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:

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


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


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%


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


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


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)


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 %)


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


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


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.


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


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.


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

F-5

05

94

, Re

v 1

P

age

14 o

f 42

Ta

ble

3 –

Eq

uip

me

nt

Ra

tin

gs

Eq

uip

me

nt

De

scri

pti

on

R

ati

ng

/ S

ett

ing

A

mp

s (M

VA

) @

14

.4k

V

Tra

nsf

orm

er

Pri

ma

ry L

ine

6

36

AC

SR

Gro

sbe

ak

7

89

A

12

.6k

A

Tra

nsf

orm

er

Pri

ma

ry S

wit

ch

12

00

A V

ert

ica

l A

ir B

rea

k S

wit

ch

12

00

A

19

.2k

A

Tra

nsf

orm

er

Pri

ma

ry B

ush

ing

A

BB

8

00

A

12

.8k

A

Po

we

r T

ran

sfo

rme

r N

om

ina

l R

ati

ng

2

0/

26

/3

3 M

VA

8

02

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/1

04

2.4

A/

13

23

.1A

Su

mm

er

(Se

ct 4

.4 a

bo

ve

) 2

1.2

/2

7.6

/3

5 M

VA

8

50

A/

11

06

.6A

/1

40

3.3

A

Win

ter

(Se

ct 4

.4 a

bo

ve

) 2

5/

32

.5/

41

.2 M

VA

1

00

2.3

A/

13

03

A/

16

51

.9A

Po

we

r T

ran

sfo

rme

r L

TC

R

ein

ha

use

n R

MV

-II-

15

00

-15

1

50

0A

18

00

A (

IEE

E C

57

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1 (

20

12

)

com

pli

an

t d

esi

gn

all

ow

s fo

r

ma

xim

um

cu

rre

nt

of

12

0%

)

15

00

A (

37

.4 M

VA

)

18

00

A (

44

.9 M

VA

)

Tra

nsf

orm

er

Se

con

da

ry B

ush

ing

L

ap

p

20

00

A

20

00

A (

49

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Tra

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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

)


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


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


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


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


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


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


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


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


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


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


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


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.


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.


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


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


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


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


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.


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


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


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


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


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


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.


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


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.


200Area summer loads plus the assumed full load of line C8L14.


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


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.


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.


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


10.6.15 H-2-90101, Sh 1, Rev 8, 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.