HomeMy WebLinkAboutGrant Lake Hydroelectric Project Detailed Feasibility Analysis Volume 1 Final Report 1984j.
Alaska Power Authority
LI 8RAitY COpy
GRANT LAKE
HYDROELECTRIC PROJECT
DET AILED FEASIBILITY ANALYSIS
VOLUME t
FINAL REPORT
Ea8D
EBASCO SERVICES INCORPORATED
January 1984
L...--_ ALASKA POWER AUTHORITY_---J
GRANT LAKE
HYDROELECTRIC PROJECT
DETAILED FEASIBILITY ANALYSIS
for the
Alaska Power Authority
by
Ebasco Services Incorporated
Bellevue, Washington
January, 1984
~ 1984 Alaska Power Authority
EXECUTIVE SUMMARY
1.0 PURPOSE
The purpose of this Feasibility Report is to: 1} describe the results
of the studies conducted from October 1981 through January 1984 of the
feasibility of the 6rant Lake Hydroelectric Project; 2} define a
selected project arrangement for the development of the hydroelectric
potential at Grant Lake; 3} provide the engineering. environmental. and
economic data required to assess the Project's feasibility; 4} present
the results of a pre-feasibility study of the expansion of the existing
Cooper Lake Hydroelectric Project; and 5} present the results of a
feasibility-level investigation of the upgrading and/or replacement of
the Daves Creek-Seward transmission line.
The Grant Lake Project has been the subject of several previous
studies; however. all previous investigations have lacked site specific
data upon which to base a reliable evaluation of the project
feasibility. The current study. which includes the required field
investigations for evaluation of project feasibility. was authorized by
the Alaska Power Authority (Power Authority) in September 1981.
2.0 SCOPE
The results of studies performed from October 1981 through February
1982 were presented in an Interim Report (Ebasco. 1982). dated February
1982. The results of studies performed subsequent to the Interim
Report are presented in this Feasibility Report. along with a summary
of the Interim Report findings.
INTERIM REPORT SCOPE
The scope of investigations and activities which were performed for the
Interim Report include the following:
1
o Performance of field studies at the Grant Lake site, including
surveying and mapping, geotechnical, hydrological, and
environmental investigations;
o Compilation and review of existing literature and data;
o Identification of reasonable alternatives for development of
the power potential at site;
o Development of a monthly streamflow model and flood hydrology
for site;
o Performance of reservoir operation and power output studies
for each alternative arrangement;
o Performance of preliminary design and preparation of
conceptual layouts of project features for each alternative
arrangement;
o Assessment of potential environmental impacts associated with
each alternative arrangement;
o Preparation of comparative conceptual-level estimates of
construction cost for each alternative arrangement;
o Determination of the annual cost of each alternative and the
resulting cost of power;
o Comparison of technical, environmental and economic
considerations of each alternative and selection of one
alternative for further study;
o Conduct of meetings and correspondence with resource agencies
to coordinate the environmental studies;
2
o Conduct of public meetings in Seward and Moose Pass, Alaska;
and
o Establishment of 1982 study plan.
These studies provided the basis for comparing the technical,
environmental, and economic considerations of the alternative schemes
for development of the project. Six alternative schemes, called
Alternatives A through F, were identified in the study. Alternatives
A, B, C, and 0 use only the inflow to Grant lake for power generation;
Alternatives E and F utilize Grant Lake inflow and flow diverted from
Falls Creek. Alternatives A, B, and C include the construction of a
main dam at the natural outlet of Grant lake with a saddle dam across a
low divide approximately 1.1 miles north of the main dam. Alternatives
o and F utilize the existing lake level and provide for regulation by
means of a low level lake tap, thus requiring no dams on Grant lake.
Alternatives 0 and F (the lake tap alternatives) were found to have the
lowest cost of power and the least environmental impacts. On this
basis the Power Authority authorized further investigations of
Alternatives 0 and F for the remainder of the feasibility study. In
subsequent studies the Falls Creek diversion was dropped due to the
high cost per kWh of energy from the diversion. The high cost is due
primarily to the length of the diversion and the short operating season
of the diversion due to freeze up.
FINAL REPORT SCOPE
The scope of investigation performed on the lake tap alternatives,
which extended from March 1982 to January 1984, include the following:
o Execution of 1982 field work program which included additional
subsurface geotechnical investigations, surveying and mapping,
hydrological data collection and environmental surveys;
3
o Designation of a selected project arrangement for development
of hydroelectric potential at Grant Lake based on optimization
studies and consideration of environmental impacts and
mitigation options;
o Performance of reservoir operation and power output studies
for the selected project arrangement;
o Performance of preliminary design and preparation of
conceptual drawings of project features for the selected
project arrangement;
o Assessment of potential environmental impacts and designation
of a mitigation plan for the selected project arrangement;
o Preparation of feasibility-level estimates of construction and
operation and maintenance costs for the selected project
arrangement;
o Performance of an economic analysis for the Grant Lake
Project. including selection of a recommended generation plan
for the City of Seward. and a comparison of the cost of power
from the Grant Lake Project with other potential generation
sources in the region;
o Conduct of meetings and correspondence with resource agencies
to coordinate the environmental studies and to establish
mitigation alternatives;
o Conduct of public meetings in Seward and Moose Pass. Alaska;
o Conduct of prefeasibility investigation of the expansion of
the existing 15 MW Cooper Lake hydroelectric project;
4
o Performance of a feasibility-level investigation of upgrading
and/or reconstruction of the existing 24.9 kV transmission
line which extends from the Daves Creek substation to the City
of Seward.
The results of these studies are presented in this Feasibility Report,
which is organized as follows:
VOLUME I: PART I -SELECTION OF GENERATION PLAN
PART II -COOPER LAKE EXPANSION INVESTIGATION
PART III -DAVES CREEK-SEWARD TRANSMISSION LINE
INVESTIGATION
PART IV -FEASIBILITY ASSESSMENT OF GRANT LAKE
HYDROELECTRIC PROJECT
VOLUME II: ENVIRONMENTAL REPORT
VOLUME III: TECHNICAL APPENDIX
3.0 CONCLUSIONS
Based on the results of the studies outlined above, the following
conclusions have been reached:
1. The existing Daves Creek-Seward transmission line is inadequate for
the existing loads and will become more inadequate as electric
power requirements in Seward increase. A new 115 kV transmission
line -generally routed along the Seward-Anchorage Highway -should
be constructed as soon as possible to upgrade the electrical power
supply to Seward to acceptable standards. This transmission line
is required regardless of the generation resources required to meet
Seward's load.
5
2. The present worth cost of the Base Case Plan and four alternative
plans for providing forecasted power requirements to the City of
Seward from 19B3 to 2037 are as follows, assuming a medium load
growth scenario over the next 20 years and forecasted marginal
prices for natural gas at Sherman Clark's (SC) escalation rates:
Base Case Plan 1
(gas-fired generation)
Alternative Plan 1-1
(gas-fired generation with the
Total Present Benefit/Cost
Worth -Jan 83 Ratio
$150,141 ,000
Grant Lake Project) $148,344,000 1 .012
Alternative Plan 1-2
(gas-fired generation with
a portion of the 90 MW Bradley
Lake Proj ect)
Alternative Plan 1-3
(gas fired generation with
a portion of the 135 MW
Bradley lake Project
Alternative Plan 1-4
(gas fired generation followed
by complete reliance on the
$146,983,000 1 .021
$149,313,000 1.006
Susitna Hydroelectric Project) $156,200,000 0.961
Alternative Plan 1 is also slightly more economical than the Base
Case Plan assuming either a high load growth scenario or a low load
growth scenario, with marginal gas prices at SC escalation.
3. The results of the economic analysis indicate that the presence of
the Grant Lake Project in the generation resource mix serving the
City of Seward would result in a slightly lower cost of power than
the Base Case Plan without the project, and regardless of whether a
low, medium, or high load growth scenario is realized (assuming
forecasted marginal prices for natural gas at SC escalation).
6
4. The present worth of the plan including the Grant Lake Project is
slightly higher than the plan including the operation of the 90 MW
Bradley Lake Project. The present worth of the plan including the
Grant Lake Project is less than the plan including a portion of the
135 MW Bradley Lake Project. The 135 MW Bradley Lake project
includes cost of transmission facilities for the Anchorage-Soldotna
Intert1e. The plan relying on Susitna after its online date is
higher in present worth than the Grant Lake Plan.
5. The Grant Lake Project is economically feasible with the outcome of
the economic analysis being particularly dependent on the
assumptions made for the price of gas and the rate of escalation of
that gas. The most recent values for anticipated prices and
escalation have been used in the analysis. In addition to the
economic benefit, the Grant Lake Project would increase the
electric system stability and reliability as the project is located
closer to the load center than the major generation sources. The
Grant Lake Project would also provide an additional benefit by
providing a generation source earlier than the Bradley Lake
Project. The timing studies indicate that the earlier the on-line
date for the Grant Lake Project the greater the benefit as it
allows for earlier displacement of gas fired generation. However,
no computations were perfonmed on a combination alternative
consisting of gas fired generation, Grant Lake, and the Bradley
Lake Project.
6. The most economical and environmentally attractive alternative
identified in the Interim Report for the Grant Lake Project is
Alternative D. Diversion of Falls Creek into Grant Lake to
increase power production from the Grant Lake Project is
uneconomical.
7. The selected project arrangement for the Grant Lake Project
consists of a lake tap intake on the west shore of Grant Lake, an
inclined tunnel leading to a powerhouse on the east shore of Upper
7
Trail Lake with an installed capacity of 1 HW, an access road and
transmission line extending from the powerhouse across the narrows
between Upper and Lower Trail Lake to the Seward-Anchorage Highway,
an access road to Grant Lake, recreation facilities at Grant Lake,
and salmon rearing facilities adjacent to the powerhouse and
tailrace. The average annual energy production from the project is
24.94 GWH, as delivered to the City of Seward.
8. The bid price estimate of construction cost for the Grant Lake
Project is $24,113,000 in January 1983 dollars. The earliest
practical on-line date for the project is April 1981. For ease of
computation the economic analysis assumes a January 1988 on-line
date at the earliest.
9. The environmental impacts associated with the development of the
Grant Lake Project are generally insignificant. The primary
environmental impact of the Grant Lake Project is loss of the fish
habitat in Grant Creek. Although Grant Creek would be dewatered
for its full length, only the lower 1/2 mile is currently utilized
by fish. An estimated 100 chinook and 500 sockeye salmon adults
would be lost annually from Grant Creek. In addition, habitat for
rainbow trout and Dolly Varden would be eliminated. Because of the
mitigation measures employed. the Grant Lake Project would not
cause a net loss to fisheries resources.
10. A prefeasibility investigation of the potential for expanding the
energy output of the existing Cooper Lake hydroelectric project
shows that, when compared to the cost of energy from gas-fired
combined cycle generation, the Stetson Creek diversion would be
economical and the Ptarmigan Creek diversion would be marginally
economical. The addition of installed capacity of the existing
Cooper Lake powerhouse would be uneconomical and unnecessary for
development of either of the diversions studied.
8
4.0 RECOMMENDATIONS
In view of the above stated conclusions, it is recommended that:
1. The Power Authority proceed with the design and construction of the
115 kV Daves Creek-Seward transmission line.
2. The Power Authority proceed with the development of the Grant lake
Hydroelectric Project in order to displace gas fired generation
earlier than can be achieved with the Bradley Lake Project and to
provide improved system stability and reliability once Bradley lake
is constructed;
3. An application for a license to construct and operate the Grant
Lake Project be prepared and submitted to the Federal Energy
Regulatory Commission;
4. Design activities for the Grant lake Project be commenced in 1984.
9
TABLE OF SIGNIFICANT DATA FOR
THE GRANT LAKE HYDROELECTRIC PROJECT
HYDROLOGY
Drainage area, sq mi
Avg. annual runoff, cfs/sQ. mi.
Maximum monthly streamflow, cfs
Average annual streamflow, cfs
Minimum monthly streamflow, cfs
PROJECT POWER DATA
Installed capacity, MW
Avg. annual energy generated at plant, GWh
Avg. annual energy at load center, GWh
Annual firm energy generated at plant, GWh
Annual firm energy at load center, GWh
Dependable capacity at load center, MW
Annual plant factor
RESERVOIR
Normal maximum power pool elevation (msl)
Minimum power pool elevation (msl)
Reservoir area at normal maximum pool, ac.
Active storage capacity, A-F
Highest reservoir level during possible maximum
flood (ms 1)
POWER INTAKE
Type -Lake tap intake structure with steel trashrack,
located 900 ft north of natural outlet of Grant Lake
Invert elevation (msl)
POWER CONDUIT
Type -Horseshoe tunnel excavated in rock.
Shotcrete lining on tunnel sides and
crown, and concrete lining on floor
Length, ft
Inside diameter, ft
Average shotcrete thickness, inches
POWER STATION GENERATING EQUIPMENT
Turbine Type -Vertical Shaft Francis
Number of units
Rated net head, ft
10
44.1
4.4
504
196
27
7.0
25.40
24.94
18.82
18.48
6.55
0.41
691
660
1 ,650
48,000
709
643
3,200
9
3
1
206
Rated flow, cfs
Speed, rpm
Runner diameter, in
Centerline elevation of spiral case
Rated turbine capacity, best gate, hp
Generator Type -vertical shaft synchronous with
enclosed cooling
Generator unit rating, kVa
STRUCTURE
Length
Width
Height (above plant grade)
Generator floor elevation
TAILRACE CHANNEL
Length, ft
Bottom width, ft
Maximum velocity, fps
TRANSMISSION LINE
Type -Wood pole construction
Voltage, kV
Length, mi
SIH ACCESS
Access Roads
459
400
52
470
9,580
7,780
45'-6"
40 1 -0"
50'-on
487.0
640
20 to 100
6
115
1.2
Class A -Used to provide permanent access from
Seward-Anchorage Highway to powerhouse
Length, mi 1.2
Width, ft 24
Maximum grade, percent 8
Class B -used to provide access to gate shaft
and recreation area at Grant Lake
Length, mi 1.2
Width, ft 18
Maximum grade, percent 8
Bri~ges:
1 required at narrows between Upper and Lower
Trail Lakes:
Type -Prestressed concrete
length, ft 140
SITE ACCESS (continued)
1 required across Grant Creek to recreation area:
Type -Timber
length, ft 60
11
VOLUME 1
GENERAL OUTLINE OF REPORT
PART I -SELECTION OF GENERATION PLAN
PART II -COOPER LAKE EXPANSION INVESTIGATION
PART III -DAVES CREEK-SEWARD TRANSMISSION FEASIBILITY STUDY
PART IV -FEASIBILITY ASSESSMENT OF GRANT LAKE
HYDROELECTRIC PROJECT
VOLUME II ENVIRONMENTAL REPORT
VOLUME III TECHNICAL APPENDIX
TABLE OF CONTENTS -VOLUM£ 1
EXECUTIVE SUMMARY . . 1
TABLE OF SIGNIFICANT DATA FOR GRANT LAKE HYDROELECTRIC PROJECT 10
PART I -SELECTION OF GENERATION PLAN
1.0 INTRODUCTION. . . . . . . . . .
1.1 AUTHORIZATION ....... .
1.2 BACKGROUND TO PRESENT STUDIES
2.0 FORECASTED POWER REQUIREMENTS ..
2.1 GENERAL .......... .
2.2 KENAI PENINSULA DEMAND AND ENERGY FORECAST
2.3 SEWARD AREA DEMAND AND ENERGY FORECAST
3.0 GENERATION PLANS IDENTIFIED
3.1
3.2
3.3
3.4
3.5
GENERAL . . . . . . . .
BASE CASE PLAN I ... . .
GENERATION PLAN WITH GRANT LAKE PROJECT
(ALTERNATIVE PLAN 1-1) ......... .
GENERATION PLANS WITH BRADLEY LAKE PROJECT
(ALTERNATIVE PLANS 1-2 AND 1-3) ...
GENERATION PLAN WITH SUSITNA PROJECT
(ALTERNATIVE PLANS 1-4) .
4.0 EVALUATION OF GENERATION PLANS ..... .
1-1
1-1
1-2
2-1
2-1
2-2
2-3
3-1
3-1
3-3
3-&
3-7
3-8
4-1
4.1 GENERAL............... 4-1
4.2 METHODOLOGY AND ASSUMPTIONS FOR ECONOMIC ANALYSIS 4-1
4.3 DERIVATION OF COST OF PLAN COMPONENTS. 4-5
4.4 OPTIMUM TIMING FOR GRANT LAKE PROJECT ... 4-16
4.5 RESULTS OF ECONOMIC ANALYSIS . . . . . . . . . . 4-16
4.6 ENVIRONMENTAL EVALUATION . . . . . . . . . . . . 4-19
4.7 SELECTION OF GENERATION PLAN .............. 4-22
PART II COOPER LAKE EXPANSION INVESTIGATION
5.0 COOPER LAKE EXPANSION INVESTIGATION ..
5.1 INTRODUCTION .......... .
5.2 STETSON AND PTARMIGAN CREEK DIVERSIONS
5.3 COOPER LAKE CAPACITY EXPANSION
5.4 CONCLUSIONS. . . . .. . .....
1
5-1
5-1
5-2
5-7
5-8
TABLE OF CONTENTS -VOLUME 1 (Continued)
PART III -DAVES CREEK-SEWARD TRANSMISSION LINE INVESTIGATION
6.0 DAVES CREEK-SEWARD TRANSMISSION LINE
6.1 HISTORICAL DATA ...
6.2 ELECTRICAL CONDITIONS
6.3 PHYSICAL CONDITIONS
7.0 LOAD FORECAST ..... .
7.1 HISTORICAL DATA ...
7.2 RECENT AND PLANNED DEVELOPMENTS
7.3 DESIGN LOAD ELECTRICAL PEAK DEMAND.
8.0 TRANSMISSION REQUIREMENTS ..
6-1
6-1
6-2
6-3
7-1
7-1
7-1
7-1
8-1
8.1 GENERAL. . . . . . . . . . 8-1
8.2 SELECTION OF LINE DESIGN . . . . . . . . . . . . . 8-1
8.3 PERFORMANCE EVALUATION OF SELECTED LINE ALTERNATIVE 8-8
8.4 CORRIDOR ............. 8-9
8.5 GEOTECHNICAL CONDITIONS. . . . . . . . . . 8-12
8.6 RIGHT-OF-WAY. . . . . . . . . . . . . . . . 8-14
8.7 SUBSTATIONS AND SWITCHING STATIONS . . . . 8-16
8.8 INTERFACE WITH CHUGACH ELECTRIC ASSOCIATION 8-19
9.0 SU8TRANSMISSION REQUIREMENTS 9-1
9.1 EXISTING 12.47 KV LOADS FROM CITY OF SEWARD
TO MILEPOST 9 . . . . . . . . . . . . . . . . . . . 9-1
9.2 EXISTNG 24.9 KV LOADS FROM MILEPOST 9 TO LAWING
METERING STATION . . . . . . . . . . . . . . . . . 9-1
9.3 24.9 KV LOADS FROM LAWING METERING STATION TO DAVES
CREEK SUBSTATION .. . .. .... 9-1
9.4 SERVICE DURING CONSTRUCTION. . . . . . 9-1
9.5 EMERGENCY OPERATION. . . . . . . . . . 9-2
10.0 TRANSMISSION LINE COST ESTIMATE AND SCHEDULE
10.1 COST ESTIMATE ......... .
10.2 OPERATION AND MAINTENANCE COST
10.3 SCHEDULE ........... .
i i
10-1
10-1
10-1
10-1
TABLE OF CONTENTS -VOLUME 1 (Continued)
PART IV -FEASIBILITY ASSESSMENT OF GRANT LAKE HYDROELECTRIC PROJECT
11.0 EXISTING SITE CONDITIONS
11 .1 GENERAL . .
11.2 TOPOGRAPHY .... .
11.3 GEOLOGY ..... .
12.0 ALTERNATIVE PROJECT ARRANGEMENTS
12.1 EARLY STUDIES ...... .
12.2 INTERIM REPORT STUDIES .. .
12.3 GENERATION WITH GRANT LAKE INFLOW ONLY -
ALTERNATIVES A, B, C, AND D ..... .
12.4 DIVERSION OF FALLS CREEK -
ALTERNATIVES E AND F ........ .
12.5 COMPARATIVE CONSTRUCTION COST ESTIMATES
13.0 FIELD INVESTIGATIONS ..
13.1 GENERAL ..... .
13.2 SPECIAL USE PERMITS
13.3 EXECUTION OF FIELD WORK
13.4 SURVEYING AND MAPPING
14.0 GEOTECHNICAL STUDIES.
14.1 GENERAL .....
14.2 REGIONAL GEOLOGY
14.3 SITE GEOLOGY ...
14.4 ENGINEERING GEOLOGY FOR PROJECT STRUCTURES
14.5 GEOLOGIC HAZARDS
15.0 HYDROLOGICAL STUDIES
2440B
15.1 GENERAL . . . .
15.2 EXISTING DATA.
15.3 FIELD STUDIES.
15.4 DEVELOPMENT OF MONTHLY STREAMFLOW MODEL FOR SITE
15.5 FLOOD HYDROLOGY ........... .
iii
11-1
11 -1
11-1
11 -2
12-1
12-1
12-3
12-4
12 -16
12 -1 B
13-1
13 -1
13-1
13 -2
13-2
14-1
14 -1
14-2
14-5
14-10
14-15
15-1
15-1
15-1
15-2
15-2
15-5
TABLE OF CONTENTS -VOLUME T (Continued)
T6.0 POWER OPERAIION STUDIES
16.1 POWER ST UDY OBJECTl VES
16.2 STUDY MEIHODOLOGY .. .
16.3 INPUT DATA ...... .
16.4 SUMMARY OF INTERIM REPORT STUDIES
16.5 DEIAILED POWER STUDIES PERFORMED FOR LAKE TAP
ALTERNATIVES ............. .
16.6 SELECTION OF OPTIMUM INSTALl_ED CAPACITY FOR
AL TERNA 11 VE 0 . . . . . . . . . . . . . . . .
16.7 EVALUATION OF ECONOMICS OF FALLS CREEK DIVERSION
1/ . 0 SELECTED PRO J E C 1 ARRANGEMENT
17.1 GENERAL ..
17.2 RESERVOIR.
17.3 INIAKE AND GATE SHAFl
17.4 POWER CONDUII .
17.5 POWERHOUSE AND TAILRACE
17.6 ACCESS ROADS AND BRIDGES
17.7 TRANSMISSION OF POWER ..
17.B MITIGATION FACILITIES ..
17.9 FALLS CREEK DIVERSION WORKS
18.0 PROJECT COSTS AND SCHEDULE
IB.l GENERAL ...... .
IB.2 PROJECT CAPITAL COST.
IB.3 ANNUAL COSTS .....
IB.4 DESIGN AND CONSTRUCTION SCHEDULE.
18.5 ALTERNATIVE F DETAILED COST ESTIMATE.
19.0 REFERENCES .......... .
VOLUME II -ENVIRONMENTAL REPORT
VOLUME III -TECHNICAL APPENDIX
i v
2440B
16 -1
16 -1
16 -1
16 -2
16 -6
16-7
169
1 6 -1 I
1 1 -1
1 / -1
1 7 -2
1 / -3
1/-4
1 / -6
17 -B
1 7 -B
17 -9
1 1 -1 0
1 8 -1
1 B-1
1 B-1
1 B -3
18 -4
18 -5
19 -1
Table
Number
LIST OF TABLES
EXECUTIVE SUMMARY -SIGNIFICANT DATA FOR GRANT LAKE
HYDROELECTRIC PROJECT
PART I -SELECTION OF GENERATION PLAN
2-1
2-2
2-3
3-1
3-2
3-3
4-1
4-2
4-3
4-4
4-5
LOAD FORECAST FOR KENAI PENINSULA
INDUSTRIAL DEVELOPMENTS AND ASSOCIATED LOADS FOR
CITY OF SEWARD
LOAD FORECAST FOR CITY OF SEWARD
EXISTING GENERATION RESOURCES ON KENAI PENINSULA
DETERMINATION OF CONSTANT RESERVE REQUIREMENT
ALLOCATION TO THE CITY OF SEWARD
DETERMINATION OF BRADLEY LAKE ALLOCATION TO CITY OF
SEWARD FOR USE IN ECONOMIC ANALYSIS
SUMMARY OF ECONOMIC ANALYSIS USING 20 YEAR PLANS
SUMMARY OF ECONOMIC ANALYSIS FOR GRANT LAKE EQUIVALENT
OPTIONS
FORECASTED PRICE OF COOK INLET GAS FOR USE IN ECONOMIC
ANALYSIS
COMPUTATION OF INTEREST DURING CONSTRUCTION FOR GRANT
LAKE HYDROELECTRIC PROJECT
OPTIMUM TIMING ANALYSIS FOR GRANT LAKE PROJECT
PART II -COOPER LAKE EXPANSION INVESTIGATION
5-1
5-2
STETSON CREEK DIVERSION -PREFEASIBILITY LEVEL COST
ESTIMATE SUMMARY
PTARMIGAN CREEK DIVERSION -PREFEASIBILITY LEVEL COST
ESTIMATE SUMMARY
PART III -DAVES CREEK -SEWARD TRANSMISSION LINE INVESTIGATION
10-1
10-2
2440B
COST ESTIMATE FOR DAVES CREEK -SEWARD TRANSMISSION
SYSTEM -115 KV
COST ESTIMATE FOR DAVES CREEK -SEWARD TRANSMISSION
SYSTEM -115 KV -DETAILS
v
9
2-5
2-6
2-7
3-10
3-11
3-12
4-24
4-25
4-26
4-27
4-28
5-9
5-10
10-2
10-3
Table
Number
LIST OF TABLES (Continued)
PART IV -FEASIBILITY ASSESSMENT OF GRANT LAKE HYDROELECIRIC PROJECT
12-1 ESTIMATE OF CONSTRUCTION COSTS FOR ALTERNATIVE
PROJECT ARRANGEMENTS 12-21
12-2 COMPARISON OF COST OF ENERGY FROM ALTERNATIVES 12-22
14-1 SUMMARY OF PERMEABILITY TESTS 14-22
14-2 CHARACTERISTICS OF SEISMIC SOURCES 14-23
15-1 MONTHLY INFLOWS FOR GRANT LAKE 15-12
15-2 COMPARISON OF 1982 GRANT CREEK FLOWS WITH LONG-TERM
AVERAGE FLOWS 15-13
15-3 FALLS CREEK/GRANT CREEK MONTHLY STREAMFLOW RATIOS 15-14
15-4 GRANT LAKE PROBABLE MAXIMUM STORM, 6-HOUR PRECIPITATION
AND TEMPERA1URE VALUES 15-15
16-1 DISTRIBUTION OF MONTHLY ENERGY CONSUMPTION FOR ANCHORAGE/
COOK INLET AREA AND CITY OF SEWARD 16-15
16-2 SUMMARY OF RESULTS OF POWER STUDIES PERFORMED FOR INTERIM
REPORT 16-16
16-3 SUMMARY OF RESULTS OF POWER STUDIES PERFORMED FOR
OPTIMIZATION OF LAKE TAP ALTERNATIVE 16-17
16-4 DETERMINATION OF OPTIMUM INSTALLED CAPACITY FOR
ALTERNATIVE D 16-18
16-5 COMPARISON OF ECONOMICS OF LAKE TAP ALTERNATIVE WITH AND
WITHOUT FALLS CREEK DIVERSION 16-19
18-1 SELECTED PROJECT ARRANGEMENT
SUMMARY OF PROJECT CAPITAL COST 18-6
18-2 SELECTED PROJECT ARRANGEMENT
DETAILED ESTIMATE OF CONSTRUCTION COST 18-7
18-3 ALTERNATIVE F DEVELOPMENT
DETAILED ESTIMATE OF CONSTRUCTION COST 18-14
vi
2440B
LIST OF FIGURES
Figure
Number Title Page
1-1 ANNUAL LOAD DURATION CURVE FOR THE ANCHORAGE AREAS 4-29
11-1 COOPER LAKE ALTERNATIVES -STETSON AND PTARMIGAN
CREEK DIVERSIONS 5-11
III-lONE-LINE DIAGRAM 10-8
111-2 PLAN -SEWARD TO MILEPOST 12, SHEET 10-9
111-2 PLAN -MILEPOST 13 TO MILEPOST 25, SHEET 2 10-10
111-2 PLAN -MILEPOST 26 TO DAVES CREEK SUB., SHEET 3 10-11
111-2 PLAN -SEWARD TO MARINE -INDUSTRIAL PARK
(WITH ELEVATION VIEWS), SHEET 4 10-12
111-3 TRANSMISSION LINE PROJECT SCHEDULE 10-13
IV-1 PROJECT LOCATION MAP 19-4
IV-2 GENERAL PROJECT AREA 19-5
IV-3 ALTERNATIVE PROJECT ARRANGEMENTS 19-6
IV-4 ALTERNATIVE A -GENERAL PROJEC1 ARRANGEMENT 19-7
IV-5 ALTERNATIVE B -GENERAL PROJECT ARRANGEMENT 19-8
IV-6 ALTERNATIVE C -GENERAL PROJECT ARRANGEMENT 19-9
IV-7 ALTERNATIVE 0 -GENERAL PROJECT ARRANGEMENT 19-10
IV-8 BORING PLOT PLAN 19-11
IV-9 DEPTH TO BEDROCK POWERHOUSE COVE 19-12
IV-10 REGIONAL GEOLOGIC MAP OF THE PROJECT AREA 19-13
IV-11 GEOLOGIC MAP ALONG TUNNEL ALIGNMENT SECTION 19-14
IV-12 TUNNEL -INTERPRETIVE GEOLOGIC CROSS SECTION 19-15
IV-13 CUMULATIVE DISTRIBUTION OF ROD VALUES, BOREHOLES
DH-3, DH-4 AND DH-5 19-16
IV-14 GRANT LAKE AREA -CAPACITY CURVES 19-17
vii
LIST OF FIGURES
Figure
Number Title
IV-15 FLOOD HYDROLOGY AND NATURAL OUTLET RATING CURVE
IV-10 MONTHLY STREAMFLOW DISTRIBUTION AND RESERVOIR
REGULATION
IV-17 SELECTED PROJECT ARRANGEMENT SITE PLAN
IV-18 POWER CONDUIT PLAN AND PROFILE
IV-19 GRANT LAKE CHANNEL EXCAVATION
IV-20 INTAKE AND GATESHAFT
IV-21 POWERHOUSE AREA PLAN AND PROFILE
IV-22 POWERHOUSE PLANS AND SECTIONS
IV-23 POWERHOUSE MAIN ONE LINE DIAGRAM
IV-24 ACCESS ROADS -TYPICAL SECTIONS
IV-25 FALLS CREEK DIVERSION WORKS -PLAN AND PROFILE
IV-20 FALLS CREEK DIVERSION DAM
IV-27 PROJECT SCHEDULE
viii
2440B
19 -18
19-19
19 -20
19-21
19-22
19-23
19-24
19-25
19-20
19-27
19-28
19 -29
19-30
;, 4111 II ; i
PART I
SELECTION OF GENERATION PLAN
1.0 INTRODUCTION
1.1 AUTHORIZATION
In August, 1981, Ebasco Services Incorporated (Ebasco) submitted a
proposal to the Alaska Power Authority (Power Authority) to perform a
detailed feasibility analysis and prepare a FERC License Application
for the Grant Lake Hydroelectric Project. The proposal was accepted by
the Power Authority and a contract for engineering services for the
study was executed in September 1981. An Interim Report (Ebasco, 1982)
was submitted in February 1982 in accordance with the terms of the
contract and with discussions with the Power Authority. The Interim
Report compared the reasonable alternative schemes for development of
the project, recommended one alternative for further study and
described the results of the field studies conducted to that time. The
comparison of alternatives in the preliminary studies permitted the
subsequent field studies to be designed specifically for the project
arrangement selected for further study.
This feasibility report of the Grant Lake Hydroelectric Project
describes the field studies that were conducted to investigate the
feasibility of the project and presents the results of these field and
office studies, in accordance with the terms of the contract and the
discussions with the Power Authority which have occurred during the
course of the study.
Two modifications to the scope of work were executed during the study
period. The first modified the field study program to more
specifically apply to the project alternatives recommended for further
investigation in the Interim Report. The second modification added a
review of the potential for expansion of the existing Cooper Lake
Hydroelectric Project, an investigation of the need for and cost of
upgrading and/or replacing the existing transmission line serving the
City of Seward, and provided for additional environmental studies if
required. The changes to the scope of work in the second modification
to the contract resulted from concerns expressed by the City of Seward
over their future power supply.
1-1
26758
1.2 BACKGROUND TO PRESENT STUDIES
The earliest published investigation of the project area is a geologic
report and map of the Kenai Peninsula by Martin et al. in 1915. More
detailed studies were performed in the early to mid 1950s, with the
topographic mapping of Grant Lake and Grant Creek by Giles, the
publication of a preliminary study of a proposed hydroelectric
development at Grant Lake by R.W. Beck and Associates (Beck, 1954), the
publication of the results of geologic investigations at the site by
the U.S. Geological Survey, and finally, the filing of an Application
to the Federal Power Commission for a Preliminary Permit for the
project by Chugach Electric Association in 1959. The above studies did
not result in the construction of the project, probably due to the low
cost of energy from alternative sources during this period.
After a period of intermittent interest in the development of the
project, there has been a recent (late 1970 1 s) increase in interest
resulting from the energy shortage and the major upset in the price of
fossil fuels, notably petroleum products. The most recent studies have
been a Reconnaissance Study of Hydroelectric Power Alternatives for the
City of Seward, Alaska (CH2M Hill, 1979) and a Feasibility Assessment
of Hydropower Development at Grant Lake (CH2M Hill, 1980). The latter
report contains an assessment of the cost of power from alternative
sources and a review of alternative hydroelectric projects that were
available to meet the projected needs of Seward. This essentially was
an office study and did not include any field investigations of either
a geotechnical or environmental nature. Reconnaissance level
investigations were performed on several development alternatives.
These included development of Crescent Lake, Grant Lake, Ptarmigan Lake
and a combination development of Grant Lake and Ptarmigan Lake (see
Figure IV-l). Based on environmental and economic considerations,
Grant Lake plus the diversion of nearby Falls Creek into Grant Lake was
selected as the most economical and environmentally acceptable. It was
concluded that the Grant Lake project showed sufficient feasibility to
justify undertaking more detailed feasibility investigations.
1-2
2675B
The Power Authority has accepted the 1980 CH2M Hill report as adequate
to meet its needs for a reconnaissance-level evaluation of alternative
energy sources for the City of Seward. The Power Authority's focus in
the present study is on the development of the Grant Lake project to
meet the need for power on the Kenai Peninsula in conjunction with
other proposed resource developments and to specifically evaluate the
development of the project to meet the future power requirements of the
City of Seward.
The study is a detailed feasibility investigation of the project,
including subsurface geotechnical and environmental investigations,
surveying and mapping, and hydrological data collection in the project
area. The studies are of sufficient detail to support an application
for a license to the FERC should the Power Authority proceed with the
project.
1-3
2615B
2.0 FORECASTED POWER REQUIREMENTS
2.1 GENERAL
The Power Authority project evaluation procedure compares the total
present worth cost of a base case plan to the total present worth cost
of one or more alternative plans for meeting a forecasted requirement
for power in a specific area for a given planning period. One or more
of the alternative plans will include the proposed new generation
project under consideration. The plan having the lowest total present
worth cost is the most economic plan under this procedure. Two key
elements in this procedure are the electrical demand and energy
forecast for the area and the definition of the area to be considered
for utilization of the proposed new generation resource.
In determining the area to be served and the electrical load forecast
to be used in the economic feasibility studies for the Grant Lake
project, it was recognized that the project is located only 25 miles
from the City of Seward load center and that Seward is the southern
terminus of a developing interconnected electric system encompassing
the entire Railbelt area. Located throughout the Railbelt are a number
of existing and proposed electrical generating plants and load
centers. In discussions with the Power Authority, it was decided that
the economic evaluation of the Grant Lake Project should be based on
comparison of a base case plan and alternative plans for meeting the
forecasted power requirements for the City of Seward. It was also
decided that a second type of economic evaluation would be included
which involves a regional comparison of the cost of power from the
Grant Lake Project with other generating resources being considered to
serve the Anchorage-Cook Inlet area, particularly those serving the
Kenai Peninsula. This regional comparison, however, did not require a
load forecast, since the analysis involves only a comparison of the
cost of power from several proposed generation resources.
2-1
26768
2.2 KENAI PENINSULA DEMAND AND ENERGY FORECAST
A number of forecasts of the power requirements for the Kenai Peninsula
have been made. In 1980, a load forecast of utility requirements for
the Railbelt was prepared by the University of Alaska's Institute of
Social and Economic Research (ISER, 1980), which included a forecast
for the Kenai Peninsula. The ISER forecast was utilized, with some
modifications, in the Bradley Lake Project Power Market Report (Alaska
Power Administration, 1982) and the Kenai Peninsula Power Supply and
Transmission Study (Beck, June 1982).
The most comprehensive recent forecast is contained in the Railbelt
Electric Power Alternatives Study: Evaluation of Railbelt Electric
Energy'Plans (Battelle, 1982). The forecast incorporated a number of
population projections and economic scenarios for both the public and
private sectors. The Supplement -Kenai Peninsula Power Supply and
Transmission Study (Beck, December 1982) used the low economic
scenario, Plan lA from the Battelle report, to re-evaluate the
alternative plans for power generation and transmission facilities for
the Kenai Peninsula. The Battelle forecast was modified in the Beck
report to incorporate a portion of potential military and industry
power requirements that are currently met by military and industrial
generation facilities. The energy forecast is of utility sales only
and, therefore, does not include utility usage and losses. In
addition, the Beck report separated the combined Greater Anchorage-Cook
Inlet load in the Battelle report into separate forecasts for the
Greater Anchorage and the Kenai Peninsula areas. The Beck power supply
study also assumed a requirement for reserves for the Railbelt region
of 200 MW, based on the coincidental outage of the two largest
generation units in the Anchorage area.
The load forecast for the Kenai Peninsula, including the modifications
and adjustments made in the Beck study, is used herein as a basis for
allocation of the required resources, including reserves for the Kenai
Peninsula to the City of Seward in the economic analysis in the
subsequent sections of this report. Utilization of this load forecast
2-2
2676B
was made in accordance with discussions with the Power Authority, and
it is considered to be the most applicable available forecast of power
requirements for the Kenai Peninsula. This load forecast demand for
the Kenai Peninsula is shown on Table 2-1.
2.3 SEWARD AREA DEMAND AND ENERGY FORECAST
For the past 25 years, the City of Seward has obtained its power by
purchase from Chugach Electric Association via a 24.9 kV transmission
line from a 115/24.9 kV substation at Daves Creek, some 48 miles north
of the City. Peak demand for the City occurred in 1979 at 6.7 MW, as
reported in Analysis of Voltage Drop and Energy Losses, (Dwane Legg
Associates, 1~82); however, recent years have shown a lower, but
steadily growing power demand. Peak demand grew at an average annual
rate in excess of 10 percent per year from 1967 to 1980. Since 1980,
demand has grown at a lower rate. Likewise, the maximum annual energy
requirement has experienced a steady growth with 25 Gwh consumed in
1981. Current developments in the Seward area, primarily a
marine-industrial park on the east side of Resurrection Bay near the
Fourth of July Creek, developments in and near the small boat harbor,
and infrastructure to support these developments, could result in
sUbstantial increase in the power requirements in the next few years.
No adequate load forecast for a 20 year planning period was found to
exist for the City of Seward Electric System. In the Kenai Peninsula
Power Supply and Transmission Study (Beck, June 1982), a forecast for
Seward is developed based on Seward's historical share of the total
power requirements for the Kenai Peninsula. This forecast, which is
based on a forecast prepared in June 1980 by the University of Alaska,
Institute of Social and Economic Research, does not consider the
potential for larger incremental growth in Seward resulting from the
current industrial developments nor does it reflect the decrease in the
rate of growth experienced subsequent to its formulation. Table 2-2
shows the industrial developments which are either currently under
construction or are planned for construction in the near future.
2-3
2676B
A forecast for the City was. therefore. developed for use in the Grant
Lake feasibility study which utilizes the most recent (1981 and 1982)
historical data and future rates of growth equal to those used in the
Supplement -Kenai Peninsula Power Supply and Transmission Study (Beck.
December 1982). As noted above. this forecast was developed from the
low economic scenario. Plan 1A in the Railbe1t Electric Power
Alternatives Study: Evaluation of Rai1be1t Electric Energy Plans
(Battelle. 1982).
Three load forecasts were prepared. which are shown on Table 2-3. The
low demand forecast was developed by using historical data from Seward
for 1981 and 1982 for demand. and then applying the same rates of
growth to demand for years 1983-2001 as were used in the Supplement -
Kenai Peninsula Power Supply and Transmission Study (Beck. December
1982). The low demand forecast assumes no incremental growth in power
requirements from the planned industrial developments in Seward. The
low energy forecast also has the same growth rate for 1983 to 2001 as
shown in the December 1982 Beck study. The medium demand forecast
assumes those projects under construction will be completed and one
half of those projected to be built will add a load increment to the
system in 1983 and 1984. with the growth rate from 1985-2001 the same
for the low forecast. The high demand forecast assumes all those
industrial projects currently under construction and all projected
industrial projects will add a load increment to the system in 1983 and
1984 with the growth rate from 1985 -2001. the same as for the low
forecast. In other words. for all three forecasts, loads beyond 1984
were assumed to grow at the average annual rates of growth projected in
the December 1982 Beck study for the entire Kenai Peninsula.
It was agreed with the Power Authority that the economic evaluation of
the Grant Lake Project will be conducted using the medium growth
forecast developed herein. and the low and high growth forecasts will
be used to evaluate the sensitivity of the analysis to varying rates of
growth.
2-4
2676B
TABLE 2-1
LOAD FORECAST FOR KENAI PENINSULA1I
Peak
Demand Energy
Year (MW) (GWH)
1983 82 397
1984 84 408
1985 86 419
1986 B9 433
1987 92 447
1988 94 462
1989 97 476
1990 100 490
1991 102 499
1992 104 508
1993 106 517
1994 108 526
1995 110 535
1996 111 542
1997 112 549
199B 114 555
1999 115 562
2000 116 568
2001 119 581
2002 122£1 594?/
11 For years 1983-2001, load forecast is obtained from Supplement to
Kenai Peninsula Power Supply and Transmission Study (Beck,
December 1982).
£1 Load growth from 2001 to 2002 is assumed to be the same as from
2000 to 2001.
2-5
2676B
Year
1983
TABLE. 2-2
INDUSTRIAL DEVELOPME.NTS AND ASSOCIA1E.D LOADS
FOR CI1Y OF SEWARDll
lype of Development
State Grain Terminal (In Construction)
AVTlC Center~1 (In Construction)
Fourth of July Shiplift (In Construction)
Fourth of July Industrial Development (Projected)
Infrastructure -Residential and Light
Commercial (Projected)
Total in Construction ~ 2.95 MW
Total Projected = 4.0 MW
Peak load
(MW)
1.0
.75
1 .20
2.0
2.0
1984 Gateway Subdivision (Scheduled for 1983
construction season) 1.5
Fourth of July Industrial Development (Projected) 6.0
Infrastructure -Residential and Light
Commercial (Projected) 3.0
Total Projected 10.5 MW
1 I All data obtained from the City of Seward.
21 Alaska Vocational Technical Education Center.
2-6
2676B
TABLE 2-3
LOAD FORECAST FOR
CITY OF SEWARD
Peak Demand (MW} Energy (GWH}
Year Lowll MediumV High~/ Low1/ Medium~/ Hi gh~/
1981 §./ 5.2 5.2 5.2 27.1 27.1 27.1
1982§./ 5.7 5.7 5.7 29.1 29.1 29.1
1983 5.9 9.6 11. 1 29.9 48.7 56.3
1984 6.0 13.8 20.4 30.7 70.6 104.4
1985 6.2 14.2 21.0 31. 5 72.5 107.2
1986 6.4 14.6 21.6 32.5 74.8 11 O. 7
1987 6.6 15. 1 22.3 33.6 77 .2 114.2
1988 6.8 15.6 23.0 34.6 79.7 117.9
1989 7.0 16.0 23.7 35.8 82.2 121 .6
1990 7.2 16.5 24.5 36.9 84.9 125.5
1991 7.4 16.9 24.9 37.6 86.4 127.8
1992 7.5 17.2 25.4 38.2 88.0 130.1
1993 7.7 17.5 25.9 38.9 89.5 132.4
1994 7.8 17 .8 26.4 39.6 91 .2 134.8
1995 7.9 18.2 26.9 40.3 92.8 137.3
1996 8.0 18.4 27.2 40.8 93.9 138.9
1997 8.1 18.6 27.5 41. 3 95.0 140.6
1998 8.2 18.8 27.8 41.8 96.2 142.3
1999 8.3 19.0 28.1 42.3 97.3 144.0
2000 8.4 19.2 28.4 42.8 98.5 145.7
2001 8.6 19.7 29.1 43.8 100.8 149.0
2002 8.8 20.2 29.9 44.8 103.1 152.5
1/ Low forecast assumes no load growth from industrial development
(both under construction and planned) in Seward area as shown on
Table 2-2. This forecast has the same growth rates as that shown in
the Supplement -Kenai Peninsula Power Supply and Transmission Study
(Beck, December 1982), except that 1981 and 1982 show actual
historical data.
£/ Medium forecast assumes all industrial projects in Seward area which
are currently under construction will be completed and one-half of
the planned industrial projects will be completed (see Table 2-2 for
list of industrial projects and associated loads).
2-7
2676B
Footnotes (Continued)
TABLE 2-3 (Continued)
LOAD FORECAST FOR
CITY OF SEWARD
11 High forecast assumes all industrial projects currently under
construction in the Seward area will be completed and all planned
projects will also be completed (see Table 2-2 for list of
industrial projects).
il Low energy forecast has the same growth rate as that shown in
Supplement -Kenai Peninsula Power Supply and Transmission Study
(Beck, December 1982), except that the energy for 1981 and 1982 has
been adjusted for the difference in peak demand in the Beck forecast
and the actual historical peak loads from the City.
il For the medium and high energy forecasts for the years 1983 and
1984, the energy required is estimated by using the same load
factors as used in the low forecast for these years. For the years
beyond 1984, the medium and high forecasts have grown at the energy
growth rates given in the Supplement -Kenai Peninsula Power Supply
and Transmission Study (Beck, December 1982).
~I Peak demand values are historical data for City of Seward.
2-8
2676B
3.0 GENERATION PLANS IDENTIFIED
3.1 GENERAL
Five generation plans have been identified which would satisfy the
forecasted energy and demand requirements for the next 20 years for the
City of Seward. After 20 years the demand and energy are assumed to
remain constant until 2037, the end of the Grant Lake Project economic
life. These plans include:
1) a Base Case Plan which involves continued use of existing
simple cycle and new combined cycle natural gas-fired
generation units on the Kenai Peninsula with no new
hydroelectric project included, referred to herein as Base
Case Plan I;
2) an alternative plan that includes the proposed Grant Lake
Hydroelectric Project with the remaining power requirements
being provided by existing and new gas-fired generation
facilities, referred to herein as Alternative Plan 1-1;
3) an alternative plan that includes a portion of the proposed
90 MW Bradley Lake Hydroelectric Project, with the remaining
power requirements being provided by existing and new
gas-fired generation units, referred to herein as Alternative
Plan 1-2;
4) an alternative plan that includes a portion of the alternative
135 MW Bradley Lake Hydroelectric Project and the Anchorage
Soldotna Intertie, with the remaining power requirements being
provided by existing and new gas-fired generation units,
referred to herein as Alternative Plan 1-3; and
3-1
5605B
5) an alternative plan that includes a portion of the Sustina
Project with the pre 1993 power requirements being provided by
existing and new gas-fired generation units, referred to
herein as Alternative Plan 1-4.
The evaluation period for each of the plans begins in 1983 and extends
for 55 years through 2037, since the economic life of the proposed
Grant Lake Hydroelectric Project is 50 years and the optimum timing for
bringing the project on line is January 1988 (5 years from January
1983). Each of the plans are described in more detail below and the
economic comparison of the plan is shown in Section 4.0.
In addition to the five basic plans for meeting the entire projected
needs for the City of Seward, five direct comparisons with the Grant
Lake capacity and energy output were made. Each direct comparison plan
would provide 24.94 GWh of net energy to Seward. Furthermore, using
capacity adjustments based on equivalent thermal capacity, each direct
comparison is equal to providing 6.55 MW of capacity to Seward. The
designation for these alternatives is distinguished from the detailed
20 year plan studies by preceding each alternative with the Roman
numeral "II".
In summary the five direct comparison alternatives include:
1) new combine cycle combustion turbines, herein referred to as
Base Case Plan II;
2) the Grant Lake Hydroelectric Project, herein referred to as
Alternative 'Plan 11-1;
3) the 90 MW Bradley Lake Project with an appropriate capacity
adjustment factor;
3-2
5605B
4) the 135 MW Bradley Lake Project and Anchorage-Soldotna
Intertie with an appropriate capacity adjustment factor. and
5) the Susitna Hydroelectric Project based on cost of energy with
an appropriate capacity adjustment factor.
3.2 BASE CASE PLAN 1
The Base Case Plan 1 was developed to identify the most economical
means of meeting Seward's need for power. assuming the Grant Lake
project was not built. Based on discussions with the Power Authority.
the Base Case Plan 1 was defined as a combination of existing and new
natural gas-fired generation facilities located on the Kenai Peninsula
which is comparable to a continuation of existing means of providing
power.
Although the purpose of the Base Case Plan 1 is to address Seward's
requirements. the Plan begins with a development of loads and resources
for the Kenai Peninsula (as do Alternative Plans 1-1 and 1-2). This
approach is required to provide a basis for assigning portions of new
plant costs. plant retirements. and reserve requirements to the Seward
market area since the basic data from which the comparsion data is
taken is based on meeting the entire Kenai load.
The Base Case Plan 1 is comprised of the following three components:
Component 1 New combined-cycle combustion turbine units on the Kenai
Peninsula (in the Kenai-Nikiski area) for satisfying new
capacity addition requirements. All new capacity
additions in the Base Case Plan 1 will be provided by new
combined-cycle combustion turbine units because these
units are considered to be the most economical form of
new thermal generation.
3-3
Component 2 Continued used of gas-fired generation from the existing
simple cycle combustion turbines at Bernice Lake on the
Kenai Peninsula until the units are retired. These
existing generation resources are listed on Table 3-1.
No new simple cycle combustion turbine units are assumed
to be built to satisfy required capacity additions, as
simple cycle combustion turbines are not as economical as
new combined-cycle combustion turbine units. The last
existing simple cycle combustion turbine unit is retired
in the year 2002.
Component 3 The proposed Daves Creek-Seward 115 kV transmission
line. The Daves Creek-Seward transmission line is a
nongeneration component of the Base Case Plan I which has
been included because several studies, City of Seward
Electrical System Planning System (CH 2M Hill, August
1979), and the Analysis of Voltage Drop and Energy Loses
(Duane Legg Associates, October 1982), have indicated
that the existing 24.9 kV transmission line that extends
from the Daves Creek substation to the Seward substation
will have to be replaced, and that it is cost effective
to replace the line with a new 115 kV transmission line
as soon as possible. A feasibility-level assessment of
the upgrading and replacement of the Daves Creek-Seward
transmission line is provided in Part III of this report.
The existing 5.5 MW of diesel capacity owned and operated by the City
of Seward is not included in the Base Case Plan I or any of the
alternative plans because the cost to operate these units ;s greater
than the cost of providing generation from either simple cycle or
combined-cycle gas-fired turbines. Furthermore, the diesel generators
are old and are not even considered appropriate for meeting Seward's
reserve requirements. Also, as a simplifying assumption, the City's
Mount Marathon 150 kW hydro project, and Chugach Electric Association's
15 MW Cooper Lake Hydroelectric Project were not included in the
existing resource mix serving Seward.
3-4
The demand and energy forecasts for the Kenai Peninsula and for the
City of Seward which are used in the Base Case Plan I and alternative
plans are described in Section 2.0 of this report. The load forecast
used for the Kenai Peninsula was obtained from the Supplement -Kenai
Peninsula Power Supply and Transmission Study (Beck, December 1982).
The load forecast used for Seward in the Base Case Plan I is the medium
growth scenario described above in Section 2.0, with sensitivity
analyses being performed using the high and low growth scenarios.
The assignment of reserve requirements to the Kenai Peninsula is based
on taking the 200 MW reserves used in the Beck report for the entire
Railbelt region and proportioning that total amount by the average
ratio of the Kenai Peninsula load to the Railbelt load for each year of
the 55 year evaluation period. The 200 MW reserve requirement is based
on the coincidental outage of the two largest generation units in
Anchorage. As the Railbelt becomes more fully and reliably
interconnected, reserve requirements may become lower. However, the
200 MW value was considered appropriate for purposes of proportioning
reserve requirements for the Kenai Peninsula and the City of Seward in
this study. Based on the proportioning procedures described above, the
resulting constant reserve requirement for the Kenai Peninsula is 28.1
MW. Seward's share of the Kenai Peninsula reserve requirements is
based on the average ratio of the Seward load to the Kenai Peninsula
peak load over the 55 year evaluation period and was calculated to be a
constant 4.6 MW. The derivation of these reserve requirements is shown
on Table 3-2. These values are also used in Alternative Plans I in the
economic analysis. In all plans, reserve requirements are met by
simple cycle generation units from 1983 through 1987, and from 1988 on,
reserves are met with new combined cycle units.
The procedure for sizing new combined-cycle units was to add capacity
in approximately 25 MW increments in a manner such that a deficit never
occurs, while at the same time minimizing the occurrence of surplus
capacity to less than 25 MW, for the Kenai Peninsula. The last unit is
added such that a zero surplus exists from 2002 through 2037. Seward IS
3-5
5605B
capital cost for new combined-cycle generation facilities is computed
on $/kW basis, with the assumption that Seward will be paying for a
portion of a larger, new plant located in the Kenai-Nikiski area. The
estimated costs for both simple and combined-cycle units, and a
tabulation of capacity additions and retirements for the Base Case Plan
I are provided in Part III of the Technical Appendix.
3.3 GENERATION PLAN WITH GRANT LAKE PROJECl (ALTERNATIVE PLAN 1-1)
The generation plan with the Grant Lake Project assumes that a 7,000 kW
hydroelectric project at Grant Lake will come on-line in early January
1988. As discussed in Section 16.0, optimization studies performed for
the project determined that net benefits were maximized at an installed
capacity of 7,000 kW, where the value of the benefits was based on the
cost of providing alternative gas-fired generation facilities. As
indicated in Section 4.4, a project timing analysis showed that the
optimum on-line date is 1988.
In the generation plan with the Grant Lake Project, power from the
hydroelectric project is assumed to displace energy and capacity that
would otherwise be generated from gas-fired units included in the Base
Case Plan I. The available dependable capacity from the Grant Lake
Project is assumed to displace the need for adding the same amount of
new combined-cycle capacity. Details of the procedure for allocation
of energy generation between the Grant Lake Project and gas-fired units
are provided in Section 4.3.9.
Alternative Plan 1-1, then, is comprised of the following components
(it should be noted that the numerical order of the components in this
and the following plan descriptions are arbitrary and bear no
relationship to the priority which may exist for the actual development
and construction of any component):
3-6
5605B
Component 1 The 7 MW Grant Lake Project, with an on-line date of
January 1988.
Component 2 New combined-cycle combustion units on the Kenai
Peninsula for satisfying capacity requirements which
cannot be met by existing units and the Grant Lake
Project.
Component 3 Continued use of gas-fired generation from existing
simple-cycle combustion turbines as described above for
the Base Case Plan I.
Component 4 Daves Creek-Seward 115 kV transmission line
(non-generation component).
3.4 GENERATION PLAN WITH BRADLEY LAKE PROJECT
(ALTERNATIVE PLANS 1-2 AND 1-3)
Two alternative generation plans were developed that includes a portion
of the proposed Bradley Lake Hydroelectric Project, which is located on
the Kenai Peninsula and is being evaluated by the Power Authority.
Costs and information on Bradley Lake were taken from the Bradley Lake
Hydroelectric Power Project Feasibility Study. published in October of
1983 by Stone & Webster for the Alaska Power Authority. The purpose of
this plan is to show the effect on the economics of Grant Lake of
including a portion of a large scale hydro project in the resource mix
for Seward. This plan is the same as the Base Case Plan I except that
a portion of the Bradley Lake Project at two different levels of
development is added to the resource mix serving the City of Seward.
The portion of Bradley Lake which would be allocated to the City of
Seward has not been designated by the Power Authority. For the purpose
of this study the portion of the project to be assigned to Seward was
determined by taking the average ratio of Seward's peak load to the
combined peak load for the Greater Anchorage area and the Kenai
Peninsula area. The analysis assumes that the installed capacity of
3-7
5605B
Bradley Lake will be 90 MW and 135 MW for the respective case. The
projected project on-line date of October 1988 has been rounded back to
January 1988 for ease of direct economic comparison with the Grant Lake
Project. The resulting portion of Bradley Lake capacity that goes to
Seward is 4.02 MW for the 135 MW project. Table 3-3 shows the
derivation of this value. The 90 MW project share allocated to Seward
is proportional to the value computed in Table 3-3 or 2.68 MW.
Component 1 A 2.68 MW share of the 90 MW Bradley Lake Project for
Alternative Plan 1-2, or a 4.02 MW portion of the 135 MW
Bradley Lake Project and share of the Anchorage-Soldotna
Intertie for Alternative Plan 1-3, assumed to come
on-line in 1988.
Component 2 New combined-cycle combustion turbine units on the Kenai
Peninsula for satisfying capacity requirements which
cannot be met by the Grant Lake Project, the Bradley Lake
Project, or the existing gas turbine units.
Component 3 Continued use of gas-fired generation from existing
simple-cycle combustion turbines at Bernice Lake, as
described above for the Base Case Plan 1.
Component 4 The Daves Creek-Seward 115 kV transmission line
(non-generation component).
3.5 GENERATION PLAN WITH SUSITNA PROJECT
(ALTERNATIVE PLANS 1-4)
An alternative generation plan was developed that includes a portion of
the proposed Susitna Hydroelectric Project, which is located on the
Susitna River near Talkeetna and is being evaluated by the Power
Authority. The purpose of this plan is to show the effect on the
economics of Grant Lake of meeting all of Sewards energy requirements
from the Susitna Project once the project is online. This plan is the
3-8
5605B
same as the Base Case 1 until 1992. The portion of the Sustina Project
which would be allocated to the City of Seward varies on a year to year
basis to match load growth (energy) in the City of Seward. When
surplus or deficit capacity exists, a capacity adjustment is made which
is equal to the equivalent value of thermal capacity. Because the cost
of energy from the Susitna Project varies with utilization, the cost of
the project must be based on an annuity with the same effective present
worth as actual cashflows for the year in which they occur. Because
this approach is computationally (not economically) different from the
other components only the cost of energy (with an appropriate capacity
adjustment) is included in the detailed economic study tables. The
derivation of the cost of energy from the Sustitna Project is included
as Table 111-24 in the Technical Appendix.
The components which comprise Alternative Plan 1-4 are:
Component 1 Seward's energy requirements met entirely by the Susitna
project from 1993 on.
Component 2 New combined-cycle combustion turbine units on the Kenai
Peninsula for satisfying capacity requirements which
cannot be met by the existing gas turbine units.
Component 3 Continued use of gas-fired generation from existing
simple-cycle combustion turbines at Bernice Lake, as
described above for the Base Case Plan 1.
Component 4 The Daves Creek-Seward 115 kV transmission line
(non-generation component).
3~
5605B
TABLE 3-1
EXISTING GENERATION RESOllRCES ON KENAI PENINSULAll
Generation
Resource
Bernice Lake 1
Bernice Lake 2
Berni ce Lake 3
Bernice Lake 4
Cooper Lake
Seward Combined
Owner Type
CEA NGT
CEA NGT
CEA NGT
CEA NGT
CEA Hydro
SES Diesel
NGT = Natural gas-fired combustion turbine
CEA = Chugach Electric Association
SES City of Seward Electric System
Capacity
(MW)
8.85
18.95
24.3
24.3
15.0
5.5
Retirement
Year?J
1983
1992
1998
2002
2011
11 Data are from the Alaska Power Administration's Bradley Lake
Project Power Market Report, January 1982. List does not include
City of Seward's Mount Marathon 150 kW hydroproject or any
industry-supplied generation facilities.
£1 Retirement dates based on economic life of facility as defined in
APA's economic analysis parameters for FY 1983 (20 years for
gas-fired combustion turbines, 50 years for hydroelectric projects).
3-10
56058
TABLE 3-2
DETERMINATION OF CONSTANT RESERVE REQUIREMENT ALLOCATION TO CITY OF SEWARD
RAILBELT RESERVE REQUIREMENTS: 200 MW
Kena i Peak Ra il bel t Peak Kenai Peak: Kenai Share of Seward Peak Seward Peak: Seward Share of
Year Load (MW) Load (MW) Railbel t Peak (% ) Res erve s (MW) Load (MW) Kena i Peak (%) Reserves (MW)
1983 82 590 13.90 27.80 9.6 11.71 3.25
1984 84 610 13.77 27.54 13.8 16.43 4.52
1985 86 630 13.65 27.30 14.2 16.51 4.51
1986 89 665 13.38 26.77 14.6 16.40 4.39
1987 92 702 13.11 26.21 15.1 16.41 4.30
1988 94 736 12.77 25.54 15.6 16.60 4.24
1989 97 773 12.55 25.10 16.0 16.59 4.14
1990 100 808 12.38 24.75 16.5 16.50 4.08
1991 102 816 12.50 25.00 16.9 16.57 4.14
1992 104 824 12.62 25.24 17 .2 16.54 4.17
1993 106 832 12.74 25.48 17 .5 16.51 4.21
1994 108 840 12.86 25.71 17 .8 16.48 4.24
1995 110 848 12.97 25.94 18.2 16.55 4.29
1996 111 842 13.18 26.37 18.4 16.58 4.37
1997 112 837 13.38 26.76 18.6 16.61 4.44
1998 114 832 13.70 27.40 18.8 16.49 4.52
1999 115 827 13.91 27.81 19.0 16.52 4.59
2000 116 821 14.13 28.26 19.2 16.55 4.68
2001 119 832 14.30 28.61 19.7 16.55 4.74
2002 122 843 14.47 28.94 20.2 16.56 4.79
Average
1983-2037 115.019 817.963 14.04 28.09l! 18.9574 16.45 4.62.Y
1/ Used as constant reserve requirement for Kenai Peninsula in 20 year plans.
2/ Used as constant reserve requirement for City of Seward in 20 year pl ans.
3-11
TABLE 3-3
DETERMINATION OF BRADLEY LAKE ALLOCATION TO CITY OF SEWARD
FOR USE IN ECONOMIC ANALYSIS
BRADLEY LAKE INSTALLED CAPACITY: 135 MW
Kenai Peak Anchorage Peak Kenai Plus Kenai Peak: Kenai Share Seward Peak Seward Peak: Seward Share of
Year Load (MW) Load (MW) Anchorage (MW) Sum Peak (%) of Bradl ey (MW) Load (MW) Kena i Peak (%) Bradl ey (MW)
1983 82 370 452 18.14 0.0 9.6 11.71 0.0
1984 84 380 464 18.10 0.0 13.8 16.43 0.0
1985 86 390 476 18.07 0.0 14.2 16.51 0.0
1986 89 403 492 18.09 0.0 14.6 16.40 0.0
1987 92 417 509 18.07 24.40 15.1 16.41 4.00
1988 94 430 524 17.94 24.22 15.6 16.60 4.02 w 1989 97 444 541 17 .93 24.21 16.0 16.59 3.99 I ...... 1990 100 457 557 N 17.95 24.24 16.5 16.50 4.00
1991 102 465 567 17 .99 24.29 16.9 16.57 4.02
1992 104 474 578 17.99 24.29 17.2 16.54 4.02
1993 106 482 588 18.03 24.34 17.5 16.51 4.02
1994 108 491 599 18.03 24.34 17 .8 16.48 4.01
1995 110 499 609 18.06 24.38 18.2 16.55 4.03
1996 111 505 616 18.02 24.33 18.4 16.58 4.08
1997 112 512 624 17 .95 24.23 18.6 16.61 4.02
1998 114 518 632 18.04 24.35 18.8 16.49 4.02
1999 115 525 640 17.97 24.26 19.0 16.52 4.01
2000 116 531 647 17.93 24.20 19.2 16.55 4.01
2001 119 543 662 17.98 24.27 19.7 16.55 4.02
2002 122 555 677 18.02 24.33 20.2 16.56 4.03
Average
1988-2037 118 537.12 655.12 18.01 24.31 19.53 16.55 4.02
4.0 EVALUATION OF GENERATION PLANS
4.1 GENERAL
Each of the five basic generation plans described in Section 3.0 for
meeting the City of Seward's forecasted energy and demand requirements
were evaluated using both economic and environmental criteria. The
economic analysis was perfonmed using the Power Authority's project
evaluation procedure which provides a comparison of the cumulative
present worth cost of the plans. The environmental evaluation provides
a comparison of the major impacts of each project. Based on a
comparison of the economics and the environmental considerations of
each of the plans, a recommended generation plan was selected.
4.2 METHODOLOGY AND ASSUMPTIONS FOR ECONOMIC ANALYSIS
4.2.1 Basic Assumptions
The criteria and basic assumptions for performing the economic analysis
were based on the Power Authority's project evaluation procedure, on
economic analysis parameters for fiscal year 1983 provided by the Power
Authority, and on specific discussions with the Power Authority
regarding the feasibility analysis for the Grant Lake Project. The
assumptions used were as follows:
1. Inflation rate of 01 (constant dollars assumed).
2. Real (inflation-free) discount rate of 3.5%.
3. Natural gas prices are forecasted marginal prices escalated at the
rates developed in the Sherman Clark No Supply Disruption Case
(NSO) developed for the Susitna Hydroelectric Project (APA, Susitna
License Application, 1983). Sensitivity analyses using marginal
prices at 01 escalation and melded prices (includes impacts of
4-1
current gas contracts) at 0% and Sherman Clark NSD escalation were
performed. These values are summarized in Table 4-3. A total of 23
cases were investigated in the analyses. (See Part IV of the
Technical Appendix for detailed discussion of gas prices).
4. Forecasted electrical energy and demand requirements from the
medium load growth scenario described in Section 2.0, with
sensitivity analyses being performed using high and low growth
scenarios.
5. The total period of evaluation for the economic analysis is 55
years (1983 through 2037).
6. The economic life for simple-cycle gas-fired combustion turbines is
20 years.
7. The economic life for combined-cycle gas-fired combustion turbines
is 30 years.
8. The economic life of a hydroelectric project is 50 years.
9. The economic life of transmission lines with wood poles is 30 years
and the economic life of transmission lines w1th steel towers is 40
years.
10. The capital cost for construction of new generation facilities are
overnight costs which consist of project bid pr1ce estimates
without escalation during construction. All capital costs are
expressed in January 1983 dollars. Interest during construction is
included.
11. Estimated construction and operation and ma1ntenance costs obtained
from other sources for the Bradley lake project are escalated to
January 1983 dollars by -0.&&% for July 1983 to January 1983 (USBR
Composite Index, September, 1983). Estimated construction and
4-2
operation and maintenance costs obtained from other sources for
gas-fired generation facilities are escalated to January 1983
dollars by 71 for calendar year 1982. The 71 escalation was based
on the economic analysis parameters issued by the Alaska Power
Authority on July 1, 1982. Subsequent to Ebasco's development of
thermal prices an additional memo was issued on May 31, 1983 by APA
which directed the use of 4.31 escalation for hydro projects. The
original 71 escalation was retained for thenma1 plants based on
ENR's Quarterly Cost Roundup published June 23, 1983 which states
that 'Cost hikes for fossil plants slowed 3.31 last year to a 6.81
annual rate of increase.' (p. 66).
12. The total annual cost for a given year in any plan is the sum of
all capital and interest costs which occur in that year plus all
annual operation and maintenance cost plus any fuel cost.
13. The total cost of any plan is obtained by discounting the annual
cost for each year of the plan to 1983 using a discount rate of
3-1/21 and summing the present worth cost of each year.
14. The within year present worth is always preserved at January 1st
levels. Therefore, cashflow which occurs later in the year is
disounted back to January 1. Interest during construction is
discounted in the same manner. Actual cashflows developed for
Grant Lake and the Daves Creek-Seward Transmission Line are used in
assessing those projects. For the other projects a unifonm
(linear) cashf10w is assumed where the same amount is expended each
quarter.
4.2.2 Interest During Construction
Interest during construction is the interest paid on funds borrowed to
undertake construction during the construction period. Obviously there
are no revenues from the project during this period and hence the
4-3
interest paid on these funds represents an additional cost which must
be amortized over the life of the project. The amount of interest
during construction is controlled by four factors as follows:
1) The discount rate which serves as the interest rate in an
economic analysis.
2) The cash flow during the project construction period.
3) The assumed date the funds are borrowed.
4) The assumed date of the construction contractor progress
payments.
An economic analysis generally makes some simplifying assumptions to
facilitate the computation of interest during construction. For the
Grant Lake and alternative projects the following assumptions are made:
1) There is no 10% or other retainage on funds due the contractor.
2) The interval over which the analysis is made is not as small
astypically used in a financial analysis (i.e. monthly). For
this study a Quarterly interval has been selected.
3) It is assumed that funds are borrowed three months before
payment is due the contractor. However, the funds are assumed
to accrue interest during this period at the rate of discount
(3.5%) and hence has no cost impact on the project.
4) As a result of 3) the interest is calculated on the
cumulative amount borrowed up to the previous Quarter.
Table 4-4 illustrates the computation of interest during construction
for the Grant Lake Project. Similar computations were made for each
component of the various cases.
4-4
4.2.3 Sensitivity Analyses
The economic analysis procedure was performed for the Base Case Plan I
and Alternative Plans 1-1 using the medium load growth scenario and gas
prices based on marginal rates with Sherman Clark NSD (SC) real
escalation. These assumptions for load growth and the future price of
gas are considered to provide the most realistic evaluation of the cost
of each of the plans. In order to assess the effect that differences
in the assumed load growth and gas prices would have on the outcome of
the economic analysis, various sensitivity analyses were performed on
the Base Case Plan and on Alternative Plan 1-1. The total cost of the
Base Case Plan and Alternative Plan 1-1 was computed holding all other
parameters equal and using both the low and high load growth scenarios
developed in Section 2.0. Also, the total plan cost for the Base Case
Plan I and Alternative Plan 1-1 was computed using the medium load
growth scenario and varying the assumption for the price of gas by
using three other gas price scenarios. A summary of all of the
economic analyses performed, including the sensitivity analyses, is
shown on Table 4-1 with a discussion of the results being provided in
Section 4.5. Detailed economic analyses for each case investigated are
presented in Part III of the Technical Appendix.
4.3 DERIVATION OF COST OF PLAN COMPONENTS
4.3.1 General
The Base Case Plan I and Alternative Plans 1-1, 1-2, 1-3 and 1-4
include up to a total of four different generation components and one
non-generation component. The basis for assignment of capital and
operation and maintenance costs for each of these components, and for
the price of natural gas is described below.
4-5
5398B
4.3.2 Simple Cycle Combustion Turbines
No capital costs are required for simple cycle combustion turbine units
because all new thermal generation capacity is assumed to be
combined-cycle rather than simple cycle units. The operation and
maintenance costs for simple cycle combustion turbine generation were
obtained from the draft North Slope Gas Feasibility Study (Ebasco
Services Inc., January 1983), where a value of 4.60 mills per
kilowatt-hour was estimated in January 1982 dollars. Escalating this
value one year to January 1983 using a 7% escalation rate provides a
value of 4.92 mills per kilowatt-hour. The breakdown between the fixed
and variable (excluding fuel costs) components of operation and
maintenance was not estimated because of the negligible amount of fixed
cost attributable to operation and maintenance of simple cycle units.
A heat rat~ of 12,000 Btu's per kilowatt-hour has been used for
simple-cycle combustion turbine generation (Supplement-Kenai Peninsula
Power Supply and Transmission Study, R.W. Beck and Associates, December
1982).
4.3.3 Combined Cycle Combustion Turbines
T~e capital and operation and maintenance costs for new combined cycle
generation facilities was obtained from the draft report on the North
Slope Gas Feasibility Study (Ebasco Services Inc., January 1983). A
cost estimate was developed in that study for a 220 MW combined-cycle
plant located in the Kenai/Nikiski area. The total estimated cost for
this pl~nt in January 1982 dollars was $135,610,000, which results in a
cost of $616 per kilowatt. Using a 7% escalation rate from January
1~182 to January 1983, the January 1983 capital cost becomes $659 per
k'ilowatt. Operation and maintenance costs were estimated at 4.0 mills
per kilowatt-hour, which, when escalated to January 1983, becomes 4.28
mills per kilowatt-hour.
4-6
5398B
The cost of transmission facilities for the combined cycle plant were
obtained from the Kenai Peninsula Power Supply and Transmission Study
(Beck, June 1982). In that study a value of $564,523/MW (January 1982
dollars) was used for the construction costs of transmission
facilities, and a value of $9,534/MW (January 1982 dollars) was used
for operation and maintenance costs. These values were escalated to
January 1983 using 1% escalation.
The Federal Energy Regulatory Commission's Hydroelectric Power
Evaluation manual, August 1919, recommends the application of a
capacity value adjustment factor of 5% to 10% to reflect the greater
reliability of hydroelectric projects when compared to thermal
generation facilities. A capacity value adjustment factor of 5% was
therefore applied to the at-market cost of capacity from the combustion
turbine facility. This resulted in a cost of $692 per MW. This
capacity value adjustment factor was also applied to the at-market
thermal capacity values in the economic analysis for the Bradley Lake
Project in both the Bradley Lake Project Power Market Report (Alaska
Power Administration, February 1982) and the Kenai Peninsula Power
Supply and Transmission Study (R.W. Beck and Associates, June 1982).
As reported in the North Slope Gas Feasibility Study, referred to
above, the heat rate for units of this type ranges from 8350 to 9200
Btu/kWh. The heat rate for combined cycle units used in the Supplement
to the Kenai Peninsula Power Supply and Transmission Study (R.W. Beck,
December 1982) is 8700 Btu/kWh, which is near the mean of the range of
heat rates given in the North Slope Gas Study. A heat rate of 8100
Btu/kWh is used in this study as a value representative of average
operating conditions considering varying load, start-up and shut-down
periods, and efficiency of the units over their economic life. This
value is consistent with the value used in the Beck report.
4-1
5398B
4.3.4 Grant Lake Hydroelectric Project
The capital and operation and maintenance costs for the 7,000 kW Grant
Lake Project are developed in Section 18.0 of this report. The tot~l
overnight estimated project cost in January 1983 is $23,390,000 with
the construction period extending over two and one half years. The
operation and maintenance costs were estimated to be $302,000 per year.
4.3.5 Bradley Lake Hydroelectric Project
The estimated construction costs for the Bradley Lake Project were
obtained from the Power Authority (Stone and Webster, October, 1983).
These costs were developed for a 90 MW and a 135 MW installed capacity
development at Bradley Lake with the assumption that construction would
begin in 1983 and the project would be operational in October 1988.
The 90 MW project is the preferred development. The total estimated
construction cost in July 1983 dollars is $283,019,000 Costs were
de-escalated to January 1983 dollars by deducting 0.66 percent of the
cost in accordance with the USBR Compostite Index of Water and Power
Costs resulting in an adjusted overnight cost of $281,163,000.
Operatlons and maintenance costs were given as $1,252,000 (July, 1983)
and adjusted to $1,243,800 (January, 1983) by the same factor. The
project cashflow was similarily adjusted resulting in the following:
Calendar Year ($000, January 1983)
1983 2,186
1984 8,146
1985 65,557
1986 77,648
1987 82,535
1988 45,091
4-8
5398B
The cost of the project assigned to Seward is based on the 4.02 MW
portion of the installed capacity which Seward is assumed to receive
(see Section 3.4 for derivation of 4.02 MW).
The 135 MW Bradley Lake Project, presented in the feasibility study, is
from an earlier comparison study conducted by Stone & Webster. It is
not directly comparable with the latest version of the 90 MW Bradley
Lake Project since the 90 Mw project includes additional refinements
which were not applied to the 135 MW project. However, as a matter of
interest, the 135 MW project is included in this study. A major
difference between the 90 MW and 135 MW project is the addition of the
Anchorage-Soldotna Intertie to the 135 MW case. The intertie is
required to transmit the higher peak load flows in the 135 MW
development.
The cashflow for the project ;s assumed to have the same percentage
distribution as the 90 MW project. Operations and maintenance costs
are given as $1,243,800 (January 1983 dollars), the same as for the 90
MW plant, by Stone & Webster.
The Anchorage-Soldotna Intertie is assumed to be built in 1987
(personal communication, Stone & Webster, December 15, 1983).
Operations and maintenance costs for the intertie are $936,800 per year.
4.3.6 Daves Creek-Seward Transmission Line
The capital and operation and maintenance costs for the Daves
Creek-Seward transmission line are developed in Section 10.0 of this
report. The estimated overnight construction cost for the line is
estimated to be $11,799,000 and the annual operation and maintenance
costs are $250,000, both in January 1983 dollars. The projected date
for the line to become operational is November 1984. The costs for
this transmission line are included in all plans because the results of
the feasibility study for the line indicate that regardless of the
5398B
method of providing power to the City of Seward, the existing 24.9 kV
transmission line that extends between the Daves Creek switchyard and
the City of Seward will require replacement. For purposes of inclusion
of the cost of the line in the economic analysis, the operational date
for the line has been assumed to be January 1985.
4.3.7 Price of Natural Gas
The price of natural gas used in the economic analysis was based on the
following: 1) Volume 1, Exhibit D of the Application for License for
Major Project; Susitna Hydroelectric Project 2) price forecasts
developed in the Railbelt Electric Power Alternatives Study: Fossil
Fuel Availability and Price Forecasts, Vol. VII (Battelle, March 1982),
and 3) an additional gas price forecasting analysis performed by the
P~wer Authority in December 1983 which is contained in the Tehcnical
Appendix in Part IV.
The method used in the License Application for the Sustina Project for
estimating the future price of natural gas is to tie the price to the
world price of oil. This is particularily applicable since the recent
Enstar contracts escalate the price of gas in relation to the price of
oil. Several scenarios for estimating the future world price of oil
were evaluated and are described in Section 5.4 of Exhibit B in the
Sustitna License Aplication. The world oil price scenario adopted for
Susitna was the Sherman Clark Associates No Supply Disruption case.
For the sake of brevity in charts and text this case is abbreviated
"SC".
The Battelle Study contained historical and forecasted prices for
natural gas for years 1980-2000 for the Alaska Gas and Service Company
(AGAS) and Chugach Electric Association (CEA). These price forecasts
(Tables 2.7 and 2.8 in Part III of the Technical Appendix) incorporate
the effect of the differing costs and escalation rates of the various
existing gas supply contracts, and the cost of supplemental (marginal)
gas supplies which will be required in the future to meet demand in
excess of the contracted supply.
4-10
5398B
The Power Authority, in its January 1983 analysis, revised the Battelle
forecasts to account for the following:
1) Historical use of North Cook Royalty Gas by AGAS -while Battelle
had estimated that North Cook Gas would provide 4 BCF/year in 1980
and 1981, only 2.68 and 1.03 BCF/year were used in actuality. This
represented such a small proportion of the total gas supply that
its effect was ignored totally in the Power Authority's analysis.
In addition, ENSTAR has indicated that they will be purchasing
little, if any, royalty gas.
2) Estimates provided to the Power Authority from ENSTAR of the
proportion of new, non-royalty supplemental gas which would be
included in the total gas supply to AGAS in future years (1983-20%,
1984-30%, 1985-40%, ... 1990-90%, 1991 and beyond, 100%).
The Power Authority's analysis of the cost of gas using the above data
is contained in the Technical Appendix. A total of four different gas
price scenarios were identified in this analysis for use in the
economic analysis:
1) Marginal rates at SC escalation,
2) Marginal rates at 0% escalation,
3) Melded rates at SC escalation, and
4) Melded rates at 0% escalation.
The forecasted prices for each of these scenarios are shown on Table
4-3.
The marginal (or non-royalty supplemental) gas rates shown in Table 4-3
were obtained from the analyses performed to forecast the weighted
price of gas to AGAS. Also, the melded gas prices were computed (at 0%
and SC escalation) based on the respective generation of CEA and
Anchorage Municipal Light and Power. The derivation of these price
scenarios is shown in the Technical Appendix.
4-11
5398B
The marginal price of gas at SC escalation was used for the sizing and
optimization of the Grant Lake project features, and in the economic
analysis. Use of the marginal price of gas is considered reasonable
and justifiable because the hydro project is being compared with the
cost of new gas-fired generation on the Kenai Peninsula and because
contracts for supply of gas will expire (excluding the recent Shell and
Marathon contracts) from use at existing power plants and for
non-electrical uses. In addition, if a gas-fired generating plant were
to be replaced by a non-gas-fired generating facility, the units shut
down would be those using the highest cost fuel.
4.3.8 Transmission Losses
4.3.8.1 General
Transmission losses were estimated for delivery of power from each
generation component to the City of Seward. A discussion of the
assumptions and procedures which were used to estimate the losses is
py'ovided below.
4.3.8.2 Grant Lake Project
Transmission losses from the Grant Lake Project to the City of Seward
were estimated based on the transmission line configuration shown in
Part IV of this report from the powerhouse to the Seward-Anchorage
Highway, and the assumption that the new 115 kV Daves Creek-Seward
transmission line would be built, as discussed in Part III of this
report. It was assumed that the transmission line from the Grant Lake
powerhouse would be connected to the new 115 kV Daves Creek-Seward
line, over which Grant Lake power would be transmitted to Seward. The
station service and transmission losses were estimated to be 1.8% for
energy and 0.8% for capacity.
4-12
5398B
4.3.8.3 Thermal Generation Facilities
The transmission losses from the vicinity of the City of Kenai to the
City of Seward were estimated for the existing and new gas-fired
thermal generation facilities used in the base case plans and
alternative plans. The transmission losses from the area near the
City of Kenai to the City of Seward consist of two main segments. The
first segment is the existing 115 kV transmission line from Kenai to
Daves Creek substation (about 40 miles northwest of Seward) and the
second portion is the new 115 kV line from Daves Creek to Seward (as
presented in Part III of this report).
The transmission losses for the first segment from the area near Kenai
to Daves Creek SUbstation are estimated to be about 5% for peak loading
and about 3-1/2% for average normal load. This estimate is based upon
the following information.
o That the 115 kV transmission line from Daves Creek to Soldotna
(near Kenai) has a 556 ACSR conductor. This conductor size
information was received from Chugach Electric Association.
o That the estimated load now on this line is 10 MW with a
direction of power flow from Soldotna toward Daves Creek.
This information obtained from the draft copy of Railbelt
Reliability Study for 1982/83 peak load base.
o That the load forecast in Section 2.3 of 20 MW be used for
peak loading. It is assumed that this load would be added to
the line's present load.
o That transformer losses are small enough to be ignored.
Information obtained from Chugach Electric indicated that this segment
of line load was higher than 10 MW and more in the order of 20 to
30 MW. If this is the case, then losses for peak loading would be more
in the area of 10%. However, the lower figure is used.
4-13
53988
The transmission losses for the second segment of this line from Daves
Creek to Seward are estimated to be 2.7% for the peak demand and 1.1%
for average normal loading. This information is presented in Section
9.3 and Part V of the Technical Appendix.
When these two segments are combined, the total loss is 7.7% for peak
demand and 4.6% for average normal loading. These values were rounded
off to 8% and 5% for use in the economic analysis.
4.3.8.4 Bradley Lake Project
The transmission losses from the Bradley Lake Hydro project to Seward
were given by Stone & Webster as 8% for both capacity and energy
(personal communication, Stone & Webster, December 15, 1983).
4.3.9 Allocation of Generation Between Plan Components
The energy allotment between generation resources was assumed to follow
the economically rational approach of using least expensive sources
prior to more expensive sources. In all 20 year plans, hydroelectric
energy (if included in the plan) is allocated first since there is no
variable (fuel) cost associated with its provision. The next lowest
cost alternative is combined cycle combustion turbine since the heat
rate of 8,700 MMBtu/ GWH is lower than the 12,000 MMBtu/GWH for simple
cycle turbines resulting in lower fuel consumption (i.e., cost) per GWH
of energy generation as well as slightly lower variable operation and
maintenance costs. Finally, after all other generation sources are
e:(hausted, the simple cycle turbines contribute the remaining energy
requirement until they are completely retired in 2002. After they are
retired, each plan ensures adequate capacity and energy are available
from the new sources to meet Seward's needs until the end of the
evaluation period.
4-14
5398B
Generally, once hydroelectric energy is fully allocated (or immediately
in the case of the Base Plan I), the combined cycle combustion turbines
are allocated .. A maximum capacity factor of 0.15 was used for the
combined cycle unit after reserves were accounted for, which results in
a maximum energy of 6.57 GWH per MW of combined cycle combustion
turbine installed capacity. If the remaining energy demand is less
than 6.51 GWH per MW then only the energy needed is generated. When
the energy demand exceeds the supply capable of being provided by
combined cycle combustion turbines the simple cycle combustion turbines
are allocated.
An additional complication exists in allocating energy during the years
prior to retirement of the simple cycle turbines in all plans. It may
be impossible for the combined cycle combustion turbines to operate at
the stated capacity factor of 0.15 or even a reduced capacity factor,
based on meeting the remaining energy demand, owing to the shape of the
load duration curve for the region and reserve requirements. To
overcome this problem an algorithm was developed for allocating energy
generation between simple cycle, turbines, combined cycle turbines, and
hydro power.
The first step in creating the algorithm was to develop an annual load
duration curve for the region based on load duration data provided in
the Bradley Lake Power Market Report (Alaska Power Administration
1982). A piecewise linear approximation at 10 percent intervals of the
curve for December was applied to the fall and winter months of October
through March when peak load is highest using the mid-range peak load
distribution for the Anchorage/Cook Inlet region. A similar approach
was taken using a piecewise linear approximation for June and applying
it to the spring and summer months of April through September. The
resulting percentages of peak load were ranked and plotted as an annual
load duration curve. Based on the plot, equations were developed which
described the relationship of percentage of annual peak to percent
exceedance of load. Integrating the equations yielded the amount of
4-15
5398B
energy which must be generated by combined cycle combustion turbines at
a given level of installed capacity adjusted for reserve requirements.
The remaining energy is allocated to simple cycle turbines.
4.4 OPTIMUM TIMING FOR GRANT LAKE PROJECT
The project schedule, shown on Figure IV-27, indicates that the
earliest practical time that the project can be constructed and come
on-line is April 1987. The load and resource analysis part of the
economic study shows that new generating resources for the Kenai
Peninsula are not required until 1988. To allow for possible slippage
in the project schedule and to meet the need for additional generating
capacity in 1988, we have assumed for the purposes of performing the
economic analysis that the earliest the project could come on-line is
January 1988.
A study was performed to determine the optimum timing for the
construction of the Grant Lake Project. The study was performed by
varying the on-line date for the project and computing the total
present worth cost of Alternative Plan 1-1 for each assumed on-line
date to find the date that results in the lowest total cost. As shown
on Table 4-5, this systematic search for the optimum project timing
showed that the lowest total cost for Alternative Plan 1-1 results with
a project on-line date of January 1988 (assuming marginal prices for
gas at SC escalation and medium load growth). As the on-line date for
the project was moved further ahead, the total plan costs increased.
It will be noted, however, that the difference in the total plan cost
for the years immediately ahead of the optimum date is extremely small.
4.5 RESULTS OF ECONOMIC ANALYSIS
A summary of the total present worth of the cost of each plan including
all sensitivity analyses described above, is shown on Table 4-1. The
detailed analysis for each of the 15 cases studied as twenty year plans
4-16
53986
is shown on Tables 111-1 to 111-15 in Part III of the Technical
Appendix. As shown on Table 4-1 with Cases 1. 2. and 3. using the
medium load growth scenario and the marginal price of gas at SC
escalation. Alternative Plan 1-1 is lower in cost than the Base Case
Plan I. and Alternative Plan 1-2 has the lowest cost of all plans.
Therefore. the economic analysis using these parameters shows that the
Grant Lake Project is economically feasible and is preferrab1e to
purchasing a similar share of combined cycle combustion turbine
facilities. Using either the low load growth scenario (Cases 6 and 7).
or the high load growth scenario (Cases 8 and 9). the alternative plan
including Grant Lake is preferable.
Using any of the assumptions for lower gas prices (Cases 10-15). the
Base Case Plan I is more economical than Alternative Plan 1-1. This
illustrates the sensitivity of the economics of the Grant Lake Project
to the assumptions made for the price of natural gas. However. the
assumption considered to be most realistic for the price of gas is that
of marginal rates at SC escalation, and under this assumption the Grant
Lake Project is shown to be slightly more economical than the Base Case
Plan I. regardless of whether a low. medium. or high load growth
scenario is realized. Although the differences in the total cost of
the Base Case Plan I and Alternatives 1-1 and 1-2 are not substantial,
the results of the economic analysis indicates that the presence of the
Grant lake Project in the generation resource mix serving Seward would
result in a lower cost of power than without the project. Furthermore,
the project is much more economical relative to base case than the
benefit cost ratio indicates since substantial portions of each plan
represent common denominators.
Table 4-1 also shows the net benefits and benefit/cost ratios
associated with each case. In accordance with the Power Authority·s
project evaluation procedure. benefits are defined as the present worth
total cost of the Base Case Plan I, supplemented by any subsidiary
benefits of a particular plan. Subsidiary benefits are beneficial
outputs other than power production. In the case of Alternative Plan
4-17
1-1. subsidiary benefits would be provided from the production of fish
from the fisheries mitigation plan and from the use of the recreational
facilities of Grant Lake. However. no attempt has been made to
quantify these subsidiary benefits, and they have been conservatively
assumed to be equal to zero. Therefore, the benefit/cost ratio for any
case is the ratio of the cost of the Base Case Plan I to the cost of
the plan of interest. As indicated on Table 4-1. the benefit cost
ratios for all cases is essentially 1.0. indicating marginal economic
feasibility for the Grant Lake Project. Therefore. the thermal
alternative and the Grant Lake Project are approximately at a
break-even point. in view of the fact that the largest difference in
the Base Case Plan I versus Alternative Plan 1-1 is only three percent
in the case of melded gas prices at 0% escalation. A summary of the
total present worth of the cost of each plan equivalent to Grant Lake
is shown on Table 4-2. The detailed analysis for each of the 8 cases
studied is shown on Tables 111-16 to 111-23 in Part III of the
Technical Appendix. As shown on Table 4-2 with Cases 16. 17. 18. 19
and 20. using the medium load growth scenario and the marginal price of
gas at SC escalation. Alternative Plan 11-1 (Grant Lake) is lower in
cost than the 8ase Case Plan II. and A1te,rnative Plan 11-2 (90 MW
Bradley Lake)has the lowest cost of all plans. Alternative Plan 11-4
(135 MW Bradley Lake) is also less expensive than Alternative Plan
11-2. but Alternative 11-5 (Susitna) is most expensive The benefit
cost ratio of Alternative 11-1 (Grant Lake) is 1.148.
For the cases where fuel prices are lower than the Sherman Clark
marginal prices. a significant difference between the results for the
20 year plans and the Grant Lake equivalent analyses is evident. For
example note that the benefit cost ratio for the 20 year plan utilizing
marginal gas prices at 0% escalation is 0.990 while the Grant Lake
equivalent yields a benefit cost ratio of 1.024. The reason for the
differing conclusions is that in the Base Plan I. the combined cycle
combustion turbines are operated at higher capacity factors. with the
additional capacity requirements being met by the simple cycle
combustion turbines. Grant Lake is hydrologically limited to a
4-18
capacity factor of 41.4%, not 75% like the combined cycle turbines, and
therefore the increased reliance on simple cycle combustion turbines
causes the overall Alternative Plan I to be more expensive than the
comparable Base Case I at 0% escalation of the Sherman Clark gas prices.
4.6 ENVIRONMENTAL EVALUATION
This section compares the environmental impacts associated with the gas
turbines and the alternative plans for supplying power to the Seward
area. An evaluation of the environmental impacts associated with each
plan is provided in the following paragraphs.
4.6.1 Gas Turbines
Environmental impacts associated with the gas turbines primarily
consist of air emissions from the Bernice Lake plant and aesthetic and
biological impacts associated with the Daves Creek-Seward transmission
line. Air emissions from gas-fired units are relatively "clean"
compared to other fossil fuel plants. Appropriate emissions controls,
such as water or steam injections to reduce nitrogen oxides levels,
would ensure compliance with the applicable air quality standards.
Because the Bernice Lake site is in an exposed coastal area, the air
quality and meteorological conditions generally favor power generation.
4.6.2 Daves Creek-Seward Transmission Line
Construction of the Daves Creek-Seward transmission line will engender
several environmental impacts. Because the line will be located near
the Anchorage-Seward Highway for most of its length, the line will have
an aesthetic impact on viewsheds between Seward and Moose Pass. Single
wood poles will be used to minimize this impact. A low profile
substation configuration will be used that can easily be screened with
existing vegetation. The transmission line will also cause minor
impacts on wildlife habitat due to clearing of the right-of-way and
access road construction in the areas where the line is not built in
4-19
53988
the existing right-of-way. A short-term increase in erosion rates
during the construction phase may slightly increase sedimentation in
nearby waterbodies, thereby degrading the water quality. Because this
impact will be short-term and low in intensity, the effects would not
be significant.
4.6.3 Grant Lake
The primary environmental impact of the Grant Lake Project is loss of
fish habitat over the l.l-mile length of Grant Creek. Although Grant
Creek would be dewatered for its full length only the lower 1/2 mile is
currently utilized by fish. An estimated 100 chinook and 500 sockeye
salmon adults would be lost annually from Grant Creek. In addition,
habitat for rainbow trout and Dolly Varden would be eliminated. The
loss of these fish would be mitigated by adding salmon culture
facilities at a nearby state hatchery and by planting trout into Grant
Lake or a nearby lake to replace sport fishery losses. Because of the
mitigation measures employed, the Grant Lake Project would not cause a
net loss to fisheries resources. A detailed assessment of potential
impacts of the Grant Lake project and proposed mitigation measures is
provided in Volume II, Environmental Report.
The environmental impacts associated with Grant Lake in combination
with gas turbines include those discussed for the gas turbines in
addition to those associated with the Grant Lake Project. The Bernice
Lake generation capacity would be reduced by 1 MW as compared with the
base plan, resulting in a corresponding decrease in air emissions.
Some environmental impacts of Grant Lake and gas are significant, but
these can be mitigated.
4.6.4 Bradley Lake
The Bradley Lake Project will inundate approximately 2,000 acres,
eliminating more than half of the tall shrub habitat in the immediate
vicinity of Bradley Lake. The effects of this habitat loss to the
4-20
5398B
local moose population is unknown, but permanent displacement is
possible. Because the project reservoir would more than double the
lake's surface area, the high water and exposed shoreline could impede
moose migration between Fox River Valley and the Kenai National
Wildlife Refuge, the shrub habitat along Kachemak Creek and upper
Bradley River, and dispersion through the Bradley River -Nuka River
pass. This dispersion is believed to sustain the only moose population
on the outer coast of the southern Kenai Peninsula (Bradley Lake
Hydroelectric Project Final Environmental Impact Statement, u.S. Corps
of Engineers, 1982).
Approximately 400,000 cubic yards of clay material will be excavated
from the Sheep Point barge basin, its entrance canal, and the
tailrace. lhis material will be placed on about 40 acres of intertidal
land and a~jacent uplands. This placement may affect existing
waterfowl habitat and the overall intertidal ecosystem.
Environmental impacts associated with Alternative Plan 1-2 and 1-3
include those discussed for Plan 1-1 in addition to Bradley Lake
impacts. Because the generating capacity of the Bernice Lake plant
would be reduced 11 MW by the Bradley Lake project, air emissons in the
Kenai area would be somewhat less than for Plan 2.
In summary, impacts associated with all three plans will generally be
insignificant.
4.6.5 Susitna Hydroelectric Project
The Susitna Project includes two dams, Watana and Devil Canyon, that
will create 48-mile and 26-mile long reservoirs, respectively. During
construction, temporary construction camps will be located at each dam
site. A permanent town will be developed near Watana and an access
road built from the Denali Highway to the dam sites.
4-21
5398B
Impacts to fisheries will occur in downstream tributaries, side
channels and sloughs. All species of Pacific salmon, but predominantly
chum salmon, will experience effects on spawning and juvenile rearing.
Mitigation planning includes controlling water temperatures and flow
regime and possibly modifying habitat, or constructing a hatchery.
Principal wildlife species in the project area are moose, caribou,
wolf, wolverine, bear and Dall sheep. Loss of moose habitat by
inundation will occur and downstream grouse may be affected by altered
flow regimes. Reservoir inundation and increased access will also
affect grazing above the dam sites. Caribou migration and calving
patterns may be affected by the access road and reservoir ice
conditions. Some black bear reductions are likely from flooded dens,
but much less impact is expected to brown bear. Partial inundation of
a mineral lick may impact sheep usage and some regulation of furbearer
trapping may be required. A slight reduction in wolf population may
occur because of reduced moose population.
Socioeconomic impacts are projected to largely affect the communities
of Cantwell, Talkeetna, and Trapper Creek based on immigration of
workers and their families. Archeological and historical resources
will be preserved through avoidance and removal.
Alternative Plan 1-3 would have the highest level of environmental
impacts of the three plans considered.
4.7 SELECTION OF GENERATION PLAN
Based on the results of the economic and environmental evaluation of
the Base Case Plan 1 and Alternative Plans 1-1, 1-2, 1-3, and 1-4, the
following conclusions can be reached:
o The 115 kV Daves Creek-Seward transmission line would be
included in any generation plan for Seward.
4-22
5398B
o Alternative Plan 1-1 (includes Grant Lake Project) is lower in
cost than the Base Case Plan. assuming the medium load growth
scenario and marginal gas prices with SC escalation;
o Alternative Plans 1-2 and 1-3 are also economically feasible.
Alternative Plan 1-4 has a benefit-cost ratio slightly below 1.
o The environmental impacts associated with either the Base Case
Plan I and Alternative Plan 1-1 are not significant enough to
effect the decision of the choice of the plan; and
o The 7 MW Grant Lake Project is economically feasible
independent of Bradley Lake Project considerations. More
significantly. the Grant Lake Project has a benefit-cost ratio
of approximately 1.15. based on the value of power from
displaced gas fired combined cycle generation with marginal
gas prices with SC escalation.
Based on these conclusions, the recommended generation plan for Seward
is Alternative Plan 1-1 which includes the 7 MW Grant Lake
Hydroelectric Project and the 115 kV Daves Creek-Seward Transmission
Line.
4-23
TABLE 4-1
SU""ARY OF ECOIO"IC AIALYSES USIIG 20 YEAR PLUS
Totll P",nnt Refe"e~ce
lIo,.tll Cost IIet Beneft t Ylble of
C 1st Phn LOld G,.o.tll P,.tc, of GIS of Phn Ben,ft ts Cost Tecll~tcll
No. Desc,.tptton Sc,nl,.t 0 (,.ltes ) ( Jift 1983 $000) Jln 1983 $000 htto Appendix
1 Blst tue L!.! ",diu. "lI'gtnll fSC 'sc. 150.141 0 1.000 III -1
2 Al t. 1-1.V ",d Iu. "lI'gt nil fSC esc. 148.344 1 .797 1 .012 III -2
3 A It. 1-21/ "edtu. "lI'gt nil fSC esc. 146.983 3.158 1 .021 111-3
4 Al t. I-l.!/ "edtu. "lI'glnll fSC 'sc. 149.313 828 1.006 111-4
5 Al t. I-,ul "edlu. "I,.gfnll fSC ,sc. 156.200 -6.059 0.961 III -5
6 BlSe Cu, Lo. "I,.gfnll fSC ,sc. 77.354 0 1.000 III -6
7 Al t. 1-1 Lo. "I,.gtnll UC esc. 76 .321 1.033 1.014 111-7
8 Bin CIS' Htgll ,,,,.gfnll UC 'sc. 217.080 0 1.000 111-8
9 Al t. 1-1 Htgll "I,.gtnll fSC esc. 215.220 1.860 1.009 111-9
10 BIS' CUI ",dtu. "I,.gtnll fOI 'sc. 136.777 0 1.000 111-10
11 Al t. 1-1 ",dtu. "I"gtnll fOI ,sc. 138.198 -1,421 0.990 111-11
12 Bin CIS' ",diu. ",ld,d fSC 'sc. 131.869 0 1.000 111-12
13 Alt. 1-1 ",dtu. ",ld,d fSC 'sc. 132,260 -391 0.997 111-13
14 81 s, Cu, "ediu. ",ld,d fOI 'sc. 118,024 0 1.000 111-14
15 Al t. 1-1 ",dtu. ",ld,d fOI ,sc. 121,141 -3,617 0.970 111-15
11 Bu, CIS' Phn I conststs of ,.tstfn, Ind n,. gls-ff,.,d g,n'''ltton.
11 A1U,.nlttu Phn 1-1 fnclud,s tile ;,.ut Llk, Hyd,.o,l,ct,.tc P"oj,ct, • IIfcll dfspllcu gls-ft,.,d g,n,rltton •
11 Al t,rftltt v, Phn 1-2 tnclud,s til, 90 "II a,.ldl,y Llk, Hyd,.o,l,ct,.fc P"oJ,ct, .IItcli dfspllc,s gls-ff,.,d
gene,.ltton.
!I Alternlttv, Plln 1-3 tnclud,s til, 135 "II a,.ldl,y Llk, Hyd,.o,lect,.tc P"oj,ct, .IItcli dtspllces gls-ft,.ed
gen,rltton.
il Alte,.nattv, Plln 1-4 fnclud,s til, Susftnl Hyd,.o,l,ct,.fc p,.oj,ct , .IIfcll dfspllc,s gls-ff,.ed g,n'''ltton.
4-24
TABLE 4-2
SUMMARY OF ECONOMIC ANALYSES FOR GRANT LAKE EQUIVALENT OPTIONS
Total Present Reference
Worth Cost Net Benefit Tab1 e of
Case Plan Load Growth Price of Gas of Plan Benefits Cost Technical
No. Description Scenario (rates) (Jan 1983 $000) (Jan 1983 $000) Ratio Appendix
16 Ba se Ca se I r.lI Medium Marginal @SC esc. 31,648 0 1.000 111-16
17 Alt.ll-lY Medium Not Appicab1e. 27,579 4,069 1.148 111-17
18 Alt. 11-22! Medium Not App1 icab1e. 21,939 9,709 1.443 111-18
19 A1 t. II-~ Medium Not App1 icab1e. 25,582 6,066 1.237 111-19
20 A1 t. II-4iI Medium Marginal @SC esc. 33,060 -1,412 0.957 111-20
21 Base Case II Medium Marginal @O'.t esc. 28,236 O. 1.000 II I -21
17 Alt. 11-1 Medium Not App1 icab1e. 27,579 657 1.024 111-17
22 Base Case I I Medium Melded @SC esc. 29,043 0 1.000 111-22
17 Alt. 11-1 Medium Not App1 icab1e. 27,579 1,464 1.053 111-17
23 Base Case II Medium Melded @O'.t esc. 25,642 0 1.000 111-23
17 Alt. 11-1 Medium Not App1 icab1e. 27,579 -1,937 0.930 111-17
l! Base Case Plan II is new gas-fired combined cycle generation.
2/ Alternative P1 an 11-1 is the Grant Lake Hydroelectric Project.
3/ Alternative P1 an 11-2 is the 90 MW Bradley Lake Hydroelectric Project with an appropriate adjustment for
capacity credit.
~ Alternative Plan 11-3 is the 135 MW Bradley Lake Hydroelectric Project with an appropriate adjustment for
capacity credit.
~ Alternative Plan 11-4 is initially new gas-fired combined cycle generation followed by complete reliance on
the Susitna Hydroelectric Project from 1993 on wi th an appropriate adjustment for capacity credit.
4-25
TABLE 4-3
FORECASTED PRICE OF COOK INLET GAS
FOR USE IN ECONOMIC ANALYSIS1I
Marginal Rates£1 Melded Rates~1
0% escalation SC escalation 0% escalation SC escalation
Year $/MCFY $/MCF2 1 $/MCF§.I $/MCFII
1983 2.77 2.77 0.65 0.65
1984 2.77 2.66 0.74 0.72
1985 2.77 2.55 0.82 0.79
1986 2.77 2.90 1.00 0.95
1987 2.77 2.90 1 .13 1.07
1988 2.77 2.90 1. 27 1.20
1989 2.77 2.97 1 .41 1.35
1990 3.12 3.05 1 .54 1 .51
1991 3.12 3.14 1. 73 1. 73
1992 3.12 3.22 1. 75 1. 81
1993 3.12 3.31 1 .84 1 .95
1994 3.12 3.40 1 .91 2.07
1995 3.12 3.49 1. 96 2.18
1996 3.12 3.59 2.94 3.41
1997 3.12 3.69 2.94 3.51
1998 3.12 3.79 2.94 3.61
1999 3.12 3.89 2.94 3.71
2000 3.12 4.00 2.94 3.82
2001 3.12 4.11 2.94 3.93
2002 3.12 4.23 2.94 4.05
11 Derivation of all values in this table is provided in a Power
Authority Memorandum to File, dated January 12, 1983, which is
contained in Part IV of the Technical Appendix.
~I The term "marginal" rates refers to the contracted price of
non-royalty, supplemental gas to AGAS.
~I The term "melded" rates refers to the forecasted price of gas to
Anchorage Municipal Light and Power and Chugach Electric Association,
where the melded rates are based on the respective amount of energy
generated by each utility.
il Prices derived on Table A,
II Prices derived on Table 8,
~I Prices derived on Table C,
II Prices derived on Table 0,
53988
Technical
Technical
Technical
Technical
4-26
Appendix,
Appendix,
Appendix,
Appendix,
Part
Part
Part
Part
IV.
IV.
IV.
IV.
TABLE 4-4
COMPUTA TI ON OF INTEREST DURING CONSTRUCTION FOR GRAHT LAKE HYDROELECTRIC PROJECT
Cumulative Basis
Project Project Cumulative Cumulative for Quarterly January 1. Year
Const. Const. Interest Project Interest Interest Present Worth
Costs Costs Paid Costs Computation Paid Of Interest
Year Quarter (19133 $) (1983 $) (1983 $) (1983 $) (1983 $)
1985 1 0 0 0 0 0
2 0 0 0 0 0
3 0 0 0 0 0
4 3192430 3192430 0 3192430 0
Total
19U6 1 4443340 7635770 27574 7663344 3192430
2 3Ul1240 10647010 93766 10740776 7663344
3 3717960 14364970 186539 14551509 10740776
4 616460 14981430 312227 15293657 14551509
Total
1987 1 3416300 18397730 444325 18842055 15293657
2 3228270 21626000 607072 22233072 18842055
3 15433UO 231693UO 799109 239613409 2223072
4 220700 23390000 1006135 24396135 23968409
Total
Grand Total January 1, 1983 Present Worth
Summary of Hesults
Present Worth
Construction
Costs
Present Worth
Interest Costs
(1983 $)
Present Worth January 1, 1983
Year
1985
19Hb
19U7
(19133 $)
3084473
115U4050
82774138
o
304249
678109
Total Costs Present Worth
(1983 $) (1983 $)
3084473
11888299
8955597
2879389
10722564
7B04286
Grand Total January 1, 1983 Present Worth 21406239
Note: Discount Rate = 3.5%
Interest Computed Quarterly
(1983 $) (1983 $)
0
0
0
0
27574
66192
92773
125688
13209B
162747
192037
207026
January 1. 1983
Present Worth IDC
(1983 $)
o
274415
590933
865348
0
0
0
0
0
27338
65063
90410
12143B
304249
130967
159972
187146
200025
678109
January 1. Year
Present Worth
of Construction
(1983 $)
0
0
0
3084473
3084473
4405290
2959B87
3623260
595614
11584050
3387045
3173216
1503991
213237
8277488
January 1. Year January 1, 1983
Present Worth Present Worth
of Project Of Project
(1983 $) (l983 $)
0 0
0 0
0 0
3084473 2879389
3084473 2879389
4432628 3997976
3024950 2728332
3713669 3349517
717051 646739
11888299 10722564
3518012 3065744
3333188 2904681
1691136 1473727
413262 360134
8955597 7804286
21406239
Generation
Plan
A lternat i ve
Alternative
Alternative
A lternat i ve
Base Case
TABLE 4-5
OPTIMUM TIMING ANALYSIS
FOR GRANT LAKE PROJECT 11
Total Present Worth
On-Line Date for Gas Price Cost of Plan in
Grant Lake Project Escalation £1 January 1983 $
($000)
1988 SC $148,344
1990~/ SC 148,424
1993~/ SC 148,600
1998~1 SC 148,735
SC 1 50, 141
l/All cases shown use medium load growth scenario and 55 year evaluation
period (1983-2037)
Increase
in Cost
($000)
80
256
391
1 ,797
£/Sherman-Clark Marginal price of gas was used in the optimum timing analysis
~/See Tables 111-25, 111-26, and 111-27 of the Technical Appendix for detailed
studies.
4-28
5398B
•
•
100
95
90 L~\
P 85
"\
""' E '" ~ LEGEND 80 ....
R ~ ACTUAL LOAD DURATION C ..
75 ~ ... CURVE E \~ 70 ~ .. ---------APPROXIMATION OF LOAD N -....;.,
~ .. DURATION CURVE T 65
60 ~ ~ a -~ ~ F 55 ~ .... ~ 50 .. ~ "'
A ~ .... ~ 45 N ~ N 40 .... ....
""""
....
U 35 ~
A "
L 30
25
P ..
E 20
A 15
K 10
5
0
0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 ge' 95 1 00 ALASKA POWER AUTHORITY
PERCENT EXCEEDENCE GRANT LAKE HYDAOEI EC11IC PROJECT
ANNUAL LOAD DURATION CURVE
FOR THE ANCHORAGE AREA
DATE FEB 1984 I FIGURE I-I
I:BASCO SERVICES INCORPORATED
PART II
COOPER LAKE
EXPANSION INVESTIGATION
5.0 COOPER LAKE EXPANSION INVESTIGATION
5.1 INTRODUCTION
A review of the existing Cooper Lake Hydroelectric Project was added to
the scope of work for the Grant Lake Project feasibility study to
determine if additional energy generation or installed capacity could
be economically developed at this site to assist in meeting the need
for power for the region and specifically for Seward. The Cooper Lake
Project, located about 12 air miles southwest of the Grant Lake site,
utilizes head between Cooper Lake and Kenai Lake. The project came
on-line in 1959 and consists of a 70' high dam on Cooper Creek at the
outlet of Cooper Lake, a gated intake to a power conduit on the
southeast shore of Cooper Lake, and a combination tunnel-penstock power
conduit incorporating a steel surge tank extending from the intake to
the powerhouse on the southwest shore of Kenai Lake. The powerhouse
contains two 7,500 kW generators directly connected to Francis turbines
which operate at 720 rpm and are rated at 726 feet of head.
The project, as conceived in the Definite Project Report (North Pacific
Consultants, 1955), includes the diversion of Stetson Creek, a
tributary of Cooper Creek, into Cooper Lake and the diversion of
Ptarmigan Creek (also referred to as Porcupine Creek), a small stream
which crosses the power tunnel, by pumping into the power conduit.
These diversions, however, have never been constructed.
A license application for the project was filed with the Federal Power
Commission (FPC) in 1956 and the license was issued in 1951 (FPC
Project No. 2170). A condition of the license required that
construction of the Stetson Creek diversion be deferred until minimum
flows for preservation of the fishery in lower Cooper Creek could be
established. The flows available for diversion that were subsequently
established by the U.S. Fish and Wildlife Service in 1958 were
5-1
22238
determined to make the diversion uneconomical at that time and the
incorporation of this feature was deleted from the license. The
diversion of Ptarmigan Creek into the power conduit was not constructed.
The addition to the Grant Lake feasibility study was to perform a
pre-feasibility study to determine the viability of diverting Stetson
Creek and Ptarmigan Creek into Cooper Lake, the provision of additional
generating capacity at the Cooper Lake Powerhouse, and the
incorporation of the results of these studies in the Feasibility Report.
5.2 STETSON AND PTARMIGAN CREEK DIVERSIONS
5.2.1 Hydrology
The basis for the evaluation of the hydrology for the Stetson and
Ptarmigan diversions is the adjusted flow data for Stetson Creek
contained in the Supplemental Design Report on Reservoir Storage Study
and of Diversion From Stetson Creek (North Pacific Consultants, 1958).
The adjusted flow data from that study is based on the flow records at
the USGS gaging station on Cooper Creek, 0.7 miles above its confluence
with the Kenai River. The adjusted data developed by North Pacific
Consultants for water years 1950 through 1957 was used to develop a
relationship between the time of year and streamf10ws as a percent of
average flow. From these relationships, and annual precipitation
records for the years 1913 through 1957, a representative historical
streamflow record was developed for Stetson Creek. A similar record
was prepared for Ptarmigan Creek by ratio of drainage areas between
Ptarmigan and Stetson Creeks.
In evaluating the water that would be made available for power
generation from the Stetson Creek diversion, the restrictions and
minimum flow requirements in the 1958 license amendment were assumed.
It was determined that the average annual flow available from the
diversion would be 22 cfs and the potential diversion rate during the
5-2
2223B
low water year of 1952 would be 8 cfs. The average annual diversion
rate for Ptarmigan Creek was found to be 4.8 cfs for the pumping system
selected.
5.2.2 Environmental Considerations
The major environmental concern for the diversion schemes is the
fishery in lower Cooper Creek and the minimum flows required to
maintain the fishery. Review of the FPC license and agency
correspondence received at that time revealed no apparent concern
regarding the Ptarmigan diversion. The USGS topographic mapping of the
project area indicates much steeper gradients at the mouth of Ptarmigan
Creek than at the mouth of Stetson Creek, thus possibly eliminating
fish runs for any significant reach in Ptarmigan Creek versus Stetson
Creek.
This prefeasibility evaluation of the Stetson diversion assumes that
the minimum flows established in the 1958 license amendment for the
Cooper Lake Project are still applicable. Any further investigations
of the feasibility of the Stetson Creek diversion should include the
necessary environmental analysis to determine whether these minimum
flows are still adequate.
Other environmental impacts of the diversion schemes would no doubt be
assessed should the schemes undergo a more detailed level of
investigation; however, at the prefeasibility level of investigation no
impacts are apparent that would preclude development of the diversions.
5.2.3 Diversion Works
The Stetson and Ptarmigan Creek diversions evaluated herein are
essentially the same in concept to the alternatives put forth in the
Definite Project Report. The Stetson diversion would utilize gravity
flow for diversion of flows into Cooper Lake. The major features of
5-3
2223B
the Stetson diversion would include an access road, a small concrete
gravity diversion dam with an ungated spillway section and a closed
diversion conduit leading to Cooper Lake. The significant change for
the Stetson diversion from that proposed in the Definite Project Report
is the use of a closed conduit versus an open channel for conveying the
water to Cooper Lake. This modification was assumed due to anticipated
requirements of environmental agencies and their concern for movement
of wildlife across the diversion channel. The dam would be located
approximately .6 miles upstream from the confluence of Cooper and
Stetson creeks and would impound water to an approximate elevation of
1,250. A conduit approximately 8,400 feet in length would extend from
the diversion dam to Cooper Lake at approximately elevation 1,200, the
Cooper Lake spillway crest elevation. A plan showing the location of
the dam, access road and conduit is provided in Figure 11-1.
The Ptarmigan Creek diversion would utilize a pumping station to pump
water from Ptarmigan Creek into the power conduit leading to the
powerhouse. It would be located near the point where the existing
power conduit for the Cooper Lake Project crosses Ptarmigan Creek.
Major features would include a concrete sill across the streambed, a
pumping station containing 2 vertical turbine pumps and an estimated
100 feet of 18 inch diameter pipeline extending from the pumping
station to the existing power conduit. Figure 11-1 shows the locations
of the diversion features relative to the existing Cooper Lake Project.
5.2.4 Diversion Operations and Increased Generation
-[he operation of the Stetson Creek diversion is assumed to be in
accordance with Article 30 of the order amending the Cooper Lake
Project License issued in 1958. Minimum in-stream flow restrictions
are specified in this Article by the U.S. Fish and Wildlife Service.
The restrictions would limit the diversion of water from Stetson Creek
to that which would still maintain the following minimum flows in
Cooper Creek at a point 0.1 miles from its mouth:
5-4
22238
May 30 cfs
June 80 cfs
July 70 cfs
August 40 cfs
September 35 cfs
October 35 cfs
November 25 cfs
December-April No diversion
It is further assumed that the maximum diversion rate would be 70 cfs
as was proposed in previous studies. The results of an operation
evaluation for the years between 1913 and 1957 show that the average
annual diversion would be 22 cfs with a corresponding increased average
annual energy generated at the powerhouse of approximately 10,162,000
kWh. The estimate of energy output assumes an average net head of 716
feet and an overall plant efficiency of 87 percent. The potential
average annual increase of flow for the low water year of 1952 was
found to be 8 cfs with a corresponding increase in firm energy of
3,695,000 kWh based on the same assumptions as for the average annual
energy.
The Ptarmigan Creek diversion with its pumping station is assumed to be
operational during times when the flow in the creek is equal to or
greater than 4 cfs. The capacity of the pumping station would be
about 12 cfs. The limits are based on the flow duration curve
developed for the site as well as manufacturers' pump curves for the
selected pumps. A cycling mode of operation would allow for flows less
than 4 cfs to be utilized in conjunction with storage capacity but
would not impact the overall feasibility to a significant degree at the
prefeasibility level; however, this should be further evaluated if the
diversion is to be implemented. The results of the evaluation for the
pumping scheme show that on an average annual basis the diversion rate
would be 4.8 cfs and the generation at the powerplant could be
5-5
2223B
increased by approximately 2,190,000 kWh with a pumping energy
requirement of about 876,000 kWh, thus resulting in an average annual
net increase in generation of 1,314,000 kWh.
5.2.5 Cost of Diversions
The cost of the Stetson Creek diversion was evaluated using a
preliminary layout for the diversion works, estimating quantities
required and applying unit costs to the quantities. The estimated
total construction cost for the diversion works is $6,473,000 at a
January 1983 level as shown in Table 5-1. The total construction cost
includes 25% for contingencies and 15% for engineering and construction
management, but does not include interest during construction.
Assuming 3.5% interest based on Power Authority guidelines, and a 50
year amortization of the total construction cost and $15,000 per year
for O&M and other costs, the estimated annual cost is $292,000 at a
January 1983 level.
The costs for the Ptarmigan Creek diversion is based on preliminary
layouts and sizes for project features. Quantities for the various
project features were estimated and unit costs were applied. Cost
estimates for major equipment items were based on experience and
manufacturers' information. The estimated total construction cost for
the Ptarmigan diversion is $384,000 at a January 1983 level as shown in
Table 5-2. The total construction cost includes 25% for contingencies
and 15% for engineering and construction management, but does not
include interest during construction. Assuming 3.5% interest in
accordance with APA criteria for a 50 year amortization of the total
construction cost and $50,OOO/year for O&M, the estimated annual cost
is $66,400 at a January 1983 level.
5-6
2223B
5.2.6 Cost of Power
The Stetson diversion would increase plant generation by 10,162,000 kWh
per year at a cost of approximately 29 mills per kWh based on the
January 1983 annual cost of $292,000. The Ptarmigan diversion would
increase net generation by 1,314,000 kWh per year at a cost of about 51
mills per kWh based on the estimated January 1983 annual cost of
$66,400. Based on a comparison of the 1eve1ized cost of energy from
gas-fired combined cycle combustion turbines (51 mills/kWh, as derived
from infonmation contained in Table 111-16 in the Technical Appendix)
the Stetson diversion would be clearly economical and the Ptarmigan
diversion would be marginally economical.
5.3 COOPER LAKE CAPACITY EXPANSION
In view of Chugach Electric Association (CEA) owning and operating the
Cooper Lake Project, the evaluation of capacity additions must take
into account the regional CEA system. The report Alaska Electric Power
Statistics 1960-1981, dated August 1982, lists the total CEA installed
capacity at 507,800 kW and a total peak demand of 330,700 kW. The
various components of the installed capacity include 421,300 kW of gas
turbine capacity, 71,500 kW of steam turbine capacity and 15,000 kW of
hydro capacity. The total 1981 net generation was 1,472,670,000 kWh of
which 1,414,919,000 kWh was supplied by gas and 57,751,000 kWh supplied
by hydro.
The Cooper Lake Project has an installed capacity of 15,000 kW, the
capacity that was recommended in the Definite Project Report, if the
Stetson and Ptarmigan diversions were also constructed. Review of
operating summaries for the years 1977 through 1981 indicate that no
water was spilled from the reservoir. In addition, the operating
reservoir levels experienced over the period 1977-1981 indicate that
substantial additional storage has been available but not used. The
unused storage could, on the average, store the additional water from
the Stetson and Patrmigan Creek diversions for an entire year. In view
5-7
of the above and considering that the average plant factor for the
period 1977-1981 was 40 percent, the installation of additional
capacity at the powerhouse would not provide any additional energy
generation over that which could be generated with the existing
equipment.
In a low water year equivalent to that experienced in 1952, with a
minimum reservoir elevation of 1,166, and with the diversions from
Stetson and Ptarmigan Creeks in place, the dependable capacity is less
than the present installed capacity. There is, therefore, no
dependable capacity benefit to be derived from the installation of
additional generating equipment.
In addition, It is apparent from the relatively large amount of gas
turbine generation on-line in the CEA system at any given time, and
excess gas-fired turbine capacity above the peak demand, that capacity
and spinning reserves are presently adequate in the CEA system with
respect to any potential capacity expansion at the Cooper Lake Project.
5.4 CONCLUSIONS
In summary, based on these prefeasibility level investigations, there
would be no additional benefits for any capacity expansion and
therefore, any expansion involving additional units cannot be
justified. This being the case, a preliminary cost estimate was not
developed for a capacity expansion using an additional unit or units.
Also, based on this prefeasibility investigation, additional energy can
be produced by the incorporation of the Stetson Creek diversion at a
cost that appears to be attractive, while the Ptarmigan Creek diversion
appears to be marginally attractive. The gain in energy is not large
and its realization would require an application for amendment of the
existing license held by CEA which includes review and comment by the
agencies. Also, the feasibility of the diversions would be adversely
affected by a revision in previously designated minimum streamflow
requirements.
5-8
TABLE 5-1
STETSON CREEK DIVERSION
PREFEASIBILITY LEVEL COST ESTIMATE SUMMARY
1.0 Mobilization
2.0 Reservoir Clearing
3.0 Diversion & Care of Water
4.0 Darn and Spillway
5.0 Diversion Conduit
6.0 Mechanical Equipment
1.0 Access Roads
Direct Construction Cost
Contingencies @25%
Subtotal
Engineering & Construction
Management @15%
Total Construction Cost
Debt Service '£/
Operation and Maintenance
Total Annual Cost
Average Annual Energy (kWh)
Cost of Energy (mills/kWh)
1/ January 1983 level.
'£/ 50 years @ 3.5% interest
5-9
2223B
1/ Cost-
$ 214,000
5,000
30,000
422,000
2,911,000
61,000
800 1 000
4,503,000
1,126 1 000
5,629,000
844 1 000
$6,413,000
261,000
25 1 000
292,000
10,162,000
28.1
TABLE 5-2
PTARMIGAN CREEK DIVERSION
PREFEASIBILITY LEVEL COST ESTIMATE SUMMARY
1.0 Mobilization
2.0 Reservoir Clearing
3.0 Diversion & Care of Water
4.0 Overflow Sill
5.0 Pump Station
6.0 Pipeline
7.0 Mechanical Equipment
8.0 Electrical Equipment
9 0 T .. L· 2/ . ransmlSSlon lne-
10.0 Access Roads
Direct Construction Cost
Contingencies @25%
Subtotal
Engineering & Construction Management
Total Construction Cost
Debt Service ~/
Operation and Maintenance
Total Annual Cost
$ 13,000
2,000
5,000
6,000
77 ,000
27,000
65,000
40,000
30,000
2,000
267,000
67,000
334,000
50,000
$384,000
16,400
50,000
66,400
Average Annual Energy Generated (kWh) 2,190,000
Pumping Energy Required (kWh) 876,000
Net Average Annual Energy (kWh) 1,314,000
Cost of Energy (mills/kWh) 50.5
1/ January 1983 level.
£/ As power source for pumping station.
~/ 50 years @ 3.5% interest
5-10
2223B
N
o 4800
~ ______ ~I~ ______ ~'FEET
SCALE
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
COOPER LAKE ALTERNATIVES
STETSON AND PTARMIGAN
CREEK DIVERSIONS
DATE FEB 1983 FIGURE][ -1
EBASCO SERVICES INCORPORATED 5-11
PART III
DAVES CREEK-SEWARD TRANSMISSION
LINE INVESTIGATION
6.0 DAVES CREEK -SEWARD TRANSMISSION LINE
6.1 HISTORICAL DATA
The City of Seward was incorporated in 1912, but it had its official
beginning much earlier, on August 23, 1903. By 1905 private companies
were supplying both water and electricity to the City. A hydroelectric
plant located at the foot of Jefferson Street on Resurrection Bay
utilized water from Lowell Creek to generate electricity. This plant
has since been abandoned. In 1938, the City formed its own electric
system and constructed a diesel-electric generating plant on the shores
of Resurrection 8ay near what is now Seventh Avenue and Armstrong
Street. The Seward electric system was then in competition with the
privately owned Seward Light and Power Company. The two organizations
competed for customers until 1951 when the City took over the Company1s
system.
In 1955, the City began the planning and construction of a transmission
line designed for 69 kV, but initially energized at 24.9 kV, between
the City and Milepost 25 on the Seward-Anchorage Highway. The
construction of this line was the initial step in an effort to provide
an adequate power supply for the City and for the cities of Homer and
Kenai. The plan included the construction of a hydroelectric power
plant at Crescent Lake, about 32 miles north of Seward. The Crescent
Lake project was later abandoned and, on June 1, 1961, Seward entered
into an agreement with Chugach Electric Association to purchase
wholesale power with delivery at Milepost 25, which became known as
Lawing metering station.
Chugach constructed a 24.9 kV transmission line from a transformation
tap off its 115 kV transmission line near Daves Creek to connect to the
Lawing metering station. This line was built to 24.9 kV standards.
The line continues to be the main source of electric power for Seward
and numerous taps exist to serve consumers along the entire length of
both the Chugach section and the Seward section of the line.
6-1
2611 B
6.2 ELECTRICAL CONDITIONS
The transmission line from Daves Creek sUbstation to Seward substation
has a 4/0 ACSR (Alum w/center of steel reinforcing) for its entire
40 mile length. The Chugach section of the line from Lawing to Daves
Creek is built as 24.9 kV construction using wood poles with horizontal
wood crossarms. The Seward section of the "line from Lawing to Seward
sUbstation is built as 69 kV construction on wood poles using various
configurations such as vertical compact without crossarms, wish bone
construction with crossarms, and H-frame with crossarms.
This 24.9 kV transmission line is at its capacity limit. The city's
current peak load of approximately 6 MW results in a line loss of
approximately 20%. The voltage drop during peak loading of the line is
greater than 15% as shown in the Technical Appendix Part V. However,
this voltage is able to be raised by load tap changers on the main
incoming transformers in Seward sUbstation. Voltage levels can also be
raised by running Seward's Emergency Diesel Generators, which are
located at Seward substation. It is reported that in fact it has been
necessary to start these generators during peak loads to maintain
reasonable voltage levels. It also has been reported that when an
outage from Chugach Electric occurs, the tie is opened and once Chugach
power is restored, the open circuit voltage is too high to reclose with
Seward's voltage levels as supplied by their diesel. These diesels are
also expensive to operate.
Information on existing electrical conditions was obtained from field
trips, from City of Seward officials, and past report and drawings. A
one-line diagram and plan of the system as it now exists, as well as
planned modifications, are shown in Figures 111-1 and 2.
Various reports have been completed in the past which give a fairly
complete description of Seward's system. The most recent report was
prepared by Dwane Legg Associates in October 1982 and is titled
Analysis of Volta~_~and Energy Losses. The City Engineer of
6-2
26116
Seward also submitted information on conditions in an August 30, 1982
memorandum to the City Manager. A summary of existing reports, that
became available to Ebasco is provided in Section 19.
6.3 PHYSICAL CONDITIONS
The existing transmission line from the City of Seward to the
substation at Daves Creek is over 25 years old. Many of the 60 foot
poles from the city to Milepost 7 have been replaced, but the poles
from Milepost 7 to the metering station are the original poles and
consequently are in poor condition. Likewise, Chugach's line from the
metering station to Daves Creek is generally the original construction
and near the end of its economic life.
The transmission line is adjacent to the Seward-Ancorage highway from
the city to Milepost 7 and between Mileposts 23 and 26. For the
remaining length, the line is located on its own right-of-way. The
transmission corridor is up to 3000 feet from the highway as shown on
Figure 111-2, Sheets 1 and 4. Where the transmission line is remote
from the highway, access to the line for maintenance and repair is
extremely difficult in the winter. In addition, portions of the line
between Lawing and Daves Creek are inaccessible in the summer due to
swampy conditions.
Areas of the transmission line are subject to avalanche damage. The
area that is reported to be most effected is between Milepost 18 and
Milepost 23. Some avalanche problems are reported near Moose Pass
(Milepost 34) and the junction of the Seward and Sterling highways
(Milepost 37).
6-3
2611B
7.0 LOAD FORECAST
7.1 HISTORICAL DATA
Since the initial connection of the transmission line, the City has
continued to purchase power from Chugach. The City's load has shown a
steady growth over the years with an average annual rate of growth in
excess of 10 percent from 19&7 to 1980; however, since 1980 the peak
load growth has been less than 5 percent per year reflecting the
general economic conditions in the period.
The peak demand in recent years has ranged between 5.0 and &.7 MW with
1979 being the peak year. The system load factor is approximately 0.55
with a maximum energy consumption of approximately 27 million kWh in
1981 (see Table 2-3).
7.2 RECENT AND PLANNED DEVELOPMENTS
The City of Seward has recently completed the initial site work, and
construction is underway, on a new Seward Marine Industrial Park. This
development is located about six miles southeast of downtown Seward
where the Fourth of July Creek flows into Resurrection Bay.
Approximately 2&0 acres have been developed at a cost of $31 million.
The City anticipates that development of this industrial area,
expansion of the existing small boat harbor, and the supporting
infrastructure will add significantly to the City's electric demand and
energy needs.
7.3 DESIGN LOAD ELECTRICAL PEAK DEMAND
Section 2.3 of this report entitled "Seward Area Demand and Energy
Forecast," describes the development of the electrical demand and
energy forecast to be used in the evaluation of the existing and any
proposed new transmission lines for the City of Seward. The load
7-1
5595B
forecast extends over the 20 year planning period and includes the
increased loads in the mid 1980s resulting from the industrial
developments in the City.
Based on the medium growth scenario defined in Section 2.3, the maximum
demand in 2003 is approximately 20 MW and the eneergy requirement is
105 million kWh.
7-2
5595B
8.0 TRANSMISSION REQUIREMENTS
8.1 GENERAL
The general requirements of the upgraded transmission system are to
provide the following:
o a means of supplying Seward's projected load growth,
o a means of tying in the output of the proposed Grant Lake
Hydro Project to Seward and other Kenai Peninsula loads, and
o a means of accepting the output of other generation resources
that may be developed (such as Bradley Lake hydro or Kenai
area thermal) to meet the projected load for the Seward area.
8.2 SELECTION OF LINE DESIGN
A number of alternative designs were evaluated to meet the above
requirements. The alternatives evaluated and the conclusions reached
concerning each alternative are given in the following paragraphs.
8.2.1 Continued Use of the Existing Line
The continued use of the existing 24.9 kV line would result in
substandard service voltages and high energy losses. It would be
mandatory that the Seward generators be operated at peak-load times to
prevent voltage levels from dropping to completely unacceptable
levels. As the system load continues to grow, it would become
necessary to operate Seward's diesel generators more hours each month,
which will cause power costs to rise. It may become necessary to buy
additional diesel generators to meet the rising load as well as to
replace the existing units as they reach the end of their economic life.
8-1
559&B
Correcting power factor by adding capacitors on the existing line will
only cause an insignificant increase in voltage level, and minimal
decrease in energy losses. This would at best be only a temporary
solution and would not last for the 20 year planning period. Providing
automatic voltage regulators would also be a temporary solution and
would be very expensive. It would be possible, by installing a
sufficient number of regulators, to provide proper levels of service
voltage, but losses would continue to increase as Seward's load grows.
8.2.2 Convert to 69 kV Transmission Voltage
This alternative would be implemented by operating the existing line
from Lawing to Seward at 69 kV and by building a new 69 kV line from
Daves Creek to Lawing or converting the existing one. A 115 kV to
69 kV autotransformer would be located at Daves Creek Substation
instead of the Seward Substation. This alternative was studied for
several cases using various conductor sizes and a computerized load
flow program. The results of the evaluation are given in Appendix
111-1 and are summarized below.
o The first case considered used 4/0 ACSR conductor from Daves
Creek to Seward with a total load of 20 MW at Seward. The
voltage drop to the Marine-Industrial Park was just over 34%
and the power loss was just over 23%. Both of these values
are unacceptable.
o The second case evaluated was the same as the first except
that a 556 kCM ACSR conductor was used. The voltage drop at
the Marine-Industrial Park was just over 18% and the system
loss was 5.5%. This voltage drop is generally too high,
although the power loss ;s more acceptable.
o The last case evaluated a 1590 KCM ACSR conductor alternative,
which is a very large conductor. The system power loss was at
low value of 2.8% and the voltage drop to the
8-2
5596B
Marine-Industrial Park was still 15%. The voltage could be
raised to reasonable levels by transformer tap changers,
however, this line would be expensive to build because of the
large size conductor.
The studies show that to convert the existing line to 69 kY can barely
be considered feasible even as a shorter term solution. In addition to
the obstacles listed above, several concerns exist on using the
existing line from Lawing to Seward. Some of these are as follows:
o The existing line is over 2S years old and wood poles have an
estimated life of 30 years. It has been reported that only
few poles have been replaced between Mileposts 7 and 25.
o Provisions would have to be made for supplying customers that
are now fed directly off this line north of Milepost 9.
o Insulators would need to be inspected and replaced as
necessary before operating at 69 kY. Also, the number of
discs per insulator varies from 4 to 6 on the existing line,
raising the question as to varying dielectric strengths.
o The line would still be subject to the avalanche conditions
previously described.
o There would be no emergency tie, as described in Section 10.5.
o The cost of an all new 69 kY line from Lawing to Seward with a
556 ACSR conductor would not be significantly lower than the
cost of a 115 kY line and would still have marginal voltage
conditions.
o The mechanical strength of all existing poles, even recently
replaced ones, would need to be checked for adequate strength
for the loading conditions mentioned in Section 9.2.4 with a
conductor at least as large as a 556 kCM ACSR.
8-3
8.2.3 Combination 115/69 kV Transmission
This alternative would require a new 115 kV line from Daves Creek to
Lawing, a 115-69 kV substation at Lawing, and operation of the existing
line from Lawing to Seward at 69 kV.
Although this alternative seems to be viable, it has all the concerns
of the 69 kV line mentioned above as well as concern about the
mechanical strength of the existing 4/0 ACSR conductor, as indicated by
the sag and tension computer calculation given in Part V of the
Technical Appendix. These calculations show that with the existing
spans this conductor does not comply with current codes.
8.2.4 115 kV Transmission Line
The voltage selected for the transmission line from Daves Creek
Substation to the City of Seward substation is 115 kV. The selection
of this voltage is based on the following:
o Computerized load flow studies indicate this to be the optimum
voltage for supplying the projected load growth to 20 MW in
terms of maintaining acceptable voltage levels and minimizing
power losses. The results of the load flow studies are
presented in Part V of the Technical Appendix. The data show
that a voltage drop of around 8% would occur between Daves
Creek and Seward Substation. This is a very reasonable
voltage drop and is within the range that can be accomodated
on the 115 kV transmission line that supplies Daves Creek.
The 115 kV Daves Creek-Seward line should have lower voltage
dips, compared to a lower voltage transmission line during
starting of large electrical motors that may be added at the
Marine-Industrial Park in the future.
o The estimated life of a wood pole transmission line is 30
years. While the proposed 115 kV line is marginally optimum
in terms of the 20-year estimated projected load growth to 20
MW, its economic benefits continue to increase for the
remaining 10 year life of the line to effectively supply power
to the City of Seward, assuming loads continue to increase
with time.
o 115 kV is the voltage level of the line that supplies Daves
Creek substation and thus its use eliminates the need for
intermediate transformation at Daves Creek. Further, the main
transmission system between the major Kenai Peninsula
substations of Girdwood, Portage, Hope, Quartz Creek,
Soldotna, and Bernice Lake is a 115 kv system. The proposed
Seward line is, therefore, a logical extension of the existing
system.
B.2.5 Configuration
The type of line construction selected is the Vertical Compact
construction on single wood poles. This construction is described in
the EPRI Transmission Line Reference Book; 115-13B kV Compact Line
Design which is shown in Part V of the Technical Appendix. This type
of construction is used on portions of the existing 24.9 kV
transmission line, for example, in the area where the Seward-Anchorage
Highway crosses the Snow River and on the 69 kV transmission line to
the Seward Marine-Industrial Park. The advantage of vertical compact
line construction is that it has the least negative visual impact since
no crossarms are used on normal spans. Only those portions of the line
that have a lower voltage underbuild will have crossarms mounted onto
the poles. However, these crossarms are for the low voltage underbuild
and are therefore below the pole tops and have low visible impact.
B-5
5596B
8.2.& Conductor Selection
The conductor selected for the 115 kV line is 33&,400 circular mil
aluminum cable, steel-reinforced, also known as 33& KCM ACSR. ACSR
conductors are widely used by electrical utilities and are the type
used on the existing system in various sizes. Specifically, the 336
KCM conductor selected has 30 outer strands of aluminum and 7 inner
strands of steel and is designated by the code word Oriole.
This conductor size was determined primarily by mechanical strength
requirements rather than thermal limits due to electric loading of the
conductor. This means that the line can carry more than normal load
current before overheating.
8.2.7 Mechanical Considerations
The mechanical considerations of the line were evaluated using the
results of hand and computer calculations on sag and tensions for
various conductor sizes and spans. The following were used as
preliminary design parameters:
NESC modified heavy loading
Ice loading: 1" radial
Temperature: -25°F to 120°F
Wind: Up to 110 mph (31 lb/sq ft.)
Part V of the Technical Appendix gives details on this aspect of the
line design. Some of the main items to be considered in line
evaluation are the following:
o The National Electrical Safety Code requires that the normal
final stress be no more than 25% of rated tensile strength
(RTS) stress and no more than 35% RTS for the initial stress.
8-&
559&B
o The National Electrical Safety Code also requires that the
final stress under ultimate load be no more than 60% of RTS;
however. it is preferred not to exceed 50% RTS.
o The Electric Power Research Institute guidelines for phase
spacing is acceptable. This affects maximum sags.
o The National Electric Safety Code clearance requirements also
affect maximum sags.
The smallest size ACSR conductor that meet these and other requirements
is 336 KCM. Oriole for spans ranging between 400 and 450 feet. The
existing 4/0 ACSR conductor was evaluated so that it might be used on
existing poles. but was found to exceed today's codes and practices on
line design. Results of this investigation are also shown in the
Technical Appendix.
The type of insulator to be generally used with this compact type of
construction is a non-porcelain type. One manufacturer's type of
insulator is made of fiberglass rod and polymer compound exterior
watersheds. This type of insulator has three times the strength
accompanied with a weight reduction of 10 to 20 times of that of the
porcelain variety. Since this type of insulator is lighter and
stronger. it is less subject to careless handling and is also much less
subject to vandalism.
The proposed transmission line will be constructed of Class Hl wood
poles with an estimated average height of 60 feet. It is presently
planned that long spans at the Snow River crossing between Milepost 17
and 18 be constructed with tubular steel poles. This crossing occurs
at the mouth of the Snow River as it flows into Kenai Lake. The river
crossing area is swampy and many of the poles are in water. The new
line is routed in the same area and similar foundation conditions can
be anticipated.
8-7
55968
8.3 PERFORMANCE EVALUATION OF SELECTED LINE ALTERNATIVE
The proposed 115 kV transmission line was modeled with a load flow
computer program to verify its performance for different operating
conditions. The model was set up using 336 KCM ACSR conductor with
resistances and reactances as shown in Part V of the Technical
Appendix. The first case considered no generation from Grant Lake, no
city diesel generation, and a total load of 20 MW (10 MW at Seward
Substation and 10 MW at Marine-Industrial Park).
The results indicate that the City of Seward's main 12.47 kV bus has a
voltage drop of slightly over 8% which can be corrected by the existing
load tap changers. The voltage at the Marine-Industrial Park has a
drop of just over 11% which also can be corrected with transformer
taps. The amount of energy loss for this condition is 0.63 MW, which
is 3.2% of the 20 MW load.
The second case is the same as the first except that the Grant Lake
project is on line. The results are very similar to the first case
except that the load bus voltages are slightly higher. In this case
Grant Lake Hydro is fully loaded and absorbs reactive power within its
midrange rating. Only slight improvements in voltage at the load buses
can be expected, since Grant Lake is much closer to Daves Creek (13
miles) than to the city load buses (27 to 33 miles) and the Kenai
Penninsula system load is much larger.
The line performance was also investigated at 10 MW and 30 MW loads to
verify operation at these levels. The results of all the studies are
in Part V of the Technical Appendix and show that the voltage drops and
power losses under the tested conditions are acceptable for the
forecast loads.
8-8
55968
8.4 CORRIDOR
8.4.1 General Plan
In selecting the transmission corridor, accessibility was a prime
consideration. Because of the existence of the highway generally
paralleling the transmission line, access has been assumed to be by
overland vehicles and not by helicopter. As mentioned in Section 6.3,
access to the existing line is difficult in certain areas at different
seasons of the year. In order to improve the access, the basic
corridor plan uses a combination of the existing transmission
right-of-way and newly obtained permits in the Alaska Highway
Department of Transportation right-of-way (Seward-Anchorage and
Sterling Highways). The general plan for the transmission line from
the Seward Substation to Daves Creek Substation is as follows.
o From the city (Milepost 0) to Milepost 7: Install new poles
in existing locations next to the highway as indicated on
Fig. 111-2. Existing poles that have recently been replaced
in this reach, and that meet detailed design criteria for the
proposed 115 kV line, may be retained.
o From Milepost 7 to Milepost 23: Install new poles on
Seward-Anchorage Highway right-of-way as shown on Fig. 111-2.
The existing transmission line right-of-way is generally to
remain as is.
o From Milepost 23 to Lawing Metering Station (Milepost 25), the
new transmission line will follow the routing of the existing
transmission line along the Seward-Anchorage Highway.
o. From Lawing Switching Station to Daves Creek (Milepost 41) the
new routing will generally be along the Anchorage-Seward
Highway instead of the right-of-way for the existing 24.9 kV
line. In some areas, the 24.9 kV line is presently routed
8-9
5596B
along the highway and it may be necessary to use the existing
transmission line right-of-way, due to limited highway right-of-way or
other problems. Conflicts of this nature will have to be resolved on a
case by case basis during final design of the transmission line.
8.4.2 Special Considerations
8.4.2.1 Avalanches
The segment of the existing line from Milepost 18 to Milepost 23 is
subject to damage from frequent avalanches. The existing line is now
located up to 1000 feet away from the highway on the uphill side as
shown on Fig. III-2. The proposed new line has been located on the
downhill side of the highway to place it further from the avalanche
chutes, where it would receive some protection from the highway and
where it can be more easily replaced if damaged by an avalanche.
The City of Seward has tried various types of line construction in the
avalanche areas. One unsuccessful construction was to build the line
very heavy with substantial pole structures. However, the conductors
and poles were still knocked down by the avalanches. This happened
even with avalanche deflectors located uphill from the structures.
When the conductors and poles were knocked down, the reconstruction of
the line has taken as much as several days because the wood poles were
broken at the snow line and pole replacement vehicles and equipment
could not get to the line to effect the replacement.
The best type of construction experienced by the City of Seward in
avalanche prone areas was to design the line so that the conductors
will break away during avalanches without pulling the poles and
supports down. This was accomplished by installing breakway devices in
the conductors and locating structures outside of the avalanche
chutes. The rationale of this approach is that though an outage will
still occur, the outage will be substantially less because the poles
are likely to remain intact. The relocation of the transmission
8-10
5596B
line downhill of the highway. within the 1atter 's 100 foot wide
right-of-way. would not only lessen avalanche danger to the line. but
would also make repairs much easier and faster by making the line much
more accessible. Construction of the transmission line in all
avalanche prone areas must consider the access to the line and the time
required to effect the repairs. During detailed design. the areas of
most active avalanche chutes. would be specifically defined. This
definition would permit optimum placement of supports. the
consideration of special structures. and the use of long spans to
reduce likelihood of pole damage and resulting line outage.
8.4.2.2 Environmental Assessment
Final detailed definitions of the route for the Daves Creek-Seward
transmission line will require conducting a comprehensive analysis of
engineering and environmental constraints. both of which influence the
final route. Various sections of this report discuss the engineering
constraints considered in the feasibility phase of the Daves
Creek-Seward transmission line design. Though efforts were made during
the study to consider environmental constraints. no detailed
environmental evaluation of the proposed Daves Creek-Seward
transmission line has been conducted. Therefore. the transmission line
route depicted in Figure 111-2 is subject to change following a
detailed environmental evaluation.
An environmental study of a proposed transmission line involves the
investigation of the topography. geologic hazards. soils. land use.
socioeconomics. aesthetics. cultural resources. aquatic and wildlife
resources. The proposed Daves Creek-Seward transmission line described
herein is. for the most part. routed along the right-of-way of the
existing transmission line or within the right-of-way of the
transportation corridor. Consideration in this proposed route
selection has been given to the topography. geologic hazards. land use
and avalanche potential. The major emphasis of the required detailed
environmental study should be an analysis of the proposed line's impact
on aesthetics. cultural resources. and aquatic and wildlife resources.
8-11
55966
The design selected for the proposed transmission line has considered
the impact on the aesthetics, and components of the transmission line
have been selected to minimize the impact by using single wood poles,
and low profile sUbstation configuration that can easily be screened by
the existing vegetation.
During the detailed environmental evaluation, coordination with the
relevant federal, state and local agencies would be continued and the
final transmission line and equipment location would be adjusted, if
necessary. The detailed environmental study would need to begin with
the onset of engineering design and has to be completed in a timely
manner to meet the engineering/construction schedule. If delays are
incurred as a result of the environmental evaluation, then the
engineering/construction schedule could be delayed.
8.5 GEOTECHNICAL CONDITIONS
This section characterizes the geologic and soils conditions for the
Seward to Daves Creek transmission line corridor. The regional geology
is presented in three parts: morphology, stratigraphy and lithology,
and geologic structures. Seismicity is also addressed.
8.5.1 Morphology
The morphology of the project region is generally of sub-arctic,
glaciated terrains. Broad U-shaped valleys dissect the mountain ranges
and form lowlands with lakes, ponds, and streams. Elevations in the
project region range from sea level at the City of Seward to over 5000
feet in the adjacent mountains. Much of the~ region was stripped clean
by the movement of glaciers, leaving bedrock exposed over large areas.
The transmission line route lies completely in lowland regions, which
are typically elongated with varying amounts of infilling. Streams are
common in the lowland areas, as are lakes and ponds. Small bogs,
8-12
559&B
formed in bedrock depressions resulting from glacial scour, are common
on the ridge tops. Such bogs are also present at lower elevations, one
example being Tern Lake.
8.5.2 Stratigraphy and Lithology
The bedrock in the project region is a complex assortment of
metamorphosed sandstone, siltstones, and mUdstones interbedded with
volcanic basalts and detritus. The predominate rock types in the
project region are low grade metamorphosed sedimentary rocks, including
slates and meta-sandstones. Unconsolidated surface deposits are
relatively rare in the project area and are typically mixtures of silt,
sand, and gravel. Soils in the project area vary from very gravelly
well drained soils to no soil cover and as such are classified as non
frost susceptible. Frost heave should therefore not be a major design
parameter.
8.5.3 Geologic Structures
The predominant geologic struture in the transmission line corridor is
the "Kenai Lineament". "Kenai Lineament" is used to refer to the Trail
Lakes valley, which is a north-trending valley that extends from the
City of Seward to Upper Trail Lake. The trend of the valley is nearly
parallel to the north-northwest fault set observed in the region, and
the Kenai Lineament may represent one of these fault zones that was
extensively eroded during the glacial period. It is unlikely that the
Kenai Lineament represents a major, active fault. More likely it is a
glacial valley whose orientation and location followed the
north-northwest trend of the major fault set observed in other areas.
Features observed throughout the area during the field investigations
repeatedly emphasized the effects of the great thickness of ice that
once moved through the region, with minor differences in rock strength
or fracturing resulting in major differences in the extent of erosion
in response to the forces of moving ice.
8-13
559&B
8.5.4 Seismicity
The Seward to Daves Creek transmission line corridor lies completely
within earthquake zone four, which indicates very severe seismic
conditions.
8.6 RIGHT-Of-WAY
The location of the 115 kV line, as discussed in the corridor section,
will require rights-of-way for the line and the substations.
8.6.1 Alaska Department of Transportation
The Department of Transportation built the Seward and Sterling Highways
upon which new poles are to be set. The highway right-of-way is
generally 200 ft. wide. Placement of poles within the highway
right-of-way is an important part of this proposal. The following
noteworthy information was received verbally from the Alaska Department
of Transportation.
o State accommodation policy (Alaska Statute 19) allows public
utilities to put poles into highway right-of-way under
permit from the Department.
o Poles should generally be at least 30 feet from the edge of
the travelled way.
o It is preferred that utility poles be only on one side of the
road.
o There are no apparent plans for major construction projects
from Milepost 7 to Daves Creek.
o The highway between Mileposts 18 to 23 is not closed too
frequently due to avalanches.
8-14
55968
o It would take 2 to 4 weeks to process a permit for pole
easements.
o Alaska Department of Transportation accepts National Electric
Safety Code. Minimum required clearance at crossings is now
18 feet with probable increase to 20 feet next year.
o Costs associated with Department of Transportation inspection
of work in their right-of-way will be charged to the owner of
the line.
8.6.2 Other Agencies
It is generally planned that a minimum amount of right-of-way will be
required from the Alaska Railroad. The City of Seward reports mixed
success in obtaining right-of-ways in the past. However, it may be
possible to obtain permits, as is reported to be done on the 345 kV
intertie that is just beginning to be constructed between Healy and
Willow.
Some right-of-way will be required from the forest service. Special
use permits for the right-of-way can be applied for following forest
service procedures which consider environmental, engineering, and
compatible use considerations.
Some right-of-way may be required from private property owners in areas
where the highway right-of-way is very narrow or when land is needed
for a substation. Some right-of-way will be required on city property
and roads which should not be a problem.
The existing Chugach Electric 24.9 kV transmission line runs mostly in
its own right-of-way. Since some of the new line would be located on
Chugach's right-of-way, easements or some other forms of agreement will
be required with Chugach and the forest service on whose land a major
portion of the Chugach line is located. Further details are presented
in Section 8.8 on Interface with Chugach Electric Association.
8-15
55968
8.7 SUBSTATIONS AND SWITCHING STATIONS
8.7.1 City of Seward Substation
The City of Seward Substation now provides for switching and
transformation of the existing 24.9 kV incoming transmission line. In
order for this sUbstation to be able to accept the 115 kV transmission
line, the following additional equipment will be added, as shown on the
one-line diagram, Fig. 111-1:
o Two 115 kV to 69 kV, 15 MVA autotransformers
o Two 115 kV circuit switchers
o One 69 kV circuit switcher
There is enough room for this equipment within the existing substation
area. However, the layout and specific requirements will be defined
during the final design. Fortunately, the 24.9 kV side of this
sUbstation is already designed for 69 kV operation. This includes the
two 7.5 MVA main transformers that have a dual voltage (24.9 kV/69 kV)
primary windings. Based on the assumption that both transformers can
be used to supply the load, they should have adequate capacity for the
next 20 years if most of the major load growth takes place at the
Seward Marine-Industrial Park. At sometime in the future, a third
transformer may be required to provide reserve capacity for maintenance
in case of equipment failure.
lhe Seward Substation would have two transmission lines connected to it
after completion of the proposed work. One would be the main incoming
115 kV supply line for Seward and the other would be the outgoing 69 kV
line to the Seward Marine-Industrial Park.
The available fault short circuit duty will be increased substantially
from its present value as a result of these modifications at Seward
Substation. Part V of the Technical Appendix, contains the results of
a study of worst case conditions for a fault. From this study, it is
8-16
5596B
concluded that the circuit switchers on the 69 kV side of this
sUbstation (rated 4000 Amp) will be able to interrupt this new fault
value of 1495 Amp. The equipment on the 12.47 kV side of the
substation will still be adequate, since the available fault duty is
reduced to about 100 MVA by the 69 kV to 12.47 kV transformers.
8.7.2 Lawing Metering Station
This station now serves as a metering point between the City of
Seward's system and Chugach's system. This station also has a 24.9 kV
recloser with fused bypass. This recloser is radio controlled from
Seward. If the metering point for the new 115 kV line is located at
the Daves Creek sUbstation then no new equipment will be required at
Lawing.
8.7.3 Grant Lake Hydro Switching Station
This switching station would be a new station and would function as the
115 kV tie-in point of the Grant Lake Hydro Power to the Kenai
Peninsula power grid. The main new equipment that would be installed
would be three 115 kV disconnects. One 115 kV disconnect would allow
the 1.2 mile long 115 kV transmission line from Grant Lake powerhouse
switchyard to be disconnected from the 115 kV line running from Daves
Creek to the City of Seward. One of the other 115 kV disconects would
function to isolate Grant Lake and the City of Seward loads from
Ch~gach's system; this could prove to be of great benefit when problems
on Chugach system occur, because it would allow the City of Seward to
still receive power from Grant Lake Hydro plant. The third switch
would allow Seward to be disconnected for problems or maintenance and
still allow Grant Lake Hydro to stay on line by supplying power to
Chugach's system, if so desired. The arrangement is shown on the
one-line diagram Fig. 111-1.
8-17
55968
B.7.4 Daves Creek Substation
The existing Daves Creek Substation is part of Chugach Electric
Association's system and serves as the source of power for the 24.9 kV
transmission line that supplies the City of Seward. The incoming
voltage to this sUbstation is 115 kV which comes from a tap on the 115
kV line between Portage and Quartz Creek Substations.
With the proposed transmission line this substation will serve as the
tie-in point to the Chugach System. The new major equipment required
at Daves Creek is a 115 kV circuit breaker, revenue metering equipment,
and equipment for termination of the 115 kV line. The exact location
of this equipment would need to be coordinated with Chugach Electric
during detailed design phases.
As a result of Grant Lake Hydro, the three phase short circuit capacity
at Daves Creek would be increased from the present 324 MVA to
approximately 363 MVA at 115 kV as shown in Part V of the Technical
Appendix. This small increase is not anticipated to have a severe
impact on this substation.
B.7.5 Milepost Nine Substation
The existing 12.47 kV distribution line, that runs north out of the
city, ends at Milepost 9. This line serves customers along its route.
From Milepost 9 to the Lawing Metering Station, Seward customers are
served from the 24.9 kV line. The customers along this 16 mile section
could be served by installing a transformer at Milepost 9 to step up
the 12.47 kV voltage to 24.9 kV and connecting the high voltage winding
to the existing line. The 24.9 kV recloser at Lawing will be opened.
This will mean that the normal power flow through this sUbstation will
be from the city out to Lawing.
During emergency operation, when the 115 kV line is out of service but
the 24.9 kV line is still in service, the 24.9 kV recloser at Lawing
would be closed and power would be supplied to the city and all
8-18
55968
customers between the city and the Lawing Switching Station through
this substation. The following major equipment is envisioned at the
Milepost Nine Substation:
o One 3 MVA, 24.9 kV to 12.47 kV transformer with load tap
changer.
o One 12.47 and one 24.9 kV fused disconnect switches.
The exact location of this sUbstation will be determined during
detailed design.
8.8 INTERFACE WITH CHUGACH ELECTRIC ASSOCIATION
In order to be able to perform the investigations presented in this
report, the following technical information on Chugach's 115 kV
transmission system and Daves Creek substation was obtained:
0 The short circuit duty at Daves Creek Substation on the 115
side is 324.5 MVA for a 3 phase fault and 294.1 MVA for a
phase to ground fault.
kV
0 The 115 kV line tapped to Daves Creek substation can handle a
load increase of about 30 MW.
Additional and updated information will be required for detailed design
activities connected with the new 115 kV transmission line serving
Seward.
8.8.1 115 kV Connection at Daves Creek
The design of the substation for connection at the new 115 kV
transmission line to Seward will have to be coordinated with Chugach
Electric. If the new 115 kV transmission line is generally routed in
the highway right-of-way as shown in Figure 111-2, the existing Chugach
24.9 kV transmission line from Daves Creek to Lawing will not be
8-19
55968
changed, except between Mileposts 36 and 39. In this segment the old
24.9 kV line would be underbuilt on the new 115 kV line, and ownership
of this line and the associated right-of-way would have to be agreed
upon with Chugach Electric Association and the Alaska Power Authority.
If the new 115 kV line will not be owned by Chugach Electric, then the
best location for revenue metering would be at the Daves Creek
substation area.
If negotiations with Chugach conclude that the entire existing 24.9 kV
transmission line and right-of-way between Daves Creek and Lawing be
acquired by the Alaska Power Authority, Chugach would be entitled to
compensation for this line. A detailed eva'luation of this transmission
line and property right would be required. It is estimated, on a gross
preliminary basis, that the cost of acquiring this line could amount to
approximately $200,000. Since the 24.9 kV line is located on a
right-of-way leased from the Forest Service, no cost for land is
included in this estimate. The cost of acquiring this transmission
line is not included in the estimate of the cost of the new 115 kV
transmission line to Seward.
8.8.2 24.9 kV Connection at Lawing
The existing interface with Chugach is at the Lawing Metering station
at Milepost 25. Customers south of the metering station are served by
Seward and those north of the station are served by Chugach. Service
of customers by the respective utilities will not change if the 24.9 kV
line south of Lawing is energized from the City and the 24.9 kV breaker
at Lawing is left open. If this arrangement is followed, the interface
between Chugach Electric and the City of Seward can remain as it is
except that the intertie breaker would normally be left open. The
breaker could be closed for emergency operation. The existing revenue
metering equipment could remain as is, if this proposal is accepted, to
serve for billing of emergency power. The new metering for normal
power would be at Daves Creek. Should emergency operation be desirable
from Seward towards the 24.9 kV Chugach system, some minor additions
will become necessary.
8-20
5596B
9.0 SUBTRANSMISSION REQUIREMENTS
9.1 EXISTING 12.47 kV LOADS FROM CITY OF SEWARD TO MILEPOST 9
The 12.47 kV distribution line, from Milepost 1 in Seward to around
Milepost 9, services loads along the highway going north of Seward.
This line can be underbuilt on the new 115 kV transmission line to
Milepost 7 and from there will remain as an underbuild on the old 24.9
kV line poles to Milepost 9 (Fig. 111-2).
9.2 EXISTING 24.9 kV LOADS FROM MILEPOST 9 TO LAWING METERING STATION
The SUbstation at Milepost 9 will step-up the voltage from 12.47 kV to
24.9 kV and service the small loads along the next 16 mile section of
highway (Fig. 111-2). In most locations this line section could remain
as it now exists. However, in some locations it would need to be
underbuilt on the new 115 kV transmission line. This line passes
through the high avalanche area betweem Mileposts 18 and 23. In this
area, the 24.9 kV line could be placed underground to improve the
reliability of this line for use as an emergency power source for the
city as discussed in Section 9.5 on emergency operation.
9.3 24.9 kV LOADS FROM LAWING METERING STATION TO DAVES CREEK
SUBSTATION
The loads along this 15 mile line section can continue to be served by
Chugach at present. In those areas where the proposed 115 kV and the
existing line occupy the same right-of-way, for example from Milepost
36 to 39 and 25 to 26, the 24.9 kV line could be underbuilt on the new
115 kV transmission line. However, most of the line would remain as it
now exists (Fig. 111-2).
9.4 SERVICE DURING CONSTRUCTION
If the construction of the new 115 kV transmission line can be
completed in the near future, service to the City can probably be
maintained during construction, by use of the Seward Diesel Power Plant
9-1
55976
with all 3 machines operating. As Seward's load increases, the ability
of the diesel plant to meet the load will become more questionable.
Most of the new line is planned to be installed separately from the
existing 24.9 kV line, which helps to provide service during
construction since the latter can be kept energized. However, there
are areas where the new line will be built on the right-of-way of the
old line. Some possible considerations for minimizing service
distruptions are as follows:
o Rent or purchase additional diesel generators that can be used
to provide service during line outages. Either small units
for residential loads or large units for in city use can be
considered.
o Schedule line outages for minimal cutover time.
o Maximize work during summer months when load is lower and
effects of outages are less severe.
o Develop a sound approach regarding work around energized lines
versus time of service outages.
9.5 EMERGENCY OPERATION
With the substation at Milepost 9 installed, limited power transfer
between Seward's and Chugach's system can be provided should service
from the 115 kV line be interrupted. This emergency arrangement would
use the existing 24.9 kV line from Daves Creek to Milepost 9 and the
existing 12.47 kV distribution line from Milepost 9 into the city. By
using of this emergency tie and the city's diesel generator sets, two
sources of emergency power would be available. Since parts of the
existing 24.9 kV line are in high avalanche areas, its reliability will
be improved by installing underground cable sections, totaling
9-2
5597B
approximately 3 miles, in the vicinity of the avalanche chutes. The
location of these areas would need to be better defined during a more
detailed level of design.
The capacity of this emergency supply source would be limited mainly by
the 9 mile section of the 12.47 kV, #2 ACSR line. During detailed
design, the maximum line loading capacity and stability would need to
be studied further. An automatic load shedding system would need to be
incorporated with this emergency tie, the existing diesel generators
and a determination of priority loads. See Part V of the Technical
Appendix for some preliminary load flow computer runs of emergency
operation.
9-3
5597B
10.0 TRANSMISSION LINE COST ESTIMATE AND SCHEDULE
10.1 COST ESTIMATE
Feasibility level capital costs and operation and maintenance costs
were developed for the selected transmission line described in
Section 8.0. The capital cost estimate includes the direct
construction costs of the transmission line and substations described
herein, indirect construction costs, contingency and engineering and
owner administration costs. The cost estimate is an overnight price
estimate with the escalation during construction shown separately.
The cost estimate is shown on Table 10-1 and shows a total cost of
$12,074,000 in January 1983 dollars.
10.2 OPERATION AND MAINTENANCE COST
An estimate of the annual operation and maintenance cost for the
transmission line was made which considered the environment in which
the line exists, the topography, and the need for a reliable power
supply. The annual cost for O&M is $250,000 which provides for
adequate maintenance equipment and manpower to service the line.
10.3 SCHEOULE
Fig. 111-3 shows the schedule for design and construction of the new
transmission line. The earliest the line can be in operation is the
fall of 1984 which assumes that environmental studies, and preliminary
design studies are initiated in the spring of 1983 so that permits for
the necessary right-of-way can be obtained and construction begun in
the spring of 1984.
10-1
55988
FERC
ACCOUNT
350
352
353
354
355
356
357
Project subtotal£/
TABLE 10-1
COST ESTIMATE FOR DAVES CREEK-SEWARD
TRANSMISSION SYSTEM -115 kV
DESCRIPTION
Land and Land Rights
Station Structures and Improvements
Substation and Switching Equipment
Steel Poles/Towers
Wood Poles/Fixtures
Overhead Conductors/Devices
Underground Conductors/Devices
Indi rect
Engineering & Environmental,
Construction Management,
Owner Administration
Contingency
3/ Escalation during construction
Total Capital Cost
l/January 1983 price level
TOTAL COST($)l1
$ 270,000
73,500
1,426,300
1,160,450
2,320,200
3,084,100
245,000
461,500
1,218,650
1,539,000
11 ,798,700
275,300
12,074,000
£/Represents overnight cost in January 1983 dollars
l/Escalation based on project schedule shown in Fig. I II -3 and an
annual inflation rate of 7%
10-2
5598B
TABLE 10-2
COST ESTIMATE FOR DAVES CREEK-SEWARD
TRANSMISSION SYSTEM -115 kV
DETAILS
Sheet 1 of 5
FERC
ACCOUNT DESCRIPTION UNIT QUANTITY UNIT COST ($) TOTAL COST ($ )
350. LAND & LAND RIGHTS 270,000
• 1 Alaska Department of Highways MILES 30 2,500 75,000
(for inspection)
.2 Various owners ACRES 15 13,000 195,000
(1 imited cases)
352. SWITCHING STATIONS 73,500
• 111 Clearing SF 6,000 0.23 1,400 ......
C)
I .112 Grading SF 10,000 0.08 800 w
.113 Gravel CY 150 15.33 2,300
· 121 Roadway LF 200 11 0 .00 22,000
.122 Fences LF 400 30.00 12,000
.13 Foundation CY 75 466.67 35,000
353. SUBSTATION EQUIPMENT 1,426,300
.112 Bus support column (4" x 10 1 ) EA 15 660 9,900
w/footing
.113 Deadend Towers (50 1
) EA 3 32000 96,000
5601B
TABLE 10-2
COST ESTIMATE FOR DAVES CREEK-SEWARD
TRANSMISSION SYSTEM -115 kV
DETAILS
Sheet 2 of 5
FERC
ACCOUNT DESCRIPTION UNIT QUANTITY UNIT COST ($) TOTAL COST ($ )
353.121 Insulators -115 kV EA 24 342 8,200
• 1211 A1ull1. Bus (3" tubular) FT 200 75 15 ,000
.122 Control Wiring in 1-1/2" condo
1 -8/c #12 FT 500 38 19,000
1 -8-2/c #16 shielded FT 400 3 15,200
.123 Grounding System
I--' .1231 4/0 Cu. w/10· rod every 50· FT 2,000 12.90 25,800 0
• -Po
353.211 Transformers -Main 598,600
.2111 15 MVA, 115 kV -69 kV Auto EA 2 244,850 489,700
Transformers (w/Tertiary Winding)
.2112 3 MVA, 24.9 kV -12.5 kV EA 1 108,900
3 winding (1 tertiary) w/LTC
.21 ?1 Potential & Current Transformers EA 24 inc1 above
"5 kV -10
.221 Circuit Breakers -115 kV EA 1 107,900
.2211 115 kV Circuit Switchers EA 2 93,800
.2212 69 kV Circuit Switchers EA 1 39,900
5601B
TABLE 10-2
COST ESTIMATE FOR DAVES CREEK-SEWARD
TRANSMISSION SYSTEM -115 kV
DETAILS
Sheet 3 of 5
FERC
ACCOUNT DESCRIPTION UNIT QUANTITY UtJIT COST ($) TOTAL COST ($ )
353.222 Disconnect Switches 55,600
.2221 115 kV Air Dis. EA 14,200
.2222 69 kV Air Dis. EA 2 11 ,000 22,000
.2223 24.9 & 12.5 kV Air Dis. EA 6 3,233 19,400
w/Fuse - 3 pole
.231 Lightning Arrestors 40,700
I-' .2311 69 & 115 kV Arrestors EA 09 3,275 29,400 0
I (I nter. Cl ass) Ul
.2313 24.9 ~ 12.~ kV Arrestors EA 12 942 11 ,300
(Dist. Class)
.241 Main Switchboard Add. EA 65,700
Seward Sub -1-3 Ft. Sec.
w/relays, meters controls
.311 Carrier Equipment -115 kV Wave Trap EA 3 8,200 24,600
.411 Lighting -Yard LOT 43,800
4 Fe -8000 Sq. Ft .
. 511 Load Shedding Control LOT 80,000 80,000
at Seward and Industrial Marine
Subs . (frequency based)
. 6111 Kwh, Kva, Kw EA 7 8,571 60,000
P.F., V, amp, Demand meters
5601B
TABLE 10-2
COST ESTIMATE FOR DAVES CREEK-SEWARD
TRANSMISSION SYSTEM -115 kV
DETAILS
Sheet 4 of 5
FERC
ACCOUNT DESCRIPTION UNIT QUANTITY UNIT COST ($) TOTAL COST ($)
353.6112 Protective relays (0. c. etc.) EA 27 985 26,600
354. STEEL POLES/TOWERS AND FIXTURES 1,160,450
. 1 Clearing R.O.W. SF 50,000 0.24 12,000
.2 Tower Foundation CY 90 520 46,800
Excavation/Backfill
.72 Augered Holes (6 1 0-25 1
) EA 6 1,000 6,000
w/concrete, rebar, anchor bolts
t--'
0
I .3 Steel Tower -Tubular EA 10 109,565 1 ,095,650 0'>
80 1 deadend & anchor
355. WOOD POLES AND FIXTURES 2,320,200
. 1 Clearing R.O.W. -30 l wide MILES 34 21 ,600 734,400
.21 Pole Holes (8 I ) & Anchor Holes EA 750 476 357,000
.23 Anchors EA 100 730 73,000
.3 Poles
60 1
, Class Hl, Doug. Fir EA 560 1 ,500 840,000
.31 Anchor Poles EA 50 1 ,000 50,000
35 1
, Cl ass 1, Doug. Fir
.32 10 1 Cross A.rms EA 210 100 21 ,000
.4 Demolition MILES 13 18,830 244,800
5601B
TABLE 10-2
COST ESTIMATE FOR DAVES CREEK-SEWARD
TRANSMISSION SYSTEM -115 kV
DETAILS
Sheet 5 of 5
FERC
ACCOUNT DESCR I PTI ON UNIT QUANTITY UNIT COST ($) TOTAL COST ($ )
356 . OVERHEAD CONDUCTORS AND DEVICES 3,084,100
. 1 Insulators and Hardware 844,250
.11 Line Post -115 kV EA 1450 545 790,000
.111 Line Post -24.9 kV EA 350 110 38,500
.12 Suspension (Deadend) -115 kV EA 300 45 13,500
.121
I-'
Suspension (Deadend) -24.9 kV EA 50 45 2,250
0
I .2 Conductors 2,239,850 -.....J
.21 336 ACSR -Oriole tHLES 123 14,120 1,736,800
.22 4/0 ACSR -Penguin MILES 48 9,077 435,700
.23 #2 ACSR MILES 16 4,209 67,350
.3 Ground Wire FT 300 incl above
.4 Hardware (for above)
.41 Breakaway Devices EA 150 incl w/insulators
357. UNDERGROUND CABLE 245,000
. 1 U.G., type tlRD 25 kV cable, ~lILES 3 81 ,670 245,000
3-1/c #1/0 alum in 3 l-mile segments
with n-30 potheads (in trench
w/treated timber cover)
5601 B
11'5 kV LINE
TO
PORTAGE
SUBSTATION
GRANT LAKE POWERHOUSE
&
SUBSTATION
SEE F!GURE N-2"3
--,
Ep HYDROELECTRIC
GEN
7 MW 4.16 kV
<J ~ 9MVA I
~ rY '(,lIo;:'I.IEoItV
-I
I
(lTV OF SEWARD SUBSTATION
1-I 1---I' ~-~
T
GRANT LAKE HYDRO LAWING METERING SWITCHING STATION f I, SWITCHER ,
-, SWITCHING STATION (HILE POST Z';) ~
(HILE POST 27) r-I ----------
11'5 kV LINE
TO
QUARTZ
(REEK
SUBSTATION I
L
I
(
DAVES (REEK SUBSTATION
(HILE POST 'II)
LEGEND
110; kV
AS NOTED
EXISTING
-- -----EXISTING TO
BE REHOVED
1 Z'I.9I\Y <J 110;: Eo9 kV 1 'I I'5HVA
I MILE POST 7 ~ , (TYP 2 TRANSF) .---------l-_==~/--.--~---:---------« ( (~:i~Ji. ,
69 kV. " •
EXISTING LOADS
INCLUDING HOOSE PASS
EXISTING LOADS ... -11---_.
----I~
-f i .. " I
\} \J.....A..A..) Z'I.9 : IZ.'I7 kY
MILE POST NINE
i --+'T Tl I
SUBSTATION
12.'17 kV
I
EXISTING LOADS
12.'17 kV
I
1_-
i
\
I
(EXIST Z'I.9 kY) , 1
I
CIRCUIT !
SWITCHER
I ~J 7.';HVA
r-v'('r' Eo9/Z'I.9: , I' IZ.'I7 kV
i
!
t /-.... -
/ /
! 1
CIRCUIT
SWITCHER
r· !
7.0; HVA
/' ,('V\ Eo9/2'1.9:'
II 12.47 ~V ,
! i
, (TYP)
3 PLACES
/.' 3.2'5 HVA
12.47:2.'1 KV
EXISTING LOADS
2.'1 kV T
j
DIESEL
GEN I
2.b HW
I
i
I • ,
) ,.
DIESEL
GEN 2
1.2 HW
,
EltISTING L'OADS'
i
,
) I
j i
\~-
/ / I
I
DIESEL
I GEN 3
1.2 HW
I ------------------'
TO SEWARD MARINE - I NO PARK
ALASKA POWER AUTHORITY
GRANT i-AKE HYDROELECTRIC PROJECT
TRANSMISSION SYSTEM
ONE LINE DIAGRAM
DATE FE9 198'3 I FIGURE ill-I
EBASCO SERVICES INCORPORATED 10-8
~-------------------------------------------------------------------------
t .. -
I
I
(.
;
/
I
I
I
/
/
I
/
'~
I
1',
I
DAVES CREEK
SUBSTATION --
N
:~
~
~ .... ""
..... ----...... ---'....... ------........... ---
_0_ STERLING HWY
---~~N-n~~~
UPPER TRAIL--
LAKE
z _______ _
-:-,--~
---------
MOOSE PASS
----v ~----.J-~-----
-----_ ... --------
GRANT LAKE
HYDRO
SWITCHING
STATION
TERN LAKE
(MUD LAKE)
MOOSE CREEK
-------------------
co
w z ......
-.-J
::r: v
f-
~
L
N
t
INDEX 1:2S0;OOO
LEGEND
• • ... ----~-
'JEW TRANSMISSION LINE
EXISTING TRANSMISSION LINE
-----ROAD
~~ +-+---+---+-RAILROAD <:> MILEPOSTS
--. • -COMBINATION OF NEW & EXISTING
TRANSMISSION LINE
1000' 0'
! " ' , ! " ' II
1000' . 20.00 ' 3000'
I
SCALE
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
SEWARD TRANSMISSION LINE
ROUTING PLAN
SHEET I
DATE FES tgSj FIGURE 1[-2
EBASCO SERVICES INCORPORATED 10-9
f-
/
LOWER
TRAIL
LAKE
W ~ ~r===::~~~~~~~~~~~~~~~ --.~ --~. w .~_ -__ --~~
3 LAWING SWITCHING '-----....... '-------_
...J STATION "'---
I
~
<{
FOREST SERVICE
WORK CENTER
L ------~-~.
TRAIL RIVER --~\ ~-----
If'
W
Z
>-<
~I ~
<{
L
... -",.,_.'
"",,,,,,--.........
~-
L __ ~
KENAI LAKE
-------
o .~~~
MATCH LINE ABOVE
(Y'
w z
>-<
...J
- -.. ____ I
------.--~
--------<{ L
NOTES:
LQNDICATES : AREA OF FREQUENT AVALANCHE ACTIVITY ]
LEGEND
. .
, t
<>
NEW TRANSMISSION LINE
EXISTING TRANSMISSION LINE
ROAD
RAILROAD
MILEPOSTS
... -• • -COMBINATION OF NEW a EXISTING
TRANSMISSION LINE
1000' 0' 1000' 2000' 3000'
t " " , , , , II • ! ,
SCALE
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
SEWARD TRANSMISSION LINE
ROUTING PLAN
SHEET 2
DATE FEB 198, FIGURE ill-2
_______ ....... E_B_A_S_C...;;O_S.;;..E_R_V_I...;;;C_E...;;.S_I_N...;;;C_O .... R_P...;;.O_R_A_T...;,ED;;;...I 10 -10
N
I-
W
W
I
l/l
~I ......
--l
I
U
~
Z-_Z::~ __
--= ------'\
SEWARD
\SUBSTATION (~NERATING PLANT
--------~
RESURRECTION
BAY
N
W z
I~
u
l-
i!
LEGEND
• • -+----...... -
I I o
0' 10,0,9:"" ",
NEW TRANSMISSION LINE
TRA NSMI SSION LINE EXISTING
ROAD
RAILROAD
MILEPOSTS EXISTING
COMBINATION OF NEW a
TRANSMISSION LINE
, 3000' 1000' 20,00 ,
SCALE
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
SEWARD TRANSMISSION LINE
ROUTING PLAN
SHEET 3
FIGURE III-2
DATE FEB Igg, CORPORA TED 10-11 EBASCO SERVICES IN
1I'5I1.V
VERTICAL COMPACT
WITH UNDERBUILD
11'5I<.V
VERTICAL DELTA
COMPACT
11'5I<.V
VERTICAL COMArlCT
1I'5I<.V
VERTICAL COMPACT
LARGE ANGLE
1I'5I<.V
VERTICAL COMPACT
DEAD END
FOURTH OF \\
JULY CREEK )
SEWARD MARINE
INDUSTRIAL PARK
LEGEND
FOURTH OF
JULY CREEK
• • NEW TRANSMISSION LINE
I~
.. ----.... -EXISTING TRANSMISSION LINE
-----ROAD
, I RAILROAD o MILEPOSTS ... -.............. -COMBINATION OF NEW a EXISTING
TRANSMISSION LINE
1000' 0'
ell' " II ! II
1090' 209 0 ' ~OO' ,
SCALE
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
SEWARD TRANSMISSION LINE
ROUTING PLAN
SHEET 4
DATE FEB IgS"1 FIGURE ill-2
EBASCO SERVICES INCORPORATED 10-12
1981 1982 198~ 1984 198t; 98b ~ WORK ACTIVITY o N 0 J F t1 A t1 J J A 5 0 N o J F t1 A t1 J J A 5 0 N 0 J F t1 A t1 J J A 5 0 N o J F t1 A t1 J J A 5 o N o J F t1 A t1 J J A 5 0 N o J F t1 A t1 J J A 5 0 N 0
I FEASIBIUTY ANALYSIS
II PERMITTING
A.PERMITS --o o. I
B. ENVIRONMENTAL EVALIATION -f--_. --~-
III DESIGN AND CONTRACT DOCUMENTS vA AR E GR CO TIl CT
r-A.DETAILED FIELD INVESTIGt\TIONS r -----
B.SURVEY _._-I---
C.MAJOR EQUIPMENT I---
t--D.DETAIL DESIGN -0
I--E BIOOING ~QNTRACTOR SELECTION -~ I-~.
t--
IV CONSTRUCTION
~A.TRANSMISSION LINE -I
B. SUBSTATIONS -
C. ENERGI2AT1QN r-
LEGEND
MAJOR EFFORT
-------CONTINUING EFFORT
.
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
TRANSMISSION LINE
PROJECT SCHEDULE
DATE FEB, IQS'3 1 FIGURE III -'3
EBASCO SERVICES INCORPORATED 1 0-13 ',-., ... --, .~ ,'"
--->" --~'---.--..,.,.".,." """""'11_11114_, _-"_IAiS _;UPI_aH I _ ••• 1*_1_*:;*)1_11 __ bE -I-_--..,. ___ "'""""r I···
PART IV
FEASIBILITY ASSESSMENT
OF
GRANT LAKE
HYDROELECTRIC PROJECT
11.0 EXISTING SITE CONDITIONS
11.1 GENERAL
The project site is located on the Kenai Peninsula approximately 50 air
miles south of Anchorage and 25 air miles north of Seward (see Figure
IV-l). The site is adjacent to the Seward-Anchorage Highway and the
Alaska Railroad line connecting Seward to Anchorage. The major project
features lie between Grant Lake, which forms the upper reservoir, and
Upper Trail Lake, which is the tailwater.
11 .2 TOPOGRAPHY
The Grant Lake project is located in the mountainous terrain that
comprises the Kenai Mountain Range (see Figure IV-2). The major
mountains that form the Grant Lake drainage basin are Lark Mountain to
the north and Solars Mountain to the south. Both peaks rise above
elevation 5000 feet and result in the fairly steep terain that
surrounds Grant Lake. Grant Lake consists of upper and lower portions
(referred to as Upper and Lower Grant Lake) nearly separated by a
natural constriction and an island at the midpoint. The total area of
the lake is nearly 1700 acres. Grant Lake has a surface elevation that
fluctuates between 691 and 700 feet (mean sea level), and depths nearly
as low as elevation 400. Its drainage area is 44.2 square miles,
measured at the USGS gaging station on Grant Creek.
Proceeding westward from Grant Lake to Upper Trail Lake over a
horizontal distance of approximately 3,000 feet, the terrain rises
abruptly to approximately elevation 900 and then slopes less abruptly
to the Trail Lakes at elevation 467. The Trail Lakes valley is a long
north-south trending valley that extends from Seward to the site area.
Trail Lakes consist of an upper and lower section, referred to as the
Upper and Lower Trail Lakes. They are separated by a narrow
11-1
2373B
constriction at the midpoint. Bathymetric surveys across Upper Trail
Lake adjacent to the powerhouse cove show the lake to be very shallow
at that location. Depths generally range from 4 to 6 feet.
Falls Creek, which was evaluated for diversion into Grant Lake, has a
varied topography from its headwater to its confluence with Lower Trail
Lake, 7-1/2 miles away. At its headwaters, which originate at
elevation 3800, and for its first 2 miles Falls Creek drops abruptly at
a 12% gradient, flattening to a 7% gradient for the next 4 miles, and
ultimately a 6% gradient for the last 1-1/2 miles. Falls Creek lies in
a steep sided valley cut in the surrounding mountains with the
exception of the last 1-1/2 miles, where the surrounding terrain is
relatively flat.
The Falls Creek drainage area is 11.8 square miles, measured at the
streamgage located at the Seward-Anchorage Highway bridge.
11.3 GEOLOGY
A detailed discussion of the geology of the area on both a regional and
project-specific basis is presented in Section 14.0. A brief
discussion of some of the more salient features is presented herein.
lhe project area is typical of sub-arctic, glaciated terrain consisting
of U-shaped valleys with lowlands consisting of lakes, ponds and
streams (see Figure IV-10). Overburden in the project area is either
nominal or non-existent due to the stripping action of the glaciers.
The bedrock in the project area is a complex assortment of
metamorphosed sandstone, siltstone, mudstone and occasionally
fine-ground volcanic rock. Where overburden exists, it consists of
glacial till, peat bogs and occasional unconsolidated alluvial deposits
of silt, sand and gravel.
11-2
2373B
The orientation of the bedrock in the project area is consistent, with
most units dipping approximately 50 degrees to the east and having
strikes approximately north 5 degrees east. Joint orientations
throughout the area vary widely.
Fault and fracture zones are present in the project area and follow two
general directions, as shown on Figure IV-10. One set trends northeast
and the other north-northwest.
11-3
2373B
12.0 ALTERNATIVE PROJECT ARRANGEMENTS
12.1 EARLY STUDIES
Development of the hydroelectric potential at Grant Lake has been the
subject of study since the 1950 l s when it was considered as one of
several energy supply alternatives for the Seward area. Chugach
Electric Association filed preliminary permit applications with the
Federal Power Commission in the 1950 l s and 1960 l s for the Grant Lake
project development, along with three other hydroelectric developments
in the same general area (filing for Grant Lake was done in 1959).
In 1954 R.W. Beck and Associates performed a preliminary study of the
development of Grant Lake and concluded that the project would be
feasible (Beck, 1954). Based on very preliminary information, Beck
recommended a two-staged development at Grant Lake. This consisted of
raising Grant Lake by constructing either a concrete-faced rockfill dam
at the outlet of Grant Lake or an arch dam downstream of the falls in
Grant Creek. As part of this development, a powerhouse would be
constructed on Lower Trail Lake to accommodate one half of the
potential power at the site, with provisions to allow for expansion to
the full potential of the site. The initial water conductors were to
have been either sized for the full project development or else for the
reduced capacity and thus requiring future penstock construction.
More recently, in 1980, CH2M Hill completed a prefeasibility study of
hydroelectric development at Grant Lake for the City of Seward (CH2M
Hill, 1980). This study concluded that constructing a hydroelectric
project at Grant Lake would present definite economic benefits to
Seward; however, such a project alone would not generate enough energy
to meet Seward1s energy needs. The study report recommended proceeding
with a detailed project feasibility study and submittal of a FERC
license application.
12-1
2266B
The investigations that were performed by CH2M Hill to arrive at these
conclusions and recommendations consisted of the following:
Preliminary reconnaissance investigations were performed on several
development alternatives. These were: development of Crescent Lake,
Grant Lake, Ptarmigan Lake and a combination development of Grant and
Ptarmigan Lakes. Based on environmental and economic considerations,
Grant Lake plus the diversion of nearby Falls Creek into Grant Lake was
selected for further development.
From preliminary hydrologic and power operation studies, CH2M Hill
concluded that Grant Lake should be raised by constructing a 68 foot
high concrete-faced rockfill dam at its natural outlet and a 30 foot
high rockfill, concrete-faced saddle dam near Portage Trail on Grant
Lake. The spillway crest on the main dam would be at elevation 750
resulting in an available reservoir capacity of 78,000 acre-feet
between elevation 750 and elevation 700. As previously mentioned, flow
from the Falls Creek drainage basin would be diverted into Grant Lake.
The study concluded that a two unit above ground concrete powerhouse to
accommodate an average flow of 380 cfs would be required. Power would
be transmitted from the site over a 69 kV transmission line to Seward's
Falls Creek metering point.
CH2M Hill studied four subvariations to this Grant Lake development.
These pertained to the location and elevation of the powerhouse, intake
and, consequently, the energy output and length of the flow line.
CH2M Hill's final recommended project layout brought the flow through
an intake canal to the saddle dam. An intake structure at the saddle
dam brought this flow into a low pressure pipeline and high pressure
penstock, to a powerhouse located approximately 2000 feet upstream of
the outlet of Upper Trail Lake. This general configuration served as
the starting point of Ebasco's detailed feasibility work.
12-2
2266B
12.2 INTERIM REPORT STUDIES
Upon receiving the Power Authority's authorization in Septemer, 1981 to
proceed with detailed feasibility studies, Ebasco retained R&M
Consultants, Inc. of Anchorage to initiate preliminary aerial and
ground surveys of the Grant Lake project area. Under Ebasco's
direction R&M also performed limited field geotechnical studies. The
purpose of these programs was to obtain a sufficient amount of site
information early in the study to support the development of
conceptual-level project alternative arrangements and cost estimates.
A selection of one project arrangement for more detailed studies could
then be made.
During the ensuing period from October 1981 through February 1982, six
alternative arrangements for the Grant Lake project were developed by
Ebasco which were presented to the Power Authority in the Interim
Report in February 1982.
The purpose of the Interim Report was to: 1) describe the results of
the preliminary feasibility studies conducted through February 1982;
2) present a comparison of the alternative project arrangements for the
development of the hydroelectric potential at Grant Lake; and
3) recommend one alternative for further detailed feasibility studies.
The project arrangements that were developed are identified as
Alternatives A through F on Figure IV-3.
Alternatives A, B, C, and D would use only the inflow to Grant Lake for
power generation; Alternatives E and F would utilize Grant Lake inflow
plus inflow diverted from Falls Creek into Grant Lake. Alternatives A,
B, and C include the construction of a main dam at the natural outlet
of Grant Lake with a saddle dam across a low divide approximately 1.1
miles north of the main dam. The differences between these three
alternatives consist of the type and alignment of the power conduit and
the location of the powerhouse on Upper Trail Lake. Alternative D
12-3
2266B
would utilize the existing lake level and provide for regulation by
means of a low level lake tap. thus not requiring dams. The power
conduit for Alternative D would consist of an inclined tunnel to a
powerhouse in the same location as that used for Alternative B.
Alternative E would combine the diversion of Falls Creek with
Alternative A (raised lake level) and Alternative F would combine the
diversion of Falls Creek with Alternative D (lake tap with no dams).
From the results of these studies it was concluded in the Interim
Report that all of the alternatives are technically feasible.
Alternative D. the lake tap scheme. was shown to be the most economical
based on the cost of energy. and also the most acceptable. from the
standpoint of potential environmental impacts. Alternative F. which
consists of Alternative D plus the Falls Creek diversion. was shown to
have a greater installed capacity than D with only a slightly higher
energy cost. It was therefore recommended in the Interim Report that
Alternative F be developed through detailed feasibility studies.
Subsequent detailed optimization studies described in Section 16.0.
however. concluded that a refined Alternative D is actually preferable
and is presented in Section 17.0 as the recommended project arrangement.
Descriptions of all the alternatives are presented in Sections 12.3 and
12.4. Section 12.5 presents the comparative construction costs for the
alternatives. as developed and presented in the Interim Report.
12.3 G[NERA1ION WITH GRANT LAKE INFLOW ONLY -ALTERNATIVES A. B. C
AND D
Four of the six alternatives evaluated in the Interim Report would
develop the project site through the regulation of only the naturally
occurring inflow to Grant Lake. The general location of each of these
alternatives is shown on Figure IV-3. Three of these alternatives
involve raising the existing level of Grant Lake approximately 45 feet
to elevation 745 by means of a dam at the natural outlet of the lake
12-4
2266B
(referred to as the main dam) and another smaller dam in a low saddle
area (referred to as the saddle dam) about 1.1-mi1e north of the main
dam. The crest elevation of both dams would be elevation 766. For
each alternative, a power conduit would convey water from Grant Lake to
a powerhouse located on Upper Trail Lake. Three alternative locations
for the location of the power conduit and powerhouse were
investigated. These are referred to as Alternatives A, Band C.
A fourth alternative, referred to as Alternative D, consists of a lake
tap and power tunnel to convey water from Grant Lake to the
powerhouse. This alternative would not require raising the lake and
thus requires no dams. The power intake would be set low enough to
allow sufficient drawdown capability for regulation of streamflow. As
a result of the full feasibility studies conducted following the
Interim Report studies, a modified version of Alternative D was
recommended for development (see Section 17.0).
12.3.1 Alternative A -Intake Upstream of Saddle Dam
Alternative A is very similar to the preferred alternative in the CH2M
Hill report and consists of raising Grant Lake from its existing level
at approximately elevation 700 to a normal maximum pool level at
elevation 745 and diverting its flow to a single-unit powerhouse with
an installed capacity of 6 MW on the east shore of Upper Trail Lake.
Raising the lake would be accomplished by constructing two dams. The
main dam would be built across Grant Creek at the natural outlet of
Grant Lake. A saddle dam would be constructed across the low saddle
area north of the main dam. These features are shown in the plan on
Figure IV-4.
Water would be conveyed from Grant Lake to the powerhouse via a power
conduit with an intake structure located upstream of the saddle dam.
The power conduit would consist of steel pipeline from the intake to a
surge tank and then a steel penstock to the powerhouse. Discharge from
the powerhouse would be through a tailrace channel to Upper Trail Lake.
12-5
2266B
The main dam and saddle dam would both be rockfi11 dams with central
impervious zones constructed using a slurry trench. Both dams and the
spillway adjacent to the main dam are also utilized in Alternatives B,
e and E, and are described separately below.
The intake for the power conduit would be a submerged circular vertical
concrete structure with vertical trashracks and would be located at
elevation 700, approximately 1,300 feet upstream of the toe of the
saddle dam. This arrangement was selected based on its simplicity and
efficient hydraulic configuration. The trashrack arrangement would be
relatively maintenance-free except for periodic cleaning of the racks.
This would be accomplished by personnel in a boat or divers collecting
the debris from the racks when the reservoir is low and ice-free. A
more complicated arrangement consisting of an intake tower and bridge
was considered, but was not selected. It was felt that the primary
advantage afforded by the intake tower, which is the continuous
accessibility of the trashracks for cleaning, was offset by the added
construction costs for the tower and access bridge that it would
require.
The power conduit between the intake and surge tank would consist of a
combination buried and above ground low-pressure steel pipe 6.75 feet
in diameter and 3,840 feet long. This arrangement was selected based
on economics and ease of construction. Where the conduit traverses
through the soft peat areas upstream of the saddle dam and the
surrounding high ground, it would be buried in a soil and rock cut
trench. Where it crosses beneath the dam, the conduit trench would be
backfilled to the top of rock with concrete, thus forming an impervious
plug around the pipe and providing support to the pipe under the
embankment loads.
Beginning about 800 feet downstream of the saddle dam, where the
conduit is located above ground, two support methods would be
12-6
22666
\
employed: The conduit would be held fixed by concrete collars and
cradles, and would be allowed to move freely along its axis under
temperature loading within intermediate steel supports.
Preliminary hydraulic transients analyses indicated that a surge tank
would be required at the end of the low pressure portion of the conduit
to protect the conduit from negative waterhammer pressures. The surge
tank for Alternative A was assumed to be of the above ground,
restricted-orifice type, with the base located at elevation &90 feet.
The steel tank would be supported by a concrete mat founded on rock.
This arrangement was selected in lieu of a tank supported on columns
because of the high seismicity in the area. The mat-support
arrangement would be more stable under earthquake loading.
The last segment of the power conduit would be an above ground steel
penstock from the surge tank to the powerhouse. The penstock would be
5 feet in diameter, 580 feet long, and would be supported in a manner
similar to the above ground low pressure pipe (i.e., fixed concrete
supports and sliding steel supports).
In selecting the type and configuration of power conduit for
Alternative A, buried prestressed concrete pressure pipe, completely
buried steel pipe, and surface steel pipe were considered. Based on
economics and constructibility, the combination of buried and surface
steel pipe was selected.
The powerhouse for Alternative A would be a conventional indoor
installation located approximately 180 feet from the east bank of Upper
Trail Lake. The substructure would be concrete founded in bedrock.
The superstructure would be structural steel with aluminum siding. The
powerhouse would house a single vertical Francis turbine having an
output of 8,300 horsepower under a rated net head of 247 feet. The
total powerhouse discharge under these conditions would be 329 cfs.
The generator would be a vertical unit with an output of &,700 kVa with
an assumed power factor of 0.9.
12-7
22&&B
A single generating unit was provided in the powerhouse because of the
size of the installation, and the economy resulting from a single unit
installation compared with a multiple unit installation for a given
capacity. The provision of a single unit should have no affect on the
capability of the plant to produce the energy as estimated in the
operation studies because of the high unit reliability and availability
(91.5+ percent according to the FERC) of this equipment, the plant
factor, and the regulation provided by the reservoir.
A 180-foot-long tailrace channel would be excavated to Upper Trail Lake
through the lake shore sands and gravels and into rock. It would have
side slopes of 2H:1V in soil and lH:4V in rock.
The substation would be located adjacent to the powerhouse. For the
conceptual layouts in the Interim Report, it was assumed that one
three-phase transformer would transform the voltage from 13.8 kV to the
69 kV transmission voltage. The transmission corridor would parallel
the main access road and follow the bridge across the Trail Lakes. It
was assumed that the transmission line from the powerhouse would
intertie with the existing Chugach line, presently operating at
24.9 kV, at the same location where the main access road intersects the
Seward-Anchorage highway on the west side of the Trail Lakes.
Total length of access roads required for Alternative A would be
5.1 miles. This assumes that access to the general project area from
the Seward-Anchorage highway would be provided by a bridge crossing
Trail Lake over the narrows between Upper and Lower Lakes, as shown on
Figure IV-4. An alternative considered in lieu of the bridge crossing
would be the longer route around the south end and along the east side
of Lower Trail Lake. The total length of access road using this route
would be 1.2 miles. The bridge crossing, while slightly more costly
than the alternative route, was selected because of its decreased
environmental impact and because of shorter length of required
transmission lines associated with it.
12-8
2266B
12.3.2 Alternative B -Intake at Main Dam with Tunnel and Surface
Conduit
Alternative B involves ralslng Grant Lake to elevation 145 by
constructing the main dam and saddle dam. Flow from Grant Lake would
be diverted to a single unit powerhouse on Upper Trail Lake with an
installed capacity of 6 MW. Alternative B combines a short power
tunnel with the raising of Grant Lake as shown on Figure IV-5. water
would be conveyed from the intake structure at the main dam to the
powerhouse by a combination of low pressure steel pipe, a short power
tunnel and finally, a steel penstock.
The main dam and saddle dam for Alternative B would both be rockfill
with impervious central zones consisting of a soil-cement-bentonite
mixture, the same as that required for Alternative A.
The intake structure would be of the same configuration as that for
Alternative A. It would be a submerged circular vertical concrete
structure with vertical trash racks. The location of the structure
would be just upstream of the main dam and would be set at elevation
100. Periodic cleaning of the racks would be accomplished by boat or
diver during periods when the reservoir is ice-free. As with
Alternative A, a more complex intake tower arrangement with removable
trash racks was considered but discarded due to its cost (a gate tower
and access bridge would have been required).
From the intake structure to the power tunnel, the conduit would
consist of a 1-foot-diameter low pressure steel pipe. For the first
300 feet of length, where this conduit passes beneath the dam, it would
be placed in a rock cut trench and backfilled with concrete. The
concrete backfill would result in impervious plug around the conduit as
well as provide it with support to withstand the embankment loads.
12-9
2266B
From the downstream toe of the main dam to the power tunnel this low
pressure conduit would be supported above ground using the same surface
support techniques discussed for Alternative A (fixed concrete supports
and sliding steel supports).
The tunnel would be horseshoe-shaped, 9-foot in diameter and would be
lined with shotcrete. At the portals and where poor quality rock was
assumed to be encountered, the tunnel would be rock bolted in addition
to the shotcreting.
An underground surge chamber would be located approximately 200 feet
upstream of the tunnel exit at elevation 697. It would be a restricted
orifice type with surface venting. The chamber would also be lined
with shotcrete. Rock bolts would be utilized where rock conditions are
poor.
Inside the tunnel, just downstream of the surge chamber, the power
conduit would transition to a 5-foot-diameter steel penstock. This
transition would occur at the location where the maximum hydraulic
pressure in the tunnel is equal to the rock overburden pressure. The
penstock would exit the tunnel and drop 220 feet to the powerhouse. It
would be supported above ground using the combination of fixed concrete
and sliding steel supports discussed above for the low pressure pipe.
Construction of the tunnel would be performed using conventional
drilling and blasting techniques. The excavation would head upstream
to facilitate mucking and drainage. The surge chamber would be
constructed using the raised bore shaft technique.
A conventional indoor powerhouse would be located approximately 180
feet from the east bank of Upper Trail Lake (see Figure IV-5). At the
time of the Interim Report, no geotechnical suburface studies were
performed in the area of this powerhouse and therefore it was assumed
12-10
2266B
that foundation conditions would be typical of what was observed at the
Alternative A powerhouse area during the Interim Report geotechnical
studies. A lBO-foot-long tailrace channel was assumed to connect the
Alternative B Powerhouse to Upper Trail Lake.
The mechanical and electrical equipment in the powerhouse was assumed
the same as for the Alternative A powerhouse, except that the turbine
would be rated at slightly different head and flow conditions.
The substation would be located adjacent to the powerhouse and would
utilize the same transformer and circuit breaker equipment as
Alternative A. The transmission of power was assumed to utilize 69 kV
lines and would tie into the existing Chugach line, which presently
operates at 24.9 kV, on the west side of the Trail Lakes. The
transmission corridor would parallel the main plant access road and
would cross the Trail Lakes at the road bridge crossing.
Construction of 2.B miles of access roads would be required to provide
access to all significant project features as shown on Figure IV-5.
Access to the general project area would be from the Seward-Anchorage
highway via a bridge crossing of the Trail Lakes at the narrows between
Upper and Lower Trail Lakes as provided for Alternative A.
12.3.3 Alternative C -Intake at Main Dam With Surface Conduit
Alternative C is similar to Alternatives A and 8 in that it involves
raising Grant Lake to elevation 745 by constructing the main dam and
saddle dam. Flow to the generating unit would originate at a submerged
intake upstream of the main dam near the right abutment. The water
would be conveyed through an above ground, low pressure steel power
conduit and a steel penstock to the powerhouse. The single unit
powerhouse with an installed capacity of 6 MW would be located on Upper
Trail Lake. Figure IV-6 shows the general plan of these features.
12-11
22668
This alternative is unique in that the flow line consists almost
entirely of above ground steel pipe. The one exception is where the
pipe is buried beneath the main dam; otherwise, no other methods of
conveying water (tunnels, canals, etc.) are used. Also, the flow line
for Alternative C is the longest, with an approximate length of one
mile.
lhe intake structure assumed for Alternative C is identical to the
Alternative B intake, i.e., a submerged circular vertical concrete
structure located upstream of the main dam at elevation 700. A
6.75-foot-diameter steel power conduit would traverse from the intake
and beneath the main dam within a rock cut trench backfilled with
concrete.
From the downstream toe of the main dam to the surge tank, the low
pressure power conduit would be supported above ground, utilizing the
design described for the alternatives.
The Alternative C surge tank, located at elevation 690, would be a
conventional above ground restricted-orifice type. This tank would be
supported by a concrete mat founded on rock. The mat-supported surge
tank was selected over one supported on columns because of its greater
stability under seismic loading.
From the surge tank to the powerhouse, flow would be through a
5.25-foot-diameter, 2,000-foot-long steel penstock. This penstock
would utilize the same support arrangement as the low pressure conduit.
The selection of above ground steel pipe for use as power conduit was
made after sudying two other alternatives. These alternatives were
buried steel pipe and buried prestressed concrete pressure pipe. Above
ground steel was chosen based on economics and constructibility.
12-12
2266B
The powerhouse would be located about 80 feet from the east shore of
Upper Trail Lake. No geologic subsurface information was obtained at
the Alternative C powerhouse area during the Interim Report studies, so
conditions were assumed to be similar to those observed at the
Alternative A site. It was therefore assumed that the structure would
be keyed into bedrock. The powerhouse would be a conventional indoor
installation with a concrete substructure and a steel superstructure
and aluminum siding. Its mechanical/electrical equipment would be
similar to the Alternative A and B powerhouses.
The tailrace channel would be excavated approximately 80 feet long to
Upper Trail Lake.
The substation would be located adjacent to the powerhouse. Its
features would be similar to those utilized for the Alternatives A and
B substations. Power transmission would utilize 69 kV transmission
lines and would tie into the existing Chugach line, which presently
operates at 24.9 kV, west of the Trail Lakes. The transmission
corridor would parallel the main plant access road and would cross
Trail Lakes at the access road bridge.
Alternative C would require the construction of 3.4 miles of access
roads, including the bridge across the narrows connecting the Trail
Lakes as provided for Alternatives A and B.
12.3.4 Alternative D -Lake Tap
For this arrangement, a lake tap from Grant Lake would supply water via
a low-level power tunnel and short length of steel penstock to a single
unit powerhouse with an installed capacity of 5 MW on Upper Trail
Lake. This alternative arrangement provided the basis for [basco's
preferred arrangement, as a result of the full detailed feasibility
studies conducted following the Interim Report. Alternative D does not
involve raising the water level of Grant Lake and therefore dam
12-13
2266B
construction would not be required. Raising Grant Lake in conjunction
with a lake tap was not considered in detail because of the obvious
adverse impact the combination of a long tunnel and the construction of
the required dams would have on power cost. Significant project
features for Alternative 0 are the lake tap, a low-level inclined power
tunnel, and a vertical gate shaft near the upstream end of the tunnel.
These project features are shown as part of the general project plan on
Figure IV-7.
The lake tap would have an intake invert at elevation 643. It would
consist of an inclined 10-foot-diameter circular tunnel which would
incorporate a rocktrap located just downstream of the intake portal. A
trashrack placed at the lake tap portal would prevent debris from
entering the power tunnel during plant operation. The power tunnel
would extend from this lake tap intake to the downstream portal near
the powerhouse.
The horseshoe-shaped power tunnel would be approximately 3,300 feet
long from the lake tap to the powerhouse and would have a finished
diameter of 9 feet. The tunnel would be lined with shotcrete. The
tunnel portal and areas of poorer quality rock would be rock bolted in
addition to being shotcreted.
Inside the tunnel, approximately 250 feet upstream of the downstream
portal, the power conduit would transition to a steel penstock. At the
tunnel portal, this 5-foot-diameter, 500-foot-long steel penstock would
drop to the powerhouse. This penstock would be supported by a
combination of fixed concrete collars and sliding steel collars similar
to the penstock supports discussed for the other alternatives.
A gate shaft, 13 feet in diameter, would be located approximately 200
feet downstream of the lake tap. A gate house would be located on the
surface of the l40-foot-deep shaft. The top of the shaft would be at
elevation 780. The shaft would be lined with shotcrete and areas of
poor rock would be bolted.
12-14
22668
A high-level tunnel alignment with a surge chamber and longer penstock
was evaluated as a possible alternative to the selected low-level
tunnel and shorter penstock. It was found that the increased costs
associated with the high-level tunnel and surge chamber, as a result of
increased rock excavation, precluded it as a viable alternative.
Construction of the tunnel would be performed by conventional drilling
and blasting excavation techniques. The excavation would head upstream
from the lower tunnel portal to facilitate mucking and drainage. This
process would proceed to within safe rock cover of the lake. The
in-place rock would act as a plug and would remain in place until the
entire power conduit is constructed. The vertical gate shaft would be
excavated by the raised bore shaft technique. At the completion of the
entire power conduit and gate shaft the in-place rock plug would be
blasted free.
A conventional indoor powerhouse, constructed of concrete and
structural steel with aluminum siding, would be situated at the same
location as the powerhouse for Alternative B, approximately 180 feet
from the east bank of Upper Trail Lake as shown on Figure IV-7. The
structure would house a single vertical Francis turbine having an
output of 6,900 horsepower under a net head of 198 feet. The generator
would be a vertical unit with a rated output of 5,600 kVa. These
outputs were subsequently modified as a result of the full
feasibility-level project optimization studies. The substation would
be located adjacent to the powerhouse and would contain the same
equipment as the other alternatives.
The powerhouse tailrace channel would be excavated approximately 180
feet to Upper Trail Lake. No geotechnical field investigations were
performed in the Alternative 0 powerhouse-tailrace area during the
Interim Report studies; however, based on the subsurface information
obtained in the Alternative A powerhouse area at that time, it was
assumed that the channel would be excavated in the lake shore sands and
gravels, and partly in rock.
12-15
2266B
In order to assure adequate flow from Upper Grant Lake to Lower Grant
Lake, the natural constriction at their intersection would have to be
widened and made deeper. It was estimated that a channel 25-feet wide
with an invert at elevation 655 would be required. This channel would
be blasted open during the winter months and dredged clear in the
spring.
Power transmission would utilize 69 kV transmission lines and would tie
into the existing Chugach line, which presently operates at 24.9 kV,
west of Trail Lakes. The transmission corridor would parallel the main
plant access road and would cross the Trail Lakes at the access road
bridge.
Construction of 2.7 miles of access roads would be required to provide
access to all significant project features. Access to the general
project area would be from the Seward-Anchorage highway via a bridge
crossing of the Trail Lakes as described for Alternative A.
12.4 DIVERSION OF FALLS CREEK -ALTERNATIVES E AND F
Alternatives A, B, C and D, described above, would utilize only the
runoff into Grant Lake for purposes of power generation. The fifth and
sixth alternatives, referred to as Alternatives E and F, would divert
the runoff from the Falls Creek drainage (located directly south of the
Grant Lake drainage area) into Grant Lake for additional power
production. For both or these alternatives, the diversion of Falls
Creek would be accomplished using a diversion dam and conduit to convey
water northward from Falls Creek into Grant Lake as shown on Figure
IV-3.
Alternative E utilizes the diversion of Falls Creek in combination with
the raising of Grant Lake from its existing level to elevation 745.
For this alternative the same power conduit and powerhouse arrangement
as Alternative A is assumed. The effect of this diversion in
12-16
2266B
combination with Alternative A would be representative of its effect on
the other alternatives using a raised lake level (B and C).
Alternative F would combine the diversion of Falls Creek with
Alternative 0, the lake tap scheme, and is the general project
arrangement recommended in the Interim Report for detailed final
feasibility studies. The results of these detailed studies, however,
indicated that a refined Alternative D (no Falls Creek diversion) is,
in fact, the most favorable project arrangement.
12.4.1 Alternative E -Falls Creek Diversion with Raised Lake
Alternative E consists of diverting flow from Falls Creek into Grant
Lake and using the Alternative A project arrangement. The resulting
increased flow from Grant Lake would be diverted through the
Alternative A power conduit to a 7 MW generating unit installed in a
powerhouse on Upper Trail Lake. All other project features for
Alternative A would apply (e.g., dams, roads, and transmission lines).
The diversion would entail constructing a small concrete gravity dam
approximately 20 feet high (crest elevation 1121 feet) and 66 feet long
across Falls Creek at the 1100-foot contour approximately 1.6 miles
upstream of its confluence with Trail River. Flow would be diverted
from Falls Creek through a 3-foot-diameter buried steel pipe,
approximately 2.1 miles to Grant Lake. Figure IV-3 shows a general
plan view of the diversion route.
The decision to bury the pipe instead of supporting it above grade was
made because of its relatively small diameter and to provide protection
from avalanches. The concete dam was selected instead of a rockfill
dam or a roller-compacted concrete dam because of the small size of the
dam, the narrow valley configuration, and the considerable amount of
excavation for the spillway required with a rockfill dam.
12-17
2266B
12.4.2 Alternative F -Falls Creek Diversion With Lake Tap
Alternative F would combine the Falls Creek diversion with the
Alternative D project arrangement (lake tap). The Falls Creek
diversion works would be identical to that described for Alternative E.
The only difference in the arrangement of the lake tap at Grant Lake is
that the powerouse would have an installed capacity of 6 MW. rather
than the 5 MW plant for Alternative D.
12.5 PRELIMINARY COMPARATIVE CONSTRUCTION COST ESTIMATES
12.5.1 General
During the studies performed for the February 1982 Interim Report.
preliminary conceptual-level construction cost estimates were prepared
for each of the six alternative project arrangements described in
Sections 12.3 and 12.4. These cost estimates provided the basis for a
comparison of the economics of each alternative. The economic
comparison was subseqently incorporated into the decision process which
led to the selection of Alternative F for more detailed study in the
detailed feasibility phase. A summary of construction cost estimates
for each alternative are shown on Table 12-1. The cost of energy for
each alternative is developed on Table 12-2.
12.5.2 Basis of Cost Estimates
Quantities were estimated in the Interim Report for each major project
feature associated with each alternative. These quantities were based
on the conceptual layouts of the alternatives as described in Sections
12.3 and 12.4 and on the topographical and geotechnical data obtained
during the 1981 field studies.
The conceptual-level unit prices used for these estimates were
developed primarily from the following sources: 1) bid tabulations
12-18
2266B
from similar hydroelectric projects in Alaska which are either under
construction or have been recently constructed, and 2) unit cost data
recently developed by Ebasco in performing independent feasibility-
level and construction-level cost estimates for the Power Authority for
various hydroelectric projects in Alaska. For each unit cost selected,
consideration has been given to the magnitude of Quantities involved,
the nature of the material being worked, and difficulty of access to
and constructibility of the particular project feature. Mechanital and
electrical equipment items were developed from the sources mentioned
above as well as catalog values, vendor information, and experience.
These estimates were prepared to reflect a January 1982 bid price level.
The estimates include the following allowances which add to the direct
construction cost:
Contingencies
Engineering, Construction Management,
and Owner Administration
Interest Rate Used for Computing IDC
Escalation
20 percent
15 percent
3 percent per annum
zero
Interest and escalation parameters were based on Fiscal Year 1982 Power
Authority parameters. The estimates do not include any allowance for
the cost of mitigation of the loss of fishery habitat resulting from
dewatering Grant Creek. Such a cost would be required for all of the
six alternatives and would therefore not effect the economic comparison.
The cost estimates prepared using the procedures outlined above provide
a reliable basis for comparing the relative economic merit of each of
the alternatives. It should be emphasized, however, that these
estimates performed during the Interim Report and described in this
section were not feasibility-level estimates. Since the objective of
the studies in the Interim Report was to select the most desirable
project alternative, it was not judged to be cost effective to develop
12-19
2266B
a detailed feasibility-level estimate for each of the alternatives. A
full feasibility-level cost estimate, however, was prepared as part of
the subsequent feasibility study, and is presented in Section 18.0 for
the single recommended and optimized project.
12.5.3 Comparison of Cost of Power of Alternatives
The annual cost of each of the six alternatives was developed using
economic parameters and discount rates established by the Power
Authority. Table 12-2 shows the derivation of the annual costs. An
allowance for operation and maintenance was added to arrive at a total
annual cost. As shown on Table 12-2, Alternative 0 (the lake tap)
would be the most attractive for development strictly from the
standpoint of minimizing the cost of energy, closely followed by
Alternative F (the lake tap plus Falls Creek diversion). The four
remaining alternatives have a significantly higher cost of power when
compared to Alternatives 0 and F. The results of this comparison of
energy costs in conjunction with technical and environmental
considerations resulted in Ebasco's recommendation in the Interim
Report that Alternative F be developed through feasibility-level
studies. Primarily, it was felt, at that time, that the added energy
benefit associated with the Falls Creek diversion outweighed its
slightly higher cost of energy. Subsequent detailed power operation
and plant optimization studies described in Section 16.0 revealed that
a refined Alternative 0 arrangement without Falls Creek is actually
preferable.
12-20
2266B
F'ERC
ACCOUNT
331.
332.1
332.2
332.3
333.
334.
335.
336.
352.
353.
355.
356.
TABLE 12-1
ESTIMATE CF COIISTRUCTIOII COSTS FOIl ALTEIIIATIYE PllDJEtT AlIWIiDl:IITS!l
(.JMUARY 1!182 DOLLARS)
ALTEIIIATIYE
DESCRIPTIOIii A B C 0
HYDRAULIC PRODUCT 1011 PLANT
Power Pllnt Structures
Ind IIIprowaents 551,700 551,700 551,700 551,700
Reservoir HO,OOO HO,OOO HO,OOO 2,000,000
DIllS 12,553,tOD 12,053,600 12,062,400
Wlterways 7,024,000 6,814,000 6,5110,800 7,674,200
Wlter lIhtel s, Tul1lines
and litne ... to rs 2,066,000 2,066,000 2,066,000 1,780,000
Accessory Electricll Equil11ent 674,500 674,500 674,500 626,000
•
Miscellineous Powerpllnt
Equip!1tnt 650,000 650,000 650,000 610,000
ROlds Ind Bridges 3,381,000 !,56,OOO 2,674,000 2,541,000
TOTAL HYDRAULIC PRODUCTION PLANT 27.851.100 26.328.800 26.280.300 15.782.900
TRANSMISSION PLANT
TrlnSilission Pllnt Structures
InC! IIIpro'ltllents 3,800 3,800 3,800 3,800
Substation Ind Switching Eqpt. 566,000 566,000 566,000 526,000
Poles Ind Fixtures !l4,7oo 52,600 36,800 52,600
ConClUctors Ind DtV'l ces 56,!IOO 31,600 22,100 31,600
TOT AL TIWISMISSIOIii PLN/T 721.400 654.000 628.700 614.000
TOTAL DIRECT CDNSTRUCTIOII COSTS 'I.m.~ 'I.H~.S D.iS.1OO ll.~2§.~
I.,IRECT CONSTRUCTION COSTS 3,162,500 3,056,000 3,023,800 1,534,500
SUBTOTAL FOR COIITIIl6EIltY 31,735,000 30,038,800 21,871 ,goo 17 ,931,400
CONT I Illi£IIt Y (2D percent) 6,347,000 6,007,BOO 5,974,400 3,586,300
SU8TOTAL 38.082.000 36.046.600 36.846.300 21.517.700
E!liI II:ERI iii, COIISTIOCTION Mll'!T.
~ OWNER _T. (15 percent) 5,712,300 5,407,000 5,376,900 3,227,700
SUBTOTAL .3.7"'.lOO .,.453.600 .,.223.200 24.745.400
I lITE RE ST DURIIIi CONSTRUCTION
(3 PERCENT PER MIlUM) l,!l70,700 1,868,000 1,855,000 128,000
TOTAL alIISTRUCTIOII COST 8.765'000 .3,32UOO 43.°71.200 25.17 3 '400
Y F,. Inttri. Report
12-21
E F
551,700 551,70e
!ISO ,000 2,000 ,ooc
12, !l51 ,400 367,50C
10,318,200 10,798,80C
2,371,000 2,066,OO(
723,000 674,50:
775,000 650,OOi
4,557,000 3,717 ,00:
33.197.300 20.825.50
3,800 3,80'
606,000 566,00
!l4,700 52,60-
56,1100 31,60
761.400 654.00
~.23.700 21.479.5C
3,716,300 2,058,30
37,675,000 23,537,8C
7,535,000 4,707,60
45.210.000 28.2 4!i.4C
6,781,500 4,236,80
51.991.500 32.482.20
2,339,600 1,216,10
54,331.100 33.7OO J,Q
......
N
I
N
N
,.
TABLE 12-2
COMPARISml Of COST Of ENERGY fROM AlT£RNATIVE~1
Al TERNATIVE
A B C 0 E f
Estimated Total Construction Cost UOOO)!/ 45,765 43.322 43.078 25,673 54,331 33,700
Debt Service (SOOO)!/ 1,779 1,684 1,674 998 2,112 1,310
Operation and Maintenance ($000) 140 140
,
140 140 155 155
Total Annual Cost (SOOO) 1.919 1.824 1,814 1,138 2,267 1,465
Average Annual Energy (GWH)~/ 29.9 29.5 29.1 23.8 35.6 27.6
Total Cost of Energy (Mills/kWh) 64.2 61.8 62.4 47.8 63.7 53.1
!/ January 1982 bid price level.
2/ Amortization factor of .03887 based on three percent interest for 50 years (fiscal Year 1982 Power
-Authority parameters).
3/ from Table 16-2.
~/ from Interim Report.
.. " II " .. " .. • • • •
13.0 FIELD INVESTIGATIONS
13.1 GENERAL
Field investigations were conducted in both the 1981 and 1982 seasons.
This work included surveying and mapping, bathymetric surveys,
hydrological data collection, geotechnical explorations, environmental
data collection and cultural resource investigations. The objective of
the earlier 1981 field work was to gather site-specific data to support
the Interim Report studies. Specifically, this data provided a
reliable basis for developing conceptual layouts of the project
features for each alternative, for evaluating the engineering and
environmental considerations of each alternative, and for preparation
of comparative conceptual-level estimates of construction cost for each
alternative. The 1982 field investigations concentrated on obtaining
more detailed site-specific information in the vicinity of the
Alternative F arrangement which, at that time, was the preferred
arrangement. The purpose of obtaining this information was to support
the development of feasibility-level project layouts and to provide a
level of project-specific information required for an FERC license
application.
13.2 SPECIAL USE PERMITS
The project lands are currently under the jurisdiction of the U.S.
Forest Service (USFS) and, as such, Special Use Permits were required
before any field work could be conducted which might disturb the
lands. An application for a Special Use Permit for field
investigations was submitted to the USFS on October 7, 1981 which
described the work planned for the 1981 season. Authorization to
proceed with the field studies was given to the Power Authority from
the USFS by letter dated October 8, 1981. Another Special Use Permit
Application for the 1982 field investigations was submitted to the USFS
13-1
2310B
on March 31, 1982 with authorization given to the Power Authority in a
letter dated June 1, 1982. In order to perform the cultural resource
investigations an additional Special Use Permit for cultural resource
evaluation was obtained from the USFS on May 24, 1982. Copies of this
correspondence are included in Part VIII of the Technical Appendix.
13.3 EXECUTION OF FIELD WORK
Field work began on October 12, 1981 and continued until work was
halted during the 81-82 winter months. Logistical coordination for all
field work was performed by Rand M Consultants, Inc., under the
overall direction of an on-site Ebasco representative. Lodging for
field work personnel was provided at the nearby Crown Point Lodge. A
float plane and helicopter were used to transport personnel and
equipment between Trail Lake and Grant Lake and for aerial
reconnaissance work in the project area. Inflatable boats with
outboard motors were used on both lakes. Smaller helicopters were used
for movement of personnel engaged in ground control survey work.
A description of the surveying and mapping work is provided below. The
geotechnical, hydrological and environmental field investigations are
described in detail in Sections 14.0, 15.0 and Volume II -
Environmental Report, respectively. A detailed description of the
cultural resource investigations is also presented in Volume II.
13.4 SURVEYING AND MAPPING
Aerial photography and topographic mapping for the project area were
performed by North Pacific Aerial Surveys, Inc. Ground control
surveying and bathymetric surveying were performed by Rand M
Consultants, Inc. Topographic and bathymetric mapping which was
prepared for the project area includes the following:
13-2
2310B
1" = 400'; 10-foot contour interval mapping of the entire Grant
lake reservoir area.
1" = 200'; 5-foot contour interval mapping of the area where the
project features would be located.
1" = 400 1 ; 10-foot contour interval bathymetric surveys of Grant
lake (both the upper and lower sections).
111 = 200'; l-foot contour interval bathymetric survey across Upper
Trail lake in the vicinity of the powerhouse tailrace.
13-3
23108
14.0 GEOTECHNICAL STUDIES
14.1 GENERAL
Field geotechnical investigations were performed during the fall of
1981 and during the summer of 1982. Studies were completed by R&M
Consultants of Anchorage, under the direction of an Ebasco geotechnical
engineer. The fall 1981 studies included geologic mapping, drilling of
thirty-six auger holes, and the drilling of one diamond drill hole.
These studies concentrated along the Alternative A Project arrangement,
since previous work indicated that it would be the most desirable
option at Grant Lake. Most of the field work was concentrated at the
dam sites which would have been required for the raised-lake
alternatives. The results of these studies are contained in the
Technical Appendix Part I, and the Interim Geotechnical Report,
February, 1982 prepared by R&M Consultants.
The summer 1982 field investigations were focused along features of the
Alternative F Project arrangement as described in the Interim Report
and which was recommended for detailed feasibility stUdies. This
arrangement consists of a lake tap on Grant Lake, tunnel and diversion
of Falls Creek into Grant Lake. As a result of these detailed
feasibility studies, this alternative was dropped in favor of a
modified Alternative D arrangement consisting of lake tap without the
Falls Creek diversion. Field work began on June 9, 1982 and was
completed July 12. Investigations consisted of additional regional
geologic mapping, detailed geologic mapping along the tunnel alignment,
reconnaissance mapping along the proposed Falls Creek diversion
pipeline, and investigations of possible dam locations in Falls Creek.
The results of these activities are presented in the Technical Appendix
Part I and are summarized herein. A total of 5 diamond core holes were
drilled along the tunnel alignment and in the powerhouse cove and
intake area as shown on Figure IV-8. The detailed logs for these
borings are presented in the Technical Appendix Part I. Water pressure
14-1
0290T
tests were conducted in three of the holes. Nearly 3200 feet of
geophysical surveys were also performed at the powerhouse site (see
Figure IV-9). A bathymetric survey of Grant Lake was completed during
this field season.
14.2 REGIONAL GEOLOGY
Studies of the regional geology consisted of a review of available
literature, as well as reconnaissance mapping and study of the area
including Grant Lake, Upper and Lower Trail Lakes, Grant Creek, Falls
Creek, and Vagt and Kenai Lakes. The following discussion reviews the
regional morphology, geologic structures, stratigraphy, and lithology.
Figure IV-10 shows the location of the project geologic features
discussed below.
Morphology
The morphology of the site region is typical of sub-artic, glaciated
terrains. Broad U-shaped valleys dissect the mountain ranges and form
lowland areas with lakes, ponds, and streams. Elevations in the
project region range from 380 feet above mean sea level at Upper Trail
Lake to over 5000 feet in the adjacent mountains. Much of the region
was stripped clean by the movement of glaciers, leaving bedrock exposed
over large areas.
Within the mountainous areas, topography is rugged and slopes are
typically steep. Hanging valleys are common, with many of them
containing lakes. Small glaciers occur at the head of most major
valleys. The morphology of the mountainous areas indicate that most
were at one time completely buried and overtopped by glaciers.
Lowland areas are typically elongated, with varying amounts of alluvial
infilling. Some of the east-west trending valleys, notably the Grant
Lake and Kenai Lake valleys, have nearly right-angle bends where they
14-2
0290T
intersect the major north-south trending lowlands. This morphology
reflects diversion of side glaciers at their intersection with the
major southward moving glaciers.
Streams are common within the lowland areas, as are lakes and ponds.
In several areas elongated ridges of relatively low relief form
foothills to the major mountain peaks. One such ridge forms the area
between Grant lake and Upper Trail lake. These bedrock ridges parallel
the trend of the adjacent valley. Small bogs, formed in bedrock
depressions resulting from glacial scour, are common on the tops of
these ridges. Many are elongated in the direction of glacial flow.
Stratigraphy and lithology
The bedrock in the site region is a complex assortment of metamorphosed
sandstones, siltstones, and mudstone, with some fine-grained volcanic
units. The formations are part of the Valdez Group of Upper Cretaceous
age (64 to 100 million years old). Intense deformation of the rocks
caused extensive folding, faulting and metamorphism. The predominant
rock types in the project region are low grade metamorphosed
sedimentary rocks, including slates and meta-sandstones (Tysdal and
Case, 1979).
Extensive glacial deposits are absent in the project region. Minor
glacial till deposits may exist at the base of some of the bogs and
lakes in the area, and within some of the coves along Upper and lower
Trail lakes.
As shown on Figure IV-10, unconsolidated surficial deposits are
relatively rare in the project area. Alluvium is found at the head of
Grant lake, in the area between lower Trail lake and Kenai lake, within
a few of the coves around the Trail lakes, and within the small bogs
found in the low, bedrock ridges flanking the Trail lakes valley.
14-3
02901
These deposits are typically mixtures of silt, sand, and gravel. Minor
sand and gravel deposits are also found at the mouths of Grant Creek
and Falls Creek.
Poorly sorted mixtures of cobbles, gravel, sand and silt occur at the
base of the major avalanche chutes and are the result of transport by
snow avalanches during the winter and spring. These deposits are local
and not extensive.
Geologic Structures
The complex deformational history of the bedrock in the project area
has resulted in a large number of structural features. The primary
foliation in the bedrock is parallel to bedding. Most units strike
approximately north 5 degrees east (N05E) and dip 45 to 55 degrees to
the east. Joints are common throughout the area. Joint orientations
vary widely, although there are minor maxima oriented EW to NE-SW
dipping between 50 and 90 degrees to the south or southeast.
Minor faults and fracture zones were discovered in several areas. Two
fracture directions are dominant. One set trends NE and the other
N-NW. Both sets are clear on the aerial photography and satellite
imagery due to differential erosion. Grant Creek follows the most
obvious of these NE trending features, which has been named the Grant
Creek Fault. Exposures near the head of Grant Creek indicate that the
fault zone is 15 to 20 feet wide. Other NE trending fractures occur
both south and north of the Grant Creek Fault, and appear as
discontinuous linear features (Figure IV-10).
The expressions of many of the N-NW trending fractures have been
accentuated by glacial action. Since these faults nearly paralleled
the direction of glacial advance, the fault zones were easily scoured.
As a result, many of the fracture traces are now expressed as near
vertical bedrock cliffs that trend N-NW across the project region.
14-4
02901
The Trail Lakes valley is a long, north-trending valley that extends
from the town of Seward northward to Upper Trail Lake. It has been
called the "Kenai Lineament" since it is obvious on satellite imagery
as a long, linear feature. The trend of the valley is nearly parallel
to the N-NW fault set observed in the region, and the Kenai Lineament
may represent one of these fault zones that was extensively eroded
during the glacial period. Foster and Karlstrom (1967) and Plafker
(1969) have presented equivocal evidence for possible movement of a
concealed fault along the Kenai Lineament during the 1964 earthquake.
Careful field investigations during this study, however, found no
evidence of recent faulting in any of the numerous outcrops along both
shores of Upper Trail Lake. It is therefore unlikely that that Kenai
Lineament represents a major, active fault. More likely it is a
glacial valley whose orientation and location followed the N-NW trend
of the minor fault set observed in other areas.
14.3 SITE GEOLOGY
Powerhouse Cove
The powerhouse site is within a small, elongated valley approximately
1000 feet long and 500 feet wide at the proposed powerhouse site (see
Figure IV-a). The valley lies within a bedrock depression formed by
glacial erosion. The valley is adjacent to and drains into Upper Trail
Lake. Elevations within the valley range from the water line of Upper
Trail Lake at elevation 467 to elevation 500 along its eastern margin.
The bedrock within the powerhouse valley is similar to that outcropping
throughout the area. Two exploratory borings indicate the presence of
massively bedded greywacke with some interbedded slate and thinner
greywacke beds. Within the valley itself there are several low ridges
or hummocks underlain by resistant greywacke beds.
14-5
0290T
Seismic refraction profiles within the valley indicate a layer of
sedimentary infilling averaging 5 to 25 feet, with locally higher
thicknesses over bedrock lows (Figure IV-9). The two exploratory
borings (DH-l and DH-2) penetrated 28 feet and 18 feet, respectively,
of soils ranging from sand and silt near the surface to poorly sorted
mixtures of cobbles, gravel, sand and silt at depth. The lower
materials may represent glacial till or outwash, while the upper
material is probably recent stream or lake bed sediment.
The groundwater table in the powerhouse valley is at or near the
surface.
No direct observations of geologic structure could be made due to the
overlying thickness of overburden. Data from the borings and the
outcrops surrounding the valley suggest that the bedding within the
bedrock strikes to the north and dips at 45-55 degrees to the east,
paralleling the regional trend. Joints observed in the two exploratory
borings dipped between 45 and 80 degrees. No evidence of shear zones
was discovered in the borings.
Analysis of air photos, satellite imagery and topographic maps indicate
a long linear feature trending N-NW from the eastern side of Vagt Lake,
along the eastern side of the powerhouse valley, and possibly extending
several thousand feet to the north (Figures IV-10 and IV-ll). lhe
linear feature represents a steep cliff face that forms the eastern
shore of Vagt Lake and the eastern boundary of the powerhouse valley.
Investigations of this feature along its length from the ground and
from the air revealed no positive evidence of fault control, although
it likely that this linear feature is an old fault. Its present
topographic expression is not the result of movement, however, but the
result of differential erosion during glacial advances. The fault zone
formed a zone of weakness nearly parallel to the direction of glacial
movement, and thus was accentuated by erosion.
14-6
02901
Power Tunnel and Intake
The power tunnel and intake would be completely within the bedrock that
forms the ridge between Grant and Upper Trail Lakes. The rocks are
typical of the bedrock throughout the area, and are composed of
metamorphosed sedimentary rocks of the Valdez Group. Figures IV-ll and
IV-12 present a geologic map and profile along the tunnel alignment.
The predominant rock types are greywacke, slate, and mixtures of the
two. Field investigations and exploratory borings indicate that the
greywacke is an extremely hard and dense metamorphosed sandstone of
varying composition. These units typically form massive beds up to
several tens of feet thick, and are the most competent rocks in the
area.
Varying mixtures of greywacke and slate form the rest of the bedrock
along the tunnel alignment and intake. The units typically consist of
beds of greywacke up to 12 inches thick interbedded with slate beds of
similar thickness. The small-scale topography of the area provides
indication of the underlying rock type. Ridges are commonly underlain
by massive greywacke beds, while bedrock depressions or swales indicate
higher percentages of slate (Figure IV-12).
Bedding along the tunnel alignment parallels the regional trend. Most
units strike to the north, and dip 45 to 55 degrees east. Joints are
common throughout the area, although their orientations vary widely.
Joint spacing is variable, and ranges from over three feet to less than
10 inches.
Minor shear zones were encountered in the exploratory borings along the
tunnel alignment. The shear zones were usually steeply dipping, and
ranged in thickness from less than a few inches to several feet. In
addition to the minor shear zones encountered in the exploratory
borings, analysis of topography and aerial photographs indicates
14-7
02901
several N-NW trending linear features crossing the tunnel alignment.
These linear features are topographically expressed as small stream
valleys or low cliffs bounding the bogs found along the ridge. It is
likely that these linear features mark the trend of minor faults.
There is no evidence that these are active features, but rather old
fractures that formed during the deformation and metamorphism of the
area.
The single exploratory boring (OH-5-82) in the intake area revealed two
open and weathered shear zones that parallel the bedding orientation.
These two zones are interpreted as bedding-plane failure surfaces,
resulting from gravitationally-induced movement of slabs of massive
greywacke. Such bedding plane failures are discussed in Section 16.5.
Reservoir
Grant Lake is over six miles long, and fills an L-shaped depression
formed by glacial erosion (Figure IV-10). It is divided into two parts
at the bend in the "L" by a natural bedrock constriction. The shores
of Grant Lake drop off steeply beneath the water, with slopes of over
2H:1V (25 degrees) in many areas. The lake is nearly flat-bottomed,
with water depths as deep as 300 feet. The bedrock constriction at the
bend in the "L" forms the Grant Lake narrows, where water depths range
from 30 to less than 4 feet.
Most of the shoreline of Grant Lake consists of steep bedrock slopes or
cliffs. The two main exceptions occur at the head of the lake, where
an alluvial delta has been formed by the glacial streams, and near the
outlet of the lake at Grant Creek, where a small alluvial valley has
developed due to the influx of avalanche debris from the adjacent
peaks. Materials within these areas consist of unconsolidated mixtures
of silt, sand, gravel, and cobbles. Other unconsolidated deposits
occur along the north shore of Grant Lake, just west of the narrows.
These deposits consist of poorly sorted sand, gravel, and cobbles.
14-8
02901
Minor accumulations of similar material occur as small deltas around
the shore of the lake, typically at the mouths of small side streams or
avalanche chutes.
The bedrock geology of Grant Lake is typical of that of the entire
region. Lower Grant Lake is underlain and bounded by the same
meta-sedimentary rocks discussed above. The units strike nearly
north-south, and dip steeply to the east.
Falls Creek Diversion -Revised Route Considered for Alternative F
The alignment of the Falls Creek diversion dam specified in the Interim
Report was relocated approximately 2500 feet upstream in the detailed
feasibility studies based on the acquisition of more detailed survey
information in the area (see Figure IV-25). The detailed survey
information showed the original location to be in a steep-walled canyon.
The area of Falls Creek considered for this revised location is
underlain by the typical Valdez Group rocks exposed throughout the
area. Bedrock is exposed along Falls Creek for virtually its entire
length, except where it drains into Trail Lake. Reconnaissance
investigations revealed interlayered greywacke and slate similar to
that exposed around the project site. Little or no soil cover was
found in the diversion dam area.
The trend of the bedrock parallels the regional trend, striking north
and dipping to the east. No major faults were discovered during the
preliminary investigations.
The revised Alternative F pipeline route between the Falls Creek
diversion dam and Grant Lake, shown on Figure IV-25, would be founded
on bedrock for about seventy percent of its length, and on
unconsolidated sediments for about thirty percent of its length.
Bedrock areas are overlain by a thin soil cover.
14-9
0290T
The areas of sediments crossed by the pipeline are bedrock depressions
and small valleys filled primarily with poorly sorted mixtures of
cobbles, gravel, sand and silt. Depth to bedrock in these areas is
unknown at this stage of investigation.
14.4 ENGINEERING GEOLOGY FOR PROJECT STRUCTURES
Powerhouse
Preliminary layouts of the powerhouse assumed that the powerhouse would
be constructed on bedrock near the center of the powerhouse valley.
The results of the mapping and boring programs and the seismic
refraction survey suggest, however, that the powerhouse should be
located in a cut constructed within the bedrock bounding the eastern
edge on the valley. The mapping work in this area indicates that the
north end of the powerhouse valley is bounded by a fracture zone that
is one of the prominent NE trending lineaments, observed on the
satellite imagery. Although this fracture zone is old and not active,
it does present a zone of weakness that should be avoided. Similarly,
analysis of air photos suggests that the eastern boundary of the valley
is formed by a minor shear zone that occurs at the base of the bedrock
cliff. No direct observation of this shear has been made to date, nor
is it considered an active fault. It probably represents a zone of
weakness and poor rock quality and was, therefore, avoided by locating
the powerhouse in the sound bedrock to the east. See Figures IV-21 and
IV-22.
No major slope stability problems are envisioned at the powerhouse
because of the orientation of the bedding. Bedrock in the cliff
overlooking the powerhouse valley dips about 55 degrees to the east,
and, therefore, is not subject to bedding plane failures westward into
the powerhouse area.
14-10
02901
Other structures in the powerhouse area include the tailrace channel
and the salmon holding facility. These structures will be constructed
in the valley. The two borings and the seismic refraction study
indicate that depths to bedrock vary considerably in the valley, with
depths along the tailrace channel exceeding 15 feet (Figure IV-9). The
data suggests that the tailrace channel will be cut within the
sedimentary valley fill. Tailrace slopes will be cut at 2H:1V and
protected with rip-rap.
Tunnel
The engineering geology for the proposed tunnel alignment was
investigated both by detailed surface mapping and with three boreholes
(R&M Consultants, Nov. 1982). The detailed mapping was designed to
identify any preferred tunnel alignments through the bedrock ridge.
The results indicated that the original proposed location and
orientation of the tunnel were as good as any nearby alternatives. The
drilling program was then designed to intersect the tunnel alignment at
depth. Two holes were drilled along the central part of the alignment,
and one was drilled at the eastern end to investigate conditions near
the intake and gate shaft locations (Figure IV-ll). The total drilling
length was 486 feet.
Three primary rock types were encountered in the borings. An average
of 40 to 50 percent of the core is hard, dense greywacke, ranging from
massive to thinly bedded. Borehole thicknesses of greywacke units
ranged from less than 5 feet to over 50 feet. The greywacke is the
most competent rock unit in the section, with Rock Oua1ity Designation
(ROD) values exceeding 80 percent in most areas. ROD is the ratio of
the sum of the length of core pieces greater than 4 inches in a core
run to the total length of the core run, expressed as a percentage.
The higher the ROD, the more competent the rock. The rock is typically
unweathered. Joint spacing and orientation is variable, although
spacings of 1 to 3 feet are typical. Most joint surfaces are
unweathered.
14-11
02901
The second rock type encountered in the borings is slate, which makes
up less than 15 percent of the total core. The slate is typically dark
grey, hard, dense, and unweathered. It is characterized by many
closely spaced fracture planes (called cleavage) which results in low
ROD values and sometimes poor recovery. Most slate units observed in
the borings are less than 3 feet thick.
The third rock type is a mixture of slate and greywacke, and has been
termed "sandy slate". The rock is light to dark grey, and consists of
varying percentages of slate and greywacke. This unit makes up about
35 to 45 percent of the total core recovered. The rock unit is
typically hard, dense, and unweathered, with ROD values ranging from 50
to SO percent. Individual units are usually less than 6 feet thick in
the borings. Joints and fractures vary in spacing and orientation,
with spacings ranging from over 1 foot to less than an inch.
Water pressure tests were conducted in these three boreholes to
identify any open zones and to determine the overall permeability of
the bedrock. Table 14-1 summarizes the results of these tests.
Testing of the entire length of boreholes DH-3-S2 and DH-4-S2 yielded
-5 -6 permeability values between 10 and 10 cm/sec. These data
indicate very low permeability in the bedrock, suggesting that the
joints found in the borings are closed and tight. Permeability values
in borehole DH-5-S2 at the intake area ranged from 10-4 to 10-5
cm/sec. These higher values reflected water loss through the two open
fractures zones identified in the boring as possible bedding-plane
failure surfaces.
Plastic piezometer pipe was installed in boreholes DH-3-S2 and
DH-4-S2. Water level monitoring indicates that the groundwater level
is at or near the surface along the tunnel alignment in the intake area
and along the top of the ridge between Grant and Trail Lakes.
Therefore, most of the power tunnel would be below the water table,
except near the portal at the powerhouse end.
14-12
02901
Additional data was obtained by a visit to the Case Mine. located about
2 1/4 miles north of the Grant Lake tunnel site. The objective of the
visit was to observe the stability and in-situ conditions of rock
similar to that at the Project site. Rock at the mine was estimated to
contain about equal Quantities of interbedded slate and greywacke. and
strikes about N10W. dipping 55 to 60 degrees to the east.
About 1200 feet of 4-foot by 6-foot section adits had been driven
during the 50 years since the mine was opened. The mining activities
followed a mineralized Quartz vein and associated shear zones. The
rock at the mine site is therefore, considerably more fractured and
less stable than the rock encountered along the tunnel alignment.
Noneless. the mine works are stable although unsupported.
The rock along most of the tunnel alignment is of high Quality. Figure
IV-13 indicates the cumulative distribution of ROD within these three
boreholes. The graph shows that nearly 80 percent of the core had ROD
values of 40 and above, with over 60 percent of the core exhibiting ROD
values over 70. These ROD values, coupled with the small design
diameter of the tunnel and low bedrock permeability, suggest few
problems in construction or operation of the tunnel. This conclusion
is supported by the data obtained during the visit to the Case Mine.
The results of the boring program suggest that, as preliminary design
values, an average of 3 inches of shotcrete will be sufficient within
the tunnel, and less than 15% of the tunnel length is anticipated to
require rock bolting. Steel support structures will probably be
unnecessary. except perhaps at the portals. These support requirements
could very possibly be reduced as actual construction proceeds, and the
condition of the rock is observed.
14-13
02901
Gate Shaft
The geotechnical studies in the gate shaft area revealed very
competent, massive greywacke. It is likely that less than 10% of the
gate shaft will need treatment by rock bolting. An average of 3 inches
of shotcrete lining is anticipated.
The exploratory boring (OH-5-82) in the gate shaft/intake area revealed
two steeply dipping shear zones at depths of about 44 ft and 60 ft
(Geotechnical Report, R&M Consultants, Nov. 1982). These zones were
open, unfilled, and bounded by weathered rock surfaces. These two
zones are presently considered bedding-plane slippage planes, resulting
from gravitational failure of large slabs of greywacke. This type of
failure would be expected along the western shore of Grant Lake, where
the massive greywacke beds dip steeply towards the lake. The presence
of these two planes suggests that additional borings should be
completed in the intake/gate shaft area prior to final design to
provide additional data for remedial measures, as necessary.
Reservoir
The bathymetric survey of Grant Lake completed during the summer of
1982 indicates that the narrows between upper and lower Grant Lake will
act as a natural dam if the level of Grant Lake is lowered during
operation of the project (Geotechnical Report, R&M Consultants, Nov.
1982). The controlling ledge of rock occurs beneath the southern of
the two channels in the narrows, at an elevation of about 685 feet.
'[his natural constriction would have to be excavated to allow movement
of water from upper to lower Grant Lake during operation of the project.
Reconnaissance mapping around the shores of Grant Lake was oriented
towards the identification of potentially unstable slopes that might
fail during project operation. The potential for slope failure around
the reservoir rim is discussed below. At this stage of investigation,
the stabilization of reservoir slopes is considered unnecessary.
14-14
02901
Access Roads
Access roads will be constructed to follow existing roads as much as
possible. In areas with no existing roads, road alignments have been
chosen to minimize extensive rock cuts and disturbance of the natural
topography. No unusual engineering problems are foreseen for any of
the proposed access roads.
Falls Creek Diversion Dam and Pipeline (Alternative F)
No detailed exploratory work was done in the area of the Falls Creek
diversion dam and pipeline proposed for the Alternative F project
arrangement. Preliminary work indicates, however, that the dam would
be founded on competent bedrock, and that probably less than 3 feet of
sediment exists in the streambed. Reconnaissance investigations
indicate that much of Falls Creek is in a bedrock canyon, with most of
the canyon walls near vertical. For this reason a pipeline route was
established to follow Falls Creek downstream of the diversion dam and
quickly ascend out of the canyon. Outside of the canyon, geologic
mapping along the route suggests that about 30 percent of the pipeline
would be founded on sedimentary material, and about 70 percent would
traverse bedrock at or near the surface.
The pipeline would have to cross one major avalanche chute about midway
between Falls Creek and Grant Lake (Figure IV-10). Additional burial
depth of the pipeline within the sedimentary deposits at the base of
this chute would provide adequate protection from damage by avalanche.
14.5 GEOLOGIC HAZARDS
Geologic hazards around the Grant Lake project site are related
primarily to the high seismicity of the area. Other hazards considered
are related to mass movements of material, including landslides,
rockslides and avalanche.
14-15
02901
14.5.1 Seismicity
Seismic hazards include vibratory ground motion, ground rupture,
seismically-induced slope failure, seiche, and liquefaction. The
potential occurrence of each of these hazards is discussed below.
Vibratory Ground Motion
The high level of seismic activity in this region of Alaska suggests
that the Grant Lake project features may at some time be subject to
vibratory ground motion.
lable 14-2 is a compilation of all the known sources of earthquakes
that are close enough to the project site to have significant impact.
The maximum credible earthquake (MCE) has been calculated for each
structure using relationships developed by Slemmons (1977) or Wyss
(1980), depending on the nature of the source feature. The MCE for the
random crustal event was selected as magnitude 6.0, a conservative
upgrade from the maximum recorded magnitude of 5.5.
The peak acceleration values, calculated using the most recent accepted
techniques, are indicated on the table. The maximum calculated
acceleration (50 percentile value) at the site is 0.40 g from the
random crustal event and 0.37 g from the Aleutian Arc megathrust.
Return periods for these maximum events have been estimated using
historical and instrumental earthquake data. Based on the estimated
return periods and the time since the last major event, the likelihood
of such events was estimated for the life of the project. The
likelihood of another 1964-type event on the megathrust is low for the
life of the project, since the return period is in excess of 160
years. The likelihood of a large random crustal event is moderate to
high with return periods estimated between 50 and 100 years. However,
since the location of this event is random, the probability of such an
event occurring at the project site is actually quite low.
14-16
02901
Ground Rupture
Rupture of the ground during seismic events can damage any structures
that are located across the trace of the rupture. Ground rupture is
associated with the movement of active fault zones. There are no known
active faults crossing the project features at the Grant Lake site.
During the magnitude 8.4 Alaskan Earthquake of 1964 many small faults
moved as a result of the tremendous earth movements during that event.
These faults are not considered active or capable in the normal sense
of releasing accumulated stress, but occurred as sympathetic failures
along pre-exisiting zones of weakness. In addition to these secondary
movements, differential settlement occurred in many areas, resulting in
ground cracking and heaving without actual fault movement. Although
some evidence has been found in the project region of such sympathetic
shifting or differential settlement during the 1964 event, there is no
evidence that such phenomena occurred in the area of the project
features. Ground rupture resulting from any of these processes, then,
is not considered a hazard for this project.
Seismically Induced Slope Failure
One of the most common features associated with moderate to large
magnitude earthquakes is slope failure. Triggered by ground motion,
naturally unstable slopes can fail. Slope failures can be broadly
classified into landslides, avalanches, and slab or tumbling failures
of rock faces.
There is little material in the project area that would be susceptible
to landsliding during seismic events. No evidence was found in the
project area of major landslides or their deposits, although some minor
landslide debris was noted uphill from the intake area.
14-17
0290T
Seismically induced avalanches could occur in most of the mountains
above the project area. The topography around the project facilities
themselves, with the exception of the Alternative F Falls Creek
diversion system, suggest no hazard from avalanche. The effects of
avalanches along the Falls Creek Diversion system are discussed below.
Slab or tumbling failure of rock faces during seismic events is common
in areas of unstable rock slopes. The western shore of Grant Lake,
where the gateshaft and gatehouse are located, is particularly
susceptible to such failures, as the slopes are steeply dipping slopes
of bedrock. Data from the exploratory boring in the intake area
suggest that bedding-plane slides have already occurred.
Feasibility-level remedial measures have been developed to preserve the
stability of the cut slope at the gatehouse. These measures would have
to be confirmed during the detailed design phase by additional field
explorations.
Seiche and Landslide-Induced Waves
Seiches are waves in lakes that are formed by the sloshing of water
back and forth as the result of ground shaking during seismic events or
the catastrophic inflow of material by slope failures around the lake's
rim.
There are several areas surrounding Grant Lake that could be sources of
earth or avalanche material for mass movements into Grant Lake, which
could generate seiche waves. However, field work did not reveal any
areas along the shoreline of Grant Lake where wave damage above normal
high water levels was noted. This observation suggests that
significant wave run-up did not occur during the 1964 earthquake.
Further, the volumes of material that could enter Grant Lake are
probably not sufficient to generate very large seiche waves.
14-18
0290T
Investigations around Lower and Upper Trail lakes indicate that the
surrounding topography coupled with the shallowness of the lakes
themselves present significantly less hazard from seiche. There are
also no areas of material that could generate large waves by mass
movement into the Lakes. The present design of the Grant Lake project
indicates that it will not be susceptible to damage by seiches that
might be expected to occur in Grant or Trail Lakes.
Liguefaction
Liquefaction is the failure of loose, water-saturated sediments under
seismic ground shaking. However, major project features would be
placed on or in bedrock, so no liquefaction problem will exist.
14.5.2 Avalanches
Hazards from avalanches have been recognized at the Falls Creek
diversion dam area and along the diversion pipeline route for
Alternative F. The upper reaches of Falls Creek are bounded by steep
mountain slopes with extensive evidence of avalanche. Hazards
associated with avalanche, causing dam overtopping, would be minimal
since the Falls Creek diversion structure would not be impounding much
water, especially in the winter months.
The diversion pipeline would be located in areas of avalanche
activity. In order to minimize the possible disruptive effects of
avalanche activity on the pipeline, it would be located either to the
west, and out of active areas, or at the very western limits of the
active areas. In addition, the pipeline would be buried along its
entire length and additional protective cover provided where it is
within the western limits of the avalanche activity.
14-19
02901
14.5.3 Hazards Induced by Reservoir Fluctuation
Hazards related to the fluctuation of the level of Grant Lake during
project operation include slope failure and reservoir-induced
I
seismicity. These hazards are discussed below.
Slope Failure
lhe fluctuation of Grant Lake during project operation may trigger
slope failures, especially along the north shore of the lake, where old
landslide and avalanche deposits exist. Failures are not expected to
be large, nor present any hazard to safe operation of the project.
Reservoir-Induced Seismicity
In many areas of the world, the filling of reservoirs or large
fluctuations in lake or reservoir levels triggers small to medium
magnitude earthquakes. It should be noted, however, that the water
pressure changes merely act as triggers for these events, and do not
actually cause stress build-up in the rocks. The bedrock materials
must already be stressed and prone to earthquake activity if
reservoir-induced seismicity is to occur.
Grant Lake is an existing reservoir which has already experienced a
variety of changing stresses, ranging from filling and covering by
thousands of feet of ice, to ice retreat, and filling with water.
Little, if any, reservoir-induced seismicity is expected to occur
during operation of the project. Any shocks that do occur will likely
be of small magnitude and present no hazard to the project or
surrounding areas.
14-20
02901
14.5.4 Other Hazards
Other geologic hazards addressed are seepage, subsidence, and mining.
The potential hazards of each of these to the Grant Lake Project are
discussed below.
Seepage
The groundwater table along most of the tunnel alignment is at or near
the ground surface. Bedrock permeabilities are very low, however, so
that seepage problems will only occur at the intersection of the tunnel
with open joints or fractures. Seepage problems during construction
are not anticipated to be severe.
Subsidence
There are no areas of project features that are susceptible to
subsidence. Although large areas of southwestern Alaska either
uplifted or subsided during the 1964 earthquake, such large scale
changes would have had little or no impact on the Grant Lake project.
Mining
Although there are several active and inactive mines around Grant and
Trail Lakes, none of the mining activites are near the project site.
No exploratory shafts or old mines exist near the project features.
The results of field investigations and exploratory borings indicate no
economic mineralization around the project site. Old or potential
mining activities, therefore, are not considered hazard to the project.
14-21
02901
TABLE 14-1
SUMMARY OF PERMEABILITY TESTS
Boring No. Tested Interval Pressure Range (1} Permeabilit~ (2}
DH-3-82 22.2 to 185.2 ft 25 to 150 psi 10-5 to 10-6 cm/sec
DH-4-82 60.0 to 225.3 ft 20 to 40 psi 4 x 10-5 cm/sec
116.0 to 225.3 ft 20 to 40 psi 4 x 10-5 cm/sec
DH-5-82 15.0 to 75.4 ft 20 to 50 psi 10-4 cm/sec
40.0 to 48.0 ft 30 to 50 psi 2 x 10-4 cm/sec
56.0 to 64.0 ft 30 to 60 psi 4 x 10-4 cm/sec
Notes:
(1) Pressures given are gauge pressures at the surface.
(2) Representative or average values for entire test.
(3)
(3)
(3) Identified shear zone (these two zones account for virtually all
of water take during entire hole test (15.0 to 75.4 ft interval).
Source: Geotechnical Report, Grant Lake Hydroelectric Project, R&M
Consultants, Nov 1982.
2620B
14-22
02901
Source Ty,. of Dis ... from F IUIt Len .. Fait Proilct Sill
R.ndom Crustal -3 km -Event
Aleutian Trench·Arc
Megathrust (Main MlgIthrust 30 to 35 km 2,000 km
Thrust)
Beni()ff Zone M ... thrust 71 km -
CII1Ia Mountain·
Ceribou F..tt Oblque StrikHlip 127 km 200km
Brui:t B.y Fault Reverse 125 km 300 km
Knik·Bonier
H .... Fault Ravene 48 km 1,700 km
Johnstone Bay Fault Nonnal (7) 67km 20 to 70 km
Hanning Bay Fault Ravena lOB km 6 km
Patton Bay Fault RIMIfII 118 kin SOOkm
Volcanic -188 kin -
Denali Fault StrikHtip and 1,000 to
Yaktaga &. Shumigan M ... thrust 255 to 300 km 2,000 km Seismic Gaps
* CsIcuI6tion methods tnIId as indictJtftI by the number
1) MCE ca/culati(}fls bIIed primarily on S/.",mons (1977) UJing ntimated
rupture length instad of tota/length where approprillte.
2) MCE ca/cullltion bll$lld on Wyss (1980).
3) Based on the instru""nt recorded Stlismicity.
14-23
Estitnllld
Ru,tJlre
L ......
-
500 km
-
120 km
140 km
120 km
10 km
6 km
62km
-
400 to
500 km
TABLE 14-2
CHARACTERISTICS OF SEISMIC SOURCES
o .......... nt Minimum His1eriaI of Recent MCE· oistlnce to Slismicity Sedimlnts Epiclntlr
Seismic activity
up to magnitu de None 3) 6.0 o km
5.5
Very high Trace not visible 1) 8.5 m.gnitude 8.4 but asociated o km
in 1964 offset in 1964
2) 8.7
Associated
seismicity up None 3) 7.5 60 km
to 7.5
Associated Offset 1) 7.4 nismil:ity up to Hoiocene 2) 7.4 127 km
magnitude 7.0 sediments
Associated
seismicity up to None 1) 7.4 125 km
magnitude 7.3
Offset
None late glacial 1) 7.5 48 km
moraines
. None Scarp in 1) 6.4 67km Holocene talus 2) 6.0
Active Offset 1) 4.8 during /following during the 2) 5.4 lOB km
the 1964 nrthquake 1964 earthquake
Active Offset 1) 6.1 during/foil owing during the 2) 6.9 118 km
the 1964 earthquake 1984 earthquake
Seismic
Activity up None 1) 5.75 188 km
to magnitude 5.5
High to low
rtClnt activity; Offset
Very high historic Hc.locene 1) 8.6 280 km
seismicity sediments
7. to B.+
** Ground Motion P8famettirs from the following sour~:
1. Page et. al., 1972
2. Krinitzsky, 1978; 80'J6 of obStlrved '*te limit
3. Bolt, 1973
4. 50 per=entile value, Joyner & Boore, 1981
5. 50 percentile villue, Campb6/!, 1981
The Campbell f"field altrlmBtive d value WBS used fer dismnces over 50 kin.
The Joyner & 800re equations were used for 8.0+ events without modification.
Estimltld
0.,111 ta
Focu
3 km
30 to 35 km
40 km
15 km
15 km
15 km
15 km
10 km
10 km
15 km
15 to 40 km
Pllk··
AcaIa'Ition in Estitnltld
G 's: 50 P..antile Return Period
V ....
4) 0.38 50 to 100
5) 0.40 yan
4) 0.38 160 to 300
5) 0.37 yean
4) 0.06 100 yean 5) 0.01
4) 0.03 Not
5) 0.01 datanniited
2) 0.03 Not
5) 0.01 determined
4) 0.11 Not
5) 0.01 detenni:ted
4) 0.04 Not
5) 0.01 determined
4) 0.01 Not
5) 0.01 determi;,ed
4) 0.02 Not
5) 0.01 determined
4) 0.01 Not
5) 0.01 determined
4) 0.01 BO to 200
5) 0.01 year.
Source: Grllnt Lllke Hydroelectric Proiect
Interim Geological Report
Estimilld Likllihood
of Eftllt Wi1llin NDt
111 Veers
Mod~nte to High
Moderate to Low
Moderate to High
Modente to Low
Moderate to Low
Low
Low
ModEnte to low
ModErate to low
Mockr.Jte to low
High
PreplI"d by R & M Consulmnts, Inc., January 1982
15.0 HYDROLOGICAL STUDIES
15.1 GENERAL
Field and office hydrological studies have been conducted for the Grant
Lake project for two purposes. First, an estimate of the available
runoff on a monthly basis from the Grant Lake and Falls Creek basins
has been made for the purpose of evaluating the power output potential
and operational characteristics of the project. Secondly, the flood
characteristics of both basins have been assessed to serve as a basis
for sizing certain project features. The field study program was
conducted by Rand M Consultants, Inc. and office studies were
performed by both Rand M Consultants and Ebasco. The studies which
have been performed in these areas are discussed below.
15.2 EXISTING DATA
The runoff from the Grant Lake drainage area was recorded for 11 years
at a USGS gaging station located 0.3 miles upstream of the mouth of
Grant Creek. Continuous historical streamflow records for Falls Creek
did not exist prior to the implementation of the field data collection
program in 1981. A summary of the available historical streamflow data
in the project vicinity is given below.
Station Drainage
USGS Station Name Number Area (mi2) Peri od of Record
Grant Creek near Moose Pass 15246000 44.2 1947-1958, 1982
Falls Creek near Lawing 15250000 11.8 1913, 1963-1970
(Annual Peaks), 1982
Trail River near Lawing 15248000 181 .0 1947-1974
Ptarmigan Creek at Lawing 15244000 32.6 1947-1958
Crescent Creek near Cooper
Landing 15254000 31.7 1949-1966
Kenai River at Cooper Landing 15258000 634.0 1947-Present
Wolverine Creek near Lawing 15236900 9.5 1966-1978
Nellie Juan River near Hunter 15237000 125.0 1960-1965
15-1
25628
lhe 10cat10n of the Grant Creek, Trail River, and Falls Creek gaging
stations are shown on Figure IV-2.
15.3 FIELD STUDIES
To supplement the existing historical data for the site, a hydrological
and climatological field data collection program was initiated in the
fall of 1981. A climatological station was installed at an exposed
site near the natural outlet of Grant Lake. Wind speed and direction,
temperature and precipitation parameters were recorded at the station
on inkless chart paper for periods of up to 30 continuous days on a
single chart. Data is presented in Part VI of the Technical Appendix
as a total daily precipitation and maximum, minimum and mean daily
tempe ra tu res.
Streamflow gages were installed on Grant and Falls creeks in the fall
of 1981, and periodic measurements of streamflow were made on a monthly
basis during the fall and winter months of 1981. Continuous recording
gaging stations were established at both creeks in April 1982, using
Leopold and Stevens F-l water level recorders.
15.4 DEVELOPMENl OF MONTHLY SlREAMFLOW MODEL FOR SilE
15.4.1 Grant Creek
lhe historical monthly streamflow record for Grant Creek (1947-1958)
was extended using the HEC-4 Monthly Streamflow Simulation Model. The
historical data from the USGS gages at Trail River, Crescent Creek and
Kenai River were used for this analysis. A total of 33 years of
monthly data, extending from water year 1948 through 1980 was
developed. The first 11 years of record were taken directly from the
historical data from the Grant Creek gage, and the remaining 22 years
of record were reconstituted by correlation. A tabulation of the 33
15-2
2562B
years of record is shown on Table 15-1. These inflows have been used
in the power operation studies for both the Interim Report and
Feasibility Report.
The continuous streamflow records gathered during 1982 at Grant Creek
were examined to determine if there was any significant deviation from
the long-term historical records (1947-1958) or the simulated monthly
streamflow record (1959-1980) used in the power studies. This analysis
was performed to ascertain whether the results of the streamflow
extension performed in 1981 for the Interim Report needed any
modification prior to performing power operation studies in 1982 and
1983 for the Feasibility Report. Both 1982 data and long-term data for
June-September are presented in Table 15-2. The average monthly
streamf10ws recorded in 1982 were within one standard deviation of the
long-term mean for each month, and did not reflect any record high or
low values. Flows for June-August were lower than average, while
September flows were higher than average. A similar flow pattern was
observed on the Susitna River in 1982, so the pattern seemed to be
regional.
The average monthly flows recorded in 1982 from Grant Creek were also
compared to those of the Kenai River at Cooper Landing, which was a
major station used in extending the historical streamflow record for
Grant Creek. A consistent pattern was found, with Grant Creek flows
about 7% of those on the Kenai River except in September, when a
glacial outburst flood occurred in the Kenai basin, but which did not
effect Grant Creek flows.
Based on this analysis, it was concluded that the nature of streamflow
data collected in 1982 did not warrant any revision to the 22 years of
extended streamflow record developed in 1982. The 33 years streamflow
record used previously for the Interim Report studies was therefore
considered appropriate use in the final power studies.
15-3
2562B
15.4.2 Falls Creek
Monthly data for Falls Creek for use in the Jnterim Report studies was
determined by developing monthly ratios of flow between Falls Creek and
Grant Creek, using regression equations deve"loped in the Water
Resources Atlas for USDA, Forest Service, Reqion X (Ott Water
Engineers, 1979). These ratios were applied to the monthly Grant Creek
streamflows to obtain a monthly streamflow record for Falls Creek.
The streamflow data collected at the Falls Creek and Grant Creek gaging
stations from May to mid-October in 1982 was utilized to develop
monthly ratios of flow between Falls Creek and Grant Creek for use in
the final power studies. A mass balance of snowpack, rainfall and
runoff was also performed, which provided a check of the 1982 flow data.
The ratios developed for Falls Creek were adjusted by area to
87 percent to account for the upstream locat'on of the point of
diversion versus the location of the streamgage. An additional
10 percent reduction was applied to account for spill at the Falls
Creek diversion during periods of high flow. This value was determined
by running an hourly simulation model of the recorded Falls Creek flows
based on actual daily flows and characterist~c diurnal variation for
each month.
The adjusted monthly flow ratios for 1982 were applied to the average
monthly Grant Creek flows for the period of record to estimate average
monthly flows for Falls Creek and for use in the power operations
studies to determine the energy contribution from Falls Creek. The
adjusted ratios are shown in Table 15-3. Only flows for May through
October are included, since freezeup may occur during any of the
remaining months and the diversion is assumed to be shut down to
prevent pipe freeze. Furthermore, the Falls Creek flow contribution is
negligible from November through April. Flows in May and October are
also somewhat less certain owing to freezing phenomena, which makes the
gage reading less accurate.
15-4
25628
15.5 FLOOD HYDROLOGY
15.5.1 Probable Maximum Storm
A detailed meteorological analysis of the Probable Maximum Storm (PMS)
at Grant lake is not available. Consequently, an analysis was
conducted which transposed the PMS from Bradley lake to Grant lake.
Grant lake is located approximately 75 miles northeast of Bradley
lake. The Probable Maximum Precipitation (PMP) derived for Bradley
lake was derived using data from stations around the Gulf of Alaska.
Due to the proximity of the lakes, parameters derived in this manner
are as applicable to Grant lake as they are to Bradley lake.
However, differences in basin elevation topography and distance to the
Gulf of Alaska also had to be considered. These relationships were
utilized in Water Resources Atlas for USDA, Forest Service, Region X,
(Ott Water Engineers, 1979), when developing the mean annual
precipitation and average monthly precipitation values. Similar ratios
for the two lakes should also apply for large storms covering the
entire region, such as those in which the PMP would occur.
Consequently, the Grant lake PMP is believed to be conservative, and
appropriate for design of the spillway for those alternative
arrangements which include a dam at the outlet of Grant lake.
The National Weather Service (NWS) analyzed available meteorologic data
in the Gulf of Alaska to determine the PHS for Bradley lake. Grant
Lake is also close to the Gulf of Alaska, but recieves a lower amount
of precipitation, based on the mean annual runoff at the two lakes.
The basins of both Bradley lake and Grant lake are dominated by rock
and ice, resulting in an estimated 95 to 100 percent of the input
precipitation passing through the basin. The mean annual runoff from
the two lakes was thus considered adequate as direct indicators of the
relative amount of mean annual precipitation. lhe mean annual runoff
is 101.& inches for Bradley lake and 59.3 inches for Grant lake.
15-5
To develop a PHS at Grant Lake, the PHS at Bradley Lake was reduced by
the ratios of the average monthly precipitation at the two sites. The
Bradley Lake PHS was developed for August and September, so these were
the months analyzed. Haps in Water Resources Atlas for USDA. Forest
Service. Region X, (Ott Water Engineers, 1979) present average monthly
precipitaton as a ratio of mean annual precipitation. Using these maps
and the mean annual runoff values presented above, the following
average monthly precipitation values at the two sites were estimated:
Grant Lake
Bradley Lake
August
9. P
September
13.2·
The ratios of precipitation at Grant Lake to that at Bradley Lake were
65 percent and 67 percent for August and September, respectively. The
PHS for Bradley Lake is estimated as 41.0 inches over a 72-hour
period. The above ratios result in an August PHS of 26.7 inches and a
September PHS of 27.5 inches for Grant Lake. The 6-hour precipitation
values are shown on Table 15-4.
Estimates of glacial melt are also required to compute the total
precipitation input during the PHS. The Grant Lake basin has a glacial
area of 18 percent of the basin, from Flood Characteristics of Alaskan
Streams (Lamke, 1979), or approximately 7.96 square miles. The
degree-day temperature index method was used to estimate snowmelt from
the glaciers. It was assumed that nonglacial areas were snow-free, and
that glacial areas had sufficient snow so as not to be depleted during
the PMS. A constant melt rate of 0.098 inches/oF day was used from
Bradley Lake Hydroelectric Project. Design Memorandum (Corps of
Engineers, 1981). Temperatures during the PMS were assumed to be the
same as those developed for Bradley Lake. Temperatures during the
August PMS average 1.9°F greater than those in September, resu1ti~g in
0.1 inches snowmelt more during the PMS than that occurring in
September. The lapse rate from sea-level assumed by the NWS is as
follows:
15-6
Elevation ( ft) Differences from Sea-Level ( oF)
a a
1000 -2.8
2000 -5.7
3000 -8.6
4000 -11 .5
5000 -14.5
6000 -17 .5
Average elevation of the glaciers in the Grant Lake basin is about
4000 feet, so that a decrease of 11 .5°F was applied to the September
PMS temperatures shown in Table 15-4. These temperatures resulted in a
snowmelt rate of 0.01 inch/hour.
Basin size and runoff characteristics for Grant Lake are such that the
time of concentration for runoff is estimated at less than 1 hour.
Consequently, the 6-hour rainfall periods previously presented were
considered too long for proper hydrologic analysis. The 6-hour
rainfalls were divided into hourly increments using the ratios of l-hr,
2-hr, and 3-hr probable maximum precipitation to the 6-hour probable
maximum precipitation, as presented in Study of Probable Maximum
Precipitation for Bradley Lake Basin (U.S. Department of Commerce,
19(1). The point probable maximum precipitation values for each period
were adjusted for area. The hourly pattern for the final 3 hours was
assumed to be slowly decreasing. The resulting hourly ratios were
applied to each 6-hour period:
2562B
2
3
4
5
6
Percent of 6-Hour Precipitation
15-7
27
21
15
14
12
11
lhe 6-hour rainfall pattern generally followed that recommended for
design general-type storms in Design of Sma"ll Dams (U.S. Dept. of
Interior, 1977). The 6-hour periods were arranged in ascending order
(except for the 3 periods with heaviest rainfall), and the hourly
periods in each were also in ascending order. The top 3 rainfall
periods were arranged in the following order: 2, 1, 3. The hourly
periods in these three 6-hour periods were arranged in the following
order of magnitude:
1-6 hours: ascending
6-12 hours: 6,4,3,1,2,5
12-18 hours: descending
It was assumed that there was no rainfall either prior to or
immediately after the storm, but that snowmelt was occurring. The PMS
hydrograph is shown on Figure IV-15 and the data is presented in Part
VII of the Technical Appendix.
15.5.2 Probable Maximum Flood
The Probable Maximum Flood (PMF) flowing directly into Grant Lake was
developed for preliminary spillway design for project alternatives with
a dam at the outlet of Grant Lake (Alternatives A, 6, C and E) and for
estimating the effect of routing the PMF through the natural lake
outlet for the lake tap alternative. Although streamflow records are
available for Grant Creek below Grant Lake, there are no corresponding
nearby precipitation or temperature data. Consequently, the data base
was considered inadequate to develop reliable hydrograph
reconstitutions. Since the basin is so small, and its runoff
characteristics result in nearly total runoff, a simplified triangular
hydrograph technique described in Design of Small Dams (U.S. Dept. of
Interior, 1977) was utilized to estimate the PMF flowing into the lake.
15-8
25626
This technique was applied to 41.3 sq. mi. Grant Lake basin which
excludes the area of the reservoir. Precipitation falling directly on
the reservoir, which has an estimated area of 2.9 sq. mi., was
converted to its cfs equivalent and combined with the average hourly
cfs of runoff from the rest of the basin. The resulting peak inflow
into the reservoir during the PMF is 52,900 cfs.
15.5.3 PMF Flood Routing
15.5.3.1 Dam Alternatives
For those alternatives which include a dam at the outlet of Grant Lake,
(A, B, C, and E) the PMF hydrograph was routed through the reservoir
and spillway, using HEC-l. A range of spillway widths (from 100 to 250
feet) was analyzed in order to evaluate the effect of varying the
spillway width on the required dam height and on the amount of rockfill
available from the spillway excavation. A spillway with an
uncontrolled ogee-type overflow crest having a width of 125 feet was
selected for the alternatives using dams. The resulting peak outflow
during the PMF is 23,300 cfs and the maximum water surface level during
the flood is El 758.5.
15.5.3.2 Lake Tap Alternative
The PMF was also routed through the reservoir and natural lake outlet
for the lake tap alternatives (0 and F). The stage-discharge
relationship for the lake outlet was determined using the HEC-2
program, Water Surface Profiles. The best available topography was
used (1 '~200', 5 foot contour interval) for developing channel cross
sections at the outlet. Also, a survey was performed at the lake
outlet to establish the outlet control elevation (El. 691). Two values
of Manning's "n" were used: n=0.06 for the channel proper and n=0.10
for the overbanks. The overbank flows are relatively small, even for
the highest values of discharge during the PMF. Critical flow occurred
15-9
25628
at the point where the outlet channel steepness increases abruptly for
all flow values; thus, critical flow at the lake outlet governs the
lake level. The resulting rating curve developed using HEC-2 for the
natural outlet is shown on Figure IV-15 and the actual tabulated data
is shown in Part VII of the Technical Appendix.
The PMF was routed through the reservoir for the lake tap alternatives
using HEC-l. The starting lake level was taken as equal to the
surveyed minimum channel elevation at the outlet, elevation 691 MSL.
The maximum water surface level which occurs during the routing of the
PMF is elevation 709.2 and the maximum discharge from the lake is
27,700 cfs. The inflow and outflow hydrographs for the PMF are shown
on Figure IV-15 and the actual tabulated data is shown in Part VII of
the Technical Appendix.
15.5.4 Grant Creek Flood Frequency Data Construction Diversion Flood
Flood frequency studies for Grant Creek have been conducted by the USGS
with the results published in Flood Characteristics of Alaskan Streams
(Lamke, 1979). Peak discharges for floods with recurrence intervals of
1.25, 2, 5 and 10 years were computed using the Log Pearson Type-III
analysis, using the 11 years of historical data from Grant Creek. Peak
discharges for floods with 25, 50 and 100 year recurrence intervals
were computed using equations developed from a multiple regression
analysis of other similar gaged basis with longer periods of record.
1hese equations relate the magnitude of the peak discharge for a given
frequency to the climatic and physical characteristics of a stream's
drainage basin. A flood frequency curve presenting the results of
these studies is shown on Figure IV-15.
A flood with a 5-year recurrence interval was selected for purposes of
sizing construction diversion works project alternatives requiring a
dam at the outlet of Grant Lake for the dam (Alternatives A, B, C, and
E). A 5-year flood is considered reasonable for the 3-year
15-10
2562B
construction period associated with construction of the main dam. The
peak discharge for Grant Creek using the log Pearson Type-III analysis
is 1,300 cfs.
15.5.5 Falls Creek Diversion Dam Spillway Flood
A flood with a SO-year recurrence interval was selected for sizing the
spillway for the Falls Creek diversion dam. This is based on criteria
contained in Recommended Guidelines for Safety Inspections of Dams,
(Army Corps of Engineers, Chapter 2). According to the Corps criteria,
the Falls Creek diversion dam falls into the ·smal1· size
classification and ·low· hazard potential classification. For these
classifications, the recommended spillway design flood is a 50 to lOa
year flood. A 50-year flood was considered appropriate for the Falls
Creek Dam, considering that only short-term minimal overtopping would
occur in the event of a lOa-year flood. Using the regression equation
for a SO-year flood with the basin characteristics for Falls Creek, as
defined in Flood Characteristics of Alaskan Streams (Lamke, 1919), the
peak discharge for the spillway design flood is 1810 cfs.
15-11
TABLE 15-1
MONTHLY INFLOWS FOR GRANT LAkE (cfs)
lIater
Year Oct Nov Dec Jan Feb Mar Apr May Jun Ju1 Aug Sept Average
1948* 262 200 116 32 24 16 27 244 493 556 385 162 211
1949* 259 90 26 15 12 15 17 137 409 474 325 446 186
1950* 194 197 71 37 21 18 26 117 447 521 481 338 207
1951* 101 33 21 19 15 14 27 124 325 518 376 505 174
1952* 88 51 30 18 16 16 14 66 375 572 434 268 163
1953'* 337 263 124 58 44 30 61 281 928 711 513 294 305
1954* 257 69 40 32 33 28 30 173 409 420 384 201 174
1955* 168 145 51 42 24 18 18 72 291 643 407 273 181
1956* 81 42 25 20 17 15 22 121 269 471 453 215 147
1957* 65 56 52 22 19 20 29 166 449 359 370 565 181
1958* 207 161 56 44 29 25 66 178 535 449 418 155 194
1959 183 61 39 29 17 18 31 190 780 399 290 121 181
1960 111 95 50 46 29 26 28 289 494 534 378 268 197
1961 168 103 101 104 204 64 51 273 497 587 434 342 237
1962 225 77 34 32 34 18 33 123 403 548 335 175 171
1963 65 120 47 48 40 37 36 132 338 533 417 293 176
1964 123 55 54 38 44 31 80 192 519 595 493 249 200
1965 192 85 58 48 35 33 73 146 295 430 375 390 181
1966 139 35 33 46 27 23 40 115 418 430 411 518 187
1967 325 109 39 32 39 29 28 142 455 422 442 666 228
1968 184 76 59 60 39 44 29 208 358 420 373 210 173
1969 180 51 26 10 15 17 30 184 585 479 280 201 165
1970 400 173 156 65 63 40 56 187 510 SOO 446 195 234
1971 94 188 54 34 38 26 22 96 441 729 580 322 220
1972 188 61 30 17 15 15 17 69 293 485 425 286 157
1973 150 63 34 22 23 20 26 121 295 395 274 237 139
1974 74 43 28 33 14 16 26 166 383 432 335 374 161
1975 230 106 61 37 25 30 29 214 374 501 365 278 189
1976 258 72 31 18 23 18 23 133 397 420 395 500 191
1977 222 222 151 42 78 43 51 195 698 595 602 272 235
1978 226 114 38 53 46 41 36 197 440 445 415 468 211
1979 296 131 58 68 21 21 48 210 399 557 480 373 223
1980 234 137 49 126 107 65 34 283 445 598 564 360 251
Average 188 106 56 41 34 27 35 168 447 507 414 319 196
* Ave rage Recorded flows -All other flows are synthesized using HEC-4 Monthly Streamflow Simulation
Model.
15-12
TABLE 15-2
COMPARISON OF 1982 GRANT CREEK FLOWS WITH LONG-TERM AVERAGE FLOWS
JUNE JULY AUGUST SEPTEMBER
Grant Creek Flows (cfs)
1982 308 454 312 412
11 Long-Term Average-441 501 414 319
+ Standard Deviation 308-585 400-614 329-498 138-500
;aximum Month1~1 928 129 602 666
Minimum Month1~1 269 359 214 121
Kenai River Flows (cfs) 4524 6348 5322 8436~1
°Grant/OKenai .068 .012 .010 .049
11 Based on 33 years of record, 11 of which are recorded flows from
the Grant Creek gage and 22 of which are extended using HEC-4.
£1 From 33-year record.
11 Glacial outburst flood occurred in this month. Records have not
been adjusted to reflect this.
15-13
May
June
July
August
September
October
TABLE 15-:3
FALLS CREEK/GRANT CREEK
MONTHLY STREAMFLOW RATIOS1/
Grant Creek~/
Flow (cfs)
168
447
507
414
319
188
Falls Creek~/
Flow (cfs)
8.7
108.2
106.8
60.4
42.7
11 .7
Ratio
Falls/Grant
at Diversion
Adjusted for Spill
0.052
0.242
0.211
0.146
0.134
0.062
1/ Diversion of Falls Creek to Grant Lake is assumed to occur
from May 1 to October 31. with the diversion being closed for the
remainder of the year.
£/ Average monthly flows in Grant Creek based on 33 years of record.
~/ Average monthly flows in Falls Creek at diversion damsite based on
streamflow data collected in 1982 and adjusted for spill and areal
difference of drainage area at dams1te versus gaging station.
15-14
6-Hour
Period
1
2
3
4
5
6
7
8
9
10
11
12
2562B
TABLE 15-4
GRANT LAKE PROBABLE MAXIMUM STORM,
6-HOUR PRECIPITATION AND TEMPERATURE VALUES
August Se(1tember
Sea-Level
PreciQitation {in) Temperature Preci(1i(1tation {in}
Total Increment (OF} Total Increment
7.2 7.2 60.0 7.4 7.4
10.9 3.7 59.0 11 .3 3.9
13.8 2.9 58.1 14.? 2.9
16.3 2.5 ~7. 3 16.8 2.6
18.2 1.9 56.6 18.8 2.0
20.0 1 .8 56.0 20.6 1 .8
21 .8 1.8 55.4 22.4 1.8
23.1 1.3 54.8 23.8 1 .4
24.1 1 .0 54.2 24.8 1 .0
25.0 0.9 53.7 25.8 1.0
25.9 0.9 53.2 26.7 0.9
26.7 0.8 52.8 27.5 0.8
. 15-15
Sea-Level
Temperature
{OF}
58.2
57.0
56.1
55.4
54.7
54.1
53.5
52.9
52.4
51.9
51.4
50.9
16.0 POWER OPERATION STUDIES
16.1 POWER STUDY OBJECTIVES
Power studies were performed throughout the course of the feasibility
study for the following purposes:
1) Comparison of energy output and reservoir operation
characteristics for project development alternatives A, B, C,
0, E and F. The results of these power studies were presented
in the Interim Report (Ebasco, 1982) and are summarized in
Section 16.4. The estimates of energy output, along with
comparative cost estimates and environmental considerations,
provided the basis for selection of the lake tap alternatives
(0 and F) for more detailed study.
2) Comparison of energy output for various instream flow release
schemes which were considered during the analysis of fisheries
mitigation alternatives. The results of these power studies
are presented in the Environmental Report, Volume II.
3) Estimation of energy and dependable capacity for various
levels of installed capacity for the lake tap alternatives for
use in optimization studies and economic analysis. The
results of these power studies are presented in Section 16.5.
16.2 STUDY METHODOLOGY
Power operation studies were performed using a single reservoir
computer model developed by Ebasco which simulates, on a monthly basis,
the energy production from a given set of constraints for the period of
hydrologic record as developed in Section 15.0. The operational
priority of the model is to first meet a specified energy generation
requirement each month, then fill the reservoir, generate secondary
16-1
5602B
energy and, if unavoidable, spill excess water. The model determines,
by an iterative process, the quantity of water required to produce the
specified amount of energy using the average gross head available
during the month, minus the head loss. The quantity of water released
and the average net head available during the month are converted to
energy production.
16.3 INPUT DATA
16.3.1 Grant Lake Inflows
A total of 33 years of monthly inflow data for Grant Creek was used as
the streamflow input data for the operation study. The development of
the monthly streamflow record for Grant Lake is described in Section
15.4, and a tabulation of the flows is given in Table 15-1.
16.3.2 Available Storage in Reservoir
Interim Report Studies
Area-capacity data used in the Interim Report studies for the reservoir
above elevation 696 was determined using 1"=400' scale, 10 foot contour
interval mapping of the entire Grant Lake rim which was prepared during
the 1981 field investigations. This area-capacity data was used in the
power studies for Alternatives A, B, C, and E. The volume of the
reservoir between elevation 696 and elevation 650 (used in power
studies for Alternatives D and F) was estimated using available USGS
bathymetric data for portions of lower Grant Lake and extrapolation of
the slope of the existing shoreline in areas where bathymetric data did
not exist. It was recognized during the Interim Report investigations
that further studies of Alternatives D or F should include obtaining
more complete bathymetric data for Grant Lake.
16-2
5602B
Studies Performed Subsequent to Interim Report
After submittal of the Interim Report in February 1982 and
authorization from the Power Authority to proceed with further studies
on the lake tap alternatives, a bathymetric survey of 6rant Lake was
performed in the summer of 1982. This survey provided bathymetric
mapping of the lake bottom for both the upper and lower basins of 6rant
lake at a scale of 11 .400 feet, with a 10 foot contour interval. The
mapping was used to develop area capacity data below elevation 696, and
the topographic mapping obtained in 1981 was used for elevation 696 and
above. This data is tabulated in Part VII of the Technical Appendix
and is summarized as an area capacity curve on Figure IV-14.
Also, a survey was performed in 1982 to establish the control elevation
of the natural outlet of the lake. This elevation was determined to be
691 HSl, and was used as the normal maximum reservoir elevation in the
power studies.
16.3.3 Efficiencies
A constant overall power plant efficiency of 0.854 was assumed for the
range of operating heads and flows through the turbine for calculation
of energy generated. This value is based on efficiencies of 88 percent
for the turbine, 98 percent for the generator and 99 percent for the
transformer. A constant efficiency is considered appropriate because
of the relatively limited range of heads over which the turbine would
operate.
16.3.4 Tai1water Elevation
All power studies performed in support of findings in the Interim
Report and for evaluation of instream flow alternatives (July 1982)
used a tailwater elevation of 470 MSl. In August 1982, a bathymetric
survey was perfonmed of Upper Trail lake in the area where the tailrace
16-3
channel would be located. This information, along with seasonal water
level data for Upper Trail lake and the configuration of the tailrace
channel, was used to estimate a constant tai1water level of elevation
468.1 at the powerhouse. This value was used in all power studies
performed for project optimization studies and economic analyses.
16.3.5 Monthly Operational Strategy
The demand of energy drives the computer model used in the power
operation studies. For large proposed hydro projects where a major
portion of the region's energy would be provided by the project, it is
conventional for the demand used in the operational model to closely
track actual energy demand in the region, since it is necessary to find
a sufficiently large market in which to sell the energy. Table 16-1
provides data on historical monthly energy consumption for the
Anchorage/Cook Inlet region and the City of Seward. Grant lake is a
relatively small resource, whose supply of lenergy is always available
to displace gas generation. Hence, the best use of the resource is to
maximize energy output while simultaneously maximizing available
dependable capacity during the peak winter months of November,
December, January, and February in order to displace an increment of
new combined cycle combustion turbine construction.
Successive iterations were run for each power study in the final report
to find the optimal target energy generation distribution on a monthly
basis. This effectively defines an operating rule for the project.
The strategy can be summarized as follows: refill the reservoir during
June, July and August while meeting energy demand percentage close to
the demand for the region. During September and October, a lower
demand is targeted in order to conserve water for the critical months
of November, December, January, and February. On the average, more
energy is generated during September and October than in June, July,
and August since the reservoir usually refills by September; however,
during very dry summers and early falls, hedging is allowed to conserve
1&-4
water for the winter months. During the winter months, sufficient
energy is targeted to meet peak energy requirements and ensure adequate
capacity, even during the second worst year of the period of record.
March has a low target energy and capacity to ensure at least some
capacity on a year round basis. The remaining water is dumped during
April and May to prepare the reservoir for refilling during the spring
run-off season. This strategy almost totally eliminates spill and
maximizes energy production and capacity credit.
16.3.6 Minimum Streamflow Requirements
For power studies performed in support of the findings presented in the
Interim Report, the instream flow requirements were taken to be zero
for all six project development alternatives. Subsequent to the
submittal of the Interim Report, studies were conducted in consultation
with Alaska Department of Fish and Game, U.S. Fish and Wildlife Service
and National Marine Fisheries Service, which evaluated available power
output associated with a range of instream flow release alternatives.
These flow release schemes ranged from 15 cfs to 100 cfs. After
evaluation of numerous fisheries mitigation plans was completed, a plan
was selected which did not include a minimum flow release (details of
this analysis is presented in the Environmental Report, Volume II);
thus, all final power studies used for optimization and economic
analyses were performed using no instream flow.
16.3.7 Falls Creek Diversion Flows
For the evaluation of the diversion of Falls Creek (Alternatives E and
F), the flow data for Falls Creek was generated by applying ratios to
the Grant Creek monthly flows. A description of the derivation of
these ratios is provided in Section 15.4. The diversions from Falls
Creek were limited to the wet season from May to October.
16-5
5602B
16.4 SUMMARY OF INTERIM REPORT STUDIES
A primary objective of the Interim Report studies was to provide an
economic evaluation of the six alternative project arrangements
(Alternatives A through F), based on a comparison of the cost of energy
from each alternative. Accordingly, power studies were conducted to
estimate the available energy from each alternative.
To determine the installed capacity to be used in the comparison of the
alternatives, a brief study was conducted to identify the approximate
installed capacity that would provide the lowest cost of power for the
various alternatives. This was accomplished by evaluating the effect
that varying the installed capacity had on potential energy production
and on the construction cost. This analysis led to the selection of a
6 MW installation for Alternatives A, B, C, and F, a 5 MW installation
for Alternative 0, and a 7 MW installation for Alternative E.
A detailed attempt was not made in the February, 1982 Interim Report
studies to optimize the installed capacity for any of the six
alternatives. As discussed below, optimization studies were performed
to establish the installed capacity for the preferred alternative for
the feasibility report.
A summary of the results of the Interim Report operation studies for
each alternative is shown on Table 16-2. The table shows the average
annual energy produced for the 33-year period for which the power
studies were performed, along with other operational data. No
transmission loss was included in the energy production calcuations for
the comparison of alternatives, since transmission losses would be
essentially equal for each alternative.
The power study results were used in combination with construction cost
estimates to establish an energy cost for each alternative. These
costs, which are shown in Section 14.0 of the Interim Report along with
16-6
5602B
environmental considerations, were utilized to arrive at a
recommendation in the report to proceed with more detailed studies of
the lake tap alternatives (0 and F).
1&.5 DETAILED POWER STUDIES PERFORMED FOR LAKE TAP ALTERNATIVES
1&.5.1 General
After authorization from the Power Authority was received to proceed
with more detailed studies on the lake tap alternatives, refinements
were made to the input parameters, based on the results of additional
field and office investigations performed in 1982. lhis included the
tailwater elevation, the normal maximum reservoir elevation, the
available storage in the reservoir, and the arrangement of project
features, which affects head losses. With these refinements
incorporated into the operational program, power studies were performed
for the purpose of optimizing the installed capacity, evaluating
whether the Falls Creek diversion should be included in the project,
and for performing the economic analysis for the project.
1&.5.2 Data Obtained from Detailed Power Studies
Power studies were performed for a range of installed capacities (& to
8 MW) to estimate energy and dependable capacity values for use in the
process of optimizing the installed capacity for Alternative 0 (lake
tap without Falls Creek diversion). After the optimum plant size (see
Section 1&.&) was determined for Alternative 0 (7 MW), power studies
were performed for an 8 MW installation for Alternative F (lake tap
with Falls Creek diversion) for the purpose of evaluating whether the
Falls Creek diversion should be included in the project. The results
of these power studies are summarized on Table 1&-3.
For each value of installed capacity, the following values were
obtained from the power studies: average annual energy, firm energy,
secondary energy, and dependable capacity. An explanation of each of
these values is provided below.
1 &-7
5&02B
Average Annual Energy -This is the total energy available from the
project per year on an average basis, computed by dividing the total
energy produced from the entire period of hydrologic record by the
number of years in the record (33 years).
Firm Energy -Firm energy is that generated on an annual basis during
severe low flow conditions. For the purpose of this study, it is
considered reasonable to base the available firm energy of the project
on the amount of energy which is generated during the water year with
the second most adverse hydrologic period. A low flow frequency
analysis which was performed for the 33 years of record used in the
power studies showed that the second worst year has a recurrence
interval of approximately 25 years.
Secondary Energy -The secondary energy is the difference between the
average annual energy and firm annual energy.
D~pendable Capacity -The dependable capacity of a hydroelectric plant
is considered herein as that available (at full gate operation) during
the simultaneous occurrence of the highest peak demand period of the
year and severe low water conditions. The second worst hydrologic year
of record was used for this analysis, which is consistent with the
approach discussed above for firm energy. The highest peak demand
months were taken to be November through February, based on inspection
of demand curves for the Railbelt region.
16.5.4 Utilization of Power Study Results
The values of average annual energy and dependable capacity obtained
from the power studies were utilized in the optimization studies
described below in Section 16.6. As indicated in that Section, the
optimum installed capacity for Alternative D was determined to be 7 MW
and inclusion of the Falls Creek diversion works was found to be
uneconomical. The power output values for the 7 MW plant were then
16-8
56028
utilized in the economic analysis presented in Part I of the report.
Figure IV-16 graphically shows for an average hydrologic year the
monthly variations in powerhouse discharge and reservoir level which
would result from the proposed operation of the project for
Alternative D.
16.6 SELECTION OF OPTIMUM INSTALLED CAPACITY FOR ALTERNATIVE 0
16.6.1 General
The procedure used for establishing the optimum installed capacity for
the project was to first optimize the plant size for Alternative 0, and
then investigate whether it is economical to divert Falls Creek into
Grant Lake (Alternative F). Once the basic project arrangement for
Alternative 0 was established as discussed in Section 12.0, an
optimization study was conducted to determine the most cost-effective
installed capacity for the project. Costs and benefits for the project
were estimated for installed capacities ranging from 6 to 8 MW. The
point at which the benefit-cost ratio from the project is maximized
becomes the optimum installed capacity.
The benefits and costs were computed for each year of the 50 year life
of the hydro project, which was taken from 1988 through 2037. The
cumulative present worth of each year's benefits and costs were then
computed and expressed in January 1983 dollars. A more detailed
description of this procedure is provided below.
16.6.2 Project Costs
For each plant size, the cost of those items which would not vary as a
function of installed capacity were obtained from the FERC code of
accounts, contained in the cost estimate in Section 18.0.
16-9
5£>028
For those items which would vary in costs with installed capacity. cost
estimates were developed for each level of installed capacity
investigated, based on preliminary pricing data obtained from equipment
suppliers and experience with similar projects. These items included
the turbine, generator, governor, miscellaneous mechanical and
electrical equipment, and civil-structural costs which would result
from varying the size of the powerhouse and tailrace. The total
construction costs so computed are shown on Table 16-4.
The annual operation and maintenance costs for the hydro project used
are as developed in Section 18. The same operation and maintenance
costs were used for each installed capacity, because the difference in
operation and maintenance costs between a 6 to 8 MW plant was
considered to be insignificant.
The total annual costs for each project were developed by amortizing
the capital cost using APA criteria for interest rates and economic
life, and adding the debt service to the annual operation and
maintenance costs. The resulting total annual cost and 50 year
cumulative present worth of project costs .are shown on Table 16-4.
16.6.3 Project Benefits
The amounts of energy and dependable capacity available from each level
of installed capacity investigated were obtained from the power
operation studies derived above in Section 16.5. The monetary value
associated with the available energy and capacity is based on the cost
of obtaining the same amount of power, as delivered to Seward, from the
most economical alternative generation resource.
The development of the alternative generation costs are discussed in
detail in Section 4.0. The Base Case plan is the most economical plan
for meeting Seward's projected loads, without the Grant Lake Project.
Using the results of the Base Case Plan, the alternative resource
against which Grant Lake was compared for computation of benefits is a
combination of existing and new gas-fired generation.
16-10
5602B
The basic assumptions used in computing the value of the various
components of the project benefits are as follows:
Average Annual Energy -The value of the average annual energy from
the project is taken to be the total variable annual cost (fuel
plus operation and maintenance) of providing the same amount of
energy from the gas-fired alternative described above. The price
of natural gas and operation and maintenance costs for gas-fired
generation are developed in detail in Section 4.0.
Dependable Capacity -The value of dependable capacity from the
project is based on the capital cost and fixed operation and
maintenance costs of new combined cycle generation. The cost of
alternative combined cycle generation is developed in Section 4.0.
16.6.4 Results of Optimization Studies for Alternative 0
Using the assumptions and procedures outlined above, the benefits and
costs were computed for a project having an installed capacity of 6, 7,
and 8 MW. The results of this analysis are presented on Table 16-4.
The analysis indicates that a 7 MW installation is the most cost
effective plant size for development of the project without the
diversion of Falls Creek.
16.7 EVALUATION OF ECONOMICS OF FALLS CREEK DIVERSION
16.7.1 General
An analysis was performed to determine whether the diversion of Falls
Creek into Grant Lake should be included in the project to obtain
additional runoff for power generation. This analysis included
comparing the economics of Alternatives D and F.
16-11
As discussed above. optimization studies performed for Alternative 0 showed
that a 7 MW installation is the optimum ~size for the project without the
diversion of Falls Creek. An 8 MW project was selected for Alternative F.
since the plant factor (ratio of average annual generation to the generation
produced by continuous plant operation throughout the year at capacity) for
the optimized 7 MW Alternative 0 project is 0.41. and applying the same plant
factor to the available energy from Alternative F provides a value of 8 MW.
On this basis. an 8 MW installation shou'ld represent about the optimum project
size for Alternative F. Ths was verified by computing benefit-cost ratios for
Alternative F for a 7 MW and 9 MW project. and the results of this check
confirmed that the 8 MW size is the optimum installation for Alternative F.
Having arrived at a plant size for Alternative F. the comparison of the
project economics with and without the Falls Creek diversion was conducted
using the following steps:
1) Evaluation of project power output with and without the Falls Creek
Divers10n Works;
2) Evaluation of project construction and operation and maintenance
costs with and without the Falls Creek diversion works; and
3) Comparison of benefit-cost ratios and 1eve1ized cost of energy from
the project with and without the Falls Creek diversion works.
Each of these steps are discussed below.
16.7.2 Power Output Evaluation
Power studies were performed to estimate the power output available from an 8
MW installation with the Falls Creek diversion; using the same power operation
program as was used for the optimization studies for Alternative D. The
results of these studies are shown on Table 16-3.
16-12
16.7.3 Project Costs
The construction cost and operation and maintenance costs for
Alternative D are developed in Section 18.0 along with the additional
cost of Falls Creek diversion works. The total construction costs of
Alternatives D and F are summarized by FERC accounts on Table 16-5.
The costs for the Falls Creek diverson works were developed to the same
degree of detail as the costs for Alternative D, and, accordingly, the
same level of contingency has been applied to the cost estimate for
both Alternatives D and F.
The annual operation and maintenance cost for Alternative D of $302,000
is also developed in Section 18.0. An additional $20,000 was added to
the operation and maintenance cost estimated for Alternative F to
provide for maintenance of the Falls Creek diversion works.
The total annual costs for Alternatives D and F are developed on
Table 16-5, using APA economic analysis criteria for fiscal year 1983
to designate the interest rate, amortization period, etc.
16.7.4 Economic Comparison of Alternatives D and F
Comparison of Benefit-Cost Rat~os -The benefits for the 8 MW
Alternative F were computed in the same manner as described above in
Section 16.6.3 for the optimization of Alternative D. As shown on
Table 16-5, the benefit-cost ratio for Alternative F is 1.05 and the
corresponding value for Alternative D is 1.20, which indicates that
Alternative D is more economical than a project that includes the Falls
Creek diversion.
Comparison of Leve1ized Cost of Power -To provide another basis for
comparing the econonics of Alternatives D and F, the 1eve1ized cost of
energy was computed for both cases. As shown on Table 16-5, the cost
of energy for Alternatives D and F is 53.4 mills/kWh and
16-13
5602B
59.9 mills/kWh, respectively. This shows that the cost of energy from
a project that includes the Falls Creek diversion is 12 percent higher
than the project without the diversion.
Based on these comparisons of benefit-cost ratios and levelized cost of
power, it was concluded that it is not economical to include the Falls
Creek diversion works in the Grant Lake Project. Accordingly,
Alternative 0 was adopted for detailed development in the selected
project arrangement, which is discussed in Section 17.
16-14
5602B
Month
October
November
December
January
Februa ry
March
April
May
June
July
August
September
TABLE 16-1
DISTRIBUTION OF MONTHLY ENERGY CONSUMPTION
FOR ANCHORAGE/COOK INLlT AREA AND CITY OF SEWARD
Distribution of Energy Consumption {Percent of Annual Dema..lli!l
Mid-Range Energy Distribution Energy Distribution
1/ for Anchorage-Cook Inlet Area-for City of Seward£/
_._ .. _--"-
8.2 7.6
9.3 9.5
10.6 9.4
10.2 7.5
9.2 8.1
9.2 9.0
8.0 8.8
7.4 8.4
6.7 9. 1
6.8 8.2
7.0 7.2
7.4 7.5
1/ From Bradley Lake Power Market Report (Alaska Power
Administration, 1982), Section 4. Values are based on averaging
utility data from 1975 to 1980.
£/ Values are derived from energy consumption data for the City of
Seward for July 1980 to June 1982.
16 -15
5602B
TABLE 16-2
SUMMARY OF RESULTS OF POWER STUDIES
PERFORMED FOR INTERIM REPORT 1I
Alternative Project Arrangement
A B C D E
-------------
Average Annual Inflow
(cfs) 196 196 196 196 234
Power pool Limits
(Water Surface El) 745-710 745-710 745-710 690-660 745-710
Ins ta 11 ed Capacity
(MW) 6 6 6 5 7
Rated Net Head (ft) 247 243 239 198 249
Rated Flow (cf s) 329 334 339 342 380
Average Annual Power-
house Flow (cfs) 191 192 192 190 2?5
Average Annual
Spi 11 (cfs) 5 4 4 6 9
Avera~e Annual Energy
(GWH)j 29.9 29.5 29.1 23.8 35.6
Annual Plant Factor .57 .56 .55 .54 .58
---------
-------_.
F
---
234
690-660
6
194
419
224
10
27.6
.52
11 These values are not used in economic analysis of Grant Lake project.
~I Energy values are at the powerplant at high voltage side of the
transformer, before transmission line losses.
16-16
56026
TABLE 16-3
SUMMARY OF RESULTS OF POWER STUDIES
PERFORMED FOR OPTIMIZATION OF LAKE TAP ALTERNATIVE!/
Installed Capacity (MW)
A1t D A1t D A1t D A1t F
6 1 8 8
Average Annual Inflow (cfs) 196 196 196 221
Power Pool Limits (Water Surface E1) 660-691 660-691 660-691 660-691
Rated Net Head (ft) 208
Rated Flow (cfs) 390
Average Annual Powerhouse Flow (cfs) 190
Average Annual Spill (cfs) 5
Average Annual Energy at Plant
(GWH) 25.21
Average Annual Energy at Load
Center (GWH)~/ 24.82
Firm Annual Energy at Load
Center (GHW)~/ 18.85
Secondary Annual Energy at
Load Center (GHW)~/ 5.91
Dependable ca~ac1ty at Load
Center (MW)-/ 5.10
Annual Plant Factor!/ 0.48
206
459
194
2
25.40
24.94
18.48
6.46
6.55
0.41
204
531
195
1
25.26
24.81
18.42
6.39
1.02
0.36
206
525
221
3
28.99
28.41
21.56
6.91
1.02
0.41
1/
l/
Values shown for Alternative D (1 MW) used in economic analysis.
}/
!
Values shown are at load center (Seward), after reduction of at-plant values for
1.8% station service and transmission losses on energy.
Values shown are at load center (Seward), after reduction for 0.8% transmission
losses on capacity.
The plant factor is calculated by dividing the average annual energy at plant in M
by the product of 8,160 hours and the installed capacity in MW.
16-11
TABLE 16-4
DETERMINATION OF OPTIMUM INSTALLED CAPACITY FOR ALTERNATIVE 011
INSTALLED CAPACITY
FERC 6MW 7MW BMW
ACCOUNT DESCR IPT ION ($1000 ) ($1000 ) ($1000)
PRODUCT ION PLANT
LAND AND LAND RIGHTS 0 0 0
331 STRUCTURES AND IMPROVEMENTS 2435 2724 2968
332 RESERVOIRS, DAMS AND WATERWAYS 7312 7352 7389
333 WATER WHEELS, TURBINES AND GENERATORS 2733 3001 3295
334 ACCESSORY ELECTRICAL EQUIPMENT 1300 1428 1569
335 MISCELLANEOUS POWER PLANT EQUIPMENT 645 645 645
336 ROADS, RAILROADS AND BRIDGES 1498 1498 1498
TOTAL PRODUCTION PLANT 15923 16648 17364
TRANSMISSION PLANT
352 TRANSMISSION PLANT STRUCTURES AND IMPROVEMENTS 5 5 5
353 STATION EQUIPMENT 469 469 469
355 WOOD POLES AND FIXTURES 46 46 46
356 OVERHEAD CONDUCTORS AND DEVICES 73 73 73
TOTAL TRANSMISSION PLANT 593 593 593
TOTAL DIRECT COSTS 16516 17241 17957
INDIRECT COSTS
61 TEMPORARY CONSTRUCTION FACILITIES 200 200 250
64 LABOR EXPENSE 150 150 195
69 MOBILIZATION/DEMOBILIZATION 826 862 898
60 TOTAL INDIRECT CONSTRUCTION COSTS 1176 1212 1343
SUBTOTAL 17692 18453 19300
CONTINGENCY 2654 2768 2895
SUBTOTAL INCLUDING CONTINGENCY 20346 21221 22195
ENGINEERING & OWNER ADMINISTRATION 2847 2971 3107
TOTAL PROJECT COSTS (IN JANUARY, 1983 DOLLARS) 23194 24192 25302
DEBT SERVICE 989 1031 1079
o & M 302 302 302
TOTAL ANNUAL COST S 1291 1333 1381
PRESENT WORTH OF COS~/ 26386 27256 28222
AVERAGE ANNUAL ENERGY AFTER LOSSES (GWH )ll 24.82 24.94 24.81
PRESENT WO~TH OF ENERGY BENEFIT~/ 21396 21498 21379
DEPENDABLE CAPACITY AFTER LOSSES (MW~ 5.70 6.55 7.02
PRESENT WORTH OF CAPACITY BENEFIr.!/ 9719 11156 11967
PRESENT WORTH OF BENEFITS 31115 32654 33346
BENEFIT COST RATIa!/ 1.18 1.20 1.18
1/ All costs in January 1983 dollars. 2/ Based on 3.5' interest and a 50 year life. '1/ Transmission losses to Seward are 1.8' for energy and 0.8' for capacity. !/ Based on yalue of displaced cOlbined cycle combustion turbine yariable
!/ costs (see Section 4.3.3).
Based on yalue displaced cOibined cycle combustion turbine capital and
!I fhed costs.
Ratio of present worth of benefits to present wor'th of costs.
TABLE 16-5
COMPARISON OF ECONOMICS OF LAKE TAP ALTERNATIVE
WITH AND WITHOUT FALLS CREEK DIVERSIONl/
FERC
ACCOUNT
331
332
333
334
335
336
352
353
355
356
61
64
69
60
DESCRIPTION
PRODUCT ION PLANT
LAND AND LAND RIGHTS
STRUCTURES AND IMPROVEMENTS
RESERVOIRS. DAMS AND WATERWAYS
WATER WHEELS. TURBINES AND GENERATORS
ACCESSORY ELECTRICAL EQUIPMENT
MISCELLANEOUS POWER PLANT EQUIPMENT
ROADS. RAILROADS AND BRIDGES
TOTAL PRODUCTION PLANT
TRANSMISSION PLANT
TRANSMISSION PLANT STRUCTURES AND IMPROVEMENTS
STATION EQUIPMENT
WOOD POLES AND FIXTURES
OVERHEAD CONDUCTORS AND DEVICES
TOTAL TRANSMISSION PLANT
TOTAL DIRECT COSTS
INDIRECT COSTS
TEMPORARY CONSTRUCTION FACILITIES
LABOR EXPENSE
MOBILIZATION/DEMOBILIZATION
TOTAL INDIRECT CONSTRUCTION COSTS
SUBTOTAL
CONTINGENCY
SUBTOTAL INCLUDING CONTINGENCY
ENGINEERING & OWNER ADMINISTRATION
TOTAL PROJECT COSTS (IN JANUARY. 1983 DOLLARS)
DEBT SERVICE
o & M
TOTAL ANNUAL COST $
PRESENT WORTH OF COST~/
AVERAGE ANNUAL ENERGY AFTER LOSSES (GWH)l/
PRESENT WORTH OF ENERGY BENEFITi/
DEPENDABLE:CAPACITY AFTER LOSSES (MW)l/
PRESENT WORTH OF CAPACITY BENEFITi/
PRESENT WORTH OF BENEFITS
BENEFIT COST RATI~/
LEVELIZED COST OF ENERGY (MILLS/KWH)
1/ All costs in January 1983 dollars.
AL TERNATIVE D
(W/O FALLS CR)
7MW
($1000)
0
2724
7352
3001
1428
645
1498
16648
5
469
46
73
593
17241
200
150
862
1212
18453
2768
21221
2971
24192
1031
302
1333
27256
24.94
21498
6.55
11156
32654
1.20
53.4
2/ Based on 3.5% interest and a 50 year life.
!/ Transmission losses to Seward are 1.8% for energy and 0.8% for capacity. ~/ Based on value of displaced combined cycle combustion turbine variable
costs (see Section 4.3.3). i/ Based on value displaced combined cycle combustion turbine capital and
fixed costs. !./ Ratio of present worth of benefits to present worth of costs.
2835B
16-19
ALTERNATIVE F
(W/FALLS CR)
BMW
($1000)
0
2968
11617
3295
1569
645
2430
22524
5
469
46
73
593
23117
250
195
1156
1601
24718
3708
28426
3980
32406
1382
322
1704
34821
28.46
24528
7.02
11967
36495
1.05
59.9
17.0 SELECTED PROJECT ARRANGEMENT
17 . 1 GENERAL
The studies conducted through the Interim Report phase developed six
technically attractive hydroelectric development scenarios for Grant
Lake. They are presented as Alternatives A through F in Section 12.0
and are shown on Figures IV-3 through IV-7. Based on an economic
comparison of these alternatives, Alternative F was originally selected
for detailed feasibility studies. Alternative F would require a lake
tap intake structure on Grant Lake which would draw the lake down from
its present level. The flow would be directed through a tunnel to a
powerhouse on Upper Trail Lake. Additional power output would be
achieved by diverting flow from Falls Creek through a buried pipeline
to Grant Lake.
As a result of plant optimization studies performed during the detailed
feasibility effort, however, it was concluded that the Falls Creek
diversion portion of the selected Alternative F arrangement should be
deleted (see Section 16.7). It was furthermore concluded from the
optimization studies that the project, which is essentially
Alternative D, should have an installed capacity of 7 MW (2 MW greater
than Alternative D identified in the Jnterim R~ort). The project
arrangement and associated features described in this section are
refinements of Alternative D and are the culmination of a level of
engineering commensurate with a detailed feasibility study. The
results of additional geotechnical field activities, and topographic
and bathymetric surveys have been incorporated into these studies. The
finalized project layout is shown on Figure IV-17 and a plan and
profile of the power conduit are shown on Figure IV-lB.
17-1
2510B
17.2 RESERVOIR
Grant Lake will serve as the storage reservoir for the project (see
Figure IV-2). The lake fills an L-shaped depression over six miles
long and in some areas is as deep as 300 feet. The natural outlet for
the lake is Grant Creek, which is at elevation 691 at the low point of
the outlet. The total volume of Grant Lake below elevation 691 is
240,000 acre-feet and will provide 48,000 acre-feet of active storage
between the minimum pool at elevation 660 and the maximum pool at
elevation 691 feet.
Grant Lake actually consists of two lakes connected by a natura 1
constriction at the midpoint of the L-shaped depression. The two
bodies of water are referred to as Upper and Lower Grant Lake. The
project's intake structure will be located on Lower Grant Lake, the
westernmost leg of the lake.
lhe selected project arrangement will not require the construction of
dams on Grant Lake. The active storage for power generation will be
obtained by drawing the lake down from its present levels by a
completely submerged lake tap intake. The reservoir level fluctuations
during a normal operational year are shown on Figure IV-16. As
mentioned earlier, the reservoir will annually fluctuate between
elevation 660 and 691. The absolute maximum reservoir level occurring
during the PMF will be elevation 709.2 and the absolute minimum level
during a record drought year will be regulated to elevation 660. Refer
to Section 15.0 for a detailed hydrologic discussion of the lake
fluctuations during the PMF.
The operation of the project will result in a seasonal lake level
fluctuation of 31 feet below its present level, which would expose and
unwater the natural constriction connecting Upper and Lower Grant
Lake. Therefore, a channel will be excavated through the constriction
to allow for the passage of adequate flow (see Figure IV-19). This
17-2
2510B
channel will be approximately 1200 feet long and 40 feet deep at its
maximum section. The channel will be cut using conventional blasting
techniques over most of its length during the winter months when the
constriction freezes over. During the warmer months. the resulting
channel will be dreQged open.
The project will be drawing the reservoir down from its present level,
and therefore no additional reservoir work, such as clearing and
grubbing. will be required.
17.3 INTAKE AND GATE SHAFT
The intake will be located on the west shore of Lower Grant Lake
approximately 900 feet north of the Grant Creek outlet (see
Figure IV-17). Details of the intake and gate shaft are shown on
Figure IV-20. The lake tap intake consists of a 10 foot diameter
inclined tunnel with an invert at elevation 643. Downstream of the
intake tunnel a rock trap will be provided to catch broken rock and
debris entering the intake upon blasting the final segment of tunnel.
After the final blast shot is made and the intake is filled with water,
a semi-cylindrical steel trashrack will be installed over the resulting
opening. This trashrack will be lowered in place by a barge-mounted
crane and installed by divers. Rock bolts and tremie concrete will
anchor it in place.
From the intake a 9-foot inside-diameter horseshoe-shaped tunnel will
emerge. This 90-foot long tunnel segment will be lined with 3 inches
of shotcrete and rockbo1ted. as required. For estimating purposes and
based on available geotechnical information. it is assumed that 15% of
the entire tunnel will require rockbolting. The tunnel will then
transition to a 10.5 foot-high. 7.5 foot-wide rectangular section
directly beneath the gate shaft. This rectangular section will serve
to seat the slide gate when in the down position.
17-3
25106
The gate shaft and gate house will be located approximately 200 feet
downstream of the intake. The gate house will be set in a rock cut at
elevation 715 as shown on Figure IV-20. This will place the gate house
well above any reservoir level, including the PMF event. Due to the
presence of steeply sloped rock bedding planes in this area, which
could result in a slope instability problem, considerable rockbolting
is provided to stabilize the cut. Drainage holes are also provided to
help relieve hydrostatic pressures in the cut. In an effort to
minimize the size of cut and the amount of exposed rock, the gate house
will be set back into the rock. Its north and west walls will be
concrete, placed and tied directly against the rock. The south and
east walls will be constructed using aluminum siding to minimize cost.
The entire gate house/gate shaft structure houses a single 9 foot by 12
foot slide gate. This gate will have a downstream seal. Lift for the
gate is provided by a hydraulic hoist and electrical controls for the
hoist will be located in the gate house.
Ladders will be provided in the shaft for access to the tunnel.
Electrical power will be provided to the gatehouse from the powerhouse
via a buried conduit within the access road right-of-way.
17.4 POWER CONDUIT
The power conduit for the project consists of a gradually sloping, low
level horseshoe-shaped tunnel with an inside diameter of 9 feet at the
spring line. The tunnel, shown in plan and profile on Figure IV-1B, is
approximately 3,200 feet long and connects the intake directly to the
powerhouse. This profile was selected to facilitate construction and
eliminate the need for a surge chamber. The determining factor in
sizing the tunnel was space requirements for construction rather than
hydraulics; therefore, the tunnel diameter was selected to provide the
minimum practical cross section which would still provide the required
17-4
2510B
space for construction activities. Studies were performed to verify
that increasing the tunnel size would not increase the net benefits
from the project, since the velocities in the 9 foot diameter tunnel
are relatively low.
Excavation of the tunnel will be by conventional drill and blast
methods from a single heading at the powerhouse. The tunnel crown and
sides will be lined along its entire length with 3-inch
average-thickness shotcrete and approximately 15% of the tunnel is
estimated to required rockbolting. These lining and support
requirements are based on geological conditions assumed to exist n the
tunnel as interpreted from the resuts of borings and surface mapping
performed along the tunnel alignment. The invert of the tunnel will be
lined with 6 inches average thickness of concrete to provide a working
surface during excavation. The actual tunnel support and lining
requirements may be reduced, based on the actual rock conditions
observed during construction.
As the tunnel approaches the powerhouse and the available rock cover
diminishes, a combination concrete and steel tunnel liner is provided.
The steel liner gradually reduces in diameter from 102 inches to 66
inches where it enters the powerhouse. The details of this transition
are shown on Figure IV-21. Contact grout will be provided between the
steel and conrete liners to ensure bond and homogeneity of support
around the steel.
Immediately upstream of the steel liner a rock trap will be excavated
to catch debris or tunnel spalling that may occur during the operation
of the project. Accumulated debris would be removed via a blockout in
the penstock at the powerhouse.
17-5
2510B
17.5 POWERHOUSE AND TAILRACE
The powerhouse will be an indoor-type remote controlled structure set
into the hillside adjacent to the east shore of Upper Trail Lake. It
will be located approximately 3000 feet upstream of the lake outlet
(see Figures IV-17 and IV-2l). The substructure of the powerhouse will
be reinforced concrete founded in rock and the superstructure will be
structural steel with aluminum siding as shown on Figure IV-22. The
structure is set back into the hillside for several reas6ns. Doing so
will shorten the flow line and eliminate the need for a surface steel
penstock; it places the structure in more competent foundation material
and it avoids shear zone observed along the Trail Lake valley, believed
to be a zone of poor rock quality (see Section 15.4). The powerhouse
location will place the shear zone downstream of the structure.
The rated flow to the powerhouse will be 459 cfs and the average annual
powerhouse flow will be 194 cfs. The unit will be protected by a
butterfly valve located immediately upstream of the turbine.
Discharge from the powerhouse will be via a 640-foot long tailrace
channel excavated to Upper Trail Lake. Velocities in the tailrace will
range from approximately 6 fps at the powerhouse to 2 fps at the lake.
The tailrace will, for the most part, be excavated in the sands and
gravels at a 2-horizontal to 1-vertical slope along the shore of the
lake. Immediately downstream of the powerhouse, however, the tailrace
will be cut in rock. The portion of the tailrace in soil will be lined
with riprap to prevent erosion from occurring and depositing sediment
in the lake. An aluminum picket fish barrier will be provided across
the tailrace to prevent fish from entering the draft tube.
The powerhouse will contain a single vertical Francis turbine-generator
unit operating at a rated speed of 400 rpm. The turbine will deliver
9,580 hp at a rated head of 206 feet under best gate operation. The
generator will be a vertical shaft three phase synchronous unit rated
17-6
25106
at 7780 kVA with a 90% power factor. This will result in a plant
installed capacity of 7000 kW, which will produce an estimated average
annual energy of 25.40 GWH, with an annual plant factor of 0.41. See
Figure IV-23 for the powerhouse main one line diagram. The generator
unit will be enclosed and will utilize surface air coolers, a solid
state exciter, governor and a CO 2 fire protection system. As
mentioned previously, the powerhouse will be remotely controlled;
however, the necessary facilities for manual control will be provided.
To facilitate maintenance of the equipment, an overhead crane will be
provided in the powerhouse. Periodic inspection of the turbine runner,
spiral case and draft tube will be provided by the access galleries
shown on Figure IV-22.
A single turbine generating unit is proposed for this Project for the
following reasons:
o A single unit is more economical than multiple units.
o The high reliability of hydro generating equipment assures a
minimum of unscheduled outages.
o The rare unscheduled outage will not adversely affect Seward,
since the City's entire load can be supplied via the
transmission line to Seward.
o No loss of generation from the Project will occur, since the
project plant factor is 0.41 and adequate storage exists in
the reservoir through most of the year to avoid spills due to
unit unavailability.
o Frequent scheduled maintenance can be provided to insure
reliability.
17-7
2510B
17.6 ACCESS ROADS AND BRIDGES
A total of 2.4 miles of access roads will be constructed at the site
(see Figure IV-17). The roads are designated as Class A and Class B
and typical sections of each are shown on Figure IV-24. A Class A road
will be used to provide permanent access from the Seward-Anchorage
Highway to the powerhouse. It will be 24 feet wide plus 5 foot
shoulders. Surfacing will be 18 inches of crushed stone. The
transmission line connecting the project with the Seward-Anchorage
intertie will be within the corridor of this main access road. Class B
roads will provide access to all other features. All Class B sections
will be 18 feet wide and surfaced with 6 inches of crushed stone. No
road grades will be steeper than 8 percent.
Two bridges will be constructed at the site as part of the access
system. A 140-foot-long, four-span prestressed concrete bridge will
provide the primary access to the site from the Seward-Anchorage
Highway. This bridge will cross the Trail Lakes at the narrow
constriction separating the Upper and Lower portions (see Figure
IV-17). The second bridge will cross Grant Creek near its outlet at
Grant Lake (also shown on Figure IV-17). This bridge will be a
60-foot-long, four-span timber structure and will be used to provide
access to the recreation area.
17.7 TRANSMISSION OF POWER
The 4.16 kV output of the generator will be transformed to 115 kV by a
9 MVA transformer located in the switchyard. The switchyard will be a
short distance to the south of the powerhouse next to the primary
access road on a prepared, graveled and fenced site. Located in this
switchyard will be a 115 kV circuit breaker and disconnect switch.
Also located in the switchyard are smaller necessary items such as 115
kV lightning arrestors, carrier equipment wave trap, potential and
current transformer, etc. Refer to Figure IV-23 for a one-line diagram
showing this arrangement.
17-8
2510B
From the switchyard a 115 kV transmission line is planned that would
run alongside the primary access road to the Seward-Anchorage Highway,
which is approximately 1.2 miles. At this point the Grant Lake
switching station will be provided. This switching station will tie
Grant Lake output into the newly planned 115 kV transmission for the
City of Seward (see Daves Creek-Seward Transmission Line Investigation
in Part III of this study). The 115 kV transmission line planned will
be on wood poles and of a compact delta configuration.
Preliminary line design criteria indicate that a 336 kcm ACSR conductor
with an approximate span of 400 feet is most suitable. This section of
line is anticipated to be basically the same design as the new 115 kV
line between Daves Creek and Seward as described in the Transmission
Line Investigation Section of this study.
17.B MITIGATION FACILITIES
Two facilities will be provided as part of the selected project
arrangement which comprise part of the project fisheries mitigation
plan. These facilities, which are described in detail in Volume II -
Environmental Report, include a salmon holding facility and a fish
bypass facility. The salmon holding facility will be located adjacent
to the tailrace channel (see Figure IV-21) and will consist of 2
aluminum raceways, channels connecting the raceways to the tailrace
channel (water is supplied to the raceways from powerhouse discharges),
a spawning shed, and provisions for security. The tunnel bypass
facility will consist of a rotatable stainless steel inclined screen
just downstream of the gate shaft and a 10 inch diameter fish bypass,
which will be embedded in the tunnel invert concrete and will extend
for the length of the tunnel, past the turbine, and into the tailrace
channel. The tunnel bypass facilities are shown on Figures IV-1B and
IV-20.
17-9
2510B
Project recreation facilities will be located on the southern end of
Grant Lake and will consist of picnic tables, fireplaces, a contained
vault toilet and a boat launch area.
17.9 FALLS CREEK DIVERSION WORKS
17.9.1 General
As discussed above, the detailed plant optimization studies resulted in
the deletion of the Falls Creek diversion from the selected project
arrangement. For completeness, a description of the diversion system
developed through the detailed feasibility studies is presented herein.
Falls Creek has its headwaters in the mountains south of Solars
Mountain and presently discharges into Trail River just south of Lower
Trail Lake (see Figure IV-2). The Falls Creek diversion system would
require the construction of a small dam on the creek to divert flow
through a gravity feed pipeline to Grant Lake as shown in plan and
profile on Figure IV-2S. The system would result in the addition of
approximately 1 MW of installed capacity to the project.
The system has been designed to accommodate a flow of 112 cfs, which
was determined by an optimization study to maximize the flow and
benefits of the system while minimizing spill and capital cost. The
diversion will take place during the wet seasons between May and
October.
17.9.2 Falls Creek Diversion Dam and Intake Structure
The diversion dam would be a concrete gravity structure with an
uncontrolled ogee spillway and flip bucket, as shown on Figure IV-26.
It would be located approximately 2 miles upstream of the confluence of
Falls Creek and Trail River. The dam would be approximately 30 feet
high (21 feet to the spillway crest at elevation 1404.5) and
17-10
2510B
constructed in a section of valley that has moderately steep
(l-horizontal to l-vertical) side slopes. This would result in a dam
that is 75 feet long. This location represents a shift of
approximately 2500 feet upstream from the dam location presented during
the Interim Report stage. This change was precipitated by the
acquisition of more detailed survey information which showed the
original dam location to be in an area of sheer, nearly vertical,
cliffs.
The spillway is sized to accommodate a 50-year flood without
overtopping. Larger floods than a 50 years event would not damage the
integrity of the structure, but would result in its being overtopped,
in which case the dam would act as a submerged weir. The flip bucket
is provided to minimize erosion at the toe of the dam during periods of
spill, which are estimated to occur for 800 hours during a normal flow
year. The maximum spill during such a year would be 164 cfs.
17.9.3 Falls Creek Diversion Pipeline
The Falls Creek diversion pipeline would be a 21-9" diameter steel pipe
originating at the dam and discharging into Grant Lake. The total drop
in elevation would be approximately 700 feet from elevation 1400 to
elevation 690, and would occur over a length of 12,800 feet. As shown
on Figure IV-25, the pipeline would closely parallel an access road. A
typical pipeline/access road section is shown on Figure IV-24.
The pipeline would be buried along its entire length. The minimum
burial depth would be 3 feet where the pipeline slope is steeper than
1% (which would be for most of its length) and 9 feet where the slope
is flatter than 1%. The pipe would be buried for several reasons: 1)
it would eliminate the need for above ground supports while utilizing
the relatively inexpensive support afforded by burying it with excess
road cut fill; 2) burying the pipeline would protect it from potential
hazards caused by avalanche; 3) it would provide protection to the pipe
17-11
2510B
from freezing during the winter months when the system is shut down and
water could accumulate in flat areas; and 4) burying the pipe would
mitigate its environmental impact to the site. Two of the above
benefits associated with burial are closely interrelated. Where the
pipeline traverses an active avalanche chute, the slope of the pipeline
is essentially flat (between stations 70+00 and 90+00). Therefore,
this area would require the 9 foot burial depth to prevent freezeups
together with giving an additional degree of avalanche protection to
the pipe.
When the pipeline reaches Grant Lake it would discharge into a channel
that would be dredged down to elevation 650 in the lake, well below the
minimum pool level. This channel would be lined with concreted riprap
in order to eliminate the potential for erosion when the pipeline
discharges into Grant Lake during a low pool condition.
17-12
2510B
18.0 PROJECT COSTS AND SCHEDULE
18.1 GENERAL
Feasibility-level estimates of capital costs and operation and
maintenance costs were developed for the selected Grant Lake project
layout described in Section 17.0. The capital cost estimate has been
prepared on an overnight price basis with escalation shown separately.
Included in the project capital costs are the following: direct
construction costs of the production plant and transmission plant;
indirect construction costs such as temporary construction facilities
and mobilization/demobilization; contingencies; overhead construction
costs including professional services to the Power Authority; and
escalation during construction. Interest during construction has not
been included since current Power Authority procedures call for
inclusion of IDC only in the nominal cost of the project, which is
utilized in the plan of finance.
The overnight cost estimate of the project includes all items in the
bid price estimate except escalation during construction. The
overnight cost has been used in the economic analysis for the project.
A project schedule was developed based on the assumption that a FERC
license application is submitted by the summer of 1983 and that
construction will commence shortly after receipt of the license. This
schedule, presented on Figure IV-27, was used as the basis for
developing the cost of escalation during construction.
18.2 PROJECT CAPITAL COST
The total project capital cost, including direct and indirect costs,
contingencies, overhead expenses and escalation during construction, is
$24,713,000. These items are presented on Tables 18-1 and 18-2, and
treated separately below.
18-1
2&22B
18.2.1 Direct Construction Costs
The direct construction costs include all directly billable charges
associated with each project feature and are overnight costs assuming
January 1983 dollars. These costs are summarized on Table 18-1 and
presented in detail on Table 18-2. The total cost of the hydraulic
production plant and transmission plant is $16,544,000 and includes all
structures, waterways and reservoirs, equipment for generation and
transmission of power to the Seward-Anchorage intertie, fish mitigation
facilities and all site access. Clearing costs associated with the
transmission line have been included under access roads. This was done
because the transmission line is located on the roadway shoulder for
its entire length. Also, no cost was included for land or land rights,
since all of the project is located on Federal lands, which are
currently in the process of being transferred to state ownership.
The basis for developing this estimate includes the assumptions that
labor rates for the project will be similar to Anchorage union
agreements and that all labor is to be performed on a contract basis.
18.2.2 Indirect Construction Costs
The total indirect construction costs are summarized on Table 18-1 as
$1,212,000 and are itemized on Table 18-2. lhis sum includes the cost
of temporary construction facilities (shops, warehouses, trailers,
etc.), extra travel pay compensation to the labor forces and
mobilization/demobilization expenses. The assumptions incorporated
into this estimate are that there will be sufficient craft labor
commuting daily from Seward (no provisions for a labor camp) since the
labor force will consist of approximately 30 men as discussed in the
Environmental Report (Volume 11) and adequate room exists in Seward and
Moose Pass for such a crew. A work week consisting of 6-10 hour days,
and mobilization/demobilization costs equal to 5% of the direct
construction cost were also assumed.
18-2
2022B
18.2.3 Contingency
The contingency for the project is $2,663,000 and is an allowance for
any unforeseen events that may result in cost increases during
construction. This amount is 15% of the total direct and indirect
construction costs.
18.2.4 Professional Services and Owner Administration (Overhead
Construction Costs)
Professional services consist of engineering, design, construction
management and related services and are estimated to be $2,971,000 (14%
of all construction costs, including contingencies).
18.2.5 Escalation
All the above costs are overnight and represent base year January 1983
prices. In order to present a true bid-level estimate for the project,
an annual escalation rate of 7% for both material and labor was used.
This escalation rate is in accordance with the Power Authority
guidelines and considers escalation for a construction period starting
at the base year. The total price escalation for the project is
estimated to be $1,323,000.
lB.3 ANNUAL COSTS
Annual operation and maintenance (O&M) costs were developed for the
project based on the experience encountered with other hydroelectric
projects in Alaska and input from the Power Authority. The total O&M
cost is estimted to be $302,000 per year. Included in this estimate
are the following:
18-3
2622B
Yearly Labor Costs
o
o
o
Operations (including recreation and fish
facilities) -1.5 men at $66,000/man yr.
Plant Maintenance - 4 man crew for 10 weeks
at $66,000/man yr.
Administration (Overhead)
Dispatch Expenses
Yearly Replacements
o
Insurance
Miscellaneous Equipment
Subtotal
Contingency (20%)
Total
18.4 DESIGN AND CONSTRUCTION SCHEDULE
$99,000
$51 ,000
$25,000
$175,000
$15,000
$12,000
$50,000
$252,000
$50,000
$302,000
The complete project schedule is shown on Figure IV-27. This schedule
is developed based on an August 1, 1983 submittal of the FERC license
application and a receipt of the license by November 1, 1984 (15 month
processing period). Detailed design and bid document preparation would
be performed concurrently with the processing of the license and would
essentially be complete by the beginning of 1985. Some continuing
design activity would be required through the construction phases and
would be primarily for field support and to address any design changes
that may be required.
Actual construction would commence in April 1985 with the award of
contract and the start of mobilization. Construction would conttnue
for two years with trial operation set for March 1987 and commercial
operation for April 1987.
18-4
2622B
18.5 ALTERNATIVE F DETAILED COST ESTIMATE
As discussed in previous sections. the project configuration originally
recommended for detailed feasibility studies was Alternative F. This
configuration was. in fact. modified and developed. and detailed
feasibility-level cost estimates were prepared before it was eliminated
as the preferred alternative. For comparative purposes. the detailed
cost estimate developed for the Alternative F configuration. which is
also described in Section 17.0. is presented on Table 18-3.
The salient features of the Alternative F cost estimate are as follows:
Hydraulic Production Plant Direct Costs
Transmission Plant Direct Costs
Indirect Construction Costs
Contingency (151 of direct and indirect costs)
Overhead Construction Costs (Engineering.
Construction Management. and Owner Administration)
Total Alternative F Project Cost in 1983 Dollars
Escalation During Construction
Alternative F Escalated Project Cost
18-5
$21.546.000
$593.000
$1.587.000
$3.559.000
$3,932.000
$31.217.000
_$1,993,000
$33.210.000
TABLE 18-1
SELECTED PROJECT ARRANGEMENTll
SUMMARY OF PROJECT CAPITAL COSTS
Cost Item
Amount -January 1983
Price Level ($l,OOOls)
Production Plant
Transmission Plant
$15,951
593
Total Direct Construction Cost
Indirect Construction Cost
Contingency
$16,544
$ 1,212
2,663
Total Indirect Construction Cost (Including
Contingency) $ 3,875
Engineering, Construction Management and
Owner Administration
Project Subtotal~1
$ 2,971
$23,390
$1,323
$24,713
Escalation During Constructionl1
Total Capital Cost
1 I Selected Project Arrangement is Alternative D with minor
refinements. The minor refinements decreased the project cost by
$802,000. The decrease was due to a reduction in excavation
quantities associated with the channel excavation and modified
unit prices.
Represents "overnight" cost estimate in January 1983 dollars.
This value is used in the economic analysis of the project.
Escalation Based on Project Schedule Shown on Figure IV-27 and
Annual Inflation Rate of 7%.
18-6
FE.RC
ACCOUNl
330.
1 ABLE 18-2
SE.LE.ClED PROJE.CT ARRANGEMENl
DElAILED ESlIMAlE. OF CONSlRUClION COSl
Sheet 1 of 7 -----------------
DESCRIP1ION
HYDRAULIC PRODUCTION PLANT
LAND AND LAND RIGHTS
UN 11
UNIl QUANlilY COSl
$ $
fOTAL
COSl
Not Included]l
331 . POWER PLANT STRUCTURES AND
lM..PROVEMENTS
· 1
· 1 1
.111
.112
.113
• 1 2
· 121
.122
.13
· 131
.132
.133
.134
.135
.130
Power House
Site Preparation
Clearing
Excavation -Rock
Excavation -Common
Substructure
Concrete -Structural
Reinforcing Steel
Superstructure
AC
CY
CY
CY
IN
Structural Steel LB
Aluminum Siding and Roofing SF
Architectural Treatment LS
Plumbing, Lighting
and Electrical LS
Miscellaneous Metal LB
Heating and Ventilating LS
Subtotal Powerhouse
0.5
4,870
310
1 ,150
00
111 ,500
10,000
5,500
3800.00
25.30
11 .94
550.00
2022.00
2.32
15.27
3.04
1900
123500
3-'00
032500
157300
258800
152700
88400
70400
10700
39900 ----
1551800
11 All project lands are Federal lands which are currently being transferred
to state ownership.
2620B
18-7
FERC
ACCOUNT
.2
.21
.211
.212
.213
.2131
.2132
.2133
.2134
.2135
.214
.215
.216
.217
.218
.219
.2191
.2192
.2193
.• 2194
.22
.221
.222
.223
.224
.225
.226
.23
TABLE 18-2
SELECTED PROJECT ARRANGE1~ENT
DETAILED ESTIMATE OF CONSTRUCTION COST
Sheet 2 of 7
DESCR IPTION
UNIT
UNIT QUANTITY COST
TOTAL
COST
Conservation of Fish and
Wil dl He
Salmon Holding Facility
Site Preparation and Grading AC
Gravel Surfacing CY
Class B Access Road
Cl eari ng AC
Excavation -Rock CY
Excavation -Common CY
Crushed Stone CY
Ra ndom Fi 11 CY
Common Excavation CY
Concrete -Structural CY
Reinforcing Steel TN
6 1 Chain Link Fence LF
Aluminum Pickets LF
ttli sce 11 aneous
Wood Foot Bri dge LS
Emergency Water Supply LS
Misc. Plumbing and Valves LS
Misc. Tanks and Equipment LS
Fish Bypass Facility
1 0" d i a s tee 1 pipe, 1 i ne d
and coated LF
Pipe hangers EA
Bypass Screen (Incl hinges) SF
Bypass Screen Hydr. Piston LS
Bypass Screen El ect Control!) LS
10" dia Butterfly valve EA
Off-Si te Fi sh Hatchery ~1odul e LS
Subtotal Conservation of Fish and
Hildl ife
TOTAL POWER PLANT STRUCTURES
AND IMPROVEMENTS
18-8
0.34
215
0.25
155
430
75
1,100
1 ,450
21
0.30
500
1 ,700
2,980
20
250
$
7500.00
19.07
4000.00
50.97
9.30
18.66
3.18
9.24
671.42
2133
25.20
10.35
122.88
150.00
68.80
$
2550
4100
1000
7900
4000
1400
3500
13400
14100
640
12600
17600
9700
33800
6000
143000
366200
3000
17200
7800
Included in Acc1t 334
1 1600.00 1600
456000
1127090
2678890
TARLE 18-2
SELECTED PRO,JECT ARRANGEf"ENT
DETAILED ESTIMATE OF CONSTRUCTION COST
Sheet 3 of 7 ----
FERC UNIT TOTAL
ACCOUNT DESCR I PT 10 tJ UNIT QUANTITY COST COST
--------$ ---"----~------------"
332. RESERVOIRS AND WATERWAYS
· 1 Re servoir
.11 Channel fxpansion
· 1 11 fxcavdtion -Rock CY "14,500 19.0U 275~U()
.11 ? Excavation -COlllmon CY 2,600 lU.OO 2600U
.12 Recreation Facilities LS 45UOO "-------
Subtotal Reservoir 3461)UO
.2 Power Tunnel 9.0' Horseshoe (320U' )
· ;:"1 Excavation -Rock CY 9,600 380.UO 3648000
.22 Steel Sets til 3,055 5.79 177()U
.23 Rock Bolts LF 2,300 25.78 593()0
.24 Welded Wire Fabric LI3 12,000 1. 17 14000
.25 Shotcrete Lining CY 720 768.65 553400
.26 Concrete -~lass CY 675 325.31 219600
. 27 Lake Tap Incl . Rock trap & Trashrack
.271 Excavation -Rock CY 240 380.00 9120()
.272 Shotcrete CY 20 765.00 15300
.273 Tremi e Concrete CY 40 322.50 12900
.274 Trashrack LI3 33,000 5.80 191400
.28 Concrete Transition
.281 Concrete -Structural CY 110 557.27 61300
.282 Reinforcin9 Steel TN 5.5 2127.00 11700
.29 Gates and Gateshaft
.291 Gates
.2911 Intake Gate EA 1 65500.00 65500
.2912 Temporary Bulkhead Gate EA 1 29500.00 29500
.292 Gate Shaft Excavation CY 352 700.00 246400
.293 Gate Shaft Shotcrete CY 30 851.42 25500
.294 Welded Wire Fabric LI3 250 1.60 400
.295 Steel Sets LB 7,500 5.83 43730
.296 Rock Bo lts LF 300 26.00 7800
.297 Concrete -Structural CY 140 650.00 91000
.298 Reinforcing Steel TN 7.5 2120.00 15900
18-9
TABLE 18-2
SELECTED PROdECT ARRANGEMENT
DETAILED ESTIMATE OF CONSTRUCTION COST
FERC
ACCOUNT DESCR I PTION UNIT QUANTITY
$
332 • RESERVOIR AND WATERWAYS (Contld)
. 299 Gatehouse
.2991 Excavat ion -Rock CY 2,750
.2992 Rockbolts (1-3/8") LF 2,600
.2993 Drain Holes (2") LF 800
.2994 Concrete -Structural CY 135
.2995 Reinforcing Steel TN 7.0
.2996 Structural Steel LB 14,000
.2997 Aluminum Siding and Roofing SF 2,100
.2998 Misc. Metal LB 1 ,160
.2999 ~'i sce" aneous
.29991 Gate Hoi st EA 1
.29992 Misc. Electrical Controls LS Incl
.2993 Bu bb 1 er Sys tern LS
.3 Penstock (75 1 Lg)(shown as steel
tunnel 1 iner, 3/8" thick)
.31 Penstock Steel LB 26,200
.32 Contact Grout SF 1800
.4 Ta il race (640 1 Lg)
.41 Excavation -Rock CY 3,035
.42 Excavation -Common CY 17,430
.43 Ri p-rap CY 2,900
.44 Bedding CY 860
Su btota 1 Wa terways
TOTAL RESERVOIRS AND WATERWAYS
333. WATER WHEELS, TURBINES AND GENERATORS
.1
.11
.12
.13
.2
(7MW -INSTALLED CAPACITY)
furblnes, Governors and Valves
Turbine and Governor
Inl et Val ve
Lube Oi 1 System
Generator, Exciters and Appurt.
TOTAL WATER WHEELS, TURBINES AND
GENERATORS
18-10
LS
EA
LS
LS
1
Sheet 4 of 7
UNIT TOTAL
COST COST
$
16.93 46600
25.77 67000
26.25 21000
845.88 114200
2119.00 14800
2.32 32500
15.29 32100
3.36 3900
24200.00 24200
in Acc I t 334
6.30
11 .56
25.37
6.18
54.39
18.95
30000
165100
20800
77000
107700
157700
16300
6352430
6698930
1647000
Incl Above
25000
1329000
3001000
TABLE 18-2
SELECTED PROJECT ARRANGEMENT
DETAILED ESTIMATE OF CONSTRUCTION COST
Sheet 5 of 7
FERC UNIT TOTAL
ACCOUNT DESCR I PTIO ~1 UNIT QUANTITY COST COST
$ $
334. ACCESSORY ELECTRICAL EQUIPMENT LS 1428000
TOTAL ACCESSORY ELECTRICAL EQUIPMENT 1428000
335. MISCELLANEOUS POWER PLANT EQU I pr~ENT
. 1 Power Station Crane (30 Ton) EA 182400.00 182400
.2 Draft Tube Gates EA 2 31500.00 63000
.3 Miscellaneous Equipment LS 400000
TOTAL MISCELLANEOUS Po\~ER PLANT EQUIPMENT 645400
336. ROADS AND BRIDGES
. 1 Access Roads
.11 Access Roads Class A (24 1 wide)
.111 Clearing AC 13 3723.00 48400
.112 Excavation -Rock CY 14,135 16.92 239100
.113 Excavation -Common CY 35,700 6.18 220600
.114 Crushed Stone CY 10,275 18.23 187300
.115 Random Fi 11 CY 30,360 3.24 98300
.12 Access Roads Cl ass B (181 wide)
.121 Clearing AC 8 3719.00 29800
.122 Excavation -Rock CY 5,890 16.92 99700
.123 Excavation -Common CY 15,840 6.18 97900
.124 Crushed Stone CY 2,920 18.24 53300
.125 Random Fi 11 CY 11 ,760 3.24 38100
Total Access Roads 1112500
.2 Bridges
.21 Trail Lake Crossing
.211 Bridge Girders -A.A.S.H. T.O. EA 8 6975.00 55800
STD. 35 1 Lg
.212 Concrete -Structural CY 310 560.64 173800
.213 Reinforcing Steel TN 31 2119.00 65700
.214 Barriers -N.J. Std Barrier LF 280 50.00 14000
.215 Expansion Joints -Metal EA 5 2320.00 11600
.216 Drains and Drain Pipes EA 16 681.25 10900
.22 Grant Creek Crossing
.221 Dimension Lumber BF 9,350 3.26 30500
.222 Concrete -Structural CY 15 853.33 12800
18-11
TABLE 18-2
SELECTED PROJECT ARRANGEMENT
DETAILED ESTIMATE OF CONSTRUCTION COST
FERC
ACCOUNT DESCR I PT IO N UNIT QUANTITY
336 ROADS AND BRIDGES (Cont'd)
.224 Reinforcing Steel TN 1.5
.225 Guard Rail -Weathering Steel LF 120
.226 Misc. Metal and Fasteners LB 250
Total Bridges
TOTAL ROADS AND BRIDGES
TOTAL HYDRAULIC PRODUCTION PLANT
TRANSMISSION PLANT
352. TRANSMISSION PLANT STRUCTURES AND IMPROVEMENTS
.1
.11
. 12
.13
.14
SWi tchyard Civi 1
Fi 11-Ra ndom
Excavation-Common
Crushed Rock
Fences and Gates
TOTAL TRANSMISSION PLANT STRUCTURES
AND IMPROVEMENTS
CY
CY
CY
LF
353. SUBSTATIOtJ AND SWITCHING EQUIPMENT LS
TOTAL SUBSTATION AND SWITCHING EQUIPMENT
355. POLES
30
45
40
130
$
Sheet 6 of 7
UNIT TOTAL
COST COST
$
2133.00 3200
49.17 5900
6.00 1500
385700
1498200
15950420
3.33 100
18.33 825
18.00 720
27.73 3605
5250
469000
469000
.1
.2
Clearing Not Included -Use Plant Roads
Poles (Douglas Fir)
(6 Dead End, 12 Guyed)
EA 18 46000
TOTAL POLES 46000
18-12
TABLE 18-2
SELECTED PROJECT ARRANGEMENT
DETAILED ESTIMATE OF CONSTRUCTION COST
Sheet 7 of 7
FERC
ACCOWJT DESCR IPTION
UNIT
UNIT QUANTITY COST
TOTAL
COST
356. CONDUCTORS AND DEVICES
• 1
.2
Conductors (336 mcm ACSR)
Insulators
TOTAL CONDUCTORS AND DEVICES
TOTAL TRANSMISSION PLANT
TOTAL DIRECT CONST COST
LF
LS
60. INDIRECT CONSTRUCTION COSTS
61.
62.
63.
64.
• 1
69.
Temporary Construction Facil ities LS
Construction Equipment LS
Camp and Commissary LS
Labor Expense LS
Travel Pay LS
Total Labor Expense LS
Mobilization/Demobilization LS
TOTAL INDIRECT CONST COSTS
SUBTOTAL
Contingency (15%)
SUBTOTAL (Incl Contingency)
70. OVERHEAD CONSTRUCTION COSTS
71. Professional Services
TOTAL OVERHEAD CONSTR COSTS
19,425
TOTAL PROJECT COST (in January, 1983 Dollars)
Escalation
TOTAL ESCALATED COST
18-13
$ $
2.57 50000
23000
73000
593250
16543670
200000
Included in Direct Costs
Not Required
150000
150000
862000
1212000
17755670
2663330
20419 000
2971000
2971000
23390000
1323000
24713000
TABLE 18-3
AL TERNATI VE F DEVELOPMDJT
DETAILED ESTIMATE OF CONSTRUCTION COST
Sheet 1 of 9
FERC UNIT TOTAL
ACCOUNT DESCRIPTION UNIT QUANTITY COST COST
$ $
HYDRAULIC PRODUCTION PLANT
330. LAND AND LAND RIGHTS Not Incl uded!/
331. POWER PLANT STRUCTURES AND
IMPROVEMENIS
• 1 Power House
.11 Site Preparation
.111 Clearing AC 0.5 3800.00 1900
.112 Excavation -Rock CY 4,870 25.36 123500
.113 Excavation -Common CY 310 11.94 3700
• 12 Subs tructure
.121 Concrete -Structural CY 1,150 550.00 632500
.122 Reinforcing Steel TN 60 2622.00 157300
.13 Superstructure
.131 Structural Steel LB 111,500 2.32 258800
.132 Aluminum Siding and Roofing SF 10,000 15.27 152700
.133 Architectural Treatment LS 88400
.134 Plumbing, Lighting
and El ectri cal LS 76400
.135 Miscellaneous Metal LB 5,500 3.04 16700
.136 Heating and Ventilating LS 39900
Subtotal Powerhouse 1551800
l! All project lands are Federal lands which are currently being transferred
to state ownership.
2620B
18-14
TABLE 18-3
ALTERNATIVE F DEVELOPMENT
DETAILED ESTIMATE OF CONSTRUCTION COST
Sheet 2 of 9
FERC UNIT TOTAL
ACCOUNT DESCRIPTION UNIT QUANTITY COST COST
$ $
.2 Conservation of Fish and
Wil dl ife
.21 Salmon Holding Facility
.211 Site Preparation and Grading AC 0.34 7500.00 2550
.212 Gravel Surfacing CY 215 19.07 4100
.213 Cl ass 8 Access Road
.2131 Cl eari ng AC 0.25 4000.00 1000
.2132 Excavation -Rock CY 155 50.97 7900
.2133 Excavation -Common CY 430 9.30 4000
.2134 Crushed Stone CY 75 18.66 1400
.2135 Ra ndom Fi 11 CY 1,100 3.18 3500
.214 Common Excavation CY 1 ,450 9.24 13400
.215 Concrete -Structural CY 21 671.42 14100
.216 Reinforcing Steel TN 0.30 2133 640
.217 6 1 Chain Link Fence LF 500 25.20 12600
.218 Aluminum Pickets LF 1,700 10.35 17600
.219 Miscellaneous
.2191 Wood Foot Bridge LS 9700
.2192 Emergency Water Supply LS 33800
.2193 Misc. Plumbing and Valves LS 6000
.2194 Misc. Tanks and Equipment LS 143000
.22 Fi sh Bypass Fac il i ty
.221 10" dia steel pipe, 1 i ned
and coated LF 2,980 122.88 366200
.222 Pipe hangers EA 20 150.00 3000
.223 Bypass Screen (Incl hinges) SF 250 68.80 17200
.224 Bypass Screen HYdr. Piston LS 7800
.225 Bypass Screen Elect Controls LS Included in Acclt 334
.226 10" dia Butterfly valve EA 1 1600.00 1600
.23 Off-Si te Fi sh Hatchery Modul e LS 456000
Subtotal Conservation of Fish and 1127090
Wildlife
TOTAL POWER PLANT STRUCTURES 2678890
AND IMPROVEMENTS
18-15
TABLE '18-3
ALTERNATIVE F DEVELOPMENT
DETAILED ESTIMATE OF CONSTRUCTION COST
Sheet 3 of 9
FERC UNIT TOTAL
ACCOUNT DESCRIPTION UNIT QUANTITY COST COST
$ $
332 . RESERVOIRS AND WATERWAYS
. 1 Re servoir
.11 Channel Expansion
.111 Ex cavat i on -Rock CY 14,500 19.00 275500
.112 Excavation -Common CY 2,600 10.00 26000
.12 Recreation Facilities LS 45000
Subtotal Reservoir 346500
.2 Falls Creek Concrete Gravity Dam
.21 Diversion & Care of Water
.211 Ra ndom Fi 11 CY 500 4.12 2060
.212 Corrugated Metal Pipe ( 3 I dia. JiLF 40 61 .50 2460
.213 Structural Concrete CY 5 840.00 4200
.214 Reinforcing Steel TN 0.25 2120.00 530
.22 Clearing AC 0.50 3600.00 1800
.23 Excavation -Rock CY 180 50.83 9150
.24 Excavation -Common CY 60 18.67 1120
.25 Foundation Preparation
.251 Surface Preparation LS 6900
.252 Grouting
.2521 Drill Grout Holes LF 210 26.14 5490
.2522 Neat Cement CF 35 73.00 2550
.26 Concrete
.261 Concrete -Mass CY 290 320.89 93060
.262 Concrete -Structural CY 90 828.89 74600
.27 Re i nforc i ng Steel TN 5.0 2122.00 10610
.28 Miscellaneous
.281 Structural Steel LB 1,200 2.33 2800
.282 Mi sc. r~etal LB 800 18.00 14400
.29 Intake Structure
.291 Structural Concrete CY 7 845.71 5920
18-16
TABLE 18-3
ALTERNATIVE F DEVELOPMENT
DETAILED ESTIMATE OF CONSTRUCTION COST
Sheet 4 of 9
FERC UNIT TOTAL
ACCOUNT DESCRIPTION UNIT QUANTITY COST COST
$ $
332 • RESERVOIRS AND WATERWAYS Continued
• 292 Reinforcing Steel TN 0.35 2114.00 740
.293 Structural Steel LB 975 2.32 2260
.294 Gate & Gate Works EA 1 20000.00 20000
.295 Trashrack LB 1,200 7.50 9000
.296 Sl uiceway Gate LS 15000
.297 Rip-rap CY 50 51.00 2550
Subtotal Dams 287200
.3 Power Tunnel 9.0' Horseshoe (3200' )
.31 Excavation -Rock CY 9,600 380.00 3648000
.32 Steel Sets LB 3,055 5.79 17700
.33 Rock Bolts LF 2,300 25.78 59300
.34 Welded Wire Fabric LB 12,000 1.17 14000
.35 Shotcrete Lining CY 720 768.65 553400
.36 Concrete -Mass CY 675 325.31 219600
.37 Lake Tap Incl. Rocktrap & Trashrack
.371 Excavation -Rock CY 240 380.00 91200
.372 Shotcrete CY 20 765.00 15300
.373 Tremie Concrete CY 40 322.50 12900
.374 Trashrack LB 33,000 5.80 191400
.38 Concrete Transition
.381 Concrete -Structural CY 110 557.27 61300
.382 Reinforcing Steel TN 5.5 2127.00 11700
18-17
TABLE 18-3
ALTERNATIVE F DEVELOPMENT
DETAILED ESTIMATE OF CONSTRUCTION COST
Sheet 5 of 9
FERC UNIT TOTAL
ACCOUNT D ESCRI PTION UNIT QUANTITY COST COST
$ $
332. RESERVOIR AND WATERWAYS (Cont Id)
.39 Gates and Gateshaft
.391 Gates
.3911 Intake Gate EA 1 65500.00 65500
.3912 Temporary Bulkhead Gate EA 1 29500.00 29500
.392 Gate Shaft Excavation CY 352 700.00 246400
.393 Gate Shaft Shotcrete CY 30 851.42 25500
.394 Welded Wire Fabric LB 250 1.60 400
.395 Steel Sets LB 7,500 5.83 43730
.396 Rock Bolts LF 300 26.00 7800
.397 Concrete -Structural CY 140 650.00 91000
.398 Reinforcing Steel TN 7.5 2120.00 15900
.399 Gatehouse
.3991 Excavation -Rock CY 2,750 16.93 46600
.3992 Rockbolts (1-3/8 11 ) LF 2,600 25.77 67000
.3993 Drain Holes (211) LF 800 26.25 21000
.3994 Concrete -Structural ICY 135 845.88 114200
.3995 Reinforcing Steel TN 7.0 2119.00 14800
.3996 Structural Steel LB 14,000 2.32 32500
.3997 Aluminum Siding and Roofing SF 2,100 15.29 32100
.3998 Misc. Metal LB 1 ,160 3.36 3900
.3999 Miscellaneous
.39991 Gate Hoist lEA 24200.00 24200
.39992 Misc. Electrical Control s LS Incl in Acc It 334
.3993 Bu bb 1 er Sys tern lS 30000
.4 Penstock (75 1 Lg)(shown as steel
tunnel 1 iner, 3/811 thick)
.41 Penstock Steel lB 26,200 6.30 165100
.42 Contact Grout SF 1800 11 .56 20800
.5 Tailrace (640 ILg)
.51 Excavation -Rock CY 3,035 25.37 77000
.52 Excavation -Common CY 17,430 6. 18 107700
.53 Rip-rap CY 2,900 54.39 157700
.54 Beddi ng CY 860 18.95 16300
18-18
FERC
ACCOUNT
332.
.6
.61
.62
.63
.64
.65
.66
.67
.68
.69
TABLE 18-3
ALTERNATIVE F DEVELOPMENT
DETAILED ESTIMATE OF CONSTRUCTION COST
DESCRIPTION UNIT QUANTITY
$
RESERVOIR AND WATERWAYS (Cont1d)
2.75 1 Dia. Falls Creek Diversion
Pipeline (12,800 1 LF)
Clearing AC 2
Excavation -Rock CY 13,685
Excavation -Common CY 20,525
Dragline Excavation CY 240
Conduit Steel LB 1 ,084,000
Backfill -General CY 33,200
Backfill -Bedding and Surround-
ing Granular Fill CY 4,800
Backfill -Riprap choked with
Concrete CY 12
Concrete Thrust Block CY 17
Subtotal Waterways
TOTAL RESERVOIRS AND WATERWAYS
333. WATER WHEELS, TURBINES AND GENERATORS
• 1
• 1 1
· 12 .13
• 2
334.
(8MW -INSTALLED CAPACITY)
ffirblnes, Governors and Valves
Turbine and Governor
Inlet Valve
Lube Oi 1 System
Generator, Exciters and Appurt .
TOTAL WATER WHEELS, TURBINES AND
GH1ERATORS
ACCESSORY ELECTRICAL EQUIpt~ENT
LS
EA
LS
LS
LS
TOTAL ACCESSORY ELECTRICAL EQUIPMENT
18-19
Sheet 6 of 9
UNIT
COST
$
3720.00
33.83
4.61
6.25
2.90
3.97
18.96
54. 17
447.06
TOTAL
COST
7440
463000
94700
1500
3143600
131800
91000
650
7600
10293720
10927420
1810000
Incl Above
25000
1460000
3295000
1569000
1569000
TABLE 18-3
ALTERNATIVE F DEVELOPMENT
DETAILED ESTIMATE OF CONSTRUCTION COST
Sheet 7 of 9
FERC UtJIT TOTAL
ACCOUNT DESCRIPTION UNIT QUANTITY COST COST
$ $
335. MISCELLANEOUS POWER PLANT EQUIPMENT
.1 Power Station Crane (30 Ton) EA 182400.00 182400
.2 Draft Tube Gates EA 2 31500.00 63000
.3 Miscellaneous Equipment LS 400000
TOTAL MISCELLANEOUS POWER PLANT EQUIPMENT 645400
336. ROADS AND BRIDGES
. 1 Access Roads
.11 Access Roads Cl ass A (24' wide)
.111 Clearing AC 13 3723.00 48400
.112 Excavation -Rock CY 14,135 16.92 239100
.113 Excavation -Common CY 35,700 6.18 220600
.114 Crushed Stone CY 10,275 18.23 187300
.115 Random Fi 11 CY 30,360 3.24 98300
.12 Access Roads Class B (18 ' wide)
. 121 Clearing AC 32 3719.00 119000
.122 Excavation -Rock CY 23,050 16.92 389900
.123 Excavation -Common CY 62,025 6.18 383400
.124 Crushed Stone CY 11 ,450 18.24 208800
.125 Random Fi 11 CY 46,060 3.24 149300
Total Access Roads 2044100
.2 Bridges
.21 Trail Lake Crossing
.211 Bridge Girders -A.A.S.H. T.O. EA 8 6975.00 55800
STD. 35' Lg
.212 Concrete -Structural CY 310 560.64 173800
.213 Reinforcing Steel HJ 31 2119.00 65700
.214 Barriers -N.J. Std Barrier LF 280 50.00 14000
.215 Expansion Joints -Metal EA 5 2320.00 11600
.216 Drains and Drain Pipes EA 16 681. 25 10900
.22 Grant Creek Crossing
.221 Di mension Lumber BF 9,350 3.26 30500
.222 Concrete -Structural CY 15 853.33 12800
18-20
TABLE 18-3
ALTERNATIVE F DEVELOPMENT
DETAILED ESTIMATE OF CONSTRUCTION COST
FERC
ACCOUNT DESCRIPTION UNIT QUANTITY
336 ROADS AND BRIDGES (Cont'd)
.224 Reinforcing Steel TN 1.5
.225 Guard Rail -Weathering Steel LF 120
.226 Misc. Metal and Fasteners LB 250
Total Bridges
TOTAL ROADS AND BRIDGES
TOTAL HYDRAULIC PRODUCTION PLANT
TRANSMIS SION PLANT
352. TRANSMISSION PLANT STRUCTURES AND IMPROVH1ENTS
.1
.11
.12
.13
.14
~i tchyard Civil
Fi ll-Ra ndom
Excavation-Common
Crushed Rock
Fences and Gates
TOTAL TRANSMISSION PLANT STRUCTURES
AND IMPROVEMENTS
CY
CY
CY
LF
353. SUBSTATION AND SWITCHING EQUIPMENT LS
TOTAL SUBSTATION AND SWITCHING EQUIPMENT
355. POLES
30
45
40
130
$
Sheet 8 of 9
UNIT TOTAL
COST COST
$
2133.00 3200 49. 17 5900
6.00 1500
385700
2429800
21545510
3.33 100
18.33 825
18.00 720
27.73 3605
5250
469000
469000
.1
.2
Clearing Not Included -Use Plant Roads
Poles (Douglas Fir)
(6 Dead Ena, 12 Guyed) EA 18 46000
TOTAL POLES 46000
18-21
TABLE 18-3
ALTERNATIVE F DEVELOPMENT
DETAILED ESTIMATE OF CONSTRUCTION COST
Sheet 9 of 9
FERC
ACCOUNT DESCRIPTION
UNIT
UNIT QUANTITY COST
TOTAL
COST
356. CONDUCTORS AND DEVICES
.1
.2
Conductors (336 mcm ACSR)
Insulators
T01"AL CONDUCTORS AND DEVICES
TOTAL TRANSMISSION PLANT
TOTAL DIRECT CONST COST
L.F
L.S
60. INDIRECT CONSTRUCTION COSTS
61.
62.
63.
64.
. 1
69.
Temporary Construction Facilities LS
Construction Equipment LS
Camp and Commi ssary LS
Labor Expense LS
Travel Pay LS
Total Labor Expense LS
Mobilization/Demobilization LS
TOTAL INDIRECT CONST COSTS
SUBTOTAL
Contingency (15%)
SUBTOTAL (Incl Contingency)
70. OVERHEAD CONS1RUCTION COSTS
71. Professional Services
TOTAL OVERHEAD CONSTR COS1S
19,425
TOTAL PROJECT COST (in January, 1983 Dollars)
Escalation
TOTAL ESCALATED COST
18-22
$ $
2.57 50000
23000
7300Q
593250
22138760
250000
Included in Direct Cos1
Not Required
_19500Q.
195000
1142000
1587000
23725no
3559240
27285000
3932000
3932000 -.---
31217000
1993000
33210000
19.0 REFERENCES
Alaska Department of Transportation, Seward and Sterling Highway
Drawings.
Alaska Power Authority. 1982. Bradley lake Power Market Report.
Alaska Power Authority. 1983. Before the FERC, Application for license for
Major Project, Susitna Hydroelectric Project, Volume 1, Exhibit -D.
Battelle Pacific Northwest laboratories. 1982. Railbelt Electric
Power Alternatives Study: Evaluation of Rai1belt Electric Energy Plans,
COlllTlent Draft.
1982. Railbelt Electric Power Alternatives Study:
Fossil Fuel Availability and Price Forecasts, Volume 1.
Bolt, B.A .. 1913. Duration of Strong Ground Motion: Fifth World Conf.
Earthquake Engineering, Rome.
CH2" Hill. August 1919. City of Seward Electrical System
Planning Study. Prepared for the City of Seward.
CH2" Hill. February 1919. City of Seward Electric System (Plan
Drawings). Prepared for the City of Seward.
CH2M Hill. March 1919. City of Seward light and Power
Division Plant Inventory. Prepared for the City of Seward.
CH2" Hill. March 1982. Drawings for 69 kV Transmission line - .
4th of July Creek, Drawing No.'s K15115.Al sheets 2 to 9. Prepared for
the City of Seward.
Campbell, Kenneth W. 1981. Near-Source Attenuation of Peak Horizontal
Acceleration. Bulletin of the Seismological Society of America, Vol 11,
pp. 2039-2010.
Chugach Electric Association, Inc. Trans. line drawings for Daves
Creek to lawing, #61-M-838 to 846.
City of Seward. 1982. Forecast Electric Demand to 1984. Prepared
by City of Seward.
Commonwealth Associates, Inc. October 1982. Anchorage Area
Reliability Study (Draft Report). Prepared for Alaska Power Authority.
Dwane legg Associates. October 1982. Analysis of Voltage
Drop and Energy loses. Prepared for the City of Seward.
Ebasco Services Incorporated. 1983. Use of North Slope Gas for Heat
and Electricity, Draft Final Report Feasibility level Assessment.
1981. Grant lake Hydroelectric Project,
Interim Report
19-1
Federal Energy Regulatory Commission. 1979. Hydroelectric Power
Evaluation.
Foster, H.F., and Kar1strom, T.N. 1967. Ground Breakage and Associated
Effects in the Cook Inlet Area, Alaska, Resulting from the March
27, 1964 Earthquake, U.S. Geological Survey Professional Paper
543-F.
Joyner, W.B. and Boore, D.M. 1981. Peak Horizontal Acceleration and
Velocity from Strong-Motion Records Including Records from the 1979
Imperial valley, California, Earthquake. Bulletin of the
Seismological Society of America, Vol. 71, pp. 2011-2038.
Krinitzsky, E.L., and Chang, F.K. 1977.
Design Earthquakes: U.S. Army Corps
Paper MP 5-73-1, Report 7, Waterways
Miss., 34 p.
Specifying Peak Motions for
of Engineers, Miscellaneous
Experiment Station, Vicksburg,
Lamke, R.D. 1979. flood Characteristics of Alaskan Streams. U.S.
Geological Survey Water Resources Investigations 78-129,66 pp.,
1979.
North Pacific Consultants. 1958. Cooper Lake Hydroelectric Project,
Supplemental Design Report on Reservoir Storage Study and Study of
Diversion from Stetson Creek.
____ ~--~~~-. 1955. Cooper Lake Hydroelectric Project, Kenai
Peninsula, Alaska, Definite Project Report.
Ott Water Engineers. 1979. Water Resources Atlas for USDA forest
Service -Region X. Juneau, Alaska.
Page, R.A. 1972. Crustal Deformation of the Denali Fault, Alaska,
1942-1970: Journal of Geophysical Research, v. 77, p. 1528-1533.
Page, R.A., Boore, D.M., Joyner, W.B., and Coulter, H.W. 1972. Ground
Motion Values for Use in the Seismic Design of the Trans-Alaska
Pipeline system: U.s. Geological Survey Circular 672, 23 p.
Page, R.A., and Lahr, J.e. 1971. Measurements for fault Slip on the
Denali, Fairweather, and Castle Mountain Faults, Alaska: Journal
of Geophysical Research, v. 76, p. 8534-8543.
Plafker, G. 1969. '"ectonics of the March 27, 1964 Alaska Earthquake,
U.S. Geological Survey Professional Paper 543-1.
1955. Geologic Investigations of Proposed Power
Sites at Cooper, Grant, Pta~igan. and Crescent Lakes, Alaska; U.S.
Geological Survey Bulletin l031-A.
19-2
R&M Consultants, Inc. June, 1982. Alaska Power Authority, Grant Lake
Hydroelectric Project, Interim Geotechnical Report.
December, 1982. Alaska Power Authority, Grant
Lake Hydroelectric Project, Geotechnical Investigations, Final
Report.
R. W. Beck, June 1982.
Transmission Study.
Kenai Peninsula Power Supply and
Prepared for Alaska Power Authority.
1982. Supplement -Kenai Peninsula Power Supply
and Transmission Study.
R.W. Beck and Associates. May 1976. Electric System Study.
Prepared for the City of Seward.
R.W. Beck and Associates. January 1975. Report on Feasibility
of Operation of the Electric Utiity System of the City of Seward by
Homer Electric. Prepared for City of Seward and Homer Electric
Association, Inc.
Slemmons, D.B. 1977. Faults and Earthquake Magnitude: U.S. Army
Corps of Engineers, waterways Experiment Station, Vicksburg,
Mississippi, Miscellaneous Paper S-73-1, Report 6, 129 p.
Tysdal, R.G. and Case, J.E. 1969. Geologic Map of the Seward and
Blying South Quadrangles, Alaska, U.S. Geological Survey Map 1-1150.
U.S. Corps of Engineers. 1982. Bradley Lake Hydroelectric Project,
Alaska. Final Environmental Impact Statement. U.S. Corps of
Engineers, Alaska District.
1982. Bradley Lake Hydroelectric Project,
General Design Memorandum.
1981. Bradley Lake Hydroelectric Project, Design
Memorandum. Anchorage, Alaska.
U.S. Department of Commerce, Weather Bureau. 1961.
Study of Probable Maximum Precipitation for Bradley Lake Basin,
Alaska. 16 pp.
Recommended Guidelines for Safety Inspection of Dams.
U.S. Department of Interior, Bureau of Reclamation. 1977. Design of
Small Dams. U.S. Government Printing Office, Washington, D.C.
University of Alaska, Institute of Social and Economic Research. June
1980. Electric Power Consumption for the Railbelt: A Projection
of Requirements.
Wyss, M. 1979. Estimating Maximum Expectable Magnitude of Earthquake
from Fault Dimensions: Geology, v. 7, p. 336-340.
19-3
2621B
,
"
. '
, i
, .
.'
KENAI PENINSIILA
ALASKA
SEWARD -RAILROAD
ANCHORAGE
HIGHWAY--tO\
.. -~ ....
KEY MAP
250 0 250 500 750
111111 I I ,
KEY SCALE-MILES
(APPROXIMATE)
10 0 10 20 30
11,,11. I f
SCALE-MILES
(APPROXIMATE'
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
PROJECT LOCATION MAP
DATE FEB 1983 FIGURE lSl-1,
EBASCO SERVICES ..coRPORATED
I
, '
t.
-,. i "
! ,.
LEGEND
-------TUNNEL
----ACCESS ROAD
• •
POWERHOUSE
INTAKE AND GATESHAFT
NOTES
I. TOPOGRAPHIC DATA OBTAINED FROM
U.S.G.S. 1'63,360 QUADRANGLES,
SEWARD 86-B7.
3000' , o 3000'
I I
6000'
I
SCALE
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
GENERAL PROJECT AREA
DATE FEB 1983 FIGURE. JlZ"-2
EBASCO SERVICES INCORPORATED 19-5
"
"
f
,.
r'
~
".
L
---ACCESS ROAD
PI PEUNE / PE NSTOCK
------.. TUNNEL • POWERHOUSE
• SURGE TANK OR CHAMBER
NOTES
I. TOPOGRAPHIC DATA OBTAINED FROM
U.S.G.5. I: 63,360 QUADRANGLES, SEWARD
B6-B7.
2. ALTERNATIVES A.J. B,C a D WOULD UTILIZE
INFLOW TO GRAN I LAKE ONLY
3. ALTERNATIVE E COMBINES THE FALLS
CREEK DIVERSION WITH ALTERNATIVE A.
4. ALTERNATIVE F COMBINES THE FALLS
CREEK DlVERSION WITH ALTERNATIVE n
:J:XX)I d
SCALE
'YXXJI f!lXX)l ,
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
ALTERNATIVE PROJECT
ARRANGEMENTS
DATE FEB 1~8'3 FIGU~E .JJZ:-'3
"
;
L
f .
"( :" '" .'
SCAl E I'b 1000'
DATUM-MSl
NORMAL MAXIMUM
POOL EL. 745
lEGEND
----ACCESS ROAD
----SURFACE POWER CONDUIT
--------BURIED POWER CONDUIT
-. -. -TRANSMISSION LINE
NOTES
I. TOPOGRAPHY PREPARED BY NORTH
PACIFIC AERIAL SURVEYS, INC.
NOVEMBER 1981.
2.ALTERNATIVE E SHARES THESE SAME
PROJECT FEATURES BUT ALSO
INCLUDES THE FAllS CREEK
DIVERSION DAM, PIPELINE AND
ACCESS ROAD (SEE FIGURE 2).
500' 0 500' lood 1500'
, , , , ' , t ,
SCALE
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
ALTERNATIVE-A
GENERAL PROJECT ARRANGEMENT
DATE FEB 1983. FIGURE .Dr -4.
EBASCO SERVICES INCORPORATED 19-/
I: ,
,-
" L
L
, "
HWY.
~
SCALE I~IOOO'
DATUM-MSL
LEGEND
----ACCESS ROAD
----SURFACE POWER CONDUIT
--------BURIED POWER CONDUIT
(BENEATH MAIN DAM)
--~ •••• -----TUNNEL
-·_·-TRANSMISSION LINE
NOTES
TOPOGRAPHY PREPARED BY NORTH
PACIFIC AERIAL SURVEYS, INC.,
NOVEMBER 19SI.
500' 0 500' 1000' 1500'
."',. e
SCALE
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
ALTERNATIVE -B
GENERAL PROJECT ARRANGEMENT
DATE FEB 1983 FIGURE :nz:-5
____________ ~_E_B~A_S_C_O_S_E_R_V_IC_E_S_I_N_C_O_R_PO __ RA_T_E_D .. 19 -8
,
'"
f'
L
'"
,
" ..
l.
N
SCALE l'klooo'
DATUM-MSL
~----!NORMAL MAXIMUM
POOL EL. 745
LEGEND
----ACCESS ROAD
-----SURFACE POWER CONDUIT
---... -----BURIED POWER CONDUIT
(AT MAIN DAM)
_._._. TRANSMISSION LINE
NOTE
TOPOGRAPHY PREPARED BY NORTH
PACIFIC AERIAL SURVEYS, INC.
NOVEMBER 1981.
5'19', . ,9 59d lo,Od 15,00'
SCALE
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
AL TE RNATIVE-C
GENERAL PROJECT ARRANGEMENT
DATE FEB 1983 FIGURE 'ISl.-6
EBASCO SERVICES INCORPORATED 19-9
,.
f .
"
" i. :
f'
L
f'
l .
f -
L
~~ , .
L ~u1 ~ , . " L (!)
R:~ POWE ~tn .. g,:x
\ g:lLI ::s
f
..
... ~~
~.J -...JlLI
SCALE Ill::: 1000'
DATUM -MSL
LEGEND
---ACCESS ROAD
---SURFACE POWER CONDUIT
--------TUNNEL
_._.-TRANSMISSION LINE
NOTES
TOPOGRAPHY PREPARED BY NORTH
PAC I FIC AERIAL SURVEYS. INC.»
NOVEMBER 1981.
ALTERNATIVE F SHARES THE SAME
PROJECT FEATURES AS ALTERNATIVE
D AND ALSO INCLUDES THE FALLS
CREEK DIVERSION DAMI. PIPELINE AND
ACCESS ROAD (SEE FI\;URE 2)
500' 0 500' load 150d
I , , , , , t
SCALE
ALASKA POWER AUTHORITY
GRANT LAKE HYDROElECTRIC PROJECT
ALTERNATIVE-D
GENERAL PROJECT ARRANGEMENT
DATE FEB 1983 FIGURE D'C-7
EBASCO SERVICES INCORPORATED 19-10
----
UPPER
TRAIL
pLAKE
, ..
, ..
, ';/
PLAN
NOTES=
I. TOPOGRAPHY IS BASED ON MAPPING PREPARED BY NORTH
R\CIFIC AERIAL SURVEYS, INC" AND SURVEYS CONDUCTED BY
RaM CONSULTANTS, INC" IN 1981 AND 1982,
2. VERTICAL CONTROL IS BASED ON U.S.G.S. DATUM (MEAN
SEA LEVEll. HORIZONTAL CONTROL IS BASED ON THE
ALASKA STATE' PLANE GRID SYSTEM t ZONE 4.
• BORING NO. COORDINATES DEPTH (FT)
.DtH-82 N 2;~02,'521.n9' ,8 ....
E 017.101.707'
DH-Z-82 N 2,,02,'511.708' ,1.,'-
E 617.181.89,+'
......
DH-,-82 N 2,,02.188.007' 18«;.2'
E 617,1578.888'
DH-'+-82 N 2,162.289.'+6'+' 2215. '3'
E 01 8 ,802.QqI'
DH-r:;-82 N 2;~o2,128.0'i9' 71).'"
E 020.202. ,O'+'
~--------~-.------............ ---~------------~~................................ ---~-------------,.............. ---------~-----------,~--~------~------------_,~ qOO
..
~ -
~ ~
800
700
,..
..J
VI
E ...,
.,!.
~
I
z
0 600 ...
l"-.e >
'" ..J
'"
C;OO
UPPER TRAIL L
EL 467 -
'+«;0 -q+OO
POWERHOUSE
-'5+00 0+00
I
I
I
I
STEEL I LIN I)
TUNNEll
'HOO
iL---~----------------------------------------------------
200' 0 200' 400' 600'
I, ,I I I I
SCALE (UNLESS NOTED)
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
------------~'i00
BORI N G PLOT PLAN L--~ ______ ~ ____________ _L -----------~~'+'i0
20+00 215+00 ,0+00 ,15+00 10+00 1'5+00
PROFILE DATE FEB 198'3 FIGURE llr-8
EBASCO SERVICES INCORPORATED 19-1 1
r
r l.
" L , ..
.. i
r"'
L •
, ..
~
f'
L
f'
L
r , '
Il.
J".
L"
!"~
1 ..
N
N362,700
N362,600
N362,500
UPPER TRAIL
LAKE
N362,400
N362,300
8 ,...
N362,200 CD" -~
I.U
i.
e.g -CD
W
5 I .~ cpo ----. --.......
----f ------. ;.
*---.
*--.
*--•
5
I:)
I:)
0)
CD" -CD
W
. ~
I:)
8. .... -ffi
19-12
8 -~" *
CD
W
30
~ .... -CD
W
EXPLANA TION
-e-e-SEISMIC LINE SHOWING GEOPHONE LOCATION
* SHOT POINT
~ BOREHOLE LOCATION
60'
I I ,
CONTOUR INTERVAL 5 FEET
o
I
60'
I
SCALE IN FEET
ALASKA POWER AUTHORITY
120'
I .
GRANT LAKE HYDROELECTRIC PROJECT
DEPTH TO BEDROCK
POWERHOUSE COVE
DATE FED 1983 I FIGURE 1Y - 9
EBASCO SERVICES INCORPORATED
r
,
r
(
,.,.
//
'/6 J '
, : '}
LEGEND·
:·:+~~;~~~AZ:iJ~!1~;.~~.f{t ALWIUM
" NOTES:
AVALANCHE DEBRIS
TALUS ROCK GLACIER
GRANT CREEK FAULT
LINEAR FEATURES VISIBLE
ON AERIAL PHOTOGRAPHS
AND SATELUTE IMAGERY.
TOPOGRAPHIC DATA FROM US.GS. MAPS,
SEWARD B6-B7.
o
I
SCALE
300cJ
I
6CIXi
I
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
REGIONAL GEOLOGIC MAP
OF THE PROJECT AREA
DATE FEB 198'3 FIGURE &-10
EBASCO SERVICES INCORPORATED 19-13
f'
~"
"
f~
0: ,
,
~
"
~.
" L
/!'
L
l
UPPER
TRAIL
LAKE
LOWER
GRANT
LAKE
N NOTES:
i
I. TOPOGRAPHY IS BASED ON MAPPING PREPARED BY NORTH
~CIFIC AERIAL SURVEYS, INC., AND SURVEYS CONDUCTED BY
RaM CONSULTANTS, INC., IN 1981 AND 1982.
2. Vf:RTlCAL CONTROL IS BASED ON U.S.G.S. DATUM (MEAN
SEA LEVEL). HORIZONTAL CONTROL IS BASED ON THE
ALASKA STATE PLANE GRID SYSTEM, ZONE 4.
LEGEND:
'EDROCK -UPPER CRETACEOUS
r-;;:-l Graywacke· Thick to raassivelY becfded with mino" L...::.J undy":.I,.te Bnd/or alate k,lerlayers.
r-;-l C,..ywacke -Thin" ~iWII bedded, wltn Hndy slate L..:.....J end/or slate interlayers.
r--;-l ....... Thinly .... lNt8CI III fl-Ugy units with minor L....:...J -.,nu of ,rap.::ke ..,d/or undy slate.
UNCONSOLIDATED DEPOSITS -QUARTERNARY
G .... rfici.' deposits, gener.lly 5 f_t or more m thickness.
o Iurlicial deposits, generally 5 f_t or less in thickness
e 4 GecMogic field Stlltlon
DH-t.. Di_ C_ .--e--Contact ..... heeI ..".,.. Inr_
f470 Strike..,d dip of bedding
411~ ... Strike slip fault
·~ ••• ReVer"H fault
D
._--Lin.-nent, probable fault
~ Probable fault su,.p, hachures on downthrown side
~ 'Thruat fault, h.chures on upper block
200' 0 , , , , , 200'
SC~LE
400' 600' , ,
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
GEOLOGtC MAP ALONG
TUNNEL ALIGNMENT
DATE FEB 1983 FIGURE riL-11
EBASCO SERVICES INCORPORATED 119 -14
,..
1
i ;
r
,1
~
j. <,
"
i. i-
f' L
r1
~~
,.
L
,-
l"
, 1 ,
L
, '
i.
W
1000-
.~() -
900
8~O -
aoo -
-ll'i!O -
UI
~
t-100 ...
Z eSo-
'2
t-
<1000 -> w
l:! ~~o-
~()()-
450-
400-
EXPLANATION
BEDROCK UPPER CRETACEOUS
~ Graywacke-Thick to massively bedded with
sandy slate and/or slate Interlayers.
NO VERTICAL [XAGGERATIOJr..
Gra'y"""Cke Thin to medium bed.ded, with sandy slate
and/or slate Inter-layers.
Sanoy Slate Gradatlof'lill If' composItion betwnn gray-
wacke and slate, Or intimately Inter-
layered packages of graywacke, sandy
slate and slate,
5Ia... Thinly laminated to flagoy units with minor
amounts of graywacke and lor sandy slate.
Diamond Core HOlle
PT 16 Tunne, Allgnmen .. ~urve.,. ,::itation
Contac", dasheo wr.e,.e Inferred
, -.000-
••
&80-
.00-
J750-
UI
::E -.... 7GO-...
~&8()-
~
>800-...
...I w 880-
~oo-.. ()-
t~~~---------------------------------------
E
NOTES:
I. TOPOGRAPHY IS BASED ON MAPPING PREPARED BY NORTH
PACIFIC AERIAL SURVEYS, INC., AND SURVEYS CONDUCTED BY
RaM CONSULTANTS, INC., IN 1981 AND 1982.
2. ~RTICAL CONTROL IS BASED ON U.S.G.S. DATLrM (MEAN
SEA LEVELl. HORIZONTAL CONTROL IS BASED ON THE
ALASKA STATE PLANE GRID SYSTEM, ZONE 4.
100'
I I
o 100'
I
SCALE
200'
I
300'
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
TUNNEL -INTERPRETIVE
GEOLOGIC CROSS SECTION
DATE FEB 1983 FIGURE ISl'-12
_________ ...... ....;E;.;;B:;,;.A.;;.;;s:.:C:.:O~S;,::E::..:R..:.V:.::I C:,:E:::S:..;I::.;:N:,::C:.,:::O::.:R:,:..P.:;::O:,:R,:::A.:,.TE:::D:::.J 19 -1 5 .
-
-
r-!.(1Ii
-
......
-
lIJ -a::
0
(.)
..... .. ~ e
.....
0 -lIJ
(.!)
' ... ~ -~
(.) a:: ,.,. ~ .-
------
-
-
100
90
80
70
60
50
40
30
20
10
0
100 90 80 70 60 50 40 30 20 10 0
PERCENTAGE ROD
NO TE: Total length of DH· 3, DH· 4 and DH· 5 is 486 feet.
ROD includes all rock types.
19-16
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
CUMULATIVE DISTRIBUTION
OF
RQDVALUES
Boreholes DH . 3, DH . 4 and DH . 5
DATE" FEB 1983 FIGURE nl-13
EBASCO SERVICES INCORPORATED
-~---------------------------------------------------------------,
---
AREA (ACRES)
-
_ ~700~----~----~-----4------+---~a------+------r-----~----~
LLI _ LLI
U.
~
z 680i~----4------+-----4~----+-----~----~~----+-----;-----~
_0 ....
I-.. cc
>
RESERVOIR
SURFACE
AREA
-~660~----4-~~-+-----4~----+-----~----~------~----;-----~
_LLI
------
-
-
-
--
, ... -
840~~ __ ~ ____ ~ ____ ~ ______ ~ ____ -L ____ ~ ______ L-____ ~ ____ ~
160 180 200 210 240 260 210 300 120
VOLUME (ACRE-FEET x 1000)
NOTE:
ALL VOLUME COMPUTATIONS ARE DERIVED FROM THE 1"=1+00'
TOPOGRAPHIC AND BATHYMETRIC MAPPING PREPARED IN 1981 AN.D
1982 BY NORTH PACIFIC AERIAL SURVEYS, INC.
ALASKA POWER AUTHORITY
GRANT LAKE HnJROELECTAIC PROJECT
GRANT LAKE
AREA -CAPACITY CURVES
DATE FEB 1983 FIGURE :nz:-14
-EBASCO SERVICES INCO~PORATED ~--------------------------------~------------------------~ -19-17
o
'----I -
2
r----
'--
, I
-I
8 0 I) 12 18 2'1 30 16 '12 '18 <;'1 ItO 66 12 18 8'+ 90
VI
"-
0
C;
OJ 10 o o
<::>
• 2<;
" o
..J "-20
-' VI
E: ... ... ...
"-
z
8
1<;
10
o
710
~ 700 ... ... ...
<Ii: ::;
1; ...
III ...
<Ii:
V-
0
TIME. HOURS
PROBABLE MAXIMUM STORM RAINFALL DISTRIBUTION
•
I
• I I
I !
I
I i I
i
I I I I
I
I
I
I j /\
I i
V
I / ~
I / \ 1
L,rOU FLOW
i I~LOW-+J / \ " ;; /V '~
/ ...-~ ~~
i -r-, -...... I
I) 12 18 2'+ 30 • ~ ~ ~ ~ 66 n n ~ •
TIME. HOURS
PROBABLE MAXIMUM FLOOD HYDROGRAPHS
I ~
i /1 " --, il '\,\ i
i
i ./ "-
J.....-V ) '" "..-I '-...
../ V i i
... J. .......... I
~ .......
i
TIME. HOURS
PROBABLE MAXIMUM FLOOD RESERVOIR ELEVATIONS
10.000
1.000
11.000
<;.000
'+.000
3.000
2.000
V\ ...
~ 1.000
1I
0
...J
"-
<;00
100
1.0001
.., ...
!
11 0
5 100 ..
III ...
III
!
III
<Ii:
RETURN PERIOD (YEARS)
1.11 1.2<; 'i 10 2'i 'i0 100
I ~ ./
l/
V[~
~,
~~
80 <;0 20 10 'i 2 I
PERCENT CHANCE
FLOOD FLOW FREQUENCY FOR GRANT CREEK
/'
/
/
I
/
............. ~
......... V
10000 1<;000
DISCHARGE. CFS
.......... ~
20000
NATURAL OUTLET RATING CURVE
...-
2<;000
1000 10,000
0.1 0.01
NOTES:
L PROBABLE MAXIMUM FLOOD WAS DERIVED BY
TRANSPOSING BRADLEY LAKE PROBABLE MAXIMUM
STORM TO GRANT LAKE AND RATIOING MEAN ANNlJAL
RUNOFF.
2. THE PMF INFLOttI HYDROGRAPH INCLUDES SNOWMELT
INPUT OF 0.01 INCHI HOUR.
,. THE INFLOW HYDRO GRAPH FOR THE PMF IS BASED
ON oHR. PERIOD AVERAGE FLOWS AND THE OUTFLOW
HYDROGRAPH ON A(TUAL ROUTING RESULTS.
4. POINTS PLOTTED ON GRANT CREEK FLOOD FLOW
FREQUENCY CURVE ARE BASED ON DATA GIVEN IN
"FLOOD CHARACTERISTICS OF ALASKAN STREAMS."
USGS. 1979. FOR USGS GAGE NO. 11)240000. GRANT
CREEK NEAR MOOSE PASS .
I). ELEVATIONS BASED ON MEAN SEA LEVEL.
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
FLOOD HYDROLOGY
a NATURAL OUTLET
RATING CURVE
DATE FEB 1983 FIGURE ISl-15
______ -.1....;;;E~B~A~S:.;:C;.:O:..S:;.;E;;;;R..;..V;;.;.I.;:.C.=.ES;:;..:.:IN;.;:.C;:.O:;,;R:.:;P;...;O:.:R~A.:..T:..:E=D:.J 19 -18
-
-
-
.-
---
-
-
-
-
--
-
-
, ... ---
-
700'---.---.---~---r---r--~--~----r---'---~--'---1600
1 ___ ~ .. ~--~--~--~~~~~~~--~--~--_+--_+--_4--~ 650~ 100
640 0
OCT. NOV. DEC. JAN. FEB. MAR. APR. MAY. JUN. JUL. AUG. SEP.
MONTH
LEGEND
___ NATURAL DISCHARGE ALASKA POWER AUTHORITY
-II) -o -
IN GRANT CREEK GRANT LAKE HYDROELECTRIC PROJECT
.. ~~~~
REGULATED RESERVOIR
ELEVATION
POWERHOUSE
DISCHARGE
19-19
MONTHL Y STREAMFLOW
DISTRIBUTION AND
RESERVOIR REGULATION'
DATE FEB 1983 I FIGURE 111-16
EBASCO SERVICES INCORPORATED
..
P i1
f1
p ,
t. • ,.
%
I..
n
~
r:
r" l ..
f' L
r:
[:
r" L
p
L
! .
r .
n
U
t.
N """,
"'"'-
\
r-'-
,\
.-'
\.-
o o o
$
t'"
N
Z
=';:'"'-'-'-=--.+ """"-
'/
"\" \ \'
\ ' , \
\ \ \
\ ,
_-.J
:::~~. ~ '"'-~-
-.
~ ~----.. ------------~.---
{
\
GRANT LAKE
~"'--~'{-~; ,
I
I
,..-L
'-1/ , , ,
1
VfJOW£R l'lJNm!£.
I ~~ ~ ,
-. --' I
•
-" ,
SALMON Hpt.,OING
FACILITV-"
" '
SEWARD-ANCHORAGE
HIGHWAY
"
:~J
I
f
'.-:_~~~
----''';;
------,...----
~-----+-----------~---------~-------
"."\'" 0\-' '
'~ " , , , , ,
PRIMARY ACCESS
ROAD
'---'
~' -
.~.-............ -.
o
~ \
-.
-,
/
/{
,~ ~ANT (;RE£I(
,. GAGING STATION
--...---------I -------..... "_ ..
----[ :X~~~N~G~C~E'!!!:A~2~4;.q~K~; .. --------GRANT LAKE
SWITCHING STATION
TRANSMISSION LINE
LE GEN 0:
- - - -PIPELINE AND TUNNEL
===== ACCESS ROAD
• • NEW liS ltV TRANSMISSION LINE
.. -----. EXISTING 24.t1tV TRANSMISSION
LINE
NOTES:
I. TOPOGRAPHY IS BASED ON MAPPING PREPARED
BY NORTH PACIFIC AERIAL SURVEYSI.INC.,
AND SURVEYS CONDUCTED BY Rail
CONSULTANTS, INC •• IN 1.1, AND 1.12.
2. VERTICAL CONTROL IS BASED ON US.G.5.
DATUM (MEAN SEA LEVELl. HORIZONTAL
CONTROL IS BASED ON THE ALASKA STATE
PLANE GRID SYSTEM, ZONE 4.
3. ALL ROADS ARE CLASS B EXCEPT THE
PRIMAY ACCESS ROAD FROM THE SEWARD-
ANCHORAGE HIGHWAY TO THE POWER-
HOUSE, *HICH IS CLASS A.
400' 0' 400'
I I I I
SCALE
800'
!
1200'
I
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
SELECTED
PROJECT ARRANGEMENT
SITE PLAN
DATE FEB 198, FIGURE Ii-17
EBASCO SERVICES INCORPORATED 19-20
, .
l ..
r 1
L
" L
r
L
f' ,
L
r'
l ,
0
0
0
.D
:0
UJ
,..,
...J
III
J: .....
.!-
~
I
Z
0 ....
l-
e(
>
UJ
...J
UJ
NOTES:
I. TOPOGRAPHY IS BASED ON MAPPING PREPARED BY NORTH
~CIFIC AERIAL SURVEYS, INC., AND SURVEYS CONDUCTED BY
RaM CONSULTANTS, INC" IN 1981 AND 1982,
2. VERTICAL CONTROL IS BASED ON U.S.G.S, DATUM (MEAN
SEA LEVEL). HORIZONTAL CONTROL IS BASED ON THE
ALASKA STATE PLANE GRID SYSTEM, ZONE 4.
3, BASED ON PRELIMINARY FIELD GEOTECHNICAL EXPLORATION
PROGRAM, ROCKBOLTING IN THE TUNNEL IS ESTIMATED TO
BE REQUIRED FOR APPROXIMATELY 15% OF THE TUNNEL
LENGTH.
I" 6 ROCKBOLTS (SEE NOTE)
STEEL
\ PENSTOCK
3" SHOTCRETE
FOR INITIAL
TUNNEL SUPPORl
~~~..... CONCRETE
,~ #J;~/ ,~\/\ \ J /' ~ ·it JIIf
I ~",JI\1
\ ... i
3" MINIMUM
THICKNESS OF
SHOTCREH
LINING
6" CONCRETE •
,---------l~ 10· e FISH
BYPASS
PIPELINE
• ,-'-___ CONTACT
GROUT~D
..
900
800
100
bOO
0;00
PLAN
TYP SHOTCRETE LINED
TUNNEL SECTION
TYP STEEL LINED
TUNNEL SECTION
4' 0' 4'
I
8'
I
12'
I f « , , I
,-----------,-------------,--------------.-------------,--------------,-------------~------------~~~~------~--------------~ qOO
r-----------+-------------~------------~--------~---4--------------~--------~~+_------------~--------~---+--------------~ 800
::i
Ir) :.
t!-
IL.
100~
o
~---------i------------_r--_t--------t_----------~----------_r~~~~~~--~--~~~~~~~----~~~~~~ __ ----~~bOO
POWERHOUSE
TAILWATER
(El 4b8 AT
POWERHOUSE) I-----------~--------~~~~r_--------~~~~--~---~--------------+_------------~------------~------------~--------------~o;OO
UPPER TRAIL LAKE
EL 467
ti > 1&1
...J
1&1
SCALE
200' 0' 200' 400' 600'
I, ,I I I I
SCALE. (UNLES!:. NOTED)
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
S=.008 ~o;O-9~+~0~0--------~-o;~+~0~0-----------0~+~0~0~--------~o;++0~0~----------1~0+-0-0------------lo;l+-0-0-----------2~0+-0-0-----------2-o;L+-0-0----------~-0~+-0-0-----------~-o;L+~004o;O
POWER CONDUIT
PLAN AND PROFILE
PROFILE DATE FEB 198'3 FIGURE ril-18
EBASCO SERVICES INCORPORATED 19-21
,.
L
r
L
[
, ' ,
I l",
r •
t!-
I.r.. ,
Z o
~ > LIJ
...J ....
o o
I'-
NORMAL MAXlMLtrl POOL '" EL69 I •
ASSUMED~.
TOP OF ROCK ---_
PLAN
200' 0'
1,,11 1,,"1
EL 691' NORMAL MAXIMUM POOL
2.00'
I
SCALE
400'
I
- -....... __ :_=----..£.~O~R~IG~IIINAL GRADE ALONG CHANNEL CENTERLINE ---
SECTION A-A
JOO' O' JOO'
1.11 ,1,11,1 I
SCALE
200'
I
---
-"
SECTION 8-8
20' (1 2(1
1,,"1",,1 I
SCALE
40'
I
NOTES:
I. TOPOGRAPHY IS BASED ON MAPPING PREPARED BY NORTH
A:\CIFIC AERIAL SURVEYS, INC .• AND SURVEYS CONDUCTED BY
RaM CONSULTANTS, INC., IN 1981 AND 1982.
2. VERTICAL CONTROL IS BASED ON U.S.G.S. DATUM (MEAN
SEA LEVEll. HORIZONTAL CONTROL IS BASED ON THE
ALASKA STATE PLANE GRID SYSTEM, ZONE 4.
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
GRANT LAKE
CHANNEL EXCAVATION
DATE FEB 198'3 FIGURE N-19
_______ a...;;;;;E,;;;;.B~A,;;;;.SC.;:..::.O...;:S:.:E:.:.R.;;..;;V~IC:;.;E:;.;S:;..;;.:.IN.;;.;C:.;O:.:R.:.;;.P..;:O;.:.R.:.:.A.;;..;;T.:E=D;.J 1 9 -22.
[
r~
L
/I' •
"
9' .. 2'
SLIDE
GATE
12'-0
SECTION A-A
TEMPORARY
BULKHEAD _______ ..
\3" MIN.
SHOTCRETE
LINING
ROCK BOLTS
AS REQUIRED
50'
FISH PIPELINE
TRANSITIONS FROM
TUNNEL CROWN TO
INVERT
SECTION B-B 9'-6 .1
SECTION C-C
"BELL-MOUTH I PIPE ENTRANCE
100'
. ,
DETAIL E
GATE SHAFT AND INTAKE PROFILE
20' 0' 20' 40' 60'
I II I I I I I
SCALE
I" ',' "
15'
VIEWD-D
PLAN OF CIRCULAR
TRASH RACK
"ROTATING
FISH SCREEN
N
ROCKBOLTS (TYP)
TREMIE CONCRETE
, , \
/1 t
II
lit
, Ie \ \ \ , "
DETAIL E
EL 691 NORMAL MAXIMUM POOL
\
,I
,
\
, I
\'
"
•
EL 660 MINIMUM POOL
TREMIE
CONCRETE
,II
III
'If
r ,
,~ :
1-' :
r I
I
I. -I
f' .. FLOW
t
h
I EL 618
t.-• • >
• . I
. ,
\ , • ~ ~ =
5'
I ,
NOTE:
ELEVATIONS BASED ON MEAN SEA LEVEL
0' 5' 10'
, I I I
15'
I
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
INTAKE AND GATE SHAFT
DATE FEB 1983 FIGURE riZ'-20
______ -~EB;;;;.;A;.;;.S:;.C:;.O.;;;;;...;;S;.;;;E;.;.R;.;.V.;;.;IC;;;.;E;;;.;S;;;...;.;;.IN.;;.;;C;..;O;;.;.R.;.;.P...;;O;.;.R_A_T_E.;......I!D 19-23
r~
t
n
!
,
" ,'~
~ .
r'
i.
r
, J
r' ,
l ..
r'
L
L
'" ~' ...
r'
til
f'l
L
r
L._
r
lj
f'
".if
,
N
~ I
~
I
)
/
(
/
:J
CI)
::IE .
l-
lL
• ~
fi > w
,.J w
/
/
/
/
",.
550
525
500
475
450 7+00
/
/'"
/
UPPER I TRAIL
LAKE
'il j EL 467
~
-6+00 -5+00
---r -rrl ~~ '""--S .001
-4+00 -3+00
PLAN
v
PO ERHO .. U~ :L V
4
1
r~ ~~IL ~
.............
Ii TURBI" EEL.470, ---I I ~lJr STEEL LI ",ER R. () POW
Ii I DIAMETE ~. VA \9'-TUNNEL ~ rr 1 FROM 10 ~itTO
~J"'V
I I -It -~ TAILRIl ~I!. CHIlNI In ~ '--r....
[)'~I!--t--U r" L-
f-s·.ooe \~: ~RO .L--S~
EL.464.6 I-;;-r.K TRAP -,!,
-2+00 -1+00 0+00 1+00\ 2+00
AVERAGE TAILWATER TRANSITION TO PROFI LE EL. 468 AT POWERHOUSE A LINED TUNNEL
R
h\JVi\
55" 'Y"
-3+
575
550
I
l-
lL .
z
Q
500 I-:!
475
450
00
w
,.J w
NOTES:
I. TOPOGRllPHY IS BASED ON MAPPING PREPARED BY NORTH
R!.CFIC AERIAL SURVEYS. INC., AND SURVEYS CONDUCTED BY
R8M CONSULTANTS, INC., IN 1981 AND 1982.
2. VERTICAL CONTROL IS BASED ON U.S.G.S. DATUM (MEAN
SEA LEVELl. HORIZONTAL CONTROL IS BASED ON THE
ALASKA STATE' PLANE GRID SYSTEM. ZONE 4.
TAILRACE CHANNEL TO BE LINED WITH RIPRAP UP TO
ELEVATION 470 BETWEEN STATIONS -0+50 AND -4+00
TAPERING DOWN TO ELEVATION 467 FOR THE
REMAINOER OF THE CHANNEL
'L'O· .... , ..... -L'--,'..J?L· __ ...l5'O_· __ Io-L,0_·_---1I~OI
SCALE (UNLESS NOTED)
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
POWERHOUSE AREA
PLAN AND PROFILE
DATE FEB 1983 FIGURE l2' -21
EBASCO SERVICES INCORPORATED 19-24
,.
L
" ,
,. ,
L
,.
L
, ..
[
r
i
L
f '
L
I ..
t
~ 4r;~
:1
14~ 11'-&
EXCITER
CONTROL ROOM
GOVERNOR
AIR I ~ COMPRESSOR I
0 I ~ g,
-I 7780kVA
0 --\$--GENERATOR 3" ---
SERVICE BAY
0
-I
~
-D ... I I i
-J.L--____ j_. ____ . __ ._~_i
SECTIONAL PLAN raJ E L 487.0'
EL ';12.0'
SWITCHGEAR
EL ';01.0' ROLL-UP
DOOR
I
GENERATOR
EL ';17.0'
INSULATED
ALUMINUM
SIDING
-GATE HOIST
I
~WL~~~~~~~~
DRAFT TUBE
GATE
{, EL 470_0' r-----
-TAILWATER
EL 4&8.0'
---------:-~ -~~~ - ---h"rIl-,-rW--l.,.</
>.c--4'::.+H-t-1I'-DRAFT TU BE
CJ--=-~-=--= =--= ~~:---=----------ACCESS GALLERY
10"_ FISH • .
BYPASS PIPELINE --------~~..,..,
EL 4';~.0'
TRANSVERSE SECTION THROUGH ~ OF UNIT
SPIRAL CASE
ACCESS GALLERY
EL 4&8.0'
::
1-'
I
I
VALVE RM
EL 4&';.0'
" . ~.
DRAINAGE
SUI'1P
SECTIONAL PLAN raJ EL 470.0'
I
GENERATOR
I
AUXILIARY
TRANSFORMER
ULI+IO~_' __ _
EL 4&';.0'
"--+-+-10" _ FISH
BYPASS PIPELINE
SUMP
i-',
:, EL 447.0'
LONGITUDINAL SECTION THROUGH i OF UNIT
LEGEND:
1=:: ::: ':':1 FIRST STAGE CONCRETE
~ SECOND STAGE CONCRETE
NOTES:
I. ELEVATIONS ARE BASED ON MEAN SEA LEVEL.
r;' 0' ,;' 10' I';' 20'
I " " I I I
SCALE
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
POWERHOUSE PLANS AND SECTIONS
DATE FEB 1983 FIGURE nT-22
EBASCO SERVICES INCORPORATED 19-25
r
i
" L
n
L
" L
r'
t .
EXCITATION
TRANSFORMER
SEE FIG. m-I
lie; KV TRANSMISSION LINE
WAVE
TRAP
~B
MAIN TRANSFORMER
9/10.0 MVA OAIOF J..-
11'5 I<.V :1+10 "V ."
Z= 11.1)" <J
GENERATOR
BREAKER
1000A
.... ----1 f-(----,
BUS OR CABLE
DISCONNE<,;T LINK
"a:::D-<+-~ ~~ SYNCH.
..
o
87
SURGE PROTECTION ~ .... _________________ ........ __ -+ ____________ .;p
STATION SERVICE
TRANSFORMER
1+.10 II. V 1+80/277V
150kVA
II.-.,:I~o--.... -.....
DISCONNECT
LINK
BUS OR CABLE
r----------------------. --,
I I
I T I
: RE~ :
I I
! u: I I
I I
I I
RECTIFIER ~:
GENERATOR EXCITATION
<STATIO
GR~DING
TRANSFORMER
'3
~~~,~~~~-~-~-~-~--+--~
GENERATOR
7.8/9 MVA 0.90PF, SO/SOC
4.16 kV 311 SOHl
400 RPM
7MW
120/208 VoA.C.
LOADS
1+80: 120V
2
1 ·
) 100AF ~ (TYP.)
I .. ov
LOADS
Z· 3%
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
POWERHOUSE
MAIN ONE LINE DIAGRAM
DATE FEB 1983 FIGURE x-a
EBASCO SERVICES INCORPORATED 19-26
f
,.
r'
L
,,,
j
f"
r'
I,
...
I.
in' ~I
---ASSUMED 115 KV TRANSMISSION 1-: ~""""'.-=~~~~~;i~~~:, LlNE-------J ~o!; ~ ----~ CRUSHED
~ ---___ ____ STONE D.. i
..-\---r----::;iIT'!''!!.":...:::.'''''=::::::::---::~f":::::_-f__-...)..._::J~~~-----.i COMPACTED
RANDOM
FILL
24' ---
40'
TYPICAL RIGHT-OF-WAY CLEARING LIMITS TYPICAL RIGHT-OF-WAY CLEARING LIMITS
35'
CLASS A ROAD AND TRANSMISSION LINE
TYPICAL SECTION FOR SLOPED TERRAIN
CRUSHED
STONE
24' 5'
(TyP)
55'
DOUGLAS FIR
AVERAGE POLE
SPAN = 400' (TYP.)
TYPICAL RIGHT-OF-WAY CLEARING LIMITS ·1· TYPICAL RIGHT-OF-WAY~CLEARING LIMITS
CLASS A ROAD AND TRANSMISSION LINE
TYPICAL SECTION FOR FLAT TERRAIN
.1
ASSUMED
TOP OF ROCK
ORIGINAL
____ ( GROUNDLINE
---. ___ <t 6"
---I
~I COMPACTED
RANDOM FILL
3
1--____ =18' ____ ---ool ~ ~I
I. 20'
TYPICAL RIGHT-OF-WAY
CLEARING LIMITS
,
·1, 20' ~
TYPICAL RIGHT-OF-WAY
CLEARING LIMITS
TYPICAL CLASS B ROAD SECTION
{:
ORIGINAL
GROUNDLINEASSUMED
l ___ 3 ~~ TOP OF ROCK
£ ... I ~I ___ t
I ---r ~~r, -~~~~~*=~~ ~ I 100----1. _---=--_~
20'
TYPICAL RIGHT-OF-WAY
CLEARING LIMITS
TYPICAL CLASS B ROAD SECTION ADJACENT TO
THE FALLS CREEK DIVERSION PIPE
5'
NOTES:
I CLASS A ROADS PROVIDE ACCESS TO THE
POWERHOUSE.
2. CLASS B ROADS PROVIDE ACCESS TO THE
GATE SHAFT, FALLS CREEK DIVERSION DAM
AND PIPELINE.
3. CLASS B ROADS ARE TYPICALLY LOCATED
IN AREAS OF SLOPED TERRAIN.
o 10'
I ' , I
5'
I
15'
I
SCALE
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
ACCESS ROADS
TYPICAL SECTIONS
DATE FEB 1983 FIGURE I2"-24
EBASCO SERVICES INCORPORATED 19-27
f
L
r
L
,.
, .
.. -
,
L
,
l . , ..
L
, , ,
-l
VI
1400
1300
1200
1100
~ 1000
r-
Io. ,
Z
o 900
~ > W
-l
W
800
N-------.-
E 623.000 +
{XI STING GRADE
-.:;;; ;;;--
~ // ..c""-<::
~ I/~ 700
600
130+00 120+00 110+00 100+00
E 6_23.000 +
gl
~
"\ -.
~OO' 0' ~OO' 1000' I~OO'
-I -. .. -I -I -II -, , , ,
SCALE
-r
/ '7
(FALLS ( REEK
~ V DIVERSI( N PIPELINE
--/-~ -----
90+00 80+00 70+00 60+00 50+00 40+00 30+00
STATIONS
DIVERSION PIPELINE PROFI LE
I , ,
. \L.........-3a.,,'
\ DIVERSION
-", PIPB.l.INE ,
\: , '
PLAN LEGEND:
----DIVERSION PIPELINE
ACCESS ROAD
NOTES:
I. TOPOGRAPHY IS BASED ON MAPPING
PREPARED BY NORTH PACIFIC AERIAL
SURVEYS. INC., IN 1981 AND 1982.
2. VERTICAL CONTROL IS BASED ON
U.S.G.S. DATUM (MEAN SEA LEVEL).
HORIZONTAL CONTROL IS BASED ON
THE ALASKA STATE PLANE GRID
SYSTEM, ZONE 4 .
EXISTING ---"'"
AC.C£$& ROAD
TO 8E IMPROVED
SP LLWAY CREST EL 1404~ I ~ FALLS CREEK
I
20+00
I
20+00
DIVERSION DAM v-' /. I ",'"
'" A 1300
i
i
!
I
!
10+00 0+
,
1200 ~ ,
z o
1100 ~
1000
00
1&1
...J
1&1
STATIONS
ALAS KA POWER AUTHORITY
GRANT
FALLS
LAKE HYDROELECTRIC PROJECT
C REEK DIVERSION WORKS
PLAN a PROFILE
DATE FEB 1983 FIGURE N-2'5
EBASCO SERVICES INCORPORATED 19-28
n
r
'1 L
" I ,
" L
" L ,.
t. ..
,.
L
f'
••
#,'1£
lo. ..
f .,
f
l.
" .
i,s
U
U
\'I4c,G
I'tZC;
20' O'
I I t I
11tOCI·
Ilfl
'lfC;O
'lf7C;
PLAN
20'
I
SCALE
140'
I
60"
I
i~~~----------------------------------------------
LOW LEVEL
RELEASE
GATE HOIST
LIMIT OF EXCAVATION
DOWNSTREAM FACE
ELEVATION -LOOKING UPSTREAM
LOW LEVEL
RELEASE
GATE HOIST~
o
~~-~~~ ~~~~-
11'-6
SECTION A-A
EL 1391.00
ASSUMED TOP OF
COMPETENT ROCK
NOTES:
I. TOPOGRAPHY IS BASED ON MAPPING PREPARED BY NORTH
PACIFIC AERIAL SURVEYS, INC., AND SURVEYS CONDUCTED BY
RBM CONSULTANTS, INC., IN 1981 AND 1982.
2. VERTICAL CONTROL IS BASED ON U.S.G.S. DATUM (MEAN
SEA LEVEL). HORIZONTAL CONTROL IS BASED ON THE
ALI\<;KA STATE PLANE GRID SYSTEM I ZONE 4.
IP:,,!! II! I~' 10'
I
20'
I
SCALE (UNLESS NOTED)
10'
I
ALASKA POWER AUTHORITY
GRANT LAKE HYDROELECTRIC PROJECT
FALLS CREEK
DIVERSION DAM
DATE FEB 1983 FIGURE llT-2b
EBASCO SERVICES INCORPORATED 19-29