IR 05000458/1989011

Insp Rept 50-458/89-11 on 890315-0430.Violations Noted.Major Areas Inspected:Plant Events,Operational Safety Verification,Maint & Surveillance Test Observation,Refueling Activities & Licensee Action on Previous Findings

ML20247Q990
Person / Time
Site:	River Bend
Issue date:	05/24/1989
From:	Constable G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20247Q966	List: IR 05000458/1989011 ML20247Q959 ML20247Q980
References
50-458-89-11, NUDOCS 8906070105
Preceding documents:	ML20006B226 (22 January 1990)
Download: ML20247Q990 (24)

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APPENDIX B u m U.S. NUCLEAR REGULATORY. COMMISSION n-REGION IV.

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NRC Inspection Report:

50_458/89-11 Operating License:

NPF-47:

l Docketi 50-458:

Licensee:

Gulf ~ States Utilities Company (GSU)

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P.O., Box 220 c*

St. Francisville, Louisiana 70775

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Facility'Name: : River Bend Station (RBS)

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' Inspection At: ~St. Francisville, Louisiana

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Irispection Conducted:

March 15 through April 30, 1989

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~ Inspectors:

E. J. Ford, Senior Resident Inspector W. B.: Jones, Resident Inspector.-

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Approved: _

k2/ 99 G. T., ConsraE e, Chief, Project Section C Date

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Division of Reactor Projects

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Inspection Summary

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Inspection Conducted March 15 through April 30,'1989 (Report 50-458/89-11)

Areas Inspected:

Routine, unannounced inspection of plant events, operational'

safety. verification, maintenance and surveillance test' observation,. refueling

a'ctivities, and licensee acti~on on previous inspection findings.

Results:

One potential violation (failure to take adequate corrective actions to ensure personnel and equipment protection,l paragraphs 3.a and 3.b)_was

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identified. This potential violation involves two examples where corrective actions taken did not prevent _ recurrence of. actions and events adverse to safety.

Specifically, repeated violations of the protective tagging program allowed conditions to exist which could have directly affected personnel and equipment safety. The~second example' involved a loss of shutdown cooling which could have been prevented -if corrective actions for a previous event had been adequately documented as a procedural requirement.

'g906070105 890531 PDR ADOCK 0500

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Operationi personnel demonstrated a good knowledge of plant systems and procedures as demonstrated by the quick recovery from four loss of shutdown

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cooling events and the loss of freeze seal event.

The need for additional attention to detail for both maintenance and radiological protection personnel became apparent in the performance of maintenance. tasks and surveying and control of contaminated areas.

Radiological controls over the invessel dive to repair the feedwater nozzles-were established and implemented.

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-5-DETAILS 1.

Persons Contacted GSU R. J. Backen, Supervisor, Operations Quality Assurance -(QA)

• J. E. Booker, Manager, Oversight E. M. Cargill, Supervisor, Radiation Programs

• J. W. Cook, Lead Environmental Analyst, Nuclear Licensing

• T. C. Crouse, Manager, Quality Assurance (QA)

J. C. Deddens, Senior Vice President, River Bend Nuclear Group

• D. R. Derbonne, Assistant Plant Manager, Maintenance R. G. Easlick, Supervisor, Radwaste

• L. A. England, Director, Nuclear Licensing A. O. Fredieu Supervisor, Operations P. E. Freehill, Outage Manager J. R. Hamilton, Director, Design Engineering

• G. K. Henry, Director, Quality Assurance Operations D. E. Jernigan, Instrumentation and Control Supervisor L. G. Johnson, Site Representative, Cajun V. J. Normand, Supervisor, Administrative Services

• W. H. Odell, Manager, Administration

• T. F. Plunkett, Plant Manager

• M. F. Sankovich, Manager, Engineering J. P. Schippert, Operations Engineer A. Soni, Supervisor, Environmental Qualification and Specification R. G. West, Supervisor, General Maintenance NRC

• D. D. Chamberlain, Chief, Prejet.ts Section A i

Tne NRC inspectors also interviewed additional licensee personnel during the inspection period.

• Denotes those persons that attended the exit interview conducted on May 5, 1989.

2.

Plant Status The licensee began their second refueling outate on March 15, 1989, at 12:55 a.m.

The reactor was placed in cold shutdown (Mode 4) on March IS, 1989, and the vessel head detensioned (Mode 5) 2 days later. Core alterations began on March 27, 1989, and were completed on April 7, 1989, with a total of 224 fuel assemblies replaced in the core.

There were four inadvertent loss of shutdown cooling events during this inspection period. No significant increase in reactor coolant temperature

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-6-was noted for any of the four events. On April 19, 1989, a freeze seal failed in a 6-inch service water pipe resulting in approximately 15,000 gallons of nonradioactive water spilling into the auxiliary building. This event is documented further in NRC Augmented Inspection Team Report 50-458/89-20.

The licensee identified the presence of loose parts in two of the four feedwater spargers. This required removal of a nozzle from each of the two spargers to facilitate removal of the loose parts. This finding is described in paragraph 3.f of this report and in NRC Inspection Report 50-458/89-17.

3.

Followup to Events (93702)

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During this inspection period, the NRC inspectors reviewed licensee condition reports (CRs) and 10.CFR 50.72 reports and held discussions with various plant personnel to ascertain the sequence, cause, and corrective action taken on selected events. A discussion of each of these selected evente is given below:

a.

Clearance Program The licensee's clearance program is documented in Administrative Procedure (ADM)-0027, " Protective Tagging." This procedure establishes the safety tagging system as an administrative control to prevent operation of components when such operation may cause personnel injury or equipment damage. During the previous month, there have been several procedural violations of the clearance program. These violations have involved workers performing maintenance on equipment under an incorrect clearance, maintenance on equipment without a clearance, and the removal of clearances with an

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applicable maintenance activity still angoing. A description of each of the clearance violations is given below:

March 18, 1989 - Maintenance personnel repaired an electrically

driven gear motor without the clearance having been checked and accepted by the requestor, (CR89-0221)

March 24, 1989 - STAR Air Conditioning personnel expanded the

scope of the work activity, which subsequently exceeded the boundaries established by the clearance.

(CR89-0263)

March 26, 1989 - A Stone and Webster (S&W) Projects person

closed a drain valve during a local leak rate test (LLRT) which was tagged open with a clearance.

(CR89-0280)

March 29, 1989 - An Anchor Darling Valve Company foreman

requested that the clearance be removed from a breaker from which the valve motor feed cables were lifted.

(CR89-0289)

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t-7-March 31, 1989 - Anchor Darling Valve Company maintenance

personnel disassembled a manual valve tagged in the open position without obtaining a partial clearcnce release to perform the activity.

(CR89-0305)

April 4,1989 - An Anchor Darling Valve Company foreman released!

a clearance although all the applicable maintenance activities were not complete. One valve downstream of the released valve was partially disassembled and interfaced with the primary system.

(CR89-0338)

April 6,1989 - A Cooper Services foreman released a clearance on the Division I diesel generator auxiliary systems although maintenance work activities were in progress.

(CR 89-0352)

April 10, 1989 - Cooper Services maintenance personnel began

removing the valve covers from the Division I diesel generator prior to the clearance tags being hung and accepted.

(CR 89-0390)

April 11, 1989 - An Anchor Darling Valve Company foreman reiease't the clearance before all applicable work packages had been completed.

(CR89-0407)

April 12,1989 - Licensee maintenance personnel removed a tagged open valve from a system without first obtaining a partial release.

(CR89-0408)

April 12, 1989 - An Anchor Darling Valve Company foreman released the clearance before all applicable work packages had been completed. This incident was almost identical to the April 11,1989, occurrence.

(CR89-0420)

The majority of the clearance violations involved contract personnel brought onsite to augment the maintenance staff during this second f

refueling outage.

Prior to the outage, contract personnel were given j

training on the clearance program and the foremen was authorized to i

request, accept, and release clearances. This action differs from j

the f;rst refueling outage in that only GSU plant staff personnel

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could request, accept, and release a clearance, i

On March 24, 1989, S&W Projects maintenance crews cut into the

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incorrect low pressure coolant injection (LPCI) test return line i

I inside the containment building. A stop work order was subsequently I

issued by operations quality control (0QC) against S&W Projects to evaluste the work activities being performed by this contractor. One j

of the contributing factors to this event was that the individuals

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involved were not familiar with the layout of RBS. After reviewing the clearance program violations up to March 25, 1989, operations quality assurance (00A) initiated a draft CR finding that the l

clearance program was not clear on requiring all maintenance work j

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-8-orders (MW0s)tobelistedontheapplicableclearance. This CR, however, was not issued because ADM-0027 does not require each MWO to be listed on the applicable clearance.

OQA responded to a request from the Manager-Oversight on April 3, 1989, to determine the reasons for the stop work and clearance violations. The licensee determined that personnel error was the root cause for each event.

On April 7,1989, following additional violations of the clearance program by two contractors, the OQA Supervisor met with the contractors' foremen to reiterate the clearance program. ' 0QA also met with outage management concerning releases of clearances and issued Memorandum 0QAS-89-076 to the contractors.

Senior plant management personnel also discussed the clearance program requirements with management representatives of the two contractors.

Following an additional event on April 10, 1989, 00A initiated Quality Assurance Finding Report (QAFR) 0-89-04-05 which identified inadequate training of personnel for two contractor groups regarding ADM-0027.

The Senior Vice President-Nuclear also contacted the president of one of the contractors to express GSU's concerns regarding the procedure violations. Because of QA's concern that additional clearance problems may still exist in the field, 00A along with QA Systems Audit and QA Engineering commenced a review of contractor MW0s and clearances on April 12, 1989.

Later that evening, a main steam line drain valve failed to properly stroke during the Division I emergency core cooling system (ECCS)

test.

It was subsequently discovered that the limit switch valve cover had been removed for an authorized MWO, however, the associated clearance had been cleared and the valve was energized. The NRC inspector discussed the significance of this as-found condition with outage management personnel.

On April 13, 1989, the outage maintenance manager initiated a stop work order after discussing the incident with the 00A-Supervisor.

The stop work order is documented in CR 89-0421. The corrective actions taken as a result of CR89-0421 included retraining of the two contractor personnel, issuance and release of clearances to designated GSU personnel, and the complete review of MWO packages to ensure proper clearance protection. Several additional MW0s were identified which were not listed on the applicable clearance.

The NRC inspectors began inquiring about the violations of the clearance program on April 7, 1989. The meeting between the 00A-bupervisor and the contractor foremen was attended by the NRC inspector. Although the intent of the clearance program was addressed, the presentation was not intended to provide additional training. QAFR 0-89-04-05, which was later issued on April 11, 1989, specifically addresses inadequate training of the contractor

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personnel. The licensee's corrective actions were directed at informing the contractor personnel that unacceptable clearance program violations were being committed, however, additional fonnal training programs were not provided until the afternoon of April 12, 1989, and the day of April 13, 1989. The corrective actions taken did not require an immediate review of MW0s in progress and the applicable clearance.

Evidence that the supplemental clearances issued to track each MWG on the original clearances were not complete was identified several days prior to issuance of the stop work order.

The licensee's failure to take adequate corrective actions to identify the status of each MWO and clearance, thereby ensuring that all personnel and equipment were adequately protected, was identified by the NRC inspector as an apparent violation (458/8911-01). The event on April 12, 1989, where the valve was energized but with an MWO authorizing work, illustrates the significance of ensuring the clearance program is effective.

On April 15, 1989, the licensee's 00A issued a stop work order on all maintenance activities because a clearance was being released while a supplemental clearance was still in effect. The tagging official had failed to note that there was an individual holding a supplement to the clearance. The licensee is reviewing all the open and closed clearances to ensure that no other clearances were released with a supplemental clearance still active. The licensee has also revised ADM-0027 to prohibit the use of supplemental clearances during refueling outages. This will result in each requestor for a clearance having to sign onto a new clearance.

b.

Loss of Shutdown Cooling During the current refueling outage, four conditions resulted in a loss of shutdown cooling (SDC).

(1) At 6:32 p.m. on March 25, 1989, the unit experienctid an inadvertent engineered safety features (ESF) actuation. This resulted in tripping the residual heat removal (RHR) Pump B and Division II isolation of SDC, main steam line (MSL) drains, and reactor water cleanup systems (RWCU). The unit was in Mode 5 at the time and RHR B was in use for shutdown cooling.

(The reactor had been shut down since March 15, 1989, for the unit's second refueling outage.)

The NRC inspector confirmed the use of Abnormal Operating Procedure (A0P)-0003, " Automatic Isolation," through discussions with the operators and log reviews. The purpose of A0F 0003 is to provide a method of assuring that system and building isolations have occuned and to provide guidance on priorities, cautions, and concerns with regard to restoring required systems to service. When an isolation occurs the operator ensures that a complete isolation has occurred, determines the cause of the

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isoluion, and then dete. mines which systems can safely be restored while maintaining isolation integrity. At 6:44 p.m.

the operators restarted the RMR B pump and reestablished shutdown cooling. Shutdown cooling was isolated for approximately 12 minutes, with no significant temperature increase.

The ESF actuation was associated with tagging out a 120VAC breaker (ISCH *PNL01B, Breaker No. 20) in a control room back panel fcr other authorized work. _When the breaker was opened, the Division II isolation logic isolated the previously mentioned systems..The cause was determined to be an inadequate load list (from a power loss effect card for the breakers in the panel). The information it supplied dit; not indicate that RHR isolation would occur.

To date. this is an isolated incident involving power loss effect cards. The licensee's corrective actions included:

(a) Briefing tagging officials and plant operutors of the

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incident with emphasis placed on carefully verifying i

supplied loads and logics.

l (b) The correction of the power loss effect card.

(c) The evaluation of other activities with the potential u isolate RHR SDC on a case-by-case basis with the shift supervisor.

Because this is an isolated incioent involving a deficient power loss effect card, and prompt corrective actions were taken, a violation is not appropriate.

(2) On Merch 29, 1989, at 11:10 p.m., the second loss of SDC occurred. The licensee was performing authorized work in a Division I transmitter cabinet in the control row. when an I&C technician bumped a temporary jumper causing a ground on the 125 VOC system. This resulted in a trip of the Division I reactor protection system (RPS) and the expected Division I isolations. This caused an isolation of the common RHR shutdown cooling line and trip of the RHR B pump.

The operators were able to correctly diegnore the cause of the isolation as a blown fuse in a timely manner, however, some delay in restoring cooling was experienced because of the need to get a replacement fuce from the warehouse, which is located outside the protected area.

Shutdown cooling was restored in 54 minutes. A temperature increase et the recirculation loops from 89'F to 95*F was noted. Discussions by the NRC inspector with. the plant manager and the I&C supervisor disclosed that, as a corrective action, a " retractable hook" jumper would be used i

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-11-in lieu of the " alligator clip" jumper which is prone to accidental removal. The licensee already has in place

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d>propriate devices for frequently jumpered points to preclude t11s type of problem.

In both the above cases, SDC was restored within the allowed one 1-hour technical specification (TS) limit (TS 3.9.11.1).

(3) On April 19.1989, at 12 midnight, a freeze seal failed on a 6-inch service water line resulting in flooding of the auxiliary ouilding 141-foot elevation and the subsequent loss of a i

I nonsafety-related electrical transformer and associateo loads.

This caused a loss of shutdown cooling when Division II RDS power was lost. Normal spent fuel pool (SFP) cooling and normal lighting in the auxiliary and reactor b9ildings were also lost.

Operators were able to restore shutdown cooling in'less than 15 minutes with no detectable rise in cooling water temperature.

An augmented inspection team (AIT) reviewed the loss of freeze seal event, its cause, and consequences. The AIT findings are available in NRC Inspection Report 50-459/69-20.

(4) While performing a surveillance (STP 508-4501) on April 27, 1989, electrical jumpers being used to provide signal input to a recorder from an instrument cabinet came apart at a taped junction. This caused an electrical transient (with an accompanying failure of the P694 Rosemount trip units) which resulted in closure of shutdown cooling isolation valve (IE12*MOVF008). Operators properly entered A0P-10 and restored shutdown cooling in 6 minutes.

In accordance with'the requirement of 10 CFR 50.72(6)(2)(11), e 4, hour, nonemergency, NRC phone notification was made. A 30-day licensee event. report is due May 27, 1989. The corrective actions of a previous incident (LER 87-029 reported that on November 19, 1987, an RRR isolation occurred due to inadvertent jumper grounding when taped together leads separated) required the use of long jumpers of the appropriate length rather than the taping of two short jumpera together with electrical tape.

RBS administrative controls require the responsible department to promptly initiate and document corrective actions. Furthermore, it is required that there be a datemination of actions necessary to preclude recurrence. Adequate licensee actions to preclude recurrence were not taken in that there was no procedural requiremer,t prohibiting the practice of + aping short leads together in lieu j

of fabricating a lead of the appropriate length.

The NPC i

inspector has identified this as the second example of an apparentviolation(459/8911-01).

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c.

Righ Drywell Temperature Issue On March 31, 1989, General Electric (GE) issued Rapid Information Communication Services Information Letter (RICSIL) No. 041. This RICSIL informs all BWR owners that higher than expected temperatures occurred in the upper drywell of a BWR/6 during its first operating cycle. Additionally, the NRC 1ssued Information Notice (IN) No. 89-30, "High Temper 6ture Environments at Huclear Power Plants,"

dated March 15, 1989. This IN was provided to alert licensees to potential problems resulting from high temperature environments in areas that contain safety-related equipment or electrical cables.

The NRC inspectors have made drywell entries and discussed licensee actions with cognizant engineers. The results of the licensee's investigations show that the affected plant experienced degradation of paint coatings, cracking of cable insulation, snubber damage, and temperatures that reached 350-400*F.

It was believed that the.

localized nature of the damage was due primarily to missing and damaged-insulation, which left a 2-3 inch gap in reactor vessel insulation. This insulation' condition was verified not to exist at RBS. The effected plant's drywell ventilation directs 2100 cubic feet per minute (CFM) to the vessel skirt; the RBS vessel skirt flow is approximately 20,000 CFM. A licensee walkdown of the drywell revealed there was some cracking and. stripping of flexible conduits

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apparently due to mechanical bending stresses.

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thermocouple and hydrogen igniter cables, but no nuclear the cables were in as-new condition (ped portions were flexible end instrumentation.) However, the strip i.e. no hardening or crumbling becauseoftemperatureorradiationdamage). The licensee reviewed the qualification of all EQ equipment and determined there was none in the area and the lowest thermal qualified life at 145*F is-34 years for resistancy temperature detectors (TS 3.6.2.6 limits dryweli bulk temperature to less than 145"F).

The licensee did observe some discoloration and f ailure of paint d

coatings on the ceiling of the drywell (anoroaching the vessel from the outer ritdius toward the refueling seal) near the main steam lines. The licensee is evaluating possible causes of this condition and the cracking of the flexible conduit. Additionally, the licensee intends to use installed equipment to record temperature data in l

Cycle 3 for trenoing.

The NRC inspector questioned the potential effects of failed coatings on ECCS samp screens. The licensee is analyzing the condition for l

any safety impact.

d.

Stop Work Directive (SWD 89-01)

workmen were told by(a contractor '28W foreman to On March 22, 1989, pull a 6-inch circulating water system CWS) valve (CWS V21-ARV 3C)

on the condenser bay east side (elevation 95-foot). This was the L

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wrong valve; workers uere to pull the A and B valves (only), as those waterboxes were dewatered and C was not. This resulted in 4000 to 5000 gallons of water going to radwaste via the floor drain system.

l Water on the turbine building floor at the 95-and 67-foot elevations j

was cleared by health physics as nonradioactive. The above. work l

involves a modification of the 'CWS for the addition of a sponge ball

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(condensertubecleaning) system.

On March 24, 1989, workers preparing to perform authorized work (the i

installation of a line orifice) on the Residual Heat Removal RHR A test return line, cut into the RHR B test return line by mistake.

l This error was due to an improper directive from the workers' field-i

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supervision. The licensee considered this a second "near miss" and issued an immediate stop work directive (SWD) (SWD-89-01). The stop work action applied to all ongoing work by S&W Projects Group at RBS.

(It did not apply to S&W Engineering Corporatfun (SWEC) persor:nel assigned as GSU staff augmentation or engaged in LLRT activities.)

SWEC'sreplytotheSWD(memodatedMarch 24,1989) cited the cause of the two problems to be similar - inadequate shift turnovers between supervisors and craft personnel in the second case, and communication breakdown between the craft foreman and mechanics in the first case. The specified corrective actions in the memo included:

(1) All work released MWO's in the possession of SWEC Projects have been revised for the addition of equipment identification hold points for QC verification regardless of QA Category.

In addition, all future MWO's, either Processed or assigneri to SWEC Projects, will be routed through QC for the same vartfication.

(2) Craft personnel will be required to attend a refresher course on their responsibilities under ADM-0028. This class will be instructed by a SWEC Planner and documented.

As a result of the above SWEC actions and additional quality activities undertaken by GSU supervisors of Operations QA and Operations 0C, an interim release for all SWEC Projects Group activities was granted on March 26, 1989.

Additional situations resulting in the issuance of stop work actions are discussed in paragraph 3.a.

e.

Service Water System During the first refueling outage, the NRC inspectors reviewed the licensee's actions on the service water system piping and heat

exchanger corrosion problem. This problem was identified uy the licensee during visual inspections of heat exchangers for the corbicula control progrcm. Certain auxiliary building unit coolers were found partially plugged because of the corrosion products. One unit cooler had to be chemically cleaned to reduce the tube blockage.

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i The licensee performed an engineering evaluation of the unit coolers for worst case heat removal degradation. Although some degradation j

was noted, all coolers were determined to be acceptable for operation to the second refueling outage. The licensee has instituted additional corrosion inhibitor controls.

The NRC inspectors observed several openings into the service water system as a result of planned and corrective maintenance activities.

It was observed that tFe buildup of corrosien products around containment isolation valve seats were preventing the valve discs from completely closing. This resulted in several valves failing their initial LLRT. The buildup of tubercules was also noted inside the service water piping and on several of the carbon steel components within tLa valve. The tubercules are characterized by an obter crust with an inner black deposit.

Independent laboratory analysis has identified the presence of microbiological growth. Thic appears to have resulted in at least some microbiological induced corrosion (MIC). Although corrosion products can be identified throughout the service water piping, the greatest corrosion attack has been within the pipe weld heat affected zone, in areas of low service water flow, and where dissimilar materials are joined. The pitting associated with the tubercules can range in size un to approximately 1-inch square with varying depth of penetration into the metal. tiltrasonic and radiograph examination of the service water piping indic6tes that some pitting has reduced wall thicknecs below the minimum wall allowed by specifications As a resuit of the NRC inspector's observations, a meeting was held with the licensee's management tc ascertair. the licensee's progran for further evaluating the conoition of the service water piping.

i This meetibg was held on March 22, 1989, and was attended by an NRC Regicn IV Division of Reactor Safety section chief. During this meeting, the licensee discussed their erosion / corrosion ronitoring program, e chemical control program which was instituted during the seccnd fuel cycle, and ct,rrective actions for problems which ha'd been identified to date. An additional briefing was held by the licensee on March 31, 1989, which further described their program for inspecting service water piping.

NRC nondestructive examination (NDE) perscnnel also performed radiography of one service water line to a safety-related unit cooler. The NDE results indie ;ed areas v

where greater than 50 percent through-wall corrosion had occurred.

On April 7,1989, NPC Region IV management held a meeting with the licensee to further discuss the licensee's program for identifying service water erosion / corrosion problems and tne licensee's plans for evaluation of the piping condition and subsequent corrective actions.

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Weekly status meetings are being held with the NRC inspectors to discuss the licensee's program findings for pipefittings and welds, heat exchanger inspections, dissimilar material joints and welds, valve inspection, leakage cor, trol system (LSV) compressor evaluation, end the standby cc,oling tower inspection.

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-15-An additional NRC management meeting will be held with the licensee in early May to discuss the licensee's findings and corrective actions which have resulted from the erosion / corrosion inspection program.

Service water system operability for Operational

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Conditions 1, 2, and 3 will also be discussed.

Further discussion of the service water system erosinn/ corrosion problem is given in NRC f

Inspection Report 50-458/89-16.

f.

Loose Parts in Feedwater Sparger In NRC Inspection Report 50-458/88-26, it was reported that the licensee had been investigating the cause of an alarm condition on the loose parts monitoring (LPM) system. The report stated:

"The system consists of eight piezoelectric sensors placed on the feedweter nc:'zles (2), the steam lines (2), the recirculation pump suctior, lines (2), and the control rod drive housings (2). Licensee discussions ar.d consultations with th-s vendor (8&W of Lynchburg, Virginia) of the IPM system have not produced definitive results with respect to the location of size, however, a small, locse part may exist in the vicinity of the feedwater sparger. Based on preliminary signal anslyses, continued operation was considered prudent in that the loose part was considered to be small in size and in a confined area that is free of small or fragile cemponents. Present analysis pcir.ts to the possibility of a chattering valve, a loose part that is swinging in the vicinity cf the feedwater line sensor, or a small loose part in the feedwater sparger, Among other actions, the licensee is working to establish the feasibility of using a boroscope and/or radiography to detect the size, location, and make up of the possible locse part during Refueling Outage Two. Additional actions and status of the situation is being monitored by the NRC inspectors."

The licensee's operator training ma. ' cal states:

"There are four (4) feedwater nozzle penetrations of the reactor vessel at an elevation of 483.5 inches. Thest penetrations, located at 90 degree intervals around the vessel, evenly distribute the feedwater in the mixing plenum (the area above the shroud head and above the downtomer annulus) through four (4)

feedwater spargers.

The feedwater sparsers are perforated

stainless steel headers that are shaped to conform to the vessel wall."

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"Feedwater entering the vessel through th? feedwater nozzle enters through the center of the spargers and is directed through the sparger around the vessel wall. Discharge nozzles in the sparger direct the feedwater radially inward and

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downward."

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Early in the second refueling outage, on approximately April 1,1989,-

the licensee used a remote undervlater camera to videotape and inspect all the feedwater spargers. The inspection revealed a damaged nozzle-I with a bolt-like object lodged inside the 45-degree sparger and another object was visible inside a nozzle of the 135-degree sparger.

The nozzle on the 45-degree sparger showed a golf ball sized hole at its elbow with grooved markings visible on the outward turned edges of the hole. The bolt-like object was threaded and appeared to be part of a larger object. The 135-degree sparger inspection revealed i

a trapped object which appeared to be a portion of a scaffolding clamp.

The licensee determined that it would be necessary to make an invessel dive to make repairs on the damaged nozzle and remove the objects from teth of the spargers. Accordingly, the licensee made i

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work preparations which included:

removal of the nozzles;.

retrieval of the foreign objects;

boroscopic examination of the inside of the sparger pipe; repair of the spargers after the nozzles were removed;

examination of the completed repairs;

radiological evaluation of the dive work area; and

diver safety evaluations.

• The NRC inspectors monitored the licensee's plans and preparations and reviewed the following documents prior to usage:

RadiationProtectionProcedure(RPP)-0224," Radiological

Precautions for Underwater Operations; pre-dive radiological surveys of the feedwater spargers and q

surrounding area; i

reactor feedwater sparger maintenance work order

package (MWO-R125630);

Additionally, extended NRC health physics coverage was provided and is discussed in NRC Inspection Report 50-458/89-17.

Nozzle removal, parts retrieval, boroscopic examinations, and sparger repair were conducted by Global Divers and Contractors, Inc., and supervised by GSU personnel. The divers were radiologically experienced comercial divers who had received licensee training on

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-17-i radiological conditions and hazards within the reactor vessel. Th'e licensee also required mock-up training which was conducted at en off site facility.

Examinations performed inside the 45-degree sparger af ter removal of the damaged nozzle did not reveal any significant damage to the sparger. A visual inspection of the object showed it to be an-eye-bolt and part of a scaffolding clamp.

It was necessary for the diver to cut up the objects in order to remove them from the sparger.

A water vacuum was used to remove debris generated during the cutting operation. Examinations were also conducted inside the 135-degree sparger after removing the nozzle in order to remove the slotted end cap portion of the scaffolding clamp.

It was noted that both of these spargers are fed from the same feedwater line.

After removal, the nozzles and scaffolding clamp pieces were removed to a storage area in the radwaste building and maintained there under radiological controls for engineering evaluation. An evaluation will be done to determine if all parts are accounted for and what, if any,

safety hazard may be present for continued operations. A special report will be issued by the licensee when the cvaluation is complete. Sparger repairs consisted of grinding the holes left by removal of the nozzles to a slightly larger, beveled size to accommodate a like-material plug which was welded in place. A weld inspection was conducted using the remote video camera. The licensee reported that the welds were determined to be acceptable and that the video record will be retained for future reference.

Two exampes of an apparent violation are identified in 3a and 3b above.

No additional violations or deviations were noted.

4.

Operational Safety Verification (71707)

The NRC inspectors continued to monitor control room activities and conduct during the refueling outage. The second refueling outage began on March 15, 1989, and is scheduled to be completed in May 1989. Control room activities and conduct were generally observed to be well controlled.

Proper control room staffing was maintained and access to the control room operational areas was controlled.

Selected shift turnover meetings were observed and it was found that information concerning plant status was being covered in each of these meetings. A concern was identified by the NRC inspectors regarding operators' knowledge of the location of each freeze seal and how the plant systems would be affected if the freeze seal was lost. An augmented inspection team (AIT) review of the loss of freeze seal event on April 18, 1989, is documented in NRC Inspection Report 50-458/89-20.

Plant tours were conducted and general plant cleanliness was indicative of the outage activities. Extensive cleanup efforts will be required to restore the plant to its normal good housekeeping state.

It was noted that the drywell contained excessive plastic sheeting which must now be

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-18-treated as contaminated waste. Contaminated areas by the step off pads were observed to be cluttered with potentially contaminated clothing on several occasions. The NRC inspectors also noted that material dropped into the suppression pool was not being accounted for or removed in a ticely manner during the first nart of this inspection period. The lack of control over materials in the suppression pool was discussed with licensee management. Prior to startup from the refueling outage, the licensee will scan the lower pool areas around the suction lines for each emergency core cooling system pump to determine what materials are present. Licensee personnel also inspect the pool surface area every 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and retrieve any floating material. A log of materials retrieved from the suppression pool is being maintained by the licensee.

General radiation protection practices were observed and no problems were noted. The NRC inspectors also reviewed several personnel contamination events which have occurred during the second refueling cutage.

Ir.

particular, the contamination event reports were reviewed for where the event occurred, the personnel areas contaminated, the radiation work permit (RWP) the individual was authorized to work under, and associated actions taken by radiation protection personnel. During this review, the NRC inspector noted that several individuals had been performing an authorized maintenance activity in an area which had been closed and was no longer considered a contaminated area. At least two individuals became contaminated on their clothes and hands because of contamination located approximately 4 feet above where they were working. The redletion protection survey which released the area was not adequately performed in that the contaminated area still existed. This apparent violation for failure to perform an adequate survey was identified to an NRC health physics inspector. This and other radiation protection potential violations are identified in NRC Inspection Report 50-458/89-17.

The NRC inspectors observed security activities in the central alarm station, secondary alarm station, and in the plant.

It was noted that alarms were being responded to as required. Plant parameter walkdowns were conducted and no problems were noted. The licensee is upgrading their security detection aids. Personr.el entry and exit from the protected area were observed, and no problems were noted.

5.

Maintenance Observations (62703)

During the inspection period, the NRC inspectors observed maintenance activities on the Division I diesel generator, inclined fuel transfer system (IFTS), reactor core isolation cooling (RCIC) system vacuum breaker, and the service water (SW) system piping and valves. The following MWO activities were observed.

a.

Division I Diesel Generator R-133331 This maintenance activity involved removal of the Division I diesel gererator (DG) turbo charger for inspection on March 21, 1989. The activity was performed

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Maintenance personnel were found to be cognizant of the steps involved in the maintenance activity and each step

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was signed off.

R-125594 During a postmaintenance run of the DG on April 10, 1989, the licensee noted an abnormal noise coming from a newly installed rocker am. The diesel was subsequently shut down and the valve covers remved.

It was discovered that the rocker am casting was contacting an adjacent push rod causing wear on both the push rod and rocker am. The clearance between the rocker arm and push rod is normally very close, however, the rocker arm casting.had excessive material by the push rod which resulted in the interference. Although the tolerances between the pivot point and push rod seats are precisely machined, the general castis,g is not. The rocker arm and push rod were replaced and the DG postmaintenance test completed satisfactorily.

b.

Inclined Fast Transfer System (IFTS)

R-126309 This corrective maintenance activity was perfomed on March 23, 1989, to replace the hydraulic directional control valve on the lower spent fuel pool IFTS hydraulic contml unit (HCU). The NRC inspecto noted that not all the personnel performing the maintenance activity had signed in on the MWD. Also, a drawing referenced in the MW0, GEK 83347, was not in the MWO package. After discussion with the maintenance personnel and the engineer observing the work, it was learned that the infomation available on the HCU is incomplete and that their experience with the system enabled them to safely work on the system.

c.

Reactor Core Isolation Coolino (RCIC) System P-524667 This preventive maintenance activity was performed on April 11,1989, utilizing preventive maintenance procedure PMP-1205, " Motor Operating Valve Routine Maintenance." Prior to beginning work on the RCIC turbine exhaust vacuum breaker (1E51*MOV77), the valve was tagged out of service and the MWO authorized to be worked by the

'

control operating foreman. The valve was functionally tested prior to being returned to service.

d.

Service Water System The NRC inspector observed maintenance activities on the following valves associated with the service water system.

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-20-l R-127173 Containment inboard isolation check valve (ISWP*V175) on-

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March 22, 1989.

R-112295 Division I auxiliary building unit cooler return isolation valve (ISWP*MOV171) on March 21, 1989.

h R-119033-Division II service water supply isolation valve

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L (1SWP*MOV778) to the Division III diesel generator jacket

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water cooler on April 7,1989.

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R-119035 Division II service water return isolation valve.

(ISWP*MOV5068) on April 7,1989. The NRC inspector.noted:

that the lifted lead log associated with the maintenance activity indicated the required leads-had been lifted, however, the performed by signature blocks had not been completed. This was discussed with the electrical foreman,

at which time the leads were verified to be' properly lifted and the signature blocks completed.

R-126509 Division I service water supply check valve (ISWP*V135) to the Division II jacket water cooler. performed on April 7, 1989.

R-126514 Division II service water return check valves (1SWP*V144)

l from the Division III jacket water cooler performed on

April 7,198s.

I For each of the service water valves listed above, corrective l

maintenance was required to restore the valves to an operable

!

condition.

In each case, corrosion products were preventing the valve discs from properly engaging the valve seat. -The ISWP*V175 valve and its associated outboard containment isolation valve required cleaning of the valve seats and replacement of the ISWP*V175 valve disc to successfully complete the local leak rate test.

Service Water Valves ISWP*MOV77B and ISWP*MOV506B, as well as the corresponding Division I isolation valves, were degraded such that the Division III diesel generator jacket water heat exchanger could not be isolated.

Further discussion of the service heater corrosion / erosion issue is given in paragraph 3.a of this report and in NRC Inspection Report 50-458/89-19.

The NRC inspectors discussed the lack of attention to detail l

demonstrated by several maintenance personnel with licensee management personnel. Similar findings have been identified by the licensee QA organization and identified in surveillance reports.

Additional management and QA oversight of maintenance activities is being provided.

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Surveillance Test Observation (61726)

During this inspection period, the NRC inspectors observed the performance of Surveillance Test Procedures (STP)-309-0601, " Division I 18-month ECCS Test," and STP-309-0603, " Division II 18-month ECCS Test."

STP-309-0601 was performed on April 14-17, 1989, to verify that the Division I DG and associated Low Pressure Core Spray (LPCS) and LPCI "A" systems met the following 18-month surveillance requirements:

'

the emergency busses deenergize and load shed on a loss of offsite power (LOP) in conjunction with an ECCS signal; the diesel generator auto starts and energizes the busses with

permanently connected loads within 10 seconds;

each automatic isolation valve actuates to its isolation position;

the automatic load timers sequence the loads onto the bus within plus or minus 10 percent of the design interval;

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the LPCS and LPCI "A" pumps activate and each automatic valve in the

flow path actuates to its correct position; Division I trip systems activate when required; the ECCS response time is within the limits established in TS Table 3.3.3.3; l

the containment unit coolers activate as required;

i a simulated ECCS signal with the DG operating in the test mode and

connected to the bus overrides the test mode and returns the DG to standby operation; the ECCS signal automatically energizes the emergency loads with

offsite power; the DG does not trip on a full load reject;

the DG starts on a loss of coolant accident signal but does not tie

onto the bus;

,

during an ECCS signal all DG trips are bypassed except engine

overspeed and generator differential current; and the DG can operate for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at loads between

3030-3130 kw without tripping.

The surveillance activities were well coordinated between the engineering, operations, and instrumentation and control (I&C) staff. The staff

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-22-briefing held prior to initiating the test was adequate to ensure all personnel were knowledgeable of their assigned duties. Upon initiation of the test, the "A" standby service water pump failed to start after the emergency diesel generator closed onto the bus. This was found to be because a test switch had been inadvertently bumped prior to the test beginning. The "A" standby service water system was manually initiated and all systems responded as expected. The licensee has generated several test exceptions as a result of this surveillance test. These exceptions are presently being reviewed by the licensee. The NRC inspectors will review the surveillance test data during this subsequent inspection period.

,

STP-309-0603 - This surveillance test was performed on April 25-27, 1989, to verify that the Division III diesel generator, high pressure core spray (HPCS) system, standby SW pump (ISWP*P2C) and the associated auxiliary systems met the following 18-month surveillance requirements:

system functional test of the HPCS system;

proper operation of the DG on a simulated LOP and loss of coolant

accident (LOCA);

verify total connected loads do not exceed 2600 kw and that the DG can operate for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> between 2750 and 2800 kw then 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> at 2500 to 2600 kw; and verify the DG can reject a load of 2500-2600 kw without tripping.

The NRC inspectors observed the surveillance activities from the main control room and DG local panel. The activities were well coordinated and system responses were as expected. One test exception was noted when the DG output breaker failed to close within 10 seconds of the buss voltage decaying to 90 percent of 160 kw on the LOP initiation signal. A retest of the D3 was performed on April 27, 1989, at which time the DG output breaker successfully closed within the required 10 seconds. The results of this surveillance test will be reviewed during the subsequent inspection period.

No violations or deviations were noted in this area of inspection.

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7.

Refuelino Activities (60710)

!

The licensee received 224 new fuel bundles between February 1 and 17, 1989, and commenced fuel movements on March P.7 completing a total of 1851 l

fuel movements on April 7,1989. This number is comprised of 1403 refuel floor moves and 448 fuel building moves. Core verification was performed on April 7 and showed.no errors. A reactor engineer assisted the licensed SRO who directly supervised all core alterations and fuel movements. in the reactor building. The official fuel movement work copy procedure was maintained on the refueling platform. An operator and spotter for the refueling platform were provided by GE. The control room's tagboard and

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infonnation copy of the fuel movement plant were maintained by a nuclear

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control operator (NCO). The NRC' inspectors discussed the NCO's responsibilities with the operator and observed refueling activities at various times.

During the refueling and ongoing activities, the NRC inspectors verified that:

refueling cavity and spent fuel pool water levels were in accordance

"

with TS requirements;

reactor mode switch was in the proper position; adequate decay heat removal flowrate existed (see paragraph 3 for.

loss of shut down cooling events);

radiation controls were proper (see paragraph 3 for invessel dives to

repair feedwater spargers); and equipment leckoat and tagging was in accordance with established procedures (see paragraph 3 for stop work order and clearance problems).

No violations or dev3tions were noted in this area of inspection.

8.

License Action on Previous Inspection Findings (92703)

(Closed) Open Item 458/8802-01:

Review of licensee actions to prevent future inadvertent siren actuations.

On April 29, 1989, the NRC inspector met witii licensee emergency preparedness personnel to review corrective actions that have been and that are to be taken to prevent future inadvertent actuation of emergency siren.

(1) The following corrective actions have been completed:

formalize Emergency Preparedness Procedures EPP-2-701, " Prompt

"

Notification System Parish EOC Control Disable Procedure," and EPP-2-702, " Prompt Notification System Individual Siren Disable Procedure," to require signoffs as each step is completed; require arming the siren at the RBS Emergency Op'. rating

Facility (EOF) before they can be activated at une different parishes Emergency Operating Centers (EOCs);

physically separate the station and microprocessor at West

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Feliciana Emergency Operations Center (WFEOC);

improve grounding and install radio frequency chokes at WFEOC

and remaining E0Cs;

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modify sirens to reduce susceptibility to storm related

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actuations; modify control software to provide security steps and sequences

for any group activation;

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procure.new computer hardware and software to improve

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maintenance and performance. The hardware and software is

% signed to fail into a safe condition and not actuate the sirens; and complete siren control and monitoring system testing.

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(2) The following corrective action is under review by the licensee:

,

install sequencing logic in each siren to require a 10 second

delay between receiving arm and either alert or silent test prior to powering the siren electronics.

This item is closed.

9.

Exit Intervie_w.

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An exit interview was conducted with licensee representatives identified in paragraph 1 on May 5, 1989. During this interview, the NRC inspector reviewed the scope and findings of the report.

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