fat M£AA WATANA DlMSIT£ )t X
' (0) ~ M'EJit NOR DlVIL. CAN'tON X X
(f) SUStT'NA RIY'EJt A'f GOLD CR££1( X
(f) CHUU!lU ~ NlM .1l!IUC!£T'HA X
(G) TAI...I<£ETNA ~ NU~ TAL.JCEE:TNl. X
(Jofl Susm&A ~WEft NEAR ~ X
( I)·$1CWEN'l'HA lltMft .HOlt $KW£N"llM X
fJt 'l'EN'llfA MV'£Jt N£Nt -~ S"11tTICN X
no !U!l\1lf. ~ AT 1IUSfTNA S"'O''Itt x
X X X )(
X X X
X X X X
X lC .X
X X X
X X
X X X
1957-PMSENT l
fi9GI -liT2 a i
lltecl-I'RESENT '
X "X ' X ' X tHO-PR£SEHT i
X • ' X
X l
IMI-·PII£SENT
(1958-lt72 •
t980 -PN:stJfT
1964-JI'WOOIT
1111-PfQ[WT
ltSg-JMO
~-~
19!4 ... ffiE8ENT
DATA COlltCT£0 IIIIIXX ..... .-.-aaa .
• ~-c:oM'I'M!OUI !III!CCIM QQO
D S1"'IIEAWWWI' • PM11Al ll!!::onD 01.00
e WiiUUI .CIUALJT\' CIICO
T ~-~ 0«)1)
* I!DIM!Wf DI3CHIMIE
• a.JiiUTE
-FfiEEZifll M1lll Nf(J lla.DUD ·R:IIIG
• !IIIIOW COUPISE
'l IINICIIr CftfZ'P
NOTES
t. l'lliWIIETtJI$ IIEA!Uft£D usrm .. »P£JiUCl( II
2. CON'TlNUOUS -~ QUWTY MCNn"t1t -~
3. DATA COLlECTIOI'f IMI SEUON
4. 111£ \..I!TTER ~ EACtt SIAl iO!Il l'iUC IN 1111£
lUU5 IS ·USED <It ntE IIW' lO .._ 'nE.
APPRDWIMATE l.OCf,1'0t OF THE S ~I IIOfC.
SCALE
FIGURE 8.43
a.
I
I -I
' I
I.
I
' I
a
I
I
I
I
I .• ~;
·'
COOK INLET
SUSITNA RIVER
DEVIL WATANA
CANYON SITE SITE
GOLD CREEK
PARKS HIGHWAY BRIDGE
GAGING STATION
SUSITNA GAGU\'G STATKW
AVERAGE ANNUAL FLOW DISTRIBUTION
WITHIN THE SUSITNA RIVER BASIN
FHlURE B.~4 ~~~~
. ... : . .. . ' . •" ~ . . ' . .. ~ . ..
.. • fi':. .. • . . ·. . · .. ,..'\' '
~ . ' ..
~-... ~-·--·-
LEGEND
-0 40.000 WETTEST YEAR ... 5962
2
0
0 AVERAGE YEAR w
(f)
0: w
Q. DRIE!~T YEAR -&969
!-:;oiooo
'"'
w w u.
(.) -m
::l
0 -
3r: 20,000
0
-' lL.
:E
<(
w n: ....
UJ
10,000
0
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
MONTHLY AVERAGE FLOWS IN
THE SUSITNA RIVER AT GOLD CREEK
FlGURE BAS
I
I
I
I
I
I ""
1: ........
I
I
I
I
I
I
a I
I
I •
I
I
I'
lilt
0 -JC -en u..
(.J -
I.U
C)
Q:
<t :r:
(.J
C/)
Q
56.
40.
16.0~
8.0
o.oL--......-.---.......--___,...-~=====::::::=:;::=
0.00 0.20 0.40 0.60 0.80 1.00
PROS OF EXCEEDENCE
FLOW DURATION CURVE
MEAN MONTHLY INFLOW
AT WATANA
PRE-PROJECT
r ..... J,
FISURE 8,.46 I •g:-,
I
I
I
I
I
I
I
I
I
I
I
I
I
I
' '~ \ \
\" ..
.,
0 -"' -CJ)
11..
Q -
0.20 0.40 0.60
PROS OF EXCEEOENCE
FLOW DURATION CURVE
MEAN MONTHLY iNFLOW
AT DEVIL CANYON
PRE-PROJECT
0.80 1.00
AGURE B.41' ~~-I
- ---.. - - -.... -
15
10
II')Q 9
)IC 8 -:r: ~ 7 --1 6
~ !Z 5
~ n. 4
~
0:
·LIJ z 3
LLI
..J
§
2
~ 2
I
0
-·
.01
.
'
-
~ --""'----
'
0 0 .05 .I 0.2 0.5 I 2 5
RETURN PERIOD IN YEARS
J II . . 125 2 5 -10
r WATANA PLUS
DEVIL CANYON
I
I --~ t
~
I
rWATANA ONLY --~ -""'"---
. ~~
•
, ..
10 20 30 40 50 60 70 80 90
PERCENT EXCEEDENCE PROBABILITY
FREQUENCY ANALYSIS OF
100 aooo
FIRM ENERGY--
,~~WEST ANNUAL -1( ~RG'k' SiMi.JL.ATED ..
r -~ ----)
~
)t
,FIRM EtERGY
\
-~
' 1"--.. ~-:
\ -.... --.._
LOWEST ANNUAL_l
ENERGY SIMULATED
95 98 99 99.8 99.9 99.99
AVERAGE ANNUAL ENERGY FOR SUSITNA DEVELOPMENTS
Fl
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
90
80
g)
il.. usn
0
0
0
30
20
10
0
/T
I
I
I
I
I
-...J
0
...
.
I I
l I
I I I
f I l !
~ 1\ I I I ~ I I i
l I I \~
I 1 I
I ll : J I .
LOW·! -----~--
v~ I"' 1'-. OUTLET ""CILITIES
AT FULL CAPACITY
5
\_POWERHOUSE AND
CUTLET FACILITIES OPERATING
(MATCHING INFLOW)
10 15 20
TIME (DAYS)
1•50 YEAR FLOOD
(SUMME~)
:-....:
I
l
' ' I -~-I l
I ;;
I
~ ~ t ~
l ;;;
I j I ' ! # .
' I '
I j
~
' I i ' i !
i ' • ' '
l
I
30
2200 1--_;1---l---+---t·-""·--+--+---1
: I I
2198 1----+--+----il---+-,,. ---+--+i. ----11
, 1 ~ 1 i
J I i I ,. I !
-2196 1---+----+----t-, ---+-·----+---..t.j----ii
1-l I i l
.... 11: I l I ·~ 219.4 1---4----i!,__ __ _,_! ---i---!-·1 -?--+ ,· ---1'
>"' I !'. ,. ! i
kl ! ! l ;
&j f rMAX WSEl • 219t.G ~
a: 2192 .1. , ~ -..... :-~:~ ... ., ·, 1 1
E I:~~~; i l ~ 2190 ~----+-----·;---+-+----..f--~-~---+----~~ ~ ! l/1 i 1 l i
2188 1----+----4--+---r.----+----~\~---~----~1 I I: I ! l I
2186 1---~, ----l_!.t-/-=OUTLET fACILlTir:S--+.-~......;:~-~~
/
. ., ~ AT FULL CAPACITY j i
i '\!..POWERHOUSE AND OUl'LET FACILITIES ~-
2184 LL--..l jl __ __Jotc..'I'£_R_A_iT_IN_GL.1 _(_M_AT_c._H.J.I,N'3_._1N_F_Lo_.~~_l __ -L.I ----1~
0 ~ ID ~ ~ ~ ~ ~
mlE. (()AYSl
I•~ YEAR FLOOD
{SUiatMEill
lBO
ISO
l40
120
U> ...
u 100
0
0
2
3t 80 0
-l
1&.
60
' I' ,l
!I
40 '· ~ It " ---'! OPERATING
POWERHOUSE AND
20 OUTLET FACILmES AT
fULL CAPACITY '
POWERHOUSE AND I
OUT.LET FACILITIES OPERATING
(MATCHING INFLOW)
0
0 5 10 15 20 25
TIME (OA"i'S)
1•101000 YEAR FLOOD
2200 1----+-
2198
~ 21.96
1-:::.
~
~
j:: 2194 ~ : MA)(. W~L 2192.~
___.
I
35
~ L j I
a: 2192 1---+-----~----~~~--~~--~~----t--~
g I OUTFL:OW CAPACITY
f; MAIN SPILLWAY OPERATING ! ~ 2190 1----+--+--+--~..::(_M_ATI-C-H;_IN.:.:G_. _IN+F..:;L.:.OW.;.:.:_) -•---r----1
!
I
TI
2188
" I. • l
POWERHOUSE ANO OUlLET FAClltTIES OPERATING ·.
(MATCHING INFLOW)
2184 1-----~--~---~--~-----~----~--~,~ o 5 ro m G ~ ~ ~~
TIME {DAYS}
1•10,000 YEAR. FLOOD
360
~20
280
240
U> ..._
u 200
0
~
~
~ 160
..J ..._
120
eo
40
0
2196 .....
1-..._
z
0 2194
j:
~
10
...1
10 2192
0:
6 > s
II) 2190 10 a:
2188
2186
2184
...,. __ ,.., .. ,.,, .... ,.,.,._,,"t···+"' , -------.
t l I
' l i I ' •
I ! I I j I l
.rOUTFLOW !
-+-~~ -~
... ,
'"
i !
-~
' .!
l
POWERHOUSE AND OUTLET
FACILITIES AT FULL CAPACITY
OUTLET FACILITIES OPERATING
0 5 10 IS 29 25 ~0 35
TIM£ (OA,YS)
PROBABLE MAXIMUM FLOOD
l 1-----+--~~----r----~-·----~~~----~
1----;---++---+---~,, ... __ -!--'-t-\--J--~
I
0 5
; ~ if I
UAIN SPILLWAY,OOTLET FACILITIES
8 POWERHOUSE OPERATlNG
l
10 1!:1 20 2!5 so
Tl"'E (DAYS)
PROBABLE MAXIMUM FLOOD
FIGURE 8.49
JtPDI.~ .. J~~-A L._A~s_KA_Po __ w_. E--=R--:-:A-:-:-U-::-::TH-:-:o-=-=-R=-IT_Y-t ftUU[O SUSITNA HYDROELECTRIC PROJECT
WATANA
HYDROLOGICAL DATA
SHEET 2
MARCH .1982.
I·
I
I
I
I
I
I
I
·I
I
I
I
I
I
I
I
I
I
.,
"" 0
360 ..---,.----;,,.....-~-,---,.---,----,----; ~SERVOJRI
INFLO'#// OUTFLOW
!
0 200~~~~---~---4-----+---~---~---~
0
~
~
~-160 l---~l--r..~,,....::..:.--,----::----+---+--.....<
...J ' POWERHOUSE
"-' CLA$!!0.1
;:-
OUTFLOW
120 1-----l-lo'L-MATCHING +----1-----lf----~----'
30
40
0
0
INFLOW
1
l
I I
POWERHOUSE AND
I~ 20
TIME(OAYS}
30 35
PROBABLE MAXIMUM FLOOD
.-........... ---rl ··-~·-,
' RESERVOIR
ELEVA!ION
~ K40~----~-~~-~~--~~~------+----~
~
~ .. ~ 1430 1---~t------1----t---+--4~--+-----4
Ill
1400
!...____._· ! ____.__I ~l __.___i -'--------ll ~
0 e 10 IS 20 25 30 35
TIME (DAYS)
PROBABLE MAXIMUM FLOOD
mor---~---.---.---~---~--r---,---. I I t
J. ~~---l~: ----~--~~~~~----~---+--~ J \ 140~--~j----4-----+T---~-----r----~i~· ---~
I i
120 ~---'----t---f-v---ft---!---+( ------J
rn JNFL.f_ .• W• OUT~LOW~I~··. .I ~ ~ I I \ i ~ ~ 100 1----~ --+,-/-1--t-! --tl-\"ic---ll'----!t-i ---1
~ 80~--~---~-r--+----+----~~--~-~ ~ I / t I~ 60~--~~----;~---~''---+-=-·--4'----+'----~
; r' 1 .. l 4or---~~==-H---f----t-----t----r--~ n 1 t· 1 1 l~. 1'-MAIN YILLWAY Of'.:ATINt l
20 v \..._POWERHOUSE AND --+~-----+!Ill·.·· .. -----1!!, f. OUTLE.T FACILITlrES . '
1 OPERArNG
1
:
0~--~----~---~~--~----~----~-~ o 5 ~ rn m ~ ~ ~
TIME{DAYS)
RESERVOIR ROUTING
1•10,000 YR.FLOOO
1460 ' I I i I
j
I t
l l t !
1458
!/POWERHOUSE, OUTLET FACILITIES iND ' MAIN SPILLWA'I'
1
Of'ERATINS I
I
'
I !
~ 1456
~ w
...l
Ill
0:
0 > 0: w
(I) w
0:
1454
1452
14~0
'
!
•
• ' I
0 5
I I .
I I i ,.__MAX. WSEL•l45~
I t I ~ I ' 'j
~
'
I I
10 15 20 2.5
TlME (I)AYS)
RESERVOIR ROUTING
I • 10,000 YR. FLOOD
i
I
t
I
30
I I
i
50~--------------~-----r--------~
I , .
INFLOW"' OUTFLOW
U>
~ ~~--~~---4----~----~----~----~ 8
2
3: 20 F---it---+--_;...----+----...~..-..---:
0
..J u.
o~--...J~ __ __.. __ ....J...----L----l....---....1
0 5 10 15 20
TlloiE (DAYS)
RESERVOIR ROUTING
1'!50 'I'R. SUMMER FLOOD
1460 .------,r---,---,----,--=-------. I I 1_: I ~·
;: 1458!------+··--+· ---+-· --!~----~-'"~-.. . ~ : llr POWER~OUSE AND ' i .. g I OUTLET FACILITiiES ! ~ ! OPERATING 1 ~ 14561----~~-~~+-----~-~---~-~------~' ci ( I I t
~o-•-----~~·. ·~"·--4-----+-~~~M~A~X~~~W~SE~L~-~~~~~~--4i > 1454 r-''"""' I ~ I I
~ i I
1452 ~----+'---A< l' ---+-----t---------t
i {
1450 ~.-. __ .... f~ __ .......__--'i'-·. --.L.---'---.....JI
0 5 10 15 20 zs 30
TilliE (DAYS)
RESERVOIR ROUTING
1•50 YR. SUMMER FLOOD
FIGURE 8.50 II PDf@ 1·~-----AL_A_SK~A_P __ o_w_ER_A~·· u __ T_Ho~R_IT __ Y--t
HUH 0 SUSITNA HYOROE~ECTRIC PROJECT
DEVIL CANYON
HYDROLOGICAL. DATA
SHEET 2
MARCH 1982.
I·
I
I 2600
SURfACE AREA {ACRES X 104 1
6 2 0 1480
2500
I
2400 T 1475
I
'
2300 !
l I
2200 1470 I
1
I
2100 j:: l 1IJ I 11.1 ....
z 2000 0 1465 ~ > 11.1
..J
11.1
1900
I
I ;:
w w ....
~
~ > I· !j ...
I I L, .. 1800 I 1460 I
1700
I 1600
I
1400
I 0 4 6 8 10
VOLUME (ACRE FEET x 106 )
12 20 40 so 80 100 120 140 160
I RESERVOIR VOLUME AND SURFACE AREA TAILWATER RATJNG
I
I
I
I
I
I
co
"-
I~
120
0 105
0
0
0
60
45
0
l I I I I J l ;
i ! l • ' l ! I I
~ . ' I ' '
' ,r l I l ' .
~ i ' ' :
' • ' I ; I I ' i ; .
~ . > ' ' !
l ! ' j ' ~ ; l ; . i ; I i ,i
i ' ! ' ~ : I ~ ! i I l
' I l ! ' • ~
' i . A~ l ' .
~· '
1
!. \ ' ' . i
" i I ! ~ ' I ' l ! ~ ' I I I i I i !
I . ,, SPRING
~ ! I [.,,.o.a;,.
I I l r; I
I
I i l ' /i ~ ~ •
I
! I I v.V0' 1 I ! I
I I I
" J
I \ _» vvt i
~ ! J i /• ; I ,, . v vr ! I ·, ; l ~~ /
~ l
I l I I
·~ !-" l l I ' I
'
I
I
f
1.005 2 5 10 20 50 100 1000 10,000
RETURN PERIOD (YEARS)
INFLOW FLOOD FREQUENCY
FIGURE 6.51
·l·e.DfP 1~---' _AL_A_S K_A.....,..P_O-,-W-,-ER_· A_U_T~HO-=-R---IT_Y-;
HuH 0 SUSITNA HYDROELECTRIC PROJECT
WATANA
HYDRLOGICAL DATA
SHEET I
~~ MARCH 1982 _________ ......,. __ _
I
I
.S\.JiFACE AREA (1000 ACRES)
I
li 1!500
I r400
I
1300
I i=
Ill
Ill
!:=
~ ... I ~ w 1200 ..J
Ill
I
1100
I
I 1000
I
900
12 10 8 4 0
" / v
): v r-'"
VOLUME-~ v ~ SURFACE I REA
. v 1\., 11 \
l I \
' \
I \
I ' l I
·=
I
<'t':"";~_,.;.
..;_;,;,~,_,.
~5 .---.----r--~----T---.----.----.----~--~--~
I f I I I I
I I ! ! i i I ~o ~···--~·---+~-----~~·· --~.·----,r---~~----r!---;j ~·----~· ~~--~
' I I I I i ~r
I. 1 l 1 I !v~ !.• · i
865 ~--~--~1 ---1----+---~~~-~--~---+--~1~--4 I l /v I
~ ! /.. I l I I
~ 660 ~-tl--+!/-....Y..i -+---t-'----1--+----+--+--l ---4
: I t i
~ ;1 I I I I I
BSS ~---+--F--+-----!---+---+----+------ci----t----t----l y I I I
/ : I I I I I ;
850 1--/-1--4------11;....----+-t -----ii-----l-1----!:'-+----t-1-·. ~ .. -
I/ I ! r-
845~-----·4---~---4----+---;---~--~~--~~~~--~ I I 1 I i I I I
I
0 4 6 8 10 12 c 20 40 eo 100 eo 120 140 160 180 200
VOLUME {ACREFEET X IOe) DISCHARGE {CFS X 103 )
I
RESERVOIR VOLUME AND SURFACE AREA TAILWATER RATING CURVE
I.
~" .. ),
I
I
I
I
180
165
150
155
120
-Ct)
IL.
Q 10~
0
0
E
60
"15
15
0
t
!
t
!
\
.i .
~
j
!
1
1
' ' 1
! ..
' •
I
!
l
f
l
i
I
f
' ~
1.005
I t l I I (
I l
I t t ~ I I !
' I I I I ~ I ~ ~ I ' I I• ~
~ l I il I I I l I l :.1
t I ' ~ t
I 1 I l i
I I l ! I l i I . j I t I I ~ j 0
! 1.;
I t ! l ; .. I I I i ;
I f ..
I I I .
i /J
1/
~
c
~
!;
f I)' ' I i'
•• I I I I
_L f
" v " ,,
' I !
i -
'1-1, ..
• 2 5 10 20 50 100
RETU~ PERIOD (YEA!~S!
FLOOD FREQ~ENCY CURVE
(INFlOW AFiER ROUTING THROUGH WATA~)
FIGURE 8.52
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
DEVIL CANYON
HYDROLOGICAL DATA
SHEET I
~ ... a ... -MARCH 1982. ____ ......., ___ , __ _
l
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
2200 ~
2180 r-
-t-=
LL. 2160 --
-1
w
>
""
2140 t-
-1
a: -2120 0 1-
> a: w rn
~ 2100 -
0
2080
0
1460 r-
1459 r-
-~ ._; 1440 LL. -
-1 w
> 1430 1-w _,
a: -0 1420 t-> a:
LIJ rn
1-
LIJ 1410 a:
1400 ~
1390
0
I I I
N 0 J
~ J J
0 J
2190 NORMAL MAX1MUM .OP~RATING LEVEL 2185 1
I·
I
I
12095
J J J _l I _L ~ ~
F M A J J A s
MONTHS
WATANA RESERVOIR
NORMAL MAXlMUM OPERATING LEVEL. l455
_I J
F
I
M A
MONTHS
-·
j_ l
M
DEVIL CANYON RESERVOIR
1400
I I J J
J A s
MONTHLY TARGET MINIMUM RESERVOIR LEVELS
FIGURE 8 .. 53,.
J
I
I
I 740 .
II 5o/o GENERA' ~OR
I
RATED POWER ~
9
/
I 720 .RESERVOIR El. 2185 I .
I --------v
I I
700 " I
I 680
I
}-
I UJ
UJ 660 Jj.,
l
l::l
<t
UJ
I :c
....
UJ z
I .640
I I
I
I
I
1/i WEIGHTED A 'ERASE HEAD
-
I I ~ INIMUM DECEME ~R HEAD
I ··-14--170 MW
I
I ~
620
I
I 600
I I
B~ST EFf'j( J~v-/ j
FUU. GATE
I I
I
4 .
••
I 580 RESERVOIR EL.2045
~ --7 --·
I 100 ISO 200 22.0 120 140 • 160
UNIT OUTPUT-MW
I
I
WATANA-UNIT OUTPUT [iJ FIGURE 8.54
I
I·
I
I
I
I
I
I
I
I
I
I
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-~ 0 -> (.) z
liJ
5
~ ~~------~~------+--------+--------+-------~--~~ "" liJ
-(13
11.. 70~----~-~--------+--------+--------+-~~---4--~~s
w
(!)
~
<t
J:
~
Q ._.
~-------+--------+---~~-+--------4-----~--~--~2~~
40,000 80,000 120PQO 160,000 200,000
TURBINE OUTPUT ( HP)
WATANA-TURBINE PE~FORMANCE
{AT RATED HEAD)
24opoo
FIGURE 8.55 1111·1 ~--------~-------------------~~· _,,-.. ~~---~--~------------------~~
~~,00~------~------~&m~------~7~00~----~~~-------1~100~
PLANT OUTPUT (MW)
WATANA-UNIT EFFICIENCY
(AT RATED HEAD)
FIGURE B.5S
I
I 620
us< ~o GENERATOR
I
·_. RA., iED POWER
600
I
I 580
,_.
'I LLI
H!
t
Q
<l
"' I = ._560
"' z
I
RESERVOIR EL. 1455 I I l ---;' --I ~·
I
I I
) v,__. WEIGH1 EO AVERAGE HI ~0
BES tr GATE l ..
I
I I GENERA1 OR RATED POWE R I
I J I
BEST EFFIC EHCY7 FULL GATE
I
540
I· 520
IOIR /a 1400 MINIMUM OFt :S:URI::'R H~ f'(t:_::;~ /---.. I _. 15 ~ MW
I
I -
' 100 120 140 iGO ISO 200 220
I UNIT OUTPUT -MW
I
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I
I DEViL CANYON-UNIT OUTPUT
I FIGURE 8~57
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-~ 0 -b z
lLi
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~ 80~----~~--------r-------~------~--------~--~ u.
UJ
IJJ z
ai
0:
~
t--U) u.. ro~-------r--------r-------~--~~~--------~--~~oos
I.!J
(!)
a:
<t
~
i5
!:: ~-------~-----~~r---------~------~---------+----~2000~
40,000
------r-------~---~1000
00,000 J20POO 160,000 200.poo
TURBINE OUTPUT ( HP)
{)EVIL CANYON -TURBINE PERFORMANCE
(AT RATED HEAD)
240,000
FIGURE 8.58 !.ill
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lLI
-----------d~T --n
I UNIT
..
§ 82~~------~--------~------~-------+--------~--~~ l&.
"'-\1.1
78~+--------r--------~------~-------+----~--+-----~
N~+-------~--------~------~-------~-------+----~
100 200 300 400 500
PLANT OUTPUT ( MW)
DEVIL CANYON-UNIT EFFICIENCY
{AT RATED HEAD)
FIGURE 8.59 ~~~~ "
I
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~
FAIRBANKS· TANANA
VALLEY f'_ __ . ~~~
RAILBELT AREA OF ALASKA
SHOWlNG ELECTRiCAL LOAD CENTERS
100,.1W
F'lGURE 9.60 ••
I
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01
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::0
1
2500 r--------.-------.,..-------.
2000 t--------;-------+----,"-------t
1500
o4l ;""("(o -I.
1000
0------------------------------------~ I~ . 1970 •. 1915 1$80
YEAR
HISTORICAL TarAL RAILBELT UTIUTY SALES
TO FINAL CUSTOMERS
l FIGURE ~61 ,., e..:;....,---..---·----------------[~~,_------------~ ....
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Ia~--------------------------------------~------------------~
15
14
13
-~ I I
"' ::1:
LEGEND
HES ... GH : HIGH ECONOMiC GROWTH i' HIGH GOVERNMENT EXPENDITURE
MES-GM : MODERATE ECONOMIC GROWTH +MODERATE GOVERNMENT EXPEND1TURE
LES ~ GL : LOW ECONOMIC GROWTH t LOW GOVERNMENT EXPENDITURE
LES-Gl. ADJUSTED : l.OW ECONOMIC GROWTH +LOW GOVERNMENT
EXPENDITURE 't LOAD MANAGEMENT AND CONSERVATION
I
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IHES-GH
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§
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~ 10~------------------~------------------~~----------------~ C-' -
, / ,
, ,
/
~
~· ,
, , , ,
'·
, , ,
I
I
. I Qb---------~----------~---------~---------*--------~----------1980 1985 1995
YEAR "
2000
ISER 1980 ENERGY FORECASTS USED
FOR DEVELOPMENT SELECTION STUDIES
200&· 2010
riGURE 8.62
______________ , _____ _
...... ----------·--_,..-------_,------------------------------.
•
ECOf'JOMIC SCENARIOS
• PRIVATE ECONOMIC ACTIVITY
• STATE FISCAL POLICY
ECONOMIC MODELS
• l.SER STATEWIDE MODEl
• REGIONAUZATION MODEL
• HOUSEHOLD FORMATION
ECOf\!OMIC, INDUSTRIAL,
POPUlATION AND HOUSEHOLD
FORECASTS
INPUT DATA AND
ASSUMPTIONS I
I
l
• END USE SURVEY i
• CONSERVATION PERFORMANCE I.
AND COSTS
• FUEL COSTS
• COMMERCIAL BUilDING STOCK l
l l
END USE MODEL ll.
(RED)
!
aECTRlC ENERGY
CONSUMPTION
FORECASTS
• ANNUAL £NERGY
• PEAK DEMAND
E:LECTRiC PtJ;•NER FORECASTING PROCESS
FIGURE B.6S
·~--~--~· ~---------------------------------------------------·------------------=-------------~
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!6, ,.-----------r-----------t---------
15
14
13
12
II
/ -~ If')
2 I0~------~-------+----------------+---------~~---4
liC
%
~
-9 / /'
HIGH//
~
•
~·
~·
0 ------~--~------~------~--------*-----~~--------1980 1985 1990 1995
YEAR
2000
DECEMBER· 1981· BATTELLE LOAD AND
2005 2010
ENERGY FORECASTS USED FOR GENERATION PLANNING STUDIES~
FIGIJR£ 8.6+ •
---..
300
250
200
---·. -. --
. --.' ..
[ WATANA ONL v IN 19!14 J
LEGEND
"""---· Energy Con of 8ht Thatmal Option
•••• ...... • • Energy Coft of Susitna Optf4n
• • (}ptratint.~ Con a of Tbtrmai Plant ln u,.
in 1893 Exttndad to 1994
~ lli;;;:M] Shaded Area RtpreMnta Plant Operati!JQ
In 1892 Dlaplaced by Wab!na
Area Under This line ia Annual Con of Bm Thermal Option
flnduding Investment Cost;)
.. r.:ea Under This Lint is Annual Cost of SusitM Option
Area Under This line ia Annual r---_,._ Operating Cost of Existir2g Capacity 1993/4
(Avoided Costs of Fu~~ and O&M Only)
Area Rcpresants Annual Operating Cosu
from Existing Generating Plant r-Common to Both Susitna and
Thermal Options
Medium Growth Syatem Energy '1111111111111111111111~!1 ~~~b 1 ~~~~ ol ==~
3,000 4.000 5,000
Annual Energy Output GWh
--
FIGURE ~.65 -ENERGY PRICING COMPARISONS-1994
--
--------~----~-~---
Rw.1
380
360
340
300
\
11
' 180 \ . " .. ~ 160
140
120
100
SYSTEM COSTS AVOIDED BY DEVELOPING SUSITNA
COMPARED WITH BEST THERMAL OPT20N IN MILLS PER UNIT
Of SUSITNA OUTPUT IN CURRENT DOLLARS
~' ·#
'r •• I I I
,, COST SAVINGS FROM SUSITNA INCREASING I . OVER WHOLE LIFE OF PROJECT
,.~
I ......
Increasing Thermal Fue: /
COiti Avoided ""-.._ ·· ·· -.... #
""-.._ .# ... ~-·--······' --_ _, , .. -,.
j .
/.-Avoids Co•t ~11:1 Further 200 M\N Coal fired Generating Unit
I .
I I . .
~t••.-.c Avoids Con of 2 x 200 MW Coal fired Gtmerating Units
1
~ Dovll Canyon on $tr .. m in 20021
02 03 04 05 06 07 liB 09 2010 11 12 13 ~~-~~~~
Watana ora Str~sm in 1993
6 6 7 8 9 2000 01
Years FIGURE 13.66 -SYSTEM COSTS AVOIDED BY DEVELOPING SUSITNA RU