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Prepared by:
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Alaska Resources
Library & Inf()rmatton Services
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SUSITNA HYDROELECTRIC PROJECT .
TASK 8-TRANSMISSION
SUBTASK 8.02
CLOSEOUT REPORT
ELECTRIC SYSTEM STUDIES
MARCH 1982
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Prepared by:
[i]
SUSITNA HYDROELECTRIC PROJECT
TASK 8-TRANSMISSION
SUBTASK 8.02
CLOSEOUT REPORT
ELECTRIC SYSTEM STUDIES
MARCH 1982
U.S, ~ant of the Interior
ARLIS
Alaska Resources
Library & Information Services
And w , ·A..J.ska
L..-----ALASKA POWER AUTHORITY __ __.
TABLE OF CONTENTS
Page
LIST OF TABLES -----------------------------------ii
LIST OF FIGURES ------------------------------------iii
1 -INTRODUCTION ----------------------------------
2 -PLANNING CRITERIA -----------------------------
3 -ELECTRIC SYSTEM ANALYSES ----------------------
3.1 -System Configuration ----~---------------
3.2 -Transmission Line Energizing -------------
3.3 -Load Flows ------------------------------
3.4 -Transient Stability Studies -------------
4 -CONCLUSIONS -----------------------------------
5 -SUPPLEHENTA.RY STUDIES ENERGY
l'1ANAGEMENT SYSTEM (EMS) ---------~-----------
6 -ATTACHt1ENT 1
7 -ATT ACHt1ENT 2
1 - 1
2 - 1
3 - 1
3 - 1
3 - 2
3 - 4
3 - 6
4 - 1
5 - 1
LIST OF TABLES
Number
1
2
3
4
Title
Transmission Line Energizing
System Load Flows
Transient Stability Runs
VAR Generation During Transient Swings
i i
LIST OF FIGURES
Number Title
1 Railbelt 345 kV Transmission System
Single Line Diagram
2 Impedance Diagram
3 Load Flow Diagram
4 Load Flow Diagram
5 Load Flow Diagram
6 Load Flow Diagram
7 Load Flow Diagram
8 Load Flow Diagram
9 Load Flow Diagram
10 Load Flow Diagram
11 Load Flow Diagram
12 Transient Stability Swing Curves
13 Transient Stability Swing Curves
14 Transient Stability Swing Curves
15 Transient Stability Swing Curves
16 Transient Stability Swing Curves
17 Transient Stability Swing Curves
18 Transient Stability Swing Curves
19 Transient Stability Swing Curves
iii
1-I1HkODUCTION
Electric system studies were started in June 19~0 to examine
the transmission requirements associated with Susitna
generation. The object of this work was to arrive at a
system configuration that would ensure the reliable and
economic transmission of Susitna generation to the Anchorage
and Fairbanks load centers. The scope of work was defined in
Subtask 8.D2 and in mid-1981 a draft Planning Memorandum was
prepared, entitled ~Preliminary Transmission System
A n a l y s i s 11
• T h i s m em o r an d u m e s t a b l i s h e d s y s t e m c o n f i g u r at i o n ,
transmission voltage and conductor sizes, on the basis of the
transmission distances, and site capability as they were
known at that time.
In the intervening period, subsequent to the Planning
Memorandum, site capability and generator unit sizes have
become finally established and the energizing studies, load
flows and stability runs have been repeated using these
latest system parameters. The results of these system
studies are presented in this report as confirmation of the
basic system design and to illustrate the system performance
under extreme conditions. Details of the technical and
economic analyses are given in the Planning Memorandum which
is attached to this report as ATTACHr1Ei:T 2.
1-l
2 -PLANNING CRITERIA
The planning criteria were detailed in Appendix A of the
Planning Memorandum. At that time the criteria included
references to the possible use of single-pole reclosing in
the event that this might be found necessary. However, since
the system has been found to be stable for the design
(3-phase) fault with 3-pole switching, the planning criteria
have been reissued, deleting all references to single-pole
switching. This has been done to eliminate possible
confusion regarding the protective relaying requirements for
the system. These updated transmission planning criteria are
given below.
In general, transmission facilities are planned so that the
single contingency outage of any line or transformer element
will not result in restrictions in the rated power transfer,
although voltages may be temporarily outside of normal
limits. The proposed guidelines concerning power transfer
capability, stability, system performance limits, and thermal
overloads are detailed below.
(a) Transmission. System Transfer Capability
The transmission system will be designed to be capaole
of transmitting the maximum generating capability of the
Susitna Hydroelectric Proj~ct with the single
contingency outage of any line or transformer element.
The sharing of load between the Anchorage and Fairbanks
areas is approximately 80 and 20 percent respectively.
To account for the uncertainty in future development,
the transmission system shall allow for this load
sharing to vary from a maximum of 85 percent at
Anchorage to a maximum of 25 percent at Fairbanks.
2-1
(b) Stability
The transmission system will be checked for transient
stability at critical stages of development. The system
is to be designed to have at least two parallel circuits
in every section to allow for peak power transfer
capability under single-contingency outage conditions.
Faults will be cleared with multiphase switching and
delayed reclosing.
The design fault for transient stability analysis will
be a 3-phase fault cleared in 80 ms (4.~ cycles) by the
local breaker and lOU ms (6.0 cycles) by the remote
breaker, with no reclosing.
(c) System Energizing
Line energizing initially and as part of routing
switching operations will generate some dynamic
overvoltages. System design should be arranged to keep
these overvoltages within the following limits.
Line open-end voltages at the receiving end should not
exceed 1.10 per unit on line energizing.
Following line energizing, switching of transformers
and VAR control devices at the receiving end should
bring the voltage down to 1.5 per unit or lower.
Initial voltages at the energizing end should not be
reduced below 0.90 per unit.
Final voltages at the energizing end should not exceed
1.05 per unit.
2-2
-The step change in voltage at the energizin9 end of
the line should not exceed the following values
(i) 15 percent with only one generating unit
operating at Watana (to represent a temporary
condition during the early stage of
commissioning of the Susitna project)
(ii) 10 percent with two units operating at Watana
(to represent a slightly longer-term condition
early in the development of Susitna)
(iii) 5 percent with 1,020 MW of generating capacity
operating at Susitna.
{d) Load Flow
System load flows will be checked at critical stages of
development to ensure that the system configuration and
component ratings are adequate for normal and emergency
operating conditions. The load levels to be checked
will include peak load and minimum load (assumed
50 percent of peak) to ensure that system flows and
voltages are within the 1 imits specifiea oelow.
-Normal system flows must be within all normal thermal
limits for transformers and lines, and should give bus
voltages on the EHV system within +5 percent,
-10 percent, and at subtransmission buses within
+5 percent, -5 percent.
-Emergency system flows with the loss of one system
element must be within emergency thermal limits for
lines and transformers (20 percent 0/L). Bus voltages
on the EHV system should be within +5 percent,
2-3
-10 percent, and at subtransmission buses within +5
+5 percent, -10 percent.
(e) Corrective Measures
Where limiting performance criteria are exceeded, system
design modifications will be applied that are considered
to be most cost effective. Where conditions of low
voltage are encountered, for example, power factor
improvement would be tried. Where voltage variations
exceed the range of normal corrective transformer tap
change, supplementary VAR generation and control would
be applied. Where circuit and transformer thermal
limits are about to be exceeaed, additional elements
would be scheduled.
(f) Power Delivery Points
For study purposes, it will be assumed that when Susitna
generation is fully developed (i.e., to 1,620 MW), the
total output will be delivered to terminal stations as
follows.
-Fairbanks -one station at ~ster with transformation
from EHV to 138 kV.
-Anchorage -one or two stations with transformation
from EHV to 230 kV or 138 kV for CEA and
115-kV supplies to MEA and MAL&P.
The provision of intermediate switching stations along
the route may prove to be economic and essential for
stability and operating flexibility. Utilization of
these switching stations for tne supply of local load
will be examined, but security of supply to Anchorage
and Fairbanks will be given priority consideration.
2-4
3 -ELECTRIC SYSTEM ANALYSES
3.1 -System Configuration
The selected system configuration consists entirely of 345-kV
ac transmission circuits as detailed below
Line Section
Watana to
Devil Canyon
26
Devil Canyon
to Fairbanks
195
Devil Canyon
to Willow
Willow to
Knik Arm
K n i k Ar rn
Crossing*
Knik Arm to
University
Substation
*Submarine Cable
84
40
4
18
Number of
Circuits
2
2
3
3
3
3-1
Voltage
t k v )
345
345
345
345
345
345
Number
and
Size of
Conductors
2 X 954
2 X 9 54
2 X 954
2 X 954
1 X 20Q(J
2 X 1351
The system single-line diagram, giving the line configuration
and switching station arrangements is shown in Figure 1.
This drawing also gives the staging of transmission circuits
and terminal equipment from the initial to the ultimate
installation.
The system impedance diagram is given in Figure 2, with all
impedances and line charging expressed in per unit on 100 MVA
base. The ratings of generators, transformers, reactors and
dynamic VAR sources are given in MW, and MVA. All ratings
given are for the ultimate Susitna development. Generation
that is assumed to be running in the Anchorage area includes
sufficient spinning reserve to cover the loss of the largest
unit at Susitna. Ratings of all VAR equipment were
determined in the studies of line energizing, load flow, and
transient stability. The results of these studies are
discussed in the following subsections.
3.2 -Transmission Line Energizing
Line energizing studies were carried out to ensure that
voltage rises and VAR flows were within acceptable limits at
each stage of development. The results of these studies are
summarized in Table 1 and they give rise to the following
conclusions.
-Devil Canxon -Fairbanks
This line section is 195 mi in length and a 75 MVAR reactor
is required on the Fairbanks end o each circuit or line
energ1z1ng. In the early years, even with the reactor in
place, the system voltage should be reduced to 90 percent
beore energizing the line. Althoug~ this is a line reactor
normally switched with the line, it is proposed to provide
reactor switching as well so it may be removed if necessary
3-2
be removed if necessary during emergency heavy line loading
conditions. This is regarded as an economic alternative to
the provision of an additional 75 MVAR of VAR generation at
airbanks.
-Devil Canyon -Willow
This line section is 84 mi in length and it can be switchea
with no line reactor. As in the case of the Fairbanks
1 ine, the voltage at Devil Canyon shoula be reauced before
energizing the line.
-Willow -Anchorage
This is a short secton, comprising 40 m of overhead line
plus 4 mi of submarine cable at the receiving end of the
section. The shunt capacitance associated with the
submarine cable has an adverse efect on lne energizing
voltages and a line reactor is needed on the Anchorage end
of each cable section. A reactor size of 30 MVAR is
sufficent to control energizing voltages. In addition, in
the early years it is necessary to reduce the system
voltage at Willow down to 9c percent o normal before line
energizng.
Line energizing must be done with reasonable care n the
early years while short circut levels are low. System
voltages need to be reduced as low as possible before
swtching is done in order to minimize the overvoltage
resulting from line pick-up. Even when tnis is done, the
overvoltage resulting at the sending end is seen by all
parts of the system that are connected at that time. The
situation improves as installed generation and short
circuit levels increase, but in the initial years, since
3-3
line switching will result in noticeable voltage
fluctuations, it is expected that line switching operations
would be carried out as infrequently as possible.
3.3 -Load Flows
A number of load flows were simulated to ensure that
equipment ratings were adequate to cover the range of
operating ~onditions that could be anticipated. The load
flow diagrams are given in Figures 3 to 11 and Table 2 gives
an index to these flows along with significant data regarding
bus voltages and required VAR support at each load bus.
In summary, the conditions examined were
-initial light load conditions with two circuits to
Anchorage and two circuits to airbanks
-intermediate peak load conditions, with 1,020 MW of
generation at Susitna, before commissioning the thira
circuit to Anchorage
-ultimate maximum output from Susitna at 1,~17 MW with a
range of load distributions, namely
(a) 85 percent of Susitna output transm1ttea to Anchorage
(i) system normal
(ii) emergency outage of one line section between
Devil Canyon and Willow
(b) 25 percent of Susitna output transmitted to Fairbanks
(i) system normal
(ii) emergency outage of one circuit between Devil
Canyon and Fairbanks
3-4
(c) Susitna output transmitted 80/20 percent to Anchorage/
Fairbanks load centers, with system normal
-the expected maximum output from Susitna at 1,668 MW with
extreme ranges of load distributions, i.e.
(a) 85 percent of output to Anchorage, 15 percent to
Fairbanks
(iJ system normal
(ii) emergency outage of one circuit between Uevil
Canyon and Willow
(b) 75 percent of output to Anchorage, 25 percent to
Fairbanks
(iJ system normal
(ii) emergency outage of one circuit between Uevil
Canyon and Fairbanks.
In general, the load flows demonstrate that the transmission
system is capable of handling the full range of steady state
conditions that are considered possible at this stage of
planning. Added to the uncertainty of the load split between
Anchorage and airbanks (ranging from 85/15 percent to
75/25 percent) is the possibility that an additional
15 percent will be availaole at Susitna because o favorable
hydraulic conditions. All of these extreme cases have been
simulated and all are within the system capability with
single contingency outages. In three of the extreme cases,
the required VAR support at the load centers results in
transformer loadings in excess of the nominal rating of the
tertiary windings. This is not considered serious as tnese
are extreme situations which could be anticipated in time to
arrange for the addition to VAK support as needed in the
subtransmission system.
3-5
In order to get a check on the static VAR controller (SVC)
ratings needed to meet system voltage requirements, two
additional emergency cases were run with Suitna generating to
its normal (Nameplate) maximum. These cases have been shown
on Table~. and the required continuous VAR output at all
three locations is within the nominal rating of the
transformer tertiary windings.
3.4 -Transient Stability Studies
A series of transient stability studies were carried out to
confirm system recovery following the design fault and fault
clearing.* These studies examined the system operating at
the full nameplate rating of 1,668 MW and also at 15 percent
additional output (1,917 MW) which may be possible under
favorable hydraulic conditions. The studies considered the
expected 80/20 percent load distribution between Anchorage
and Fairbanks and also the extreme cases of 85/15 percent and
75/25 percent. Since, at this stage of planning, generation
inertia constants are not known, the studies included a range
of 11 H11 constants (3.0, 3.5, 4.0) that would be appropriate
for the generator sizes and speeds being considered.
An additional factor which is significant to stability is
unknown at this time. This is the character of the load
that will be experienced at botn load centers wnen the
system approaches the design loading in the early 2000 1 s.
It is assumed that at the peak period heating and lighting
(constant impedance or static loads) would account for most
*The design fault is a 3-phase fault, cleared in 80 MS by the
local breaker and in 100 MW by the remote circuit breaker.
3-6
of the system load, followed by rotational load lconstant
MVA, or dynamic) and synchronous load in decreasing order of
importance.
The· transient stability runs which are presented in this
report are summarized in Table 3. The table shows the range
of system parameters that were examined in the runs and it
also lists the extreme values of static VAR controller
outputs that were encountered throughout the transient swing.
The latter are used as an indication of the transient VAR
capability that is needed to ensure stable operation.
Swing curves are shown in Figures 12 to 19 inclusive, and the
conclusions from these curves and from other runs as well are
discussed below. The system is considered to be transiently
stable if it survives the first swing. It is assumed that
damping provided by properly adjusted control elements would
control subsequent oscillations except in the case of
synchronous motor loads which are not a significant portion
of the total load.
At the ultimate maximum Susitna output of 1,917 MW, swing
curves, Figures 12, 13, 14 and 15 illustrate conditions that
are judged as being stable. Generally speaking, as the
character of the loads is changed from 80 percent static and
20 percent dynamic to 60 percent static and 40 percent
dynamic, a higher inertia constant is needed to ensure stable
operations. When the inertia (H) constants are reduced to
3.0 the system is unstable even for 100 percent static load
representation.
At the nameplate maximum Susitna output of 1,668 MW, tne
system performance is illustrated in 4 swing curves,
Figures 16, 17, 18 and 19. As the swing curves show the
system is stable for all extremes of load distribution and
3-7
for inertia constants down to 3.0 and dynamic load components
as high as 40 percent. In two of the swing curves {18 and
19), where part of the dynamic load has been represented as
synchronous load, the synchronous motors have been shown on
the curves. The behavior of these synchronous machines, with
their lower 11 H11 constant is classic, and they would very
likely lose synchronism eventually, following the severe
disturbances represented. This is to be expected, and it is
not counted as a system failure.
In the summary of system stability runs in Table 3, peak
values of transient output from the static VA~ controllers
havB been listed. These are used in the following section to
establish transient VAR ratings that should be specified for
this equipment.
3-8
4 -CONCLUSIONS
On the basis of the electric system studies that have been
carried out, it is concluded that the basic system
configuration as arrived at in the preliminary system
analysis will provide satisfactory system operation for the
expected maximum Susitna output.
System transient performance is enhanced by a higher
generation 11 H11 constant and values in the range 3.5 to 4.0
are preferred. These should be done to the "natural" value
for machines of this size and speed.
VAR control equipment which 1s required at Anchorage and
Fairbanks load centers is given continuous and short-time
ratings as determined by the energizing, load flow, and
transient stability studies. These ratings are summarized
below, along with a reference to the table in which each
limiting rating was established.
location
Fairbanks
Line Reactor
svc
Anchorage
line Reactor
s vc
s vc
Equipment ~ating (MVAR)
Rating
Voltage No Continuous
(lvlax/tvlin)
345 kV 2x 75
138 kV 1x +200/-100
345 kV 3x 30
230 kV 2x +150/-75
115 kV 1x +200/-75
4-1
Short Time
(l'~ax/il1in)
+300/-100
+200/-75
+300/-75
~eference
Table
1
2.4
1
2.4
2.4
The recommended configuration and system component ratings
are considered adequate to handle the magnitude and type of
loads that are envisaged at this time. At later stages of
project design and implementation, system requirements will
be better defined, and component ratings should be confirmed
by further study.
4-2
5 -SUPPLEMENTARY STUDIES
ENERGY MANAGEMENT SYSTEM (EMS)
The introduction of Susitna hydroelectric power in the
R.ailbelt area will require several hundred miles of
transmission lines from the Susitna River basin to An~horage
and Fairbanks. In fact, the ultimate development will
require approximately 850 mi of transmission, 5 switchyards
and 2 hydro generating stations at Watana and Devil Canyon.
To operate such an enlarged Railbelt system, a control system
or energy management system (eMS) will be required.
Studies were conducted by Energy & Control Consultants to
determine the system requirements for the EMS control center.
The report was prepared jointly with Acres and is appended in
i t s e n t i r e t y a s ATTACH~,1ENT 1 -to t h i s do c u me n t .
5-l
TABLE 1 : TRANSMISSION LINE ENERGIZING
Sending End
Line Sect lon Short Receiving
Being Length L1ne Wa tan a Ci rcu.lt Init.ial Final Voltage Line End
Energ1zed O.H.Line Cable Reactors Generation Level Voltage Volta!i]e Rise Flow Voltage
( ml) (mi) (MVAR) (MW) (MVA) (/un lt) (/unit) (/un lt) (MVAR) (/unit)
Devil Canyon 195 0 170 496 0.900 1. 250 0.350 267 I. 356
-Fairbanks 75 170 496 0.900 1. 0 54 0. I 54 99 1 • 06 I
75 340 931 0.950 1.040 0.090 97 I. 04 7
75 680 I, 6 59 0.950 0.999 0.049 89 I. 00 5
75 1 '020 2,246 0.950 0.985 0,035 87 0.992
Dev ll Canyon 84 0 170 496 0.900 1. 0 17 0. I I 7 73 1.033
-will ow 0 340 931 0.950 1 • 0 2 0 0.070 73 I. 03 5
0 680 I, 6 59 0.950 0.988 0.038 69 I. 003
0 I, 020 2,246 1.000 'I. 0 3 2 0.032 75 1. 048
Wlllow 40 4 u 170 410 0.920 1 . I 6 3 0. 24 3 I 37 I. 186
30 170 410 o. 920 I. 07 6 0. 156 82 1. 090
30 340 668 0.950 I. 0 50 0. I 00 78 I. 06 3
30 680 976 0.950 I. 0 16 0.066 73 I. 02 9
30 I, 0 2 0 I. 1 53 0.950 I. 00 5 0.055 7 I I. 0 I 8
TABLE 2: SYSTEM LOAD FLOWS
Load Susitna Assumed Load Load Bus VAR
Flow Load Generated Distribut1on System Generat1on
Figure Year Outeut Anchorage Fairbanks Cond1t1on Anchorage Fa1rbanks Comments
(MW) PO (~0 ( 2 30 kV) ( I I 5 kV)
3 1993 85 80 20 Normal -150 -6) -90 Initial Condit ions
W.lth m.1n.1rnum
generation
4 19 97 1 t 0 20 80 20 Normal 140 48 40 Intermed.1ate
cond.1tion -maximum
1 oad with 2 c 1rcuit s
to Anchorage
5 I, 917 85 1 5 Normal 177 195* 4) Ultimate maximum
generation -full
system -85 pel'Cent
to Anchorage
6 1 '917 85 1) Emergency 293 220* 87 Ultimate maximum
generation -
emergency outage
Dev 11 Canyon -W.1llow
*Ind.lcated VAR generat.1on exceeds the nominal rating of the transformer tert.1ary w.1nd1ng.
Table 2
System Load flows -2
load Susitna Assumed Load load Bus VAR
flow Load Generated Distribut~on System Generat~on
f ~gure Year Outeut Anchorage fairbanks Cond lt ion Anchorage f a~rbanks Comments
(MW) (~0 UO) ( 2 30 kV) ( 1 1 5 k v)
7 1,917 75 25 Normal 146 1 29 79 Ult~mate maximum
generation -full
system -25 percent
to fa~rbanks
8 1. 917 75 25 Emergency 158 134 310* Ultimate maximum
generation -
emergency out age
Devil Canyon -
fa~rbanks
9 I, 917 80 20 Normal "177 137 66 UltImate maximum
generat~on -full
system -80/20
percent load sp 1 ~t
10 1,668 85 15 Normal 146 100 25 Nominal maximum
generat~on -full
system -85/15
percent load split
Table 2
System Load Flows -3
Load Sus J.t na Assumed Load Load Bus YAH
flow Load Generated Distribul1.on System GeneratJ.on
Figure Year Outeut Anchorage fair banks Condition Anchor age Fairbanks Comments
(MW) on (%) (230 kV) ( I I 5 k v)
I, 668 05 1 5 Emergency 199 130 39 Nominal maximum
generation -
emergency outage
Dev 11 Canyon
Willow
11 I, 668 75 25 Normal I I 6 54 70 Nominal maximum
generation -full
system -75/25
percent load split
I, 668 75 25 Emergency I 16 61 200 Nominal maximum
generation -
emergency outage
Dev ll Canyon -
Falfbanks
TABL£ 3: TRANSIENT STABILITY RUNS
Fault at Oevd*
Canyon 34 5 kV
Load Base Load Characterist1cs Hydro Bus -Circuit
Sustina D1str ibut wn Load Constant Constant "H" Swing Cleared From
Outeut Anchorage Fairbanks Flow lm~edance MW and MVAR S~nchronous Constant Curves Devil Can~on to -
(MW) (~0 (~.;) (Figure) (%) (%) (%) (Figure)
I, 917 85 15 5 80 20 3.5 12 Willow
1 '917 80 20 9 70 30 3.5 13 Willow
1' 917 80 20 9 60 40 4.0 14 W1llow
I, 917 80 20 9 60 40 4.0 15 Faubanks
I ,668 85 15 10 60 40 3.0 16 Willow
I ,668 85 15 10 60 40 3.5 17 W1llow
I ,668 as 15 10 60 30 10 3.5 18 W1llow
I ,668 75 25 II 60 30 10 .3. 5 19 F aubanks
*The design fault 1s a 3-phase fault, cleared by the local breaker 1n 80 ms and by the remote breaker 1n 100 ms.
TABLE 4 -VAR GENERATION Dli.RING TRANSIENT SWINGS
Swing* Transient VAR limits
Curve Anchorage
F ~sure 230 kV 11 ~ kV F a~rbanks
(Max) Ohn) (Max) (M~n) (Max) (Min)
1 2 +372 -26 +281 -31 +20~ -43
1 3 +348 -26 +271 -3 2 +2 1 1 -4 3
14 +331 -21 +2~9 -26 +302 -37
1 ~ +224 -38 +174 -38 +213 +7 4
16 +2~7 -8 +197 - 1 ~ +132 -28
17 +222 -2 +171 -9 +1 14 -2 2
18 +328 -63 +266 -~~ +187 -63
1 9 +264 -46 +200 -4~ +300 +48
*Deta~ls of transient stabil~ty runs are given ~n Table 3.
.--1
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RAILBELT 345 KV TRANSMISSION SYSTEM SINGLE LINE DIAGRAM
ESTER
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STAGING LEGEND
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0
:1:., -,60
i ~~
I() 6
en , " -<Il
"' ~
0
" "'
.... ...
"'
500
<D
"' 0
6
" X
MVA
SVC + 200/-75 CONTiNUOUS
+ 300/-75 SHORT TIME
-..j...-...(702 115 KV
AMLP
BRADLEY LAKE
1303 MVA
...
i\i
"' "'
CD
"' 0 ::;:0
~~
it
"' 0
0
0
0::
345 KV
IMPEDANCE D~GRAM
162 MW
~ 138 KV
ESTER
LEGEND
'345 KV e
svc
NOTES
+ 200/-100 CONTINUOUS + 300/-100 SHORT TIME
GEt<ERATOR
TRANSFORMER (2 WINC:NG)
TRANSFORMER ( 3 WiND I >.!G )
REACTOR
9US iDENTIFICATION NUMBER
STATIC VAR. COMPIONSATOR
ALL IMPEDANCES AND LINE CHARG lNG
ARE IN :PER UNIT ON 100 MVA BASE.
SVC RATINGS ARE IN MVAR .
fi(;URE 2
L-------------------~---------------------~~------~--~~-------------
345 KV
WILLOW
387
0. 95 L::£.!.
:1 ~g f I-
KNlK
ARM
I Z.O 20.0 ---
12.0 20.0 ...,_-
348 345 KV
0.97l=.2:.!_
748 115 KV
1.00~
----r-'-----;,....-..L.---,.---{301 345 KV
UNIVERSLTY
svc ot ~:; CEA ~ ye AMLP
_,.---1.:.;;---..(201 230 KV --l--.....(702 115 KV
~t ii ~~ t~
1.00~
it +~ N. ·~ ~• t-~ gj ~ . t~ 1::: "'' Nl ,:
~t t~ DEVIL ~t h
CANYON I~
;t t~ WATANA ~t f~
-.J..:...--.,...---&.:..--o(391 34 5 KV
1.04~
LOAD FLOW DIAGRAM
"' 138 KV
1.01 L::U
.STER
LEGEND
345 KV GENERATOR
t.04l£d_ 0'YY"Y"'\ TRANSFORMER (2. WINDING I
~ 7RANSF'ORMER {3 WINDING)
NOTES
SUSITNA GENERANON = 85 MW
400 ---
1.01~
svc
LOAD DISTRIBUTION = ANCHORAGE 80%
FAIRBANKS 2.0%
LIGHT LOAD -NORMAL ( 1993 )
REACTOR
POWER FLOW ( MW )
VAR ·FLOW
BUS VOLTAGE ( PE.R UNIT )
AND ANGLE (DEGREES)
BUS IDENTIFICATION N!JMBER
STATIC VAR COMPENSATOR
FIGURE 3m
387'J--""'"l•
1.01~
~+ l;\
~~ I~
·-
~+ ttJ
~· t~
~f
KNIK ~I +!
ARM ' '
~~ ttJ
UNIVERSITY
-------345--f<v-~--~--------~
w I LLOW ~ ro1 LH.
3S4 400
~--....----
345 KV
~· +·S! .I 'f 115 KV
i.OOL..L!__ ~t +N DEVIL
.~ CANYO"J
301 345 KV
2t t~ LOI~
• lo ~~ ,-
~J ~: lw .~
~t t::: WAT ANA ~t t: ~
CEA it f~ AMLP
....,..----T-----{201 '230 KV 702 115 KV
~t h ~~ t! 097~ 2t t:. "'0~~
---~-·-----·-~--'-
• t: <:.il
391 345 KV
~;
'Wei'
-~ _,_
~I ~f
,.
1.00~
~STER
LEGEND
345 KV
1.03t....!.!:Q_
NOTES
SUSITNA GENERAT'!.ON = 1020 MW
LOAD DISTRIBUTIOI\I = -ANCHORAGE
FAIR!lAN~S
e
406
~
10 ~
1.01~
svc
80%
20%
PEAK LOAD FL.OW NORMAL ( 1997 )
LOAD FLOW DIAGRAM
-· ------l
GENERATOR
TRANSfORMER {2 WlN-DlNG)
TRANSFORMER { 3 WINDiNG )
REACTOR
POWER FLOW ( MW )
VAR ·FLOW
BUS VOLTAGE (PER UN•T )
AND ANGLE (DEGREES)
BUS IDENTIFICATION NUM8ER ·
STATIC VAR COMPEl'< SA TOR
r-1
FIGURE 4
1 A~~~ I
;:'I
"t
CEA ~· ~t +o t:£ e Nt
345 KV
WILLOW ,~ oo1~
~~ J~ KNiK ~[ -Lt-.~
wT T ARM ~, t~
gl f of '~ "t
:g. ~~
1 .. f• UNIVERSITY :t
l!? AMLP
201 230 KV
t~ • ~0 : l .:-I.ODLQ&_ ~t
!.05U,L r.osli..i._
BRADLEY LAKE
469" ~21 ------
469 ---
lo
521 ----
301
r 0.95~
702
.J-:. ,-0.98~
345 KV
115 KV
345 KV
115 KV
~t :;,
N.
~~
.,t
:llr
' .... ~~ ' ' J +~ :m ~· .j.m
Tm :<I :ll lm ~I ,~
~~ Nt t~ DEVIL
CANYON ::,
t WATANA :::t .L
I ~I I~
391 345 KV
1.03~
LOAD FLOW DIAGRAM
r.oo~
E:STER
345 K\
l.04l!!:.!_
NDTES
LEGEND
e
406 -
1.01~
svc
SUSITNA GENERATION= 1917 r,IW
LOAD DISTRIBUTION : ANCHORAGE 8 5 %
FMRBANKS 15 %
PEAK LOAD FLOW -NORMAL
GENERATOR
TRANSFORMER (2 WIN!JI"G)
TRANSFORMER (3 WI'IDING)
REACTOR
POWER FLOW ( MW )
VAR FLOW
BUS VOLTAGE (PER UNIT )
AND ANGLE (DEGREES )
BUS IDENTIFICATION 'lUMBER
STATIC VAR COMPENSATOR
-----------·--· ------------------------~------------------------~-"-'-345 KV
WILLOW ~ o.9zUll
.~ ...i!!-2-
---++--+-
II 17
••• -
~
345 KV
, ..
~
-~ 57 >07 __.. --~ 37
~f ~ zo
_, I ;)• r· KNiK
ARM
*t }:; UNIVERSITY
1.04~
•• -4--
I.OSL__!L
BRADLEY LAKE
0.99l!__Q:.!_
LOAD FLOW D !A GRAM
LOOL...!.!!.
ESTER
LEGEND
NOTES
SUSrfNA GENERATtbN: 1917 MW
e
406
~
1.01 L..!.:..!
svc
LOAD DISTRIBUTION : .ANCHORAGE 85%
l'AIRBANKS I 5%
PEAK LOAD FLOW -EMERGENCY
GENERATOR
TRANSFORMER (2 WINDING)
TRANSFORMER (3 WINDING)
REACTOR
POWER FLOW ( MW )
VIIR FLOW
BUS VOLTAGE (PER UNIT )
AND ANGLE (DEGREES )
BUS IDENTIFICATION NUMBER
STATIC VAR COMPENSATOR
CIRCUIT OUTAGE
(CIRCUIT OUTAGE-DEVIl CANYON TO WILLOW )
r=:l
FiGURE 6 1Aum 1
ol '~ ~' ~~ +~ ' '
~t t~
~J t~
rYY>
KNiK
ARM
UNIVERSITY
J.D4Ll.?_
., -
er lc ~, ,~
~~ :; j.o tm
3L5 K\/
WILLOW til o•• LI_U>
n
~+
407
-4-
--+-6
407 ...,._
407
------
453 -
... -
348 345 KV
115 KV
301 345 KV
lm .,.. 0.98~
BRADLEY LAKE
_.1 .. ,
~l t~
~t .1 t:
.. t
:li[ 4~
:1 • A' A .. t~ i! l~~ E!
DEVIL ' 1~ CANYON ~I 1 ..
;t i~ "" WATANA ,~
391 345 KV
;j 1..03l_E&
LOAD FLOW DIAGRAM
LEGEND
.345 K\ 8
(YYYY'I
rvy-y-,
ryyy'"\
..flTL
406 _______.
10
--++-
svc
NOTES
SUSITNA GENERAT!~ .o 1917 MW
:.'',
LOAD DISTRIBUTION.~. ANCHORAGE 75 %
FAIRBANKS 25 %
:~.;-;
PEAK LOAD FLOW ";;NOR MAL
GENERATOR
TRANSFORMER ( 2 W!ND!NG )
TRANSFORMER (3 WINDING)
REACTOR
POWER FLOW ( MW)
VAR FLOW
BUS VOLTAGE (PER UNIT )
AND ANGLE (DEGREES )
BUS IDENT!F\CAT!ON NUMBER
STATIC VAR COMPENSATOR
:g!,! .. KN!K ~~l .. ~t. t" ARM ~r t"
34-5 KV
--1•
20
401 -.. , --
345 KV
115 KV
-----...t..----r---(301 345 KV
UNIVERSITY
AMLP
i + 201 230 KV -;-,+
1
-
2
--(702 I I 5 KV
.!j t~ 1.00 tJLQ__ ,0' ., r• Q.99~
1_05~
•• -
... ...
N
1.05~
BRADLEY LAKE LOAD FLOW DIAGRAM
.345 KV e
("YYYY\
406 --10
--HO-"
J.OI~
NOTts·
SUSITNA GENERATION: lSI? MW
LOAD DISTRIBUTION :· ANCHORAG.E
~ ,; ' .
FAIRBANKS
PEAK LOAD F.LOW -EMERGENCY
svc
.$
75 °/o
25%
GENERAiOR
TRANSFORMER ( 2 WINDING )
TRA~SFORMER (3 WINDING I
REACTOR
POWER FLOW ( MW )
VAR ·FLOW
BUS VOLTAGE (PER UNIT )
AND ANGLE (DEGREES )
BUS IDENTIFICATION NlNBER
STATIC VAR COMPENSATOR
CiRCUIT OUTAGE
(CIRCUIT OUTAGE li'c.DEV.IL CANYON TO ESTER )
j4~ ':<.V
\Vl [_LOV\1 i'i' o.g.g.~_r__u~
438 4Se --r----------------~ "*+-
0 21
4~8 488
~ ~----------------,
o.99GL
345 I<V
115 KV
! 4 :tit~
i. I ~~ + ..
'
----.,...--IL-.-------..1..---..,..---: 301 345 KV
UNIVERSITY s.l +s: '"'t , .. 0.9BU2__
~· 4
~I -'-" ~· ~-
0.99L=..!:_~
BRADLEY LAKE
~+:1N _i. ' i.
~i ..;..~ §J :i 'l.n I
DEVIL ~t t~
CANYON ' )
"'
. ~-' ...
WATANA ::I "-~ ;-
391
.f.
1.o4 L2e.1
891
~t 4 1.04l~"" , ..
TOi
'""
LOAD FLOW DIAGRAM
"u
345 KV
ESTER
345 KV 8 GENERATOR
(Yf""YY\ TRtcNSFDRMER 12 W 1N::>:"'G)
~ TRANSFCR.II.ER { 3 w;~DtNG)
10 --c--.
!.DJ L:....!
svc
NOTES
SUSiTNA GENERATIQ:N = 19 17 MW
LOAD OISTRIBUTIOfi~'~ ANCHORAGE 80 %
!{'·,.fAIRBANKS 20 %
PEAK LOAD FLOW!JC NORMAL
REACTOR
PCWE" ~"LOW ( "'W )
VAR FLOW
BUS VO~TAGE (PER UNiT
AND ANGLE (DEGREES)
BUS lDENTJFiCATtON NUMbER
STATIC VAR COMPENSATOR
138 KV
097~ ;T.Lr.L~ -I'¢ T + T !.DOLL!>_
345 KV
115 KV
BRADLEY LAKE LOAD FLOW DIAGRAM
~---
345 KV
NOTES
1-00~~
ESTER
LEGENU
8
40. -10 --;--
1.01~
svc
SUSITNA LOAD GENERAt;i(JN ' I 6S8
DISTRIBUTIC)N MW ' ANCHORAGE 8 5 %
FAlR8ANKS ! 5 o/o
PEAK LOAD FLowC NORMAL
TRAI\SF'2.HW.£R
TRANSFORMER
R~ ACTOR
POWER FLOW
VAR FLOW
(2. Wl"lDING}
( 3 WIN~ING)
MW)
SUS VOLTAGE ' A~D ANGLE ( ~ PE~ UJ\l1T ) o~GRc.ES)
' .... NUMBER BUS IDENTIFICATI,~N '
STATIC VAR COMPENSATOR
FIGURE
I.OOL§...2._
I I' ~.I.~ ;;' P'
;!,[ lm ,, ,~
KNiK
ARM
345 r<V
WIL_LOW ~~ i.OILLQ.,]
396 -,------1--------·-·
...-r-• •·+-..
!..!!_.,..
~·. !38KV ~ ~I !h LOIL.£.5
·~
I
3<8
0.93~
748
l.OOL~
'f -
345 KV
~~
~· 115 KV
~· ~I
•• • ;l 1 • d ~~~~~ ~l l.m t-i-N]
~~ DEVIL ~· ~~ CANYON ~I '
----...... ...!.--------J...---.,...--{301 34 5 KV
~I +~ wT ,-UNIVERSITY ~ ~ i~ o ••Ui
_., 1 • l
~ WATANA -':! , .. ;;I ,.. , •.
....1!.:..---,....----1..:~--<('39! 345 KV
.i 1.04~
CEA *~ l:i: AMLP ·-• A ! 201 230 KV 702 115 KV
~I 1~ ~~ -1-e ~t t:.;r.oo~ ~t lN 1.00~
I~ 'N t=
1.04~
BRADLEY LAKE LOAD FLOW DIAGRAM
;:; 138 KV
STER
LESENC'
345 KV e GENERATOR
rYYYY'> TRA"--SFORMER I 2 W!ND'NG l
r-rYY\
rn'V'\ TRANSFORMER (o Wli<D!NG)
--"'T\-REACTOR
•o• POWER FLOW ( MW) _...
10 VAR FLOW -1.01~ BUS VOLTAGE (PER UNIT )
AND ANGLE (DEGREES}
® BUS IDENTIFICATION NUMBER
svc STATIC VAR COMP~NSATOR
NOTES
SUSITNA GENERA-ICN' I 558 MW
LOAD OiSTR~BUTION :. ANCHORAGE 75 °/0
FAIRBANKS 25 %
PEAK LOAD FLOW NORMAL
SUSITNA GENERATION: 1,917 MW, H = 3.5 sec
LOAD DISTRIBUTION: ANCHORAGE 85%
LOAD CHARACTERISTIC: STATIC 80%
BASE LOAD fLOW: FIGURE 5
FAIRBANKS 15%
DYNAMIC 20%
FAULT LOCA~ION: DEVIL CANYON, 345 kV
CIRCUIT CLEARED: O~VIL CANYON TO WILLOW
0 ;-,,... " • '.)-..J V•
0
0o
~n N
u
_._j
<Co
~ l:t
f-ci 0;:::
LIJ z
1---f .:,.)
D
0
f-N
0;::
3 0
()
ll.J 0
_._j..,.
(.!>
2:
<(
()
0;::0
oc;
1-· "' <( i
0;::
Wo
Zo
~ (~
UJ
I
0. 8: .... r•
LEGEND•
iO
iJ
C.2:) r }0 C."-0 c. so <j.
f' 1''1 •.J •.... u ·J. j(J ~.110 c. so
<:;TUDY T
ANCHORAGE GENERATION
BRADLFY LAKE GEN
WATANA GENERATION
DEVIL CANYON GEN
i M[
SYNCI:IRONOUS 0%
c.r-..o 0.70
0. FlO Q.7G
(SECSl
o.to
0.80
TRANSIENT STABILITY SWING CURVES
G.YD I .oo
0
()
()
N
0
0
C)
0
L:l
0
('J
I
0
0
0 ..,.
I
0
0
C)
"' '
0
()
0
-tO
' Q,q8 I or· . v
FIGURE 12
SUSITNA GENERATION: I , 91 7 MW, H ~ 3. 5 sec
LOAD DISTRI.BUTION: ANCHORAGE 80% FAIRBANKS 20%
LOAD CHARACTERISTIC: STATIC 70% DYNAMIC 30%
BASE LOAD FLOW: FIGURE 9
FAULT LOCATION: DEVIL CANYON 345 kV
CIRCUIT CLEARED: DEVIL CANYON TO WILLOW
O.G~ 8. I 0 ,.... 'j"\
'.I.'-•J C-30 ::L 40 o.~o
·o
.;_) L)
c)o r•
0
_j
~(.)
t'--"-10
~ c;
w z
...-D
0
•C)
1-~.i
0:::
30
() ~' W c)
_j'7
(.')'
z
<(
() o:::o ~~ 0 c)
>--({)
<(o
0:::
Wo :zo
LLJ •
L')~
I Q.OG !J, I 0 0.2;'J G.JO G. 4Q (,.SO
L[GEND:
STUDY TIME
ANCHORAGE GENERATION
BRADLEY LAKE G[N
WATANA GENERATION
DEVIL CANYON GfN
SYNCHRONOUS 0%
C.f>C o. 10 o.&o
o.so c. 70 0.1)1)
(SECSl
TRANSIENT STABILITY SWING CURVES
0.90 i .oo
()
{)
0
"'
<>
0
C)
()
()
0
"' I
0
0
C)
'7
I
0
()
()
({)
()
()
()
(Q
I ·c. -~8 i .co
FIGURE I~
SUSITNA GENERATION: I, 917 MW, H = 4.0 sec
LOAD DISTRIBUTION: ANCHORAGE 80% FAIRBANKS 20%
LOAD CHARACTERISTIC: STATIC 60% DYNAMIC 40%
BASE LOAD FLOW: FIGURE 9
FAULT LOCATION: DEVIl CANYON 345 kV
CIRCUIT CLEARED: DEVIL CANYON TO WILLOW
o.oc Q. tO G.JJ c. 30 ,, 40 c. so
. ()
C) L,
on r-,J
u
__l
<.o
~o
~ c~
w z -()
L)
'" C)
1-('J
•
0::
:30
0
w c)
_,J"
0 z
<
0 n::::o
0 c.i
I-IV
<t:•
0::
Wo
Zo
l.:.J \.'} ii
I o. OC; .G. i .;
U~GEND: [']
Q)
'i!.
+
a.~J (,.30 r 4Q G.SO
STUDY TIME
ANCHORAG[ GENERATION
Eif~ADLFY LAKE GEN
WATANA GENERATION
DEVIL CANYON GFN
SYtlCHRONOUS 0%
r, F,C Q,1'Q 0.€0 'J •
O.F,C G. 7 0 Q.BO
<SECSl
TRANSIENT STABILITY SWING CURVES
c.·.):) LOG
()
t)
Cl
~,
0
0
()
()
0
CJ
('J
I
C)
L)'
0
" I
()
(J
0
<£!
'
{)
(>
.:_,
.(()
' C.:)8 I ,Q(j
FIGURE 14
SUSITNA GENERATION: I, 91 7 MW, H = 4.0 sec
LOAD .DISTRIBUTION: ANCHORAGE 80% FAIRBANKS 20%
LOAD CHARACTERISTIC: STATIC 60% DYNAMIC 40%
BASE LOAD FLOW: FIGURE 9
FAULT LOCATION:
CIRCUIT CLEARED:
L') o.o::; c. i 0
0 .o
u <?
()
__JN
4:
1-
0::: wo :z~
~c'
1-o
• 'J
0:::
• C:)
3~J
UJ
__J .J cni:") ;z.
4: Cj .,.
0:::
0 .-o
<':
0::: Cl LU'f
~ (LOG
'-')
L[GENO:
DEVIL CANYON 345 kV
DEVIL CANYON TO FAIRBANKS
C.-:!0 G.JO 8.40 c. ~Jo
Q. 40 G.~o
STUDY TIM[
ANCH8RAGE GENERATION
BRADLFY LAKE (;[N
WATANA GENERATION
DEVIL CANYON GFN
SYNCHRONOUS 0%
0. F)C 0.70
O.f)C D. 7 0
<SECSJ
TRANSIENT STABILITY SWING CURVES
o.tc c. ·~a i .oo
()
·~ Q
a
"'
0
()
()
0
()
0
<'J
I
0
Cl
0 ..,.
I
0
()
0
U)
I
0.60 G.:.jC: l. 00
FIGURE 15
SUSITNA GENERATION: 1 '668 MW, H ; 3.0 sec
LOAD DISTRIBUTION: ANCHORAGE 85% FAIRBANKS 15%
LOAD CHARACTERISTIC: STATIC 60% DYNAMIC 40%
BASE LOAD FLOW:
FAULT LOCATION:
CIRCUIT CLEARED:
~:C. QG 0. I 0
C) 0 ·"' 0
u
()
<)
_J •
<(O
f-
0::
Wo zo
~o -I
f-
O::o
.()
3 (.;
I")
UJ I
_J
0
Zo <Co
a:::;
01
f-
<( u:g w. za
w';-
<..:> o.oo 0. I 0
LEGEND:
FIGURE 10
DEVIL CANYON 34 5 kV
DEVIL CANYON TO WILLOW
t> V> v ...... u o.so 0 • .110 o. ~ .. o
c.~o C.3G C.40 {). ':0
STUDY TIME
ANCHORAGE GENERATION
9RAOU~ Y LAKE GEN
WATANA GENERATION
DEVIL CANYON GEN
SYNCHRONOUS 0%
0.60 c. 70 o.r:.o
-,------,
0.50 0.70 Q.F;O
<St:CSl
TRANSIENT STABILITY SWING CURVES
0.90 I .00 0
0
0 ,.,
()
()
0 -
()
0
0 -I
()
0
0 ,..,
I
0
()
0
11"1
I
0
0
0 ......
I 0.9G I. OG
FIGURE 16
SUSITNA GENERATION: 1,668 MW, H • 3.5 sec
LOAD DISTRIBUTION: ANCHORAGE 85% FAIRBANKS IS%
LOAD CHARACTERISTIC: STATIC 60%. DYNAMIC 40% SYNCHRONOUS 0%
BASE LOAD FLOW: FIGURE 10
FAULT LOCATION: DEVIL CANYON 345 kV
CIRCUIT CLEARED: DEVIL CANYON TO WILLO~
L)
• q) r.~ 0~~· ..IV
v• I iJ O.J:J '-' .30 c. •o
·n
(..) ~~
___J
<
~g we: z
0
0
f-
0
G ~.c 0 ,:.iC w ?G
l-.e:J.'t"
0. f,[J
"'1'' a:::"' ~ I
3
w ') ___J~
Go :z-t
..;:I
a:::/.) oo f-o
.0::10
a::: 'o "" ~ 10 w .........
z w
'-'
LEGEND:
Q.2J c.3c c. ilQ c.sc
STUDY T
~ ANCHORAGE GENERATION
~ BRADLEY LAKE GEN
& WATANA GENERATION
+ DEVIL CANYON GEN
1 ME
0. ~>C G 'G
<SE CSl
TRANSIENT STABiLiTY SWING CURVES
0 F ,, -··
r ~'J v. I nr " ....... .J
I 0
Cl
rJ
0
u
Cl
()
0
c
"'
l)
l]
"' ..,.
0
u
0
I '7'
r 0~
v ,~ I .QC
FIGURE 17
SUSITNA GENERATION: 1,668 MW, H : 3.5 sec
LOAD DIS TR I BUT I ON: ANCHORAGE 85% FAIRBANKS 15%
LOAD CHARACTERISTIC: STATIC 60% DYNAMIC 30%
BASE LOAD FLOW:
FAULT LOCATION:
CIRCUIT CLEARED:
0 o.oo G. I 0
0 .o
u~
0
..J C"J
<(
1-o
0::0 w.
z~
~I
1-o
•o
a::• .o :.d'
w
_JCJ
{!)~
:z:o
<(~
I a::
Oo
1-0 <a Q::v w-z' o. l 0 w o.oo
0
LEGEND:
FIGURE 10
DEVIL CANYON 345 kV
DEVIL CANYON TO WILLOW
o.;?O 0.30 0.40 0. r)o
o.;w 0.30 0.40 0~50
STUDY TIME
~ ANCHORAGE GENERATION
C9 BRADLEY LAKE GEN
& WATANA GENERATION
+ DEVIL CANYON GEN
X AML&P SYNCH LOAD
SYNCHRONOUS 10%
o.r.o 0.70
O.fiO o. 70
(SECSl
TRANSIENT STABILITY SWING CURVES
0.1;0 c. ·~c I .OG
0
0
0
C"J
0
0
0
"' I
0
0
0
OJ)
'
0
CJ
c)
0 -I
0
()
0 ..,. -' G.!iO c.g:J 1. oc
FIGURE 18
SUSITNA GENERATION: I, 668 MW, H : 3.5 sec
lOAD DISTRIBUTION: ANCHORAGE 75% FAIRBANKS 25%
lOAD CHARACTERISTIC: STATIC 60% DYNAMIC 30%
BASE lOAD FLOW:
fAUlT LOCATION:
CIRCUIT CLEARED:
C) o.oo o. 10
0 .o
0 c?
0
_JN
..::
1-o
0::0 w.
:;;::~
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w
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(!)C)
:zo
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I
0:: oo
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<(' .Q o:: .. w-
~ 10.oo o. 10
(.!)
LEGEND:
FIGURE II
DEVIl CANYON 345 kV
DEVIl CANYON TO FAIRBANKS
[I]
C)
~
+
X
o.~a Q,JQ c. 40 0. rJo
0.20 0.30 o. 40 0.':.0
STUDY TIME
ANCHORAGE GENERATION
BRADLEY LAKE GEN
WATANA GENERATION
DEVIL CANYON GEN
ESTER SYNCH LOAD
SYNCHRONOUS 10%
0.">0 0. 70 O.bC
O.fiO 0.70 0.80
(SECSl
TRANSIENT STABILITY SWING CURVES
0.9:1 1 .oc
0
C)
0
('J
0
0
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N
I
()
0
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I
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0
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0 .. -I 0.9:) 1. co
FIGURE 19
Prepared by.:
Energy and Control Consultants
960 Saratoga Avenue
Suite 116
San Jose, California 95129
Telephone (408) 243-5495
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT
ATIACH~1ENT 1
ENERGY MANAGEMENT SYSTEM (EMS)
SYSTEM REQUIREMENTS REPORT
TASK 8 -TRANSMISSION
December 1981
For:
Acres American Incorporated
100 Liberty Bank Building
N a i n at Co u r t
Buffalo, New York 14202
Telephone (716) 853-7252
TABLE OF CONTENTS
LIST OF FIGURES ----------------------------------------------
1 -INTRODUCTION ---------------------------------------------
1.1 -Scope----------------------------------------------
1.2-Study Objectives-----------------------------------
1. 3 -Present Ra i 1 be 1 t Po\<1er Systems --------------------·-
1.4-1984 Power System Operation------------------------
1.5 -1993 Power System Operation -------------·-----------
ii.i.
1-1
1 -1
1-1
1-1
1-2
1-2
2 -FUNCTIONAL REQUIRH4ENTS ----------------------------------2-1
2. 1 -SCADA Subsystem ------------------------------------2-2
2.2 -Generation Control Subsystem -----------------------2-4
2.3 -Power Scheduling and Load Forecasting Subsystem-----2-5
2. 4 -Energy Accounting Subsystem ---------------·---------2-6
2.5 -System Security Subsystem --------------------------2-6
2. 6 -System Support Subsystem ------------------·---------2-7
2.7-External Data Transfer and Coordination Requirements 2-8
3-RAILBELT ENERGY MANAGEMENT SYSTEM ALTERNATIVES -----------3:..1
3.1 -Alternative I -EMS System Configuration -----------3-1
3.2 -Alternative II -EMS Configuration -----------------3-6
4 -SYSTEN COMMUNICATION REQUIREMENTS -------------·-----------4-1
4.1 -Microwave System ---------------------------·--·------4-1
5 -SYSTEM SOFTWARE REQUIREMENTS ----------------·-------------5-l
6 -WILLOH CONTROL CENTER FACILITY REQUIRH1ENTS --------------6-1
6.1 -Site-----------------------------------------------6-1
6.2 -Control Center Layout ------------------------------6-1
6.3-Control Center Requirements ------------------------6-1
7 -STAFFING REQUIRU1ENTS ------------------------------------7-1
7.1 -Transmission and Generation System Operations Staff-7-1
7.2 -Computer Applications ------------------------------7-1
7.3 -Power Coordination ---------------------------------7-1
7. 4 -E~1S System Maintenance Group -----------------------7-1
8 -SYSTEM INSTALLATION, f.1AINTENANCE, AND TRAINING -----------8-1
9-PROJECT IMPLEMENTATION-----------------------------------9-1
9.1 -EMS Project Staffing -------------------------------9-1
9.2 -EMS Project Schedule -------------------------------9-1
9.3 -EMS Control Center ---------------------------------9-2
10-BUDGETARY COST ESTIMATES ---------------------------------10-1
10.1 -Project Cost--------------------------------------10-1
10.2 -Alternative I -------------------------------------10-1
10.3 -Alternative II ------------------------------------10-6
10.4 -EMS Control Center Cost ---------------------------10-8
TABLE OF CONTENTS (Cont.)
Page
ll -RECOMMENDATION --------------------------------------------ll-1
ii
LIST OF FIGURES
Number
1.1
J. 1
3. 2
3.3
3.4
4. 1
6. 1
9. 1
.Tit 1 e
Energy Management System, Alternative I
Configuration Block Diagram
Energy Management System, Alternative I
System Configuration
In-Plant Monitoring and Control System
Alternative I
Susitna River Plants Control Center
Energy Management System, Alternative II
System Configuration
In-Plant Monitoring and Control System
Alternative II
Susitna River Plants Control Center
Proposed Microwave Communication Facilities
Willow System Control Center, Functional
Layout
EMS Project Implementation Schedule
iii
1 -INTRODUCTION
1.1 -Scope
To produce a conceptual design and cost estimate for a
computerized control and dispatch center that will provide
reliable and secure operation of the Susitna development and
the A~chorage-Fairbanks transmission link. Appropriate
communications for the center will be recommended.
1.2 -Study Objectives
The present Railbelt electrical generating capacity is
c o n c e n t r at e d i n t wo a r e as , n am e 1 y Fa i r b an k s a n d An c h o r a g e .
The generating capacity is predominantly thermal electric.
With the introduction of the Susitna development it is
proposed to interconnect the Fairbanks area with the
Anchorage area. This will create a larger power system
than the two existing systems. To make effective use of all
t h e g en e r at i n g and t r an sm i s s i o n fa c i 1 i t i e s a v a i l a b 1 e i n t h e
enlarged pool~ an Energy Management System (EMS) will be
required.
The objective will be to examine a range of alternatives to
achieve the goal of providing effective control of the power
pool. The cost of the chosen alternatives will be estimated
and compared. Conceptual design of the selected system will
be described and a cost estimate will be prepared.
1.3 -Present Railbelt
Power Systems
(a) Northern Area (Fairbanks)
The area of operation of this system is concentrated
a r o u n d F a i r b an k s a n d c o n s i s t s o f t wo m a i n u t i 1 i t i e s .
Golden Valley Electric Association, Inc. which has a
generating capacity of 206 MW and Fairbanks Municipal
Utility System with a capacity of 65 MW. The utilities
are interconnected throDgh a 69-kV line. Golden Valley
is also interconnected with the University of Alaska and
m i 1 it ar y f ac i 1 it i es.
Each utility has operators to control and dispatch
system operations. Neither utility has a control center
specifically designed for supervisory control and ·data
acquisition system.
Golden Valley Electric Association is responsible for
maintaining frequency in the northern area.
1-1
(b) Southern Area (Anchorage)
The main utilities of this area are Chugach Electric
Association, Anchorage Municipal Light and Power, and
tVlatanuska Electric Association. The utilities with
genera t i n g c a p a ci t y are C h u g a c h ( 4 9 3 M W) , Anchor age
Municipal (230 MW) and Alaska Power Administration
(30 MW). All these utilities are interconnected at the
115-kV and 138-kV level.
Each utility have their own system operations.
Matanuska Electric does not generate any electric power
and depends on importation from CEA or Alaska Power
Administration.
Chugach Electric has a control center for their system
i n An c h or age • A 11 the C E A g en e r at i n g u n i t s are
controlled from this center, including supervisory
control of power system devices located at various
substations. CEA uses microwave for communications.
CEA intends to relocate their dispatch center to the
International Generating Station from the present
location.
Frequency c~ntrol is presently being maintained by
Chugach Electric in the southern area.
1.4-1984 Power System Operation
(a) Fairbanks -Anchorage Intertie
APA proposes to construct an intertie between Fairbanks
and An c h o r age w h i c h w i 1 1 be o per at i on a 1 by 1 9 8 4 . T h i s
line will be built to 345 kV standards and operated at
138 kV. The intertie will have a transfer capability of
70 MW.
Th i s i n t e r t i e w i 1 1 r e q u i r e c o o r d i n at i o n b e t we en at 1 e a s t
two utilities in the north and south. This will give
both areas an opportunity to communicate and develop
supervisory functions to maintain an orderly transfer of
power when required by load or electrical generation and
provide frequency control coordination for the combined
area.
1.5-1993 Power System Operation
(a) Railbelt Power System Facilities
The present schedule calls for the first Susitna
hydroelectric station at Watana to be operational by
1993. At that time the first stage of the enlarged
Railbelt power system will be completed. This system
1-2
will be operated at 345 kV and will ultimately consist
of approximately 850 mi of transmission lines and 5
s w i t chi n g stat i on s . The two m aj or 1 o ad centers at
Anchorage and Fairbanks will be interconnected with the
Susitna complex to form a large integrated power
system.
The first stage will consist of the Watana generating
station transmitting electrical power to Devil Canyon
which in turn will have two 345-kV lines going to
Fa i r b an k s . I n bet ween De v i 1 Can yon and An c h o r a g e , t h e r e
w i 11 be t wo i n t e r m e d i at e s w i t c h i n g s t at i o n s at W i 1 1 o w
and Knfk Arm. The switching stations will have capabi-
1 ities to transform the voltage to subtransmission level
for d i s t r i but i on to 1 o c a 1 1 o ad's .
(b) Energy Management System (EMS)
To provide an effective and reliable transmission and
generating system, it is essential that one control
center be established. This center will manage the
generation and transmission between the generating
plants and load centers.
In the year 1993 there will be three generating centers
at Anchorage, Fairbanks and the Susitna River Complex.
The Anchorage and Fairbanks generation will be predomi-
nantly thermal. It is proposed that the control center
which is located at Willow will have direct frequency
control of the Susitna generating plants. The center
will also have the responsibility to establish genera-
tion requirements for the Anchorage and Fairbanks areas
and will transmit these requirements on a periodic
basis. The control centers at Anchorage and Fairbanks,
which have direct control of their generating units in
their area, will -assume the task of complying with the
system requirements. Frequency control will be the
res p o n s i b i 1 i t y of t h e W i 1 1 ow En e r g y Man a g em e n t C e n t e r .
Railbelt Central Control System
A b 1 o ck d i a g r am of t h e p r e fer r e d c o n t r o 1 s y s t em i s
shown on Figure 1.1. As described above the Willow
Control Center exercises direct control of the Susitna
complex but indirect control of the northern and
southern are as . The center w i 1 1 a 1 so rem o t e 1 y con t r o 1
the substations at Ester (Fairbanks), Willow, Knik Arm
and University (Anchorage). The communications 1 ink
will be via microwave.
1-3
--... -" TO
GENERATORS
-
NORTHERN AREA
CONTROL SYSTEM-1----------,
FAIRBANKS
ESTER
SUBSTATION
WILLOW
SUBSTATION
KNIK ARM
SUBSTATION
UNIVERSITY
SUBSTATION
SOUTHERN AREA
ENERGY MANAGEMENT
SYSTEM
WILLOW CONTROL
CENTER
WATANA
SWITCHING
STATION
TO GENERATORS
'~ J~ a Jl' ~~ ~~
SUS! TNA
HYDROELECTRIC
CONTROL CENTER
11t 1r ,. ,.
TO GENERATORS
DEVIL CANYON
SWITCHING
STATION
..,.-t----1 CONTROL SYSTEM-1------------...l --ANCHORAGE
TO
GENERATORS
ENERGY MANAGEMENT SYSTEM, ALTERNATIVE I, l•.·'···u·I@I
CONFIGURATION BLOCK DIAGRAM FIGURE J.t JtU 0
2 -FUNCTIONAL REQUIREMENTS
The Railbelt Energy Management System (EMS) will provide a
centralized interconnected, efficient, and secure dispatching
operation of the high voltage transmission network and will
allow remote control of the Susitna hydro generating units.
The purpose of this section is to describe general functional
requirements that will define the current state-of-the-art
and develop a framework for understanding the interrelation
of various power system functions that will subsequently be
proposed for the future EMS.
The power system functions that were studied and analyzed
cover six major areas of the Railbelt EMS, and are as
follows.
Supervisory Control and Data
Acquisition (SCADA) Subsystem
Includes real-time system data acquisition; remote control
of the power system devices; data base and data base
management; data processing; operation data logging and
report generation; and man/machine interface requirements.
Generation Control Subsystem
Includes automatic control of hydro and thermal units in
the Railbelt control area to maintain interconnected system
frequency and interchange scheduling; economic unit opera-
tion; generation reserve evaluation; and monitoring of
system generation performance.
Power Scheduling and
Load Forecasting Subsystem
Includes the forecasting of system load, and the scheduling
of the power system generation to meet the load require-
ments in the most economical and reliable way.
Energy Accounting Subsystem
Includes collection, recording, and processing of data
power transaction among various utilities in the inter-
connected system; also the cost information and the
savings/losses resulting from the purchase/sale of power.
System Security Subsystem
Includes the ability to evaluate system performance based
on present and predicted system conditions, and the ability
to evaluate the impact of probable contingencies (loss of
generation, loss of a transmission line, etc).
2-1
System Support Subsystem
Includes on-line/off-line functions that could be performed
by the EMS to support engineering, accounting, and system
operation organizations.
2.1 -SCADA Subsystem
(a) Data Acquisition Function
The data acquisition function will be responsible for
gathering data from the substations, generating plants,
system interchange points, and the neighboring power
con t r o 1 c en t e r f a c i 1 i t i e s . Th i s f u n c t i an w i 11 per f o r m
all communication channel control and message encoding,
decoding, channel security verification, data filtering,
and formatting of data.
(b) Supervisory Control Function
The su.pervisory control function will allow power system
devices to be remotely controlled from a central
location. Several types of supervisory control actions
will be provided
-control of binary power system devices (i.e.,
breakers)
-incremental control of power system devices (i.e.,
transformers)
-set point control {i.e., valves)
-on/off controls (i.e., unit starting/shutdown
sequences).
(c) Data Processing Function
Th e d at a p r o c e s s i n g f u n c t i o n w i l l p e r f o r m t h e s t and a r d
SCAOA data processing operations, such as conversion of
data to engineering units, limit checking, and alarm
generation. In addition, the following capabilities
will also be provided.
-Integration of certain data over a designated period.
-Performance of various arithmetic calculations,
algebraic, and trigonometric functions.
-Recording of the minimum or maximum value of specific
data and averaging over a designated period.
-Initiation of an alarm or calling function upon
detection of limits violations.
2-2
-Calculation of the net MW, MVAR, and the unit
auxiliary power.
-Per f o rm i n g 1 o g i c a 1 o per at i o n s ( Bo o 1 e an a 1 g e b r a ) .
Post-disturbance data processing.
(d) Data Base and Data Base Management
Th e d at a b as e and d at a base man a g em en t fun c t i on w i 1 1
provide a centralized location for the EMS data and will
allow efficient management and access to all data by
various power system functions. The system data base,
as a minimum, will contain the following data.
-Real-time data obtained from the power system on
periodic basis.
-Program calculated data.
-Manually entered data.
-System parametric data.
-Historical data.
A set of quality codes will be provided with each data
point to enable the user to determine the worth of the
information presented at each point. The system data
base management will allow any power system configura-
tion changes to be made without rearranging or refor-
matting the system data base. The system data base will
be expandable to accommodate the future system changes,
growth, and expansion.
{e) Man/Machine Interface Function
The man/machine interface function will provide
requested data in the tabular or schematic formats on
the CRT screens. This function will also allow the
system operator to perform super v i so r y con t r o 1 , m an u a 1 1 y
enter or change data, invalidate data, and request
report or logs to be generated by the system.
A 1 arm report i n g w i 1 1 be one of t h e m o s t c r i t i c a 1 of the
man/machine interface services by properly, without
ambiguity, alerting the system operator of impending
mal functions.
2-3
2.2 -Generation Control Subsystem
(a) Automatic Generation Control
(AGC) Function
The aut om at i c genera t i on con t r o 1 fun c t i on w i 11 pro v i de
generation control of all generating facilities in the
R a i 1 be 1 t genera t i on con t r o 1 are a. Th i s con t r o 1 are a
will encompass the existing northern and southern
generating facilities (Fairbanks and Anchorage) and the
Susitna River hydro plants (Devil Canyon and Watana).
The AGC function will provide load frequency control of
generating units by computing the individual unit
as s i g nm e n t ( M W ) , w h i c h h as t w o c om p o n e n t s : b a s e l o ad
and regulation participation. In addition, the AGC
function will be allowed to recognize certain operating
limitations of the hydro units related to excessive
vibration and/or cavitation.
·{b) Economic Dispatch Function
The economic dispatch function, in conjunction with the
AGC ftJnction, will compute base load assignments for
units in the automatic control mode in a manner that
will minimize the total system input (in terms of total
fuel cost or 11 water cost 11
) for the real-time system load
supplied by controllable generation.
(c) Generation Reserve Function
The generation reserve function will determine the
actual reserve availability for each reserve category
(spinning reserve, responsive reserve, ready reserve,
replacement reserve, etc), depending on unit status,
actual load, capacity, allowable rate of change,
currently active interchange contracts, and other
factors.
(d) Inadvertent Interchange Function
The inadvertent interchange function will continuously
monitor and integrate inadvertent energy interchanges.
All inadvertent interchange calculation will include
-heavy load hours/light load hours
-total inadvertent interchange
-inadvertent energy due to frequency bias
contribution
-inadvertent energy due to control performance.
2-4
(e) Hydro Calculation Function
The hydro calculation function will be capable of calcu-
lating certain variables associated with the hydro
system
-spillage
-turbine flow
-others, as required.
(f) Unit Commitment Function
The unit commitment function will provide an optimum
minimum cost solution to the problem of which unit to
commit while meeting the constraints stated by genera-
tion control functions. This function will be flexible
to allow easy specification of type of fuel or hydro,
mandatory schedules, unit maintenance constraints,
spinning reserve requirements, etc, and providing daily
fuel/water usage and the costs by unit plant, and
system. The hydro-thermal coordination will consider
stored hydro, run-of-river hydro, and pumped hydro
operational problems.
2.3 -Power Scheduling and
Load Forecasting Subsystem
(a) Power Scheduling Function
The power scheduling wi 11 perform all power system
interchange scheduling. Various types of interchange
transactions will be required, such as
-long-term firm
-short-term firm
-erne rg ency
-economy
-others.
(b) Int~rchange Transaction
Evaluation Function
The interchange transaction evaluation function will
allow the system operator to evaluate various potential
power transactions with the interconnected utilities.
Two basic interchange types will be considered.
2-5
-Economy A, which is usually an on-the-spot decision.
-Economy B, which is normally a firm transaction and
requires bringing up additional generating units. A
unit commitment function is usually required to
determine which unit to put into operation.
(c) Load Forecasting Function
The load forecasting function will provide the ability
to forecast system load on a short-term basis. This
system load forecast function will consider the histori-
cal load trends, typical seasonal daily load cycle,
wind, temperature, hour of day, cloud cover, etc, to
obtain a best estimate of a forecast for a daily loading
profile.
In addition, the bus load forecast and area load fore-
cast should also be considered for implementation.
2.4 -Energy Accounting Subsystem
The energy accounting subsystem will maintain a historical
energy transaction data base to serve as the source of all
data required for the logging and report generation and the
energy accounting.
This subsystem w.ill include the following major tasks
-wheeling scheduling
-payback scheduling
-loss schedules
-economy and dynamic participation schedules
-excess wheeling
-special railbelt accounting adjustments.
2.5 -System Security Subsystem
The end use of the system security subsystem are
-to alert the system operator in real-time about contingent
system problems before they occur
-to serve as an analytical tool that can be used to help to
identify possible remedial action.
The system security subsystem is comprised of four supporting
functions.
2-6
(a) Network Modeling Function
This function will determine the real-time system
configuration by monitor i n g s y stern power devices . The
external power network (northern and southern areas)
will be modeled by simplified equivalences determined
through the use of key status and power measurement
information (breakers, power flow, and voltage).
(b) State Estimation Function
This function will use the network model and will
satistically analyze the real-time system data; it will
also generate an estimated data set for use for the
dispatcher•s (operator•s) real-time load flow function.
(c) Dispatcher's Load Flow Function
This function will generate a base solution utilizing
the network modeling and state estimation inputs. The
load flow function will be used to evaluate system
contingencies and analyze the consequences of
preselected system contingencies.
(d) Contingency Analysis Function
As a result of the contingency analysis, possible
identifiable remedial actions including generation
rescheduling, interchange rescheduling, line switching,
and 1 o ad shedding wi 11 be recommended.
2.6 -System Support Subsystem
The following functions have been considered for the future
implementation to support EMS operations.
-Dispatcher training simulator.
-Engineering load flow.
-Au t om at i c r em e d i a 1 act i o n .
-Optimal load flow.
-Automatic VAR control.
-Bus load forecasting.
-Optimal hydro-thermal coordination.
2-7
Currently, we do not recommend some of these functions
because
-they are not presently in widespread use
-there is current uncertainty about the effectiveness and
economic benefits of some of these functions.
2.7 -External Data Transfer and
Coordination Requirements
The Railbelt Energy Management System is envisioned as an
energy coordination system providing system operation
coorination, generation control, and system security
evaluation services. Therefore, provisions should be made
for external data transfer between Railbelt 1 S EMS computers
and the computers of
-neighboring utilities (north and south)
-Alaska Power Pool
-various APA departments.
2-8
3 -RAILBELT ENERGY MANAGEMENT
SYSTEM ALTERNATIVES
Our evaluation of alternative system configurations showed
that two different approaches to generation control are
possible.
-Alternative I provides indirect control of generating
units.
-Alternative II provides direct control of generating
units.
To f o r m u 1 at e an d e v a 1 u at e a 1 t e r n at i v e EM S c o n f i g u r at i o n s , we
used the following criteria.
-Configurations must fulfill the SCADA, Generation Control,
Power Scheduling and Load Forecasting, Energy Accounting,
and System Security Subsystem functional requirements, as
defined in Section 2.
-Configurations must be technically-economically and
operationally -maintainable throughout the 1 ife of the
systems (10 to 15 years).
-Configurations must be technically feasible, as well as
proven.
3.1-Alternative I-
EMS System Configuration
The Alternative I system configuration is typical of the
current offerings of several EMS equipment manufacturers {see
Figure 3.1, EMS Alternative I, System Configuration). The
configuration is based on the assumptions that
-an in-plant, computer-based control system, located at
Susitna Hydroelectric Control Center will be provided
-the Susitna in-plant control system will directly control
all hydro generating units and the power switching stations
(Watana and Devil Canyon). The EMS, Alternative I System,
will determine generation participation requirements on the
unit level, but the units will be pulsed by the in-plant
system. The supervisory control actions for the Watana and
Devil Canyon stations will be initiated at the EMS level
(Willow Control Center), but the controls will be
implemented by the in-plant control system.
3-1
-the northern and southern areas computer-based systems will
receive gineration participation requirements frnm the EMS,
but participation allocation and direct unit pulsing will
be done by these systems.
-Alternative I will directly monitor and control the
following high-val tage substations
-Ester
-Willow
-Kn i k Arm
-University
-others, as required.
(a) EMS Hardware Configuration
(i) Computer Subsystem
-Two (2) medium size computers, 32 bits, 2-M
b yt e s o f m a i n m emory
-Two (2) dedicated CRT terminals
-Two ( 2 ) 1 i n e p r i n t e r s
-Two (2) moving head disk systems, 600-M bytes,
each
.. Two (2) magnetic tape systems
-0 n e ( 1 ) CPU -CPU d at a c h anne 1
-Interface controllers, cabinets, cablings,
power supplies, etc
(ii) Man/Machine Subsystem
-Four (4) single position consoles, each
equipped with two (2) CRTs one (1) cursor
control, one (1) A/N keyboard, and one (1)
function a 1 control panel . These cons o 1 e s w i l 1
be designated to perform the following
functions
-transmission control
-ge~eration control
-system security
-programming/training.
-Two (2) data 1 oggers
-One (1) time and frequency standard equipment
3-2
(iii) Communication Subsystem
-Four {4) microprocessor-based communication
controllers, with associated communication
modems, 1,200 baud, synchronous, to support
four (4) remote terminal units
-Two (2) redundant, microprocessor-based
communication controllers with associated
communication modems, 4,800 baud, synchronous,
to support data transfer to/from the northern
area computer-based system
-Two (2) redundant, microprocessor-based
communication controllers with associated
communication modems, 4,800 baud, synchronous,
to support data transfer to/from the southern
area computer-based system
-Two (2) redundant, microprocessor-based
communication controllers with associate~
communication modems, 4,800 baud, synchronous,
to support data transfer to/from the Susitna
Hydroelectric Control System
{ iv) Remote Terminal Units (RTUs)
Six (6) RTUs, (two (2) switching stations, and
four {4) power substations) microprocessor-based,
capable of supporting Sequence of Events
function, 300 data points.
(b) Susitna Hydroelectric In-Plant
Monitoring and Control System,
Alternative I Hardware Configuration
(i) Computer Subsystem
-Two (2) small size computers, 32 bits, 1-1"1 byte
o f m a i n m em o r y
-Two (2) dedicated CRT terminals
-One (1) line printer
-Two (2) moving head disk systems, 100-M bytes,
each
-One (1) magnetic tape system
-One {1) CPU-CPU data channel
3-3
-Interface controllers, cabinets, cablings,
power supplies, etc
See Figure 3.2, In-Plant Monitoring and Control
S y s t ems , A 1 t e r n at i v e I , S u s it n a R i v e r P 1 ant s
Control Center.
(i i) Man/Machine Subsystem
-Two (2) single position consoles, two (2) CRTs,
two (2) cursor control, t~<~o (2) A/N keyboards,
and two ( 2 ) fun c t i on a 1 con t r o 1 pane 1 s
-Two ( 2 ) d at a 1 o g g e r s
{iii) Communication Subsystem
-Seven (7) micorprocessor-based communication
controllers with associated communication
modems~ 1,200 baud, synchronous, to monitor and
control seven RTUs located at two switching
stations and ten generating units
-Two {2) redundant, microprocessor-based
communication controllers with associated
communication modems, 4~800 baud, synchronous,
to support data transfer to/from the Railbelt
EMS
(iv) Remote Terminal Units (RTUs)
Five (5) RTUs, computer/microprocessor-based,
capable of high speed monitoring of hydroelectric
units.
(c) Alternative I System
Data Flow
(i) From EMS
-Supervisory control actions
-Unit participation requirements
-Data transfer requests
-Operator's messages
To EMS
-Unit performance data
-Plant performance data
-Switching station performance data
-\~eather data
3-4
-System water data
-Selected log data
-Selected display data
-Operator's messages
(ii) EMS Power Substation RTUs
From EMS
-Supervisory control commands
-Data requests
To EMS
-Substation measurement and status data
-RTUs test data
(iii) Susitna River In-Plant
System and R TU s
From Susitna River System
to Generation RTUs
-Data requests
-Unit pulsing
-Unit controls
To Susitna River System
From Generation RTUs
-Unit performance data
-Unit power data (MW, MVAR, etc)
From Susitna River System
to Switching Station R T Us
-S u p e r v i s or y c o n t r o 1 c o mm and s
-Data requests
To Susitna River System
From Switching Station RTUs
-Station measurement and status data
-RTUs test data
(iv) EMS Northern/Southern
Area Control Systems
From EMS
-Data requests
-Unit/plant participating
-Operator's messages
3-5
To EMS
-Unit/plant performance data
-System device status
-System Measurements
-Operator 1 s messages
3.2 -Alternative II -
EMS Configuration
The Alternative II system configuration is also typical of
the current offerings of several EMS equipment manufacturers
(see Figure 3.3, EMS, Alternative II, System Configuration).
The configuration is based on the assumptions that
-an in-plant, computer-based control system, located at
Susitna Hydroelectric Control Center will be provided to
monitor generation units performance and control the units
-all Watana and Devil Canyon generation units will be
controlled (raise and lower) directly by the EMS from the
W i 1 1 ow Control Center
-all northern and southern area generating units will be
directly controlled (raise and lower) by the EMS from the
Willow Control Center
-the switching stations (Watana and Devil Canyon) and four
power substations will be directly monitored and controlled
by the EMS from the Willow Control Center.
(a) EMS Hardware Configuration
(i) Computer Subsystem
S a m e a s A 1 t e r n a t i v e I [ s e e Se c t i o n 3 . 1 ( a ) ( i ) ] .
(ii) Man/Machine Subsystem
Same as Alternative I [see Section 3.1(a)(ii)].
{iii) Communication Subsystem
-Eight {8) microprocessor-based communication
controllers with associated communication
modems, 1,200 baud, synchronous, to support
four power substations, two switching
substations, and five generation RTUs
-Two (2) microprocessor-based communication
controllers, as a minimum, with associated
communication modems, 1,200 baud, synchronous,
3-6
to support two generating plants located in
northern and southern areas. (Note: the exact
number of generating plants and units is not
known.)
-Two (2) redundant, microprocessor-based
communication controllers with associated
communication modems, 4,800 baud, synchronous,
to support data transier to/from the Susitna
Hydroelectric Control System
-Four (4) redundant microprocessor-based
communication controllers with associated
communication modems, 4,800 baud, synchronous,
to support data transfer to/from the EMS, and
the northern and southern control centers.
(iv) Remote Terminal Units
-Eight (8) RTUs, microprocessor-based, capable
of supporting Sequence of Events function
(6 RTUs) and generation control {2 RTUs).
(b) Susitna Hydroelectric In-Plant
Monitoring and Control System,
Alternative II, Hardware Configuration
(i) Computer Subsystem
Same as Alternative I [see Section 3.l(b)(i)].
See Figure 3.4, In-Plant Monitoring and Control
System, Alternative II, Susitna River Plant
Control Center.
(ii) Man/Machine Subsystem
Same as Alternative II [see Section 3.l(b)(ii)].
(iii) Communication Subsystem
-Five (5) microprocessor-based communication
controllers with associated communication
modems, 1,200 baud, synchronous, to monitor and
control five RTUs located at two generating
plants (10 units)
-Two (2) redundant, microprocessor-based
communication controllers with associated
communication modems, 4,800 baud, synchronous,
to support data transfer to/from the Railbelt
EMS.
3-7
(iv) Remote Terminal Units {RTUs)
-Five (5) RTUs, computer/microprocessor-based,
capable of high-speed monitoring of
hydroelectric units.
(c) Alternative II System Data Flow
(i) EMS Susitna River In-Plant
Monitoring and Control System
From Ei'1S
-Data transfer requests
-Operator's messages
To EMS
-same as A 1 tern at i v e I [ see Sect i on 3 . 1 ( c ) ( i ) ]
(i i) EMS Power Substation RTUs
Same as Alternative I [see Section 3.l(c)(ii)].
(iii) Susitna River In-Plant
System and RTUs
From Susitna River System
to Generation RTUs
-Data request
-Unit pulsing (local control mode)
-Unit controls
To Susitna River System
From Generation, RTUs
- U n i t p e r f o rm an c e d at a
-Unit power data
(iv) EMS Generation RTUs
From EMS
-Data request
-Unit pulsing (remote control mode)
To EMS
-Unit/power data (MW, MVAR, etc)
-Unit status
3-8
(v) EMS Switching Stations
and Power Substations
From EMS
-Supervisory control commands
-Data requests
To EMS
-Station/substation measurement data and status
data
-RTUs test data
(vi) EMS Northern/Southern
Area Control Systems
From EMS
-Data requests
-Operator's message
-System performance data
To EMS
-Unit/plant performance data
-System device status
-S y s t em m e as u r em en t s
-Operator's messages
(vii) EMS Generation RTUs
(Northern/Southern Area)
From EMS
-Data request
-Unit pulsing (remote control mode)
To EMS
-Unit/power plant data
-Unit status.
3-9
NORTHERN AREA
CONTROL SYSTEM
COMPUTER
PERIPHERALS
MAN/MACHINE
INTERFACE
COMPUTER
COMMUNICATION SUBSYSTEM
SOUTHERN AREA
CONTROL SYSTEM
SUSITNA HYDROELECTRIC
CONTROL CENTER
RTU -----
SUBSTATION
RTU5
ENERGY MANAGEMENT SYSTEM, ALTERNATIVE I, SYSTEM CONFIGURATION FIGURE 3.1 [i]
WATANA
SWITCHING
STATION
COMPUTER
(PRIMARY}
MAN/MACHINE
SUBSYSTEM
PERIPHERALS
COMMUNICATION SUBSYSTEM
WATANA GENERATING STATION
COMPUTER
(STANDBY)
DEVIL CANYON
GENERATING STATION
IN-PLANT MONiTORING AND CONTROL SYSTEM, ALTERNATIVE I
SUSITNA RIVER PLANTS CONTROL CENTER
EMS
CENTER
(WILLOW)
DEVIL
CANYON
SWITCHING
STATION
FIGURE 3.2 •
NORTHERN AREA
CONTROL SYSTEM
COMPUTER
PERIPH~RALS
MAN/MACHINE
INTERFACE
COMPUTER
COMMUNICATION SUBSYSTEM
SOUTHERN AREA
CONTROL SYSTEM
SUSITNA HYDROELECTRIC
CONTROL CENTER
WATANA/DEVIL CANYON SUBSTATION. RTU
SUBSTATIONS
ENERGY MANAGEMENT SYSTEMl ALTERNATIVE lll SYSTEM CONFIGURATION FIGURE 3.3.
EMS CENTER
(WILLOW)
WATANA
SWITCHING
STATION
COMPUTER
(PRIMARY)
DEVIL
CANYON
SWITCHING
STATION
MAN/MACHINE
SUBSYSTEM
PERIPHERALS
COMPUTER
(STANDBY)
COMMUNICATION SUBSYSTEM
WATANA
GENERATING
STATION
EMS CENTER
(WILLOW)
DEVIL CANYON
GENERATING
STATION
IN-PLANT MONITORING AND CONTROL SYSTEM, ALTERNATIVE TI
SUStTNA RIVER PLANTS CONTROL CENTER FIGURE 3.4.
4 -SYSTEM COMMUNICATION REQUIREMENTS
We evaluated various communication systems to determine the
most reliable and the most cost-effective communication
media.
(a) Power line Carrier System
The power line carrier system is not a viable
communication option for the Energy Management System.
This system is dependent on the state of a power line
and, therefore, will be unavailable when the line is
down. In addition, it requires a high capital cost
expenditure and is very expensive to maintain.
(b) Telephone Communication System
The telephone companies provide data transmission
services. In general, this service is very erratic and
unreliable for the E~1S applications.
( c) Microwave System
The privately owned microwave system provides the most
reliable and cost-effective communication solution for
the EMS communication problem. It is highly desirable
to build a looped microwave system for power system
operations .
4.1 -Microwave System
Microwave systems are line-of-sight propagation and have an
average standard of approximately 35 to 40 mi path for a flat
terrain. WCC recommended criteria is 40 db fade margins for
any microwave paths used for protective relaying. A full
diversity repeater station will be installed at each tower.
No tower spotting has been attempted at the present time.
The number of towers was esiimated wtthout having the benefit
of a detail communication analysis.
Figure 4.1 shows the proposed microwave communication
facilities.
4-1
FAIRBANKS STATION 17, ESTER
STATION 15
STATION 14
STATION 13.
STATION 12
STATION II
STATION 10
15 MILES
STATION 9
20 MILES
DEVIL CANYON
26 MIL£s
--.---.:.:::..:::._ ____ wATANA
15 MILES
STATION 5
STATION 4
STATION 3, WILLOW
STATION 2, KWIK ARM
STATION I, UNIVERSITY
PROPOSED MICROWAVE
COMMUNICATION FACILITIES FIGURE 4.1 [iJ
5 -SYSTEM SOFTWARE REQUIREMENTS
The EMS should be provided with all software required to
satisfy all the functional requirements described in
Section 2 and all software functions in this section.
The system software should be the general purpose operating
system, developed and tested by a major computer supplier and
verified through many installations in real-time
applications. It should provide a reliable, high-
performance environment for the concurrent execution of
multiuser, time-sharing, batch, and time-critical
a p p 1 i c at i an s . Th i s software w i 1 1 cans i s t a f the fa 1 1 a w i n g
major components
-executive services
-system failover and system restart
-diagnostic programs
-programming services
-special data base~ CRT display, and log/generation
compilers
-engineering support
-special I/0 handlers.
FORTRAN compatibility of the software is essential, as most
of the power application programs (as defined in Section 2)
will be written in a high-level language.
5-l
6 -WILLOW CONTROL CENTER
FACILITY REQUIREMENTS
This section covers the requirements necessary to support the
EMS operational equipment and personnel for the Willow
Control Center facility.
The facility will be the nerve center of the APA power system
operations of the interconnected high-voltage network and
power generation. All decisions concerning the operation and
maintenance of the power system will be implemented through
this complex. The importance of this facility dictates that
its location be selected with a great deal of care.
6.1-Site
The control center must be located on a site that provides
high security against disruption of power system operation by
human intervention or by acts of God. Acts of human
intervention that must be considered are civil disturbances
and terrorist activities. Natural disturbances that could
occur are floods, fires, earthquakes and landslides.
Several additional factors that have a bearing on the
suitability of a site are
- 1 and a v a i lab i l it y
-housing availability
-transportation accessibility
-education facility availability
-climatic conditions
-power availability
-centralized location.
It is recommended that a rn1n1mum of 10 acres of flat land
provided for the Willow Control Center.
6.2-Control Center Layout
F i g u r e 6 . 1 p r o v i d e s a co n c e p t u a 1 1 a yo u t of t h e W i 1 l ow Co n t r o 1
Center. This layout is based on a one-level building having
a total space of 14 537 ft2.
6 • 3 -C o n t r o l C en t e r R e q u i r em e n t s
This section covers the general requirements for the
facilities that are necessary to support the system
o p e r at i o n a l e q u i pm en t a n d p e r so n n e l .
6-1
(a) Construction Guidelines
Construction guidelines include
-extra wide doors and corridors
-the use of subfloor cabling makes it essential that
provision be made to prevent water f~oding
- a network of temperature sensors, ultraviolet
detectors, and smoke detectors should be installed for
fire protection. A total gaseous flooding system
using Halon 1301 is recommended
-all doors to these facilities should be established as
limited access entries
-raised floors should be installed in the equipment
rooms
accoustical treatment of floors~ ceiling, and walls is
highly desirable
-special lighting tailored to each area should be
considered. The dispatch arena should have
sectionalized, individually controlled lighting area
-color coordination should be developed to reduce the
psychological effects of various colors.
(b) Environmental Support
T em p e r at u r e c o n t r o 1 t o m a i n t a i n am b i e n t t em p e r at u r e at
72 deg/78 deg and a relative humidity of 35 to
55 percent is recommended for the EMS equipment room.
Other rooms may be air conditioned for comfort.
In addition to the building 1 s air conditioning system,
air conditioning built specifically for computer
environmental conditioning should be procured for the
e q u i pm e n t room as s t a n d - a 1 o n e u n i t s .
(c) Interference Reduction
In order to minimize electromagnetic int~rference
between variant equipment groups, a single-point ground
c ·a n c e p t i s r e c om m en d e d f o r t h e EM S c o n t r o 1 c e n t e r
building.
(d) Uointerruptible Power Supply
An uninterruptible power supply (UPS) should be
installed in the control center to handle voltage
6-2
regulation, transients, and short-term power outages.
It is estimated that a 50-kVA redundant power supply
will be required.
(e) Diesel Generator
A diesel engine is required to provide a continuous
source of power in the event of power line failure.
6-3
MECHANICAL AND
FACILITY SUPPORT
1200 so~ FT.
CONFER. TRAIN I PROG.
ROOM ROOM
400 SQ. FT. 400 SQ. FT.
OFFICE AREA
1500 SQ. FT.
0 20 40
FEET
170
COMMUNICATION STORAGE 13ATTERY ROOM
350 SQ. FT.
ROOM 300
UPS ROOM
600 SQ. FT. SQ. FT. 350 SQ.FT.
EMS EQUIP. EMS EQUIPMENT
MAINT. ROOM ROOM
900 SQ. FT. 1500 SQ. FT.
HALL 7.5 FT. WIDE
ENG. KITCHEN a MEN
LAV.
SUPPORT LOUNGE
450
600 SQ. FT. 900 SQ. FT. SQ. FT.
TOTAL: 14,537.5 SQ. FT.
WILLOW SYSTEM CONTROL CENTER,
FUNCTIONAL LAYOUT
,-
LAV. a
KITCHEN
350 SQ. FT. DISPATCHING
DISPATCH ARENA
AREA
1500 SQ. FT.
-00 650 SQ. FT. ,.._:
00
LOBBY
450 SQ. FT.
WOMEN
LAV. MANAGEMENT
450 AREA
SQ. FT. 637 SQ. FT.
......._ -
ENTRANCE
FIGURE 6.1
7 -STAFFING REQUIREMENTS
The functional organization of the EMS control center must
efficiently and comprehensively support all aspects of the
operation and control of the Rai lbelt•s power system. This
includes not only the day-to-day operations, but also the
coordination of power transmission and generation and the
ongoing training of personnel to improve efficiency and
effectiveness.
7.1 -Transmission and Generation
System Operations Staff
We recommend that T&G operating staffing consist of the
following personnel
-one chief T&G operator
-five senior operators
-nine load operators
-one engineering technician
-one clerk.
This organization will support a 24 hour operation,
365-1/4 days a year.
7.2 -Computer Applications
The computer applications section should be managed by a
supervisor of software applications. Reporting to this
supervisor should be at least three additional software
engineers charged with the duties of maintaini~g the SCAOA,
generation control~ and system security software programs.
7.3 -Power Coordination
The power coordination group will be responsible for evalu-
ating unit commitment runs~ preparing interchange schedules,
and performing after-the-fact power accounting~ etc. This
group will include one supervisor, one power production
specialist, one budget specialist, two power system engineer/
analysts, two statisticians, and one power scheduler.
7.4 -EMS System
Maintenance Group
The EMS system maintenance group will be responsible for
maintalning the EMS system (hardware and software). As a
minimum, this group should include
-one system hardware engineer
-two system software engineers
-two hardware technicians
-two RTU maintenance technicians
-one communication maintenance technician.
7-1
8 -SYSTEM INSTALLATION,
MAINTENANCE, AND TRAINING
We recommend that all EMS equipment be installed by the power
system personnel (engineers, technicians, and software
engineers) under the supervision of the EMS system
suppliers.
We also recommend that the power system personnel start main-
taining the EMS equipment one year after system acceptance
(after one-year warranty).
We further recommend that a vigorous training program be
undertaken to train APA 1 S personnel in hardware and software
maintenance. It is estimated that a minimum of eight
engineers/technicians should be trained in hardware
maintenance (com~uters, peripherals, man/machine,
communication, and RTU equipment) and in software maintenance
(operating system and power application programs).
8-1
9 -PROJECT IMPLEMENTATION
9.1 -EMS Project Staffing
We recommend a full-scale project staffing commitment by APA
to define, develop, procure, install, test, and accept the
En€rgy Management System.
The following key personnel should be assigned full time to
the EMS project team for the duration of this project (see
Section 9.2 for the project scheduling).
-EMS Project engineer
-software engineer
-hardware engineer
-system programmer
-application programmer.
This project team should be supported on a part-time basis by
various APA personnel (such as purchasing agents, contract
people, and others).
9.2 -EMS Project Schedule
The procurement of the EMS system will encompass the
following major phases.
(a) Phase 1 -System Requirement Study
This phase will last approximately 6 to 9 months and
will culminate in development of the EMS system
functional requirement, system hardware configurations,
bu~getary cost estimates, economic evaluation, and other
pertinent tasks.
(b) Phase 2 -Specification Development
This phase wi 11 also last approximately 6 to 9 months.
EMS system specification will be developed and issued
for general bidding.
(c) Phase 3 -Proposal Preparation
This phase will last 3 months, during which a number (4
to 6) of viable proposals will be received from the EMS
system suppliers.
(d) Phase 4 -Proposal Evaluation
This phase will last 3 to 4 months, when the most
cost-effective proposal will be selected and a letter of
Intent will be written to start Work Statement
(contract) negotiations.
9-1
(e) Phase 5 -Work Statement Negotiations
This phase will last 3 to 5 months, at the end of which
a total EMS contract (Work Statement) will be negotiated
and a contract will be signed.
(f) Phase 6 -EMS System Development
This phase will last 30 to 36 months, during which the
system will be developed, designed, tested, integrated,
delivered. and accepted.
The total EMS project will last between 51 and 69 months.
Figure 9.1 shows an overall EMS project implementation
.schedule.
9.3 -EMS Control Center
Based on our past experience in the lower 48 states, the
following EMS control center schedule is provided as a
reference
-control center concept development - 6 months
-preliminary architectural drawings - 6 months
-building design approval - 3 months
-building specification preparation-6 months
-bidding - 3 months
building construction 12 months (could be doubled in
Alaska).
The total time required is between 39 and 51 months.
9-2
YEAR 1988 1989 1990 1991 1992 1993
PHASE
QUARTER I 2 3 4 I 2 3 4 I 2 3 4 I 2 3 4 I 2 3 4 I 2 3 4
I . PHASE I-SYSTEM REQUIREMENTS STUDY
2. PHASE 2-SPECIFICATION DEVELOPMENT ·-•• ·-
3. PHASE 3-PROPOSAL PREPARATION -~--· ·--· ~-~
4. PHASE 4-PROPOSAL EVALUTION •• -· ·--· ·-~· .. , -
-
5. PHASE 5-WORK STATEMENT NEGOTIATION -· "'--· ·--· ·-•• ---
6. PHASE 6-EMS SYSTEM DEVELOPMENT ·--· ·--· ·-i-• -•• -••
7. EMS CONTROL CENTER
CC CONCEPT DEVELOPMENT ... ·--· ·-
PRELIMINARY ARCHITECTURAL DRAWINGS -•• -· ·--· ·-
BUILDING DESIGN APPROVAL -· ·--· ·--· ·--· --
ButLDlNG SPECIFICATION PREPARATION -·· -•• -· •• -· ·--· ·-
BIDDING -· ·----•• -· ·--· ·--· ·--
SUI LDING CONSTRUCTION -·--· •• -· ·--· ·--· ·--· -
EMS PROJECT IMPLEMENTATION SCHEDULE FIGURE 9.1 [i]
10 -BUDGETARY COST ESTIMATES
This section provides budgetary cost estimates for the
development, procurement, system test, and installation of
EMS Alternatives I and II. Costs for the EMS control center
and the microwave system are also provided. These costs are
representative of what ECC, Inc. estimates the middle price
bid would be.
The cost estimates for these configurations, microwave
system, and EMS control center are given in January 1982
dollars for a fixed-price contract that includes milestone
payments.
10.1 -Project Cost
The total project cost is comprised of the following major
parts.
(a) System Cost
Total amount that is paid to system supplier.
(b) APA Internal Cost
-Project management
-Facility preparation (substations, switching stations,
RTU installations, power plant preparation to
receive RTUs)
10.2 -Alternative I
(a) EMS Project Cost
System Cost
A. Hardware Cost
1. Computer Subsystem
Total Computer Sybsystem
[see Section 3.1(a)(i)]
2. Man/Machine Subsystem
M/M Subsystem including
4 consoles
[see Section 3.1(a)(ii)]
3. Communication Subsystem
(see Section 3.1(a)(ii i)]
1~1
$1,800,000
220,000
$ 122,000
B .
c .
4. Remote Terminal Units
Six RTUs
[see Sectlon 3.1(a)(iv)]
5. Interface controllers, cabinets
cablings, power supplies, etc.
Hardware Subtotal
6. Spare parts
(20 percent of total
hardware cost)
TOTAL HARDWARE COST
Software Cost
1. Operating System and
Enhancement to OS
2 . SCAD A Subsystem
(see Section 2. 1 )
3 . Generation Control Subsystem
(see Section 2 . 2 )
4. Power Scheduling and Load
Forecasting
(see Section 2. 3)
5. Energy Accounting Subsystem
(see Section 2 . 4 )
6. System Security Subsystem
(see Section 2. 5)
7. System Support Subsystem
(see Section 2. 6)
TOTAL SOFTWARE COST
Auxiliary Cost
1. Project Management, System
Engineering, etc
.2 . System Test and Installation
3 . System Warranty
l0-2
190,000
120,000
$2,452,000
490,000
$2,942,000
$ 180,000
650,000
473,000
240,000
800,000
710,000
903,000
$3,956,000
$ 350,000
450,000
280,000
4. Performance Bond
5. Shipment
TOTAL AUXILIARY COST
TOTAL SYSTEM COST
Note: The total EMS system cost does
not include federal, state, and
local taxes.
Internal Cost
A. EMS Project Management
-EMS project engineer (5 m/y)
-software engineer (5 m/y)
-hardware engineer (5 m/y)
-system programmer (4 m/y)
-application programmer (4 m/y)
Subtotal
B. System Maintenance Training
(Salaries)
-engineers and technicians
C. Training Expenses
D. Switching Station
S i t e P r e p ar at i o n
(instrumentation, RTU housing, etc)
E. Power Substation
Site Preparation
F. Communication Installation
Support
TOTAL INTERNAL COST
Total EMS Project Cost
-system cost
-internal cost
TOTAL COST
10-3
$ 70,000
60,000
$1,210,000
$8,108,000
$ 500,000
450,000
450,000
320,000
320,000
$2,040,000
$ 240,000
$ 96,000
$ 320,000
$ 480,000
$ 240,000
$3,416,000
$ 8,108,000
3,416,000
$11,524,000
(b) Susitna Hydroelectric In-Plant
Monitoring and Control System
Project Cost
System Cost
A. Hardware Cost
1. Computer Subsystem
[see Section 3.1(b)(i)]
2. Man/Machine Subsystem
[see Section 3.1(b)(i i)]
3. Communication Subsystem
[see Section 3.1(b)(iii)]
4. Remote Terminal Units
[see Section 3.1(b)(iv)]
5. Interface controllers, cabinets,
cablings, power supplies, etc
Hardware subtotal
6. Spare parts
(20 percent of total
hardware cost)
TOTAL HARDWARE CDST
B. Software Cost
C. Auxiliary Cost
TOTAL SYSTEM COST
Internal Cost
A. Project Management
B. System Maintenance Training
(Salaries)
C. Training Expenses
D. Hydro-units Site Preparation
E. Communication Installation
Support
TOTAL INTERNAL COST
10-4
$ 380,000
175,000
86,000
250,000
65,000
$ 876,000
175,000
$1,131,000
$1,200,000
$ 750,000
$3,081,000
$ 800,000
160,000
50,000
700,000
60,000
$1,770,000
Total Susitna Hydroelectric
In-Plant Monitoring and Control
System Project Cost
A. System Cost
B. Internal Cost
TOTAL COST
(c) Communication Project Cost
Microwave System Cost
(see Section 4)
A. Communication Equipment
B. Towers and Installation
C. Foundations
D. Buildings, power supplies, etc
E. Contingencies
TOTAL SYSTEM COST
Internal Cost
A. Project Management
B. System Engineering
C . In s t a 1 la t i on Support
TOTAL INTERNAL COST
Total Communication Project Cost
A. System Cost
B. Internal Cost
TOTAL COST
(d) Alternative I,
Total Project Cost
A. Total EMS Project Cost
B. Total Susitna River Hydroelectric
In-Plant Monitoring and Control
System Project Cost
C. Total Communication Project Cost
TOTAL ALTERNATIVE I PROJECT COST
10-5
$3,081,000
1,770,000
$4,851,000
$1,020,000
1,190,000
400,000
850,000
680,000
$4,140,000
$ 180,000
90,000
510,000
$ 780,000
$4,140,000
780,000
$4,920,000
$11,524,000
4,851,000
4,920,000
$21,295,000
10.3 -Alternative II
(a) EMS Project Cost
System Cost
A. Hardware Cost
1. Computer Subsystem
[see Section 3.2(a)(i)]
2. Man/Machine Subsystem
[see Section 3.2(a)(ii)]
3. Communication Subsystem
[see Section 3.2(a)(iii)]
4. Remote Terminal Units
[see Section 3.2(a)(iv)]
5. Interface controllers cablings,
power supplies, etc
Hardware subtotal
6. Spare Parts
(20 percent of total
hardware cost)
TOTAL HARDWARE COST
B. Software Cost
C. Auxiliary Cost
TOTAL SYSTEM COST
Note: The total EMS system cost does
n o t i n c 1 u de f e d e r a 1 , s t at e -:--arid
local taxes.
Internal Cost
A. Project Management
B. System Maintenance Training
(Sa1aries)
C. Training Expenses
0. Switching Station Site Preparation
E. Power Station Site Preparation
F. Communication Installation Support
TOTAL INTERNAL COST
10-6
$1,800,000
220,000
170,000
220,000
150,000
$2,560,000
512,000
$3,072,000
$4,200,000
$1,350,000
$8,622,000
$2,200,000
240,000
96,000
320,000
480,000
270,000
$3,606,000
Total EMS Project Cost
-system cost
-internal cost
TOTAL COST
(b) Susitna Hydroelectric In-Plant
Monitoring and Control System
Project Cost
System Cost
A. Hardware Cost
1. Computer Subsystem
[see Section 3.2(b)(i)]
2. Man/Machine Subsystem
[see Section 3.2(b)(i i)]
3. Communication Subsystem
[see Section 3.2(b){iii)]
4. Remote Terminal Units
[see Section 3.2(b)(iv)]
5. Interface controllers, cabinets,
cablings, power supplies, etc
Hardware subtotal
6. Spare Parts
(20 percent of total
hardware cost)
TOTAL HARDWARE COST
B. Software Cost
C. Auxiliary Cost
TOTAL SYSTEM COST
Internal Cost
A. Project Management
B. System Maintenance Training
C. Training Expenses
D. Hydro-units Site Preparation
E . Co mm u n i c at i o n I n s t a l ·1 at i o n S u p p o r t
TOTAL INTERNAL COST
10-7
$ 8~622,000
3,606,000
$12,228,000
$ 380~000
175,000
70,000
240,000
60,000
$ 925,000
169,000
$1,094,000
$1,200,000
$ 700,000
$2,994,000
$ 800,000
160,000
50,000
780,000
85,000
$1,875~000
Total Susitna River Hydroelectric
In-Plant Monitorinq and Control
System Project Co~f
A. System Cost
B. Internal Cost
TOTAL COST
(c) Communication Project Cost
(d) Alternative II,
Total Project Cost
A. Total EMS Project Cost
B. Total Susitna River Hydroelectric
In-Plant Monitor and Control Cost.
System Project Cost
C . To t a 1 C o mm u n i c a t i o n C o s t
TOTAL ALTERNATIVE II PROJECT COST
10.4 -EMS Control Center Cost
(a) Control Center Building Cost
1. Building Architect 1 s Cost
2. Building Construction Cost
14,537 ft2, $220/ft2
TOTAL COST
(b) Additional Costs
... parking
-landscaping
-access roads
-A/C power line (2 mi)
Subtotal
(c) UPS and Diesel Generator
-UPS (50 kVA), including batteries
-diesel generator
Subtotal
(d) Special, Stand-Alone
Air-conditioning
- 3 units
(e) Total Cost, EMS Control Center
10-8
$2,994,000
1,875,000
$4,869,000
$5,100,000
$12,228,000
4,869,000
5,100,000
$22,197,000
$ 160,000
3,198,140
$3,358,140
$ 70,000
50,000
50,000
70,000
$ 240,000
$ 120,000
90,000
$ 210,000
$ 4 5, 000
$3,853,140
11 -RECOMMENDATION
W e r e c o mm en d t h e i m p 1 em e n t at i o n o f A 1 t e r n at i v e · I , R a i 1 b e 1 t
Energy Management System for the monitoring and control of
the power transmission network and generation facilities as
the most cost-effective system approach.
We do not recommend Alternative II system approach, because
this option wi 11 create unnecessary problems with the
interconnected utilities in the area of automatic generation
control (direct control of generating units by the EMS system
1 o c ate d at the W i 1 1 ow Con t r o 1 Center) .
We further recommend the procurement and installation of a
microwave system for the interconnected power transmission
network and generating facilities located in the Rail belt
are a.
11-1
SUSITNA HYDROELECTRIC PROJECT
PLANNING MEMORANDUM
SUBTASl< 8.02
PRELIMINARY TRANSMISSION
SYSTEM ANALYSIS
ATTACHMENT 2
PREFACE
This Planning Memorandum is an interim report to describe the preliminary
analyses carried out under Subtask 8.02, "Electric System Studies". In
view of the uncertainty of a number of system parameters, some sweeping
assumptions had to be made to be able to carry out this preliminary
analysis.
One important item which is still undecided at the time of this writing
is the interconnection configuration of the Susitna transmission with the
utilities in the Anchorage area. The technical analyses, including
transmission line energizing, load flow and transient stability studies,
were performed assuming two major switching and transformer stations in
Anchorage, without knowledge of their locations, as shown in the system
diagrams in Figures 3.1 and 3.2. Due to later information, it was
proposed to base the economic comparison of the various transmission
alternatives on a single switching station at the western terminal of a
230-kV cable crossing of K.nik Arm. The costs of the cable crossing,
being common to all alternatives, were excluded from the comparison.
The final common configuration will have to be determined, as will a
number of other parameters, before the technical and economic analyses
can be completed. The capital and operating costs of all components of
the Susitna transmission system will then have to be included in the
economic comparison of alternatives. It is expected that the conclusions
drawn from this study will not be significantly affected by the resulting
changes in system parameters.
TABLE OF CONTENTS
LIST OF TABLES ................................................................................................................................................ ...
LIST OF FIGURES ------------------------------------------------
-INTRODUCTION -----------------------------------------------
2 -SUMMARY ---------------------------------------------------
3 -DESCRIPTION AND RESULTS OF STUDIES ........................................................................ ...
3.1 -Planning Criteria------------------------------------
3.2 -Existing System Data --------------------------------
3.3 -System Load Forecast ---------------------------------
3.3.1 -Load Levels ----------------------------------------
3.3.2 -Load Distribution-----------------------------------
3.3.3 -Load Power Factors --------------------------------
3.4 -System Configuration -Ac Alternatives ---------------
3.4.1 -Susitna Configuration------... -----------------------
3.4.2 -switching at Willow ............................................................................................. ...
3. 4.3 -Switching at Healy ---------------------------------
3.4.4 -Anchorage Configuration----------------------------
3.4.5 -Fairbanks Configuration ---------------------------...
3.5 -Alternating Current Alternatives Analyzed ------------
3.5.1 -Susitna to Anchorage Transrnission Alternatives -----
3.5.2 -Susitna to Fairbanks Transmission Alternatives ................
3.5.3 -Total System Alternatives --------------------------
3.6 -Electric system Studies ....................................................................................... ...
3.6.1 -Power Transfer-------------------------------------
3.6.2 -Conductor Sizes ------------------------------... ----
3.6.3 -Line Energizing --,---.-------------------------------
3.6.4 -Load Flow studies ---------------------------------
3.6.5 -Transient Stability --------------------------------
3.7 -Economic Studies ------------------... -----------------
3.7.1 -Cost Estimates -------------------------------------
3.7.2 -Life-Cycle Costs ----------------------------------
3.8 -HVDC Transtnission ------------------------·-----------
3.8.1 -General--------------------------------------------
3.8.2 -Comparative Transmission systems ...................................................... ...
3.8.3 -Comparative Costs ----------------------------------
4 -CONCLUSIONS ----------------------------------------------
5 -RECOMMENDATIONS ................................. ..,. ............................................................................................. ...
APPENDIX A -TRANSMISSION PLANNING CRITERIA
APPENDIX B -EXISTING TRANSMISSION SYSTEM DATA
APPENOIX C -ECONCMIC CONDUCTOR SIZES
APPENDIX D ... COST ESTIMATES
APPENDIX E .... HVDC TRANSM.ISSION
i
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2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
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Page
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-10
-10
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-12
-14
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-17 -17
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-1
-
LIST OF TABLES
Number
3.2
3.3
3.5
3.6
3.7
3.8
3.9
3.10
3.11
3.12
3.13
3.14
3.15
3.16
Title
Railbelt Region Peak and Energy Demand Forecasts Used for
Generation Planning Studies
Staging of the Susitna Development
Maximum Power to be Transmitted to Anchorage and Fairbanks
for Each Stage of the Susitna Development
Line Losses Under Maximum Power Transmission
Transmission Line Energizing -Transmission Alternative 1
Transmission Line Energizing -Transmission Alternative 2
Transmission Line Energizing -Transmission Alternative 5
.Ratings of Reactive Compensation Required
Transmission and Substation Unit Costs
Life Cycle Costs -Transmission Alternative 1
Li.fe Cycle Costs -Transmission Alternative 2
Life Cycle Costs -Transmission Alternative 3
Life Cycle Costs -Transmission Alternative 4
Life Cycle Costs -Transmission Alternative 5
Summary of Life Cycle Costs
Summary of Comparative Costs -ac Versus de Transmission
ii
LIST OF FIGURES
Number,
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
Title
Transmission System Configuration -Alternative l
Transmission System Configuration -Alterna~ive 2
Peak Demand Flow -Alternative l -85 Percent Load at
Anchorage
Peak Demand Flow -Alternative l -25 Percent Load at
Fairbanks
Peak Demand Flow -Alternative 2 -85 Percent Load at
Anchorage
Peak Demand Flow -Alternative 2 -25 Percent Load at
Fairbanks
Transient Stability Swing Curves -Alternative l -85 Percent
Load at Anchorage
Transient Stability Swing Curves -Alternative 1 -25 Percent
Load at Fairbanks
Transient Stability Swing Curves -Alternative 2 -85 Percent
Load at Anchorage
Transient Stability Swing Curves -Alternative 2 -25 Percent
Load at Fairbanks
iii
1 -INTRODUCTION
The Plan of Study (POS) for the Susitna hydroelectric project, which is
currently being undertaken for the Alaska Power Authority (APA) by Acres
American Incorporated includes studies. of the required transmission
system under Task 8.
Subtask 8.02 of Task 8 is entitled Electric System Studies. The
objective of this subtask, as defined in the February 1980 POS is as
follows.
"To ensure that the electrical aspects of the project design are
integrated with the existing Railbelt area power systems and to design an
electrical power system which is reliable and economic."
The transmission system for the Susitna project, as currently envisaged,
will ultimately involve lines from the Watana and Devil canyon sites to
both Fairbanks and Anchorage. The system is to be designed in such a way
that the proposed intertie between Anchorage and Fairbanks, which is
presently under study for APA by Commonwealth Associates, will eventually
become part of the Susitna transmission system.
Work on Subtask 8.02 commenced in June 1980 and is scheduled to be
complete by March 1982. The purpose of this Planning Memorandum is to
present the results of the ~eliminary analysis completed under
Subtask 8.02 through June 15, 1981.
1 - 1
2 -SUMMARY
The studies are best summarized by outlining the scope of the work to be
performed.
The scope of work includes
-develop transmission system planning criteria
-assemble all data describing existing Railbel t power systems
-study the present and projected load distribution to Anchorage and
Fairbanks
-determine delivery points for Susitna power into local utility systems
-determine line loadings for the Susitna transmission system -propose
alternative preliminary system configurations
-prepare preliminary cost estimates for alternative system
configurations
-perform preliminary screening of various alternatives
-recommend transmission system configuration, voltage and conductor
sizes.
Based on the results obtained from the above activities a transmission
alternative is recommended which best satisfies the technical planning
criteria at an economical cost. The recommended option, called
A1 ternative 2 in this study, has the following major characteristics.
2 - 1
Transmission Line Number of Conductor
Section Len9:th Circuts Volta9:e Size
(mi) (kV) ( kcmil)
Watana -Devil Canyon 27 2 345 2 X 954
Devil Canyon -Willow 90 3 345 2 X 954
Willow -Anchorage 50 3 345 2 X 954
Devil canyon -Fairbanks 189 2 345 2 X 795
2 - 2
3 -DESCRIPTION AND RESULTS
OF STUDIES
3.1 -Planning Criteria
The planning criteria were developed to ensure the design of a reliable
and economic electrical power system, with components which are rated to
allow a smooth transition through early project stages to the ultimately
fully developed potential.
System planning criteria were submitted to APA in August 1980 and
subsequently accepted without comment. As a result of the better
understanding of the Susitna transmission system, gained from the
preliminary analyses carried out to date, revised criteria were proposed
as outlined in Appendix A. In the revision, some of the criteria were
modified to allow for larger variations in performance parameters during
early stages of project development. Strict application of optimum,
long-term criteria would require the installation of equipment with
ratings larger than necessary and at excessive cost. In the interest of
economy and long-term system performance, these criteria were temporarily
relaxed during early development stages of the project.
While allowing for satisfactory operation during early system
development, final system parameters must be based on the ultimate
Susitna potential.
The criteria are based on the desirability to maintain rated power flow
to Anchorage and Fairbanks during the outage of any single line or
transformer element. The essential features of the criteria are
-total power output of Susitna to be delivered to one or two stations at
Anchorage and one at Fairbanks
-"breaker-and-a-half'' switching station arrangements
3 -1
dynamic overvoltages during line energizing not to exceed specified
limits
-system voltages to be within established limits during normal
operation
-power delivered to the loads to be maintained and system voltages to be
kept within established limits for system operation under emergency
conditions
-transient stability during a 3-phase line fault cleared by breaker
action with no reclosing
-where performance limits are exceeded, the most cost effective
corrective measures are to be taken.
3.2 -Existing System Data
The data on the existing power systems in the Railbelt area were
assembled by R. w. Retherford Associates. These data have been compiled
in a draft report by Commonwealth Associates Inc., dated November 1980
and entitled "lmchorage-Fairbanks Transmission Intertie -Transmission
System Data". This report is included, with minor revisions, as
Appendix B. other system data were obtained in the form of single-line
diagrams from the various utilities.
3.3 -System Load Forecast
3.3.1 -Load.Levels
Energy and peak demand forecasts were prepared for the Alaska
Railbelt region by the Institute for Social and Economic Resea,rch,
University of Alaska (ISER). These were modified to account for
3 -2
self-supplied industrial and military generation as well as
expected results of load management and conservation efforts. The
resulting low, medium and high forecasts of peak and energy demand,
as shown in Table 3.1, were used in the generation planning
analyses of Subtask 6.36.
3.3.2 -Load Distribution
At present, the total Railbelt system load is shared approximately
80 percent by Anchorage and 20 percent by Fairbanks. While the
projections of various load forecasts vary somewhat around these
figures, the predicted changes are small. To account for the
uncertainty in future development, the transmission system was
designed to allow for this load sharing to vary from a maximum of
85 percent of Susitna generating capacity at'Anchorage to a maximum
of 25 percent at Fairbanks.
3.3.3 -Load Power Factors
Loads were represented in the electric system studies at the
highest subtransmission level at each load center transformer
station, generally 138 kV. Subtransmission at 138 kV from the
point of delivery of Susitna power was considered to be the
responsibility of individual utilities. As such it was not
included in the system simulation. Load power factors were assumed
to be corrected to 0. 95. Conditions of low voltages were corrected
with the help of additional static var generation at the EHV/138-kV
. transformer station. During detail design stages, it may prove
advantag.eous to carry out most of this power factor correction at
lower voltages in the distribution network. This method is
expected to be more cost effective in equipment costs and result in
operational advantages as well.
3 ... 3
3.4 -System Configuration -
AC Alternatives
Alternative configurations for the proposed transmission system were
developed after reviewing the existing system configurations at both
Anchorage and Fairbanks as well as the possibilities and development
plans in the Susitna, Anchorage, Fairbanks, Willow and Healy areas.
3.4.1 -Susitna Configuration
Preliminary development plans indicate that the first project to be
constructed would be Watana with an initial installed capacity of
400 MW to be increased to approximately 800 MW in the second
development stage. The next project, and the last to be considered
in this study, is Devil Canyon with an installed capacity of 400 MW
to 600 MW.
Devil Canyon and Gold Creek were considered as the sites for a
major switching station to collect all of the Susitna generation
for transmission to Anchorage and Fairbanks. Switching at Gold
Creek would involve the construction and operating cost of one
additional station. It would require a larger number of circuit
breakers but would reduce the number of transmission circuits in
the canyon. Uncertainty about detail line routing and access
requirements make a switching station at Gold Creek less desirable.
A cost comparison between the two alternative configurations proved
that a switching station at Devil Canyon is more economical than at
Gold Creek. In the light of all these factors, it is considered
advantageous to base present studies on a switching station located
at Devil Canyon with transmission directly from there to Anchorage
and Fairbanks.
3 -4
3.4.2 -Switching at Willow
Transmission from Susi tna to Anchorage is facilitated by the
introduction of an intermediate switching station. This has the
effect of reducing line energizing overvoltages and reducing the
impact of line outages on system stability. Willow is a suitable
location for this intermediate switching station and in addition it
would make it possible to supply local load when this is justified
by development in the area. This local load is expected to be less
than 10 percent of the total Railbelt area system load, but the
availability of an EHV line tap would definitely facilitate future
power supply.
3.4.3 -Switching at Healy
A switching station at Healy was considered early in the analysis,
but was found not to be necessary to satisfy the planning criteria.
The predicted load at Healy is small enough to be supplied by the
local. generation and the existing 138-kV transmission from
Fairbanks.
3.4.4 -Anchorage Configuration
In its 1975 report on the Upper Susitna River Hydroelectric
Studies, the United States Department of the Interior Corps of
Engineers favored a transmission route terminating at Point
MacKenzie.
The 1979 Economic Feasibility Study Report for the Anchorage-
Fairbanks Intertie by International Engineering Company Inc.
(IECo) recommends one circuit from Susitna terminating at Point
MacKenzie and another passing through Palmer and Eklutna
substations to Anchorage along the eastern side of Knik Arm.
3 - 5
At the beginning of the studies, it was assumed that Susitna power
would be delivered to Anchorage through two major transformer
stations. Initially, it was thought that one of these might be
near Palmer and the other "elsewhere" without detailed knowledge of
its location.
Analysis of system configuration, distribution of loads and
development in the Anchorage area reveals that a transformer
station near Palmer would be of little benefit. Most of the major
loads are concentrated in and around the urban Anchorage area at
the mouth of Knik Arm. In order to reduce the length of
subtransmission feeders, the transformer stations should be located
as close to Anchorage as possible.
The routing of transmission into Anchorage may be chosen from three
possible alternatives.
(a) Submarine cable crossing from Point MacKenzie to Point
Woronzof. This would require transmission through a very
heavily developed area. It would also expose the cables to
damage by ship's anchors, as has been experienced with
existing cables, thus resulting in questionable transmission
reliability.
(b) Overland route north of Knik Arm via Palmer. This is likely
most economical in terms of capital cost in spite of the long
distance involved. However, approval for this route is
unlikely since overhead transmission through this developed
area is considered environmentally unacceptable. A longer
over land route around the developed area is considered
unacceptable because of the mountainous terrain.
(c) Submarine cable crossing of Knik Arm, in the area of Lake
Lorraine and Six Mile Creek, approximately parallel to the new
230-kV cable under construction for Chugach Electric
3 - 6
Association (CEA). This option, including some 3 to 4 miles
of submarine cable, requires a high capital cost. Being
upstream from the shipping lanes to the port of Anchorage it
would result in a reliable transmission link, and one that
would not have to cross environmentally sensitive conservation
areas.
The load flow and stability studies were carried out assuming two
major switching and transformer stations, without knowledge of
their locations, as shown in the system diagrams in Figures 3.1 and
3.2. Later information from the field indicated that Susitna power
would likely be delivered to a single 345/230-kV station at the
western terminal of the cable crossing outlined in option (c)
above. The cost of the cable crossing (at 230 kV) would be common
to all transmission alternatives under this option. This cost was
thus excluded from the economic analysis comparing the five
alternatives in this planning memorandum. The final analysis will
benefit from more definitive knowledge regarding the most likely
transmission routing and locations of Anchorage transformer
stations. The costs of cable crossings and terminal stations for
the EHV system will then be included in the final economic
comparisons between the various transmission alternatives.
3. 4.5 -Fairbanks Configuration
Susitna power for the Fairbanks area is recommended to be delivered
to a single EHV/138-kV transformer station located at Ester.
3.5 -Alternating Current
Alternatives Analyzed
Because of the geographic location of the various centers, transmission
from Susitna to Anchorage and Fairbanks will result in a radial system
configuration. This fact allows significant freedom in the choice of
3 - 7
transmission voltages, conductors, and other parameters for the two line
sections with only limited dependence between them. In the end, the
advantages of standardization for the entire system will have to be
compared to the benefits of optimizing each section on its own merits.
Transmission alternatives were developed for each of the two 'System areas
including voltage levels, number of circuits required, and other
parameters, to satisfy the necessary transmission requirements of each
area.
Having established the peak power to be delivered and the distances over
which it is to be transmitted, transmission voltages and number of
circuits required were determined. To maintain a consistency with
standard ANSI voltages used in other parts of the USA, the following
voltages were considered for Susitna transmission.
-Watana to Devil canyon or Gold 500 kV or 345 kV
-
Creek and on to Anchorage
Devil Canyon or Gold Creek to 345 kV or 230 kV
Fairbanks
3.5.1 -Susitna to Anchorage
Transmission Alternatives
Transmission at either of two different voltage levels could
reasonably provide the necessary power transfer capability over the
distance of approximately 140 miles between Devil Canyon and
Anchorage. These are 345 kV and 500 kV. The required transfer
capability is 85 percent of the ultimate generating capacity of
1,400 MW (1,190 MW). At 500 kV, two circuits would provide more
than adequate capability. At 345 kV either three circuits
uncompensated, or two circuits with series compensation are
required to provide the necessary reliability for the single
contingency outage criterion. At lower voltages, an excessive
3 - 8
number of parallel circuits would be required while above 500 kV
two circuits are still needed to provide service in the event of a
line outage.
3.5.2 -Susitna to Fairbanks
Transmission Alternatives
Using the same reasoning as for the choic~ of transmission
alternatives to Anchorage, two circuits of either 230 kV or 345 kV
were chosen for the section from Devil Canyon to Fairbanks. The
230-kV alternative requires series compensation to satisfy the
planning criteria in case of a line outage.
3. 5 .• 3 -Total System Alternatives
The above-mentioned transmission section alternatives were combined
into five realistic total system alternatives. Three of the five
alternatives have different voltages for the two sections. The
principal parameters of the five transmission system alternatives
to be analyzed in detail are as follows.
Alternative
1
2
3
4
5
Susitna to
Anchorage
Number of
Circuits
2
3
2
3
2
*Denotes series compensation.
Voltage
(kV)
345*
345
345*
345
500
3 - 9
Susitna to
Fairbanks
Number of
Circuits
2
2
2
2
2
Voltage
(kV)
345
345
230*
230*
230*
Single-line diagrams explaining the details of the two most
promising system configurations, Alternatives 1 and 2, are shown in
Figures 3.1 and 3.2.
3.6 -Electric System Studies
Early in the system studies, it was realized that 345 kV was the one
voltage which showed greatest promise for transmission from Susitna to
both Anchorage and Fairbanks. A 500-kV system has higher transmission
capabilities but at significantly higher costs. Transmission at 230 kV
is insufficient for the section from Susitna to Anchorage, and all dual
voltage systems have increased complications and decreased reliability at
little or no economic advantage. For these reasons, 500-kV and 230-kV
system alternatives were only analyzed sufficiently to determine their
equipment ratings so that cost estimates could be prepared.
3.6.1 -Power Transfer
After studying various reports and obtaining preliminary
information on the staging of Susitna from Subtask 6.36, Generation
Planning, the electric system studies were able to proceed in
December 1980. Table 3.2 shows the preliminary staging schedule
for the Susitna developnent. The maximum power to be transmitted
to Anchorage and Fairbanks for each stage of development, based on
the 85 percent and 25 percent limits is given in Table 3.3. The
load power factor is assumed to be 0.95 and the power factor rating
of the Susitna generators is assumed to be 0. 90.
Following determination of the system power transfer requirements
for each stage of Susitna development, alternative system
configurations were developed taking into account the following
3 -10
-initial Susitna development at the Watana site
- a major switching station at Devil Canyon or near Gold Creek
-possible intermediate switching at Willow and Healy.
Preliminary line lengths for the system configurations under study
were obtained from Subtask 8. 03, Transmission Line Route
Selection.
3.6.2 -Conductor Sizes
Based on the transmission and power transfer requirements at the
various stages of Susitna development, economic conductor sizes are
determined. The methodology used to obtain the economic conductor
size and the results obtained are outlined in Appendix C, Economic
Conductor Sizes. Also included in Appendix C are the capitalized
costs of transmission line losses. The costs of these losses are
taken into account in com~ring the overall costs of alternative
transmission schemes.
When determining appropriate conductor size, the economic conductor
is checked for radio interference (RI) and corona performance. If
RI and corona performance are within acceptable limits, then the
economic conductor size is used. However, where the RI and corona
performance are found to be limiting, the conductor selection is
based on these requirements.
Total line losses for the proposed conductor size for each of the
different line voltages being considered are given in Table 3. 4.
These losses are for the alternatives where a major switching
station is located at Devil Canyon. The losses given are the total
line losses for transmission from Devil Canyon to Anchorage and
from Devil Canyon to Fairbanks. The line from Devil Canyon to
Anchorage is 155 miles long. The losses were calculated for the
3 -11
maximum expected power transfer to Anchorage and to Fairbanks for
each of the stages of the Susitna development as given in
Table 3.3.
3.6.3 -Line Energizing
Transmission line energizing studies were carried out to determine
the need for and ratings of reactive shunt compensation at the
receiving ends of transmission line sections at the various
voltages. This compensation is required to limit overvoltages
during line energizing to acceptable levels. Shunt reactors are
required at Willow and Anchorage for the 500-kV transmission
alternative and at Fairbanks for 345-kV transmission. These
reactors are switched with EHV breakers directly to the respective
transmission lines in order to be connected prior to energizing of
the line sections. The breakers are required to disconnect the
reactors at times of heavy line flows, and especially during line
outage conditions. This arrangement reduces the need for
capacitive var generation to compensate for the reactors. The
results of the line energizing analysis are shown in Tables 3.5 to
3.7. Included in the tables are values which fall outside the
proposed planning critera and must be corrected with shunt reactors
as indicated.
3.6.4 -Load Flow Studies
Load flow studies confirmed satisfactory system performance under
both normal and emergency conditions for all transmission
alternatives. Emergency conditions tested include outages of any
single 345-kV transmission circuit for the 345-kV alternatives as
well as the critical outages of a 500-kV circuit between Devil
Canyon and Willow and a 230-kV circuit between Devil Canyon and
Fairbanks for the 500-kV and 230-kV alternatives.
3 -12
Voltages on the 138-kV and 230-kV load buses range from 0.99 to
1.02 per unit for normal operation and from 0.93 to 1.02 per unit
under emergency outage conditions. Voltage ranges on the EHV
systems were 0.95 to 1.04 and 0.90 to 1.04 for normal and emergency
conditions, respectively.
Load conditions were assumed to be at peak demand with Susitna
generation fully utilized and only minimal other generation
available on the system. This situation is expected to result in
the most critical operating conditions. Total load is 1,600 MW at
a power factor of 0.95. System load distribution was simulated at
a maximum of 85 percent of the total load for Anchorage and a
maximum of 25 percent for Fairbanks. Generation assumed for the
above load conditions includes SUsitna capability fully utilized
(Watana 800 MW, Devil Canyon 600 MW) plus 300 MW of coal-fired
generation at Beluga and 100 MW of gas turbines at each of
Anchorage and Fairbanks. All of the thermal units are assumed to
be running'at approximately half load in order to provide 250 MW of
spinning reserve.
Load flow diagrams showing normal system operation at peak demand
for 85/15 percent and 75/25 percent load sharing for transmission
Alternatives 1 and 2 are included as Figures 3.3 to 3.6. The load
flow diagrams show a system configuration containing two terminal
stations in Anchorage with a subtransmission voltage of 138 kV.
Transmission from Beluga is represented as a 345-kV infeed. In the
final analysis the transmission between Willow and Anchorage will
include approximately four miles of submarine cable for the Knik
Arm crossing, but this is not represented in the initial studies.
Switching of the 345-kV shunt reactors at Fairbanks is not shown in
the diagrams, but these will be disconnected for peak demand and
line outage conditions as required. While these changes have
significant effects on transmission system equipment costs, they do
I
not significantly affect system operation. For this reason, they
were included in the latest cost estimates but not in the electric
3 -13
system studies to avoid repeated updating of system parameters.
System performance was found to be critical for line outages
between Devil canyon and Willow and between Devil canyon and
Fairbanks. Consequently, it was these line outages which
determined the ratings of static var sources and series
compensation.
The required ratings of compensation equipment for the five
transmission alternatives are listed in Table 3.8.
3.6.5 -Trans;ient Stability
Detailed transient stability studies were carried out only for the
345-kV transmission Alternatives 1 and 2.
Before the studies had advanced to the stage of stability analysis,
alternatives containing 500-kV or 230-kV transmission had been
recognized to be noncompetitive with the remaining 345-kV
alternatives, on either economic or technical grounds. A 500-kV
transmission to Anchorage would have sufficient surplus capability
to ensure stable operation. On the other hand, should 230-kV
transmission to Fairbanks ever have to be reconsidered, transient
stability would still need to be confirmed.
As outlined in the planning criteria, the design fault for
transient stability analysis is a 3-phase fault. In the
preliminary studies, the fault was cleared in 4.8 cycles at both
ends of the faulted line section, rather than in 4.8 and 6 cycles
at the near and remote ends, respectively, as stipulated in the
planning criteria. A test run for the most critical system
condition confirmed that the additional delay does not
significantly affect system performance.
Transient stability was analyzed for a 3-phase fault on the 345-kV
line from Devil Canyon to Willow (with 85 percent of the system
3 -14
load at Anchorage) and similarly on the line from Devil canyon to
Fairbanks (with 25 percent of system load at Fairbanks). To
simulate worst conditions, the fault was assumed to be near Devil
canyon in both cases. The fault was cleared in 4.8 cycles without
reclosure. System transient behavior was observed .for a period of
1 second after the fault. Exciter and governor response in the
transient interval was ignored. The dynamic voltage regulating
capabilities of the static var sources at Anchorage and Fairbanks
were ignored as well. For the final analysis a revised computer
model (with representation of dynamically variable static var
sources) will be available.
The attached swing curves, Figures 3.7 to 3.10, show the rotor
angles of all generators relative to the rotor angles at Watana.
All generators recover from the first and second swings for both
transmission alternatives. The actions of exciters and governors
should ensure that these swings are damped out and return the
system to a new equilibrium after each disturbance. System
transient behavior seems to be quite sensitive to the generation
on-line at both Anchorage and Fairbanks at the time of a fault.
Detailed analysis at the design stages will have to determine the
minimum spinning reserve required at both Anchorage and Fairbanks
to ensure system stability in the event of a major fault. The
transient studies are considered adequate to confirm the stability
of the system configuration and the primary equipment parameters
needed to ensure satisfactory operation.
3.7-Economic Studies
Economic studies were carried out to determine the capital and operating
costs and to compare the total life cycle costs of the various
transmission alternatives. The economic studies exclude the costs of the
Knik Arm crossing and terminal stations in Anchorage. These were
considered common to all alternatives (for a 230-kV crossing). They will
have to be included in the final analysis.
3 -15
3.7.1 -Cost Estimates
The transmission cost estimates include all costs for transmission
lines and substations. All estimates include the costs of land
acquisition and clearing. Included in the substation cost
estimates are site preparation and all equipment costs for circuit
breakers, transformers, shunt reactors, static var sources and
transmission line series capacitors. Cost estimates of major
equipment include the costs of all ancillaries such as disconnect
switches, potential transformers, current transformers, controls,
instrumentation, etc. At the generating stations all EHV circuit
breakers are included, but generator transformers and low-voltage
breakers are excluded. These are included in the powerhouse
estimates. Similarly at the load centers all EHV breakers are
included as well as the necessary circuit entries at the
subtransmission voltage (230 kV or 138 kV) for each transformer
bank. The remainder of the lower voltage station is common to all
alternatives and therefore excluded from the comparison. At
Anchorage, transformation to 230 kV is assumed on the west side of
Knik Arm implying cable crossings at 230 kV. The cable crossings
and other 230-kV equipment are considered common to all ac
transmission alternatives for Susitna and their costs have been
excluded from this comparison. They must be included for
comparison of schemes with different Knik Arm crossing
configurations such as HVDC transmission from Susitna.
The unit costs and assumptions in the cost estimates are shown in
Table 3.9.
All details on which the cost estimates are based are given in
detail in Appendix D.
3 -16
3.7.2-Life-Cycle Costs
Life-cycle costs for each transmission alternative were calculated
by discounting all cost components over a SO-year lifetime from
1993 to 2043 to a common present worth datum of 1981. The
calculations and results of total present-worth costs are shown in
Tables 3.10 to 3.14. Included in the life-cycle costs are capital
(including engineering, contingencies, land acquisition and
clearing and bond commission). Also included are the capitalized
annual costs of operation and maintenance, insurance, interim
replacement, contribution in lieu of taxes, and transmission
losses. A summary of present-worth life-cycle system costs for all
five transmission alternatives is shown in Table 3.15.
3.8 -HVDC Transmission
In order to determine the relative economics of HVDC as compared to the
preferred ac transmission alternative an economic screening was carried
out. The details of this analysis are given in Appendix E, and the
results and significant features are summarized here.
3.8.1 -General
A HVDC transmission system linking Susitna generation with the
Anchorage and Fairbanks load areas would need to be either one
3-terminal system or two 2-terminal systems. Another alternative
would be a combined scheme using ac transmission from Susitna to
one load center and de transmission to the other. In order to
ensure that no possible economic combination is overlooked,
transmission to Anchorage and Fairbanks are considered separately.
3 -17
3.8.2 -Comparative Transmission
Systems
The ac and HVDC transmission systems whose costs are compared are
essentially comparable in terms of security of supply. Each
alternative is planned to maintain rated transfer capability with
the single contingency outage of any element in the transmission
system.
{a) Ac Transmission
The ac transmission system which is considered as the base
case utilizes 345 kV with 3 circuits ultimately to Anchorage
and 2 circuits to Fairbanks. Transmission to the load centers
originates at a switching station at Devil Canyon with Watana
generation brought in at 345 kV.
Transmission to Fairbanks is direct to a 345-kV/138-kV
terminal station at the load center.
Transmission to Anchorage involves an intermediate switching
station at Willow and proceeds to a 345-kV/230-kV station on
the west side on Knik Arm. At this point transmission
continues via a 230-kV submarine cable* to the east side of
Knik Arm and into a terminal station from which local
distribution circuits would radiate.
*Transformation to 230 kV and use of 230-kV submarine cable is not
necessarily the optimum arrangement, but it is considered adequate for
the ac versus HVDC economic screening.
3 -18
(b) HVDC Transmission
The HVDC converter terminals are assumed to be located at
Devil Canyon with local ac transmission at 230 kV between
Watana and Devil Canyon.
Transmission to Fairbanks is via a single bipolar HVDC line
operating at ;t250 kV, with an inverter terminal and 138-kV
circuit entries at the load end.*
Transmission to Anchorage is also at .:!:,250 kV but would require
2 bipolar HVDC circuits to meet the security constraints.
These circuits would proceed directly to Anchorage, utilizing
HVDC submarine cables across Knik Arm and into an inverter
station on the east side of Knik Arm. The inverter output is
via 230-kV circuit entries which would supply local
distribution identical to the ac alternative. The cost of a
separate 230-kv ac supply from Point McKenzie to Willow is
allowed for, so that both ac and de alternatives would be
functionally equivalent.
3.8.3 -Comparative Costs
The details of equipment ratings and llll.it costs are given in
Appendix E; the results are summarized in Table 3.16.
Individual costs are given for line and terminal facilities in
order to illustrate the basic relationships between ac and HVDC
transmission costs. All capital costs are for the ultimate
installation with no discounting of staged components. The
*During the single contingency outage of one pole of the line or terminal
facilities, earth return would be utilized to maintain rated power flow
to Fairbanks.
3 -19
capitalization of annual charges such as operating costs and the
cost of losses is at 3 percent discount rate over the 50-yr life of
facilities.
As the comparative costs show there is no obvious cost advantage
favoring HVDC over ac transmission either to Anchorage or to
Fairbanks. This is particularly true in the case of Anchorage
where HVDC is over 20 percent more costly than ac transmission.
The margin favoring ac is only 8 percent in the case of
transmission to Fairbanks, and although this might be reduced by
further study, it is unlikely the savings would be sufficient to
justify the operating complexity of combined ac and HVDC systems.
On the basis of this economic screening it is concluded that ac is
an appropriate choice for transmission from Susitna to the load
centers at Anchorage and Fairbanks.
3 -20
TABLE 3.1: RAILBELT RgGION PEAK AND ENERGY DEMAND FORECASTS
USED FOR GENERATION PLANNING STUDIES
L 0 AD C A S E
Low Plus Load
Management and
Conservation 1 (LES-GL Adjusted)
Low 2 (LES-GL)
Medium 3 (MES-GM)
High 4 (HES-GH)
Load Load Load
Year MW GWh Factor MW GWh Factor MW GWh Factor MW GWh
1980 510 2790 62.5 510 2790 62.4 510 2790 62.4 510 2790
1985 560 3090 62.8 580 3160 62.4 650 3570 62.6 695 3860
1990 620 3430 63.2 640 3505 62.4 735 4030 62.6 920 5090
1995 685 3810 63.5 795 4350 62.3 945 5170 62.5 1295 7120
2000 755 4240 63.8 950 5210 62.3 1175 6430 62.4 1670 9170
2005 835 4690 64.1 1045 5700 62.2 1380 7530 62.3 2285 12540
2010 920 5200 64.4 1140 6220 62.2 1635 8940 62.4 2900 15930
Notes:
l LES-GL: Low economic growth/low government expenditure with load management and conservation.
2 LES-GL: Low economic growth/low government expenditure.
3 MES-GM: Medium economic growth/moderate government expenditure.
4 HES-GH: High economic growth/high government expenditure.
Load
Factor
62.4
63.4
63.1
62.8
62.6
62.6
62.7
Year
1993
1996
2000
2000 {optional)
TABLE 3.2: STAGING OF THE SUSITNA DEVELOPMENT
Susitna Capacity -MW
Watana
Increments
400
400
Total
400
800
Devil Canyon
Increments
400
200
Total
400
600
Susitna
Total
400
800
1,200
1,400
TABLE 3. 3: MAXIMUM POWER TO BE TRANSMITTED TO ANCHORAGE
Total Susitna
Capacity
{MW)
400
800
1,200
1,400
AND FAIRBANKS FOR EACH STAGE OF SUSITNA DEVELOPMENT
Maximum Power Transmission:
To Anchorage To Fairbanks
(~) ,.,
340
680
1,020
1,190
100
200
300
350
Note: For system planning purposes a maximum of 85 percent of Susitna
generation is assumed to be transmitted to Anchorage and a maximum
of 25 percent to Fairbanks.
TABLE 3.4: LINE LOSSES UNDER MAXIMUM POWER TRANSMISSION
Devil Can:t:on to Anchorage (155 mi)
Susitna Power 500 kV 345 kV 345 kV
CaEacity Transmitted 2 Circuits 2 Circuits 3 Circuits
(MW) (MW) (.MW) (MW) (MW}
400 340 1.5 3.2 2.9
800 680 6.2 12.8 11.2
1,200 1,020 13.8 28.8 25.5
1,400 1,190 18.8 39.2 35.3
Devil Canyon to Fairbanks (189 mi)
Susitna Power 345 kV 230 kV
CaEacit:t: Transmitted 2 Circuits 2 Circuits
(MW) (MW) (MW) (MW)
400 100 0.5 1.5
800 200 2.0 6.1
1,200 300 4.6 13.7
1,400 350 6.3 18.6
Transmission Alternative 1
Line Secti,on Length
(mil
Devil Canyon -189
Fairbanks
Devil Canyon -189
Fairbanks
Devil Canyon -189
Fairbanks
Devil Canyon -189
FairPanks
Devil Canyon -90
Willow3
Devil Canyon -90
Willow3
Devil canyon -90
Willowl
Willow -65 1
Anchor agel
Willow -651
Anchor agel
Willow -651
Anchorage)
Line
Reactors
(receiving
end)
(MVAR)
0
'75
75
75
0
0
0
0
0
0
No. of
Circuits
at 345 kV
2
2
2
2
2
2
2
2
2
2
TABLE 3,5; TRANSMISSION LINE ENERGIZING
No. and
Size of
Conductors
(kcrnil)
2 X 795
2 X 795
2 X 795
2 X 795
2 X 1272 1
Watana
Generation
(MW)
200
200
400
800
200
400
BOO
200
400
BOO
Sendint,J End
Short
Circuit
Level
(MVA)
541
541
1006
1768
541
1006
1768
436
696
992
Initial
Voltage
(per unit)
0.900
0.900
0.950
1.000
0.900
0.950
1.000
0.950
0.950
0.950
Final
Voltage
(per unit)
1.025
1.025
1.048
1.017
1.021
1.046
1.073
1.024
1.000
Voltage
Rise
(per unit)
0.125
0.075
0.048
0.117
0.071
0.046
o.Ul
0.074
0.050
Line
Flow
(MVAR)
229
85
85
89
80
80
84
64
58
55
Notes1 1The distance from Willow to Anchorage and conductor size from Susitna to Anchorage will be revised for the final analysis.
2shunt reactors are required at Fairbanks to satisfy voltage rise criteria.
3
Results for the line sections Devil Canyon -Willow -Anchorage are also valid for Transmission Alternative l.
Receiving
End
Voltage
(per unit)
1.028
1.028
1.051
1.035
1.038
1.063
1.083
1.033
1.009
TABLE 3.6: TRANSMISSION LINE ENERGIZING
Transmission Alternative 2
tine Sendin2 End
Reactors No. of No. and Short Receiving
(receiving Circuits Si2:e of Watana Circuit Initial Final Voltage Line End
Line Section Len2th end) at 345 kV Conductors Generation Level Volta2e Vo1ta2e Rise Flow Voltage
(mi) (MVAR) (kcmil) (MW) (MVA) (per unit) (per unit) (per unit) (MVAR) (per unit)
Devil Canyon -1B9 0 2 2 X 795 200 541 0.900 1.1B92 0.2892 229 1. 2B3 2
Fairbanks
Devil Canyon -1B9 75 2 2 X 795 200 541 0.900 1.025 0.125 B5 1.02B
Fairbanks
Devil Canyon -1B9 75 2 2 X 795 400 1006 0.950 1.025 0.075 B5 1.028
Fairbanks
Devil Canyon -189 75 2 2 X 795 BOO 176B 1.000 1.048 0.04B 89 1.051
Fairbanks
Devil Canyon -90 0 3 2 X 954 200 541 0.900 1.013 0.113 76 1.030
Willow3
Devil Canyon -90 0 3 2 X 954 400 1006 0.950 l.OlB 0.06B 77 1.035
Will owl
Devil Canyon -90 0 3 2 X 954 BOO 1768 1.000 1.044 0.044 Bl 1.062
Willow3
Willow -65 1 0 3 2 X 954 200 433 0.950 1.069 0.119 61 1.07B
Anchorage3
Willow -651 0 3 2 X 954 400 6BB 0.950 1.022 0.072 56 1.031
Anchorage3
Willow -651 .0 3 2 X 954 BOO 976 0,950 0.999 0.049 53 l.OOB
Anchor agel
Notes: 1The distance from Willow to Anchorage will be revised for the final analysis.
2 Fairbanks to satisfy Shunt reactors are required at voltage rise criteria.
3Results for the line sections Devil Canyon -Willow -Anchorage are also valid for Transmission Alternative 4.
TABLE 3. 7; TRANSMISSION LINE ENERGIZING
Transmission Alternative 5
Line Sending End
Reactors No. of No. and Short Receiving
(receiving Circuits Sh:e of Watana Circuit Initial Final Voltage Line End
Line Section Length end) at sao kv Conductors Generation Level Volta2e Volta2e Rise Flow Volta2e
(mi) {MVAR) (kcmil) (MW) (MVA) (per unit) (per unit) (per unit) (MiiAa) (per ~nit)
Devil Canyon -90 0 2 3 X 795 200 564 0.900 1.184 2 0.284 2 234 1.2052
Willow
Devil canyon -90 75 2 3 X 795 200 564 0.900 1.035 0.135 97 1.037
Willow
Devil Canyon -90 75 2 3 X 795 400 1091 0.950 1.027 0.077 96 1.029
Willow
Devil Canyon 90 75 2 3 X 795 800 2044 1.000 1.046 0.046 99 1.048
Willow
Willow -50 1 0 2 3 X 795 200 506 0.950 1.1372 0.187 2 ll9 1.143 2
Anchorage
Willow -so 1 50 2 3 X 795 200 506 0.950 1.027 0.077 44 1.026
Anchorage
Willow -so 1 50 2 3 X 795 400 892 1.000 1,049 0.049 46 1.049
Anchorage
Willow -so 1 50 2 3 X 795 800 1443 1.000 1.030 0.030 44 1,029
Anchorage
Notest 1'I'he distance from Willow to Anchorage will be revised for the final analysis.
2 Shunt reactors are required at Willow and Anchorage to satisfy voltage rise criteria.
3shunt compensation is not required for 230-kV lines Devil Canyon to Fairbanks, Alternatives 3, 4 and 5.
D FAIRBANKS
------E150/100 MW
100 MVAR
LEGEI\1 D
6> GENERATION
~ LOAD
Q STATIC VAR SOURCE
@ BUS NUMBER
...
...
REAL POWER FLOW ( MW)
REACTIVE POWER FLOW (MVAR)
CANNOT
SCAN
LARGE
MAP
'ENSATION
SR
~RY
SHUNT REACTOR
• 1.03 BUS VOLTAGE MAGNITUDE (PER UNIT)
~ BUS VOLTAGE PHASE ANGLE (DEGREES)
TRANSMISSION LINES
---• 345 KV
13'8 KV OR LOWER
NOTE: EQUIP.MENT RATINGS INDICATED ARE FOR
ULTIMATE INSTALLATION (YEAR 2000)
FIGURE-3.1
) FAIRBANKS
-e50/100MW
100 MVAR
LEGEND
...
...
-II
+
1.03
GENERATION
LOAD
STATIC VAR SOURCE
BUS NUMBER
REAL POWER FLOW ( MW)
REACTIVE POWER FLOW (MVAR)
CANNOT
SCAN
LARGE
MAP
BUS VOLTAGE MAGNITUDE (PER UNIT)
BUS VOLTAGE PHASE ANGLE (DEGREES)
TRANSMISSION LINES
345 KV
138 KV OR LOWER
NOTE' EQUIPMENT RATINGS INDICATED ARE FOR
ULTIMATE INSTALLATION (YEAR 2000)
l.;;l
FIGURE 3.2.
51 FAIRBANKS
50/IOOMW
17 ..
100 MVAR
I. 0 2 l.!..!:2_
LEGEND
8 . GENERATION
•----i LOAD
8) STATIC VAR SOURCE
~ BUS NUMBER
.,. REAL POWER FLOW ( MW )
., RI'"M'TIVI'" PnWER FLOW (MVAR)
(
1.03
CANNOT
SCAI\J
LARGE
MAP
EN SAT ION
R
RY
SHUNT REACTOR
BUS VOLTAGE MAGNITUDE (PER UNIT)
BUS VOLTAGE PHASE ANGLE (DEGREES)
TRANSMISSION LINES
----345 KV
13"8 KV OR LOWER
FIGURE 3.3 •
;v FAIRBANKS
lbL
~ ~50/IOOMW
57~'40-t-
100 MVAR
LEGEND
8 GENERATION
•-----i LOAD
8) STATIC VAR SOURCE
~ BUS NUMBER
.. -..
1.03
REAL POWER FLOW ( MW )
REACTIVE POWER FLOW (MVAR)
CAf\INOT
SCAN
LARGE
MAP
NSATION
SHUNT REACTOR
BUS VOLTAGE MAGNITUDE (PER UNIT)
BUS VOLTAGE PHASE ANGLE (DEGREES)
TRANSMISSION LINES
345 KV
13'8 KV OR LOWER
FIGURE 3.4 [i]
) FAIRBAI\JKS
4.8
·~50/IOOMW
100 MVAR
LEGEND
i .... ~
...
-
GENERATION
LOAD
STATIC VAR SOURCE
t!US NUMBER
REAL POWER FLOW ( MW )
REACTIVE POWER FLOW (MVAR)
CAI\INOT
SCAN
LARGE
MAP
~SAT ION
SHUNT REACTOR
1.03 · BUS VOLTAGE MAGNITUDE (PER UNIT)
~ BUS VOLTAGE PHASE ANGLE (DEGREES)
TRANSMISSION LINES
345 KV
13B KV OR LOWER
FIGURE 3.5 ~~till
) FAIRBANKS
·~50/IOOMlLES
~400
. ~
----.130
68~
IOOMVAR
LEGEND
8 GENERATION
E3) STATIC VAR SOURCE
@ BUS NUMBER
...
~
'
1.03
REAL POWER FLOW ( MW )
REACTIVE POWER FLOW (MVAR)
CANNOT
SCAN
LARGE
MAP
ISATION
::JR
BUS VOLTAGE MAGNITUDE (PER UNIT)
BUS VOLTAGE PHASE ANGLE (DEGREES)
TRANSMISSION LINES
345 KV
13B KV OR LOWER
FIGURE 3.6.
TABLE 3.8: RATINGS OF REACTIVE COMPENSATION REQUIRED
Fairbanks Anchorase Willow
Transmission Static VAR Shunt Series Static VAR Shunt Series Static VAR Shunt Series
Alternative Source Reactor Ca;eacitor Source Reactor ca;eacitor Source Reactor ca;eacitor
(MVAR) (MVAR) (MVAR) (MVAR) (MVAR) (MVAR) (MVAR) (MVAR) (MVAR)
1 100 2 X 75 400 430 773
2 100 2 X 75 400
3 200 430 400 430 773
4 200 430 400
5 200 430 200 2 X 50 2 X 75
TABLE 3.9: TRANSMISSION AND SUBSTATION UNIT COSTS
Transmission
Line Costs
Base Cost . l 1 F1.na Cost
Voltage Conductor $/Circuit Mile $/Circuit Mile
(kV) (kcmil)
230 1 X 954 120,000 162,000
2.30 1 X 1272 136,000 184,000
230 1 X 1351 140,000 189,000
345 2 X 795 190,000 256,000
345 2 X 954 207,000 279,ooo·
345 2 X 1351 251,000 339,000
500 3 X 795 326,000 440,000
Land Acquisition and Clearing
Voltage No. of Circuits $/Mile
(kV)
230 2 70,000
345 2 75,000
345 3 96,000
500 2 80,000
Table 3.9
Transmission and Substation Unit Costs - 2
Substations
Voltage Station Base Cost2 Circuit Breaker Position
(kV) ($ Million) ($ Million)
138 1.000 0.400
230 1.500 0.700
345 2.000 1.000
500 2.500 1.600
Autotransformers (including 15 kV tertiary}
Voltage
(kV)
230/138
345/138
500/138
345/230
500/230
Generator Transformers
Voltage
(kV)
345
500
75 MVA
($ Million)
0.500
0.700
$/kVA
4.20
5.00
150 MVP." 250 MVA
($ Million) ($ Million)
0.800 1.100
0.900 1.300
l. 200 1.600
0.900 l. 300
1.200 1.600
Table 3.9
Transmission and Substation Unit Costs -3
Shunt Reactors
Volta~e
(kV)
345
500
50 MVARS
($/kVAR)
24.60
Series Compensation (all voltages)
$14.00/kVAR
Static VAR Sources (tertiary voltage)
$30.00/kVAR
Notes:
75 MVARS
($/kVAR)
1.11
17.20
1 Final transmission line costs (Sheet 1) include 20 percent contingency
plus 5 percent engineering, 5 percent construction management, and
2.5 percent owner's cost.
2substation base cost {Sheet 2) includes land acquisitions, site
preparation, foundations, etc.
TABLE 3.10: LIFE CYCLE COSTS
Transmission Alternative l
Susitna to Anchorage - 2 x 345 kV, 2 x 1351 kcmil, 50 percent series compensation.
Susitna to Fairbanks - 2 x 345 kV, 2 x 795 kcmil, no series compensation.
1993 Costs 2000 Costs
Current $ x 106 1981 P.W. Current $ x 106 1981 P.W.
Line Capital
Line Capital Cost
1.5 percent Bond Commission
Total Line Cost
Land Acquisition
Capitalized Annual Charges
Capitalized Line Losses
Station Capital
Station Capital Cost
1.5 percent Bond Commission
Total Station Cost
Capitalized Annual Charges
1981 Present Worths
Total Life Cycle Cost
220.12
3.30
223.42
26.70
181.56
75.66
123.88
l. 86
125.74
135.46
156.70
18.73
127.34
53.07
44.74
0.67
88.19 45.41 25.90
95.01 45.60 26.01
539.04 51.91
Total
1981 P.W.
156.70
18.73
127.34
53.07
114.09
121.02
590.95
TABLE 3.11: LIFE CYCLE COSTS
Transmission Alternative 2
Susitna to Anchorage
Susitna to Fairbanks
3 x 345 kV 1 2 x 954 kcmil 1 no series compensation.
2 x 345 kV 1 2 x 795 kcmil 1 no series compensation.
1993 Costs 2000 Costs
Current $ x 106 1981 P.W. Current $ x 106 1981 P.W.
Line Capital
Line Capital Costs
1.5 percent Bond Commission
Total Line Cost
Land Acquisition
Capitalized Annual Charges
Capitalized Line Losses
Station Capital
Station Capital Cost
1.5 percent Bond Commission
Total Station Cost
Capitalized Annual Charges
1981 Present Worths
Total Life Cycle Cost
192.25
2.88
195.13
29.64
160.76
77.70
123.88
1.86
125.74
135.46
39.12
0.59
136.86 39.71 22.65
20.79
112.75 30.49 17.39
54.50
31.47
0.47
88.19 31.94 18.21
95.01 32.07 18.29
508.10 76.54
Total
1981 P.W.
159.51
20.79
130.14
54.50
106.40
113.30
584.64
TABLE 3.12: LIFE CYCLE COSTS
Transmission Alternative 3
Susitna to Anchorage
Susitna to Fairbanks
2 x 345 kV, 2 x 1351 kcmil, 50 percent series compensation.
2 x 230 kV, 1 x 1272 kcmil, 50 percent series compensation.
1993 Costs 2000 Costs
Current $ x 106 1981 P.W. Current $ x 106 1981 P.W.
Line Capital
Line Capital Cost
l. 5 percent Bond Commission
Total Line Cost
Land Acquisition
Capitalized Annual Charges
Capitalized Line Losses
Station Capital
Station Capital cost
1.5 percent Bond Commission
Total Station Cost
Capitalized Annual Charges
1981 Present Worths
Total Life Cycle Cost
188.18
2.82
191.00
25.76
153,17
91.97
135.95
2. 04
137.99
148.66
133.96
18.0'7
107.43
64.51
54.48
0.82
96.78 55.30 31.54
104.27 55.53 31.67 ----
525.02 63.21
Total
1981 P.W.
133.96
18.07
107.43
64.51
128.32
135.94
588.23
TABLE 3. 13: LIFE CYCLE COSTS
Transmission Alternative 4
Susitna to Anchorage -3 x 345 kV, 2 x 954 kcmil, no series compensation.
Susitna to Fairbanks -2 x 230 kV, 1 x 1272 kcmil, 50 percent series compensation.
1993 Costs 2000 Costs
Current $ x 106 1981 P.W. Current $ x 106 1981 P.W.
Line Capital
Line Capital Cost
1.5 percent Bond Commission
Total Line Cost
Land Acquisition
Capitalized Annual Charges
Capitalized Line Losses
Station Capital
Station Capital Cost
1.5 percent Bond Commission
Total Station Cost
Capitalized Annual Charges
1981 Present Worths
Total Life Cycle Cost
166,16
2.49
168.65
28.70
136.08
93.85
135.95
2.04
137.99
148.66
39.12
0.59
118.29 39.71 22.65
20.13
95.44 30.49 17.39
65.82
41.21
0.62
96.78 41.83 23.86
104.27 42.00 23.95
500.73 87.85
Total
1981 P.W.
140.94
20.13
112.83
65.82
120.64
128.22
588.58
TABLE 3.14: LIFE CYCLE COSTS
Transmission Alternative 5
Susitna to Anchorage 2 x 500 kV, 3 x 795 kcmil, no series compensation.
Susitna to Fairbanks - 2 x 230 kV, 1 x 1272 kcmil, 50 percent series compensation.
1993 Costs 2000 Costs
current $ x 106 1981 P.W. Current $ x 106 1981 P.W.
Line Capital
Line Capital Cost
1.5 percent Bond Commission
Total Line Cost
Land Acquisition
Capitalized Annual Charges
Capitalized Line Losses
Station Capital
Station capital Cost
1.5 percent Bond commission
Total Station Cost
Capitalized Annual Charges
1981 Present Worths
Total Life Cycle Cost
223.72
3.36
227.08
26.59
180, 95
61.05
185.06
2' 7 8
187.84
202.36
159.27
18.65
126.91
42.82
131.75
141.93
621.33
39.73
0.60
40.33 2 3. 00
40.49 2 3. 09
46.09
Total
1981 P.W.
159.27
18.65
126.91
42.82
154.75
165.02
667.42
Transmission Alternative
Transmission Lines
Capital
Land Acquisition
Capitalized Annual Charges
Capitalized Line Losses
Total Transmission Line Cost
Switching Stations
Capital
Capitalized Annual Charges
Total Switching Station Cost
Susitna Life Cycle Cost
TABLE 3.15: SUMMARY OF LIFE CYCLE COSTS
1981 $ X 106
1 2
156.70
18.73
127.34
53.07
355.84
ll4.09
121.02
235 .ll
590.95
159.51
20.79
130.14
54.50
364.94
106.40
ll3. 30
219.70
584.64
3
133.96
18.07
107.43
64.51
323.97
128. 32
135.94
264.26
588.23
4
140.94
20.13
ll2.83
65.82
339.72
120.64
128.22
248.86
588.58
5
159.27
18.65
126.91
42.82
347.65
154.75
165.02
319. 77
667.42
TABLE 3.16: SUMMARY OF COMPARATIVE COSTS AC VERSUS DC TRANSMISSION
Cost Components
Line Cost 1 line capital
line capitalized
land acquisition
O&Ml
3 (R.O.W.)
Station Costs 1 station capital 2 station capitalized O&M
4 Capitalized Cost of Losses
Total Costs
ComEarative Costs - $ Million
Transmission to Anchorage
AC DC
198.18 125.40
165.72 104.86
13.44 8.40
99.38 239.59
108.67 262.00
83.87 74.94
669.26 815.19
1 Line and station capital costs are developed in Appendix E.
Transmission
AC
96.77
80.92
14.18
35.32
38.62
13.72
279.53
to Fairbanks
DC
37.80
31.61
7.56
100.10
109.46
16.63
303.16
2 capitalized O&M charges include O&M, insurance, interim replacement and contributions in lieu of taxes. These
annual charges total 3.25 percent of transmission capital and 4.2~ percent of station capital, and they are
capitalized over 50 years at 3 percent.
3Land acquisition (R.O.W.) costs are estimated at $96,000/mile and $75,000/mile for 345 kV, 3 cct and 2 cct
transmission respectively, and $60,000/mile and $40,000/mile for ±250 kV de 2-circuit and single circuit,
respectively.
4 Losses are valued at 3.5¢/kW·h, and they are capitalized over the 50-year line life at 3 percent.
(f)
IJ.J
IJ.J a:::
(.!)
w a
(f)
IJ.J
.J
C) z
~
a::
f2
0 a::
a::: ~ a:::
IJ.J z w
(.!)
10~--------~----------~----------~----~--~~--------~
WATANA
0
I ~··· ··~ i .. ..
•• --. --""'!""'(:~t'f'(O» I ··t-··-·· oE'IJ\\..
. I -10 .
/
-20
-30
-40
\
\ -50 \
\
-60
-70~--------_.----------~----------._ ________ ~----------~ 0 0.2 0.4 0.6 0.8
TIME {SECONDS)
NOTE
-DISTURBANCE !S 3· PHASE FO.ULT AT DEVIL CANYON CLEARED IN 0.08 SECONDS
BY 3-PHASE TRIPPING OF DEVIL CANYON-WILLOW LJNE WITHOUT RECLOSURE
-ROTOR ANGULAR DISPLACEMENT PLOTTED IS THAT OF ALL GENERATORS
RELATIVE TO WATANA
TRANS1ENT STABILITY SWING CURVES-ALTERNATIVE I
85 °/o LOAD AT ANCHOR AGE FIGURE 3.7
1.0
U1
lU w a:
<.::> w a
U'l w
_j
<:> z
<(
a:
~
0 a:
a:
~
<(
a: w z w
<:>
10~---------r--~~----r---------~----------~--------~
I 0 ~--------~----------~IW_.AT•A•N•A._ __ ~~~------~--------~
I . .-.··~ ·---..__... •• _ I . , oE.'J\\.. c.e.. -,.._.._. __
I
--~ ..... ._ ..
-10 I
-20
-30
-40 .
I
-so .
-60
\ I I
I .
-70--------~~--~--~--------~--------~~·~_/~----~ 0 0.2 0.4 0.6 1.0
TIME (SECONDS)
NOTE
-DISTURBANCE IS 3· PHASE FAULT AT DEVIL CANYON CLEARED IN 0.08 SECONDS
BY 3-PHASE TRIPPING OF DEVIL CANYON-FAIRBANKS LINE WJTHOUT RECLOSURE
-ROTOR ANGULAR DISPLACEMENT PLOTTED IS THAT OF ALL GENERATORS
RELATIVE TO WATANA
TRANSIENT STABJUTY SWING CURVES-ALTERNATIVE I
25°/o LOAD AT FA1R8ANKS FIGURE 3.8
(/)
w w a::
(!)
l.LI a
(/) w
....l
(!) z
<(
a::
~
0 a::
a:: ~
<(
a:: w z w
(!)
IOr---------~-----------r----------~----------~--------~
0
-10
-2.0
-30
-40
-so
-60
-70
WATANA
I ~"' •• """' I ....... ·~---..... .. ........, --~~~f(O~ I .l ........._,__ .. oE.\J\\.. .. __.,.,
\ I
0 0.4 0.6 0.8
TIME (SECONDS)
NOTE
-OISTUR6ANCE IS 3-PHASE FAULTATOEVILCAN'I'ON CLEARED IN G.08 SECONDS
BY 3-PHASE TRIPPlNG OF DEVIL CANYON-WILLOW LINE WITHOUT RECLOSURE
-ROTOR ANGULAR DISPLACEMENT PLOTTED IS THAT OF ALL GENERATORS
RELATIVE TOWATANA
TRANSlENT STABILITY SWING CURVES-A LTERNATlVE 2
85 o/o LOAD AT ANCHORAGE FIGURE 3.9
1.0
-U1
UJ
UJ a::
(!)
w
0
(/)
UJ
...J
(!)
;::
<t
a::
Q
0 a::
a:: ~
<t a::
LLJ z
LLJ
(!)
10~--------~----------~----------~----------~--------~
WATANA
0~--------~----------~----------+-------~~~--------~ L I •• --··-;---................ =··----··~c""\'fON . ·· .. .. • oE.\1\\... ,...\,
-10
-20
-30
-40
-50
\
-60 I
'--\ .
-70
0 0.2 0.6 0.8
TlME (SECONDS)
NOTE
-DISTURBANCE JS 3-PHASE FAULT AT DEVIL CANYON CLEARED IN 0.08 SECONDS
BY 3-PHASE TRIPPING OF DEVIL CANYON-FAIRBANKS LINE WITHOUT RECLOSURE
-ROTOR ANGULAR DISPLACEMENT PLOTTED lS THAT OF ALL GENERATORS
RELATIVE TO WATANA
TRANSIENT STABILITY SWING CURVES-ALTERNATIVE 2
25o/o LOAD AT FAIRBANKS FlGURE 3.10
1.0
4 -CONCLUSIONS
All five transmission alternatives which were developed and tested would
be capable of transmitting Susitna power to Anchorage and Fairbanks with
acceptable levels of reliability. All, except Alternative 5, have very
similar present worth life cycle costs.
There are, however, other differences between these alternatives which
have not been quantified in the above analyses. These differences, as
outlined below, result in making some of the alternatives more desirable
than others.
-500-kV transmission to Anchorage has a higher ultimate capability than
any other alternative, but at a significantly higher cost.
Furthermore, this added capability is not required with presently
foreseen installation at Susitna. This alternative also implies a dual
voltage system with less possibility of standardization and reduced
reliability because of the additional transformation required at Devil
Canyon.
-230-kV transmission to Fairbanks would need to be combined with a
higher voltage transmission to Anchorage with the resultant
disadvantages of a dual voltage system. Furthermore, it includes
series compensation with additional complexity in protection and
operation. Its reduced transfer capability offers no economic
advantage.
-Of the 345-kV alternatives, the three-circuit configuration to
Anchorage has the greatest reliability and simplicity by not requiring
series compensationA It also has a higher ultimate transfer capability
and a higher capability with single contingency outage, thus allowing
for greater flexibility of capacity planning for Susitna. It also has
partial transfer capability in the case of the double contingency
outage of parallel circuit elements.
4 - 1
-On the other hand, the three-circuit configuration results in a
slightly greater visual impa.ct than the two-circuit alternative.
Considering the overall balance of economy, reliability, transfer
capability and operational complexity, the three-circuit configuration of
Alternative 2 is seen to offer the best combination of advantages.
It is recognized that; in view of the 1.mcertainties regarding some of the
system parameters, several sweeping assumptions had to be made to be able
to carry out this preliminary analysis. The most obvious of these
uncertainties involves the interconnection configuration between the
Susitna transmission and the high-voltage transmission system in the
Anchorage area. Installed capacities and generating unit sizes, as well
as other technical characteristics of the Susitna project, are likely to
be revised as well. However, it is expected that the conclusions drawn
from both the technical and economic analyses will not be significantly
affected by the resulting changes·in system parameters.
4 - 2
5 -RECOMMENDATIONS
The following recommendations result from the preceding analysis.
(a) Recommended transmission alternative
-Watana to Devil canyon - 2 circuits at 345 kV with 2x954 kcmil
conductors
-Devil Canyon to Anchorage - 3 circuits at 345 kV with 2x954 kcmil
conductors
-Devil Canyon to Fairbanks - 2 circuits at 345 kV with 2x795 kcmil
conductors
All without series compensation.
(b) Before proceeding with the final feasibility analysis, it is
recommended to await revisions and more definitive decisions and
values for the following parameters.
( i) Ultimate in.stalled capacity at Susi tna.
(ii) Generating unit sizes at Susitna.
{iii) Number and location of points of delivery for Susitna power
to the Anchorage area.
( iv) Details of generation planning, resulting in thermal
development at Beluga or elsewhere.
5 - 1
(c) At a .future date, it is recommended to analyze the possible
advantage of standardization by constructing all of the Susitna
transmission to Fairbanks with 2x954 kcmil conductors. The first
circuit is expected to be built with this conductor between Willow
and Healy as part of the Anchorage-Fairbanks transmission intertie.
5 - 2
APPENDIX A
TRANSMISSION PLANNING CRITERIA
APPENDIX A
TRANSMISSION PLANNING CRITERIA
In general, transmission facilities are planned so that the single
cont~ngency outage of any line or transformer element will not result in
restrictions in the rated power transfer, although voltages may be
temporarily outside of normal limits. The proposed guidelines concerning
power transfer capability, stability, system performance limits, and
thermal overloads are detailed below.
(a) Transmission System
Transfer Capability
The transmission system will be designed to be capable of
transmitting the maximum generating capability of the Susitna
Hydroelectric Project with the single contingency outage of any line
or transformer element. The sharing of load between the Anchorage
and Fairbanks areas is approximately 80 and 20 percent respectively.
To account for the uncertainty in future development, the
transmission system shall allow for this load sharing to vary from a
maximum of 85 percent at Anchorage to a maximum of 25 percent at
Fairbanks.
(b) Stability
The transmission system will be checked for transient stability at
critical stages of development. The system is to be designed for
high speed reclosing following single-phase faults that are cleared
by single-pole switching. In the case of multiphase faults, delayed
reclosing is assumed.
A - 1
The design fault for transient stability analysis will be a 3-phase
fault cleared in 80 ms (4.8 cycles) by the local breaker and 100 ms
(6.0 cycles) by the remote breaker, with no reclosing.
(Note: At later stages of design it may be useful to check dynamic
stability for unsuccessful reclosure of an SLG fault cleared
eventually by 3-phase trip and lock-out following initial
single-pole trip. For the present, a 3-phase design fault
is considered to be equivalent in terms of severity.)
(c) System Energizing
Line energizing initially and as part of routine switching
operations will generate some dynamic overvoltages. System design
should be arranged to keep these overvoltages within the following
limits.
-Line open-end voltages at the remote end should not exceed
1.10 per unit on line energizing.
Following line energizing, switching of transformers and var
control devices at the receiving end should bring the voltage down
to 1.05 per unit or lower.
Initial voltages at the energizing end should not be reduced below
0.90 per unit.
Final voltages at the energizing end should not exceed 1. 05 per
unit.
The step change in voltage at the energizing end of the line
should not exceed the following values
A - 2
(i) 15 percent with only one generating unit operating at
Watana (to represent a temporary condition during the early
stage of commissioning of the Susitna project)
(ii) 10 percent with two units operating at Watana (to represent
a slightly longer-term condition early in the development
of Susitna)
(iii) 5 percent with 800 MW of generating capacity operating at
Susitna.
(d) Load Flow
System load flows will be checked at critical stages of development
to ensure that the system configuration and component ratings are
adequate for normal and emergency operating conditions. The load
levels to be checked will include peak load and minimum load
(assumed 50 percent of peak) to ensure that system flows and
voltages are within the limits specified below.
-Normal system flows must be within all normal thermal limits for
transformers and lines, and should give bus voltages on the EHV
system within +5 percent, -10 percent, and at subtransmission
buses within +5 percent, -5 percent.
-Emergency system flows with the loss of one system element must be
within emergency thermal limits for lines and transformers
(20 percent 0/L). Bus voltages on the EHV system should be within
+5 percent, -10 percent, and at subtransmission buses within
+5 percent, -10 percent.
A-3
(e) Corrective Measures
Where limiting performance criteria are exceeded, system design
modifications will be applied that are considered to be most cost
effective. Where conditions of low voltage are encountered, for
example, power factor improvement would be tried. Where voltage
variations exceed the range of normal corrective transformer tap
change, supplementary var generation and control would be applied.
Where circuit and transformer thermal limits are about to be
exceeded, additional elements would be scheduled.
(f) Power Delivery Points
For study purposes, it will be assumed that when Susitna generation
is fully developed (i.e. to approximately 1,500 MW, the total output
will be delivered to terminal stations as follows.
-Fairbanks -one station at Gold Hill with transformation from EHV
to 138 kV.
-Anchorage -one or two stations with transformation from EHV to
230 kV or 138 kV.
The provision of intermediate switching stations along the route may
prove to be economic and essential for stability and operating
flexibility. Utilization of these switching stations for the supply
of local load will be examined, but security of supply to Anchorage
and Fairbanks will be given priority consideration.
A - 4
APPENDIX B
EXISTING TRANSMISSION SYSTEM DATA
TABLE OF CONTENTS
LIST OF TABLES -------------------------------------------------B -i
LIST OF FIGURES ----·--------------------------------------------B -iv
B1 -ANCHORAGE MUNICIPAL LIGHT AND POWER -----------------------B - 1
B2 -CHUGACH ELECTRIC ASSOCIATION, INC. ------------------------B - 7
B3 -FAIRBANKS MUNICIPAL UTILITY SYSTn1 ------------------------B -14
B4 -GOLDEN VALLEY ELECTRIC ASSOCIATION, INC. ------------------B -19
BS -UNIVERSITY OF ALASKA, FAIRBANKS ---------------------------B -28
B6 -rULITARY INSTALLATIONS, FAIRBANKS AREA --------------------B -30
B7 -MATANUSKA ELECTRIC ASSOCIATION AND ALASKA P&ER
AI:MINISTRATION -------------------------------------------B -32
LIST OF TABLES
Number
B 1. 1
B1.2
B 1. 3
B 1.4
B 1.5
B 1.6
B2.1
B2.2
B2.3
B2.4
B2.5
B3.1
B3.2
B3.3
Title
Anchorage Municipal Light and Power
Existing Generating Capacity
Anchorage Municipal Light and Power
Generator Data
Anchorage Municipal Light and Power
Transmission Line Data
Existing and Planned Facilities
Anchorage Municipal Light and Power
Transformer Data
Anchorage Municipal Light and Power
Distribution Substation Data
Existing and Planned Facilities
Anchorage Municipal Light and Power
Historical System Peak Demands
Chugach· Electric Association, Inc.
Existing and Planned Generating Capacity
Chugach Electric Association, Inc.
Generator Data
Chugach Electric Association, Inc.
Transmission Line Data
Existing and Planned Facilities
Chugach Electric Association, Inc.
Transformer Data
Existing and Planned Facilities
Chugach Electric Association, Inc.
Distribution Substation Data
Existing System
Fairbanks Municipa~ Utility System
Existing Generating Capacity
Fairbanks Municipal Utility System
Generator Data
Fairbanks Municipa1 Utility System
Transmission Line Data
Existing and Planned Facilities
B -i
List of Tables - 2
Number
B3.4
B3.5
B4.1
B4.2
B4.3
B4.4
B4.5
B4.6
B4.7
B4.8
B5.1
B6. 1
Title
Fairbanks Municipal Utility System
Transformer Data
Existing and Planned Facilities
Fairbanks Municipal Utility System
Historical Load Data
Golden Valley Electric Association, Inc.
Existing Generating Capacity
Golden Valley Electric Association, Inc.
Generator Data
Golden Valley Electric Association, Inc.
Transmission Line Data
Existing System
Golden Valley Electric Association, Inc.
Transmission Line Data
Planned Facilities
Golden Valley Electric Association, Inc.
Transformer Data
Existing System
Golden Valley Electric Association, Inc.
Transformer Data
Planned Facilities
Golden Valley Electric Association, Inc.
Distribution Substation Data
Existing System
Golden Valley Electric Association, Inc.
Distribution Substation Data
Planned Facilities
University of Alaska, Fairbanks
Generating Capacity and Data
University of Alaska, Fairbanks
Transformer Data
Military Installations, Fairbanks Area
Generating Capacity and Data
B -ii
List of Tables - 3
Number
B6.2
B7. 1
B7.2
B7.3
B7.4
Title
Military Installations, Fairbanks Area
Transformer Data
Matanuska Electric Association and
Alaska Power Administration
Existing Generating Capacity
Matanuska Electric Association and
Alaska Power Administration
Generator and Transformer Data
Matanuska Electric Association and
Alaska Power Administration
Transmission Line Data
Existing System
Matanuska Electric Association and
Alaska Power Administration
Distribution Substation Data
Existing System
B -iii
LIST OF FIGURES
Number
B.l
B.2
B.3
Title
Anchorage-Fairbanks Railbelt Area Map
Anchorage Area, One-Line Diagram -1984 System
Fairbanks Area, One-Line Diagram -1984 System
B -iv
Unit
Station -Unit 1
Station -Unit 2
Station -Unit 3
Station -Unit 4
Station 1 -D1
Station l -OS
Station 2 -Unit 5
Station 2 -Unit 6
Stat ion 2 -Unit 7
Total available capacity
*Peak rat i ng at 0 °F.
TABLE B 1. 1: Af\CHJRAGE MUNICIPAL L I G-\T AND FOWER
EXISTING GENERATING CAPACITY
Yea.r of
Installation ~ Ca~acit:t*
(MW)
GT 16.25
GT 16.25
GT 19.50
GT 37. so
Diesel 1.10
Diesel 1. 10
GT } ST 138. 90
GT
230.60
Abbreviations: GT -Gas Turbine
ST -Steam Turbine
B - 1
Remarks
Natural gas
Natural gas
Natural gas
Natural gas
Black start units
Black start units
Natural gas,
combined cycle, base
load
TABLE 81.2: ANCHORAGE MUN l C I PAL Ll GHT AND POWER
GENERATOR DATA
Power
Unit Voltage Rating Factor
( kV l (MVAJ
Station -Unit 1 13. a 15.5 .as
Station -Unit 2 13.a 15.6 .as
Station -Unit 3 13. a 19.2 .as
Station -Unit 4 13.a 31.755 .as
Station - D 1 1. l 1. 0
Station -05 1. 1 1.0
Station 2 -Unit 5 13.6 39.2
Station 2 -Unit 6 13.a 38.8
Station 2 -Unit 7 13.2 110.5
* Impedance in per unit on 100 MVA base.
**Inertia constant in per unit on 100 MVA base.
Generator lm£edance*
xd X'd X"d
11.54 2.44 1. 50
11.54 2.44 1.60
14.43 2.43 1.50
5.6a .72 .41
104.55 29.09 20.00
104.55 29.09 20.00
5.22 • 70 .41
4. 12 • 57 .2a
2.25 .34 .24
B - 2
x2
1.50
1.60
1.61
.41
21.a2
21.a2
Inertia
Xo Constant**
1.64
1.54
1. 94
• 14 2.89
3.a8
1.63
8.40
TABLE Bl.3: ANCHORAGE MUNICIPAL LIGHT AND POWER
TRANSMISSION Ll NE DATA
EXISTING AND PLANNED FACILITIES
Transmission Circuit-Voltage
From Bus -To Bus
Station 1-Station 2 115 kV
Length
(mi)
(via Ft. Richardson-Eimendo.rf AFBJt
Conductor
Pas Seq
Impedance*
R X
Susceptance**
BC
Station 1 -Station 2 5.5 :f.J7 ACSR (26/7) .01134 .0.3087 .00456
Station 2-APA Tap 115 kV
Station 2 -APA Tap .6 397 ACSR (26/7) .00124 .00338 .00050
Station 1 -Anctorage <APA) 115 kV
(Approximate in-service date 1982) tt
Stat ion 1 -Stat ion 6 1. 7
Station 6-Station 11 Tap 1 .8
Station 11 Tap-Station 16 .8
Station 16 -Station 15 3.1
Station 15 -Anchorage (APA) • l
Total 7.5
Station 11-Station 11 Tap 3.0
Station 1 -Station 2 (APAJ 115 kV
(Approximate i n-sarv ice date 1982)tt
Station 1 -Station 14 1.6
Station 14 -Stat ion 17 Tap .9
Station 17 Tap -Station 2 3.0
Total Station 1 -Station 2 5.5
Station 17 Tap-Station 17ttt 1 .o
Stat ion 17 -Anctorage (APA) .8
Total 1 .8
397 ACSR ( 26/7) .00356
397 ACSR (26/7) .00377
39 7 ACSR ( 26/7) .00156
397 ACSR (26/7) .00634
397 ACSR (26/7) .00025
:f.J7 ACSR (26/7) .00613
397 ACSR (26/7) .00336
397 ACSR (26/7) .00187
397 ACSR ( 26/7 ) .00630
397ACSR (26/7) .00210
397 ACSR (26/7) .00165
* Positive sequence impedance in per unit on 100 MVA base.
**Total line charging susceptance in per unit on 100 MVA base.
***Zero sequence impedance in per unit on 100 MVA base.
t Normally no power exchange to mi I itary system.
tt Rebuild and conversion of existing 34.5-kV circuit to 115 kV.
.00973 .00144
.01030 .00152
.00427 .00063
.01733 .00256
.00068 .00010
.01680 .00248
.00918 .00135
.00512 .00076
.01712 .00253
.00574 .00085
.00450 .00066
tttstation 17 is scheduled for installation in 1985. Station 17-Station 17 Tap
w i II be operated normal I y open.
B - 3
Zero Seq
Impedance***
Ro Xo
Substation -Transformer
Two Winding Transformers
Station - 1
Station 1 - 2
Station -GSU
Station -GSU 2
Station 1 -GSU 3
Station 1 -GSU 4
Station 1 -GSU Diesel
Station 2 -GSU 5
Station 2 -GSU 6
Station 2 -GSU 7
TABLE 81.4: At<:HORAGE MUNICIPAL LlGH AND POWER
TRANSFORMER DATA
Voltage
( kV)
115/34.5
115/34.5
13.8/34.5
13.8/34.5
13.8/34.5
13.8/34.5
2.4/33
13.8/115
13.8/115
13.2/115
Rating
(MVAl
28/37/46
28/37/46
12
12
12
21/25/28
3. 75
30/40/50
30/40/50
44/59/74
Tap Setting Tap Range
*Transformer reactance in per unit on 100 MVA base.
B-4
Reactance*
.2893
.2893
• 5833
• 5833
.5000
.2810
2. 0373
.2233
.2267
.1528
Substation
Central business district*
12 kV substations**
Total
TABLE B1.5: ANCHORAGE MUNICIPAL LIGHT AND POWER
DISTRIBUTION SUBSTATION DATA
EXISTING AND PLANNED FACILITIES
Voltage
{kV)
34.5/4.2
115/12.5
Load***
{percent)
31
69
100
* The central business district is suppl led fran generating Station
34.5-kV bus via a number of 34.5/4.2-kV substations.
**Stations 6, 11, 14, 15, 16 and 17 are 115/12.5-kV substations.
Substation 17 is scheduled for Installation in 1985. The 12-kV load
is equally divided among the 12-kV substations.
***The percentage of load supplied at 34.5 and 12.5 kV is expected to
rerna in constant.
B -; 5
/
Winter
1974/1975
1975/1976
1976/1977
1977/1978
1978/1979
1979/1980
TABLE 61.6: AIICHORAGE MUNICIPAL LIGHT AND POWER
Peak Demand
(MW)
82.B
89.5
93.4
101.5
109.0
1 11. 5
HISTORICAL SYSTEM PEAK DEMANDS
B-6
TABLE B2.1: CHUGACH ELECTRIC ASSOCIATION, ll'C.
EXISTING AND PLANNED GENERATING CAPACITY
Year of
..!!.!!.!..! Installation ~ Capacity
Beluga -Unit 1
Be I uga -Un i t 2
Beluga -Unit 3
Be I uga -Un it 4
Beluga -Unit 5
Beluga -Unit 6
. Beluga -Unit 7
Beluga -Unit 8 1982
Bernice Lake -Unit 1
Bernice Lake -Unit 2
Bernice Lake-Unit 3
Cooper Lake -Unit 1
Cooper Lake-Unit 2
I nternationa I -Unit
International -Unit 2
International -Unit 3
Knik Arm-TGS
Kn i k Arm -TG6
Knik Arm-TG7
Knik Arm-TG8
Total ava i I able capacity
Abbreviations: GT -Gas Turbine
ST -Steam Turbine
CMW)
GT 16.5
GT 16. 5
GT 54.6
GT 9.3
GT 65.5
GT 67.8 } GT 68.0
ST 62.0
GT 8.85
GT 18.95
GT 29.60
Hydro 7. 5
Hydro 7. 5
GT 14.0
GT 14.0
GT 18.58
ST 3. 0
ST 3. 0
ST 3.0
ST 5.0
493.18
B - 7
Remarks
Base load
Base load
Base load
Jet engine
Base load
Combined cycle-
base load
Base load
Base load
TABLE B2. 2: CHUGACH ELECTRIC ASSOCIATION, I !'C.
GENERATOR DATA
Power Generator lmeedance*
Unit Voltage RatIng Factor
( kV) (MVAJ
Beluga -Unit 1 13.8 18.824 .90
Beluga-Unit2 13.8 18.824 .90
Beluga-Unlt3 13.8 57.0 .95
Be I uga -Un It 4 13.8 10.0 • 90
Beluga -Unit 5 13.8 68.889 .95
Beluga-Unit 6 13.8 85.0 .so
Beluga-Unit 7 13.8 85.0 • 80
Beluga-Unit 8 13.8 68.889 .90
Bernice Lake-Unit 24.9 9.375 .95
Bernice Lake -Unit 2 13.8 20.65 .90
Bernice Lake -Unit 3 13.8 29.60 1.00
Cooper Lake -Unit 1 39.8 8. 33 .90
Cooper Lake -Unit 2 39.8 8.33 .90
I nternat ion a I -Unit 13.8 17.647 .80
International -Unit 2 13.8 17.647 .so
I nternat i ona I -Unit 3 13.8 19.200 • 95
Kni k Arm -TG5 4.2 3.75 .so
Knik Arm -TG6 4. 2 3. 75 .so
Knik Arm -TG7 4.2 3.75 .so
Kn i k Arm -TG8 4.2 6.25 .so
* Impedance in per unit on 100 MVA base.
**Inertia constant in per unit on 100 MVA base.
xd X'd X"d
1.59 .58
1. 59 .58
2.87 .28 • 18
2.87 .28 • 19
2. 54 .33 • 21
2.54 .33 .21
2.44 .23 • 16
16.00 3. 73 2.13
8. 96 .82 • 53
6.31 .65 .43
3. 11 2. 16
3. 11 2. 16
10.65 1.02 • 71
1 o. 65 1.02 • 71
9. 74 I. 74 1.24
6.00
6.00
6.00
3.40
B-8
Inertia
x2 Xo Constant**
.34
l. 86
2. 19
TABLE B2.3: CHUGACH ELECTRIC ASSOCIATION, INC.
TRANSMISSION LINE DATA
EXISTING AND PLANNED FACILITIES
Transmission Circuit-Voltage
From Bus -To Bus
Beluga -Pt MacKenzie 230 kV
Beluga-Pt MacKenzie Ckt 1t
Beluga -Pt MacKenzie Ckt 2t
Beluga -Pt MacKenzie Ckt 3tt
Length
(mi)
Pt MacKenzie -University 230 kvttt
Pt MacKenzie-West Terminal
Submarine cable
East Tenninaf -University
Totals
International -University 13B kV
I nternat iona I -University
I nternat lonat -Pt Woronzof 138 kV
International ~ Pt Woronzof Ckt I
International -Pt Woronzof Ckt 2
Pt Mad<enz i e -Tee I and 138 kV
Pt MacKenzie -Teeland
Pt Mad<enz ie -Pt Woronzof 138 kV
Cables 1 to 4
Cable 5
Cable 6
Cables 7 to 10
Bernice Lake~ Soldotna <HEA> 115 kV
Bernice Lake -Soldofna
Conductor
795 ACSR
795 ACSR
795 ACSR
Pos Seq
I mpedanoe*
R X
Susceptance**
sc
.0094 .0627 .1216
.0094 .0627 .1216
.0094 .0627 .1216
954 and 795 ACSR .0016 .0108 .0220
l ,000 Kcmi I Cu .0010 .0056 .0004
954 and 795 ACSR .0037 .0266 .0536
795 ACSR
B - 9
.0063 .0430 .0760
.0048 .0189 .0054
.0038 .0151
.0038 .0151
.0538
.0538
.0176 .1066 .0264
.0030 .0041 .0562
.0035 .0045 .1 034
.0035 .0045 • 1034
.0086 .0034 .2800
.0310 .1390 .0156
Zero Seq
Impedance***
Ra Xo
Table 82.3: Chugach Electric Association, Inc.
Transmission Circuit-Voltage
from Bus -To Bus
Soldotna -Quartz Creek 115 kV
Transmission Line Data
ExisTing and Planned Facilities-2
Length
( mi)
Conductor
Pos Seq
Impedance*
R X
Susceptance**
BC
Soldotna -Quartz Creek .0684 0.3070 .0371
Quartz Creek -University 115 kV
Quartz Creek -Daves Creek
Daves Creek -Hope
Hope -Portage
Portage -Girdwood
Girdwood -Indian
Indian-University
Bernice Lake -Soldotna (HE/I) 69 kV
Bernice Lake-Kenai
Kenai -Soldotna CHEA)
Cooper Lake -Quartz Creek 69 kV
Cooper lake -Quartz Creek
Homer CHEAl -Soldotna (HEAl 69 kV
Homer (HEAl -Kasi I of CHEAl
Kasi I of (HEAl -Soldotna CHEA)
Soldotna (HEA) -Quartz Creek 69 kV
Soldotna (HEA) -Quartz Creek
.0184
.0215
.0250
.0140
.0136
.0210
.2300
.0733
.0218
.6350
* Positive sequence impedance in per unit on 100 MVA base.
**Total line charging susceptance in per unit on 100 MVA base.
***Zero sequence impedance in per unit on 100 MVA base.
.0827 • 0108
.0964 .0125
• 1124 .0146
.0627 .0082
.0610 .0079
.0941 .0122
.3250 • 0051
.1040 • 0016
.0863 .0015
.8980 .0129
t Existing 138-kV circuits are being reinsulated to permit operation at 230 kV,
approximate in~service date-1981.
tt A third 230-kV circuit being added, approximate in-service date-1981.
tttApproximate in-service date-198Z.
Abbreviation: HEA-Homer Electric Association
B -10
Zero Seq
Impedance***
Ro Xo
TABLE 82.4: CHUGACH ELECTRIC ASSOCIATION, INC.
TRANSFORMER DATA
EXISTING AND PLANNED FACI UTI ES
Substation -Transformer Voltage RatIng
(kV) (MVA)
Beluga-!** 230/138 180/240/300
Beluga-2** 230/138 180/240/300
pt MacKenzie-!** 230/138 180/240/300
pt MacKenzl e-2** 230/138 180/240/300
University** 230/138 180/240/300
Teel aoo 138/115 45/60/75
University-! 138/115/34. 5 45/60/75
University-2 138/115/34. 5 45/60/75
i nternat i ona I -1 138/34.5 125
lnternational-2 138/34.5 125
Bernice Lake 115/69 33.6/44.8/56
Soldotna CHEA) 115/69 32.6
Quartz Creek 115/69 12/15
Bel uga-GSU t 13. 8/138 16
Bel uga-GSU 2 13.8/138 16
Betuga-GSU 3 13.8/138 48.8/65/81.3
Bel uga-GSU 4 13.8/138 12/16
Be I uga-GSU 5 13.8/138 45/60/75
Bel uga-GSU 6 13.8/138 48.8/65/81.3
Be I uga-GSU 7 13.8/138 45/64/80
Bel uga-GSU 8 13.8/138
Bernice Lal<e-GSU 24.9/69 5
Bern ice Lake-GSU 2 13.8/69 23
Bernice Lake-GSU 3 13.8/69 20.4/27.2/34
Cooper La ke-GSU 39.8/69 20
I nternat i ona 1-GSU 1 13.8/34.5 12/16
lnternationai-GSU 2 13.8/34.5 11.25/15
International-GSU 3 13.8/34.5 12/16/20
Knik Arm-! 4.2/34.5 5
Kni k Arm-2 4. 2/34.5 5
Knik Arm-GSU 8 4.2/34.5 6.25
* Transformer impedance in per unit on 100 MVA base.
**Approximate in-service date 1981 to 1982.
Abbrev lations: HEA -Homer Electric Association
B -11
Tae Setting Tap Range
Impedance*
R X
.0020
.0020
0 0020
.0020
0 0020
0 0222
.0222
.0222
.0222
.0222
.1805
(ZH=-j.0245, ZL=j.2045, ZT=j.1712)
.0073
.0073
.0880
.0880
.2972
.1333
.3420
.0450 .6780
0 0440 .6640
.0110 0 1600
.0450 .6780
• 0140 • 2040
.0140 • 1650
.009 1.3600
.043 .5170
.0310
.3889
.4600
.5000
.5510
.5000
1. 2200
1. 2200
.9600
TABLE 82.5: CHUGACH ELECIR!C ASSOCIATION, INC.
Substation
Anchorage Area
Suppl led via International
Substat.ion at 34.5 kV
Arctic
Blueberry
Campbe.ll
Jewel Lake
Klatt
Sand lake
Spenard
Tudor
Turriagai n
Wood l and Park
International Subtotal
Suppl i ed vi a University
Substation at 34.5 kV
Boniface
DeBarr
Fairview
Huffman
Mt View
0 1 Malley
Un i varsity Subtotal
Supplied via Beluga Substation
Tyonek
Tyonek Timber
Be I uga Subtota I
DISTRIBUTION SUBSTATION DATA
EXISTING SYSTEM
Transformer
Voltage
( kV)
34.5/12.5
34.5/12.5
34.5/12.5
34.5/12.5
34. 5/12.5
34.5/12.5
34.5/12.5
34.5/12.5
34.5/12.5
34.5/12.5
34.5/12.5
34.5/12.5
34.5/12.5
34.5/12.5
34.5/12.5
34.5/12.5
24. 9/12. 5
24.9/12.5
Rating
(MVA)
14.0
14.0
14.0
1 1.2
14.0
14.0
10.0
14.0
5. 0
2 1.0*
131.2
14.0
25.2*
3. 8
1 7.8*
12. 0*
86.8
12.2
B -12
Percent
of Total
46
30
4
Substation
K ena i Pen i ns u I a
Daves Creek
Girdwood
Homer
Hope
Indian
Kas i I of
Kenai
Portage
Soldotna
Kenai Peninsula Subtotal
TOTALS
Table 62.5: Chugach Electric Association, Inc.
Distribution Substation Data
Existing System -2
Transformer
Voltage
( kV}
115/24. 9
115/24.9
69/24. 9/12.5
115/24.9
115/24.9
69/24.9
69/33
115/12.5
69/24.9
Rating
(MVA)
14. 0
11.2
3.8
3.8
2.3
3.8
7. 5
2.8
___l_:2_
56.7
286.9
Percent
of Tota I
20
100
*Tota I MVA capacity of two transformers.
B -13
Unit
Chena 1
Chena 2
Chena 3
Diesel 01
Diesel D2
Diesel D3
Gas Turbine 4
Chena 5
Chena 6
Total Avai I able
TABLE 83.1: FAIRBANKS MUNICIPAL UTILITY SYSTEM
EXISTING GENERATING CAPACITY
Year of Nameplate
Installation ~ caeac i :tt:
(M/1)
1954 ST 5.00
1952 ST 2.00
1952 ST 1. 50
1967 Oi esel 2. 75
1968 Diesel 2. 75
1968 Diesel 2. 75
1963 GT 5.25
1970 ST 20.00
1976 GT 23.10
Capacity 65. 10
J3 -14
Remarks
Coal
Coal
Coal
Oi I
Coal -Base load and
district heating
Oil
TABLE 63.2: FAIRBANKS MUNICIPAL UTILITY SYSTEM
GENERATOR DATA
Power Generator I meedance*
Unit Voltage Rating Factor xd X'd xud
( kV) <MVA)
Chena 1 4.2 6. 25 .85 23.36 2.50 1. 4 7
Chena 2 4.2 2.40 .85 55.00 7.88 4. 13
Chena 3 4.2 1.SO .ss 75.00 12.33 6.39
Diesel 1 12. 5 3.44 .so 6.63 4. 54
Diesel 2 12.5 3.44 .so 6.63 4.54
Diesel 3 12.5 3.44 .so 6. 63 4. 54
Gas turb 1 ne 4 12.5 6.25 .so 6.24 3.68
Chena 5 12.5 25. 10 .ss 1. 08 .66
Chena 6 12.5 29.00 .85 • 73
* Impedance in per unit on 100 MVA base.
**Inertia constant in per unit on 100 MVA base.
B -15
Inertia
x2 Xo Constant**
TABLE B3.3: FAIRBANKS MUNICIPAL UTILITY SYSTEM
TRANSMISSION LINE DATA
Transmission Circuit -Yo I tage
EXISTING AND PLANNED FACILITIES
Pos Seq
Impedance*
From Bus -To Bus Length Conductor R X
Chena -Zehnder (G VEAl
69 kV I nterconnectiont
( mi)
Zero Seq
Susceptance** Impedance***
BC R0 X0
Chena -Zehnder .a 336 ACSR (25/7) .0047 .0120 .0002 .oo95 • 04n
Chena -South Fairbanks 69 kV
(ApproximaTe in-service date 198ztt
Chena-South Fairbanks 3. 0 336 ACSR (26/7) .0175 .0451
* Posi-tive sequence impedance in per unit on 100 MYA base.
**Total fine charging susceptance in per unit on 100 MVA base.
***Zero sequence impedance in per unit on 100 MYA base.
t Metered at Zehnder.
tt Estimated date.
B -16
.0006 .0355 • 1770
TABLE 83.4: FAIRBANKS MUNICIPAL UTILITY SYSTEM
TRANSFORMER DATA
EXISTING AND PLANNED FACILITIES
Substation -Transformer
Two Winding Transformer
Chena - 1
Chena-2 (1982)***
South Fairbanks ( 1 982 )***
Voltage
( kV)
69/12.47
69/12.47
69/12.47
Rating*
(MVA)
12/16/20
12/16/20
12/16/20
* Continuous full load rating at 65"C rise.
** Transformer reactance fn per unit on 100 MVA base.
***Approximate in-service date.
Abbreviation: LTC -Load Tap Changing
Tap Setting
LTC
LTC
LTC
B -17
Tap Range Reactance**
.6250
.6250
.6250
TABLE 83.5: FAIRBANKS MUNICIPAL UTILITY SYSTEM
HISTORICAL LOAD DATA
Historical Peak Demands {MW)*
Substation Voltage
(kV)
1975 1976 1977 1978
Chana 12.47 and 4.16 27.2
* Historical load power factor -• 95
**1980 maximum danand through June 1980.
25.0 27.6 24. 1
B -18
1979
25.3
1980**
25.2
TABLE 84. 1: GOLDEN VALLEY ELECTRIC ASSOCIATION, It-e.
EXISTING GENERATING CAPAC!TY
Year of
Unit Installation
Healy-51 1967
Healy -Dl
North Pole-GTl 1976
North Po I e -GT2 1977
Zehnder -GTl 1971
Zehnder -GT2 1972
Zehn:ler -GT3 1975
Zehnder -GT 4 1975
Zehnder - D
Zehnder - D
Zehnder - 4 units
Total Ava i I ab I e Capacity
* Capacity at estimated power factor -.ao.
**Combined capacity of 4 units.
Abbreviations: ST-Steam Turbine
Gr -Gas Turbine
~ Caeacit:t:
(MWJ
ST 25.00
Diesel 2. 75
Gr 60.50
GT 60.50
Gr 18.40
18.40
GT 2.80*
GT 2.80*
Diesel 2.28*
Diesel 2.28*
Diesel 10.64**
206.35
B -19
Remarks
Co a I base I oa:l unit
Peaking unit
Peaking units
TABLE B4. 2: GOLDEN VALLEY ELECTRIC ASSOCIATION,
GENERATOR DATA
Power Generator lm~edance*
Unit Voltage Rating Factor
( kV) (MVA)
Healy -S 1 13.8 29.4 .as
Healy-Dl 2.4 3.5 .ao
North Po! e -GT 1 13.8 71.9 .90
North Pole-GT2 13.8 71.9 .90
Zehnder -GT 1 13.8 20.7 .as
Zehnder -GT2 13.8 20.7 .as
Zehnder -GT3 4.2 3. 5 .ao
Zehbder -GT4 4.2 3.5 .80
Zehnder - D 4. 2 2. 9 .80
Zehnder - D 4.2 2.9 .80
Zehnder - 4 Units 4.2 3. 3 .ao
*Impedance in per unit on 100 MVA base.
**Inertia constant in per unit on 100 MVA base.
xd X'd xnd
6.086 • 731 s. 10
23.190 B. 700 5.220
2.866 .285 .185
2. 932 .284 .185
a. 959 .823 .533
8.959 .823 .533
32.86 4.29 2.86
32.86 4.29 2.86
63.86 16.84 11.23
63.86 16.84 11.23
24.02 9. 00 5.40
B -20
INC.
Inertia
x2 Xo Constant**
• 510 • 170 .88
5.507 1.449
• 177 • 107 5.62
.172 .104 5.62
.484 .315 1.86
.484 .3!5 1.86
3. 71 1. 14
3. 71 1. 14
8.42 4.21
8.42 4.21
5. 70 1. 50
TABLE 84.3: GOLDEN VALLEY ELECTRIC ASSOCIATION, INC.
Transmission Circuit-Voltage
From Bus -To Bus
H ea J y -Go I d H i 1 I 138 kV
Gold Hi II -Nenana
Nenana -Healy
Total
Length
( mi>
47.0
..2&:1..
103.2
North Pole -Fort Wainwright 138 kV
Fort Wainwright-North Pole 12.3
North Po I e -Highway Park 69 kV
Highway Park -North Pole 2.3
Zehnder -Fort Wa i nwr i ght 69 kV
Fort Wainwright-Hamilton Acres 2.9
Zehnder -Fox 69 kV
Fox -Steese
Steese -Zehnder
Total
Zehnder -Go I d Hi II Double CIrcuit
69 kV (Z mutual = .0060 + j.0431
per mile>
Gold Hi II -Musk Ox Tap
Musk Ox Tap -U of Ak
a. 1
.8
3.5
University of AK-University Ave .3
University Ave -Zehnder ~
Total
Musk Ox -Musk Ox Tap
Gold Hi II • Chena Pui'Jl) Tap
Che.na Pump Tap.-Airport Tap
Airport Tap -Zehnder
Total
7. 2
2. l
1. 5
..2.:£.
7.2
TRANSMISSION LINE DATA
EXISTING SYSTEM
Conductor
556 ACSR (26/7)
556 ACSR (26/7)
Pas Seq
Impedance*
R X
Susceptance**
BC
.0415 • 1963 .0475
.0496 .2349 .0569
795 ACSR (26/7) .0075 .0489 .0130
795 ACSR (2/17) • 0057 • 0321 .0007
4/0 ACSR (6/1 )
336 ACSR (26/7)
336 ACSR (26 /7)
336 ACSR (26/7)
336 ACSR (26/7)
336 ACSR (26/7)
336 ACSR (26/7)
336 ACSR (26/7)
336 ACSR (26/7)
336 ACSR (2 6/7)
336 ACSR (26/7)
B -21
.0269 .0478 .0008
• 0330 • 082 6 • 00 1 6
.0141 .0352 .0007
.0046
.0203
.0018
.0153
.0114
.0510
.0044
.0384
.0309 .0798
.0121 .0303
• 0091 .0227
.0208 .0522
.0002
.0010
.0001
.0008
.0015
.0006
.0004
.0010
Zero Seq
Impedance***
Ro Xa
• 1120 .6311
.1341 .7552
.0259 .1650
.0195 .1331
.0442 • 1743
.0669 .3381
• 0285 • 1442
.0092
.0412
.0036
• 0310
• 0466
.2080
.0179
• 1566
.0628 .3126
.0245 .1237
.0184 .0926
.0422 .2128
Table B4.3: Golden Valley Electric Association, Inc.
Transmission Circuit-Voltage
From Bus -To Bus Length
(mi)
Chena Pump -Chena Pump Tap .4
International Airport-Airport 1.5
tap
fort Wainwright-HighwayPark 69 kV
fort Wainwright-Fort W Gen
fort W Gen -Badger Tap
Badger Tap -Brockman Tap
Badger Tap -Highway Park
Total
Badger Road -Badger Tap
Brockman -Brockman Tap
.5
6. 7
2.3
3.0
12.5
1. 0
6.3
fort Wainwright-Peger Road 69 kV
Fort Wainwright-S Fairbanks
S fairbanks -Peger Road
Total
Highway Park -Jarvis Creek 69 kV
Highway Park -Newby Road
( futureJ
1. 2
3.2
4. 4
4.0
Newby Road (future} -Eielson AFB 9.4
Ei el son AFB -Johnson Road 9. 5
Johnson Road -Carney (future) 6. 5
Garney (future)-Jarvis ~tt 52.6
Total 82.0
Transmission Line Data
Existing System-2
Conductor
Pos Seq
Impedance*
R X
Susceptance**
BC
336 ACSR (26/7) .0023 .0061 .0001
336 ACSR (26/7} .0088 .0226 .0004
4/0 ACSR (6/1 l
4/0 ACSR <6/1 l
4/0 ACSR (6/1 )
4/0 ACSR (6/1)
• 0047 • 0083 • 0001
.0622 .1103 .0018
• 0213 • 0378 • 0006
• 0280 • 0497 • 0008
4/0 ACSR (6/1} .0093 .0164 .0003
336 ACSR (26/7} .0368 .0948 .0012
336 ACSR (26/7) .0070 .0181 .0003
336 ACSR (26/7) .0185 .0476 .0009
4/0 ACSR (6/1 l
4/0 ACSR (6/1 )
4/0 ACSR (6/1)
336 ACSR (26/7)
556 ACSR (26/7 l
.0374 .0663 .0011
.0874
.0888
.0380
.1856
• 1551
• 1575
.0978
.8624
.0025
• 0026
.0018
.0136
* Positive sequence impedance in per unit on 100 MVA base.
**Total line charging susceptance in per unit on 100 MVA base.
***Zero sequence impedance in per unit on 100 MVA base.
t Estimated data.
ttcarney (future)-Jarvis Creek is constructed to 138-kV standards.
tttearney (future)-Jarvis Creek is converted to 138-kV operation.
B -22
Zero Seq
Impedance***
Ro Xo
.0047
.0178
.0077
.1021
• 0350
.0461
.0152
.0746
.0142
.0374
• 0614
• 1436
.1459
.0770
.5016
.0234
.0885
.0303
.4024
.1380
• 1815
.0599
.3716
.0708
.1864
.2420
• 5658
.5749
.3834
2.8579
TABLE B4.4: GOLDEN VALLEY ELECTRIC ASSOCIATION, INC.
TRANSMISSION LINE DATA
PLANNED FACILITlESt
Pos Seq
Transmission Circuit-Voltage l mpedance*
Zero Seq
Susceptance** Impedance***
From Bus -To Bus Length Conductor R X BC R0 X0
{mil
Peger Road-International Airport 69 kV
(Approximate in-service date-1981 l
International Airport -Peger
Road
3
North Pole -Gold Hi II 138 kV
(Approximate in-service date-1984)
Go I d Hi I I -North Po I e-OH
-uG
Total
21
22
North Pole-Jarvis Creek 138 kV
{Approximate in-service date -1984)
North Pole-Carney
Carney -Jarvis cKttt
Total
20
52.6
72.6
Bent! y -Fort Wainwright 138 k V
(Approximate in-service date-1992)
Bently-Fort Wainwright 16.2
Bently-Gold Hi! J 138 kV
(Approximate in-service date-1992)
Bently -Gold Hi II 9.5
336 ACSR (26/7 l
556 ACSR (26/7) • 0192 • 0902 • 0326
556 ACSR (26/7) .0175 .0820 .0206
556 ACSR (26/7) .0464 .2156 .0542
795 ACSR (2 6/7)
795 ACSR (26/7 l
* Positive sequence impedance in per unit on 100~VA base.
** Total I i ne charging sysceptance in per unit on 1 OO~VA base.
***Zero sequence impedance in per unit on 100-MVA base.
t Estimated data.
tt Carney (futurel-Jarvis Creek is constructed to 138-kV standards.
tttcarney {future)-Jarvis Creek is converted to 138-kV operation.
B-23
• 1254 • 7145
TABLE 84.5: GOLDEN VALLEY ELECTRIC ASSOCIATION, li'C.
TRANSFO~~ER DATA
EXISTING SYSTEM
Substation -Transformer Voltage Rating* rae Settins
(kll) CMVA)
Autotransformers
Fort Wainwrigllt-FWS1380TI 138/69 60/80/100 138 000
Go I d Hi I 1-GHS 1380T1 138/69 18/24/30 134 550
Gold Hi II-GHS0690T2 69/34.5 1. 725 69 000
Two Wind i ng Transformers
Heal y-HLP1380T1 138/13.2 18/24/30 134 550
Healy HLS1380T1 138/24.94 10/12.5 138 000
Healy 24. 9/2.4 5 24 900
North Po I e-NPS 1380T 1 138/13.2 45/60/75 138 000
North Pol e-NPS 1380T3 138/13.2 45/60/75 138 000
North Po I e-NPS0690T2 69/13.2 36/48/60 69 000
Zehnder-T4 CGSU-GT1) 69/13.8 12/16/20 69 000
Zehnder-T3 (GSU-GT2> 69/1.3.8 12/16/20 69 000
Zehnder-T6 69/4.16 7.5/9.4 69 000
Zehnder-T5 69/4. 16 7.5/9.4 69 000
* Continuous full load rating at 65"C rise.
** Transformer reactance in per unit on 100-MVA base.
***Tap range: 144 900, 141 450, 138 000, 134 550, 131 100.
t Tap range: 72 450, 70 725, 69 000, 67 275, 65 550.
tt Adjusted to base of 13.8 kV fran nameplate base of 13.2 k v.
B -24
Tae Range
***
***
t
***
***
***
***
t
Reactance**
.0800
.2194
3. 1933
.38o2tt
.8180
1. 0940
• l484tt
• 1484tt
• 2094tt
.5760
.6780
.9470
.9810
TABLE B4. 6: GOLDEN VALLEY ELECTRIC ASSOCIATION, It-C.
TRANSFORMER DATA
PLANNED FACILITIES*
Substa-tion-Transformer Voltase Rati ns** Ta2 Setting
(kVl (MVA J
Autotransformers
Carney-1984t 138/69 30/40/50 138 000
Senti ey-1992t 138/69 138 000
* Estimated da-ta.
** Cant i nuous fu I I load rating at 65 •c rise.
***Trans former
t Approxima-te
tt Tap range:
reac-tance in per uni-t on 100-MVA base.
in-service date.
144 900, 14 [ 450, 138 000, 134 550, 131 100.
B -25
Tae Range
tt
tt
Reactance***
• 1500
TABLE B4. 7: GOLDEN VALLEY ELECTRIC ASSOC: IATI ON, lt\C.
DISTRIBUTION SUBSTATICN DATA
EXISTING SYSTEM
Transformer* No nco incident Substation Peak Demand Read l nss
Substation Voltage Ra'ti ng** 1975 1976
( kV) CMVA)
Badger 69/12.4 7 13.44 2. 98 5.65
Brockman 69/24.94 7. 00 NIS NIS
Chena Pump 69/12.47 22.40 NIS NIS
Energy Company 13.8 *** NIS NIS
Fox 69/34. s 8.40 2.57 3. 11
Gold Hi I 1++ 34.5 t .57 • 81
Ham i I ton Acres 69/12.47 22.40 NIS NIS
Healy 24.94 tt na 1. 15
Highway Park 69/12.47 14.00 6.45 7.33
Jnternat i anal 69/12.47 11.20 12.65 13.02
Airport
Jarvis Creek+++ 69x138/24. 94 22.40 NIS NIS
Johnson Road 69/24.94 8.40 4.64 6.43
Musk Ox 69/12.47 14.00 NIS NIS
Nenana 138/24.94 3.12 2.27 z.oo
Peger 69/12.47 13.44 6. 67 6. 91
South Fairbanks 69/12.47 11.20 1 1. 0 1 6.53
Steese 69/12.47 8.40 7.43 7. 67
University Ave 69/12.47 7. 8zttt 8. 76 9. 16
Zehnder 69/12.47 11.20 11 .35 11 .36
77.45 81. 13
* Load tap changing transformer un I ess otherwise noted.
**Maximum nameplate continuous full toad rating at 65°C rise.
***Supplied frcm North Pole 13.8-kV bus.
t Supplied frcm Gold Hill 34.5-kV bus.
tt Suppl Jed.from Healy 24.94-kV bus.
tttMaximum rating of two transformers in para! let.
x 1980 maximum demand through July 1980
xx 3 months data.
xxx5 months daTa.
+ 4 months data.
1977 1978 1979
5. 52 3.84 4.80
NIS 1.3QXX 1. 62
NIS 3. 12xxx 4. 92
2.3s+ 2. 05 2. 23
2.66 2. 61 2. 72
.84 0 91 .82
NIS 4.80 4.26
1. 56 na 4. 20
9.22 6. 71 5.40
10.68 9. 19 5. 69
NlS NIS 6.48
8.64 7.02 2.48
4.39 4.90 3.31
2.05 1.34 1.80
5.28 4.80 5.28
7.30 6.16 6. 91
7. 49 6. 19 4.90
7.39 5. 69 4.25
~ ~ 7.63
88.55 83. 16 79.70
++Includes a demand of approximately 300 kW at Murphy COme supplied by Eielson AFB.
+++Includes a demand of approximately 2,600 kW at Fort Greely supplied fran Fort Wainwright.
Abbreviations: na -r.b data ava i I ab I e.
NIS -Not in service.
B -26
(M\'1)
198QX
4.74
1. 76
3. 72
2. 10
3.85
.82
3.36
3. 06
5.66
5. 42
6.24
2.57
2. 84
1.94
5. 16
6.61
4. 72
4.25
~
75.80
Substation
Newby Road
* Estimated data.
TABLE 84.8: GOLDEN VALLEY ELECTRIC ASSOCIATION, INC.
Transformer**
Voltage
( kV)
69/12.47
DISTRIBUTION SUBSTATION DATA
PLANNED FACILITIES*
Rating***
(MVA)
12 (ApproxImate in-service date -1984)
** load tap. changing transformer un I ess otherwise noted.
***Maximum nameplate continuous full load rating at 65"C rise.
B -27
TABLE 85.1: UNIVERSITY OF ALASKA, FAIRBANKS
GENERATING CAPACITY AND DATA
Ge.nerat i ng Unit
Year of
Instal I at ion ~ caeacitz:
University of Alaska-51
University of AI as ka-S 2
University of AI aska-5.3
Un 1 versi ty of AI aska-D 1
University of Alaska-D2
Total Available Capacity
Unit
University of AI aska-5 1
University of Alaska-52
University of AI aska-53
University of Alaska-Dl
University of Al aska-D2
Voltage
( kV)
4.2
4.2
4.2
4.2
4. 2
1980
Power
Rating Factor
CMVA)
1.875 .so
1.S75 .so
12.50 .so
3.438 .so
.3.438 .so
* Impedance in per unit on 100-MVA base.
**Inertia constant in per unit on 100-MVA base •
.Abbreviation: 5T -Steam Turbine
{MW)
ST 1.50
ST 1.50
ST 1 o.oo
Diesel 2. 75
Diesel ~
18.50
Generator lmEedance*
xd X I d xnd
61.33 s.oo 5. 3.3
61 • .33 s.oo 5.33
13.SO 1. 77 1.02
23.27 s. 73 5.24
23.27 s. 73 5.24
B -28
xz
6. 93
6. 93
1.02
5e53
5. 53
Remarks
Coa I
Coal
Coal
Inertia
xo Constant**
2. 13
2. 13
0.34
1. 45
1.45
TABLE B5. 2: UNIVERSITY CF ALASKA, FAIRBANKS
Substation -Transformer
Two Winding Transformer
University of Alaska-1
Voltage
(kV >
69/4. 16
TRANSFORMER DATA
Rating*
(MVA)
7. 5
Tap Setting
LTC
*Continuous full load rating at 55°C rise.
**Transformer reactance in per unit on lOO~VA base.
Abbreviation: LTC -Load tap changing
B -29
Tap Range Reactance**
.8933
TABLE 86.1: MILITARY INSTALLATIONS, FAIRBANKS AREA
GENERATING CAPACITY AND DATA
Unit Total
Generating Unit ~ Capacity Caeacity
Ei el son AFB-S 1, 52 ST
E r el son AFB-53, 54 ST
Fort Greely -a 1, D2, D3 Diesel
Fort Greel y-D4, 05 Diesel
Fort Wainwright-S I, 52, S3, 54 ST
Total Available Capacity
Power
Unit Voltage Rating Factor
( kV) <MVA)
E i e I son AFB-5 1 , 52 7. 2 3.124 .8
Ei el son AFB-53, 54 7.2 6.250 1.0
Fort Greel y-o 1, 02, D3 4.2 1.250 .8
Fort Gree I y -D4, 05 4.2 1.563 .8
Fort Wainwright-12.4 6. 25 .8
51, 52, 53, 54
* Impedance in per unit on 100-MVA base.
**Inertia constant in per unit on 100 MVA base.
Abbreviation: ST -Steam Turbine
(MW) (MW)
2.50 5.0
6. 25 12.5
1.00 3.0
1. 25 2. 5
5.0 ~
43.0
Generator lmeedance*
~ X'd xnd
39.36 5.44 2.88
18.40 2.40 1.60
64.00 24.00 14.40
51. 18 19.20 11.52
18.40 2. 40 1.60
B -30
x2
2.88
2.08
15.20
12. 16
2.08
Inertia
xo Constant**
a. 96
0.64
4.00
3.20
o. 64
TABLE B6.2: MILITARY INSTALLATIONS, FAIRBANKS AREA
TRANSFORMER DATA
Substation -Transformer
Two W i nd i ng T ra ns formers
Eiel son AFB
Fort Greely
Fort Wainwright
Voltage
CkV)
69/7.2
24.9/2.4
69/12.4
Rating*
(MVA)
5.6
2.5
8.4
*Continuous fuJI load rating at 65"C rise.
**Transformer reactance is per unit on 100-MVA base.
Abbreviation: LTC -Load tap chang i ng
Tap Setting
LTC
LTC
B -31
Tap Range Reactance**
1.518
2.372
0.983
TABLE 97.1: MATANUSKA ELEC1RJC ASSOCIATION AND
Unit
Ekf ui"na -(APA)
Ekl utl'la -2 CAPA)
Year of
Installation
Total Ava i I able CapaciTy
ALASKA PCWER ACMI N I STRATI ON
EXISTING GENERATING CAPACITY
~ Cai:!acit:z:
(MW)
Hydro 15
Hydro 15
30
B -32
Remarks
Unit
Eklutna -1 <APA)
Ekl utna - 2
(APA)
Transformer
Ekl utna -1 (APA)
Ekl utna -2 (APA)
TABLE 87.2: MATANUSKA ELECTRIC ASSOCIATION AND
ALASKA POWER ADMINISTRATION
GENERATOR AND TRANSFORt;ER DATA
Fbwer Generator lm~edance*
Voltage Rating Factor xd X'd X"d
( kV) (MVA)
6.9 16.667 .9 6. 12 1.65 1. 16
6.9 16.667 .9 6. 12 1.65 1. 16
Tap
Voltage Rati n9 Setti n9
(kV) (MVA)
115/6.9
115/6.9
* Impedance in per unit on 100-MVA base.
**Inert-ia constarrt in per unit on 100-MVA base.
B -33
Inertia
x2 xo Constant**
1. 41 • 78
1.41 .78
Tap
Ranse Reactance*
TABLE B7.3: MATANUSKA ELECTRIC ASSOCIATION AND
ALASKA POWER ADMINISTRATION
TRANSMISSION LINE DATA
EXISTING SYSTEM
Transmission Circuit-Voltage
Frcrn Bus -To BJs
Pos Seq
Impedance*
Zero Seq
Susceptance** Impedance***
Length Conductor R X BC R0 X0
(mi)
Anchorage (APA)-Eklutna (APAl 115 kVt
Ancho.rage U.PAl -Briggs T<:~p (MEAl 8.8
Briggs Tap (MEAl -Plppel (MEAl 5.0
Pi ppel (MEAl -Parks (MEAl 6.4
Parks <MEAl -Reed <MEAl 6. 0
Reed (MEA) -Ekl utna (APAl .E_
Total
Briggs (MEAl -Briggs Tap CMEA)
Eklutna CAPAJ -Shaw (M::Al 115 kYt
Ekl utna (APAJ -Dow Tap (MEA)
Dow Tap (MEAl -Lucas (MEA}
Lucas <MEAl -LaZel le Tap (MEAl
LaZel Je Tap (MEAl -Shaw (MEAl
Total
Dow ( MEAl -Dow Ta p (MEA)
LaZe! I e -LaZelle Tap
Shaw CM::Al -Teeland (CEAl 115 kV
Shaw (MEAl-Herning (MEAl
Herni ng (MEAl -Teelan::t (CEA)
Total
33.4
6.3
8.6
5. l
4.3
~
22.3
1. 2
3.9
12.6
Douglas OEM -Teeland <CEAl 115 kV
Douglas <MEAl -Anderson Tap (MEA) 19.0
Anderson Tap (MEAl -Tee Ia n::t CCEAJ ~
Total 25.5
397 ACSR (26/7 l • 0156
397 ACSR (26/7) .0089
397 ACSR (26/7) .0113
397 ACSR (26/7l .0107
397ACSR C26/7l .0158
.0528
.0300
.0384
.0360
.0433
• 0061
.0035
.0045
.0042
.0050
397 ACSR (26/7) .0112 .0375 .0045
397 ACSR (26/7l .0106
397 ACSR (26/7) .0090
397 ACSR & MC .0076
397 ACSR (26/7l .0076
.0502
.0311
.0255
.0229
.0060
.0036
.0030
.0033
4/0 ACSR • 0032 • 0066 • 0008
397 ACSR C26/7l .0066 .0215 .0030
397 ACSR (26/7) • 0085 • 0259 • 0037
397 ACSR (26/7) .0139 .0422 .0060
556 ACSR (26/7) .0241 .1111 .0139
4/0 ACSR (6/0) .0219 .0423 .0048
B -34
.0347 .2023
• 019 7 • 1150
• 0253 • 1471
.0237 • 1360
• 0284 • 1656
• 0246 • 1440
• 0339 • 1977
.0203 • 1177
.0168 • 0977
.0167 .1026
• 0054 • 0242
.0161 .0933
.0190 .1161
.0309 .1891
• 0653 • 4339
.0365 .1574
Transmission Circuit-Voltage
from Bus -To Bus
Tab I e 87.3: M:!tanuska Electric Association and
AI aska Power Administration
Transmission Line Data
Existing System - 2
Length Conductor
{mil
Pos Seq
Impedance*
R X
Anderson (MEA)-Anderson Tap (MEA) 3.5 4/0 ACSR {6/0) .0118 • 0228
* Positive sequence impedance in per unit on 100-MVA base.
**Total I ine charging susceptance in per unit on 100-MVA base.
***Zero sequence impedance in per uniT on 100-MVA base.
t Ekl utna-Anchorage and Ekl utna-Lucas 115-kV circuits owned by APA.
Abbreviations: APA -AI as ka Power Adm i n i sTrati on
MEA -t-'atanuska Electric AssociaTion
CEA ~ Chugach ElecTrIc Association, Inc.
B -35
Zero Seq
Susceptance** Impedance***
BC R0 X0
.0026 .0194 .0870
TABLE 87.4: MATANUSKA ELECTRIC ASSOC lA T I ON AND
ALASKA PCWER ADMINISTRATION
DISTRIBUTION SUBSTATION DATA
EXIST l NG SYSTE r.f<
Transformer* Noncoi nci dent Substation Peak Demand Read l ngs (MW)
Substation Voltage Rating** 1975 1976
(kV) (MVAl
Anderson 115/12. 47 12/16/20 2. 74 3.98
Campttt 1.37 1. 12
Couglas 115/24 12/16/20 NIS NIS
Dow 115/12.47 5 1.98 1. 94
HerninJ 115/12.47 22/26/30*** 4.99 6.34
LaZe II e 115/12.97 12/16/20 NIS NIS
Lucas 115/12.47 1st 7. 82 9.31
Parks 115/12.47 10 5. 81 3. 79
Pippel 115/12.47 2ott 8. 06 10.44
Reed 115/12.47 5 na 1. 97
Settlers Bay 34.5/12.47 2. 5 NIS NIS
Shaw 115/12.47 12/16/20 NIS NIS
Site Bay 34. 5/12.47 1. 5 .....hlZ.. ~
36.94 43. 11
* Load "tap changing transformer un I ess otherwise noted.
** r~aximum nameplate continuous full load rating at 55°C rise.
***Two transformers in para I I el , one 10 MVA and one 12/16/20 MVA.
t Two transformers in parallel, one 5 MVA and one 10 MVA.
tt Two transformers in parallel, each 10 MVA.
tttsupplled at Eld ui"na.
x AI I distribution facilities are MEA.
Abbreviations: na -1\b data available.
NIS -Not in ser..ice.
B -36
1977 1978 1979 1980
6. 19 3. 94 4. 56 na
2.07 • 98 • 63 na
NIS 2.69 3.07 na
2.45 3.24 2.99 na
11.04 12.96 13.32 na
NIS NIS 3.26 na
12.72 14.98 11.38 na
4.42 4.32 4.22 na
9. 22 10.51 9. 50 na
2.59 2.98 2.98 na
.65 • 76 .50 na
NIS 4. 13 3.84 na
....1..:£ ~ ~ na
56.00 64.97 62.03 na
I
_______ ... .._~.,....._.__.,ao..,.. .... ••,. _______________ ..,. ____________________ ~~~....,~---------"----------------.....,.-...-.~--------------,
IDHlllll $11.11 lUCU I 1----· ·----~----~------'-,
---------------------------------, ANCHORAGE UUN I c I pAl I l.l4l.U
LIGHT & POWER i
UATANUSKA ELECTRIC I MI~S ASSOCIATION
nan
lUUIII
__ j
SlA. IJ I I "' r~-n·_;_II_--~---~-::::!.~----~J~~-:[~--~~~-+---~~---~~----~~~----~------r~---~~-----J
I
llUV
2Jt»:V
1151tV
CIIUGACil EUCTRIC ASSOCIATION
• -USIUlf CfQ'fl un
II)'(
~ J ------------------------------------~------------------------~-------
IIIli AII
ANCHORAGE AREA ONE-LINE DIAGRAM -1984 SYSTEM
I
FIGUREB.2.
I
--------------------------------------------------------------------------------------------------------
MD
IIU
&•v
DIIJIAI'UII'
1Jti'411Sin
f6 .IUSII.A
AIII'Ull
'"'
IIIII
SIU5l
-+~1--f-ZUIOOfK
ll.\llllll*
fl
1/.IH~ICitl
I
I
I • lnuu GOLDEN VAllfY '---n:-lG£1-R-oo------s.-JiliiAI«s
ElECTRIC ASSOCIATION
---------·-------------------------------------,
INlW Jt----1
(lfiSQI
AU
I t
I
I [ _________________________________________ ::_ ____ _]
FAIRBANKS AREA ONE-LINE DIAGRAM-1984 SYSTEM FIGURE B.31Ul
APPENDIX C
ECONOMIC CONDUCTOR SIZES
TABLE OF CONTENTS
C1 -INTRODUCTION -----------------------------------------------C -1
C2 -LINE CAPITAL COST ------------------------------------------C -
C3 -CAPITALIZED COST OF LOSS -----------------------------------C - 2
LIST OF TABLES
Number
C3.1
C3.2
C3.3
Title
Transmission Line to Anchorage
Developnent of capitalized Cost of IDss
Transmission Line to Fairbanks
Development of capitalized Cost of Loss
Summary of Economic Factors and
Proposed Conductor Sizes
LIST OF FIGURES
Number
C3.1
Title
Transmission -Total Cost per Mile as a Function of
Conductor Area
APPENDIX C
ECONOMIC CONDUCTOR SIZES
C1 -INTRODUCTION
In EHV transmission, line conductors and conductor bundles must be sized
to minimize corona, RI and audible noise effects. An additional factor
that needs to be quantified is the economic incentive to increase the
conductor section still further to achieve savings in the future cost of
line loss.
This appendix deals with the economic aspects of conductor sizing, and
since both line costs and line losses are proportional to line length,
the analysis is carried out on the basis of costs per circuit-mile.
C2 -LINE CAPITAL COST
Tr ansm.ission costs are generally a function of the transmission voltage
and conductor size, modified by local considerations such as
meteorological factors, access, transport costs and local labor costs.
At a particular voltage, the variation in line cost as a function of
conductor area is normally of the form.
Line cost per mile = K1 + K2 (kcmil)a
c -1
On the basis of line cost estimates for Alaska, values of "K 1 11
1
"K2" and "a 11 have been determined. These are approximate, but
they describe the relationship between line cost and conductor size
sufficiently well to be used as a guide in determining the economic size
of line conductor. The equations are shown below.
230 kV: $/mile~ 110 000 + 16 {kcmil)1.18
345 kV: $/mile~ 160 000 + 16 (kcmil)1.18
500 kV: $/mile C! 285 000 + 16 (kcmil) 1.18
C3 -CAPITALIZED COST OF LOSS
Line loss varies directly as the square of the line loading and inversely
as the conductor cross-sectional area. Since the line loading varies in
a daily pattern and also throughout the life of the facility, these
variations must be taken into account.
Transmission line loading over the life of the facility can only be
estimated at this time. According to generation planning studies, each
time a block of 400 MW of generation is commissioned (in years 1993,
1996 and 2000) 1 this capability is fully absorbed by the system. It is
further assumed that all of the average energy capability at Susitna
would be utilized at each development stage, resulting in load factors
{LF) and loss load factors (LLF) as indicated in the table below.
In this table no generation additions are included after year 2000 as the
contribution to loss energy from any additional peaking capacity is
assumed to be negligible.
c-2
Line .Loadin9:s (MW)
Susitna To To
Period ca32acitz Ener9:2: LF LLF* Anchora9:e Fairbanks
(MW) ( GW • h)
1993 to 1996 400 2 990 0.85 0.786 320 80
1996 to 2000 800 3 252 0.46 0.336 640 160
2000 to 2043 1 200 6 227 0.59 0.469 960 240
Expressing line loading and line resistance in per unit on surge
impedance loading (SIL) and surge impedance (Zc) base leads to
the following expressions.
Line resistance 100 = ohms per mile kcmil
100 1 = x --per unit per mile kcmil Zc
If line loading = S per unit on SIL base
Then line loss per mile 2 100 1 = _S x kcmil x Zc per unit
and since SIL kV2
= -zc (MW)
Line loss per mile 2 100 1 kV2
= S X X -X -(MW/mile) kcmil Zc Zc
Annua~ loss energy/mile 2 100 kV2
= S X kcmil X~ X 8.76 X LLF
Zc (GW•h/mile)
And if the cost of loss energy = c $/kW•h
= c $ million/GW•h
Then ann~ cost of loss 2 100 kV2
= s X X 2· X 8.-76 X LLF. X c
kcmil Zc ($ million/mi~e)
*Loss load factor (LLF) is estimated as LLF = LF2 + LF
2
c -3
A typical value of C for Susitna is $0.035/kW•h. This energy
cost is an average figure derived in the OGP-5 planning studies based
on zero inflation and 3 percent net cost of money.
.·.Annual cost of loss= 30.66 s 2 kv2
...;;..;.__,;;...;._=o.,~..;..._ LLF ($ million/mile)
kClllil zc2
In Tables C3.1 and C3.2 the capitalized cost of loss per mile is derived
for transmission to Anchorage and Fairbanks, respectively, as a function
of conductor size and for the line voltages that are being considered.
The capitalized cost of loss is derived in three components, representing
the three stages of developnent of the project. In all cases two
circuits are assumed from the outset for security reasons. In the case
where three circuits are used for the ultimate line loading, it is
assumed that the third circuit is added at the final (1,200 MW) stage of
developnent.
In Table C3.3 the line capital cost and capitalized cost of loss (as
developed in Tables C3.1 and C3.2) are shown as a function of conductor
area for each voltage and transmission alternative. The indicated
optimum conductor areas are also given in the table and these were
derived as follows.
If line capital cost = K1 + K2 (kcmil)a $ million/mile
and capitalized cost of loss
K3
= kcmi1 $ mil1ion/mdle
Total. cost per mile
K3 = K 1 + K ( kcmi.l) a + $ million/mile 2 kcmil
c -4
Differentiating with respect to kcmil and equating to zero for
minimum total cost per mile.
d cost
d koail (kcmil)2
1 K3 a • K
2
( kcmil ) a-= _._.;;;.__
(kcmil)2
K3
a•K 2
(kCID.il)a+1 =
and
= 0
In two cases, namely 500-kV transmission to Anchorage and 345 kV to
Fairbanks, line losses are relatively low and lead to indicated economic
conductor areas that are below the acceptable limit from an RI and Corona
point of view. The proposed conductor sizes which are shown at the
bottom of Table 3 have been adjusted, where necessary, to frOVide
acceptable Corona and RI performance.
The relationship between line capital cost and total cost (including
capitalized cost of loss) is shown graphically as a function of conductor
area in Figure C3. 1. The cases illustrated are for 345 kV to Anchorage
and 230 kV to Fairbanks, the two cases where cost of loss was a factor in
the proposed conductor arrangement.
c -5
'l'A,BLE C3.1: TIUINSHISS10!4 LINE 'l'Q ANCHORAGE DEVELOl>HEN'l' Oli' Cl\PITl\LIZED COST OF LOSS
Loading per
Anllua1 2 Circuit
Total No, of on SIL Cost of
Period Load Circuits Basel IE. Loss
"iiWl (MW) 1S=PiiT cM·kc~il)
cct•fllde
1993 -1996 320 2 160 0,386 0,786 5,195
1996 -2000 640 2 320 0.711 0,336 8,861
2000 -2043 960 2 480 1.157 0,469 27,654
1993 -1996 320 2 160 o. 386 0,786 5,195
1996 -2000 640 2 320
:> ~ 0, 771 0,336 6.661
"' ...
2000 -2043 960 l 320 PI o. 771 0.469 12,368
1993 -1996 320 2 160 0,178 o. 786 2.474
1996 -2000 640 2 320 :,;; 0,356 0,336 4,230
a
0
2000 -2043 960 2 480 "' 0,533 0,469 13.236
1siL base valuea are 415 HW (345 kV) and 900 HW (500 kV) ,
2Annua1 cost of loss ~ 30,66 s 2 ·kV2 • LLF/zc2 based on losses valued at $0,035/kW.h,
3n ~ duration of load period
4m ~offset from· present worth datum,
5
Present worth factor ~ f f;---1 --:-J x -1--, annual discount rate U) = 3 percent,
[ (l+i) :J (lt-i)nl
3 4 n Ill
(yr) TYrT
3 0
4 3
43 7
Total at 345 kV (2
0
4
43 7
Total at 345 kV (3
3 0
4 3
43
Total at 500 kV (2
Present 5 Capitalized
Worth Cost of
~ Loss
(SM·kcmil)
cct·mile
2.8286 14.695
3,4017 30.142
19.4995 ~
circuits) 587,976
2.8286 14,695
3,4017 30,142
19,4995 ~
circuits) 286,016
2,8286 6,998
3,4017 14,389
19.4995 ~
circuits) 279.482
TABLE C3.2; TRANSMISSION LINE i~ FAIRBAN~ DEVELOPMENT OF CAPITALIZED COST OF LOSS
Loading per
Annual2 Circuit
Total No, of on SIL Cost of
~ Load Circuits Basel ~ Loss
TMii) (MW) (S-pu) { $M·kcmil)
cct•m>.le
1993 -!996 60 2 40 0.292 0,766 0, 7290
1996 -2000 160 2 80 ~ 0,584 0.336 1. 2466
0
"' 3. 9151 2000 -2043 240 2 120 "' 0,676 0,469
1993 -1996 80 2 40 0,100 0,786 0,3240
1996 ~ 2000 160 2 80 ~ 0,200 0.336 0,5539
II>
2000 -2043 240 2 120 .. .., 0,300 0,469 1,7397
1 siL base values are 137 HW (230 I<V) and 400 MW (345 I<V),
2 Annual cast of loss • 30,66 s 2 ·kV 2 • LLF/zc2 based on losses valued at $0,035/I<W•h,
3n ~ duration of load period,
4m -offset from present worth datum,
5
Present worth factor = f fl -!..___. =1 x -1--, annual discount rate (i) • 3 percent. ~ (l+i)0_j (1+i)m
Present 5
3 4 Worth
n m ~ (yi") Vr>
3 0 2.8286
4 3 3,4017
43 7 19.4995
Total at 230 I<V (2 circuits)
3 0 2,8286
4 3 3,401'7
43 7 19.4995
Total at 345 I<V (2 circuits)
Capitalized
coat of
Loss
cM·kc~il)
cct~m1le
2.0620
4.2406
~
82.6451
0,9165
1,8842
~
36,7240
TABLE C3.3: SUMMARY OF ECONOMIC FACTORS AND PROPOSED CONDUCTOR SIZES
Transmission to Anchorage
500 kV ~3..:.45::-,..:k~V'-:--------~=---:-:-.-
2 Circuits 3 Circuits 2 Circuits
Capital cost of line
($M/ndle)
caeitalized cost of loss*
($M/mile)
0Etimum conductor area**
(MCM)
Pro12osed conductors
0.285 + ~ kcmil 1 •18
106
279,482
kcmil
1; 946
3x795***
0.16 + 16 kcmill.lB
106
286,106
kcmil
1,967
2x954
*Capitali~ed cost of loss expressions are derived in tables 1 and 2,
1
**Optimum conductor area= {capitali~ed cost of loss)2,19 kcmil per phase.
\i6xl,19
0.16 + 166 kcmill.lB
10
587,976
kcmil
2,737
2xl,351
Transmission to Fairbanks
0,16 + ~ kcmi11.18
106
36,7240
kcmil
767
2x795***
0,11 + ~ kcmill.l8
106
82,6451
kcmil
1,113
lxl,272
***The economic conducto.r areas for 500 kV to Anchorage and 345 kV to Fairbanks are smaller than the minimum needed for RI and Corona performance,
Hence, RI considerations will dictate conductor si~e,
-U)
:z
0
:J
_.J
:t
-tit
w
_.J
::E
1-
::l
0
0::
u
a:: w a..
1-
(()
0
0
0.4
SUSITNA TO FAIRBANKS AT 230 KV
I
TOTAL COST INCLUDING CAPITALIZED
0.3 -COST OF LOSS (TWO CIRCUITS)
I
0.2 -
LINE CAPITAL COST
0.1 --~---
OL---------~--------~--------~
500 1000 1500
TOTAL CONDUCTOR AREA (kcmil)
PER PHASE
2000
0.7 .....-------r---------..-----.--------------.
SUSITNA TO ANCHORAGE AT 345 KV
0.6 TOTAL COST INCLUDING CAPITALIZED ~
COST OF LOSS (TWO CIRCUITS)
(/) z
Q
_.J
...J
~
~ 0.5
w
...J
~
!::
::>
0 a::
u
a:: w a..
1-
(()
8
TOTAL COST INCLUDING CAPITALIZED
COST OF LOSS (THREE CIRCUITS)
0.4
0.3
LINE CAPITAL COST
0.2L--------~----~-------L------~
1500 2000 2500 3000 3500
TOTAL CONDUCTOR AREA (kcmil)
PER PHASE
TRANSMISSION -TOTAL COSTS PER MILE AS A FUNCTION OF CONDUCTOR AREA
FIGURE C3.1
APPENDIX D
COST ESTIMATES
LIST OF TABLES
Number
0.1
0.2
0.3
0.4
o.s
0.6
Title
Transmission and Substation Unit Costs
Transmission Line Capital Costs
Substation Capital Costs
Transmission and Substation Annual Charges
Transmission Line Land Ac.quisition Costs
Capitalized Transmission Line Losses
API'ENDIX D
COST ESTIMATES
The economic analysis for the Susitna transmission system was carried
out using cost estimates based on 1981 unit costs, without escalation,
for all equipment and services. The unit costs for all transmission
and substation equipment are given in Table o. 1. The principal para-
meters of the five transmission alternatives analyzed in detail are as
follows.
Susitna to Anchorage Susitna to Fairbanks
( 140 Miles) {189 Miles)
Number of Number of
Alternative C-ircuits Voltag:e Conductors Circuits Voltag:e Conductors
(kV) (kcmil) (kV) {kcmil)
2 345* 2 X 351 2 345 2 X 795
2 3 345 2 X 954 2 345 2 X 795
3 2 345* 2 X 351 2 230* X 272
4 3 345 2 X 954 2 230* X 1 272
5 2 500 3 X 795 2 230* 1 X 272
The b:ansmission line capital cost estimates for the five transmissiort
alternatives are shown in Table o. 2. The 1993 line costs include an
adjustment for the use of a larger conductor than required by the
intertie, 9 years before the construction of the Susitna transmission
system. This adjustment accounts for intertie construction with con-
ductors ultimately required for Susitna transmission. The adjustment
consists of the difference in line costs multiplied by the length of
the line section in question and the factor to account for the
*Denotes series compensation.
D - 1
accummulated interest for the incremental conductor cost. It is
calculated as follows.
Adjustment= length•[(1.00+i)n-1.00]•(Cs-Ci}
= length•[{1.Q3)9-1.00]•(Cs-Ci}
= length•0.3048•(Cs-Ci}
where
i = discount rate {3.0 percent)
n = time period (9 years)
Cs = cost of Susitna conductor in $M/mile
Ci = cost of conductor required for intertie in $M/mile.
The substation capital cost estimates are shown in Table 0.3 and
include a base cost plus costs for major components at each station.
The base cost includes land acquisition, site preparation, foundations,
etc. Cost estimates of major equipment, such as circuit breakers,
transformers, etc, include ~~e costs of all ancillaries such as
disconnect switches, potential and current transformers, controls,
instrumentation, etc. At the generating stations all EHV circuit
breakers are included, but generator transformers and low-voltage
breakers are excluded. These are included in the powerhouse estimates.
Similarly at the load centers all EHV breakers are included as well as
tne necessary circuit entries at the subtransmission voltage (230 kVor
138 kV) for each transformer bank. The remainder of the lower voltage
station is common to all alternatives and therefore excluded from the
economic comparison. At Anchorage, transformation to 230 kV is assumed
on the west side of Knik. Arm implying cable crossings at 230 kV. The
cable crossings and other 230-kV equipment are considered comtoon to all
ac transmission alternatives for Susitna and their costs have been
excluded fran this estimate. They must be included for comparison of
schemes with different Knik Arm crossing configurations such as HVDC
transmission from Susitna.
D - 2
The calculations of annual charges for transmission lines and
substations are shown in Table D. 4. Annual charges include the
following components.
Item
Operating and maintenance
Insurance
Interim replacement
Contribution in lieu
of taxes
TOTALS
Percent of
Transmission
Capital Per
Year
1.00
0.10
0.15
2.00
3.25
Percent of
Substation
Capital Per
Year
2.00
0.10
0.15
2.00
4.25
At a discount rate of 3. 0 percent and for a 50-yr period of analysis
from 1993 to 2043 the capitalized annual charges are calculated as
follows.
For equipment commissioned in 1993
Transmission lines: 3. 25 percent
0.03
I( 1. 03) so -1 • 0 01
[ ( 1. 03 )SO J
Substations:
== 83.62 percent of 1993 transmission
line capital cost
4.25 vercen.t
0.03
n1.03)50_ 1.ool
[ (1.03}5o · :J
= 109.35 percent of 1993 substation capital cost
D - 3
For equipment conunissioned in 2000
Transmission lines: 3.25 percent
0.03
[11.03)43-1.ool
[ (1.03)43 J
= 77.94 percent of 2000 transmission line
capital cost
Substations: 4.25 percent
o. 03
11_1.03)43 -1.0Q1
[ (1.03)43 J
= 101.92 percent of 2000 substation capital cost
Costs of land acquisition and clearing for transmission lines are
calculated in Table 0.5. It is assumed that all right-of-way
requirements will be acquired in 1993. This includes the land
acquisition costs for all additional circuits to be constructed in the
year 2000.
Costs of capitalized transmission line losses are calculated in
Table o. 6. Unit costs per mile for capitalized transmission losses
have been derived from the costs of loss developed in Appendix C,
"Economic Conductor Sizes". In the case of the line section from
Watana to Devil canyon the unit costs have been adjusted to take into
account the loading that will apply during the various stages of
project development.
D - 4
Transmission
Line Costs
Voltage
(kV l
230
230
230
345
345
345
500
Land Acquisition
Voltage
( kV)
230
345
345
500
Substations
Voltage
CkVl
138
230
345
500
TABLE 0.1: TRANSMISSION AND SUBSTATION UNIT COSTS
Conductor Base Cost
(kern i I l ($/circuit mi lel
1 X 954 120,000
1 X 1 272 136,000
1 X 351 140,000
2 X 795 190,000
2 X 954 207,000
2 X 1 351 251,000
3 X 795 326,000
and Clearing
Number of Circuits
2
2
3
2
Station Base Cost**
($ M iII ion)
1.000
1.500
2.000
2.500
Final Cost*
($/circuit mile)
162,000
184,000
189,000
256,000
279,00.0
339,000
440,000
$/Mile
70,0()0
75,000
96,000
80,000
Circuit
Breaker Position
($Million>
0.400
0.700
1.000
1.600
Table D. 1
Transmission and Substation Unit Costs-2
Auto trans formers (inc I ud i ng 1 5-kV tert fary)
Voltage
( kV l
230/138
345/138
500/138
345/230
500/230
75 WA
($ Mi II ion)
o.soo
o. 700
Generator Transformers
Voltage
( kV)
345
500
Shunt Reactors
Voltage
( kV)
345
500
4. 20
s.oo
50 WARS
($/kVAR)
24.60
Series Compensation (all voltages)
$14.00/kVAR
Static VAR Sources <Tertiary volte~gel
$30.00/kVAR
150 WA
( $ M i I I ion)
o. 800
0.900
1.200
0.900
1. 200
75 WARS
($/kVAR)
1. 11
17.20
250 M'IA
($Mill ion)
1. 100
1. 300
1. 600
1.300
1.600
* Fl naJ transmission I ine costs (page 1 of table) include 20 percent contingency, pi us
5 percent eng i neer i ng, 5 percent construction management and 2. 5 percent owner 1 s cost.
**Substation base cost (page 1 of table) includes land acquisition, site preparation,
foundations, etc.
TABLE 0.2: TRANSMISSION LINE CAPITAL COSTS
Transml ss ion Alternative
I 2 3 4 5
Year 1993 Transmission Circuit Circuit Circuit Circuit Circuit
Line Costs Unit Cost Milas ~ Mi ies ~ Miles ~ Miles $M Miles .!!:!_
($M/mi)
Watana to Dev i I Canyon (27mi)
Voltage Conductor
345 l<V 2 X 954 l<cmi I 0.207 54 11. 18 54 11. 18
345 kV 2 x 1,351 kcmi 1 0.251 54 13.55 54 13.55
500 kV 3 X 795 kcmll 0.326 54 17.60
Oev I I Canyon to Anchorage ( 140 ml)
345 kV 2 X 954 kcmi I 0.207 280 57.96 280 57.96
345 kV 2 X 1,351 kcmil 0.251 280 70.28 280 70.28
500 kV 3 X 795 kcmll 0.326 280 91.28
Dev i I Canyon tofairbanks C189mi)
230 kV 1 X 1,272 kcmi I 0.136 293 39.95 378 51.41 378 51 .41
230 kV l X 1,351 kcmil 0.140 85 11.90
345 kV 2 )( 795 kcmi I o. 190 293 55.67 293 55.67
345 kV 2 X 954 kcmil 0.207 85 17.60
345 kV 2 X 1,351 kcmil 0.251 85 21.34
Subtotal 1993 I i ne costs 160.84 142.41 135.68 120.55 160.29
Contingency (20 percent) 32.17 28.48 27. 14 24.11 32.06
Subtotal 193.01 170.89 162.82 144.66 192.35
Eng I nearIng and Management 24.13 21.36 20.35 18.08 24.04
( 12.5 percent)*
TOTAL 1993 Transmission Line Costs 217.13 192.25 183. 17 162.74 216.39
Adjustment for Advanced lntertie
Construction With Larger Conductor** $M/mi $M $M/mi $M $M/mi $M $M/mi $M $Mimi $M
WHiow to Gold Creek (80 mi) (0.251-0.207) 1.07 (0.207-0.207) 0 (0.251-0.120) 3. 19 ( o. 207-0.120) 2.12 ( 0.3 26-0. 120) 5.02
Go I d Creek to Hea I y ( 85 mi ) (0.251-0.207) 1.14 (0.207-0.207) 0 (0.14<r0.120) 0.52 (0. 136-0.120) 0.41 (0. 136-0. 120) 0.41
Subtotal I ntert i e adjustment 2.21 0 3.71 2.53 5.43
Contingency, engineering, etc o. 77 0 1.30 0.89 1.90
Total adjustment 2.98 0 5.01 3.42 7.33
TOTAL Adjusted 1993 Transmission Line Costs 220.12 192.25 188.18 166.16 223.72
Table 0.2: Transmission Line Capital Costs-2
Transmission Alternative
I ~2--~--------
CI rcu It Gi rcu It
3
Year 2000 Transmission
Line Costs Unit Cost Miles $M Miles $M
Circuit
Miles
<$Wmi>
Dav II Canyon to Anchorage ( 140 m I>
Vo I tage Conductor
345 kV 2 x 954 kcmi I o. 207
Contingency (20 percent)
Subtotal
Eng I neer I ng and Management
( 12.5 percent)*
TOTAL 2000 TransmIssIon Ll ne
Capital Costs
* EngIneerIng and Management Inc I udes
-EngIneering 5. 0 percent
-Construction Management 5.0 percent
-Owner's Cost 2.5 percent
-Total 12.5 percent
140 28.98
5.80
34.78
4.35
39.12
**lntertie adjustment accounts for construction with a larger conductor than required by the intertle
9 years before construction of Susitna transmission system.
4
Circuit
Miles
140 28.98
5.80
34.78
4.35
39.12
5
Circuit
Miles
TABLE D.3: SUBSTATION CAPITAL COSTS
Transmission Alternative
I 2 3 4 5
Year 1993 Substation Costs Unit Cost Quantitl $M Quantitl $M
($M)
Quantltl _!!:!_ Quantlt~ $M Quant it~ $M
Anchorage
Base cost • 345 kV 2.00 2.00 2.00 2. 00 2.00
-500 kV 2.50 2. 50
Circuit breakers -230 kV 0. 70 6 4.20 6 4.20 6 4.20 6 4.20 6 4.20
-345 kV 1.00 9 9.00 9 9.00 9 9.00 9 9.00
-500 kV 1.60 11 17.60
Transformers-345/230 kV, 250 t-tVA 1.30 4 5.20 4 5.20 4 5.20 4 5.20
-500/230 k v, 250 MVA 1. 60 4 6.40
Shunt reactors-500 kV, 50 MVAR 1. 23 2 2.46
Static VAR sources (MVAR) o. 03 400 12.00 400 12.00 400 12.00 400 12.00 200 6.00
Subtotal 32.40 32.40 32.40 32.40 39. 16
ContIngency (20 percent> ~ ~ 6.48 ~ ~
Subtotal 38.88 38.88 38.88 38.88 46.99
Engineering and management ( 12.5 percent)* 4.86 4.86 ~ 4.86 5.87
TOTAL 1993 Anchorage Station Cost .Qill. 43.74 43.74 43.74 52.87
WI I low
Base cost -345 kV 2.00 2.00 2.00 2. 00 2. 00
-500 kV 2. 50 2. 50
Circuit breakers -138 kV 0.40 3 1.20 3 1. 20 3 I. 20 3 1.20 3 1. 20
-345 kV 1.00 9 9.00 9 9.00 9 9.00 9 9.00
-500 kV 1.60 11 17.60
Tra.nsformers-345/138 kV, 75 MVA 0.50 2 1.00 2 1.00 2 1. 00 2 1. 00
-500/138 kV, 75 MVA o. 70 2 1.40
Shunt reactors -500 kV, 75 MVAR 1.29 2 2.58
Subtotal 13.20 13.20 13.20 13.20 25.28
Table 0.3: Substation Capital Costs -2
Transmission Alternative
I 2 3 4 5
Year 1993 Substation Costs Unit Cost Quant it~ .!!:!. Quant it~ $M Quant it~ .!!:! Quantitl $M Quant it~ $M
C$M)
Contingency {20 percent) 2.64 ~ 2.64 ~ 5.06
Subtotal 15.84 15.84 15.84 15.84 30.34
Engineering and management {12.5 percent)* ~ 1.98 ~ _h2!!_ 3.79
TOTAL 1993 Willow Station Cost 17.82 17.82 17.82 17.82 34.13
Dev II Canyon
Base cost -230 kV 1. 50 I. 50 I. 50 I. 50
-345 k.V 2.00 2.00 2.00 2.00 2.00
-500 kV 2. 50 2. 50
Circuit breakers -230 kV o. 70 8 5.60 8 5.60 8 5.60
-345 kV I. 00 12 12.00 12 12.00 15 15.00 15 15.00
-500 kV 1.60 15 24.00
Transformers -345/230 kV, 150 MVA o. 90 3 2.70 3 2. 70
-500/230 kll, 150 MVA 1. 20 3 3.60
Generator transformer Incremental cost, 220 MVA o. 176** 3 0.53
Subtotal 14.00 14.00 26.80 26.80 37.73
Contingency {20 percent) 2.80 2.80 5.36 5.36 7.55
Subtotal 16.80 16.80 32.16 32.16 45.28
Engineering and management ( 12. 5 percent)* ~ 2.10 4.02 4.02 ~
TOTAL 1993 Oev II Ganyon Station Cost 18.90 18.90 36.18 36.18 50.94
Watana
Base cost -.345 kV 2.00 2.00 2. 00 2.00 2.00
-500 kV 2.50 2.50
Circuit breakers -345 kV 1.00 9 9. 00 9 9.00 9 9.00 9 9.00
-500 k\1 1. 60 9 14.40
Generator transformer Incremental cost, 220 MVA o. 176** 4 ~
Subtotal 11.00 11.00 II. 00 II. 00 17.60
Table 0.3: Substation Capital Costs -3
Transmission Alternative
1 2 3 4 5
Year 1993 Substation Costs Unit Cost Quant it~ ..!!1 Quant it~ $M Quant it~ ..!!1 Quantitl $M Quantitl ~
($M)
Conti. ngency ( 20 percent) 2.20 2.20 2.20 2.20 3.52
Subtotal 13.20 13.20 13.20 13.20 21.12
Eng lneer I ng and management ( 12.5 percent)* ~ ~ ~ ~ 2.64
TOTAL 1993 Watana Station Cost 14.85 14.85 14.85 14.85 23.76
fairbanks
Base cost -230 kV 1.50 1.50 1.50 1.50
-345 kV 2.00 2.00 2.00
Circuit breakers -138 kV 0.40 4.5 1.80 4.5 1.80 4.5 1.80 4.5 1.80 4.5 1.80
-230 kV 0.70 8 5.60 8 5.60 8 5.60
-345 kV 1.00 10 10.00 10 10.00
Transformers -230/138 kV, 150 MVA 0.80 3 2.40 3 2.40 3 2.40
-345/138 kV, 150 MVA 0.90 3 2.70 3 2.70
Shunt reactors -345 kV, 75 MVAR 0.83 2 1.66 2 1.66
Static V/'R sources <MV /'R) 0.03 100 3.00 100 3.00 200 6.00 200 6.00 200 6.00
Subtotal 21. 16 21. 16 17.30 17.30 17.30
Contingency (20 percent) 4.23 4.23 3.46 3.46 3.46
Subtotal 25.39 25.39 20.76 20.76 20.76
Engineering and management ( 12.5 percent)* ~ __h!l 2.60 2.60 2.60
TOTAL 1993 fa lrbanks Stat ion Cost 28.57 28.57 23.36 23.36 23.36
TOTAL 1993 Substation Capital Cost 123.88 123.88 135.95 135.95 185.06
Table 0.3: Substation Capital Costs-4
Transmission Alternative
I 2 3 4 5
Year 2000 Substation Costs Unit Cost Quantit:t 1!1 Quant It~ !!i Quant it~ 1!1 Quantlt:t $M Quantlt~ $M
($M)
Anchorage
Circuit breakers -230 k V o. 70 3 2. 10 3 2. 10 3 2. 10 3 2. 10 3 2. 10
-345 kV 1.00 3 3.00 5 5.00 3 3.00 5 5.00
-500 kV 1.60 3 4.80
Transformers-345/230 kV, 250 MVA 1.30 2 2.60 2 2.60 2 2.60 2 2.60
-500/230 k v. 250 MVA 1.60 2 3. 20
Series compensation (MVARl 0.014 430 6.02 430 ~
Subtotal 13.72 9. 70 13.72 9. 70 10. 10
Contingency (20 percent) 2.74 ___h2! ....b.1i ~ 2.02
Subtotal 16.46 II. 64 16.46 II. 64 12. 12
Engineering and management (12.5 percent)* 2.06 _!_d§_ 2.06 ____hi§_ ____hg
TOTAL 2000 Anchorage Station Cbst 18.52 13.10 18.52 13.10 ...!hl!
WII low
Circuit breakers -138 kV o. 40 I. 5 0.60 I. 5 0.60 I. 5 0.60 I. 5 0.60 I. 5 0.60
-345 kV 1.00 2 2.00 5 5.00 2 2.00 5 5.00
-500 kV I. 60 2 3.20
Transformers -345/138 kV, 75 MVA 0.50 0.50 0.50 0.50 0.50
-500/138 kV, 75 MVA o. 70 o. 70
Series compensaTion (1-!VAHl 0.014 773 10.82 773 10.82
Subtotaf 13.92 6. 10 13.92 6.10 4.50
Coot i ngency (20 percent) 2.78 _!:n_ 2.78 1.22 0.90
Subtotal 16.70 7. 32 16.70 7.32 5. 40
EngineerIng and management ( 12. 5 percent)* 2.09 0.92 2.09 0.92 0.68
TOTAL 2000 Wii low Station Cost 18.79 8.24 18.79 8.24 6.08
Year 2000 Substation Costs
Dev II Canyon
Circuit breakers-230 kV
-345 kV
-500 kV
Transformers -345/230 kV, 150 MVA
-500/230 kV, 150 MVA
Subtotal
Contingency (20 percent)
Subtotal
Table 0.3: Substation Capital Costs - 5
Transmission Alternative
I ~2----~~---
Unit Cost Quantity J.!i Quantity $M
( $M)
o. 70
1.00
1.60
0.90
1. 20
3 3.00
3.00
0.60
3.60
5 5.00
Englneerjng and management (12.5 percent)* _Q&
5.00
1.00
6.00
0.75
TOTAL 2000 Devil Canyon Station Costs
fairbanks
Cl rcul t breakers -138 kV
-230 kV
-345 kV
Transformers -230/138 kV, 150 MVA
-345/138 kV, 150 MVA
Ser-1 es compensatIon ( MVAR)
Subtotal
ContIngency (20 percent)
Subtotal
0.40
o. 70
1. 00
0.80
o. 90
0.014
1. 5
~
0.60
1. 00
o. 90
Engineering and management (12.5 percent)*
2.50
0.50
3. 00
0.38
TOTAL 2()00 FaIrbanks Station Costs
TOTAL 2000 Substation Capital Costs
*Engineering and management includes-engineering 5. 0 percent
5. 0 percent -construction management
-owner's cost 2.5 percent
Total 12.5 percent
1. 5 0.60
I. 00
o. 90
2. 50
0.50
3. 00
0.38
3.38
3 4 5
Quantity $M Quantity .!!1 Quantity $M
1
3
I. 5
I
430
o. 70
3.00
0.90
4.60
0.92
5. 52
0.69
6.21
0.60
0.70
0.80
1
5
1. 5
1
6.02 430
8. 12
~
9. 74
I .22
10.96
0.70
5.00
o. 90
6.60
-l..!R
7. 92
0.99
8.91
0.60
o. 70
0.80
3
1. 5
1
6.02 430
8. 12
~
9. 74
1.22
10.96
o. 70
4.80
6. 70
___hli
8.04
__!_:.Q!_
0.60
o. 70
o.so
6.02
8. 12
___!_:.g
9. 74
~
10.96
**Cost of generator transformers for 345-kV transmission is Inc I uded in powerhouse cost est lmates.
Alternative 5 requires adjustment for incremental cost of 500-kV transformers.
TABLE 0.4: TRANSMISSION AND SUBSTATION ANNUAL CHARGES
Transmission Alternative
' 2 3 4 5
Percent of Capital I zed Cap I tall zed Capitalized Cap ita II zed Cap i tall zed
Capital Capital Annual Capital Annual Capital Annual Capital Annua I Capital Annual
Cost* Cost Charges Cost Charges Cost Charges Cost Charges Cost Charges
($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)
1993 Capitalized Annual Line 83.62 217.13 181.56 192.25 160.76 \83. 17 153. 17 162.74 136.06 216.39 160.95
Charges
2000 Capitalized Annual Line 77.94 39. 12 30.49 39. 12 30.49
Charges
1993 Capitalized Annual Station 109.35 123.86 135.46 123.88 135.46 135.95 148.66 135.95 146.66 165.06 202.36
Charges
2000 Capital I zed Annual Station 101. 92 44. 74 45.60 31.47 32.07 54.48 55.53 41.21 42.00 39.73 40.49
Charges
*Capitalized annual charge percentages are developed In the text on page D-3.
TABLE 0.5: TRANSMISSION LINE LAND ACQUISITION COSTS
Transmission Alternative
1 2 3 4 5
rransmlsslon Line Unit Cost Length $M Length ..!!:! Length ..!!:! Length $M Length $M
<$Mimi) (miles) (miles) (mi I es) (miles) (miles)
Number of
ioltage Circuits
230 kV 2 0.070 189 13.23 )89 13.23 189 13.23
~45 kV 2 0.075 356 26.70 216 16.20 167 12.53 27 2.03
345 kV 3 o. 096 140 13.44 -140 13.44
500 kV 2 o.oso 167 13.36
TOTAL 1993 Land Acquisition Costs 26.70 ~ 25.76 26.70 26.59
TABLE 0.6: CAPITALIZED TRANSMISSION LINE LOSSES
T ransm iss I on A I ternat iva
1 2 3 4 5
Cae I ta.ll zed L lne Losses Unit Cost ~ $M ~ 1!1 ~ J!i Miles 1!i Miles $M
($M/mi>
Watana to Oev II Canyon {27 m I)
2 X 345 J(V 1 2 X 11 351 kcmil 0.2517 27 6.80 27 6. 80
2 X 345 kV 1 2 X 954 kcrni I 0.3565 27 9. 62 -27 9.62
2 X 500 k V 1 3 X 795 kcmll o. 1358 27 3.67
Devil Canyon to Anchorage {140 ml)
2 X 345 kV 1 2 X 1,351 kcmfl 0.4352 140 60.93 140 60.93
3 X 345 kV 1 2 X 954 kcmll 0.4262* 140 59.67 -140 59.67
2x500kV, 3 X 795 kcmll 0.2344 140 32.82
Devil Canyon to fairbanks {189 mi)
I X 230 kV I 1 x 1 1 272 kern II 0. 06497 293 19.04 378 24.56 378 24.56
X 230 kV I 1 x 11 351 kcrnil 0.06117 85 5.20
X 345 kV• 2 X 795 kcmll o. 02310 293 6. 77 293 6. 77 -
X 345 kV 1 2 X 954 kcrnll o. 01925 85 1.64 -
X 345 kVI 2 X 1 I 351 kern II 0.01359 85 _h.!§_
TOTAL 1993 Cap I tali zed Ll ne Losses 75.66 77.70 91.97 ~ ~
*Includes losses on two circuits from 1993 -1999 and three circuits from 2000 -2042 Inclusive.
APPENDIX E
HVDC TRANSMISSION
TABLE OF CONTENTS
E1 -GENERAL --------------'---------------------------------------E-1
E2 -ECONOMIC SCREENING -------------------------------------------E-2
E2.1 -Basic Schemes ----------------------------------------E-2
E2.2 -Comparative Costs --------------------------------------E-4
E2.3 -· Results -----------------------------------------------E-7
LIST OF TABLES
Number
E2.1
E2.2
E2.3
E2.4
E2.5
Title
Ac Transmission to Anchorage
Development of Capital Costs
HVDC Transmission to Anchorage
Development of Capital Costs
Ac Transmission to Fairbanks
Development of Capital Costs
HVDC Transmission to Fairbanks
Development of Capital Costs
Summary of Comparative Costs
Ac Versus De Transmission
LIST OF FIGURES
Number
E2.1
E2.2
Title
Comparison of HVDC Versus Ac
Transmission to Anchorage
Comparison of HVDC Versus Ac
Transmission to Fairbanks
APPENDIX E
HVDCTRANSMISSION
E1 -GENERAL
Traditionally, HVDC has found economic application for long-distance
overhead line (point-to-point) transmission or where significant
lengths of s.ubmarine cable were involved. In either case, the savings
resulting from the HVDC line or cable as compared to the cost of ac
lines or cables need to be sufficient to offset the additional cost of
de terminal facilities.
other characteristics of HVDC transmission that have been significant
in its application are
its asynchronous nature and hence the elimination of a transient or
dynamic stability problem
-its "controllability" may be an advantage to limit steady-state
circulating power flow in system interconnections, or to introduce
damping to limit or control system dynamic oscillations
-its ability to limit short-circuit contributions.
In the case of Susitna transmission, HVDC is not an obvious contender.
No technical difficulties are anticipated in an ac transmission scheme
and the transmission distances { 140 miles to Anchorage and 189 miles to
Fairbanks) are well within the normal economic limits of ac transmis-
sion. Also, the transmission involves three terminals leading to some
complication of the de control and adding to the cost of some of the
primary circuit elements as well. However, in the Anchorage area some
submarine cable circuits may be involved in delivering Susitna power
E - 1
to the load center. Hence, it is appropriate to carry out a screening
analysis to determine whether or not the de alternative merits further
study.
E2 -ECONOMIC SCREENING
E2. 1 -Basic Schemes
Since a number of variations are possible in the HVDC basic arrange-
ment, and also in combinations of ac and HVDC transmission, each
transmission link (from Susi tna to Anchorage and Susi tna to Fairbanks)
will be examined separately. In this base comparison, separate
point-to-point de schemes are implied.
In order to take into account possible savings associated with HVDC
cable circuits in the Anchorage area, the transmission costs to
Anchorage include submarine cable circuits as needed to bring the p:>wer
to the metropolitan load center.
All transmission from Susitna to Anchorage and Fairbanks is assumed to
start at a Devil Canyon switching station and terminate at an appro-
priate voltage in each load center. Ac transmission circuits and
switching facilities between Devil Canyon and Watana are assumed to be
common to both ac and de alternatives, and their costs are excluded
from the analysis.
Dynamic var generating equipment is needed at the load centers for both
ac and de alternatives. The necessary var capability for ac transmis-
sion was determined in load flow studies of critical line outage condi-
tions. In the case of the de alternative some vars will be generated
by the ac filters. The balance, as needed to meet the total var demand
of the load and the inverters themselves, is estimated and charged to
the de alternative. All of the required var generation is assumed to
E - 2
be located on transformer tertiary windings. Necessary switching is
included in the unit var cost.
The alternative HVDC transmission systems are planned to be capable of
handling full rated power under conditions of single contingency
outages. In the de terminals, this means that one valve group module
could be out of service and the remaining valve groups should be able
to handle the rated load. Similarly, on the transmission line, one
pole may be out of service and the remaining pole(s) should be capable
of handling the load without interruption.
For the transmission to Anchorage (rated 1,190 MW) a ~250-kV bipolar
scheme is envisaged, with four valve groups per terminal. Under normal
conditions one bipolar transmission line to Anchorage would be
adequate. However, the loss of one line pole would result in a
temporary power reduction, and full power could be resumed only after
terminal switching, and an earth return current would flow throughout
the total duration of the pole outage. For this reason, and to provide
a system more comparable to the ac alternative in case of a tower
failure, two bipolar transmission lines are provided for transmission
to Anchorage.
In the case of ac transmission to Anchorage, an intermediate switching
station and transformation to 138 kV is provided at Willow. This is an
integral part of the ac alternative. For the de alternative, an equi-
valent power supply to Willow is provided by adding two 230-kV ac
circuits from Point Mackenzie to Willow. The cost of these circuits
plus a 230-kV bus and transformation to 138 kV at Willow is included as
part of the cost of de transmission to Anchorage, so that both schemes
would be functionally equivalent.
The transmission to Fairbanks is rated 350 MW and at this load level it
is difficult to justify more than a single bipolar transmission line.
Loss of one pole would result in an earth return current and, if a
power interruption is to be avoided, the terminal equipment on each
E - 3
pole must be capable of handling the full 350 MW. This results in
100 percent reserve capacity, but it is still more economic than the
building of a second bipolar transmission line.
The ac and de comparative systems are shown in single line diagrams in
Figure E2. 1 for transmission to Anchorage and in Figure E2. 2 for trans-
mission to Fairbanks.
E2.2 -Comparative Costs
capital costs associated with the various ac and de transmission
alternatives are developed in a series of tables as follows.
Tables Transmission Alternative
E2.1 ac to Anchorage
E2.2 de to Anchorage
E2.3 ac to Fairbanks
E2.4 de to Fairbanks
The costs developed in these tables are all for the ultimate installa-
tion as the effect of staging is expected to be similar for both ac and
de alternatives.
In all ac transmission alternatives, the unit costs for station equip-
ment and transmission lines are those used in Section 3.7 of this
planning memorandum. The costs used for ac cable circuits are based on
quoted estimates for 230-kV cables. Where station buses are existing
or would be common to both ac and de alternatives, no base cost is
charged.
All HVDC terminal equipment is estimated at $44/kW per terminal, based
on manufacturers• recent estimates.
E - 4
The necessary ac switchyard circuit entries are estimated additional to
the ba.se HVDC te,rm.inal costs. Var generatipn over and above that
provided by the HVDC filter circuits is estimated, based on the var
demand of the converters and the load, and the cost is allowed for in
the receiving terminals. At the HVDC sending. end, no additional charge
is made to ensure that generating equipment can tolerate the var demand
and harmonic currents of the convert.ers. Some added costs would be
incurred, but these are expected to have only a secondary effect on the
cost comparison.
HVDC transmission line costs are estimated as follows for +250-kV
bipolar transmission lines.
Conductor Area
per Pole
{ kcmil)
2 X 1,780
2 X 1,272
Estimated Cost
per Mile
{ $)
250,000
200,000'
In the case of the HVDC cable circuits, these are estimated at 20 times
the cost of equivalent overhead line, or $5 million per mile. This is
consistent with the estimate used for ac cable circuits and it is
considered to be sufficiently close for this type of cost comparison.
Comparative costs for ac and de transmission alternatives are
summarized in Table E2. 5. Here the line and station capital costs
developed in Tables E2.1 to E2.4 are combined with cost of right-of-way
and capitalized annual operating costs to give capitalized total costs
that may then be compared. Included in the annual operating costs are
a number of miscellaneous charges which contribute to totals for
transmission and stations as follows.
E-5
Operating and maintenance
Insurance
Interim replacement
Contribution in lieu of
taxes
Total annual operating
Annual Operating Charges
(Percent of Capital Cost)
Transmission
1. 00
o. 10
0.15
2.00
3.25
Substation
2.00
0. 10
0.15
2.00
4.25
The annual operating charges shown in Table E2. 5 have been capitalized
at a 3 percent interest rate over the 50-yr life of the transmission
system. The same annual charge rates have been used for both ac and de
transmission on the assumption that differences in operating costs due
to differences in complexity will be adequately reflected in the
differences in capital investment for ac and de plant.
Capitalized costs of losses for ac transmission lines were developed as
part of the exercise to determine economic conductor sizes. Loss
energy was valued at 3.5 cent/kW•h, based on the results of the
generation planning exercise for the period under study. The capita-
lized total cost of loss for ac transmission was derived by adding
transformer losses at 0.5 percent per terminal to the line losses. In
the case of HVDC transmission, total terminal losses were calculated at
1.25 percent and added to line losses to derive the capitalized cost of
losses shown for the de alternatives.
Land acquisition costs are estimated for the line right-of-way only.
Land requirements at terminal locations are assumed to be similar for
both ac and de al terna ti V'es •
E -6
E2.3 -Results
Comparative costs of ac and de transmission alternatives as shown in
Table E2.5 confirm that ac is an appropriate choice for transmission
from Susitna to load centers at Anchorage and Fairbanks. The conclu-
sion is based on separate assessments of transmission costs to each of
the two load centers, and this implies the use of two 2-terminal de
transmission systems. Some de economies might be 'achieved with an
alternate 3-terminal de arrangement, but any savings are unlikely to
overcome the indicated 15 percent margin favoring ac transmission.
The economic conclusions are consistent with the results of other
studies for the load levels and transmission distances involved, and
they are considered adequate to support the selection of ac
transmission over HVDC for the Susitna project.
E - 7
TABLE E2.1: AC TRANSMISSION TO ANCHORAGE DEVELOPMENT OF CAPITAL COSTS
Cost Components
Unit Station Cost.
Location Details Quantity Cost Component Total Line Costs Total Costs
($M) ($M) ( $M) ( $M) ($M)
pevil canyon breakers 345 kV 5 1.00 5.00 5,00
Overhead Transmission 3 cct, 345 kV, 2x954 kcmil
conductor -140 mi route 420 0.279 117.18
Willow Terminal base 345 kV 1 2.00 2.00
breakers 345 kV 14 1. 00 14.00
breakers 138 kV 5 0.40 2,00
transformers 75 MVA 3 0,50 1. 50 19.50
West Terminal base 345 kV 1 2.00 2.00
breakers 345 kV 14 1. 00 14.00
breakers 230 kV 15 0.70 10.50
transformers 250 MVA 6 1. 30 7.80
VAR generation 400 MVAR 0.03 12.00 46.30
Cables 4 cct, 230 kV, 3.7 mi 4 20,25 81.00
Anchorage Terminal breakers 230 kV 6 0.70 4,20 4,20
Terminal Subtotal 75.00
Indirect Costs (at 32.5 percent) 24.38
Total Costs 99.38 198,18 297,56 ----·----
TABLE E2.2: HVDC TRANSMISSION TO ANCHORAGE DEVELOPMENT OF CAPITAL COSTS
Cost Components
unit Station Costs
Location Details Quantit:t Cost Component Total Line Costs Total Costs
($M) ($M) ($M) ($M) ($M)
Devil Canyon breakers 230 kV 6 0.70 4, 20
HVDC 1,586.7 MW 0.044 69.81 74.01
HVDC Transmission
Overhead 2 bipolar circuits ±250 kV
2xl,780 kcmil conductor
140 mi route 280 0.250 70,00
Cable 2 bipolar circuits
3.7 mi route 2 18,50 37,00
Anchorage HVDC 1,586.7 MW 0.044 69.81
breakers 230 kV 6 0.7 4.20
VAR generation 670 MVAR 0.03 21,10 94.11
AC Supply to
Willow
Point Mckenzie breakers 230 kV 3 0.70 2,10
Transmission 230 kV, 2 circuits
1,272 kcmil conductor
50 mi route 100 0.184 18.40
Willow base 230 kV 1 l. 50 l. 50
breakers 230 kV 8 0.70 5. 60
breakers 138 kV 5 0,40 2.00
transformers 75 MVA 3 0.50 l. 50 12.70
Terminal Subtotal 180.82
Indirect Costs (at 32.5 percent) 58.77
Total Costs 239,50 125,40 364,99
TABLE E2.3: AC TRANSMISSION TO FAIRBANKS DEVELOPMENT OF CAPITAL COSTS
Cost Components
Unit Station Costs
.Location Details Quantity cost Component Total Line Costs Total Costs
($M) ($M) ( $M) ( $M) ($M)
Devil Canyon breakers 345 kV 3 1. 00 3,00 3,00
Overhead 2 cct, 345 kV, 2x795 kcmil
Transmission conductor, 189 mi route 378 0,256 96.77
Fairbanks Terminal base 345 kV 1 2.00 2. 00
breakers 345 kV 11 1,00 11.00
breakers 138 kV 6 0.40 2,40
transformers 250 MVA 4 0,90 3.60
reactors 75 MVAR 2 0,83 1.66
VAR generation 100 MVAR 0.03 3,00 23,66
Terminal Subtotal 26.66
Indirect Costs (at 32.5 percent) 8.66
Total Costs 35,32 96,77 132.09
TABLE E2.4: HVDC TMNSMISSION TO FAIRBANKS DEVELOPMENT OF CAPITAL COSTS
Location
Devil Canyon
HVDC Transmission
Fairbanks Terminal
Terminal Subtotal
Details
breakers
HVDC
230 kV
700 MW
1 bipolar circuit
±250 kV, 2xl,272 kcmil
conductor
HVDC 700 MW
breakers 138 kV
VAR generation 245 MVAR
Indirect Costs (at 32.5 percent)
Total Costs
Cost Components
unit
Quantity Cost
6
189
6
($M)
0,700
0,044
0,200
0.044
0.400
0.030
Station Costs
Component Total
($M) ($M)
4,20
30,80
30.80
2.40
7.35
35.00
40.55
75.55
24,55
100.10
Line Costs
($M)
37.80
37,80
Total Costs
($M)
137.90
TABLE E2.5: SUMMARY OF COMPARATIVE COSTS AC VERSUS DC TRANSMISSION
comparative Costs -$ Million
Transmission to Anchorage Transmission to Fairbanks
Cost Components AC DC AC DC
Line Costs 1 line capital l 198.18 125.40 96.77 37.80
line capitalized O&M 3 165.72 104.86 80.92 31.61
·land acquisition (R.O.W.) 13.44 8.40 14.18 7,56
Station Costs 1 35.32 100.10 station capital 2 99.38 239.59
station capitalized O&M 108.67 262.00 38.62 109,46
Capitalized Cost of Losses 4 83.87 74.94 13.72 16,63
Total costs 669.26 815.19 279,53 303,16
1 Line and station capital costs are developed in Tables E2.l to E2.4. 2capitalized O&M charges include O&M, insurance, interim replacement and contributions in lieu of taxes, These
annual charges total 3.25 percent of transmission capital and 4.25 percent of station capital, and they are
capitalized over 50 years at 3 percent. 3Land acquisition (R.O.W.) costs are estimated at $96,000/mile and $75,000/mile for 345 kV, 3 cct and 2 cct trans-
mission respectively, and $60,000/mile and $40,000/mile for ±250 kV de 2-circuit and single circuit,
4 respectively.
Losses are valued at 3.5¢/kW·h, and they are capitalized over the 50-year line life at 3 percent.
230 KV 230 KV 6 X 250 MVA 345 KV 345 KV
H-1-,--,1,.,
1
-ul l
ANCHORAGE
KNIK
ARM
345 KV AC ALTERNATIVE
4X397
230
ANCHORAGE
±250 KV HVDC ALTERNATIVE
/--{>--
{3¢-2X954 KCMIL
..--D-.-£:1*--D-__. 3 CIRCUITS )
230 KV
POINT MACKENZIE
230 KV
(BIPOLAR 2 X 17o80 KCMIL
2-CIRCUI.:S
/-!> ~--<1-------
-;-!>~ ~ -<}----------------
I-f>----<3-----------------
KNIK
ARM
WILLOW
WILLOW
COMPARISON OF HVDC VERSUS AC TRANSMISSION TO ANCHORAGE
345 KV
DEVIL CANYON
138 I("V•
4X 397 MW
DEVIL CANYON
345 KV
DEVIL CANYON
345 KV AC ALTERNATIVE
230 KV
DEVIL CANYON
± 250 KV HVDC ALTERNATIVE
( 3¢-2 X 795 KCMIL
2-CIRCUITS )
1----
"MVM (
( Bl POLAR 2 X 12 72 KCMIL
ONE CIRCUIT )
/----
FAIRBANKS
-I
-1
FAIRBANKS
COMPARISON OF HVDC VERSUS AC TRANSMISSION TO FAIRBANKS
ANCHORAGE TI
1.00 1~0.7
600, .... '----
200, ...... ~-t-
+-----85
200 MVAR
1.02 l-0.7
ANCH()RAGE I
50/100 MW
1.01 I 0.0
600..,.__ __
200 .... -c:__-t-
1.02 10.0
1.00 14.7 --... 1~~-..a....":"'!"'"""'--(.
5:3 150
I 5o....---
130-oC
0.9813.6
1.01 (10. 4
0.98l.iJ_
WIL IN
1025 ..,.__ __
10 , ...... !----+-
30 !Of
+ 1.03l..ill:.Q_ t
31
t
1.04122.0 37
1.03 130.7
t
78
796
1
800
1
356
t
600 MW
WATANA
PEAK DEMAND FLOW-ALTERNATIVE 2
25% LOAD AT FAIRBANKS
LEGEND
(9 CENERATION
I OAlJ
STATIC VAR SOURCE
~ 8US NUMBER
REAL POWER FLOW ( MW )
-+ REACTIVE POWER FLOW (MVAR)
I 03
SERifS COMPENSATION
TRANSFORMER
WITH TERTIARr
SHUNT REACTOR
BUS VOLTAGE MAGNITUDE (PER UNIT)
BUS VOLTAGE PHASE ANGLE (DEGREES:
TRANSMISSION LINES
...... _ __,.., 345 KV
15B KV OR LOWER
~~~----·1
FIGURE 3.6 J~I(IJ
I .00 &J.-.-.-~--:--r-"--""""""'
t ~ ANCHORAGE II
1.00 1-0.9
225....-+
3x250 }-....-+----+------< MVA ~145
200 MVAR
1.03 l-0:9
150..,._ __
134 .... CE---+
0. 9 8 U:.:..!...
ANCHORAGE I
1.01 IO.O
225~
3x250
~~~~------~ MVA
200 MVAR
1.03 !QQ. 0.98 14.6
59 150
1.00 l..!bQ_
w
76 1204
1.03l.£f_J_
T
123 1 1
t
30
796
I
1.04l.£.2J_
t
36 T
192
1
190 u
10ol81
Jl
4xl50
MVA
I.OiliL!.
600MW
WATANA
PEAK DEMAND FLOW-ALTERNATIVE 2
85% LOAD AT ANCHORAGE
FAIRBANKS
1.02 /14.8
50/100 MW
--240
17<11
100 MVAR
LEGEND
E3J STATIC VAR SOURCE
@ bUS NUMBE"'
....;--.-+ Rb~CTIVF POWER FLOW (MVAR)
SERIES CCJMPENSATION
TRANSFORMER
WITH TERTIARi
SHU~H REACTOR
I 03 . !:JUS VOL.TAGE MAGNITUDE (PER UNIT)
~ f3US VOLTAGE f)hASE ANGLE (lJEGREES)
TRANSMISSION LINES
345 KV
13B KV OR L.OW ER
FIGURE 3.5
r--···· -···-~ JJI~j
I.OIU1£. BELUGA
ANCHORAGE II
36 150
1.00 j-0.3
150........-
600.-4----
200 ... 114 ...
200 MVAR'
1.02 !-0.3 WILLOW
1.00!4.2
ANCHORAGE I 1024....,._ __ _
1.02 I 0.0
72 ...... f----t-
50/100 MW
521~
46 6004111411---
1.01 J9.6 25 1041 t t I 84
1.04!15.8 t 797
1 33
2QOI ...... f----l-
0.99!4.0
>-J-:-::~+-----< 3 x250 +Jo.-57 MVA
200MVAR
1.03!0.0
t
42 1.04W!.&_ _ __.......,~_ ...... _"'
800
I
1.03127.3
--•350 1(
--1----........ 173
1( 0.99!6.4
DEVIL CANYON
600MW
WATANA
PEAK DEMAND FLOW-ALTERNATIVE I
25% LOAD AT FAIRBANKS
~FAIRBANKS
I LU_
50/100 MW
100 MVAR
LEGEND
8 GENERATION
•---i LOAD
E0 STATIC VAR SOURCE
@) BUS NUMBER
REAL POWER FLOW ( MW )
... REACTIVE POWER FLOW (MVAR)
-H-SERIES COMPENSATION
1 TRANSFORMER
WITH TERTIARY
( SHUNT REACTOR
1.03 BUS VOLTAGE MAGNITUDE (PER UNIT)
BUS VOLTAGE PHASE ANGLE (DEGREES)
TRANSMISSION LINES
---345 KV
1313 KV OR LOWER
FIGURE 3.4 ~i
ANCHORAGE ll
0.99l.PJL ---~..-~-.. ...... ---{ r ~
61 150
1.00 J-0.1
680.,._._ 150...,._ __
225-+ 136 ...
200 MVAR
103 i.::Q.J.
ANCHORAGE I r l
1.01 10.0 41 45
50/100 MW
225,.. I I.OOUl:.l.
200 MVAR 0.9814.6
BELUGA
WILLOW
1183>...,._ __
190 r{
103 ....... 1---+-
Jool78
4xl50
MVA
1( 1.011!3.5
DEVIL CANYON '! 'T .t 't'
1.03L!!L§_ -a.....::.....-..;...-+t-:---~t---.......................... "'"T--""'1 , T
t 800
24 t 10 3 Lfl.1_ _ __.u..;..;~....;...a--'"'
600MW
WATANA
PEAK DEMAND FLOW-ALTERNATIVE l
85% LOAD AT ANCHORAGE
LEGEND
8 GENERATION
.... ---i LOAD
Q STATIC VAR SOURCE
@ BUS NUMBER
REAL POWER FLOW ( MW)
FAIRBANKS
"" REACTIVE POWER FLOW (MVAR)
1.02 Wd..
50/IOOMW -11-SERIES COMPENSATION
-240
-r------.... 80 1 TRANSFORMER
WITH TERTIARY
17,.._---t-
100 MVAR ( SHUNT REACTOR
1.02 I..!J.d..
1.03 BUS VOLTAGE MAGNITUDE (PER UNIT)
~ BUS VOLTAGE PHASE ANGLE (DEGREES)
TRANSMISSION LINES
.....,...,.......,. 345 KV
1313 KV OR LOWER
FIGURE 3.3 •
BE:LUGA
ANCHORAGE II
50 MILES
200MVAR
15 MILES
ANCHORAGE I
90 MILES
50/100 MW
200 MVAR 3 3x75 3 MVA
27 MILES
189 MILES
600MW
WATANA
75/
MVARS
75 I
MVAR s
DEVIL CANYON
4xl50
MVA
TRANSMISSION SYSTEM CONFIGURATION
ALTERNATIVE 2
FAIRBANKS
50/100 MW
100 MVAR
LEGEND
8 (;[NERATiON
LOAD
STATiC VAR SOURCE
BUS NUMBER
-~ REAL POWER FLOW ( MW)
-+ REACTIVE POWER FLOW (MVAR)
103
SERIES COMPENSATiON
TRANSFORMER
WITH TERTIAR)
SHUNT REACTOR
BUS VOLTAGE MAGNITUDE (PER UNIT)
~ BUS VOL.TAGE. PHASE ANGL.E (DEGREES)
TRANSMISSION LINES
..,..._......, 345 KV
I 3'8 KV OR LOWER
NOTE' EQUIPMENT RATINGS INDICATED ARE FOR
ULTIMATE INSTALLATION (YEAR 2000)
FIGURE 3.2
BELUGA
ANCHORAGE II
50 MILES
200 MVAR
15 MILES
ANCHORAGE I
90 MILES
1-
200 MVAR 3X250MVA . 3 3X75 3 MVA
27 MILES
189 MILES
75{
MVAR
4xl50
( MVA
75
MVAR
600MW
WATANA
TRANSMISSION SYSTEM CONFIGURATION
ALTERNATIVE I
FAIRBANKS
100 MVAR
LEGEND
E1 GENERATION
<~ LOAD
Q STATIC VAR SOURCE
@) BUS NUMBER
REAL POWER FLOW ( MW)
"" REACTIVE POWER FLOW (MVAR)
-ir-SERIES COMPENSATION
1t TRANSFORMER
WITH TERTIARY
( SHUNT REACTOR
~
1.03 BUS VOLTAGE MAGNITUDE (PER UNIT)
~ BUS VOLTAGE PHASE ANGLE (DEGREES)
TRANSMISSION LINES
---345 KV
13B KV OR LOWER
NOTE: EQUJP.MENT RATINGS INDICATED ARE FOR
ULTIMATE INSTALLATION (YEAR 2000)
FIGURE 3.1 •