HNF-50594 - Rev 01 Libr… · For quick approximations, Table 4 of ANSI C57.91-1995(R2004) provides...
Transcript of HNF-50594 - Rev 01 Libr… · For quick approximations, Table 4 of ANSI C57.91-1995(R2004) provides...
Approved for Public Release;
Further Dissemination Unlimited
Approved for Public Release;
Further Dissemination Unlimited
By Janis D. Aardal at 1:49 pm, Jul 08, 2015
Jul 08, 2015
DATE:
50
ECR-15-000865
HNF-50594, Rev 1 Page i of iv
251W (Substation A8) Loading Capacity Study
HNF-50594, Rev 1 Page ii of iv
Rev. 1
Description of Change:
1. Updated SCADA information since 2011.
2. Updated incoming cable and LTC ratings and Appendix D Calculations.
HNF-50594, Rev 1 Page iii of iv
TABLE OF CONTENTS
1.0 PURPOSE .............................................................................................................................1
2.0 SCOPE ..................................................................................................................................1
3.0 ASSUMPTIONS ...................................................................................................................1
4.0 EXISTING SUBSTATION CAPACITY .............................................................................1
5.0 EXISTING LOADS ............................................................................................................15
6.0 FORECAST LOADS ..........................................................................................................23
7.0 DISCUSSION .....................................................................................................................30
8.0 CONCLUSIONS ................................................................................................................38
9.0 RECOMMENDATIONS ....................................................................................................40
10.0 REFERENCES ...................................................................................................................41
11.0 Reinhausen LTC Service Contact .......................................................................................42
LIST OF TABLES
Table 1 – Transformer Factory Test Data ..................................................................................................................... 2
Table 2 – Duct bank Ampacity Comparison ................................................................................................................ 11
Table 3 – Equipment Ratings ............................................................................................................................................ 14
Table 4 - Existing A8 Substation Loads ........................................................................................................................ 19
Table 5 - Forecast Additional Loads .............................................................................................................................. 25
Table 6 - Forecast Loads to be Removed ..................................................................................................................... 26
Table 7 – Existing Load Summary & Capacity Limits ............................................................................................. 30
Table 8 - Forecast Loads and Substation Capacity Summary ............................................................................. 31
Table 9 - Transformer Capability .................................................................................................................................... 33
Table 10 - Suggested SCADA Alarms ............................................................................................................................. 37
LIST OF FIGURES
Figure 1 – IEEE C57.91 Transformer Loss of Life ...................................................................................................... 3
Figure 2 - Normal Life and Aging Vs Hot Spot Temperature ................................................................................. 4
Figure 3 – 30 Year Daily Average Temperatures ....................................................................................................... 5
Figure 4 - Average Daily Ambient Vs Transformer Rating ..................................................................................... 6
Figure 5 - Daily Average Temperature & Approximate Rating Adjustment ................................................... 7
Figure 6 - Calculated Transformer Temperatures ..................................................................................................... 8
Figure 7 - Calculated Transient Transformer Temperatures ................................................................................ 9
HNF-50594, Rev 1 Page iv of iv
Figure 8 - Monthly Average Soil Temperature .......................................................................................................... 11
Figure 9 - Transformer Temperature Setpoints ....................................................................................................... 13
Figure 10 - Power Factor, 100 & 200 Areas ............................................................................................................... 15
Figure 11 - 100 Area Monthly Demand ........................................................................................................................ 16
Figure 12 - 200 Area Monthly Demand ........................................................................................................................ 17
Figure 13 - Winter & Summer Average Weekly Load Profile .............................................................................. 18
Figure 14 - Winter & Summer Weekday Average Load Profile & Approx. Step Load Representations
....................................................................................................................................................................................................... 18
Figure 15 - 100 Area Hourly Demand ........................................................................................................................... 19
Figure 16 - 200 Area Hourly Demand ........................................................................................................................... 20
Figure 17 - 200 Area Hourly Demand + C8L14 Load .............................................................................................. 20
Figure 18 - Bank 1 Load & Oil Temp, July .................................................................................................................... 21
Figure 19 - Bank 2 Load & Oil Temp, July .................................................................................................................... 22
Figure 20 - Bank 1 & 2 Composite Load & Oil Temp, July ..................................................................................... 22
Figure 21 - Bank 1 & 2 Composite Load & Oil Temp, November ....................................................................... 23
Figure 22 - Forecast Additional Summer Loads ....................................................................................................... 26
Figure 23 - Forecast Additional Winter Loads .......................................................................................................... 27
Figure 24 - Forecast Additional A8 Load ..................................................................................................................... 28
Figure 25 - Forecast Summer A8 Load ......................................................................................................................... 29
Figure 26 - Forecast Winter A8 Load ............................................................................................................................ 29
Figure 27 - Weekday Transformer Temperature Variation ................................................................................ 32
Figure 28 - Winter Forecast Loads and Transformer Capability ....................................................................... 34
Figure 29 - Summer Forecast Loads and Transformer Capability .................................................................... 35
LIST OF APPENDICES
Appendix A – Equipment Data
Appendix B – Hanford Meteorological Station (HMS) Climatological Data
Appendix C – Electrical Utilities Electrical Meter Data
Appendix D – Duct Bank Data & Ampacities
Appendix E – Transformer Temperature Calculations
Appendix F – Forecast Load Data
HNF-50594, Rev 1 Page 1 of 42
1.0 PURPOSE
1.1 Evaluate capacity of A8 Substation to adequately supply existing loads, determine
capability to supply future additional loads, and identify impacts or required
modifications due to these additional loads.
2.0 SCOPE
2.1 The scope of this study includes the 230kV and 13.8kV equipment between the main 230kV
substation bus and the downstream 13.8kV switchgear load feeders.
2.2 Three general load scenarios will be evaluated.
2.2.1 Capability of existing substation systems and equipment to serve present loads,
including limited modifications or adjustments if required.
2.2.2 Capability of existing substation to serve additional documented or assumed loads,
primarily due to forecasted Tank Farm upgrades.
2.2.3 Determination of maximum or optimum capacity of substation considering existing
systems and equipment and identify recommended modifications or upgrades.
2.3 Additionally, set points of protective and alarming devices will be evaluated for
optimization and appropriate alarm responses will be provided.
3.0 ASSUMPTIONS
3.1 Substation Capacity
Backup redundancy - Although while in normal operation the substation loads are shared
between the two 230kV transformers, the design redundancy of the double-ended
substation configuration requires that each of the two 230kV transformers, and their
associated equipment and cables, must be capable of serving the entire substation load,
with the other out of service.
3.2 Loads
3.2.1 “Existing Loads” are assumed to be same as recent historical loads.
3.2.2 For purposes of calculating load currents from power values, the 251W switchgear
bus and transformer secondary voltage is assumed to be 14.4kV as maintained by
the automatic load tap changer (LTC).
4.0 EXISTING SUBSTATION CAPACITY
The capability of the existing substation to serve the loads on the 13.8kV distribution
system depends upon the ratings and settings of the upstream systems and equipment. The
HNF-50594, Rev 1 Page 2 of 42
lowest rating or setting will determine maximum load allowed. The substation settings and
equipment is discussed below.
4.1 Power Transformer Ratings
4.1.1 Each of the two 230,000V-13,800Y/7970V transformers at A8 are nominally rated
20/26/33 MVA, ONAN/ONAF/ONAF, 65 deg C. Load sensing transformer
protection presently in use includes backup overcurrent protection provided by the
bus differential and transformer differential relays, high winding temperature trip
from a temperature relay on the transformer, and high winding and oil temperature
alarms. Analog winding and oil temperature is also gathered by the SCADA system.
Only oil temperature data is archived.
4.1.2 Transformer Load Tap Changer (LTC) - The transformer secondary load tap changer
is a Reinhausen RMV-II-1500-15. Full load current rating is 1500A (37.4MVA @
14.4kV). IEEE C57.131 (2012) compliant tested reactance-type LTC design allows
for an overload current of 120% (1800A) of the nominal current rating. A field
modification kit is available to increase the nominal rating to 2000A (49.9MVA) is
available.
4.1.3 Transformer Primary Bushing Ratings – 230kV, 900kV BIL, 800A (draw lead).
4.1.4 Transformer Secondary Bushing Ratings – 15kV, 110kV BIL, PRC, 2000A at 95 deg C
oil temperature.
4.1.5 Transformer Temperature Rise Factory Test Data (Summary), see
4.1.6 Table 1.
Table 1 – Transformer Factory Test Data
Ambient during test = 21 C 20MVA
Self-Cooled
33MVA
2 Stages of Fans
No Load Losses 19.9kW 19.9kW
Load Losses 69.9kW 196.1kW
Total Losses 89.8kW 216kW
Top Oil Temperature Rise above Ambient 46 51 C
Winding by Resistance Temp Rise above Ambient H=45 C
X=47 C
H=51 C
X=56 C
Calculated Hot Spot Rise above Oil Temp 21 C 21 C
Calculated Hop Spot Rise above Ambient 67 C 72 C
4.2 Transformer Capacity
Nominal transformer MVA ratings are not an absolute upper operating limit, but give an
indication of the continuous loading under rated conditions that will produce “normal” life
expectancy. Deviation from continuous loading at rated conditions will increase or
decrease this estimated life, with under loaded operation increasing life less than
overloaded operation decreases life. Transformer (insulation) life expectancy is primarily
HNF-50594, Rev 1 Page 3 of 42
governed by time and temperature with the hottest spot taken as a reference. One goal then
is to monitor or predict the hot spot temperature of a transformer to determine the effect of
transformer’s load on its life expectancy.
Industry standard IEEE C57.91-1995(R2004)[Ref. 10.1] provides guidelines for transformer
loading (“Guide for Loading” or “guide”), and presents methods to calculate or approximate
transformer heating and percent loss of life based upon hot spot temperature profiles,
which are ultimately dependent upon complicated relationships between transformer
loading, cooling methods, and ambient temperature.
Transformer load capacity thus is a tradeoff between load and acceptable loss of life, with
the calculated loss of life (if any) heavily influenced by ambient temperature and duration of
load. Actual in-service transformer capacity may differ significantly from the nominal
nameplate values.
The IEEE guide for loading provides relatively simple equations to estimate loss of life.
Normal loss of life is assumed to be 0.0133 % for a continuous 110 deg C hot spot
temperature (based on a 20.55 year life). Loss of life rates increase with increasing hot spot
temperatures and duration. See Figure 1 below. The loss of life equations, however, are
based upon transformer hot spot temperature, which is not directly measured and is
difficult to predict due to varying transformer characteristics and conditions of use.
Figure 1 – IEEE C57.91 Transformer Loss of Life
Using the same loss of life equations, Figure 2 shows the relationships of the aging
acceleration factor (FAA) and transformer per unit normal life expectancy (PU Life) vs. hot
0.01
0.10
1.00
10.00
100 110 120 130 140 150 160 170 180 190 200
Ho
urs
Hot Spot Temperature, Deg C
Hours at Hot Spot Temp and % Loss of Life
0.4%
0.3%
0.2%
0.1%
0.05%
0.02%
0.0133%
HNF-50594, Rev 1 Page 4 of 42
spot temperature. The aging acceleration factor provides the relative aging rate for a given
temperature. The tradeoff between life and temperature is clearly indicated.
Figure 2 - Normal Life and Aging Vs Hot Spot Temperature
4.3 Ambient Temperature & Transformer Capacity
Transformer capacity (for a given assumed loss of life) is greatly influenced by ambient
temperature. Low ambient temperature in winter significantly increases transformer
capacity by helping to lower oil and hot spot temperatures for a given load. Conversely,
summer high ambient temperatures reduce the load capacity.
4.3.1 Historical Ambient Temperature
Hanford climatological data including 30 year annual daily average temperatures, hourly
temperatures for July and August 2010, and annual subsurface temperatures, have been
obtained from the Hanford Meteorological Station (HMS). This temperature data was used
to help validate earth ambient temperature for underground duct bank derating as well as
to help establish approximate transformer rating adjustments and evaluation of
transformer load and temperature correlation.
The (30 year) annual daily average temperature at the HMS is shown in Figure 3 below.
Superimposed with the daily average temperature is a curve including an additional 5 deg C
for conservatism.
0.0001
0.001
0.01
0.1
1
10
100
1000
10000
0 50 100 150 200
Hot Spot Temperature, Deg C
Transformer Aging Acceleration Factor and Per Unit Life
PU Life
FAA
HNF-50594, Rev 1 Page 5 of 42
Figure 3 – 30 Year Daily Average Temperatures
4.3.2 Quick Approximate Ambient Temperature Corrections to Transformer Ratings
For quick approximations, Table 4 of ANSI C57.91-1995(R2004) provides adjustments of
transformer rated MVA for operation in average daily ambient temperatures different from
the nominal 30 deg C rating temperature. For ONAN/ONAF/ONAF transformers such as
those at substation A8, the derating is 1.0% per degree C above 30, and a 0.75% increase in
rating for each degree C below 30 deg C average daily ambient. This rating adjustment is
plotted in Figure 4. An additional 5 deg C margin is suggested for conservatism when using
average temperatures. This method will produce conservative equivalent normal loading.
-5
0
5
10
15
20
25
30
35
1-Jun 23-Jul 13-Sep 4-Nov 26-Dec 16-Feb 9-Apr 31-May
Deg C 30 Year Daily Average Hanford Temperature
Daily Avg Deg C+5
Daily Avg Deg C
HNF-50594, Rev 1 Page 6 of 42
Figure 4 - Average Daily Ambient Vs Transformer Rating
As an example, per PNNL-15160, Hanford Site Climatological Summary 2004 with Historical
Data [Ref. 10.6.4] , the Hanford average monthly temperature for January is minus 0.5 deg C.
Under this condition, Table 4 suggests the A8 substation transformer rating may be
increased by (30 – (-0.5 + 5) x 0.75% = 19.1%, for a result of 39.3 MVA. During the low
temperature period on November 24, 2010, the average daily temperature was minus 16.7
deg C, with Table 4 suggesting an increase of 31%, for an effective transformer rating of
43.2 MVA. Combining this rating adjustment with the historical annual daily average
temperatures produces an annual daily ambient-temperature-corrected rating for the
transformer, shown as the third plot in
Figure 5.
0%
20%
40%
60%
80%
100%
120%
140%
160%
180%
0.0
10.0
20.0
30.0
40.0
50.0
60.0
-40 -30 -20 -10 0 10 20 30 40 50 60
MV
A
Average Daily Ambient Temp (deg C)
Approx 33MVA Transformer Rating at Other Than 30 deg C
Ambient
(From IEEE C57.91 Table 4)
HNF-50594, Rev 1 Page 7 of 42
Figure 5 - Daily Average Temperature & Approximate Rating Adjustment
The rating adjustment curve indicates that for the low daily average temperatures of
Hanford winter (5 deg C), the effective transformer rating may be increased up to nearly
120%. Conversely, in the heat of summer (32 deg C), effective transformer ratings may be
less than 100%, say 98%.
4.4 Transformer Temperature Model
IEEE Std C57.91 provides methods and models to calculate transformer temperatures for
various load, cooling, and ambient temperature scenarios. Calculations using these
methods are presented in Appendix E and summarized below. Inputs to the transformer
model include manufacturer’s factory heat test data and physical characteristics of the
transformer, and empirical data from the guide based on the cooling method. Transient and
steady state temperatures may be calculated.
Using the IEEE Std C57.91 Clause 7 equations, as a first approximation, steady state
transformer temperatures are calculated and plotted for a range of loads for an assumed
daily average summer high temperature of 30 deg C and a daily average low winter
temperature of 5 deg C. See Figure 6.
97.36%
120.38%
90%
95%
100%
105%
110%
115%
120%
125%
130%
-5
0
5
10
15
20
25
30
35
1-Jun 23-Jul 13-Sep 4-Nov 26-Dec 16-Feb 9-Apr 31-May
RatingDeg C Daily Average Temp + 5 deg C & "Quick Approximate"
Transformer Rating Adjustment
Daily Avg Deg C Daily Avg Deg C+5 C57.91 Table 4 (Rating %)
HNF-50594, Rev 1 Page 8 of 42
Figure 6 - Calculated Transformer Temperatures
The model’s equations show the hotspot temperature reaches the normal loss of life
temperature of 110 deg C at a steady state load of approximately 106% (35MVA) in the
summer and 125% (41.2MVA) in winter. In practical application, the loads and ambient
temperature are not steady state, and some loss of life may be acceptable for short term
operating conditions that exceed the 110 deg C hot spot temperature.
The transient temperature calculations indicate the A8 substation transformers have a top
oil thermal time constant of approximately four hours. Calculated temperature rise in
response to 33MVA step load change is shown in Figure 7 below.
0.0
20.0
40.0
60.0
80.0
100.0
120.0
140.0
160.0
180.0
200.0
0 5 10 15 20 25 30 35 40 45 50
Deg C
Load, MVA
A8 Transformer Calculated Steady State Temperatures
IEEE C57.91-1995(R2004) Model
Hot Spot Temp Summer (30 Deg C)
Top Oil Temp Summer (30 deg C)
Hot Spot Temp Winter (5 Deg C)
Top Oil Temp Winter (5 deg C)
Normal Loss of Life Temp
HNF-50594, Rev 1 Page 9 of 42
Figure 7 - Calculated Transient Transformer Temperatures
This time constant can be utilized to ride through short periods of moderate overload if the
load decreases before the transformer reaches overload temperatures.
4.4.1 Transformer Overload Capacity
If overload is defined as simply operation above nameplate ratings, such an overload may
not produce detrimental hot spot temperature (110 Deg C), and no additional loss of life
may occur. Overload conditions that produce elevated hot spot temperature may include
nameplate load at high ambient temperature, heavy load for an extended period, or a very
high load for short duration.
Estimation of the overload capacity of a transformer (below ultimate maximum limits)
involves predicting hot spot temperature, time at temperature, and determination of
acceptable loss of life. Advantage can be taken of thermal capacity and thermal time
constants of the transformer to allow overload operation while remaining within acceptable
limits.
Factors affecting the overload capability include many variables. The ambient temperature
affects the total heat capacity of the transformer. The initial load determines initial
transformer temperature, and thus the amount of temperature rise (with associated time
constant) available to the overload condition. The magnitude of the overload determines
the heat input and rate of temperature rise. The duration of the overload coupled with the
rate of rise determines the peak temperature. Added to these factors is the loss of life that is
acceptable to the user (determined by hot spot time and temperature as discussed above).
0
20
40
60
80
100
120
0 5 10 15 20
Hours
Rated Full Load Step Response
(30 Deg C Ambient)
Hot Spot Temp Deg C
Top Oil Temp Deg C
Load MVA
HNF-50594, Rev 1 Page 10 of 42
While the overload capability of these transformers may be used to ride through abnormal
or emergency overload conditions, other associated equipment and systems must be rated
or set accordingly.
4.5 Transformer Primary Conductors and Primary Switch
Transformer primary conductors are overhead strain bus cables tapped to the main 230kV
substation bus through overhead air break switches. Switches are rated at 1200A, and the
636 ACSR Grosbeak cable is rated over 700A. These ratings are an order of magnitude
above the nominal rating of the transformer (50-60A primary), and are not a practical
limitation of the substation rating.
4.6 Transformer Secondary Conductors
The present transformer secondary conductors are paralleled 15kV shielded cables in a
concrete encased underground duct bank. These cables were replaced during the
installation of the present transformers.
Present installation consists of 9-1/c 750kcmil, 15kV shielded conductors, three per phase,
and each individual conductor is in its own separate 4 inch Type EB duct in a 3 x 3 concrete
encased duct bank arrangement. The ampacity calculations for these conductors is subject
to engineering judgment and assumptions including variable burial depth, non-uniform
(unformed) concrete encasement thickness, soil temperature and thermal resistivities.
Additionally, published duct bank ampacity data from AIEE-IPCEA and cable manufacturers
assume conductors are installed at the periphery of the duct bank, not in the central
position subject to mutual heating from surrounding cables, as is the case for the A8
substation.
For a more accurate, and conservative determination of the installed ampacity of the
secondary cables, the software package AmpCalc for Windows, Version 4.0, Revision 31,
from CalcWare of Katy, Texas was employed to determine ampacities of each of the
individual cables. AmpCalc determines cable ampacities by rigorous application of the
Neher-McGrath ampacity calculation procedures based upon user input of cable, duct,
encasement, and ambient earth data.
While this software program has not been officially verified, test cases run using cable and
duct bank data given in AIEE S-135-1 / IPCEA P-46-426 yield results similar to those
standards’ published ampacities (See Appendix D).
Soil temperature data from the Hanford Meteorological Station has been recorded for
depths of 0.5, 15, and 36 inches, and is shown in Figure 8. Annual temperature at 36 inch
depth ranges from 5.6 deg C in January to 25.8 deg C in August.
HNF-50594, Rev 1 Page 11 of 42
Figure 8 - Monthly Average Soil Temperature
Comparison of duct bank ampacity values and their source is given in Table 2.
Conductor Configuration Data Source Published
Ampacity
AmpCalc
Ampacity
750kcmil, single conductor
cable, open circuit shield,
outside ducts only, 20 deg C
earth ambient, RHO 90, 100%
Load Factor, 30 in depth, 7-1/2
in centers. Three circuits, nine
cables in separate ducts, 5001-
35000V, 90 deg C.(circular
array of 5 inch ducts)
AIEE S-135-1 / IPCEA P-46-
426 (1962) Single Conductor
Concentric Strand Rubber
Insulated, 9 Cables in Duct
Bank, 90 C, 20 C Earth
Ambient, RHO-90, 100% LF.
531A 529.4A
Same as above, except 3 x 3
rectangular array of 5 in ducts
@ Figure 8 Summer
(25.8C)/Winter (5.6C) ratings.
505.3A –
579.7A
Actual A8 installation.
Same as above, except 3 x 3
rectangular array of 4 in ducts
@ Figure 8 Summer
(25.8C)/Winter (5.6C) ratings.
503.6A –
577.8A
Table 2 – Duct bank Ampacity Comparison
5.9 5.6
7.8
11.8
15.9
20.3
23.925.8
23.8
19.6
13.8
8.8
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
Jan Feb Mar April May June July Aug Sept Oct Nov Dec
Deg C
Monthly Average Soil Temperatures by Depth (Inches)
-0.5
-15
-36
HNF-50594, Rev 1 Page 12 of 42
4.7 Switchgear
The 13.8kV switchgear is a double ended arrangement with two incoming line breakers, bus
tie breaker, and 14 feeder breakers. Breakers are vacuum interrupter type. Load sensing
protective devices in the switchgear consist of instantaneous and time-overcurrent relays
on the incoming line and feeder breakers, and time overcurrent relays on the bus tie. The
switchgear bus, main incoming, and bus tie breakers are rated at 2000A. Feeder breakers
are rated 1200A.
4.8 Overcurrent Protection
4.8.1 Transformer overcurrent protection consists of backup instantaneous and time
overcurrent functions provided by the bus and transformer differential relay units.
These relay functions trip the transformer lockout relays. Transformer backup
instantaneous overcurrent relays are set at 480A (primary), above the maximum
through fault current. Inverse time overcurrent backup relays are set at 240A
primary, approximately 500% of the 20 MVA rating of the transformer. These
settings represent equivalent values of over 95 MVA and pose no practical limitation
to the 13.8kV distribution capacity.
4.8.2 Transformer secondary conductor overcurrent protection consists of inverse time
overcurrent relays on the switchgear main incoming line breakers. These relays trip
the main incoming breakers [Ref. 10.6.23]. Present pickup setting for the relays is
1680A per phase. These trip settings represent an equivalent 14.4kV value of 41.9
MVA per incoming line.
4.8.3 The 13.8kV switchgear bus tie breaker has an associated time overcurrent relay
with an existing pickup setting of 1200A (29.9MVA).
4.9 Transformer Over Temperature Protection
4.9.1 Present transformer thermal protection consists of a hot spot winding temperature
relay with a trip setting of 135 deg C [Ref. 10.6.8]. This relay trips the transformer
lockout relay [Ref. 10.6.13].
4.9.2 Present transformer load related alarms consist of hot spot winding alarm set at
120 deg C, and an oil temperature alarm set at 90 deg C [Ref. 10.6.8].
4.10 Transformer Cooling Fans
4.10.1 Two stages of forced air cooling are provided for the power transformers. Stage 1
fan setpoint is 85 deg C hot spot winding or 75 deg C oil temperature. Stage 2
setpoint is 95 deg C hot spot winding or 80 deg C oil temperature. These setpoints
are depicted in Figure 9. [Ref. 10.6.8]
4.10.2 Transformer hot spot and oil temperatures, as well as associated setpoints and
maximum temperature indicators are visible on two Qualitrol gauges on the exterior
of the transformers.
HNF-50594, Rev 1 Page 13 of 42
4.10.3 While failure of the cooling fans represents a potential limitation of substation
capacity, and is alarmed accordingly, evidence suggests that transformer
temperatures have never reached the setpoint temperatures for cooing fan
operation.
4.10.4 Maximum temperature indicators on Bank 2 Qualitrol temperature gauges indicate
a maximum oil temperature of approx. 40 deg C, and a max winding temperature of
approximately 45 deg C. Status of Bank 1 gauges is unknown at this time. The
history and maintenance and inspection procedures for these gauges is also
unknown.
Figure 9 - Transformer Temperature Setpoints
4.11 Operator Alarms
4.11.1 Load related alarms consist of the transformer hot spot winding and oil temperature
alarms mentioned above, as well as SCADA software generated alarms for the
13.8kV incoming lines and the bus tie breaker. Alarm setpoints for the main
incoming line breakers are 1120A and 1400A. Alarm setpoints for the bus tie
breaker are 960A and 1200A.
4.12 Rating and Setting Summary A summary of the existing current ratings and load sensing
protective device settings and limits is presented in Table 3 below.
Self CooledSelf Cooled
Stage 1 Fans
Stage 1 Fans
Stage 2 Fans
Stage 2 Fans
AlarmAlarm
Trip
0
10
20
30
40
50
60
70
80
90
100
110
120
130
140
150
Winding Oil
Deg C Transformer Temperature Setpoints
HN
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ry B
ush
ing
L
ap
p
20
00
A
20
00
A (
49
.9M
VA
)
Tra
nsf
orm
er
Ba
cku
p
Inst
an
tan
eo
us
& T
ime
Ov
erc
urr
en
t R
ela
ys
SE
L-5
87
50
W1
C
T=
30
0:5
, PU
=8
, De
lay
=0
8
34
8A
SE
L-5
87
51
W1
C
T=
30
0:5
, LT
PU
=4
Cu
rve
=U
4, T
D=
1
41
74
A
SE
L-3
87
50
W1
C
T=
60
0:5
, LT
PU
=4
, De
lay
=0
8
34
8A
SE
L-3
87
51
W1
C
T=
60
0:5
, LT
PU
=2
, Cu
rve
=U
4, T
D=
1
41
74
A
Tra
nsf
orm
er
Te
mp
era
ture
4
9 H
ot
Sp
ot
Win
din
g T
em
p T
rip
1
35
de
g C
4
9 H
ot
Sp
ot
Ala
rm
12
0 d
eg
C
2
6 H
ot
Oil
Te
mp
Ala
rm
90
de
g C
13
.8k
V I
nco
min
g L
ine
s 9
-1/
c 7
50
kcm
il, 1
5k
V S
hie
lde
d ,
EP
R, 2
20
mil
, 90
C, c
ab
les
in a
3x
3
UG
Co
ncr
ete
Du
ct
Su
mm
er
(50
3.6
) -
Win
ter
(57
7.8
A)
Su
mm
er
15
10
.8A
(3
7.7
MV
A)
– W
inte
r 1
73
3.4
A
(43
.2 M
VA
)
13
.8k
V S
wit
chg
ea
r W
est
ing
ho
use
VA
C-C
LA
D-W
20
00
A B
us
20
00
A (
49
.9 M
VA
)
13
.8k
V S
wit
chg
ea
r In
com
ing
Lin
e a
nd
Bu
s T
ie B
rea
ke
rs
We
stin
gh
ou
se T
yp
e 1
50
VC
P-W
50
0M
VA
20
00
A, 1
8k
A S
CA
2
00
0A
(4
9.9
MV
A)
13
.8k
V S
wit
chg
ea
r In
com
ing
Bre
ak
er
OC
Re
lay
s
C8
X1
00
50
/5
1
C8
X2
00
50
/5
1
CO
-11
, 26
5C
O4
7A
07
12
00
:5, T
ap
=7
, TD
=5
, IN
ST
=O
FF
1
68
0A
(4
1.9
MV
A)
13
.8k
V S
wit
chg
ea
r B
us
Tie
Bre
ak
er
Re
lay
C8
X1
00
-20
0
CO
-11
, 26
5C
O4
7A
07
12
00
:5, T
ap
=5
, TD
=4
1
20
0A
(2
9.9
MV
A)
SC
AD
A A
larm
s C
8X
10
0, C
8X
20
0
11
20
A &
14
00
A
(27
.9 M
VA
& 3
4.9
MV
A)
C8
X1
00
-20
0
96
0A
& 1
20
0A
(2
3.9
MV
A &
29
.9 M
VA
)
HNF-50594, Rev 1 Page 15 of 42
5.0 EXISTING LOADS
Existing loads that must be served by the A8 Substation, include the present 200 Area
substation loads, plus the 100 Area loads (“emergency” or otherwise) that may be supplied
by the 13.8kV tie line C8L14.
The original justification for construction of the tie line included serving as an “emergency”
backup for the aging 100KW Substation A7, as well as a potential permanent normal supply
for future diminished 100 Area loads. Since construction of the tie line, a new 230kV
substation has been constructed at the former location of the 100KE Substation A9, and has
replaced the aging A7 substation. Need for an “emergency” source may be reduced,
however, potential use of the tie line for a future normal supply remains. This evaluation
assumes A8 capacity will include full capacity operation of the C8L14 tie line.
5.1.1 Power Factor
Power factor (monthly average) for the 100 and 200 Areas varies annually with a summer
low and winter high. 200 Area variation is between 93 and 99 percent, while the 100 Area
is lower, varying between 80 and 95 percent. See Figure 10.
Figure 10 - Power Factor, 100 & 200 Areas
5.1.2 C8L14 Load
Calculation HNF-32354-R0 Appendix D (Ref. 10.6.1) demonstrated the C8L14 tie line can
adequately support the assumed 100 Area loads of 5.4MVA at 95% power factor.
Calculation HNF-32354-R0 Appendix G determined tie line capacitor controller settings for
an assumed maximum 5MVA load, however, the capacitor settings are not load limiting.
0.75
0.80
0.85
0.90
0.95
1.00
6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5
PO
WE
R F
AC
TO
R
MONTHS FOR LAST 2 YEARS
100 AND 200 AREAS TOTAL
MONTHLY PROFILE
200 Area 100 Area
HNF-50594, Rev 1 Page 16 of 42
Appendix G also calculated the tie line power factor to be 93.5% for an A7 5MVA 76% pf
load, and 99.6% for an A7 5MVA 90% pf load.
The current 24 month peak demand profile for the 100 Areas is given in Figure 11 below,
and in Appendix C. Winter peak demand is shown to be approximately 5.1MW at 95%
power factor, or 215A per phase @ 14.4kV. Hourly demand data for the past 12 months is
presented in Figure 15.
Figure 11 - 100 Area Monthly Demand
This evaluation will assume a constant C8L14 tie line load of 5.4MVA at 98% pf and 14.4kV
at the A8 substation, or 216A per phase.
5.1.3 Existing “Normal” A8 Load
Most recent 24 month demand load profile for the A8 substation loads is given in Figure 12
below and in Appendix C. A detailed hourly demand profile for 12 months is given in Figure
16.
0
1,000
2,000
3,000
4,000
5,000
6,000
6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5
KILOWATTS
MONTHS FOR LAST 2 YEARS
100 AREAS COINCIDENTAL
MONTHLY DEMAND PROFILE
MINIMUM AVERAGE MAXIMUM
HNF-50594, Rev 1 Page 17 of 42
Figure 12 - 200 Area Monthly Demand
The peak hourly demand load for the combined incoming feeders of substation A8 was
recorded as 31.7MW on November 24, 2010. The winter peak for the previous year was
28.1MW. 31.7MW at 14.4kV and 98% power factor is 1297A per phase. Average total
monthly demand is approximately 20MW.
5.1.4 A8 Load Daily Load Profiles
Using hourly demand load data from June 2010 through May 2011, average daily load
profiles were determined for summer (July and August) and winter (December & January)
load periods. Hourly loads were averaged for each hour of each day of the week to obtain
an average weekly load profile. From the average weekly load profile data, Monday through
Thursday were averaged to obtain a weekday load profile. Approximate one and two step
load profiles with RMS values similar to the hourly load profiles were chosen to represent
the average summer and winter daily profiles. These step load profiles were found to have
a daily cyclic form with an amplitude of approximately 4 MW and a 60% duty cycle
superimposed on top of the constant base load. See Figure 13 and Figure 14 below.
23,313.6
9,007.2
31,658.4
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
05
/20
09
06
/20
09
07
/20
09
08
/20
09
09
/20
09
10
/20
09
11
/20
09
12
/20
09
01
/20
10
02
/20
10
03
/20
10
04
/20
10
05
/20
10
06
/20
10
07
/20
10
08
/20
10
09
/20
10
10
/20
10
11
/20
10
12
/20
10
01
/20
11
02
/20
11
03
/20
11
04
/20
11
KILOWATTS
MONTHS
A-8 DEMANDS
C8X100 C8X200 TOTAL
HNF-50594, Rev 1 Page 18 of 42
Figure 13 - Winter & Summer Average Weekly Load Profile
Figure 14 - Winter & Summer Weekday Average Load Profile & Approx. Step Load
Representations
0
5000
10000
15000
20000
25000
kW
Winter & Summer Average Weekly A8 Load Profile
December & Jan
July & Aug
10000
11000
12000
13000
14000
15000
16000
17000
18000
19000
20000
21000
22000
23000
24000
25000
0:00 3:00 6:00 9:00 12:00 15:00 18:00 21:00 0:00
kW Mon-Thurs Avg
Winter
Winter Approx
Summer
Summer Approx
HNF-50594, Rev 1 Page 19 of 42
5.1.5 Normal A8 Load and C8L14 Load Combined
For a first order approximation, the 100 Area load served by C8L14 from substation A8 is
assumed to be a constant 5.4MVA at 14.4kV, or 216A. Adding this base load (at an assumed
98% power factor) results in the total hourly kW load profile for A8 shown in Figure 17
below. The A8 November 24, 2010 peak winter load then becomes 36.95MW, with the
summer peak load of 23.6MW. These combined peak loads equate to 1512A and 966A
respectively at 14.4kV and an assumed 98% power factor. These loads are summarized in
Table 4.
Table 4 - Existing A8 Substation Loads
Existing Peak 200 Area and C8L14 Loads
Summer Winter
200 Area Peak
(Hourly Demand)
18.3MW 31.7MW
C8L14 Full Load 5.4MVA @ 98% pf 5.4MVA @ 98% pf
Total 23.6MW (966A) 36.95MW (1512A)
Figure 15 - 100 Area Hourly Demand
0
1000
2000
3000
4000
5000
6000
6/1/10 7/21/10 9/9/10 10/29/10 12/18/10 2/6/11 3/28/11 5/17/11
kW
100 Area Hourly Total kW
100 Area Hourly Total kW
HNF-50594, Rev 1 Page 20 of 42
Figure 16 - 200 Area Hourly Demand
Figure 17 - 200 Area Hourly Demand + C8L14 Load
0
5000
10000
15000
20000
25000
30000
35000
40000
6/1/10 7/21/10 9/9/10 10/29/10 12/18/10 2/6/11 3/28/11 5/17/11
kW
A8 Substation Total Hourly kW
C8X100+C8X200 kW
0
5000
10000
15000
20000
25000
30000
35000
40000
6/1/10 7/21/10 9/9/10 10/29/10 12/18/10 2/6/11 3/28/11 5/17/11
kW
A8 Substation Total Hourly kW + 5.4MVA C8L14 Load
A8 + C8L14 5.3MW Base Load
HNF-50594, Rev 1 Page 21 of 42
5.2 Historical Transformer Temperature
Transformer hot spot and oil temperatures are monitored by the SCADA system. However,
(apparently) only oil temperature measurements are recorded and archived. Hourly
transformer oil temperature data has been collected for the months of July 2010 and
November 2010 for comparison with transformer load and ambient temperature data.
Maximum ambient temperatures occur in late July and early August, while maximum
transformer load occurred in late November. Figure 18 through Figure 21 below present
graphs of oil temperature, ambient temperature, and transformer load for July and
November 2010.
Figure 18 - Bank 1 Load & Oil Temp, July
10
15
20
25
30
35
40
45
50
55
60
0
2
4
6
8
10
12
14
16
18
20
1-Jul-10 6-Jul-10 11-Jul-10 16-Jul-10 21-Jul-10 26-Jul-10 31-Jul-10
Deg CMWBank 1 Load, Oil & Ambient Temp
July 2010
Bank 1 MW
Bank 1 Oil C
HNF-50594, Rev 1 Page 22 of 42
Figure 19 - Bank 2 Load & Oil Temp, July
Figure 20 - Bank 1 & 2 Composite Load & Oil Temp, July
10
15
20
25
30
35
40
45
50
55
60
0
2
4
6
8
10
12
14
16
18
20
1-Jul-10 6-Jul-10 11-Jul-10 16-Jul-10 21-Jul-10 26-Jul-10 31-Jul-10
Deg CMW Bank 2 Load, Oil & Ambient Temp
July 2010
Bank 2 MW Bank 2 Oil C Ambient Max C Ambient Avg C
10
15
20
25
30
35
40
45
50
55
60
0
2
4
6
8
10
12
14
16
18
20
1-Jul-10 6-Jul-10 11-Jul-10 16-Jul-10 21-Jul-10 26-Jul-10 31-Jul-10
Deg CMWBank 1 & 2 Load, Oil & Ambient Temp
July 2010
Bank 1 MW Bank 2 MW Bank 1 Oil C
Bank 2 Oil C Ambient Max C Ambient Avg C
HNF-50594, Rev 1 Page 23 of 42
Figure 21 - Bank 1 & 2 Composite Load & Oil Temp, November
These graphs demonstrate that despite the peak load in November of nearly double that of
July’s load, transformer temperature in November is significantly lower. July graphs also
show a similarity between Bank 1 and Bank 2 oil temperature, despite a 200% difference in
load.
The November graph shows a nearly constant Bank 1 oil temperature despite its load
doubling and exceeding its self-cooled rating as the ambient temperature decreases.
6.0 FORECAST LOADS
6.1 For this study a 20 year load forecast was completed to determine additional expected
demand load at 251W substation. This evaluation considered the following sources for
additional or removed loads:
6.1.1 Projects where design is complete and construction is scheduled, underway or
recently completed
6.1.2 Planned future projects.
-30
-20
-10
0
10
20
30
40
50
0
5
10
15
20
25
30
35
40
1-Nov-10 6-Nov-10 11-Nov-10 16-Nov-10 21-Nov-10 26-Nov-10 1-Dec-10
Deg CMWBank 1 & 2, Load, Oil and Ambient Temperature
November 2010
Bank 1 MW Bank 2 MW BANK 2 Temp C
BANK 1 Temp C Ave 15 Min Temp Min Temp
Ave Temp Daily Avg C
HNF-50594, Rev 1 Page 24 of 42
6.2 Projects with completed design and where construction is scheduled, underway or recently
completed are included in Appendix F. Estimates on expected maximum demand were
made based in part on 1) transformer size 2) estimated demand factors and 3) similar
facilities located on site where historical demand load data is available. The estimated
maximum summer and winter demands for these new projects are indicated in the year the
additional load is expected. The following new projects are included in the load forecast:
· 222-S Electric Heat Addition
· New facilities at unsecured core area (200E) including 2268E, 2269E, 2610E, 2611E,
and associated trailers
· New 200W Pump and Treat, including 289-T, TA, TB, TC, TD, TE and TF
· ERDF TMF 6618-D
· C-Farm (MARS)
· ERDF CMF
· ERDF EMF/OPS Facilities
· New 200W Sewer Lagoon (L-691)
· ERDF Batch Plant
· 2711E Shop Addition
· 2713-S
6.3 For future projects, the most significant load increases are due to the planned waste
retrieval efforts underway at WRPS. These load forecasts are documented in RPP-5228 Rev
2 [Ref. 10.6.5]. In this assessment, WRPS has evaluated the worst case electrical loading
scenario and has determined it is due to power required for simultaneous retrieval
activities involving 1) safe storage of waste, 2) retrieval of waste from double shell and 3)
retrieval of waste from single shell tanks. These activities are expected to occur initially in
2013, and continue for this study period. Additionally, new tank farm offices are planned
for 2016 and are included in the forecast.
6.4 Several significant load reductions are expected in the future, and are included in the load
forecast for the year the load is expected to cease. Estimated load reduction was based on
actual metered demand date for these facilities, and is included in Appendix F. Load
reductions include the following:
· D&D completion at PFP, including 234-5-Z, 291-Z, D&D trailers and 234-5-Z-BE
· Removal of 216-ZP-1 upon completion of new Pump and Treat facility
· WTP construction power loads on line C8-L5 being transferred to A6 substation
· D&D completion at U-Plant
6.5 Additional forecast loads are summarized in Table 5, loads to be removed are summarized
in Table 6.
HNF-50594, Rev 1 Page 25 of 42
Table 5 - Forecast Additional Loads
Projects in Design/Construction
Facility Transformer
Size (kVA)
Initial
Energization
Date
Estimated
Additional
Summer
Demand
Load
(kVA)
Estimated
Additional
Winter
Demand
Load
(kVA)
Comment
PFP Site #1 Portable
Sub
1500 5-11-11 0 0 Offsets existing
PFP load
PFP Site #2 Portable
Sub
1500 5-11-11 0 0 Offsets existing
PFP load
200W Sewer Lagoon 225 150 150
222-S 1000 7-31-11 1000
222-S 1000 7-31-11 1000
2713-S 500 9-7-11 150 250
2711-E Addition 750 200 300
S&GW Mobiles
(USC North)
150 2-24-11 0 0 Additional load
offset by ARRA
removals
2611E/2268E 500 12-8-10 105 50 Winter Delta
2610E/2269E 500 1-23-11 105 50 Winter Delta
AW Mobiles 225 4-19-11 0 0 Replace 272-
AW
MARS (C-Farm) 750 6-27-11 300 400
2720-EA 150 4-7-11 0 0 Replaces 2754-
W/ trailers
289-T 2-1500 1200 1500
289-TA 750 7-26-11 300 400
289-TB 150 4-27-11 50 75
289-TC 150 5-19-11 50 75
289-TD 150 6-15-11 50 75
289-TE 300 6-30-11 105 150
289-TF 112.5 40 55
ERDF Batch Plant 300 4-10-11 150 150
ERDF TMF (6618-D) 500 4-10-11 25 70 Winter Delta
ERDF Ops/EMF 225 6-13-11 70 200
ERDF CMF 150 6-13-11 40 120
Tank Farm Offices n/a 900 1400 planned, no
design
SST Retrieval n/a 390 520 planned, no
design
WFD n/a 6000
(note 1)
7200
(note 1)
planned, no
design
Note 1: Excludes the 125% NEC demand factor referenced in RPP-5228, Rev 2.
HNF-50594, Rev 1 Page 26 of 42
Table 6 - Forecast Loads to be Removed
Facilities Scheduled for Removal
Facility Existing
Transformer
Size
Estimated
Summer Load
Reduction
(kVA)
Estimated Winter
Load Reduction
(kVA)
Comment
PFP Chillers 1500 1330 0
234-5-Z 2-1000 1000 1000
291-Z 2-1000 1000 1000
2736-ZB 500 170 190
234-5-Z-BE 2-3000 0 5000
C8-L5
(Construction
Power to WTP)
(7 MW
Capacity Line)
3000 4500
U Plant D&D 500 300
PFP Mobiles 225 105 350
216-ZP-1 225 220 275
6.6 Forecast additional summer loads including new and removed load contributions, is shown
in Figure 22. Forecast additional winter loads including new and removed load
contributions, is shown in Figure 23. Years noted are calendar years.
Figure 22 - Forecast Additional Summer Loads
-15000
-10000
-5000
0
5000
10000
15000
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
kW
Forecast Additional Summer Peak LoadsTotal Summer Add'l
AW Mobiles
WTP
U Plant D&D
2711E Shop Addition
Tank Farm Offices
ERDF Batch Plant
Tank Farms (SST/WFD)
Sewer lagoon
ERDF EMF/Ops
PFP D&D Trailers
ERDF CMF
C-Farm (MARS)
ERDF TMF (6618-D)
291-Z
289-TB,TC,TD,TE,TF
289-TA
289-T
2736-ZB
2713-S
2611-E / 2268-E
2610-E / 2269-E
234-5-Z-BE
234-5-Z
222-S (Electric Heat)
216-ZP-1
HNF-50594, Rev 1 Page 27 of 42
Figure 23 - Forecast Additional Winter Loads
6.7 Forecast additional A8 substation loads are summarized in Figure 24 below. Maximum
additional summer load of approximately 8.1 MW occurs in 2014 and 2015, while the
maximum additional winter load of 8.4MW occurs in 2013.
-15000
-10000
-5000
0
5000
10000
15000
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
kW
Forecast Additional Winter Peak LoadsTotal Winter Add'l
AW Mobiles
U Plant D&D
2711E Shop Addition
Tank Farm Offices
WTP
ERDF Batch Plant
Tank Farms (SST/WFD)
Sewer lagoon
ERDF EMF/Ops
PFP D&D Trailers
ERDF CMF
C-Farm (MARS)
ERDF TMF (6618-D)
291-Z
289-TB,TC,TD,TE,TF
289-TA
289-T
2736-ZB
2713-S
2611-E / 2268-E
2610-E / 2269-E
234-5-Z-BE
234-5-Z
222-S (Electric Heat)
216-ZP-1
HNF-50594, Rev 1 Page 28 of 42
Figure 24 - Forecast Additional A8 Load
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
kW Forecast Additional A8 Load
Total Summer Add'l
Total Winter Add'l
HNF-50594, Rev 1 Page 29 of 42
6.8 To forecast the total A8 substation load, the existing loads are added to the forecast
additional load shown above. Existing loads are summarized in Table 4 above, and the
resultant total forecast summer and winter load is shown in Figure 25 and Figure 26 below:
Figure 25 - Forecast Summer A8 Load
Figure 26 - Forecast Winter A8 Load
6.9 The peak forecast A8 substation load is approximately 29.3MW in summer of 2016 and
nearly similar in 2013, and 45MW in winter 2013. At the assumed 94% and 98% power
factors these loads equate to 1248A and 1841A @ 14.4kV respectively.
0
5000
10000
15000
20000
25000
30000
35000
40000
45000
500002
01
0
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
kW Forecast Summer A8 Load
Total Summer
Exist 200 Area Summer Peak
Total Summer Add'l
C8L14
0
5000
10000
15000
20000
25000
30000
35000
40000
45000
50000
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
kW Forecast Winter A8 Load
Total Winter
Exist 200 Area Winter Peak
C8L14
Total Winter Add'l
HNF-50594, Rev 1 Page 30 of 42
7.0 DISCUSSION
7.1 Existing Loads and Substation Capacity
The existing A8 substation transformer winter capacity (41.2 MVA), per section 4.4 above,
is the most limiting factor, followed by the incomer relay settings of 1680A (41.9 MVA),
transformer secondary cables 1733A (43.2 MVA), and transformer LTC overload rating of
1800A (44.9 MVA). The A8 transformer seasonal summer and winter temperatures are the
limiting factors for load limits.
A summary of the present substation peak loads (Table 4) and switchgear incoming line
ampacity is presented in Table 7 below. The existing incoming line ampacity and LTC
ratings are not exceeded for the present substation peak winter load combined with the
assumed fully loaded C8L14 line supplying the 100 Area.
Table 7 – Existing Load Summary & Capacity Limits
Load Scenario Peak Load Amps @
14.4kV
Existing Switchgear Incoming Line Winter Ampacity 1733 A
Exiting Switchgear Incoming Line Summer Ampacity 1511A
Existing LTC Rating 1800 A
Exist A8 200 Area Peak Winter Load 31.7MW (98% pf) 1297A
Exist A8 200 Area Peak Summer Load 18.3MW (94% pf) 781A
Exist A8 200 Area Peak Winter Load + C8L14 Base
Load
36.95MW (98%
pf)
1512A
Exist A8 200 Area Peak Summer + C8L14 Base Load 23.6MW (94% pf) 1006A
Transformer oil temperature records indicate, as expected, summer oil temperature is
much higher than that in winter, even though transformer load may be significantly less.
There is no evidence that the transformer oil or winding temperatures have reached the
setpoints for forced air fan cooling operation. Consequently, there is no in service SCADA
data to demonstrate the cooling effect of the fans during summer operation.
In the absence of historical transformer performance data for rated loads, or overloads, only
estimated performance based upon manufacturer’s tests, and IEEE Std. loading guidance is
available.
Methods and equations for calculating transformer temperatures for varying loads are
given in the IEEE guide. Calculations based on this guide are presented in Appendix E and
summarized in Section 7.2.2 below.
HNF-50594, Rev 1 Page 31 of 42
Sophisticated modeling computer software programs exist for determining transformer
temperature and loss of life, but are not available for this study and may not be appropriate
for this small transformer application.
7.2 Forecast Loads and Substation Capacity
7.2.1 The total forecast A8 substation loads are summarized in Table 8 below:
Table 8 - Forecast Loads and Substation Capacity Summary
Load Scenario Peak Load Amps @
14.4kV
Existing Switchgear Incoming Line Winter Ampacity 1733A
Existing Switchgear Incoming Line Summer Ampacity 1511A
Existing LTC Overload Rating 1800A
Forecast A8 200 Area Peak Winter Load w/o C8L14 39.7MW (98% pf) 1624A
Forecast A8 200 Area Peak Summer Load w/o C8L14 23.8MW (94% pf) 1015A
Forecast A8 200 Area Peak Winter Load + C8L14 Base
Load
45.0MW (98% pf) 1804A
Forecast A8 200 Area Peak Summer + C8L14 Base Load 29.3MW (94% pf) 1250A
7.2.2 The total forecast load values are within the existing 13.8kV equipment however,
the 45MW, 1804A load is 105% of the recommended incoming line winter ampacity
rating. The existing cable is MV-105, which is rated to run continuously at 105C.
The 1733A cable rating has been limited to 90C because the PVC conduit is rated for
use with 90C cable.
7.2.3 The 29.3MW summer peak (31.2MVA @ 94% pf) is below the nominal 33MVA
rating of the transformers, however, per the IEEE quick approximate guidelines of
Table 4 as discussed in 4.3.2 above, the high ambient temperature of July and
August effectively reduces the nominal transformer rating to approximately 97%
(32MVA). See
Figure 5. The IEEE thermal model calculations discussed in section 4.4 above
however show a 35MVA limit before above normal loss of life transformer
temperature is reached.
7.2.4 The 45MW winter peak (45.9MVA @ 98% pf) is 139% of the nominal 33MVA
transformer rating. This exceeds the “approximate” increased rating (120% =>
39.6MVA) afforded by the low winter ambient temperatures per the IEEE quick
guide by approximately 6MVA. The IEEE thermal model equations (section 4.4
above) allows 125% or 41.2MVA before above-normal loss of life temperature is
reached. Also per the thermal model, 45MVA will produce a steady state hot spot
temperature of nearly 132 deg C. (See Figure 6), near the existing 135 deg C over-
temperature trip setting of the transformer. Loss of life equations for this hot spot
HNF-50594, Rev 1 Page 32 of 42
temperature result in an accelerated aging factor (FAA) of 8 (i.e. 8 times normal loss
of life), or equivalently, 0.125 per unit life (see Figure 2).
7.2.5 The transformer loads discussed above in this section are assumed to be constant
steady state loads. Actual loads will have a daily cyclic profile as shown in section
5.1.4. Using a 3.5MW cyclic daily load profile on top of a steady state base load to
produce the 45MW (45.9MVA) forecast peak as load input to the IEEE thermal
model equations reduces the peak hot spot temperature from the steady state peak
load temperature of 132 to 126 deg C as shown in Figure 27 below. (Note that this
calculation assumes a steady state ambient temperature, the conservative winter
daily average of 5 deg C (41 deg F).
Figure 27 - Weekday Transformer Temperature Variation
7.2.6 The 45.9MVA forecast winter load is near the limits of the 13.8kV equipment, as well
as the thermal capabilities of the transformer. Considering that the duration of the
forecast winter peak is only one season (2013), and drops to below 41MVA in 2016,
and given that the “emergency” justification of supplying the 100 Area via line
C8L14 may be significantly diminished due to the construction of the new A9
substation, consideration should be given to removing the C8L14 tie line load from
the A8 single transformer service load requirement. If so, from Table 8 the forecast
winter peak load in 2013 becomes 39.7MW (40.5MVA). The IEEE thermal model
steady state temperature for this winter load is 100 deg C, within the normal loss of
life temperature limits. Winter forecast load in 2016 and beyond is less than 41MW
(41.8MVA) without the C8L14 tie line load, well within the winter capability of the
transformer.
7.3 Transformer Capacity
7.3.1 Ultimate transformer capacity maybe be determined by the maximum load resulting
in transformer hot spot temperatures less than 110 deg C (the maximum limit of
40
41
42
43
44
45
46
47
48
49
50
50
60
70
80
90
100
110
120
130
140
150
0 5 10 15 20
MVADeg C
Time of Day (hours)
Winter Weekday, Forecast Load
Hot Spot Temp
Top Oil Temp
Load
HNF-50594, Rev 1 Page 33 of 42
normal loss of life), or may include acceptance of higher temperatures and the
resultant additional loss of life for short periods of high load conditions due to cyclic
daily load profiles or abnormal overloads.
7.3.2 In the absence of actual in-service transformer temperature data, or use of
applicable detailed software or calculation models to predict the transient load
performance (temperature) of transformers, the following methods are available to
determine estimates of the seasonal capacity of the transformers.
7.3.2.1 Quick approximate rating adjustments of IEEE C57.91 Table 4. The
results of this method is presented in Figure 4 and
Figure 5 above.
7.3.2.2 Application of transformer modeling equations of IEEE C57.91
Clause 7. These equations can be used with steady state loads, or
iterated with step or transient loads. These equations are
summarized in Figure 6 and discussed in sections 4.4 and 7.2 above.
7.3.2.3 Comparison of the results of these methods and substation loads are
presented Table 9, Figure 28 and Figure 29.
Transformer Capability (MVA)
Summer
(30 deg C
daily avg ambient)
Winter
(5 deg C
daily avg ambient)
Trip
(135 deg C From Thermal
Model)
41.2 46.5
Thermal Model “Normal” Rating
(110 deg C from Thermal Model) 35 41.2
Table 4 Ambient Adjustment 32.3 (98%) 39.6 (120%)
Nameplate Rating 33 33
Table 9 - Transformer Capability
HNF-50594, Rev 1 Page 34 of 42
Figure 28 - Winter Forecast Loads and Transformer Capability
Nameplate Rating
Table 4 Ambient
Adjustment
Thermal Model
Overload
(> 110 Deg C)
Transformer Trip
(> 135 Deg C)
20000
25000
30000
35000
40000
45000
50000
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
kVA
Winter Forecast Loads and Transformer Capability
Transformer Trip (> 135 Deg C)
Overload (> 110 Deg C)
Thermal Model
Table 4 Ambient Adjustment
Nameplate Rating
Total Winter
Total Winter w/o C8L14
HNF-50594, Rev 1 Page 35 of 42
Figure 29 - Summer Forecast Loads and Transformer Capability
7.3.3 It should be noted that the rating adjustments and transformer thermal model
temperature calculations presented in this study are generally based upon the
historical daily average ambient temperature. For summer 30 deg C (86 deg F) is
used, and for winter, 5 deg C (41 deg F). Actual instantaneous and even daily
average temperatures may vary significantly and it is assumed that these chosen
values will produce conservative results. For short transients of heavy winter load
that may exceed the forecast load values it is reasonable to assume they may be
abnormally high heating loads due to extreme low temperature conditions. These
low temperatures will further help increase the loading capability of the
transformers.
7.3.4 All possible operating scenarios with varying load profiles, peak load durations, and
steady state or transient ambient temperatures are too numerous to specifically
address in this study. Significant departures from the assumed loads and
temperatures presented in this study, whether they be potential scenarios or real
time events, should be evaluated in detail on a case by case basis.
7.4 Operator Indicators and Alarms
7.4.1 To be useful, indicators and alarms should be relevant to the potential trouble or
hazards. In the case of single transformer operation at the A8 substation, the
potential trouble is a transformer operating above nameplate rating. The ultimate
Table 4 Ambient
Adjustment
Nameplate
Thermal Model
Overload
(> 110 Deg C)
Transformer Trip
(> 135 Deg C)
20000
25000
30000
35000
40000
45000
50000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20kVA
Summer Forecast Loads and Transformer Capability
Transformer Trip (> 135 Deg C)
Overload (> 110 Deg C)
Thermal Model
Nameplate
Table 4 Ambient Adjustment
Total Summer w/o C8L14
Total Summer
HNF-50594, Rev 1 Page 36 of 42
trouble in this case is excessive winding hot spot or oil temperature. The precursor
to this high temperature is an overload condition. Indicators and warnings
therefore should be triggered by transformer load and temperature setpoints
directly related to the cause of the overload condition. Possible scenarios for this
overload condition include:
7.4.1.1 Normal substation operation with load shared between the two
transformers and the total load is transferred to one of them which
results in an overload condition
7.4.1.2 Single transformer operation with an normal load increasing toward
overload condition
7.4.1.3 Single transformer operation below overload and line C8L14 is
required to serve 100 area loads where the additional load will
result in an overload condition
In each one of these cases, knowledge of the total of the 200 Area and 100 Area
loads would forewarn of potential single transformer overload.
Existing SCADA alarms include those for current on each incoming line. However,
these measurements in themselves don’t provide direct indication of potential
single transformer operation overload. An additional SCADA alarm that responds to
the total of the two incoming line currents and perhaps an additional alarm that also
includes the 100 Area loads that line C8L14 would serve would indicate conditions
of potential overload for single transformer operation at substation A8. Alarm
conditions based upon load only will not necessarily indicate potential overload
conditions however, as ambient temperature is a factor. However an alarm to
indicate total load exceeding nameplate rating, and perhaps an additional alarm
condition for potential summer and winter nominal overload conditions would be
indicative. New SCADA alarm setpoints are suggested in Table 10 below. The
response to all these alarms would be to evaluate each specific case for
unacceptable potential overload conditions before transferring loads to a single
transformer. Considerations for determining acceptable loading would include
transformer capacity as discussed in this study such as ambient temperature,
existing transformer temperature (load), and acceptable loss of life based upon
magnitude and duration of overload condition. During single transformer operation
during these conditions, transformer temperature should be monitored to
determine magnitude of overload and to acceptability of associated loss of life.
HNF-50594, Rev 1 Page 37 of 42
Table 10 - Suggested SCADA Alarms
Condition Calculation Summer
Setpoint
30 deg C
Winter
Setpoint
5 deg C
Bank 1 + Bank 2 Load > Single
Transformer Nameplate
C8X100 MVA + C8X200 MVA 33MVA 33MVA
Bank 1 + Bank 2 Load + C8L14 >
Single Transformer Nameplate
C8X100 MVA + C8X200 MVA
+ Total 100Area MVA
33MVA 33MVA
Bank 1 + Bank 2 Load > Nominal
Single Transformer Seasonal
Capability
C8X100 MVA + C8X200 MVA 35MVA 40MVA
Bank 1 + Bank 2 Load + C8L14 >
Nominal Single Transformer
Seasonal Capability
C8X100 MVA + C8X200 MVA
+ Total 100Area MVA
35MVA 40MVA
HNF-50594, Rev 1 Page 38 of 42
8.0 CONCLUSIONS
8.1 Summary
Based on the transformer loading guidelines of IEEE C57.91, including general
approximations and transformer and site-specific transformer temperature calculation
models, the existing and forecast 200 Area A8 substation loads are within the thermal
capabilities of a single existing transformer. Use of the tie line should not be assumed to be
within the thermal capabilities of a single transformer and should be restricted during
periods of peak winter loading.
8.2 Existing Load Capacity
Substation single transformer operation capacity IS sufficient to supply the existing
200Area peak loads.
8.3 Forecast Load Capacity
8.3.1 Substation single transformer operation capacity IS sufficient to supply the forecast
200Area peak summer loads.
8.3.2 Substation single transformer operation capacity IS sufficient to supply the forecast
200Area summer loads plus the assumed full load of line C8L14.
8.3.3 Substation single transformer operation capacity IS sufficient to supply the forecast
200Area winter loads, but requires taking credit for the additional transformer
capacity afforded by the low winter ambient temperature, and may require
operation in small loss of life overload condition.
8.3.4 Substation single transformer capacity IS sufficient to supply the forecast 200Area
winter loads without the assumed full load of line C8L14 without operating in a loss
of life overload condition. The total load is 139% of the nominal 33MVA rating of
the transformer, and exceeds the 120% rating allowed by the 30 year daily average
low winter ambient temperature for normal loss of life operation. The IEEE thermal
model calculation for this condition indicates transformer temperatures near the
over temperature trip setpoint with accelerated aging factors of nearly 10 times
normal.
8.4 Maximizing Substation Capacity
8.4.1 Capacity of the existing substation is limited by taking advantage of its low winter
ambient rating of 41.2 MVA (Sect 4.4 above), followed by the 41.9 MVA incomer
relay settings. Although not recommended by this study, significantly increasing the
capacity of the substation’s 13.8kV system, with one transformer out of service, will
require additional transformer capacity, either from larger units, or an additional
transformer.
8.5 Alarms and Indicators
HNF-50594, Rev 1 Page 39 of 42
8.5.1 Existing SCADA alarms based on incoming line current setpoints do not directly
indicate potential overloads for the single transformer operating condition analyzed
in this study. New SCADA alarms should be programmed to respond to the total
substation load that would potentially precipitate a single transformer operation
overload condition.
HNF-50594, Rev 1 Page 40 of 42
9.0 RECOMMENDATIONS
9.1 General
9.1.1 Evaluate requirement to include full capacity of line C8L14 in substation A8 single
transformer load capacity requirements. With the replacement of the A7 substation,
with new the new A9 substation, the original need for the C8L14 tie line as a backup,
may be significantly reduced. Full capacity use of the tie line may not be supported
by the thermal capability of a single transformer during periods of peak forecast
winter loads.
9.2 Major Equipment Modification / Construction
9.2.1 Reset SCADA incoming line current alarms to match incoming cables.
9.3 Minor Modifications
9.3.1 Ensure 13.8kV switchgear feeder loading is reasonably balanced between Bus 1 and
Bus 2, so no bus total load exceeds the 1200A (29.9MVA) pick up setting of the bus
tie breaker time overcurrent relay. Alternatively, raise the bus tie relay pickup
setting. Note that the bus tie relay settings must selectively coordinate with the
incoming line breaker relay settings.
9.3.2 Reprogram SCADA system to record and archive transformer winding temperatures
(in addition to oil temperatures).
9.4 Operations
9.4.1 Manually operate (run) transformer cooling fans when periods of heavy or overload
conditions are anticipated. While this may not be necessary for transformer
operation, the additional cooling will reduce the initial transformer temperatures
and help negate and delay detrimental effects of high transformer temperatures.
9.4.2 Include local transformer temperature gauges and recording/resetting maximum
winding and oil temperature indicators in maintenance and operation program.
9.4.3 Preclude full capacity use of C8L14 tie line during periods of maximum transformer
loading (winter peaks), or when total substation load approaches 35MVA.
9.5 SCADA Alarms
9.5.1 Implement SCADA alarms responsive to total substation load, with and without
C8L14. Alarm setpoints should alert dispatchers to potential transformer overload
conditions before transferring loads to a single transformer. Specific actual
conditions should be evaluated to determine if the potential overload condition is
acceptable. Suggested alarms and setpoints are given in Table 10 above.
HNF-50594, Rev 1 Page 41 of 42
10.0 REFERENCES
10.1 IEEE Std C57.91(R2004) IEEE Guide for Loading Mineral-Oil-Immersed Transformers
10.2 IEEE Std C57.131 (2012) IEEE Standard Requirements for Tap Changers
10.3 Electrical Transmission and Distribution Reference Book, Westinghouse Electric
Corporation, East Pittsburgh, PA, Fourth Edition: Tenth Printing, 1964
10.4 AIEE Pub. No. S-135-1 / IPCEA Pub. No. P-46-426, AIEE-IPCEA Power Cable Ampacities
Volume 1 - Copper Conductors, American Institute of Electrical Engineers, New York, NY,
1962.
10.5 NFPA 70 – 2008 National Electrical Code
10.6 Hanford Documents
10.6.1 HNF-32354, Revision 0, Design Calculations Project L-325, A7/A8 13.8kV Tie Line,
Project L-325, May 2007.
10.6.2 HNF-26750, Revision 0, Acceptance Test Report, Substation A8 (251W) 230kV
Power Transformers, Project L-325, July 2006.
10.6.3 HNF-SD-LL-ES-004, Revision 5D, Electrical Utilities Relay Settings, September
2009.
10.6.4 PNNL-15160, Hanford Site Climatological Summary 2004 with Historical Data,
May 2005.
10.6.5 RPP-5228, Rev 2, Assessment of the Electrical Power Requirements for Continued
Safe Storage and Waste Feed Delivery
10.6.6 RPP-40149, Rev 1A, Integrated Waste Feed Delivery Plan
10.6.7 SVF-1805, Rev 1, Electrical Power Needs for WFD & SST Retrieval
10.6.8 H-2-1406, Sh 1, Rev 9, Substation Plan & Elevations
10.6.9 H-2-1406, Sh 3, Rev 3, Electrical A8 Yard Plan Elevations
10.6.10 H-2-90003, Sh 1, Rev 3, 251W Substation Conduit Layout
10.6.11 H-2-90003, Sh 2, Rev 3, 251W Substation Conduit Layout
10.6.12 H-2-90075, Sh 1, Rev 15, A8 230kV One Line Diagram
10.6.13 H-2-90080, Sh 2, Rev 6, 251W Substation D.C. Schematic Diagram Bank No. 1
Differential
10.6.14 H-2-90083, Sh 1, Rev 6, 251W Substation DC Schematic Diagram Bus Differentials
HNF-50594, Rev 1 Page 42 of 42
10.6.15 H-2-90101, Sh 1, Rev 8, 251W Substation Wiring Diagram Panel 2
10.6.16 H-2-90101, Sh 2, Rev 10, 251W Substation Wiring Diagram Panel 2
10.6.17 H-2-90101, Sh 3, Rev 11, 251W Substation Wiring Diagram Panel 2
10.6.18 H-2-90101, Sh 5, Rev 2, 251W Substation Wiring Diagram Panel 2
10.6.19 H-2-90109, Sh 2, Rev 8, 251W Substation Basement Terminal Bo Wiring Diagram
10.6.20 H-2-93595, Sh 1, Rev 4, Electrical SCADA System I/O One Line Diagram
10.6.21 H-2-93602, Sh 3, Rev 3, 251W Substation Interconnection Schedule SCADA RTU –
5
10.6.22 H-2-95974, Sh 1, Rev 2, 20/26/33MVA Transformer Bank No. 1 Control Wire
Connection Diagram
10.6.23 H-2-817613, Sh 1, Rev 8, A8 13.8kV One Line Diagram
10.6.24 H-2-831422, Sh 1, Rev 3, Electrical Wire Run List / Conduit Schedule
10.6.25 H-2-831424, Sh 1, Rev 1, 251W Substation Interconnection Schedule SCADA RTU
– 6B
10.6.26 H-2-831428, Sh 4, Rev 2, 251W Substation Bank 1 Power Xfmr Schematic Diagram
11.0 Reinhausen LTC Service Contact
11.1 David Utley, Field Service Coordinator, Telephone (731) 562-4132, email:
[email protected]. Reinhausen Manufacturing, Inc. 2549 North Ninth
Avenue, Humbolt, TN, 38343, (731) 784-7681.