ML20246K756

Insp Rept 50-302/89-14 on 890531-0602.Violations Noted.Major Areas inspected:890529 Event Involving Emergency Feedwater Piping & Containment Penetration Heated Above Design Limits & Unanalyzed Thermal Stresses Imposed on Steam Generator

ML20246K756
Person / Time
Site:	Crystal River
Issue date:	06/27/1989
From:	Robert Carrion, Kellogg P, Schin R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20246K717	List: ML20246K713 ML20246K725 ML20246K756
References
50-302-89-14, NUDOCS 8907180255
Download: ML20246K756 (19)

See also: IR 05000302/1989014

Text

m- T-

s- -e E UNITED STATES

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[' .ph rec^g NUCLEAR REGULATORY COMHisSION

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n REGION 11

101 MARIETTA STREET,N.W.

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ATLANTA, GEORGf A 30323

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l Report No. 50-302/89-14

Licensee: Florida Power Corporation

3201 34th Street South

St. Petersburg, FL- 33733

Docket No. 50-302 Ucense No. DPR-72

Facility Name: Crystal River 3

Inspection Conducted: May 3 - June 2, 1989

Inspectors:

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R. 'Schin Date. Signed

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R. Ca'rrion Date Sfgned

Approved by: , fdj Iwlu b 27,v7Ff

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P. 'Kellogg, Chief (/ Date Sidned '

Operational Programs Section

Operations Branch

Division of Reactor Safety

SUMMARY

Scope:

This was a special announced reactive inspection to review an event of May 29,

1989. In that event, Emergency Feedwater piping and a containment penetration j

were heated above design limits and unanalyzed thermal stresses were imposed

on the A steam generator. The event occurred with the plant in Mode 5 on

Decay Heat Removal cooling, and with no reactor coolant pumps operating. The

purpose of this inspection was to assess: l

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1. Potential damage, by physical inspection of affected piping and

equipment and by review of engineering evaluations.

2. Written procedures for adequacy, by review of operating procedures

and system drawings and by interviewing operators. <

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3. Operator use of procedures, by review of logs and records relating

to the event and by interviewing operators.

4. Cor.ective actions taken by the licensee.

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Florida Power Corporation 2

Results:

The inspection results are summarized as follows:

1. There was no apparent damage to safety equipment as a result of this

event. One incorrect drawing of a pipe support and one improperly

stored. piping swing connection were identified by the inspectors.

Control of pipe support drawings .is an unresolved item. (paragraph 6.)

2. Written operating procedures were inadequate to prevent overheating

of the EFW piping and containment penetration, and also to prevent

the imposition of unanalyzed thermal stresses on the A steam

generator. (paragraph 5.)

3. Operator use of procedures was also inadequate. Procedures that did

exist were not-reviewed by the operators. This was a contributing

factor to the event. (paragraph 4.)

4. Corrective actions taken or planned by the licensee at the time of

the inspection were incomplete. The licensee had not identified the

full scope of weaknesses in operating procedures. Also, the

licensee had not identified any weaknesses in operator use of

procedures. (paragraph 8.)

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• Unresolved items are matters where more information is required to determine

whether they are acceptable or may involve violations or deviations.

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REPORT DETAILS

1. Persons Contacted

Licensee employees

• T. Austin, Principal Mechanical Design Engineer

• W. Bandhauer, Nuclear Operations Superintendent

• R. Fuller, Senior Nuclear Licensing Engineer

• F. Fusick, Supervisor, Mechanical Design

• B. Hickle, Manager, Nuclear Plant Operations

• W. Marshall, Nuclear Operations Superintendent

• W. Rossfeld, Manager, Nuclear Compliance

R. Widell, Director, Nuclear Operations Site Support

• M. Williams, Nuclear Regulatory Specialist

Other licensee employees contacted included operators, engineers, and

office personnel.

NRC Representatives

• P. Holmes-Ray, Senior Resident Inspector

• A Tedrow, Resident Inspector

• Attended exit interview

Acronyms used throughout this report are listed in Attachment 7.

2. General Description of the Event (93702)

This event occurred with the unit in Mode 5, with a steam bubble in the

pressurizer and no RCPs operating. Operators were maintaining RCS

pressure

at about 90atdegrees

about 160 F byp(sig

using(by

DHR using pressurizer

cooling). heaters)

Pressurizer andRCP

level and temperature

seal flows were being maintained by the makeup system. The DHR system

was taking a suction from RCS loop B hot leg (this is the only DHR

suction connection to the RCS) and discharging int'o the reactor vessel

through the core flood nozzles. The DHR flowpath is shown in Attachment

1, Reactor Coolant drawing and Attachment 2, DHR drawing. Steam

generators were in wet layup. Unit startup was delayed by the

unavailability of auxiliary steam, pending repair and startup of one of

the coal fired power plants on site.

To save time during the forthcoming unit startup, operators began

degassing of the RCS by initiating pressurizer spray from the DHR system.

The spray flowpath is shown in Attachments I and 2. As a result of this

spray flow, hot water (approximately 350 degrees F) flowed .out of the

pressurizer through the surge line and into the lower part of the hot leg

of the A loop. This flowpath is shown in Attachment 1. The hot water

then rose through the stagnant cooler water in the A loop, past the wide

range T hot detector, to the top of the hot leg and the top of the A

steam generator. The elevations are shown in Attachment 3, Reactor

Coolant Piping Assembly Elevation drawing. Thus the top of the A steam

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generator was heated. Operators were not aware of the increasing A loop

hot leg temperature and began recirculating the secondary side of the A

steam generator using a chemical recirculation pump. Periodic recircula-

tion of steam generators is routinely done for chemistry control when'the

steam generators are in wet 9ayt7. The pump took a suction from the steam

generator blowdown piping and discharged through a spoolpiece connection

to the Emergency Feedwater piping and back into the steam generator.

The flowpath is shown in Attachment 4, Main and Reheat Steam drawing;

Attachment 5, Chemical Cleaning Steam Generators drawing; ond Attachment 6

Feedwater drawing.

Portions of the EFW piping including EFW containment penetration 424 were

heated to 222 degrees F, which is above their design temperature of 150

degrees F. Also, the A steam generator was subjected to a thermal

gradient of about 270 degrees F, from top to bottom, for which it had not

been analyzed. A total of approximately 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> elapsed from the time

that pressurizer spray flow was started until it was stopped upon

discovery of the overheating problem. Three different shift crews of

operators were involved, including a total of six licensed R0s and six

licensed SR0s.

3. ' Detailed Sequence of Events (93702)

Time Data Source Item

0000, SS Log Shift turnover plant status: Mode 5, RCS at 93

May 28 degrees F and 158 psig, A DHR train operating

0015 R0 Log Started pressurized spray per EQ 89-1521

0556 R0 Log Started B OTSG on recirc

0800, SS Log Shift turnover plant status: Mode 5, RCS at 90

May 28 degrees F and 167 psig, A DHR train in service

1600, SS Log Shift turnover plant status: Mode 5, RCS at 91

May 28 degrees F and 160 psig, A DHR train in service

1650 R0 Log Started A OTSG on recirc, secured B OTSG

0000, SS Log Shift turnover plant status: Mode 5, RCS at 92

May 29 degrees F and 165 psig, A DHR train operating

prior Interviews An R0 on shift was performing an instrument i

to 0440 calibration check PT that was required for entry I

into Mode 3. This lead him to discover that the I

RCS A loop T hot was reading high (approximately l

350 degrees F). The licensed operators on shift

(2 SR0s and 2 R0s) were surprised that A loop l

T hot temperature was high. l

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0440 R0 Log Stopped pressurizer spray

0440 Interviews The SS was concerned about a possible steam

bubble in the top of the A loop hot leg.

Operators increased pressurizer pressure by

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about 20 psig. Steady levels in the pressurizer

and makeup tank indicated to them that there had

been no steam bubble in the A loop.

0500 NCOR 89-124 Containment penetration #424 (EFW) temperature

was found to be 222 degrees F, which exceeded

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l and

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Interviews the design limit of 150 degrees F. This was

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discovered by an R0, who went out in the plant

to read the local temperature indicator for-

penetration #424. This temperature-instrument

had recently been installed, as a result of-

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overheating the B OTSG EFW containment

penetration last year.

0600 NCOR 89-124 The NCOR was completed and signed by the SS.

and The SS had &cided that no 10CFR50.72 telephone

Interviews . report to the NRC was was required and had so

indicated on the NCOR.

about Interviews Oncoming SS questioned deportability of the event

l 0800

about Interviews Penetration #424 temperature was down to about

0830 150 degrees F.

about Interviews An ad hoc management group, including Operations

0945 and Compliance, decided that the event was

reportable as a four hour report.

0951 SS Log and The NRC was notified of the event via ENS phone,

NCOR 89-124 under 10CFR50.72B21.

4. Operator Use of Procedures (93702)

The inspector asked the licensee to have copies of all operator logs,

procedures, and drawings that related to this event available upon arrival.

With only a few hours of advance notice, the licensee did have most of

these records available when the inspector arrived on site. The Operations

- Superintendent and Principal Mechanical Design Engineer reviewed these

records with the inspector, along with the sequence of events and current

status.

The inspector noted that the R0 Log entry of 0015 on May 28 stated that

operators started pressurizer spray per EQ 89-1521. EQ 89-1521 was a

question from operators with a written response from Engineering. The

question was:

Currently the pressurizer temperature is approximately 270 degrees F

higher than the RCS temperature. Operations would like to initiate

pressurizer spray to assist in the removal of non-condensibles from

the RCS. Is there any engineering concern with this?

The response addressed the plant heatup procedure limit of 250 degrees F

delta T for use of pressurizer spray. It also addressed minimum spray

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flow needed to assure that surge line stratification would not occur.

The engineering response concluded that. spray from DHR with the existing

270 degrees F delta T presented no thermal shock concern as long as no

heatup was in progress. It also concluded that a spray flow of at least

20 gpm was needed .to prevent thermal stratification in the surge line.

The inspector found that EQ 89-1521 provided a good basis for making a

permanent change to plant operating procedures. But it was not a

procedure: it did not have the required review and approval, nor was it

written in the required format of a procedure. Also, it did not contain

adequate action steps, initial conditions, limits, or cautions. The

inspector's subsequent review of procedures and interviews with operators

revealed that' the operators did not use this EQ to change an operating

procedure. The inspector concluded that operators had used EQ 89-1521 in

place of a procedure, just as recorded in the R0 Log.

The licensee showed the inspector copies of procedures that they stated

were used during this event. The inspector noted that all of these

procedures contained signature blanks by each step. The inspector then

asked for copies of the signed off procedures that were actually used by

the operators to initiate DHR spray flow. The licensee was unable to

provide the signed off copies, because they did not exist. In subsequent

interviews, the SS on shift when the spray flow had been initiated stated

that operators had not gotten out any written procedures for initiating

DHR spray flow to degas the RCS. The SS stated that this was a simple,

routine evolution and as such a written procedure was not required to be

present or to be signed off. The Operations Superintendent supported

this policy expressed by the SS. The inspector reviewed the operating

procedures that the SS stated provided authorization for initiating :: pray

from DHR, and cJncluded that if the operators had gotten these procedures

out and read them, they would have been alerted to watch for increasing

temperatures in the A hot leg. In response to further inspector

questions, the SS stated that he had never before personally degassed the

RCS by using spray from DHR. Also, he did not know anyone who had done

this evolution. The Operations Superintendent stated that when he had

asked operators to show which procedures they had used te initiate spray

from DHR to degas the RCS, the operators had difficulty in locating such

procedures. They were surprised to find that the Plant Heatup procedure

did not address initiating spray from DHR. The inspector concluded that

operator failure to review existing procedures was a contributing factor

to this event. This failure to have procedures present is an example of

violation 302/89-14-01.

The Operations Superintendent stated that degassing the RCS from DHR

spray was a routine evolution, and had been done many times to expedite

plant heatup. He stated that a number of operators had done it and knew

from experience that high temperatures in the A loop hot leg were to be

expected. The inspector found that degassing of the RCS by using DHR

spray is not described in the Plant Heatup procedure, nor in any other of

the licensee's procedures. Use of DHR spray, for pressure control, is

l addressed in only one general operating procedure, Plant Cooldown. The

inspector concluded that operators had previously performed this

evolution without having an adequate procedure.

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Other statements were made by the SS and Operations Superintendent that

were of some concern to the inspector, such as:

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if . ...

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Ifjaction steps (such as ' egassingd the- RCS using DHR spray) are not

. included in a procedure (Plant Heatup), but also are not- prohibited

by~ that pro'cedure, it is still allowable for operators to perf orm '

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such. steps on safety equipment.

Individual : procedures do not ' stand on their .own; instead. plant

. conditions flow from one'. procedure (ie. Plant Cooldown) to' the .next

(ie. - Plant. Heatup). Therefore, while in one general' procedure

-(Plant Heatup), . the operators may' select and perform action steps

z(such as initiating DHR spray) from another . procedure (Plant

Cooldown) even though these steps. are not referenced from the main

(Plant 'Heatup) procedure in use.

The inspector expres,e a concern about operation of the plaht without .

using approved procs, -

He asked to see the licensee's rules on use

of procedures. The inspector reviewed administrative instruction'

AI-400E,' Performance and Transmittal of Procedures, Revision 1, and found

that it did address requirements that had to be met before a plant

operation could be performed without having.a procedure present. The

inspector discussed this further with' the Operations Superintendent, and

the licensee elected to initiate prompt corrective action .for operators

not adequately using procedures. This corrective action was in the form

of a written Short Term Instruction to operators, which emphasized and

clarified the administrative instruction. The Short Term Instruction

stated that either the operating procedure must be' present or the-

following conditions must be satisfied:

The steps must be routine procedural action that is frequently

repeated. Also, the procedure performer must have personally

performed or directly observed the applicable procedure steps within

a reasonable time period.

In addition, the procedure performer must be able to recall from

memory: the procedure steps, all aplicable limits and precautions,

and plant conditions required by the procedure.

The licensee issued the Short Term Instruction prior to the completion of

.this inspection. They stated that all operators will be required to read

and sign it as they go on shift. In addition, shift supervisors will

,

review it in pre-shift briefings to operators.

One violation was identified in this area.

5. Adequacy of Procedures (93702)

The ,0perations Superintendent stated that the licensee wanted to continue

the practice of degassing the RCS using DHR spray, with the unit in Mode 5.

The inspector reviewed OP-202, Plant Heatup, Rev. 80. The stated purpose

of the procedure is for plant heatup from cold shutdown or refueling

shutdown condition (Mode 5 or 6) to 532 degrees F (Mode 3). OP-202 does

not provide for degassing the RCS by using spray from DHR. It does address

degassing the RCS in Mode 4 with RCPs operating.

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The SS stated 'that OP-209, Plant Cooldown, Rev. 66 provided authority for-

degassing the RCS by- using spray from DHR while in Mooe 5. The

inspector found that OP-202 does not refer to 0P-209 for these steps.

The inspector reviewed OP-209 and found that it does - not rddress

degassing the RCS by using DHR spray. It does address use of DHR spray

for pressure control. During the plant cooldown, OP-209 directs

operators to align DHR cooling and to start a DHR train per OP-404.

OP-404 Decay Heat Removal System, Rev. 73 aligns pressurizer auxiliary

spray from DHR for operation. OP-209 then stops RCPs and presents two

notes:

NOTE: RCS pressure control is now through the use of pressurizer

heaters and auxiliary spray valve, RCV-53.

NOTE: Hot leg flashing may occur due to pressurizer outsurge to hot

leg caused by contraction from cooldown or pressurizer spray.

Neither OP-209 nor 0P-404 contains any conditions, cautions, or limits to

prevent heating the EFW piping and its containment penetration beyond

design limits or to prevent subjecting the A steam generator to

unanalyzed thermal stress. In fact, the A steam generator m6y have been

subjected to such unanalyzed thermal stresses in the past.

Throughout this event, the - applicable general operating . procedure was

OP-202, Plant Heatup, Rev. 80. Also, that procedure did not adequately

address using DHR pressurizer spray control to degas the RCS while in

Mode 5. The inadequacy of OP-202 to prevent heating the EFW piping and

containment penetration #424 beyond design limits and to prevent subjecting '

the A steam generator to unanalyzed thermal stresses is identified as as

an example of violation 302/89-14-01,

6. Physical Inspection of Affected Piping (93702)

Because the portions of the EFW line and the related containment penetra-

tion were heated above ' design temperatures, the inspector was concerned ,!

about possible damage to the piping, its respective supports, and the I

penetration. Therefore, the inspector performed a physical inspection of

the components that were potentially heated beyond design limits. These

included' the EFW line inside the Reactor Building from penetration 424 at l

elevation 118'-2" to the vertical run of pipe at elevation 112'-0", where l

pipe supports EFH-118A and EFH-119A attach to the pipe. In addition to  !

the two referenced supports; the pipe, the inboard portion of the

penetration, and pipe support EFH-115 were visually inspected by the

inspector for evidence of degradation, failure to function as designed,

and any other detrimental effects due to operation at elevated j

tempera tures. Although minor paint flaking and oxidation were noted on

the penetration and pipe support attachments, the inspector observed no

abnormalities.

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The inspector also visually inspected the EFW line outside the Reactor

Building from the penetration to the first pipe support, EFH-134, located

about 15 feet upstream of penetration 424. The inspector noted that the

chemical cleanup line, through which the steam generator recirculation

operation was conducted, discharges into the EFW line within two feet of

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penetration 424 via a removable spool piece and that there is a check

valve, FWV-44, immediately upstream to prevent flow from backing up into

the EFW line. Therefore, essentially the only section of the EFW line

outside the Reactor Building that was exposed to elevated temperatures

was the short length (less than three feet) between the check valve and

the penetration. As inside the Reactor Building, the inspector noted

similar. minor point flaking and oxidation on the penetration and pipe

support attachment, but no abnormalities.

One questionable practice was observed by the inspector during this

walkdown. That is, the removable spool piece had been placed onto a

Snistrut frame, CSI 95130, near where-it is normally used. It was held

in place by being tied to the unistrut by two large-gauge wires. Although

no safety-related equipment or piping was observed in the immediate

vicinity, a falling spool piece could nevertheless cause damage to itself

as well as adjacent piping, which could result in operational delays /

inconveniences. The' licensee agreed with this assessment and committed

to promptly remove the spoolpiece froth the plant. In additic the

licensee stated they would review procedures for spool piece L ,orary

storage requirements while in the plant, and for ensuring timely return

to the warehouse for controlled storage. This information will be reviewed

by the NRC Resident Inspector.

Also, as a result of the walkdown, the inspector noted that support EFH-74,

which appeared on orthographic drawing P-304-091, Revision 1, was not

installed. Further investigation determined that it had been deleted

per FCN No. 6A, written against MAR 88-07-11-02. The licensee had

performed the- work in the field, but the information had not been

incorporated into the appropriate orthographic drawing. The inspector

noted that technically the drawing which was to incorporate the latest

revisions had not been signed off. However, the licensee engineer

assisting the inspector expressed a high degree of confidence that the

latest drawing revision would show the support as being deleted and was

surprised to find that the deletion had not been incorporated. The

drawing had already been through several levels of review and the

licensee engineer felt the probability was high that this error would

have remained through final drawing approval and issuance. To assure that

this situation is rectified, the licensee issued FCR 11, written against

the above-referenced MAR and drawing. To assure that this case is

isolated and not symptomatic of a larger problem with control of design

documents, the licensee committed to reviewing a sample of 10 similar

recent design mo.iifications for piping restraints, to check for

completeness of incorporating new information in plant drawings. The

results of this review will be shown to the NRC Resident Inspector.

Pending completion of this review, this item is identified as

UNR 50-302/89-14-02.

7. Review of Engineering Evaluations (93702)

The inspector reviewed licensee engineering evaluations concerning the

affect of operating the EFW line at elevated temperatures and its

potential for system deg radation. He reviewed Calculation

No. 5510-716-PAC-2, which is part of the "EFW System Thermal Upgrade

Analysis", which assumes operating temperatures of 600 degrees F at the

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top of the steam generator to 200 degrees F at the inboard side of penetra-

tion'No. 424. The penetration consists of a 14" sleeve and 2" thick end

plate inside the Reactor Building. A 6" Schedule 160 process pipe passes

through the center of the sleeve and end plate. Welded lugs secure the

sleeve to the concrete containment wall. A 3/4" plate is welded on the

sleeve to provide a closure plate to facilitate testing of the penetration.

The 3/4" plate is not considered part of the containment boundary, and is

not -credited as a pipe support in the piping analysis. The analysis

included the supports for the EFW line inside the Reactor Building and the

calculations for the three supports inspected during the walkdown.

The inspector also reviewed calculation No. DC-5510-707.19.2, Revision 1,

entitled, " Penetration X-109 Investigation - Stress Evaluation," which

evaluated the structural effects on the penetration due to a temperature

gradient of 300 degrees F imposed on the process pipe. This calculation

was chosen for review by the inspector because this penetration is

identical to Penetration No. 424 and the temperature differential is much

more severe, It concluded that the 3/4" thick closure plate located on

the outboard end of penetration 109 was stressed beyond its elastic limit

into the plastic range. This mechanical behavior thereby relieved the-

thermal loads while assuring containment isolation via the 2" thick

plate, which remained in the elastic range. The inspector reviewed two

additional calculations, DC-5515-704.7,0-SE, Revision 0, entitled,

" Penetration No. 424 Elevated Temperatu re" and DC-5515-704. 7,0-P E,

Revision 0, entitled, " Penetration No. 424 Temperature Analysis." These

two calculations were initiated specifically to evaluate the high

temperature event identified on May 29, 1989. The logic used for these

two calculations is the same as that used for DC-5510-7/ / 7.19.2, for

penetration 109. The calculations concluded that the 3/4' thick closure

plate of Penetration No. 424 was stressed into the plastic range by the

elevated temperatures, allowing relief of the thermal stresses, while the

2" thick plate remained in the elastic range and continued to assure

containment isolation. The concrete adjacent to the penetration was not

adversely affected because the penetration temperature did not exceed the

guidelines of the American Concrete Institute as outlined in Appendix A

of ACI 349/359, which allows localized concrete temperatures adjacent to

penetrations to be 200 degrees F for long time periods and 350 degrees F

for short emergency periods.

The calculations all appeared to be professionally done, utilizing

applicable codes and standards, reasonable assumptions, and conservative

judgment. They concluded that no damage was done to the EFW piping, pipe

supports, or containment penetration 424.

FPC asked Babcock and Wilcox (B&W) to conduct an analysis regarding the

effects of the differential temperature on the "A" 0TSG. Specifically,

B&W was asked:

- Is there a differential growth between the "A" hot leg and the

OTSG/Rx Vessel that would cause any concern?

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- Is there a delta T concern across the OTSG axially or tube to shell

that is considered detrimental?

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- When secondary recirculation was in progress and downcomer

temperature was at 240 degrees F, was there a problem ecross the

lower tube sheet?

B&W responded verbally via telecom that due to the low power / temperature

levels at the time of the excursion, there were no detrimental effects.

However, they requested more time to undertake a more detailed evaluation

of the event. The licensee stated that they would review the

forth-coming information with the NRC Resident Inspector.

No violations or deviations were identified in this area.

8. Reporting of the Event (93702)

The inspector reviewed the licensee's reporting of this event to the NRC

for timeliness and adequacy. The discovery that EFW containment

penet ration 424 had been heated beyond its design temperature occurred at

0500 en May 29. The NRC was notified at 0951, four hours and fifty one

minutes later. The event was reported under the requirements of

10 CFR 50.72(b)(2)(1), which requires reporting within four hours. The

SS had completed the NCOR form on the event at 0600. He had decided that

no telephone report to the NRC was required, and had so indicated on the

NCOR. Later, at about 0945, a group of licensee management personnel

decided that the event was reportable and the 0951 phonecall to the NRC

was made. The inspector concluded that, since deportability requirements

for this event were not immediately clear and obvious, the timeliness of

the licensee's reporting was adequate.

The event was reported under 10 CFR 50.72(b)(2)(1), which requires the

reporting of:

Any event, found while the reactor is shut down, that, had it been

found while the reactor was in operation, would have resulted in the

nuclear power plant, including its principal safety barriers, being

seriously degraded or being in an unanalyzed condition that

significantly compromises plant safety.

The licensee's management group decided the event was reportable, because

it could have gone undetected. No plant procedures would have assured

the detection of the overheating of the EFW piping or the imposition of

unanalyzed thermal stresses on the A steam generator. The high RCS A

loop T hot reading was discovered by luck: an R0 was performing a PT

ahead of schedule. Thus the licensee could have potentially subsequently

operated the unit at power in an unanalyzed condition, without knowing

that possible damage or weakening had been done to the EFW piping,

containment penetration 424, or the A steam generator. Based on this I

conservative evaluation of the event, the licensee correctly classified

and reported it to the NRC.

No violations or deviations were identified in this area.

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9. Corrective Actions (93702)

The inspector assessed the corrective actions taken or planned by the

licensee at the time of this . inspection. The licensee had begun to

assess damages: they had performed a physical inspection of the

affected equipment and had initiated engineering evaluations for the

containment penetration and steam generator.

The licensee's identification of the root cause of the event, however,

was incomplete. They had determined that a problem existed with

operating procedures, but only for the unique situation of degassing the

RCS using DHR sprey while at the same time recirculating the secondary

side of the A steam generator. They had not identified the lack of

procedures for degassing the RCS using DHR spray nor the fact that this

evolution, and resultant unanalyzed thermal stresses on the A steam

generator, may have occurred previously. The licensee also had not

identified any weaknesses in operator use'of procedures in this event.

Insufficient time had elapsed for the licensee to complete a formal

investigation of the event. Nonetheless, the inspector found that the

licensee's initial investigation into the root cause of this event was

weak.

No violations or deviations were identified in this area.

10. Exit Interview (30703)

The inspection scope and findings were summarized on June 2,1989, with

those persons indicated in paragraph I above. The team described the

areas inspected and -discussed in detail the inspection results listed

below.

Item Number Status Description / Reference Paragraph

302/89-14-01 OPEN VIOLATION - Inadequate procedures and

failure to follow procedures, paragraphs

4. and 5.

302/89-14-02 OPEN UNRESOLVED - Control of drawings for pipe

supports, paragraph 6.

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ATTACHMENT 7

ACRONYMS-

ACI - American Concrete Institute

DC - Design Calculations

DHR - Decay Heat Removal

EFW - Emergency Feedwater

ENS - Emergency Notification System

EQ - Engineering Question

F - Farenheit

FCN - Field Change Notice

FCR - Field Change Request

FPC - Florida Power Company

MAR - Modification Approval Record

NCOR - Non Conformance Operating Report

NRC - Nuclear Regulatory Commission

OTSG - Once Through Steam Generator

PT - Performance Test

RCP - Reactor Coolant Pump

RCS - Reactor Coolant System

R0 - Reactor Operator

SS - Shift Supervisor

T - Temperature

.

1

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