ML20198B325

Engineering Evaluation Rept,Npp Cold Weather Problems & Protective Measures

ML20198B325
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Site:	Wolf Creek
Issue date:	12/31/1997
From:	Padovan L NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD)
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.

- AEODIE97 !

1 ENGINEERING EVALUATION REPORT NUCLEAR POWER PLANT COLD WEATHER PROBLEMS AND PROTECTIVE MEASURES -

s 3

DECEMBER '1997 t-Prepared by:

L. Mark Padovan 9801060269 971219

~

PDR ADOCK 05000482 8

PM Reactor Analysis Branch Office for Analysis and Evaluation

-of Operational Data

. U.S. Nuclear Regulatory Commission

, e. u

_ ]

Contents

- Abbreviation s............................................................. v Executive Su mm ary..,............................,....................... Vii i t introdu ction...... _..............'...........,......................... 1 1.1 Cold Weather Event Risk Significance...

............................... 3 2: Intake lce Events and Protectivo Measures................................. 4

2. f Introduction.................................s.....".........<.....

.4 2.2 Operating Experience............................................... 4

2. 3 Les sons Lea med.................................................. 8

-2.3.1 Intake Ice Problem Generic Communications..,..................... 8 2.3.2 - Design Approaches to Minimize Ice Formation at intake Structures........ 9 2.3.3 Operating Approaches to Minimize Ice Formation at intake Structures..... 9 2.3.4 Training Approaches to Minimize Ice Formation at Intake Structures...... 10 3 Process Line Cold Weather Events and Protective Measures.................. 11 3.1 I ntrod u ctien...............................,....................... 1 1 3.2 Operating Experience............................................... 11 3.2.1 Service Water Strainer Backwash Line Freezing..................... 11 3.2.2 Safety injection Pump Recirculation Line Freezing............,..... 12 3.2.3 Potential Standby Liquid Control Sodium Pentaborate Precipitation....... 12 3.2.4 Emergency Feedwater Recirculation Line Freezing..................,,12 3.2.5 Heating, Ventilation, and Air Conditioning System Fvents............. 13 3.3 Lessons Leamed........

.........................................15 3.3.1 Cold Weather Process Line Generic Communications................. 15 3.3.2 Process System Freeze Protective Measures,,................,,... 15 4 Instrument Line Cold Weather Events and Protective Measures............... 17 4.1 I ntrod uction....................................................... 17 4.2 O perating bperience.............................................. 17 4.2.,1 Refueling Water Storage rank Level Transmitter Line Freezing......... 17 4.2.2 Condensate Storage Tank Level Transmitte: Jne Freezing............,18 4.2.3 Auxiliary Boiler Control Line Freezing.............................. 19 4.2.4 Turtnne First Stage impulse Pressure Instrumentation Line Freezing..... 19 4.2.5 Traveling Water Screen System Failure Due to Frozen Pressure Switches. 20

4. 3 !.es son s Le a med................................................... 20 4.3.1 -Instrument Line Freezing Generic Communications and Protective Measures..................................... 20 4.3.2 ~ Instrument Line Freezing Findings................................ 21 iii

5 Emergency Diesel Generator Cold Weather Ever'ts and P otective Measures... 22 5.1 Introduction............................

. 22 5.2 Operating Experience........................................ 22 5.3 Lessoras Learned....

.. 23 5.3.1 Generic Communications on Emergency Diesel Generator Failures From Cold Fuel Oil...

. 23 5.3.2 Emergency Diesel Generator Room Low Temperature Findings........ 24 6 Essential Chiller Cold Weather Events and Protective Measures.............,. 25 6.1 Introduction.........

. 25 6.2 Operating Experience.

. 26 6.3 lessor.3 Learned..

. 26 s

6.3.1 Essential Chiller Generic Communications...

. 26 6.3.2 Essential Chiller Problem Findings

. 26 7 Electrical Cold Weather Events and Protective Measures

.27 1

7.1 I n t rod u ctio n.............................

. 27 7.2 Operating Experience........

.27 7.3 Lessons Learned.......

..... 28 7.3.1 Electrical Problems Generic Communication....

... 28 7.3.2 Electrical Event Findings 28 8 Conclusions..

.29 8.1 Intake Ice Pioblems...

.. 29 8.2 Process Line Cold W0ather Problems................................ 29 8.3 Instrument Line Cold Weather Problems.........

. 29 8.4 Emergency Diesel G 3nerator Cold Weather Problems........

. 30 8.5 Essential Chiller CoH Weather Problems.

.30 8.6 Electrical Cold Wea'her Problems.

. 30 9 References

. 31 Figures E

Figure 1-1 Cold Weather Operating Experience by Year

.2 Figure 1-2 Generic Communications on Cold Weatt. 4r Problems................

2 iv

l

.o-Abbreviations.

j 1

AEOD Analysis and Evaluation of Operational Data (Office for) -

CRREL=-

Cold Regions Research and Engineering Laboratory (U.S. Army Corps of -

' Engineers)

CST-

. condensate storage tank.

DGSW-diesel generator service water EDG

,, emergency diesel generator--

ErW emergency feedwater

.ESF.

engineered safety feature.

ESW essential service water / emergency service water HVAC-heating, ventilation, and air conditioning IN

- information notice LER licensee event report LCO limiting condition for operation LOOP:

loss of offsite power NRC U.S. Nuclear Regulatory Commission RHR-residual heat removal RWST refueling water storage tank QA quality assurance SI.

. safety injection SW service water TS Technical Specification

~WG water gauge J

4 h

V t

Executive Summary A significant event on January 30,1996, at the Wolf Creek Generating Station involved icing of cooling water intake trash racks and traveling screens, subsequent loss of an essential service i

water system train, and other plant co,nplications. This led the U.S. Nuclear Regulatory Commission's Office for Analysis and Evaluation of Operational Data to evaluate the extent of cold weather related problems at other nuclear power plants over the past 6 years.

l A search of operating experience occurring at nuclear power plants from 1991 through April 1997 involving ice, freezing, and low ambient temperature problems was completed. The events discussed include both actual failures due to cold weather and somr/ design or.

configuration vulnerabilities which could lead to failures under postulated conditions. This report describes 37 such events at 23 different sites. This report also identifies previously issued cold weather related NRC information notices and a series of reports by an industry group on cold weather operating experience at nuclear power plants.

Recent operating experience suggests that despite NRC and industry communications on this subject, some licensees have not effectively protected components whose failure could degrade safety systems. Extremely cold weathe Tditions continued to affect intake structures, process lines, instrument lines, emergc;, diesel generator oil and grease viscosities, essential chillers, electrical systems, heating, ventilation and air conditioning systems. Lack of design oversight, incomplete review of operating experience, and insufficient attention to cold weather preparations resulted in most of the events important approaches and measures licensees have used to protect against cold weather operational events appear in the Lessons Leamed Sections of this report.

vii

L 1

Introduction

)

A significant event on January 30,1996, at the Wolf Creek Generating Station involved icing of-cooling water intake trash racks and traveling screens, subsequent loss of an essential service j

water l',SW) system train, and other plant complications. This led the U.S. Nuclear Regulatory Commission's Office for Analysis and Evaluation of Operational Data to evaluate the extent of cold weather related problems at other nuclear power plants over the past 6 years. A search of j

- operating experience occurring at nuclear power plants from 1991 through April 1997 involving -

1 Ice, freezing, and low ambient temperature problems was completed. The events discussed include both actue! failures due to cold weathe' and some design or configuration vulnerabilities r

which could lead to failures under postulated conditions. This report describes 37 such events at 23 different sites. This report also identifies previously issued cold weather related NRC information notices and a series of reports by an industry group on cold weather operating experience at nuclear power plants. Analysis of these events revealed that extremely cold heather continues to cause intake ice problems, process line freezing, instrument line freezing, emergency diesel generator (EDG) oil viscosity problems, essentist chiller problems, and electrical problems. This evaluation includes operating experience from licenae event reports

(.ERs) and NRC inspection reports. Most importantly, this report compiles lessons leamed from a variety of sources conceming approaches and measures that have been used to protect against cold weather operational events through

+ design, operating, and training approaches to minimize intake cooling water ice plant process, instrumentation, and sampling line cold weather protection techniques e

. cold weather related design, operation, and preparation associated with EDGs, electrical power and logic conduits, switchyard breaker cabinet gaskets and seals, and switchyard breaker U-bend heaters and fuses

. research by U.S. Army Corps of Engineers Cold Regions Research and Engineering Laboratory (CRREL) located in Hanover, New Hampshire.

Figure 1-1 shows that events similar to those described in NRC and industry documents continued to increase from 1991 to 1996. Figure 1-2 shows that the industry prepared eight reports regarding cold weather problems at nuclear power plants since 1982, while the NRC issued four information notices (ins), one IN supplement, a NUREG, and a t:ulletin on this subject since 1979. Summaries of the following NRC generic communications appear as various types of events are discussed in this report:

. IN 96 36, " Degradation of Cooling Water Systems Due to Icing," June 12,1996, i IN 94-82,"Concems Regarding Essential Chiller Reliability During Periods of Low Cooling Water Temperature," December 5,1994.

. IN 94-19 " Emergency Diesel Generator Vulnerability to Failure from Cold Fuel Oil,"

- March 16,1994;

. IN 9129, Supplement 3 " Deficiencies identified During Electrical Distribution System Functional Inspections," November 22,1995.

. IN 88-76,"Recent Discovery of a Phenomenon Not Previously Considered in the Design of Secondary Containment Pressure Control," September 19,1988.

. - Bulletin No. 79-24 " Frozen Lines," September 27,1979.

. NUREG/CR-0548," Ice Blockage of Water intakes," March 1979.

1

i

)

Figure 1-1 Cold Weather Oporating Experience by Year i

\\

Number of Events 12 10 8

6 4' k h;9:

lY a

t Sk 2

4M9M1 ha4($

/

ad+k 0

91 92 93 94 95 96 97 Year IE Electrical C Essential Ch :lers E EDG Oil Viscosity Olnstrument Lines E Process Lines Eintake Ice Data la current through October 1997 j.

Figure 1-2 Generic Communications on Cold Weather Problems Number of Reports 3

l li N

l l

l 1

a'.a

-,g 7

g 9,

4

^

0

~'

L i'

79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 Year E NRC Cindustry Data is current through October 1997 -

l 2

J Fermi Unit 2 -

Diesel generator service water (DGSW) pump C failed to develop normal discharge pressure

and flow during a surveillance test on February 5,1996, while the plant was at 96 percent power (Ref. 4). As a result the licensee declared the EDG associated _with the DGSW pump

inoperable.- After several attempted starts and an air purge of the pump column over a 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> period, the DGSW pump started and operated normally after 5 seconds of erratic operation.

The next day the licensee conclu'ded that the most probable cause for this pump failure was ice formation on one or both bearing supports in the pump column that was exposed to freezing weather. The initial design of the residual heat removal (RHR) complex had not considered that the temperature cou!d drop below freezing in the airspace below the pump room floor and freeze any water leaking past the check valves into the pump columns. Low temperatures and -

a strong wind into the reservoir contributed to the freezing conditions.

The licensee tested the other pumps in the RHR complex to determine if they were also.

affected by ice.- All tested satisfactorily except one. DGSW pump B was started and was

- allowed to operate erratica'ly until normal operating conditions developed after approximately 90 seconds. Although the erratic performance of the pump would not have adversely affected the associated EDG, the licensce acknowledged that recognition of the potential for common-cause failure of deep draft pumps because of ice formation and pump _ testing should have occurred earlier.

The licensee instituted a procedure to monitor the temperatures in the air space below the RHR complex pump rooms whenever outside temperatures fell below 2.2 *C (36 'F). Operators were to run all service water (SW) pumps in the affected division if the. temperature in a division fell below 2.2 'C (36 'F) for three consecutive shifts. These interim measures were to remain in effect while the licensee evaluated permanent design changes to prevent freezing of the -

safety-related SW pumps in the RHR complex.

Wolf Creek IN 96-36,

• Degradation of Cooling Water Systems Due to Icing" (Ref. 5), and Wolf Creek LERs96-001 (Ref. 6) and 96-002 (Ref. 7) describe the effects of the Wolf Creek intake trash rack and traveling screen icing event that occurred at 0337 hours0.0039 days <br />0.0936 hours <br />5.57209e-4 weeks <br />1.282285e-4 months <br /> on January 30,1996. Water from the spray wash system froze on the circulating water system traveling screens causing them to become Inoperable. - Ice buildup'on the :ntake trash rakes c nd traveling screens caused abnormally low water levels in bays 1 and 3. Frazil ice completely blocked the ESW trash -

racks, causing the train B suction bay level to be below normal and to slowly decrease.1The shift supervisor then directed a manual reactor / turbine trip. Operators also tripped the Train A ESW pump, and declared it inoperable because of low discharge pressure and high strainer differential pressure. Plant personnel sparged the ESW bay with air to clear the trash rake ice blockage.

The ESW system was designed to have warming flow injected in front of its trash racks to increase bulk water temperature and prevent the formation of frazil ice.~ The licensee originally

- concluded that architect-engineer calculational errors and the as-built system configuration resulted.in insufficient ESW warming flow to prevent frazil ice from forming on the Train A trash L

L 5

racks. Wolf Creek NRC Special inspection Team Report 96-003 fef. 8) and the March 15

(

1996, Wolf Creek luter to the NRC (Ref. 9) indicated that desigm6rs made the following warming line temperature and flow design errors:

• The maximum available warming line flow rate with proper valva lineup was 157.7 liters per second (2500 gpm), while orig nal design calculations showed that 252.3 liters per second (4000 gpm) of 1.6 *C (35 'F) warming water was necessary to keep frazil ice from forming.

Subsequent calculatiens indicated that the required warming line flow would be 315.4 liters per second (5000 gpm) given the actual water temperature during the event of 0 *C (32 'F).

. Piping diameters and elevations of the warming line and the ESW-to-ultimate-heat-sink return line were such that portions of these lines operated with only partial pipe flows, maleng

'he calculation methods nonconservative.

The Wolf Creek licenseo paid a $300,000 fine to the NRC.

Later, on August 5,1997, the licensee issued Revision 1 to LER 96-001, after determining that two of three air release valves were plugged (plugging mechanism not documented) on the circulating water warming line during the event caused the warming flow to be near zero. The effect of the resultant air binding was demonstrated during a 5-day test in January 1997 with 2.8 *C (37 'F) take water, when warming line flow was reduced from 1388 liters per second (22,000 gpm) to approximately 347 liters per second (5,500 gpm). Based on U.S. Corps of Engineers guidance that "a 0.2 'F temperature differential between the lake and the pump suctions was sufficient to prevent frazilice build up," the licensee concluded that less than 347 liters per second (5,500 gpm) warming flow had to have been present during the event. The licensee explained that as lake water temperature decreased to 0 'C (32 'F) during the event it contained more air in solution and exacerbated the warming line air binding. Although air removal by the water box venting system should have significantly reduced the potential for air binding, approximately one half of the water box air release valves were isolated during the January 1996 event. This information was not in IN 96-36 or the Wolf Creek NRC Special Inspection Team Report 96 03.

Based on further review of the event, the licensee initiated additional corrective actions. The licensee revised procedures to delete the requirement to operate traveling screens continuously in slow manual mode during cold weather or unusual icing conditions and allow the sc eens to be operated in automatic mode in which the screens remained stationary without sprays until the system is started either by timer or hign differentiallevel. The traveling screens were enclosed in a heated environment. The three sir release valves on the warming line were replaced and incorporated into the preventative maintenance program Procedures were revised to ensure manual venting of the circulating water warming line when the inlet temperature falls below 1.1 *C (34 'F), and verification of the presence of circulating water warming flow and the passing of air from the air release valves when the warming line valve is opened in fall 1997. A caution was added to the c!rculating water system operating procedure stating that " isolating and draining a pass on the main condenser may result in a rapid loss of circulating water warming flow due to air inleakage past the reium isolation valves." A precaution wan added to the plant winterization procedure stating that " isolating a significant amount of the water box air release valves may increase the probability and/or speed of warming line air binding." A step v as also added to verify that the water box air release valves were not isolated.

6

1.1 Cold Wrath:r Evant Risk Significance One of the 37 cold weather events occurring between 1991 and 1997 was important from a risk perspective; the January 30,1996, Wolf Creek reactor trip and subsequent loss of ESW train A.

. The risk significance of cold weather effects on nuclear power plants stems from the potential to create common-cause failure mechanisms in a variety of trains and systems simultaneously.

AEOD's results of an Accident Sequence Precursor Program analysis of the Wolf Creek event indicated that the estimated conditional core damage probability was 2,1 x 10d To put_ this event's risk significance into perspective, 581 precursor events with conditional core damage probabilities a 1,0 x 104 occurred between 1969 and 1995. Of these events,192 had j

conditional core damage probabilities a 1.0 x 10d. The safety signifivers of the remaining cold weather related events described in this report fell below the threshoic ice analysis by the Accident Sequence Precursor Program.

Y a

5 f

f' f

f f

3 l

l

I 2

Intak9 Ice Cvents and Protectiv] Me:sures

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2.1 Introduction Ice can block both surface and submerged nuclear power plant intakes. NUREG/CR-0548, " Ice Blockage of Water Intakes" (Ref.1), published in 1979, explains how sheet ice and frazil ice

- form, what ice sizes and thicknesses occur, how mobile the ice is, and how it adheres S surfaces. Water velocity or turbulence determines whether sheet ice or frazilice forry Surface cunents greater than about 0.6 m/sec (2 ft/sec) prevent sheet ice from forming but allow frazil ice to develop. Frazil ice is composed of up to 5 mm (0.2 inch), round or pointed ice crystals that are formed in supercooled water and prevented from coagulating into sheet Ice by water turbulence. However, intake structures, bars, or tmsh racks provide a place for frazilice to adhere. Small frazilice particles readily adhere to any object or other frazilice they ccntact.

TurbuteQce can :arry frazil ice below the surface, where it can collect on and eventually block intake bars and trash racks because of their relatively small openings. Spraying intake trave screens with near freezing wash water can also cause ice to build up and immobilize the screens.

The NUREG/CR noted that at Lake Ontario municipal water supply intakes, operators reported that severe frazil ice formed whenever water temperature was below 1 to 2 *C (33.8 'F to 35.6 *F) and air temperature rapidly decreased to -7 to -15 *C (19.4 'F to 5 *F). Experience at the Cardinal, Ontario, Canada, industrial water supply intake on the St. Lawrence Seaway showed that a large air temperature change during a short period formed more frazilice than when mean air temperature did not vary 3 *C (5.4 *F) in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> during prolonged periods of very cold weather. Operators also reported the formation of frazilice when the sky was clear and air temperature and wind direction changed, with the wind blowing against the current.

CRREL has researched cold weather problems with private industry, and been involved in design solutions for in ake icing problems, such as frazilice detectcrs and edge-heated trash rakes. CRREL recently compared the advantages and disadvantages of various instruments used in monitoring river ice temperature, thickness, and movement in CRREL Technical Digest No. 97 2, " River Ice Data instrumentation" (Ref. 2) that was issued in June 1997. CRREL Cold Regions Technical Digest No. 91-1, "Frazil ice Blockage of Intake Trash Racks" (Ref. 3), gives additional information on frazil ice formation and lessons leamed, as described in Sections 2.3.2,2.3.3. and 2.3.4 of this report.

2.2 Operating Experience The formation of frazil or other ice in plant cooling water intakes can degrade multiple cooling water systems, including the ultimate heat sink. Ice formed in a pump column exposed to freezing weather at Fermi Unit 2 in 1996. Frazil ice formed in the cooling water intakes at Wolf Creek in early 1996, at Ginna la early 1994, and at FitzPatrick in early 1993.

1 4

Robert E. Ginna

/

On January 20,1994, the licensee for Ginna informed the NP,C (R9f.10) of a reactor power level reduction from 97 percent to 50 percent This was initiated at 0411 hours0.00476 days <br />0.114 hours <br />6.795635e-4 weeks <br />1.563855e-4 months <br /> because of a low intake water level and the need to take a circulating water pump out of service as a compensatory measure. Frazilice from Lake Ontario had built up and caused flow blockage that resulted in the intake structure water level being 2.44 to 2.74 m (8 to 9 ft.) below its normal level. The ESW and fire water pumps take their suction from the intake structure. If the water level had decreased another foot, these systems would have been inoperable and the site would have entered a site area emergency condition in accordance with their emergency procedures.

James A. FitzPatrick Three intake icing events described below occurred at the James A. FitzPatrick Nuclear Power Plant during February and March of 1993 (Ref.11).

February 25,1993 The first event occurred when the ambient air temperature wa ;-11.6 *C (11 'F) and the lake temperature was 0.5 *C (33 *F)(Ref.12)(Ref,13). There had been a steady wind throughout the day on Februa'y 24. Screenwell water was being tempered by retuming circulating water discharge to the intake where it mixed with lake water. Eighty of eighty-eight intake bar rack heaters were operating. Despite these precautions, frazil or slush ice built up around the bar racks, partially biocking the entrance of the intake tunnel 3.65 m (12 ft) below the surface of Lake Ontario. Th4 occurred in less than an hour and significantly restricted flow into the screenwell. The water level in the screenhouse forebay was estiinated to be about 3 m (10 ft) below normal. Two fire pumps started automatically on low fire header pressure (after the fire header jockey pump lost suction when the water level decreased below its suction bell). The pumps operated without adequate suction head for 12 minutes. Condenser inlet temperature rose from its normal 2.7 *C (37 *F) to 14.4 *C (58 'F). Despite a power level reduction to 70 percent and shutdown of one circulating water pump, a manual reactor scram was necessary at 0140 hours0.00162 days <br />0.0389 hours <br />2.314815e-4 weeks <br />5.327e-5 months <br /> on February 25,1993. Three minutes later, the condenser inlet temperature peaked at approximately 19.4 *C (67 *F). After a second circulating water pump was secured, the screenwell forsbay water level increased to normal over a period of several hours.

The February 1993 event was "significant because had the operators not recognized the low water level problem and not secured the circulating water pumps, the water level in the screenwell could have dropped below the minimum required water level for the safety-related ESW and residual heat removal service water pumps."

As corrective actions, the licensee proposed:

. several comput3r alarms to identify any 2.8 *C (5 *F) change in circulating water condenser inlet temperature over 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />

. an abnormal protadure for low screenwelllevel or circulating water temperature change alarm a surveillance establishing requirements for monitoring intake water level and temperature to assess environmental conditions and determine the probability for the formation of frazilice 7

• wat:r lev,:1 indicators on the screenwellint:ke w ll upstream of th] trash racks in the emergency pump bay to provide operators with a reference to actual water level Additional subsequent events described in Reference 11 include:

March 13,1993 A second event occurred when the plant was in cold shutdown, during extreme storm conditions with gale force winds and 4.57 m (15 ft) waves on Lake Ontario. Ice clockage occurred at the traveling screens and trash rakes when ice was pulled into the intake structure.

High traveling screen differential pressure alerted plant personnel to the ice blockage. The licensee broke up the ice with a trash rake.

March 22,1993 s

The tfiird event involved ice blockage at the traveling screens while the plant was at 10 percent

~

power during a startup. Although tempering flow was in operation, floating ice was pulled into the intake structure. High traveling screen differential pressure also alerte plant personnel to d

ice blockage in this event. The operators secured one circulating water pump to reduce the amount of ice collecting at the intake structJTe.

2.3 Lessons Learned Various information sources describing design, operating, and training approachec to minimize the build up of ice and frazil ice in intake cooling water are available to licensees. The following is a summary of lessons leamed from generic communications and technical reports prepared by CRREL.

2.3.1 Intake Ice Problem Generic Ccmmunications Information Notice 96-36. " Degradation of Cooling Water Svetems Due to leirig."

June 12.19%

IN 9 3-36 describes events at Fermi (February 5,1996), Wolf Creek (January 30,1996), and FitzPatrick (February 25,1993) which are described in more detail in Section 2.2. The IN also discussed how frazil ice is formed, indicated that frazil ice can potentially block intake water flow, and referenced NUREG/CR-0548," Ice Blockage of Water intakes."

8

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NUREG/CR-0548. " Ice Blockaoe of Water intakes " March 1979

~

In NUREG/CR-0548, the U.S. Army Corps of Engineers discussed how surface sheet ice and frazil ice form, what ice sizes and thicknesses occur < how mobile the ice is, and how the ice adheres to surfaces. The report also gives some design approaches to minimize and prevent ice from blocking intake structures, as noted below, 2.3.2 Design Approaches to Minimize Ice Formation at intake Structures CRREL described lessons learned from cold weather operating experience in Technical Digest No. 91 1 "Frazil Ice Blockage of Intake Trash Rakes' (Ref. 3) and the NRC identified lessons teamed from the Wolf Creek event in Special Inspection Team Report 96-03 (Ref. 8). These suggest the following design cptions or practices can minimize potential ice blockage of intake structures (Ref. 3, except as indicated):

Redirect waste beat to the intake oy direc4g well-mixed warm ' !ater (through spargers/

diffusers)immediately upstream of the intake trash racks.

. Verify that plant warming line tempera'ure and flow design assumptions are correct (Ref. 8).

Use directly heated trash rack bars (hollow bars with steam or hot water flowing through them or electrically heated bars) to Iceep the racks above 1.0 to 1.5 *C (33.8 to 34.7 *F) during frazil ice conditions, Fully or partially remove trash racks in the winter after carefully evaluating thn amount of debris at the intake and whether frazilice might accumulate on the next downstream structure it contacts.

Use trash rack coatings to reduce ice adhesion strength and make removing ice easier (something that will not prevent frazil ice buildup).

Use maximum trash rack bar spacing, the thinnest bars possible, and the minimum number of supports consistent with strength and vibration considerations.

. Provide proper access (enclosed, heated, and well-lighted enclosure) for manual trash rack raking and means to dispose of collected ice.

2.3.3 Operating Approaches to Minimize Ice Formation at intake Structures The following is a compilation of lessons teamed from cold weather operating experience described in CRREL Technical Digest No. 91-1 "Frazil ice J1ockage af intake Trash Rakes" (Ref. 3) and the Wolf Creek event from NRC Special Inspection Team Report 96-03 (Ref. 8).

These suggest the following operating options can minimize the potential for ice blockage of intake structures (Ref. 3, except as indicated).

. Create and maintain a stable ice cover as soon as possible to insulate the water surface and prevent frazilice production.

Manually or mechanically rake ice from intake trash racks.

. Verify that procedures require raking trash racks before they become totally blocked.

9

Proactively perform carly and frequent backwashing to avoid ice build up on the traveling e

screens when (1) operators use screen wash water sprays to backwash screens, (2) ambient temperatures are low, and (3) the screens operate at slow speed allowing long exposures to low temperature air (Ref. 8)-

Collect data at intakes to predict ice formation conditions, for example:

Use continuous visual or instrument readouts to monitor the degree of ice blockage of intake trash racks and traveling screens (such as differential pressure, or differential water level across the trash rack).

Obtain intake bay water temperature measurements with accuracies of i 0.11 *C

~ (10.2 *F) or better.

Keep detailed logs of water temperature, weather condition, and ice condition and make maps showing ice locations during the winter to determine site-specific conditions in which frazilice occurs.

- Uss a light hand-held rake to detect frazilice on the upstream side of trash racks.

Verify that contingency plans keep trash racks and traveling screens free of ice (by ice detection chains and air lances)(Ref. 8).

. Assure that operating instructions specify mandatory plant shutdown steps and identify which steps operators could delay or perform concurrently for a rapid plant woldown (Ref. 8).

2.3.4 Training Approaches to Minimize Ice Formation at Intake Structures The following compilation of lessons teamed from cold weather operating experience described in CRREL Technical Digest No. 91 1 "Frazil ice Blockage of Intake Trash Rakes" (Ref. 3) and the Wolf Creek event from NRC SpecialInspection Team Report 96-03 (Ref. 8) suggest training options that can minimize the potential for ice blocking of intake structures (Ref. 3),

except as indicated).

Instruct operators on site specific conditions in which ice occurs.

Include icing event scenarios during operator qualification or requalification training (Ref. 8).

Enhance circulatirig water /SW training where necessary.

10

3 Process Line Cold Weather Events and Protective Measu d j

3.1 Introduction Cold weather events have included problems with :ommon SW backwash lines, safety injection (SI) pump recirculation lines, standby liquid control system piping, emergency feedwater (EFW) recirculation lines, and heating, ventilation, and air conditioning (HVAC) systems.

3.2 Operating Experience 3.2.1 Service Water Strainer Backwash Line Freezing Millstone Unit 2

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On January 8,1996, with the plant at 100 percent power, the licensee discovered an ice plug in a common SW backwash discharge line that would have prevented automatic backwash of the SW strainers (Ref 14). The safety related SW system is serviced by nonsafety-related backwash piping. An ice plug formed in a horizontal strainer backwash drain line that ran through the intake wallin a trough towards a fish basket. This 0.61 m (2 ft) section of pipe had been welded onto the end of the original vertical discharge leg in the early 1980s in a modification that had not undergono a formal engineering review. Minor leakage through the strainer backwash isolation valves coupled with an unusually long period of subfreezing temperatures created the conditions needed to foa m this ice plug. This was the first ice plug in the 15 years of service of the pipe. Maintenance personnel removed the ice plug and restored the strainer backwash capability. Operators backwashed the str'iners every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to ensure another ice plug would not form otil the horizontal pipe section was eliminated through a modification. Nonetheless, the utility later found that the open end of the line was still susceptible to ice buildup.

After further analysis, the licensee determined that the SW strainer backwash system, which served both SW trains, was susceptible to a common-mode failure if the intake structure nonvital heating system failed to operate. This finding was subsequently reported on February 29,1996 (Ref.15). The original design did not consider the potential for ice blockage in backwash system piping. The licensee changed an operating procedure to require monitoring of the intake structure temperature when temperature falls below 4.4 *C (40 *F),

and proposed using prtable space heaters or manually operating the strainers to prevent freezing. The licensee also proposed replacing the common line with three independent backwash lines, locating the discharge points to minimize the effect of outdoor weather conditions, and protecting differential pressure instrumentation from freezing.

In addition, on February 5,1996, tha licensee determined that both trains of the SW system should have been declared inoperable in the January 8,1996, event. This finding was subsequently reported on March 6,1996 (Ref.16). A declaration of inoperability would have required entering Technical Specification (TS) Limiting Condition for Operation (LCO) 3.0.3, i

which required a plant shutdown. The operators had failed to recognize that the ice plug in the l

common SW strainer backwash line that made the backwash functions of the SW strainers I

inoperable also made both SW system trains inoperable. The root causes of this were determined to be (1) a management policy that was ambigur 3 with regard to nonquality l

assurance (OA) support systems and their impact on ope % y of safety systems, (2) failure to 11

consult appropriate r: sources before making an oper:bility decision, and (3) a nonconservative decision by the shift manager.

3.2.2 Safety injection Pump Recirculation Line Freezing Zion Unit 1 On March 8,1996, a section of a common Si pump recirculation line froze while the plant was in cold shutdown, rendering both Sl pumps inoperable (Ref.17). This portion of the recirculation line ran through a purge supply inlet plenum duct (exposed to outside air temperatures) prior to entering the refueling water storage tank (RWST). The utility found that the portion of the line inside the purge duct could freeze when purging with below-freezing outside conditions. An undetected temperature gradient could exist in the piping due to the location of the temperature sensor tnat controls the purge supply heating coils. The licensee consMered recirculation line freezing possible but unlikely without the purge operation in 3

addition to temporary administrative controls and recirculation line heat tracing, the licensee proposed rerouting the recirculation line outside the purge duct to correct the problem. NRC Culletin 79-24 " Frozen Lines" of September 27,1979, and an industry colo weather report had previously identified Si recirculation line freezing.

3.2.3 Potential Standby Liquid Control Sodium Pentaborate Precipitation Cooper On October 9,1994, the licensee determined the they were not monitoring the standby liquid control system suction piping temperature in accoidance with TS requirements (Ref.18). The TS requirements require that the piping is warm enough to maintain the sodium pentaborate in solution. The pump head was not property heat-traced and insulated, such tt_1 during the worst case wintertim3 room temperatures of 10 *C (50 *F), some sodium pentaborate could have precipitated out into the bottom of the pump head. A heat tracing thermostat was found improperty installed on the outside of the insulation such that it did not monitor actual pipe temperature. In addition, the heat tracing on the discharge side of the pump was not working becauae of an open circuit.

Tne root cause was attributed to a QA deficiency in not identifying the requirement to monitor the suction piping to satisfy TS or the need to property heat trace and insulate the pump hesd and suction piping. Corrective actions included improvements to the heat tracing and procedure changes to require monitoring in the TS surveillance program.

3.2.4 Emergency Feedwater Recirculation Line Freezing Seabrook On September 9,1993, the licensee determined (Ref.19) that portions of the common recirculation line from the EFW pump to the condensate stormge tank (CST) did not have dual heat tracing as stated in the Updated Final Safety Analysis Report and theli response to NRC Bulletin 79-24. Also. the control room alarm on the single heat tracing circuit had been removed. Portions of the recirculation line in the CST valve room, or embedded in concrete, could potentially freeze if the heat tracing circuit were to fait during design basis cold weather conditions. Blocked recirculation flow could result in inadequate pump flow. This might 12

- damage both the motor driven and turbine driven EFW pumps, if op$rators were required to throttle EFW flow during a cooldown during limiting cold weather conditions. The licensee attributed the failure to provide redundant heet tr.scing circuits to a design omission in the original plant design, There was no definitive design basis document for the plant heat tracing s/ stems. As a corrective action, the licensee proposed reviewing all heat tracing circuits to de termine the nuclear safety classification of the associated systems. The EFW heat tracing hhs been reassigned to alarm on the main control board. Additional heat tracing alarm r9sponse procedures were proposed to ensere safety related lines are protected from design oasis cold weather conditions.

3.2.5 Heating, Ventilation, and Air Conditioning System Events Maine Yankee On February 18,1997, a licensee engineering analysis revealed that a loss of offsite power

- (LOOP) or a ventilation exhaust fan malfunction could create freezing conditions in the circulating water pump houss (Ref. 20). Stagnant SW pump piping, and smaller lines providing pump bearing and gland cooiing, could potentially freeze assum!ng a low outside air temporature. This could occur by two means. A LOOP would cause pump house heating to fail, and the building ventilation dampers would fail open. In the event of a pump house exhaust fan malfunction where a fan inadvertently starts on fast speed, discharge air flow would increase and potentially create freezing conditions in the pump house. The circulating water pump house design basis did not consider the potential for freezing temperatres coincident with a LOOP and/or fan malfunction. Short term licensee corrective actions included installing temperature indicators and high and low air temperature alarms 6 the pump house, Harris Nuclear Plant Unit i On February 7,1997, the licensee determined (Ref. 21) that main feedwater isolation valve area %mperatures were below the minimum allowable valve actuator temperature due to improper HVAC system function. This resulted in potentially inoperable main feedwater isolation valves. The isolation valves had to close in s 10 seconds to isolate feedwater in the event of a main steam line break or spurious opening of a feedwater regulating valve. Vendor documentation specified that a minimum valve actuator operating temperature of 15.5 *C (60 'F) was necessary to ensure that the valves wtuld stroke in the required 10-second period.

Valve actuator hydraulic oil might be too viscous to allow a 10-second stroke time if the actuator temperature fell below 15.5 *C (60 *F).

Steam tunnel HVAC supply fans take suction from the outside atmosphere and exhaust directly to the main feedwater isolations valve area. Fan design includes an automatic -1.1 *C (30 *F) low ambient temperature shutoff. However, plant process computer data showed that the fans continued to run with outside temperatures well below the low ambient temperature shutofi setpoint. The licensee further determined that the nialn feedwater isolation valve area temperatures would still have been below the minimum actuator temperatiire even if the fans hed shut off at -1.1 *C (30 *F). Immediate corrective actions were to have operations staff locally monitor steam tunnel temperatures once per shift when outside ambient temperature was less than 18.3 *C (65 *F) Plant staff would then place temporary heaters in the steam tennel as necessary. The licensee indicated that it would further investigate and troubleshoot the HVAC system, and take required corrective actions to ensure propcr HVAC system operatinn.

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LaSalle County Station Units 1 and 2 On February 3,1997, the licensee determined that snow ingestion into the main control room ventilation system and the auxiliary electric equipment room ventilation system could cause a common mode failure of both trains of both ventilation systems (Ref. 22). These systems are engineered safety features (ESP) designed to maintain habitable room environments during normal and abnorma! conditions. The licensee found that the ventilation systems could draw snow into the inlet plenums during heavy snow storms. The snow could then accumulate on the air-cooled condensing coilinlet filters and cause high differential pressure. In response to this, operators had opened condensing unit access panel doors to allow warmer building air into the condensing units. This reduced the quantity of incoming snow and melted snow on the inteke filters. However, the licensee determined that operating these systems with opers access panel doors for extended periods was not an analyzed configuration, was not addressed in any site procedure, and constituted operating outside the plant design basis. Furtherniore, the licensee concluded that operating with the condenser plenum access panel doors open could have resulted in lower than normal temperatures in the adjoining Auxiliary and Turbine Buildings. Lower than normal temperatures in these buildings could have created freezing problems affecting equipment operability.

Maine Yankee On January 10,1906, plant operators declared the low pressure Si pumps and the containment spray pumps inoperable because of inadequate pump cubicle ventilation flow rates (Ref. 23).

Ice buildup blocked the spray building ventilation suction flow path. An overhead heating coil leaked water onto the spray building air inlet filter, freezing the filter and partially blocking ventilation flow.

Duane Amold On February 10,1994, following a surveillance test performed in -27.2 *C (-17 'F) ambient air conditions, a (hot water) heating coil for the B control building standby filter unit froze, ruptured, and released hot water and steam into the downstream high efficiency particulate sir filter and charcoal adsorber, rendering it inoperable (Ref. 24). The heating coil froze because cold air continued to flow past the coils while the licensee was troubleshooting electric heater trips which occurred during the surveillance test. When the licensee subsequently shutdown the standby filter unit, the cold air flow stopped. Fifteen minutes later the heating coil thawed, relesoing the hot water an.1 steam through the rupture. In its evaluation of past operability, the licensee determined that there was a potential common-mode failure mechanism. Specifically, with the existing electric heater trip setpoints, the nonsafety-related hot water heating coil in each standby filter unit could also have ruptured during a simultaneous design basis accident and LOOP if the air inlet temperature was less than -9.4 *C (15 *F).

Immediate corrective actions included removing the ruptured hot water coil and capping off its connections, replacing the B unit high-efficiency particulate air filters and charcoal, raising the temperature setpoints for the electric heater sheath and the operating thermostat on both filter units, and conducting operational tests.

Palisades On January 21,1994, during a surveillance test with the plant at 100 percent power, the licensee declared both control room emergency HVAC trains inoperable when they were unable 14

to maintain the required 3.2 mm (0.125 in) water gauge (WG) pressd The plant entered TS LCO 3.0.3 at 1017 hours0.0118 days <br />0.283 hours <br />0.00168 weeks <br />3.869685e-4 months <br /> (Ref. 25). Air at 472 liters per second (1000 cubic ft per min.) enters a 35.4 cm (14 in) diameter control room emergency fresh air makeup inlet pipe on the service building roof. At the time of the test, winds were 581 cm per second (13 mph), which caused the plume from the cooling towers fa envelop the plant site. The outside temperature varied between -15 and 12.2 *C (5 and 10 *F) and it was snowing, causing snow to accumulate e.ad ice to form on the control room e'nergency HVAC fresh air intake bird screen. The snow and ice degraded system performance, such that the lowest pressure in the control room was 1.8 mm (0.07 in) WG. As corrective action, the licensee proposed modifying the surveillance procedure to record control rcom pressure hourly, instead of taking readings once every 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. The licensee also proposed modifying the alarm response procedure to instruct operators to inspect the intake for blockage if control room pressure was low.

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3.3 Lessons Learned 3.3.1 Cold Weather Process Line Generic Communications IE Bulletin No. 79 24 " Frozen Lines," September 27,1979 This bulletin described an event at Davis-Besse on January 3,1979, in which water froze in a portion of the high-pressure coolant injection system recirculation line that is commoa to both high pressure coolant injection pumps. The licensee did not thaw the line until 2 days later.

The line lead redundant heat tracing, was insulated, and had a low temperature alarm system.

Insulation defects and incorrectly located temperature-sensing elements caused the problem.

Additionally, the bulletin stated that there had been events at 15 plants involving frozen instrument and sampling lines in the previous 5 years. The bulletin requested licensees to review their plants to assure that safety-related process, instrument, and sampling lines do not freeze during extremely cold weather.

Industry Reports The industry published a report in 1994 on process pipe freezing.

3.3.2 Process System Freeze Protective Measures Lessons learned from rdustry reports based on cold weather operating experience, cornpiled below, can minimize the potential for inoperable safety systems:

Process Systems Determine whether any common-cause freezing of unprotected piping or equipment could make nMdple safety related trains inoperable.

Determine whether the failure of nonsafety-related support equipment because of low temperatures,-ice, or snow could affect the operability of safety systems.

Proceduralize ccmpensatory responses if the faiiure of nonsafety-related support equipmer,t (such as building heating, heat tracing, or SW backwash discharge) could cause the inoperability of a safety system.

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Whenever a cold wrther r:lited failure occurs, consider whether it represents a common-cause failure mechanism that could affect a safety system. Take appropriate actions if it could.

Repair damaged waterproof insulation covers and any water leaks that could soak into insulation on piping or equipment subject to freezing conditions.

Consider rerouting piping located inside purge or HVAC inlet ducts subject to freezing conditions.

Heat Tracing Provide alarmed, redundant heat tracing for safety-related process lines subject to freezing and determine the nuclear safety classification of the systems associated with hea' tracing circuits.

Repair defective or de-energized heaters and adjust heat tracing setpoints, rather than removing inputs from the control room computer alarm when they cause spurious alarms.

Include heat tracing systems in plant design basis documents.

Heating, Ventilation, and Air Conditioning Systems Determine if a LOOP would cause circulating water pump house heating to fall, and the pump house ventilation dampers to fail open.

Evaluate the effect of cold air on area components and systems where HVAC supply fans take suction from the outside atmosphere and exhaust directly to the area.

Consider the effect of temperature-induced pressure gradients in secondary containment pressure control.

Prevent, detect, and/or remove any snow and ice b'ocking safety-related HVAC inlets.

Repair overhead heating coil leaks or othur water sources that could drip onto air inlet filters, freezing the filters and blocking ventilation flow.

System Design

Verify that the lowest measured cooling water temperatures are within system design values and that thert. is sufficient insulation to protect piping under the worst case conditions.

Conshler the need for cold temperature protection in any plant modification deleting cold temperature protection equipment or adding new equipment in an area subject to cold

. temperature conditions. This should include areas that are normally warm during power operation Lut are subject to cold temperatures while the plant is shutdown during cold

weather, 16

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Instrument Line Cold Weather Events and Protective Mealures 4.1 Introduction Recent instrument line freezing events have included RWST level transmitter lines, CST level transmitter lines, and nonsafety-related components.

4.2 Operatng Experience 4.2.1 Refueling Water Storage Tank Level Transmitter Line Freezing McGuire Unit 2 On February 8,1996, with the plant at 100 percent power, two of three RWST level transmitters were found to be inoperable because of frozen impulse lines (Ref. 26). Tho lines froze because thermostat setpoints for the strip heaters were not set high enough for cold weather conditions.

The frozen impulse lines affected control room RWST level indication and the ability to automatically swap to the emergency core cooling system sump. The licensee increased the the:mostat setpoint and added inspection of the level transmitter panels to the cold weather preventive maintenance procedure.

Shearon Harris Unit 1 On February 5,1996, with the plant at 100 percent power, two of four RW3T level transmitters failed high because of frozen sensing lines, requiring entry into TS LCO 3.0.3 (Ref. 27). The operators did not sufficiently understand the significance of missing insulation and did riot prevent freezing of the second transmitter sensing line 5-% hours after the first transmitter failed The frozen lines were caused by a combination of missing insulation, heat tracing that was not installed per design, and use of inappropriate insulation in wet locations. Immedi. ate corrective actions included applying extemal heat to thaw the frozen lines, replacing missing insulation, and providing additional freeze protection guidance to operations personnel.

Long-term corrective actions included upgrading the heat tracing configuration and wattage and changing the inrulation type and configuration.

Crystal River Unit 3 The licensee reported that the plant was operated at 100 percent power while outside its design bases at times from January 31,1995, through February 17,1995 (Ref. 28). When an entrance door was left open, the borated water storage tank level instruments were subjected to ambient temperatures down to -3.8 *C (25 *F), less than the minimum 4.4 *C (40 *F) considered in the level measurement error calculatioas. This levelinstrumentation provided an in 1t to several safety-related functions, including post-accident operator dose calculations, tank vortex calculations and low pressure injection pump net positive suction head. A subsequent engineering analysis de' ermined that the actual temperature had only a 1.015 meter (1.05 ft) effect on level loop error. The cause of the event was determined to be a lack of knowledge of the requirement to keep the door closed. Correc ve actions included posting the entrance door to the borated water storage tank room with a sign indicating thst the door must be closed when exiting the area, and re-evaluation of the environmental zone temperatures for the area.

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1 Beaver Valley Unit 2 During a 16-hour period on January 14-15,1994, with the plant at 100 percent power, three RWST level transmitters failed low because of sensor line freezing (Ref. 29). The level transmitters were located in an area open to the outs;de environment that was below freezing for several hours. The piping to each transmitter was heat traced. On January 14, the channel B RWGT low low level bistable indication alarmed in the control room. After determining that the transmitter sensing lines were frozen, the licensee adjusted the heat trace controls and returned the B channel to service late that same day. On January 15, the control room received a low-low level ind ;ation on the channel D RWST bistable. The licensee bypassed the D bistable and adjusted its heat tracing to thaw the transmitter sensing lines. Before it was declared operable, the control room later received a low low levelindication on the channel A bistable. With one less than the required three operable level transmitters, the licensee applied TS LCO 3.0.3 and began a load reduction. Technicians drained the A and D charinel sensing lines and flushed warm water from the heat traced piping back through the transmitters sensing lines to verify operability. The heat trace circuit setpoints were adjusted to preclude freezing and a temporary enclosure with supplemental heat was constrmted around the transmitters and associated piping. Technicians established periodic transmitter venting and voltage monitoring to detect adverse trends and prevent freezing. After verifying reliable transmitter voltages, both transmitters werd declared operable and TS LCO 3.0.3 was exited on January 15.

An industry report described this event as being caused by

. water entering between the insulation and the sensing lines, freezing, and then degrading sensing line insulation

. sensing line pipe supports without insulation or heat tracing, aliowing the supports to conduct heat away from the lines heat trace cables electrically connected in parallel, making it difficult to detect individual line failures 4.2.2 Condensate Storage Tank Level Transmitter Line Freezing Palisades With the plant at 99 percent power on December 9,1995, one of two CST level transmitters failed high when water froze in its sensing tube. This was a repeat of an incident that occurred on February 11,1995, but the actions intended to prevent recurrence had not been completed (Ref 30) (Ref. 31). Coincident with both events, several other nonsafety-related plant devices also exhibited the effects of freezing. An insulation contractor was to have added insulation around the level transmitters in response to the first event, but left the site before doing so. The work was tumed over to maintenance work order planning, but the actions were not completed despite discussions with the NRC resident inspectors in November and December 1995. The root cause was insufficient commitment to implement the cold weather preparation program. A contributing factor was a failure in administrative processes used to control thermalinsulation work. The licensee also acknowledged that the precautions identified in an industry report on cold we ather protection had not been fully implemented. immediate compensa'ory measures included hourly checks of the redundant operable levelindication and the use of blanket insulation, welding blankets, and trouble lights to warm the level transmitter. The licensee 18

refurbished the insulation on both lev;l transmitters and verified transper operability. The licensee also added insulation after a plant inspection tour identified ddditional cold weather protection needs.

4.2.3 Auxiliary Boiler Control Line Freezing Limerick Unit 1 On January 16,1994, operators manually isolated the reactor enclosure secondary containment becs.use the differential pressure between it and the outside atmosphere was lower than the P.35 mm (0.25 in) WG required by TS (Ref. 32). Pnor to this manual ESF actuation, several avents occurred. The A auxiliary boiler tripped on low : team drum water level. Inadeqt ate feedwater level control response also resulted in the tripp auxiliaty boiler. The loss of two of three auxiliary boilers resulted in the loss,ing of the of steam to the reactor enclosure ventilation system heating coils and inadequate heating of the supply air.

The cold air entering the reactor enclosure was heated by residual air, expanded, and j

increased the reac*or enclosure pressure such that the exhaust fans could not control the differential pressure to the normai-6.35 mm (-0.25 in) WG. The A auxiliary boiler tripped because a feedwater sensing line froze after water from a small valve packir.g leak soaked the line insulation and the heat tracing could not prevent it from freezing in wtremely low temperatures. The licensee repaired the valve packing leak and instalad a new covering for the insulation to prevent water infiltration. After an inspection of other auxiliary boiler areas susceptible to freezing, the licensee installed permanent insulation coverings and repsired other potentially low temperature-sensitive auxiliary boiler instrument lines.

4.2.4 Turbine First Stage Impulse Pressure Instrumentation Line Freezing Salem Unit 2 Cn February 6,1933, automatic reactor control rn d insertion was caused by false readings b both main turbine first stage impulse pressure indication channels (Ref. 33). With outside ambient temperature less than 6.7 *C (20 *F) at 2105 hours0.0244 days <br />0.585 hours <br />0.00348 weeks <br />8.009525e-4 months <br />, one pressure channel failed down scale and the other failed upscale because of frozen sr. sing lines. These channels provided inputs for reactor control during power operation, including anticipated transient without scram mitigation system actuation circuitry, steam generator level control, and permissives for reactor trip and automatic cot.trni rod operation. L'nder these circumstances, if there had been a reqtired automatic actuation of the steam dump system because of a valid load rejection, the steam dump valves would not have opened automatically Operators stopped the control rod motion t,y placing rod controlin manual. The turbine first stage pressure indications retumed to normal within a minute after the building ventilation lineup was changed to increase ambient air temperature around the sensing lines. The root cause of the event was missing insulation oi, both transmitter sensing lines and bumt open primary and secondary heat trace wiring and controllers on one transmitter. The licensee committed to repairing the failed heat tracing, replacing the missing sensing line insulation, reviewed the administrative program for preparing the plant for winter operation, and evaluated the Unit 1 heat tracing configuration.

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i 4.2.5-Vraveling Water Screen System Failure Due to Frozen Pressure Switches Hatch On December 21,1996, following a hard freeze, plant equipment operators could not get th up river or the down river traveling water screens to automatically or manually operate (Ref. 34). Maintenance personnel determined that the screen pressure switches were frozen.

The licensee had heat traced the pressure switch sensing lines. However, they did not heat trace or insulat'J the switches so that they could read the pressure indication. Plant personnel made a design change to enclose the switches with insulating material, and install heat lamps near the pressure switches. NRC inspectors concluded that maintenance and operations personnel failed to identify portions of the system that were vulnerable to cold weather conditions during their system checks and cold weather preparations. Also, the !nspectors concluc}3d that engineering personnel failed to identify that the system design and configuration

'* did not effectively protect system components from cold weather conditions.

4.3 Lessons Learned 4.3.1 Instrument Line Freezing Generic Communications and Protective Measures Industry Report The industry has published generic reports on preventing instrument and sampling lines from freezing, However, recent plant events show that the recommendations in these reports have not always been followed. One industry report listed the following ways to prevent instrument line cold weather related problems:

. Include sensing lines and process-related piping subject to freezing temperatures in station winterizing programs.

. Adequately insulate and heat trace transmitters and piping.

. Insulate and heat trace sensing line pipe supports, as necessary, to prevent the supports from conducting heat away from the lines,

. Provide a positive means for verifying heat trace current flow (e.g., a pilot light or current indication and operable low-temperature alarms).

Be certain heat trace controller setpoints are correct and appreciate that increasing heat trace setpoints a. a compensatory action is not alwaye affective.

. Promptly and adequately investigate heat trace alarms or monitor heat trace systems.

. Do not electrically connect heat trace cables in parallel, as this makes it difficult to detect individualline failures.

. Have the safety related heat tracing system as an input to the control room computer alarm.

. Assure plant design basis documents address heat tracing syst3ms.

. Consider increasing heat trace circuit monitoring frequency during extremely cold weather.

. Make certain heaters work and are energized.

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. Verify fans or obstructions do not direct cold air on process transmitters, air regulators, and lines.

• Look for water leaking onto other components and freezing.

• Consider that some plant areas zie hot during power operation but might freeze when the plant is shut down during cold weather.

• Consider that previously effective cold weather protection practices might not t>e effective during extreme cold weather conditions.

. Consider installing portable space heaters or enclosing cold sensitive Press.

4.3.2 Instrument Line Freezing Findings Instrument line freezing events continue to occur at various plants despite repeated industry reports on correcting instrumentation line freezing problems. Some licensees did not effectively respond to instrument line freezing as a potential common-mode failure mechanism that also affected other redundant instruments which led to simultaneous failures of redundant, safetv-related level instrumentation. Missing or insufficient insulation, lack of waterproof insulation covering, inadequate heat trac lng setpoints or wattage, and insufficient attention to cold weather preparations continued to cause recent instrument line freezing. Events have shown that level instruments have failed upscale or down scale because of sensing line freezing, in addition, plants lccated in warm climetes have been subject to unusually cold conditions that had not been adequately addressed in the original design or cold weather programs. Cold weather ;nspection programs have missed insulation and heat tracing problems.

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5 Emergency Diesel Generator Cold Weather Events Cnd Protec.tive Measures 5.1 Introduction i

Unusually low temperatures in EDG rooms have affected the ability of EDGs and fuel oil transfer pumps to start and continue operation at several plants. The following specific operating experience has not been addressed in recent NRC generic communications.

5.2 Operating Experience North Anna Units 1 and 2 On January 21 and 22,1994, with the units at 100 percent and 96 percent power, the licensee declared four of eight EDG fuel oil transfer pumps inoperable after thermal overload relays tripped their moter broakers during pump starts (Ref. 35). The licensee declared one EDG inoperable when both its lead and standby fuel oil transfer pumps were inoperable. The fuel oil transfer pumps were located in an unheated building. Forced ventilation with outside air reduced fuel fumes in the pump rooms, but the room temperature closely followed the outside air temperature. Outside air temperature ranged between 18.9 *C ( 2 'F) and 5 'C (23 'F) over the several day period. Both inboard and outboard fuel oil transfer pump motor bearings were double shielded and did not require additional greasing following installation. However, as part of the preventive maintenance program, the fuel oil transfer pumps motor bearings were greased every 18 months. Too much grease was forced into the bearings, and the combination of cola temperatures and hardened excess bearing grease increased the torque on the motors, resulting in thermal overload trips. Corrective actions included securing the fuel oil pump house exhaust fans, installing po' table heaters, and raising the pump house room temperature to 9 bout 10 *C (50 'F). The licensee also replaced the fuel oil transfer pump motor bearings and tested each pump.

D.C. Cook Unit i On February 10,1992, with the plant at 100 percent power, an EDG tripped on overspeed while starting for a routine operability test (Ref. 36). Earlier, on February 6,1992, the supply ventilation damper malfunctioned and was de-energized in its open position to ensure adequate cooling for the EDG, An investigation found that the open damper allowed outside air between 9.4 'C (15 'F) and 2.2 *C (36 'F) to blow on the EDG governor wanning line. The resulting low govemor oil temperatures and sluggish govemor operation caused the overspeed trip.

After the licensee corrected the ventilation supply damper problem and warmed the EDG room and govemor, the EDG started and functioned property. To prevent the jacket water from being cooled excessively while en route to the govemor, the licensee insulated the govemor warming lines associated with all four EDGs on the site.

Mittstone Unit 1 On February 12,1991, the EDG tripped on low lube oil pressure 27 seconds after starting during a required surveillance test, but troubleshooting found no mechanical explanation 22

(Ref. 37). Low temperature was not considered a cause at that timegecause the EDG was equipped with a lube oit keep warm system. Later, parts of the externallube oil piping, including the mLin lube oil filter, main lube oil strainer, associated piping, and sensing line for the tube oil pressure switches, were identified as subject to ambient temperature ef#ects. A chart recorder showed a decrease in lube oil pipe temperature as ambient air temperature decreased and verified that the time to reach reset pressure of the lube oil pressure switches increased as lube oil piping temperatures decreased. The time margin available for a successful EDG start was shown to be directly related to ambient rocm temperature. The viscosity of the oil, Mobilgard 450, was found to vary asymptotically below 21.1 'C (70 'F),

while the ambient temperature could be lower than this when the plant heating system was out of service. Mobil Oil and Fairbanks Morse concluded that increased oil viscosity reduced the flow rate in the engine oil lines, which increased main lube oil pump discharge pressure and the time required to reach reset pressure. On March 7,1991, with the giant in told shutdown, a special test of the EDG was conducted in which room temperature was lowered. The EDG tripped again on low lube oil pressure with an external lube oil temperature 8,f 14.4 'C (58 'F),

venfying the cause of the February 12 EDG trip. Further testing found that engine operability could be assured above 20 *C (68 'F) oil temperature in the external piping. As a result, the ticonsee revised plant operating procedures to requira operators to record diesellube oil pipe temperatures each shift. At 23.9 *C (75 'F) lube oil pipe temperrture, temporary area heaters were to be placed in service. A continued decrease v. lube oil pipe temperatures to 21.1 'C (70 'F) required the EDG to be started and operated to provide temperature equilibrium throughout the entire engine lube oil system. With the r,ormal plar,t heating system in service, the EDG room temperature will remain within acceptable limits.

5.3 Lessons Learned 5.3.1 Generic Communications on Emergency Diesel Generator Failures From Cold Fuel Oil IN 9419. " Emergency Diesel Generator Vulnerability to Failure from Cold Fuel Oil,"

March 16,1994:

This IN discusses Vermont Yankee and Point Beach Electrical Distribution System Functional inspection results. The July 6 to August 7,1902, Vermont Yankee engineering distribution system functional inspection found that the EDGs might be vuinerable to excessive viscosity problems and that wax crystals could form in cold fue' oil. Wax crystals could clog fuel oil filters and plate out on fuel ou piping walls and obstruct fuel oil transfer from the storage tank to the EDGs. The inspection team observed that fuel oil piping heat tracing was not energized with a safety related electrical power source. During a March 12 to April 6,1990, engineering distribution system functional inspection at Point Beach, inspectors discovered another fuel oil viscosity concem. Fuel oil would not gravity drain from the ou side storage tanks to the EDG day tanks at very low temperatures. The licensee changed its fuel oil blend and implemented procedures to recirculate fuel oil and monitor its temperature during extremely cold weather.

The licensee could also park oil tank trucks in a heated warehouse, if necessary. The IN noted that unless licensees use fuel oil with the correct cloud point, pour point, and viscosity for expected weather conditions, common mode EDG failures could occur.

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l 5.3 2 Emergency Diesel Generator Room Low Temperature Findings Recent operating experience includes failures of fuel oil trar,sfer pumps because cold weather related hardening of excess motor bearing grease increased torque during starting. Low ambient EDG room temperatures have increased EDG lube oil viscosity, reduced oil flow, and tripped EDGs on low tube oil pressure; and caused sluggish govemor operation. These oit viscosity problems have occurred even though the EDG lube oil keep warm system was functioning. The problerns were due to heat losses from extemal piping. The American Society for Testing Materials Standard Viscosity Temperature Charts for Liquid Petroleum Products (D 341) (Ref, 38) are available to aid in preventing EDG oil viscosity problems such as those experienced at the Millstone and D.C. Cook plants, l

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Essential Chiller Cold Weather Events and Protactive Mea'sures 6.1 Introduction The NRC issued IN 94 82,' Concerns Regarding Essential Chiller Reliability During Periods of Low Cooling Water Temperature,"in December 1994 (Ref. 39). The IN addressed NRC concerns about essential chiller reliability during periods of low cooling water temperatures for the South Texas Project and the Perry nuclear facilities. The following section includes related events at McGuire and Duane Arnold. The root cause appeared to be insufficient engineering consideration of low heat load operation of the chillers during p9tiods of low cooling water temperatures. In addition, contributing causes for these four events varied from plant to plant and included poor procedures, low oil temperatures and pressure, low condenser heat load conditions, high Freon charge, insufficient oil cooler temperature probe thermogrease, and slowly responding temperature control valves.

6.2 Operating Experience McGuiro Unit 1 On February 21,1995, the licensee determined that the A control room ventilation / chilled water system had been inoperable for several periods in 1994 (Ref. 40). Testing verified that the system had been susceptible to tripping on low evaporator refrigerant temperature from a combination of low temperature and high flow rates of the nuclear SW system through the system condenser. On February 7,1995, when the system was at its hbtorically low temperature, the licensee performed a heat balance to determine if the A chiller would remain operable with the control valves in their full open position. This test and an associated calculation indicated that tha A chiller would likely trip on low evaporator refrigerant temperature with low nuclear SW syt, tem temperatures and high flow rates. The cause of this event was insufficient review of the cumulative effects of the field changes and operational practices on design functions; as a result, the licensee overlooked the potential for 'oss of an essential chiller during periods of low cooling water temperature and high flow rates.

Duane Amold On November 11,1993, with the plant at 100 perce.it power, both control building chillers were inoperable simultaneously (Ref. 41). One chiller tripped during normal operation while the other was out of service for preplanned maintenance. Initial attempts at restarting the chillers were unsuccessful because of setpoint problems and Freon charge balancing for cold weather operation. The chiller trips were caused by several factors associated with load balancing, including slightly high Freon charge for low load conditions, insufficient oil cooler temperature probe thermogrease that caused a slow response to oil temperature changes, and a slowly responding three way temperature control valve. The licensee rebalanced the chillers by adjusting the Freon charge, expansion valve setup, and the three way temperature control valve. The licensee also recoated the oil cooler temperature probes with thermogrease to allow improved temperature monitoring and added a preventive maintenance action for their annual inspection. The three way temperature control valve was disassembled, cleaned, and reassembled to improve its response. The licensee committed to change its procedure to address the winter as well as the summer chiller setup requirements, e

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6.3 t.essons Learned 6.3.1 Essential Chlber Generic Communications i

IN 94 82," Concerns Regarding Essential Chiller Reliability During Periods of Low Coolin Water Temperature " December 5,1994:

This IN describes a condition at the South Texas Project in which essential chillers could become under loaded if an accident signal was generated during cold weather.. The licensu modified procedures and hardware to assure stable chiller operation at low cooling water temperatures. It also describes a January 28 and 29,1994, Perry Nuclear Power Plant event where low emergency closed cooling water system temperature made both control room emergency recircutation trains inoperablw. The IN cautioned against overlocking the potentlar to lose essential chillers during cold weather if the design focus was on peak loading.

6.3.2 Essential Chiller Problem Findings Low heat load operation of the essential chillers during periods of low cooling wates teraperatures is a design condition for plant personnel to consider during any design modification to the control room ventilation system. Performing a heat balance during surveillance testing on the control room ventilation essential chillers caring low heat load conditions at low cooling water temperatures and high flows might identify design or compon deficiencies that could make the system susceptible to tripping on low evaporator refrigera temperature. Some control room ventilation systems can be balanced for warm or cold weather operation before maximum design parameters occur.

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7 Electrical Cold Weather Events and Protective Measures [

7.1 Introduction Licensees have recently experienced cold weather preparation problems involving insufficient inspection and repair of logic and electrical power conduit seals, switchyard breaker cabinet gaskets and seals, and switchyard breaker U-bend heaters and fuses.

7.2 Operating Experience LaSalle Unit 2 On Fet'ruary 4,1996, operators manually scrammed the plant wher1the ma'n transformer oil temperature could not be maintained within its limits because of the loss of the transformer cooling fan and cooling pump (Ref. 42), ice severed the transformer cooling logic cable in its conduit where it entered the underground cable trough. Licensee corrective actions included inspecting other transformer conduits, clearing water and ice from conduits, and sealing the conduits.

Wolf Creek A November 10,1995 LOOP to the west bus in the switchyard caused the startup transformer feeding an ESF transformer to lose power (Ref,43). A degraded air break disconnect motor operator cabinet door gasket allowed snow, ice, and sleet to enter the cabinet. This foreign material shorted out air break disconnect contacts and caused the disconnect to spuriously open. The licensee inspected 19 switchyard cabinots und found that half had degraded gaskets. The licensee leplaced the damaged gaskets and made other minor repairs.

Fermi Unit 2 Division 1 electrical power was lost on January 27,1994, while the plant was in cold shutdown.

This resulted in a power loss to the Division 1 reactor protection system and in 11 groups of primary containment isolations, shifted control center HVAC to the recirculation mode, and caused the standby gas treatment system and tne emergency equipment cooling water system to auto start. The Division 1 EDG autostrr+ed on bus undervoltage. The closure of an RHR common suction inboard isolatinn valve resulted in the loss of Division 11 RHR shutdown cooling for about an hour and the reactor coolant tempe.ature increased 8.3 *C (15 'F)

(Ref. 44).

Two of three incoming Division I incoming offsite feeds were lost because of faults during a heavy ice storm. The third line was not successfully isolated because an incoming feeder brecker failed to open. Water had entered the breaker, froze on the breaker Y phase trip linkage and mechanically inhibited the trip linkage. Protective relaying subsequently isolated the remaining feed at another station.

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Farley Unit 1 On November 28,1092, while the unit was preparing to enter Mode 2, a one phase fault tripped two 230 kV switchyard breakers, de-energized the 1 A startup transformer, and e aused a train A loss of site power ESF actuation (Ref. 45). The phase to-ground fault occurred during told 1

weather when inoperable U bend heaters allowt;d the SF, gas to liquefy below 13.3 'C (56 'F) in the brnaker U bend.

The primary cause of the event was blown fuses in the heater circuits that made the U bend heaters inoperable. The 3 amp fuses in the heater circuits did noi, provide adequate operating margin since the circuit normally drew 2.7 amps. The licensee concluded that the most likely cause of fuse failure was transients due to frequent cycling of the heaters by the thermostats.

Corrective actions included upgrading all of the 230 kV Westinghouse SFV switchyard breaker i

fuses 310 amps, checking the U bend heater fuses twice per year, and inspecting the U bend heater fuses dunng cold weather conditions.

s A contributing factor to this event was the lack of calibration of the U bend 'amperature indicator / alarms. The licensee found that the indicator / alarm read 8.3 *C (15 'F) above the actual temperature. Thus the alarm setpoint was actually at 10 'C (50 'F)instead of 18.3 'C (65 'F). The instruments had not been calibrated since installation in 1984. After the event, the licensee checked and recalibrated all of the 230 kV switchyard breaker U bend temperature indicators / alarms.

7.3 Lessons Learned 7.3.1 Electrical Problems Generic Communication The specific operating experience described above has not been addressed in recent NRC generic communications.

7.3.2 Electrical Event Findings Licensees at',1buted recent electrical events to insufficient cold weather inspection and maintenance of electrical conduit seats and switchyard breaker cabinet gaskets and seals.

Water was allowed to intrude past gaskets and seals and subsequently froze. Also, switchyard breaker U bend control circuit heater fuses had blown because of improper sizbg.

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8 Conclusions N

Recent operating experience suggests that despite NRC and industry communications on this subject, some licensees have not effectively protected components whose failure could degrade safety systems. Extremely cold weather conditions continued to affect intake structures, process lines, instrument lines, EDG oil and grease viscosities, essential chillers, electrical systems, heating, ventilation and air conditioning systems. Lack of design oversight, incomplete review of operating experience, and insufficient attention to cold weather preparations resulted in most of the events. Important approaches and measures licensees have used to protect against cold weather cperational events appear in the Lessons Learned Sections of this report.

8.1 Intake Ice Problems Ice in cooling water pumps and intake structures has degraded multiple safety-and nonsafety-related cooling water systems, including the ultimate heat sink. Licensees found that intake icing is a common cause fa!!ure mechanism that can quickly affect safety related cooling water systems unless mitigating cetions are taken in a timely manner. The most significant events involving intake ice buildup have occurred in a short period in the middle of the night during windy, low temperature conditions. Response to rapid ice buildup requires plant operators to recognize the significance of antake icing, constantly monitor intake conditions, and respond proactively using predetermined actions. Because water can hold more air in solution as its temperature decreases, verification of air flow through condenser water box and warming line air release valves becomes very important during icing conditions to ensure sufficient intake water warming flow to maintain the 0.1 'C (0.2 'F) temperature differential between intake water and pump suctions needed to prevent frazilice buildup. Automatic operation ofintake water traveling screens in a heated environment in conjunction with effective mitigating actions has been shown to minimize ice build up during extreme cold weather conditions.

8.2 Process Line Cold Weather Problems Oversights in design or operations experience review contributed to most of the process line events, in some cases, licensees relied on nonsafety-related systems and alarms to ensure continued operation of safety related equipment. Cold weather caused failures in nonsafety-related systems resulted in unrecognized failures of s.3fety systems. Freeze prevention measures including compensatory actions were sometimes ineffective in preventing process liw %m freezing.

8.e Instrument Line Cold Weather Problems Missing or insufficient insulation, lack of waterproof insulation covering, inadequate heat tracing setpoints or wattage, and insufficient attention to cold weather preparations have continued to cause instrument line freezing at various plants. Some licensees did not respond to instrument line freezing as a potential common-mode failure mechanism that also affected other instruments. This resulted in simultaneous failures of redundant, safety related, RWST level instrumentation.

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8.4 Emergency Diesel Generator Cold Weather Problems Cold weather related hardening of excess EDG fuel oil transfer pump motor bearing grease increased torque during pump starts and caused pump failures. Also, low ambient EDG toom i

temperatures increased EDG lube oil viscosity, tausing sluggish govemor operation, reducing lube oil flow, and tripping the EDG on low lube oil pressure. Heat losses from external piping allowed this to occur even though the EDG lube oil keep warm system was functioning.

8.5 Essential Chiller Cold Weather Problems Low cooling water temperatures can cause essential chillers to become unstable. Design modifications to the control room ventilation system had not considered operation of the essential chillers at low heat loads during periods of low cooling water temperatures.,

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Perforrnng a heat bblance during surveillance testing on the controftoom vtfhtilation essential 1

chillers during low heat load conditions at low cooling water temperatures and high flows may identify design or component deficiencies that could otherwise make the system susceptible to tripping on low evaporator refrigerant temperature.

8.6 Electrical Cold Weather Problems Insufficient cold weather inspection and maintenance of electrical (logic and power) conduit seals, and switchyard breaker cabinet gaskets and seals have caused recent electrical events.

As a result, water was allowed to intrude past gaskets and seals and subsequently froze i

resulting in inoperable breakers. Frequent cycling of switchyard breaker U bend heaters due to cold weather caused their undersized fuses to blow and resulted in the loss of the heaters. This allowed the SF, gas to liquefy and produce a one phase fault that resulted in breaker trips, loss of a stattup transformer, and a LOOP ESF actuation.

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9 References 1.

U.S. Nuclear Regulatory Commission, NUREGICR-0548," Ice Blockage of Water intakes," March 1979.

2.

U.S. Army Corps of Engineers Cold Regions Rescarch and Engineering Laberatory, TRiver Ice Data Instrumentation," Cold Regions Technical Digest No. 97 2, June 1997 3.

U.S. Army Corps of Engineers Cold Regions Research and Engineering Laboratory, "Frazil ice Blockage of Intake Trash Racks," Cold Regions Technical Digest No. 91 1 March 1991.

4.

Detroit Edison, Fermi Unit 2, Licensee Event Report 50 341/96-001, February 5,1996.

s s

5.

. U.C. Nuclear Regulatory Commission, Information Notice 96 36,

• Degradation of Cooling Water Systems Due to Icing," June 12,1996.

6.

Wolf Creek Nuclear Operating Corporation, Wolf Creek Generating Station, Licensee Event Report 50-482/96-001, February 28,1996.

7.

Wolf Creek Nuclear Operating Corporation, Wolf Creek Generating Station, Licensee Event Report 50-482/96-002, February 29,1996.

8.

U.S. Nuclear Regulatory Commission, Special Inspection report 50-482/96 003, April 24,1996.

9.

N.S. Carns Wolf Creek Nuclear Operating Corporation, letter to NRC, WM 96-0038, March 15,1996, 16.

U.S. Nuclear Regulatory Commission, Emergency Notification System Report No. 26645 from Ginna, January 20,1994.

11.

J. Donovan, New York Power Authority, memorandum to H. Salmon,

" James A. FitzPatrick Nuclear Power Plant icing Events of 2/23 and 3/13/93 Fleet Technology L*d. Assessment " April 5,1993.

12.

New York Powe Authority, James A. FitzPatrick Nuclear Power Plant, Licensee Event Report 50-333/93-004, March 26,1993.

13.

- New York Power Authority, James A. FitzPatrick Nuclear Power Plant, Licensee Event Report 50-333/93-006-01, May 5,1993.

14.

. Northeast Nuclear Energy, Millstone Nuclear Power Station Unit 2, Licensee Event

._ Report 50 336/96-002, February 5,1996.

15.

Northeast Nuclear Energy, Millstone Nuclear Power Station Unit 2, Licensee Event Report 50 336/96 004, February 29,1996.

16.

Northeast Nuclear Energy, Millstone Nuclear Power Station Unit 2, Licensee Event Report 50 336/96 003, March 6,1996.

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17, Commonwealth Edison Company, Zion Nuclear Power Statio)t. Unit 1, Licensee Event Report 50 295&304/96-007, April 9,1996.

/

18.

Nebraska Public Power District, Cooper Nuclear Station, licensee Event Report 50-298/94-026, November 9,1994, 19.

North Atlantic Energy Service Corporation, Seabrook, Licensee Event Report 50-443/93-016-01, December 9,1993.

20.

Maine Yankee Atomic Power Company, Maine Yankee, Licensee Event Report 50-309/97-005, March 20,1997.

21, Carolina Power & Light Company, Shearon Harris Nuclear Plant Unit 1 Licensee Event Report 50;400/96 002, March 10,,1997, g

a 22.

Commonwealth Edison Company, LaSalle Generating Station Units 1 and 2, Licensee Event Repor150 373/97-002, March 5,1997.

23.

Maine Yankee Atomic Power Company, Maine Yankee, Licensee Event Report 50-309/96-001, February 7,1996.

24.

IES Utilities, Duane Amold Energy Center, Licensee Event Report,50 331/94 004, February 14,1994.

25.

Consumers Power, Palisades Plant, Licensee Event Report 50-255/94-001, February 18,1994.

26.

Duke Power Company, McGuire Nuclear Station Unit 2, Licensee Event Report 50-370/96 00101, April 18,1996.

27.

Carolina Power & Light Company, Shearon Harris Nuclear Plant Unit 1, Licensee Event Report 50-400/96-004-01 April 4,1996, 28.

Florida Power Corporation, Crystal River Unit 3, Licensee Event Report 50 302/95-May 17,1995.

29.

Duquesne Light, Beaver Valley Power Station Unit 2, Licensee Event Report 50412/94-001,."ebruary 14,1994.

30.

W.J. Kropp, U.S. Nuclear Regulatory Commission, letter to T. Palmisano, Palisades Nuclear Generating Plant, " Integrated Inspection Report 50-255/95014 and Notice of Violation," February 6,1996.

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R.W. Smeuley, Consumers Power, letter to U S Nuclear Regulatory Commission,

" Docket 50 255 - License DPR Palisades Plant Reply to Notice of Violation for Two Violations - Inadequate Freeze Protection for Condensate Storage Tank Level indicator and Safety injection Low Pressurizer Pressure Signal Disabled with Primary Coolant System Greater than 300'F," March 6,1996 32.

PECO Nuclear, Limerick Generating Station Unit 1, licensee Event Report 50 352/94-002, February 9,1994.

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33.

Public Service Electric and Gas Company, Salem Generating Station Unit 2, Licensee Event Report 50 311/93-004, March 5,1993.

34.

U.S. Nuclear Regulatory Commission, Region 11 Inspection Report No. 50-321/9615, 50 366/9615, E.I. Hatch Units 1 and 2. Enclosure 2, pages 5 and 6, February 13,1997.

35.

Virginia Electric and Power Company, North Anna Power Station Units 1 and 2 Licensee Event Repor150 338/94-001, February 22,1994.

36.

Indiana Michigan Power Company, D. C. Cook Nuclear Plant Unit 1, Licensee Event Report 50 315/92 002 01, September 29,1992.

37.

Northeast Utilities, Millstone Nudear Power Station Unit 1. Licensee Event Report 50 245/91-004-01, August 22,1991.

38.

Diesel Engine Manufacturers Association, Standard Practices for Sfationary Diesel Engines and Gas Engines, American Society for Testing Materials Standard Viscosity Temperature Charts For Liquid Petroleum Products (D 341), Chart B: Saybolt Universal Viscosity, Abridged, sixth edition,1972, page 114.

39.

U.S. Nuclear Regulatory Commission Information Not:ce 94-82, ' Concerns Regarding Essential Chiller Reliability During Periods of Low Cooling Water Temperature,*

December 5,1994.

40.

Duke Power Company, McGuire Nuclear Station Units 1 and 2 Licensee Event Report 50 369/95-002, March 23,1995.

41.

Iowa Electric Light and Power Company, Duane Arnold Energy Center, Licensee Event Report 50-331/93-011, December 3,1993.

42.

Commonwealth Edison Company, LaSalle Generating Station Unit 2, Lloensee Event Report 50 374/96-02, March 4,1996.

43.

Wolf Creek Nuclear Operating Corporation, Wolf Creek Generating Station, Licensee Event Report 50-482/95-006-01, February 1 1996.

44.

Detro!t Edison, Fermi 2, Licensee Event Report 50 341/94-001 February 28,1994.

45.

Southem Nuclear Operating Company, Farley Nuclear Plant Unit 1, Licensee Event Report 50-348/92-007, December 22,1992.

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