IR 05000440/1990005

Insp Rept 50-440/90-05 on 900228-0416.Violations Noted. Major Areas Inspected:Evaluation of QA Program implementation,self-assessment Capability,Info Notice Followup,Ler Followup & ESF Walkdowns

ML20042G180
Person / Time
Site:	Perry
Issue date:	05/03/1990
From:	Patricia Pelke NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20042G178	List: IR 05000440/1990005 ML20042G177
References
50-440-90-05, 50-440-90-5, NUDOCS 9005110190
Download: ML20042G180 (30)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION III

Report No. 50-440/90005(DRP)

Dochet No. 50-440 License No. NPF-58 i

Licensee: Cleveland Electric Illuminating Company Post Office Box 5000

Cleveland, OH 44101

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Facility Name:

Perry Nuclear Power Plant, Unit 1 Inspection At:

Perry Site, Perry, Ohio Inspection Conducted:

February 28 through April 16, 1990

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Inspectors:

P. L. Hiland G. F. O'Dwyer S. Stssek B. Drouin

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Approved By:

P. R. Pelke, Acting Chief 5/

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Reactor Projects Section 3B Tate

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_I,nspect1on Surygry n

insp(etion on February 2B through Apri! 16,1990 (Report No. 50-440/90005(DOPj]

Xreas Inspected:

Routine, unannconced safety inspection by resident inspectors

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of licensee action on previous inspection items; evaluation of QA program

' implementation; evaluation of self-assessment capability; information notice followup; licensee event report followup; engineered safety feature walkdown; monthly suaveillance observation; monthly maintenance observations; operational safety verification; and onsite followup of events.

Results: Of the ten areas inspected, one violation for which a Notice of Violation was not issued, was identified in the area of licensee event report followup (paragraph 6.); two violations, for which Notices of Violation were-not issued were identified in the area of onsite followup of events (paragraph 11.b.5.).

As discussed in those paragraphs, the licensee met the criteria

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stated in 10 CFR 2, Appendix C, Section V.G.1 for not issuing a ' Notice of Violation. One Unresolved Item was identified in the area of maintenance observations (paragraph 9.b.) concerning the adequacy of maintenance controls /prioritization. The continued inoperability (6 months) of an emergency service water screen wash pump resulted in the licensee declaring an ALERT on April 3 when the redundant system failed.

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For this inspection-period, the area of plant operations was considered a

,Ni strength based on routine observations of plant evolutions and the inspectors

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review of operator response to events.

The area of maintenance and surveillance activities was considered adequate; however,-the inspectors identif.ied concerns with the adequacy of maintenance oversight that may have failed'to recognize the potential impact of degraded support equipment (paragraph 9.b.).

The inspectors considered the licensee's investigation and followup corrective action to events to be adequate with the appropriate level of management involvement.

In general, the inspectors considered the licensee's implementation of security and radiological control programs to be a strength based on routine observations throughout the inspection period.

The inspectors considered the licensee's emergency planning to be adequate based on observations made during.the April 3 ALERT declaration.

At the conclusion of.the report period, licensee management-was aware of the identified open items and were taking appropriate actions,

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DETAILS

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Persons Contacted

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Cleveland Electric Illuminating Company (CEI)-

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-A. Kaplan, Vice President, Nuclear Group

• M. Lyster, General Manager, Perry Plant Operations Department,

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(PPOD)

• D. Cobb, Senior Operations Coordinator, PP00 i

V. Concel, Mana'ger, Technical Section, Perry Plant Technical

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Department (PPTD)

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• W. Coleman, Manager, Operations Quality Section, Nuclear Quality-

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-Assurance Department (NQAD)

M. Gmyrek,-Manager, Operations Section, PP00 H. Hegrat, Compliance Engineer, Nuclear Support Department (NSD)

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S. Kensicki, Director, PPTD

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• R. Newkirk, Manager, Licensing and Compliance Section (NSD)

R. Stratman, Director, Nuclear Engineering Department (NED)

F. Stead, Director, NSD

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• D. Takacs, Acting Director, NQAD

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• M. Cohen, Manager Maintenance Section, PP0D

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U. S. Nuclear Regulatory Commission

• P. Hiland, Senior Resident Inspector, RIII

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G. O'Dwyer, Resident. Inspector, RIII

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T. Colburn, Perry Project Manager, NRR

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B. Drouin, Reactor Engineer, RIII S.. Stasek, Resident Inspector, Fermi, RIII

• Denotes those attending the exit meeting held on April _18, 1990, 2.

Licensee Action on Previous Inspection Findings (92701)(92702)

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a.

(Closed) Violation (440/89022-03(DRP)): -Inadequate Corrective l

Actions to Control Overtime. -As detailed-in the Diagnostic

. Evaluation Team (DET) report-for the Perry Nuclear Power Plant i

dated May 1989,. Section -3.2.2, the licensee was not adhering to-their administrative controls for approving overtime. A previous violation had been issued.in Inspection Report 50-440/88012 for

.similar problems with the licensee controlling plant personnel

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overtime.

Since the corrective an ion for the 1988 violation was not effective, the NRC staff issued the subject violation.

The-licensee responded to the subject-violation in letter

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PY-CEI/NRR-1071L,' dated October 11, 1989, in a timely manner. As stated in that response, the licensee revised Plant Administrative Procedure (PAP)-110, " Shift Staffing and Overtime," to clarify the use of overtime deviations.

In addition, the licensee provided training on the svchct violation to all managers and first line i

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E supervisors. Training of personnel affected by the revision to

' PAP-110 was conducted through the licensee's procedure revision-training process.

The root cause identified by the licensee for failure to implement

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established administrative controls over staff overtime was i

attributed to incomplete procedural compliance and inadequate I

procedural guidance (ref.: Audit 89-12, AR0002 rev. 1).

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inspectors concurred with the licensee's root cause assessment;

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however, existing procedural guidance appeared to have been adequate j

had strict compliance been required, t

In order to determine the effectiveness of the licensee's corrective action, the inspectors reviewed " time-cards" for all Operations j

Department personnel. The review covered the time fremes of

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January 1 through March 15, 1990.

In general, the inspectors noted j

licensee compliance with established overtime guidelines. A few (4)

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" Overtime Deviation Requests" were required during an unexpected

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' forced outage.

The inspectors noted that proper approval had been

obtained for those deviations.

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Based on the inspectors' review of the licensee's corrective actions

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taken in response to the subject violation and the inspectors'

verification that those corrective actions were effective, this item is closed, b.

(Closed) Open Item (440/89022-04(DRP)): Operator Aids.

As detailed in the Diagnostic Evaluation Team (DET) report for the Perry Nuclear

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Power Plant dated May 1989, Section 3.2.2, the licensee control of

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operator aids was not effective in ensuring their adequacy or

-accuracy.

The licensee responded to this item in letter

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PY-CEI/NRR-1043L dated July 29, 1989, Section 2.1.2.4, stating that:

j in addition to correcting specific operator aid deficiencies, a walkdown of all in plant control panels was to be conducted to j

identify other uncontrolled or inadequate operator aids.

Licensee memorandum.G. Chasko to M. Gmyrek dated December 21, 1989, l

stated'that a walkdown of all plant areas was completed.

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addition.to in plant control panels, the licensee expanded the scope-of the walkdown to include any hand-written component numbers or any

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" graffiti" ir the plant. The licensee stated that all handwritten

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i discrepancies had been removed and that permanent labels, where required, were being prepared for permanent plant installation.

During the report period, the inspectors performed a walkdown of

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control panels in the main control room and other safety-related i

buildings to verify completion of the licensee's response to this

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. item. The results of that walkdown indicated that the licensee was effectively controlling operator aids. Based on the actions taken

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by the licensee to improve control of operator aids and verification l

that actions were completed as stated by the licensee, this item is closed.

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(C.losed) Open Item (440/89022-08(DRP)):

Implementation of Corrective Actions. As detailed in the Diagnostic Evaluation Team (DET) report for the Perry Nuclear Power Plant dated May 1989, Section 3.2.8, the licensee's corrective actions following a 1988

"special evaluation" of root cause for personnel errors that had resulted in a number of reactor trips had not all been effectively

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implemented.

The licensee responded to the subject item in letter

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PY-CEI/NRR-1043L, dated July 29, 1989.

In that response, the licensee stated that a re-evaluation of the status of recommendations from their 1988 "special evaluation" would be performed.

The inspectors reviewed licensee memorandum M. Gmyrek to Operations Section dated December 27, 1989, which discussed licensee management actions that had been taken to specifically address all of the e

"special evaluation" report recommendations.

In addition, the

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memorandum detailed actions taken to improve communications between management and the operating crews.

The inspectors noted that each of the "special evaluation" recommendations was responded to by Operations Management.

Recommendations were incorporated if i

. appropriate; however, some recommendations were not incorporated

after licensee evaluation.

The basis for not incorporating

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recommendations was clearly stated or was an obvious management prerogative.

In addition, the inspectors reviewed licensee actions to improve communication within the Operations Section.

Based on review of Operations Management responses to operator problems and/or concerns that had been expressed at " Management-Operator" i

meetings, the inspectors concluded that, as stated in the licensee's i

response to the subject item, improvements in communications had I

been made.

The inspectors also noted through routine review of l

" Daily Instructions" that the Superintendent of Plant Operations was.

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effectively communicating and responding to issues and concerns generated within the plant Operations Department.

n Based on the actions taken by the licensee to re-evaluate recommendations from their 1988 "special evaluation," this-item is

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closed.

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(0 pen) Open Item (440/89022-10(DRP)):

Equipment Trend Analysis.

As detailed in the Diagnostic. Evaluation Team (DET) report for the Perry Nuclear Power Plant dated May 1989, Section 3.3.6, the

inspectors considered the licensee's effectiveness in equipment trending based on maintenance history to be diminished due to incomplete maintenance history records. - The licensee responded to

this item in letter PY-CEI/NRR-1043L dated July 29, 1989.

In that

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response, the licensee stated that their Reliability Information Tracking System (RITS) would be implemented during the fourth

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quarter of_1989. That-system implementation was intended to improve the quality and quantity of root cause/ failure analysis.

Licensee memorandum J. Register to E. Root, dated January 3,1990, l

stated that the RITS program was incorporated into the licensee's

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In addition training was provided to potential

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-RIT! users and a " users'" manual was published and issued as a

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controlled document.

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~However, the inspectors noted that audit Action Request PA90006-001 dated April 3, 1990, was initiated by the licensee to establish

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required administrative controls over the RITS program.

This item w111' remain open pending the inspectors review of the licensee's

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I response to that audit action request.

(Closed)' Unresolved Item (440/89022-16(DRP)):' Vacuum Breaker I

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' Surveillance Testing. As detailed in the Diagnostic Evaluation t

. Team (DET) report for the Perry Nuclear Power Plant dated May

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E 1989, Section 3.4.2, the inspectors concluded that Surveillance

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Instruction (SVI)-M16-T0414 was technically deficient.

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conclusion was based on the fact that the subject surveillance

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instruction directed that drywell vacuum breakers be opened-

with their power operators before relief settings were measured

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and verified. The licensee responded to this item in letter

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PY-CEI/NRR-1043L, dated July 29, 1989, stating that "as-found" i

setpoints were not adversely affected by first cycling the-drywell vacuum breakers with their power operators.

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Although the licensee provided a reasonable technical'b' asis for I

their "no-impact" on as-found data conclusion, further review with the inspectors and cognitive licensee personnel noted that approved changes to the licensee's Inservice Test Program required full

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stroke of the drywell vacuum breakers at least once per 18 months'

with the plant in COLD SHUTDOWN.

Therefore, the need to equalize

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pressure across the vacuum breakers could be accomplished by.other means than pre-exercising.

The licensee revised.-SVI-M16-T0414, revision 2, via temporary change number 4, dated December 28,~1989.

That change incorporated instructions to' lock-open the drywell

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airlocks (normal cold shutdown _ condition) and to open the-vacuum

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breaker isolation valves.

Those.procedura1cinstructions would allow'

i vacuum breaker pressure equalization,without the need to j

pre-exercise.

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Based on the licensee's-actions to revise the surveillance instruction such.that as-found data would be accurately obtained, this unresolved item is closed.

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(Closed) Open Item (440/89022-17(ORP)); Work Package Rejection Rate. As detailed in.the Diagnostic Evaluation Team (DET) report for the Perry Nuclear Power Plant dated.May'1989, Section 3.5.4, the inspectors concluded that a continued large work order rejection rate was due to a lack of management attention.

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The anspectors reviewed licensee memoranda E. Parker to D. Graneto,

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dated May 16, June 14, July 24,1989, and licensee memorandum

.j L. Minter to M. Cohen dated December 5, 1989.

The subject of those memoranda was the evaluation and analysis for work order rejection rates between April 1 and October 31, 1989. The work order

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rejection rates were reduced from the DET reported high of 32' percent.

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to 3 to.9 percent, except;for the' month-of July 1989, which _had a 16 percent work order rejection rate.

The inspectors considered the continued lower work order rejection rate sufficient indication that adequate licensee management

attention was devoted to improving the work order process.

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item is, closed.

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(Closed) Open-Item (440/89022-18(DRP)): Root Cause Analysis a

Program. As detailed in the Diagnostic Evaluation Team (DET)

report for the Perry Nuclear Power Plant dated May 1989, L

Sections 3.5.7 and 3.6.8, the inspectors concluded that several weaknesses in the licensee's root cause analysis program existed.

The. licensee responded to this item in letter PY-CEI/NRR-1043L

. dated July 29, 1989.

The response detailed the licensee's initiatives for improving root cause analysis, timeliness-of corrective actions, and equipment failure analysis.

As detailed in licensee memorandum D. Conran to H. Hegrat dated.

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February 9, 1990, the licensee's enhancements to improve corrective

. action effectiveness since January 1988 included-the following:

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s (1) Enhanced documentation in work orders.

t (2) Establishment of an Incident Response Team.

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(3) Engineers, Maintenance Planners, Supervisor and Event h

Investigators trained in HPES, MORT and K-T Techniques.

(4) Condition Report Program' enhancements which included:

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(a). Lowerin'g the threshold for condition report initiation.

(b) Emphasizing corrective action effectiveness.

(c). Improving CR/LER trending.

-(5) Maintenance Self Assessment which also identified, established, and/or enhanced:

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(a) Quality of documentation.

(b) Trending and problem identification.

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(c) Thirteen week Rolling Schedule,

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(d) Functional-equipment grouping codes.

(e) Plant System Status Report,

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(f) Work order categories / priorities.

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(g) Forced outage ready to work list.

(h) Automatic Tag-Out System (partially implemented, but still under development).

(i) Outage critiques.

(6) Implementation of Reliability Information and Tracking System

(RITS) used to trend data from corrective maintenance.

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(7) Improved status feedback mechanisms.

(8) Training on initiation criteria.

Since the DET report was issued in May 1989, the inspectors have observed / reviewed several of the above corrective action enhancements (Ref:

Inspection Reports (IR) 50-440/89017, /89023,

/89026, and /90002). Work orders reviewed during numerous maintenance inspections were found to contain adequate documentation.

Effectiveness of the licensee's " Incident Response Team" was considered adequate during the inspectors followup review of a January 7,1990, reactor trip (Ref:

IR50-440/90002).

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inspectors review of licensee event reports, condition reports,

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action requests, and licensee responses to NRC Notice of Violations or Deviations. indicated adequate training of investigators and a reasonable threshold for initiating corrective action.

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The inspectors reviewed the licensee's third and fourth (draft)

quarter 1989 report for condition report and licensee event report trends. Those reports appeared comprehensive and critical of negative trends. The inspectors noted that those quarterly trend repcrts received appropriate level.of licensee management review with assignment of recommendations to the responsibio section.

Status of previous recommendations was included in the trend report.

The inspectors observed on goir.g maintenance self assessment by reviewing daily maintenance activities, planned maintenance activities in the licensee's thirteen week rolling schedule, and through review of the first refuel outage critique and the January 1990 forced outage critique.

In general, the: inspectors considered the maintenance self assessments'to be adequate with a clear goal of improving maintenance activities to better support overall plant

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In addition, the inspectors noted that the Reliability-Information System was implemented.

However the inspectors noted that adequate attention to prompt corrective maintenance on an.

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t emergency service water screen wash pump may have led to an ALERT declaration on April 3,1990, as discussed below in paragraphs 9.b and 11.b.(2).

Based on the inspectors observations and review of the licensee's corrective action and root cause analysis programs as discussed above, this item is closed.

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(0 pen) Open Item (440/89022-19(DRP)):

Independent Safety Engineering Group (ISEG), As detailed in the Diagnostic Evaluation Team (DET) report for the Perry Nuclear Power Plant dated May 1989,

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the inspectors concluded that the ISEG had. limited effectiveness due to a lack of management attention and support.

The licensee responded to this item in letter PY-CEI/NRR-1043L dated July 29, 1989.

That response stated that a new ISEG " charter" was to be in place in 1989.

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Appendix B, Revision-2, of-the Perry Nuclear Power Plant Quality Assurance Plan,'" Independent Safety Engineering Group Charter," was, issued on November 6, 1989.

The inspectors noted.that the revised charter defined the function, composition, and responsibilities _of ISEG and met the_ requirements of Technical Specification 6.2.3.

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-inspectors reviewed several ISEG reports-(89-005,89-007, 89-009, and 90-002) since'the licensee revised the ISEG charter;;however, the inspectors had not completed a review of the ISEG effectiveness in _accordance with Inspection Manual procedure 40500, " Evaluation of Licensee Self. Assessment-Capability." This item will remain open pending the inspectors further review of ISEG effectiveness.

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(Closed) Open Item (440/88020-03(DRP)):

Loss of All Rod Position Indication.. This item was previously reviewed by the inspectors in Inspection Report 50-440/89017(DRP),. dated August 18, 1989, paragraph 2.h.

At the. time of that review, the inspectors noted.

actions taken by the licensee to proceduralize methods of_ obtaining.-

control rod position -indication following loss of a power supply.

However,-the inspectors ~did not document or discuss with. licensee management staff expectations that Technical Specification action.

statements be adhered to regardless of the existence of an alternate:

method of determining control rod position.

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NRR memorandum M..Virgilio to E. Greenman dated March 20, 1989, clarified the staff's. expectations on actions to be taken by the-licensee in response to the. inspectors questions.following a'.

December 12, 1938, event at Perry.

During that event, a 5-volt DC power supply was _ lost resulting in a-loss of the~ rod display module (RDM) and the operator control-module (OCM):(Ref:- ' Inspection Report 50-440/88020, paragraph 7.b.(2)).

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For the December 12, 1988-event, the loss of both-~the RDM and OCM

?resulted in the inoperability of_the rod position indication system-(RPIS) and the rod control and'information system (RCIS), respectively.

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Under these conditions, normal insertion / withdrawal of control' rods

was not-possible. Control rods could be inserted by a manual or.

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automatic scram.

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L First, since Technical Specifications indicated that control rod

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insertion was required in lieu of "no-action'! when accompanied by a

loss of all-rod position indication, the inspectors requested a

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i clarification from the NRC staff..The followi.1g'was provided:

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"Before responding to Region III's concerns, a brief j

discussion of the intent of the two applicable Specifications-

is pertinent.

The intent of Specification 3.1.3.1 is that all _.

I (or nearly all) control rods should be operable. The intent of i

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Specification 3.1.3.5 is that at least one RPIS should be.

operable or that a control rod with an intperable position'

. indicator should be moved to'a position with an operable

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position indicator.

The Basis for these two Specifications states that the occurrence of eight (or more) inoperable control rods could be indicative of a generic problem and the

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reactor must be shut down (emphasis added) for investigation

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and resolution of the problem.

The Perry event was an unusual

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event that, among other things, clearly resulted in more than

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eight inoperable control rods.

In fact, all of the control t

rods were inoperable.

Therefore, entering Action Statement c of Specification 3.1.3.1 would have led to the reactor being placed in at least Hot Shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This result would meet, therefore, both tne scope and intent of the two applicable Specifications.

For the Perry event, it is not obvious that control rods could not or did not receive erroneous insert or withdrawal signals from the failed systems (the RDM, the OCM, the RPIS and the

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RCIS). Thus, the exact state of the~ reactor was not absolutely known during the event.

On this basis,.NRR cannot recommend a no-action position, that is, leaving the reactor in its assumed pre-event position.

In fact, if control rods had moved because.

i of erroneous signals, the no-action position could cause fuel

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thermal limits to be exceeded so that fuel failures could possibly result. The Technical Specification position is clearly the preferred position because it places the reactor'in a known, safe condition.

Here we have no evidence that the i

failed systems would affect the trip function of the Reactor Protection System or the scrammability of the control rods.

If they did, this event would be an ATWS precursor. The e

disadvantage of tripping the reactor is, of course, the challenge to safety systems. All things considered we advise against the no-action position and prefer the Technical Specification position.

In addition, we conclude that a.

reactor trip is not unconservative and that the subsequent potential for stuck rods and out-of-sequence rod movement that could result in hot spots and potential core damage should not-be of concern.

However, for a. Perry type-of event., we suggest a possible modification to the Technical Specification position if the' action statement has been entered to bring the reactor to the Hot Shutdown condition within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This possible modification is to reduce power by reducing recirculation flow, consistent with the applicable flow control' line and stability-restrictions, if a portion of the 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is used to perform trouble-shooting before bringing the reactor to a Hot Shutdown condition. This reduction in power without resorting to i

control rod movement has the advantage of ' ensuring ample margin to the thermal limits."

Second, during the December 12, 1988 event, the licensee was able to obtain control rod positions off of control room back panels on a rod-by-rod basis.

The inspectors requested clarification if the rod position obtained from the back panel readings was sufficient for L

not entering Action Statement of Technical Specification 3.1.3.5 or exiting the Action Statement once operators were setup to monitor back panel rod indication.

The following was provided:

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"Our response to the second of Region-III's two concerns is straightforwa rd.

It is not permissible, as the Specification l

is now written, to obtain rod position indication by back panel

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readings on a rod-by-rod basis to prevent entering the Action Statement of Specification 3.1.3.5 or to allow exiting the Action Statement once operators are setup to monitor back panal rod, indication.

In this instance, restoration of the normal rod: position indication is required. However, credit could be taken for using the back panel as an alternative method for

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obtaining rod position indication if a licensee followed the usual procedures for modifying Technical Specifications.

This means that the licensee would have to (1) evaluate the back panel' as an alternate means of rod position indication including establishing a time. interval for performing the rod

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position readings and the-development of procedures, and P

(2) submit the evaluation and a proposed Technical Specification modification to the NRC.

If an evaluation led to

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a-favorable Safety Evaluation, the NRC would issue a license

amendment authorizing the use of the back panel as an alternative means for determining rod position for Specification 3.1.3.5.

It should be noted that for the loss ofL the 5 volt DC power j

supply, this would only permit exiting TS 3,1.3.5, the LC0 and -

t-associated ACTION STATEMENTS of TS 3.1.3.1 would still apply."-

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The. inspectors discussed the above clarifications and recommendations-

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with the Manager Plant Operations during the report period..This j

item is closed.

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No Violations or deviations were identified.

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3.

Evaluation of Licensee Quality Assurance Program Implementation (35502)

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To evaluate licensee Quality Assurance (QA) program implementation, the

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inspectors conducted an in-office analysis of-previous NRC inspection i

. reports, SALP. reports, licensee corrective actions for NRC' inspection findings, and licensee event reports (LERs).

Based.on the inspector's review, Region III management determined that no

significant weaknesses existed in licensee QA program implementation j

which warranted special regional followup during the remainder of the.

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SALP 10 period.

However, several weaknesses were identified during.the in-of fice review which will receive. continued NRC~ scrutiny during the.

j SALP 10 period.

The weaknesses are described below:

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Poor communications among plant staff had been a contributing factor to several plant events during the period that was reviewed.

Recent.

.j examples; included a November 25, 1989, lack of communications.

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technical advisors which delayed the correct-analysis of failed

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scram time test results for control rod 34-47 for approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

Poor communications between plant and reactor operators on

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January 31, 1990, resulted in the failure to un-isolate loop seal

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level _ instrumentation, the subsequent overpressurization of the loop seal, and an Offgas System transient.

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b.

Maintenance and Surveillance activities were involved in 16 of 32 LERs in 1989 and' 3 of 4 LERs in 1990. -- Personnel error inattention

to detail was the cause of several maintenance / surveillance errors.

Examples of personnel errors were:

(1) maintenance personnel removed the wrong fuses which caused the loss of control power.to the turbine driven feedwater pumps and resulted in a reactor scram

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'on low level (LER 90001); and (2) control power transformer to the

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"A" emergency service water (ESW) discharge valve was burned out during the performance of a surveillance when technicians jumpered

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the wrong terminals resulting in the inoperability of "A" ESW system (LER 89027).

Inattention to detail was evidenced by several inadequate surveillance instructions (SVI) or inadequate SVI.

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revisions. Examples include:

(1) poor SVI revision led to the isolation of the RCIC steam supply valve during the performance of a surveillance on the leak detection system logic (LER 89003);(2)a.

procedural deficiency resulted in incorrect' ca'11bration of the scram discharge volume water level high channel (LER 89022) 'and the-inappropriate Division 2 under-voltage time delay relay settings (LER 89021); (3) motor operated valves were not stroked open/ closed as_'

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required (LER 90003) resulting in an entry into Technical Specification (TS) 3.0.3; and (4) Unit 2. snubbers were not included in required snubber surveillances (LER 90004).

There were also several examples of plant staff performing activities without being fully aware of impacting. plant conditions which resulted in plant events. - The isolation of drywell (DW)

instrument air to perform maintenance on the DW personnel air lock resulted-in the closure of three of four niain steam isolation valves'

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'on June 27, 1989 (Inspection Report'No. 440/89017(DRP)).

Maintenance personnel isolated an alternate radiological process

sampler to. perform troubleshooting on the permanently. installed process sanpl u.

The alternate sampler was raquired to be available

,by Technical? Specification when the permanent sampler was inoperable (LER 89029).

Maintenance personnel transferred an Automatic Bus

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Transfer'(ABT) device from its emergency to normal supply, which was providing power to "A" RPS alternate bus.

RPS bus "A" was utilizing its alternate power source,.and "B" RPS bus was deenergized for

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maintenance.

The transfer of the ABT caused'a momentary loss of power'to the Balance of Plant (BOP) isolation relays supplied by the "A" RPS bus, which resulted in an outboard BOP isolation (LER 89012).

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~A concern about the thoroughness and timeliness of licensee technical submittals to the NRC was not'ed in the SALP 8 and 9 reports.

Recently, the NRC experienced some problems with the licensee's initial Technical Specification change request (RCIC Delta-T) in February 1990.

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y The licensee's communications and maintenance / surveillance weaknesses described above will be monitored by the NRC during routine inspections

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-for the purpose of early trend identification, i

Any violation of NRC requirements resulting from the events described

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above were noted in appropriate NRC inspection reports.

No violations were identified as a result of the in-office review.

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4.

Evaluation of Licensee Self-Assessment Capability __(f 0500)

During-the report period, the inspectors observed several on-site review committee meetingb to evaluate that organization's effectiveness.

For the meetings attended, the inspectors considered one of more of the following attributes:- degree of plant management involvement and/or domination of conversations; if constructive discussion occurred; if the

majority of the committee consistently voted the same as the chairman; if the committee was biased toward operation or safety; and, if the committee used design basis, FSAR, or vendor technical manuals for their determinations. in addition to the technical specifications.

The inspectors attended on-site review committee meetings90-024 (March 8),90-027 (March 27),90-028 (March 22), and 90-029 (March 29).

In preparation for the attended meetings, the inspectors

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reviewed draft submittals of items that were submitted for the on-site

committee approval.- Items presented to the on-site review committee included safety evaluations, licensee event reports, proposed revisions to~

l technical specifications, licensee condition reports, temporary changes to procedures, scram report 1-90-1, procedural revisions, and design change packages.

The inspcctors no'ted that the required quorum of committee members were present'for each meeting observed. The meetings were conducted-in a professional. manner.following an approved agenda.

Each item presented'

to the committee was'done so by'a cognizant individual (sponsor) who

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remained available to answer committee members questions.' The inspectors.

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noted that committee: members conducted constructive discussions free from any influence by a single-individual or line organization.

For the meetings. attended, the inspectors noted that items approved were done so by a unanimous vote of committee members.

Items that were not acceptable to-a_ll committee members were " tabled" until outstanding.

questions and/or. concerns were resolved.

The inspectors noted that the

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committee used various technical information and did not rely solely on technical. specifications and the judgement of management in their-deliberations.

Based on the inspectors observations of items rejected or " tabled" at the

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attended meetings, the-inspectors concluded that the on-site committee viewed plant safety as a primary concern. The inspectors concluded the on-site review committee was effectively implementing the requirements of technical specifications.

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U No violations or deviations were identified.

F 5.

NRC Information Notice Followup (92701)

p During the report period, the inspectors. performed-a review of licensee-actions related to selected Information Notices issued by the Office of-Nuclear. Reactor Regulation.

The review included verification that each information notice was-reviewed for applicability; the'information

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notices received proper distribution to appropriate personnel; and if

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applicable, the scheduling of appropriate corrective action was completed.-

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(0 pen) Information._ Notice N_o. 88-24 -(4Ft/88024-IN):

Failure of Air:

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Operated Valves Af fecting Safety Related Systeu.

The subject information-Notice (IN) dated May 13, 1988, was received-by the licensee _on May 23, 1988.. In accordance with the_ licensee's

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administrative controls, the subject IN was distributed to _the I&C Mechanical department for review.

That review concluded.that the referenced ASCO model solenoids were' not in use at Perry.

Since some' application problems with other model ASCO valves-were identified at a similar RIII facility, the inspectors requested the licensee to_ review their safety-related solenoid valve-application again.

That' additional evaluation' focused on the maximum operating. pressure

. differential (MOPD)_that.ASCO-solenoids were designed for compared to the normal operating instrument air pressure of 120 psig._ Two valves (1833-F419 and -F420) were identified where their M0PD of

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110 psig was.below the normal instrument air pressure.1 The licensee-concluded that-those two " sample valves" could fail with no impact on safe' shutdown capabilities.of~the system or plant. The

. inspectors requested the licensee to continue-and broaden their review process to assure that other safety-related solenoid valves-(not limited to ASCO) were not subject to the concerns identified in.

the-subject IN. At.the conclusion of the report period, that.

additional review was still in' progress.

This item will remain open pending the_ inspectors review of the-licensee's completed actions.

b.

(Closed) Information Notice No. 90-18 (440/90018-IN):

Potential i

Problems With Crosby Safety Relief Valves Used On Diesel Generator

~i Air Start. Receiver Tanks.

The subject information notice (IN) was issued on-March 9,1990, and

was initiated in part from an event that occurred at the Perry

'z Nuclear Power plant. As documented in licensee Condition Report'

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(CR)89-060, dated February 19, 1989, the Division 1 emergency diesel generator (EDG) air receiver tank relief valves inadvertently

]4 actuated after mechanical agitation.. During the licensee's investigation it was-identified that the installed Crosby relief valves had not been seismically qualified since the system designer, (

Transamerica Delaval, considered that component to be mechanically

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Based on'the event occurrence, the licensee reclassified'

the relief valves as active components and performed seismic

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. qualification tests, The licensee did not consider the identified relief. valve deficiency

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to be reportable under the provisions of 10 CFR 21; however, I

licensee letter PY "T" S0-5445, dated March 13,- 1989, advised the current responsible organization, Cooper Industries, of the event and identified corrective actions taken or planned. As stated in.

F the subject IN, Cooper Industries submitted a 10 CFR 3 report on

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January 17, 1990.

Licensee letter PY-CEI/NRR-1043L, Section 2.1.6.8, dated July 29, f

1989, detailed corrective actions taken and planned for_the EDG

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relief valves'.in response to an NRC' Diagnostic Evaluation Team (DET)

report dated May 1989.

During this report' period, the inspectors

reviewed the current status of corrective actions with cognizant-licensee personnel.

The subject IN indicated that a single _ relief valve actuation caused both of the redundant Division I air receiver tanks to-depressurize.-

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Asldocumented in CR 89-060, the sequence of events were:

. While a plant operator was attempting to reseat the first-actuated relieff-valve, the second relief valve was mechanically agitated by the-operator's movements causing it to actuate also.- At. Perry, the air cross connect valve between the' redundant: receiver-tanks is -

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. maintained closed and was closed daring the February 19. 1989.

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event.

Corrective actions completed included:

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Air receiver: tank relief valves were reoriented in the vertical i

plane to-satisfy seismic test-results.

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Hanger rods that were. located in close proximity to the-. relief valves were removed to' prevent mechanical agitation.

• Air receiver relief valves.were'recicssified as active components in. the licensee's "Q-List."

Air receiver relief valves were seismically qualified by= the licensee (Ref: Farwell & Hendricks, Inc. Report No. 10470,

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dated April 24,1989).

Reviewed safety related plant systems to confirm classification l

of relief valves as active or passive.

In addition to.the above, the licensee identified that the installed

- I Crosby relief valves had a 60 percent blowdown upon lifting at the 275 psig setpoint. The 120 psig " reset" value was 30 psig below the

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EDG 150 psig. lockout. The licensee issued a purchase order to

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procure new relief valves that will reset abose the EDG lockout i

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value.

The licensee informed the inspectors that the new relief a

valves were still being manufactured and that upon receipt, replacement of the currently installed valves would be implemented.

Based on the inspectors review of current licensee actions with

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regard to the EDG air receiver relief valves and the planned

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modification to~ replace with upgraded components, this item is l

closed.

l No violations or deviations were identified. One item remained open

pending completion of licensee activities.

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6.

, Licensee Event Report Followup (92700)

i Through direct observations, discussions with licensee personnel, and

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review of records, the following event report was reviewed to determine i

if reportability requirements were fulfilled, immediate corrective actions were accomplished in accordance with Technical Specifications and corrective action to prevent recurrence had been accomplished,

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(Closed) LER 87061-00:

Failure to Maintain The Inner Drywell Airlock Door Closed While The Outer Drywell Door Was Inoperable.

In August 1987, a mechanica1' failure of the drywell outer personnel airlock door c:: curred

at the time Health Physics personnel were taking surveys inside of the drywell. With the inoperable outer door, Health Physics personnel exited f

the drywell by opening the inner drywell airlock door.

Failure to maintain at= least one drywell personnel airlock door closed was a

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Violation (440/90005-01) of. Technical Specification 3.6.2.3.

However, a.

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Notice of Violation was not issued in accordance with'10 CFR 2,-Appendix C,Section V.G 1 because:

the violation was identified by the licensee; this; specific. violation would normally be classified at a Severity = Level IV or V; the violation was reported by the licensee in accordance with 10 CFR 50.73; the licensee completed corrective actions as discussed below;

and it was.not a willful violation.

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The root cause for the failure of the outer door was identified by the

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licensee to have been the design of the airlock door closing mechanism C

causing.overstress and eventual failure of bushings.

Initially the licensee proposed to modify the closing mechanism to obtain better alignment. However, in. licensee memorandum W. Farrell to H. Hegrat dated March 3, 1990, the corrective action was revised based on actual-operating practices' and maintenance experience since the August 1987:

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failure. As stated in that memorandum, minimum usage: of the drywell

airlock doors occur during plant operation; the drywell airlock doors are blocked open during plant outages to allow access into the drywell;

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and the mechanical failure had not recurred. The licensee revised'

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preventative raintenance instruction 89-115 and -116 to include

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inspection of the mechanical linkage bushings. That inspection was

performed during the Spring 1989 (RFO-1) outage and was scheduled for the Fall 1990 (RFO-2) outage.

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~Although the licensee revised the corrective action stated in the subject-

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report, the inspectors concluded that appropriate corrective actions had.

been completed.

Based on the inspectors review of NUREG-1022,' Supplement t

No. 1, Question 13.2, the licensee's decision not to submit a supplemental report appeared reasonable.

This item is closed.

One violation was identified for which a Notice of Violation was not

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issued in accordance with 10 CFR 2, Appendix-C,Section V.G.I.

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7. -

Engineered Safety Feature-(ESF) Walkdown (71710)

a During this inspection period, the inspectors perforred a detailed g

walkdown of the accessible portions of train "B" of the residual heat removal ~(RHR) system. The system walkdown was conducted using Valve

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L Lineup Instruction (VLI)-E12, Revision 4, System Operating Instruction (501)-E12, Revision 6, " Residual Heat Removal System (Unit 1)," and piping and' instrumentation diagrams (P& ids) for the RHR System.

Durir,9 the walkdown,- the licensee identified the "B" train as operable.

The inspectors took into account that during the walkdown the "B" train was in various modes of operation ~and therefore in various valve lineups.

• During the system walkdown, the inspectors directly observed equipment-conditions to verify'that hangers and supports were made up properly;

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appropriate levels of cleanliness were being maintained; piping insulation, heaters, and air circulation systems were installed and operational;-valves in the system were installed in accordance with-applicable P& ids and did-not exhibit grossipacking leakage, bent stems, missing handwheels, or improper labeling; and, that major system

components were properly labeled and exhibited no leakage.

The-inspectors verified that instrumentation-. associated with the system was properly installed, fu_nctioning, and. that significant process parameter

values <were consistent with normal expected values.

By direct visual

- observation or_ observation of. remote position indication,; the i_nspectors verified that: valves in the system flow ~ path were in the correct y

positions as required by the various modes of operation that.were-required; power was available to the valves; valves ~ required to,be locked in_ position were locked;.and, that pipe caps and blank flanges were-

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instal _ led as. required.

Based on the walkdown performed as described above, the inspectors concluded that the "B" train of _ RHR was properly aligned to perform its intended engineered safety function.

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O No violations or deviations were identified.

8.

Monthly Surveillance Observation (61726)

For the below-listed surveillance activities the inspectors verified one

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or more of the'following:

testing was performed in accordance with procedures; test instrumentation was calibrated; limiting conditions for

. operation were met; removal and restoration of the affected components

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were: properly accomplished; test results conformed with technical specifications and' procedure requirements and were reviewed by personnel

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other than the individual directing the test; and that'any deficiencies 1dentified'during the testing were properly reviewed and resolved by

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appropriate management personnel.

Surveillance Test No.

' Activity SVI-1821-T0032D,- Revision 3

" Reactor Vessel Steam' Dome

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Pressure and Reactor Vessel Pressure.(RHR Cut-in

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Permissive) Channel _D Functional For 1821-N678D"-

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SVI-D17-T0040-0, Revision 2

" Main' Steam Line Radiation -

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Monitor 1017-K610D"'

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SVI-E12-T5368,- Revision 1, TCN 4

"ECCS/LPCI Pump B Start Time Delay Channel Functional" i

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SVI-P53-T6305, Revision 1

" Lower Containment Airlock I

In-Between The Seals Test"-

s SVI-P53-T6312, Revision _1

" Upper Primary Containment'

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- Airlock In-Between The Seals-

Test" x

i Details a.

.During The-Performance of Step 5.'1.11 of -Surveillance Inst'ruction (SVI) -017-T0040-D, Revision 2, " Main Steam Lin'e Radiation Monitor

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1D17-K6100," on March 24, 1990,, an unexpected-half scram was f

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receivedi The unit supervisor and instrumentation and calibrationi

_(I&C);personne1Lmade a preliminary determination that the procedure-probably needed a caution before Step 5.1.11' warning that a half-j scram may1 be ~ received when perforning this step.

The uniti

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supervisor directed that the SVI be terminated; however, the

. equipment was still: considered operable since the problem appeared i

to be procedural; The unit supervisor also directed the leadL

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technician to initiate a condition report to investigate.the problem and confirm-that it was a procedural problem and;to change the.

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u procedure if necessary.

Revision 3 to SVI D17-T0040-D was issued on

' March 23, 1990.

That revision-included a precaution in'Section 2.12 identifying the potential to receive reactor protection system half'

i scrams during performance of the-SVI.

In. addition, Section 5.1.11 i

slearly ' stated that a half scram signal would be generated.

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During the_ inspectors observation of SVI-E12-T5368, the test was (

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terminated when the expected relay timing did not occur.

The

technicians performing the test suspected test equipment problems g

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and informed the on-shift senior reactor operator.

A procedural b

problem was subsequently identified concerning the use of recently-modified test equipment.

SVI-E12-T5368 was revised on April 9, 1990, via Temporary Change 5 to correct the test equipment procedural deficiency.

No violations or deviations were identified.

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9.

Monthly Maintenance Observation (62703)

Station maintenance activities of safety related systems and components listed below were observed / reviewed to ascertain that they were conducted

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in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with technical specifications.

The following. items were considered during this review:

the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by

. qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and, fire prevention controls were implemented.

Work requests were reviewed to determine status of outstanding jobs and to assure that priority was assigned to safety related equipment

maintenance which may affect system performance.

.The following specific maintenance activities were observed / reviewed:

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Details

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a.

LWork Order 90-1266, was written because the fuel handling building ventilation exhaust fan "C" motor was-running warmer and noisier than normal and the trend of vibration data indicated potential degraded motor bearings. On March 27, 1990, the fan motor was meggered and it passed Generic Electrical Instruction, Revision-1,

" Performing Insulation Resistance Checks." Maintenance personnel disassembled the fan motor and on March 28, replaced the inboard and outboard sets of motor shaft bearings.

b.

Work Order 88-5560, Revision 2, which directed the replacement of the 0-rings, a pitted shaft and the shaft sleeve on screen wash pump, OP49C0028.

The inspectors reviewed licensee actions regarding the maintenance activity being conducted on emergency service water screen wash pump OP49C0028. That safety-related component had been removed from service on November 15, 1989, to perform maintenance.

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The purpse of screen wash pump OP49C002B was to remove debris, by water spray.,_from associated traveling screen OP49D001B. At Perry, there are two traveling screens located in the emergency service water pumphouse.

As detailed in Perry Updated Safety Analysis Report (USAR), Section 9.2.1, the traveling screens were designed to meet the requirements for Safety Class 3 and Seismic Category I equipment.

In accordance with the licensee's administrative controls, a " potential" limiting condition for operation (LCO) tracking sheet was initiated on November 15,1989, to indicate that the LCO may be " active" if a loss of redundant screen wash pump OP49C002A occurred. As discussed below in paragraph 11.b.(2), the

"A" screen wash system failed on April 3,1990, requiring the licensee to declare an ALERT until repairs were made to restore that component to service.

Since screen wash pump OP49C0028 was a safety related component and it performed an indirect support function on safety related tre.veling screen OP490001B, the inspectors reviewed the licensee's basis for concluding that no affect on system cperability occurred when screen wash pump OP49C002B was removed from service. Perry USAR Table 9.2-13. " Traveling Screens," provided design information that indicated sufficient screen area was available with only one traveling screen in service (i.e. the two traveling screens provided 100 percent iedundancy). The inspectors noted that Perry USAR Appendix 9A, " Fire Protection Evaluation Report,"

Tab 9A.7 Section G8, indicated that the emergency service water system had operated for two months prior to initial plant operation without availability of traveling screens.

Emergency service water pump operation'during that time span was not degraded.

In addition, the licensee indicated that traveling screen OP490001B could be manually cleaned if required.

As defined in Perry Technical Specification 1.29, a " system" shall be

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OPERABLE or have OPERABILITY when it is capable of performing its specified function and when all necessary auxiliary equipment required -

for the " system" to perform its function are capable of performing their related support function. The " system" supported by the screen wash-pumps was emergency service water (ESW). The ESW operability requirements are stated in Perry Technical Specification 3.7.1.1.

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on the fact that traveling screen OP490001A was capable of performing the required screening function; the USAR information that indicated no increase in differential pressure across the traveling screens after a two month period of pump operation without traveling screens; the ability to compensate for the inoperable screen wash pump on traveling screen OP490001B by manual cleaning; and the inspectors direct field observation that no affect on screening capabilities had occurred with screen wash pump OP49C002B removed from service, the inspectors noted that the licensee's basis for concluding no immediate " system" impact was reasonable. However, the inspectors also noted that the licensee had not defined a maximum out-of-service time for one of the two traveling screens.

The inspectors requested the NRR staff in Region III memorandum E. Greenman to J. Zwolinski dated March 19, 1990, to review actions taken

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by the licensee and the acceptability of those actions to comply with Perry. Technical Specifications..The inspectors will document the_results L

of that st'aff review in a future inspection report.

The-inspectors noted that the extended length of time screen wash pump OP490002B was out of service was apparently due to delays.in procurement of-repair parts. The inspectors were concerned that adequate management

attention mayL not have been focused on this safety related' component due to a lack of awareness of its safety significance.

The. inspectors based their concern on the fact that the licensee's monthly performance report for December 1989 did not list the screen wash pump as an out of service

component even though its out of service time had exceeded the 30 day i

criterion.

In addition, the inspectors noted that the licensee's i

January-1990 monthly performance report identified the screen wash pump as an out of service component;- however, the potential impact on plant operations was not accurate.

The inspectors noted that these " management'

tools" depend on accurate input from several line organizations. At the conclusion of the report period, the inspectors were still' evaluating

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whether the licensee's maintenance program was effectively' implemented commensurate with the safety significance of the out of service screen wash pump.

Pending completion of the inspectors review, the adequacy of

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corrective actions taken following removal of screen wash pump OP4900028

from service on November 15, 1989, is considered an Unresolved Item (440/90005-02(DRP)).

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One Unresolved Item was identified ccocerning adequacy of correctiveL maintenance.

'10 Operational Safety Verification (71707)

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General

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ine inspectors observed control room operations, reviewed applicable.

logs, 'and conducted discussions with control room opsrators during

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this inspection; period. The inspectors verified the' operability of

selected emergency systems, reviewed tag-out records ar.d -verified "

. tracking of Limiting Conditions for Operation associated with affected components. Tours of the-intermediate, auxiliary, reactor, and turbine buildings were conducted to observe plant equipment a

conditions including potential fire hazards, fluid leaks, and excessive vibrations, and to verify that maintenance requests lhad been initiated for certain pieces of equipment in need of maintenance. The inspectors by observation and di_ rect interview verified that the physical security program was-being implemented in-accordance with the station security plan.

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The inspectors observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls.

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These reviews and observations were conducted to verify that facility cperations were in conformance with the requirements established under technical specifications,10 CFR, and administrative procedures.

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_(1) ' During the inspection period, the inspectors walkedidown.

F-the accessible portions of the following systems to verify

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' operability by comparing system lineup with plant drawings,

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as-built configuration or present valve lineup lists; observing equipment conditions that=could degrade performance;1and verified that instrumentation was properly valved, functioning,-

and calibrated.

High Pressure Core Spray (HPCS) System

Emergency Diesel Generator (EDG) - Division 3

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Emergency Service Water (ESW) - Division 3

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120'VDC Batteries - Division 3

The following were noted during the walkdowns:

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(a) Excessive. leakage was evident from ESW pump 1P45-C002.

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Water was obr,erved coming' from the shaft seal area and running down to a nearby floor drain.

Subsequently,. the.-

licensee determined that the-gland seal leakoff line had-

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become blocked. The blockage was removed and' leakage subsequently. decreased.

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(b) Inlet-pressure gauge IP45-R0237 to ESW strainer IP45-D003

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.was observed to be indicating approximately 18 psi _. With

.the system in operation and the strainer outlet pressure-

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gauge. reading 74 psi, the inspector concluded that the __

inlet gcuge was inoperable and possibly ' valved out. - The

licensee subsequently confirmed _the inspector's

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' determination that the gauge was inoperable.

(c) The strainer outlet pressure gauge IP45-R0236', although

apparently indicating properly, was missing.its front'

faceplate glass cover.

(d) Switch 1E22-N724 on the Division 3 EDG had a deficiency

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tag hung on it dated December 21,~1988 describing that it.

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was " undersized'for operating-pressure."_ When approached on.this matter, the licensee determined the tag was

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associated with nonconformance report NEDO 3565-2 which

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had,. prior to the' inspectors review, been dispositioned as -

"use as i s."

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(e) A Xertex.Sensall Control sonic type-level transmitter which provided local indication of Division 3 fuel oil tank level was observed to be reading 99 percent full.

y However, a local. low level alarm light was also-

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illuminated on the unit.

When brought to the attention -

the operating authority, review determined that the local low level alarm light was not routinely used to check tank level; control room annunciation logic was separate from

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. c o the local alarm circuit. A work request was subsequently.

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initiated to~ adjust the alarm setpoint such to clear the y'

local alarm light.

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(f) A substantive ecount of combustible materiai (wood)'

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was noted-in the ESW pumphouse.

Examples included

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approximately a dozen 4x4s, apparently once used as k[

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dunnage, stored in a location near the entrance to the

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diesel fire: pump room, a storage area for scaffolding

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parts'that included flats of plywood, and a plywood

enclosure approximately 3x3x5 feet placed to enclose a.-

strainer control panel adjacent to the ESW Division-3 line.

The inspector contacted the licensee's fire

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protection group and questioned the effect of these

' additional combustibles on the analyzed fire loading

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for that area.

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In response, the fire protection'iaspection group-

performed an inspection of the ESW pumphouse. The plywood

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enclosure was found to be an acceptable installation.

However, the excess dunnage was nonapproved and involved enough material to potentially impact the. limitations-specified in plant administrative procedure PAP-1913,

" Control of Transient Combustibles." The licensee's fire protection group removed the subject dunnage. They-also-

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determined.the scaffold storage area had not'been-established in accordance with plant administrative

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procedures in that a review per PAP-1913 had-not been performed. Condition Report 90-049 was initiated by the licensee to document corrective actions taken.

Subsequent tours of the'affected area by the inspectors noted that

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the licensee had taken effective corrective actions, j

(2).During a walkdown of control't>om panels on March-5, 1990, the inspectors noted that the' control switch for the shutdown

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cooling outboard isolation valve (E12-F008), had ~an information

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tag hung. indicating'it had been. manually torqued-closed to

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580 ft-lbs.

Followup discussions with control room operators revealed that,the valve had been torqued to that value:in accordance with engineering recommendations to eliminate s

leakage past the. seat with the unit at power.

Control room K

operators stated that to reopen the valve required use of a

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specific procedure. However, during a subsequent.walkdown of-

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the remote shutdown panel (RSP) on March 8, the inspactor observed that although control.of E12-F008 was also available at the RSP,'no information tag was'hu.'g on its respective RSP control switch. The inspectors noted that the requirement to

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hang an information tag at the RSP war. contained in Administrative Procedure PAP-1404, "Iaformation Tags." The licensee took corrective action to place an information tag at the-RSP.

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.No violations or deviations were identified.

11i Onsite Followup of Events at Operating Power Reactors (93702)

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a.

General-d b

The inspectors performed onsite followup activities for events which

< occurred during the inspection period.. Followup inspection included j

.one or more.-of the following:

reviews of operating logs, procedures,-

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condition reports; direct observation of licensee actions; and-interviews of licensee personnel.

For each event, the inspectors j

reviewed one or more of the following:

the sequence of actions; the '

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functioning of safety systems required by plant conditions; licensee l

actions: to. verify consistency with plant procedur_es and -license

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conditions;-and ve~rification of the nature of.the event. Additionally, in some cases,-the inspectors-verified that licensee investigation had identified root causes of equipment malfunctions.and/or personnel errors and were taking or had taken appropriate corrective actions.

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Details'of the events and-licensee corrective actions noted during

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the ins'pectors' followup are provided in Paragraph b. below.

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'b.

Details

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(1) Loss of Containment Integrity

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On March 16, 1990, at about 8:00 p.m. (EST), while operating at 100 percent power, the licensee declared a loss of containment integrity due'to exceeding allowable secondary containment bypass leakage. At Perry, the Technical-Specification -limit for allowable bypass;1eakage (0.0504 La) is 5051 standard cubic centimeters per minute (SCCM).

The known bypass leakage prior-to the' event was 2506 SCCM.

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Upon identification that a post accident sample system _.

containment penetration was leaking water past the closed isolation valves at.a' rate of 0.132 gpm, the licensee' performed

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initial calculations to determine equivalent bypass leakage and

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concluded the Technical Specification l'imit was not met.' The:

i licensee entered the action statement of Technical

Specification 3.6.1.1.'1 which required restoration witnin

1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. At-

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about 3:20 a.m. on March 17, the licensee ' commenced an orderly

shutdown.

While performing the plant shutdown, additional measurements were made to determine leakage of water at normal system pressure of 1024 psig.

The initial. calculations vere performed assuming 125 psig. With the. containment isolation valves closed and sensing normal system pressure, the measured leakage

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was quantified at 0.176 gpm.

That leakrate was then calculated to an equivalent " bypass" leakage and added to the known bypass i

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-leakage of 2506 SCCM. The total bypass leakage was calculated-to be 4454 SCCM which was below the allowed value of 5051; therefore, the licensee exited the SuVTDOWN action statement at about 5:00 a.m.

At the time the action statement was exited, plant power had been reduced to about 50 percent. The licensee returned to 100 percent power at about 7:00 a.m.

The licensee notified the NRC operations center of the event via the ENS at-about 4:00 a.m. on March 17 within one hour of commencing the power reduction.

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The inspectors obs'erved the licensee's actions during the event from the main control room.

In addition, the inspectors reviewed the calculations performed as documented in Field

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Change Report (FCR) No.13704 dated March 17, 1990.

Based on i

the observations and reviews performed, the inspectors concluded that the licensee had complied with Technical Specifications for this event.

(2) ALERT Due To Loss Of Emergency Service Water On April 3, 1990, at about 2:30 a.m., while operating at 100 percent power, the licensee declared emergency service water (ESW) systems "A" and "B" inoperable dut to component failures.

At the time'of event occurrence, testing of Division 1 emergency diesel was in progress due to the failure of the

. Division-3 emergency diesel (High Pressure Core Spray), As discussed below in paragraph 11.b.(4), the Division 3 emergency diesel had been declared IN0pERABLE on April 2, 1990, due to degraded fuel oil; therefore, Technical Specifications required surveillance testing be performed on the Division 1 and 2 emergency diesels.

During that test performance, a gasket.

failed on-an inspection cover for the ESW "A" pump discharge strainer. With the gasket failure, a water spray developed that wetted several Division 1 electrical components in the

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immediate vicinity of the ESW "A" pump strainer including a 480 volt motor control center.

The immediate action of plant operators'was to declare ESW "A" and associated systems inoperable. With the Division 1 emergency diesel generator inoperable (cooled by ESW "A"),

Ter.hnical Specification Action statement 3.8.1.1.e required that within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> all systems, subsystems, trains, components, and devices dependent on the remaining OPERABLE emergency diesel be verified OPERABLE. The ESW "B" screen wash pump had been inoperable since November 15, 1989, as discussed above in paragraph 9.b.

The water spray from the failed gasket had caused the failure of ESW "A" screen wash system. With both "A" and "B" screen wash systems inoperable, the licensee considered the traveling screen support function to be inoperable and declared ESW "A" and "B" inoperable.

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Since the licensee had determined that ESW "A" and "B" were INOPERABLE, the associated supported emergency core cooling system (ECCS) were declared INOPERABLE.

Those systems included i

Residual Heat. Removal (RHR) trains A, B, and C, and Low Pressure Core Spray (LPCS).

In addition, all three emergency diesel generators were INOPERABLE; Division 1 and 2 because of the loss of ESW "A" and "B" and Division 3 which was already IN0PERABLE due to degraded fuel oil.

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In accordance with Emergency Plan' Instruction (EPI)-A1, " Loss of Shutdown Functions, Decay Heat Removal or Reactivity,"

Revision 3, the licensee declared an ALERT at about 2:30 a.m.

The ALERT declaration was made due to the loss of ESW "A" and.

"B".

The inspectors monitored the licensee's actions in the Control Room Operations Support Center, and Technical Support Center from the time of arrival on site (about 3:00 a.m.) until event termination at about 6:00 a.m.

The inspectors noted that ESW "B" was running throughout the event and did not exhibit I

any degradation due to the loss of the support function i

provided by screen wash pumps "A" and "B".

Repairs were made by maintenance teams. working out of the Operations Support Center.

Repairs performed included:

ESW "A" pump discharge strainer inspection cover gasket was replaced; a shorted

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control power transforraer in the wetted Division 1480 volt motor control center was replaced; inspections for grounded equipment were performed with-a "megger" at the 480 voit motor control center; and the repaired equipment was functionally tested prior to declaring-it OPERABLE.

At about 5:30 a.m., following successful post maintenance testing 'of af fected equipment, ESW "A" and "B" were declared OPERABLE.

In addition, the supported emergency core cooling systems were also. declared-0PERABLE. At about 6:00 a.m. the

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licensee terminated the ALERT after consultation with State and local officials.

The licensee initially informed the NRC operations center of'

this event via the ENS at about 3:15 a.m.

A-continuous communication link via the ENS was maintained with the licensee until event termination at 6:00 a.m.

The inspe: tors will

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review the licensee's root cause determination for this event in a subsequent report-following.the-licensee's submittal of the licensee event report required by 10 CFR 51.73.

(3)

High Pressure Core S ray System Inoperable p

On April 5,1390, at about 4:00 a.m. (EDT), while operating at 100 percent power, a loss of a safety function occurred when the high pressure core spray (HFCS) system was declared

inoperable. While performing a routine surve9 1ance activity, the measured vertical pump displacement (2.5 mil) exceeded the

surveillance acceptance criteria and HPCS was declared

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inoperable.

However, upon further' review of the actual method used to measure the HPCS pump vertical displacement, the-licensee noted that during the " failed" surveillance the proper

'q location was not used by plant technicians when measuring vertical displacement. The surveillance was repeated the

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morning of April 5 with acceptable results.

The HPCS-system was i

then declared operable; however, as discussed below, the HPCS l

system was declared inoperable again at about 1:00 p.m. on April-5 due to its associated emergency diesel generator exceeding the technical specification allowed out of service time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

j The licensee informed the NRC operations center of the event

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via the ENS at about 5:15 a.m. on April 5, 1990.

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(4) High Pressure Core Spray System Inoperable

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On April 5,1990, at about 1:00 p.m. (EDT), while operating at 100 percent power, the licensee declared the high pressure core.

-spray system inoperable due to its associated emergency diesel--

generator being inoperable greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The Division 3 emergency diesel had been declared inoperable on

'i April 2 when ' routine sampling identified-the Division:3 fuel oil storage tank contained greater than.05 percent sediment.

At that time, in accordance with technical ~ specifications, the Division 3 emergency diesel was declared inoperable and the licensee began actions to replace the fuel oil. The licensee completed replacement of the Division 3 fuel oil and the high pressure core spray system was declared operable on April 6,1990.

The licensee informed the NRC operations center of this event via the ENS at about 1:30 p.m. on April 5.

L (5) Loss of-Control Room Ventilation Safety Function On April 11, 1990, at about 8:35 a.m. (EDT), with the plant operating at 100 percent power, a loss of control room ventilation safety function occurred. At the time of event occurrence, the "A" train of control room ventilation system had been declared inoperable (but functional) for planned maintenance activities.on an associated support system.

The "B" train of control room ventilation was operable and in standby. As part of a routine preventive maintenance activity, surveillance technicians requested control room operators to align the control room ventilation system to prevent spurious starts while changing out cassette tapes on air intake monitors.

The plant operators placed the "A" train (inoperable but functional) in its emergency recirculation mode and placed the

"B" train in a secured status by placing its control switch in the pull-to-lock position.

Plant surveillance technicians then proceeded with the cassette tape changeout.

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,p About 10 minutes'after establishing this ventilation lineup, control room operators recognized that an error had been made and that the control room ventilation trains were both t

inoperable. The "A" train had been declared inoperable due to the planned maintenance on its support system (cooling water)

and the "B" train was made inoperable by moving its control switch to the pull-to-lock position (i.e. the "B" train was not capable of responding. to automatic signals)'. Control room operators restored the "B" train to service in the emergency recirculation mode at 9:12 a.m.

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The inspectors noted that the on-shift senior. licensed operator (SRO) directing the ventilation lineup was aware of the train

"A" inoperability; however, when that SRO directed the ventilation lineup change, he was not specific to. control room:

l operators as to which train should be secured.

Since the "A" l

train was functional and running, it was placed in emergency j

recirculation and the "B" staudby train was secured by placing

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it-in pull-to-lock. When the control room operators reported l

to the SR0 the specific lineup performed about 10 minutes after

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completion, the SR0 recognized the error made and took actions to restore the control ventilation systems to an operable l

condition.

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Failure of the licensee to maintain at least one train of control room emergency recirculation system operable due to the l

above described personnel error is a Violation

(440/90005-03(DRP)) of Technical Specification 3.7.2.

However,

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a Notice of Violation-was not issued in accordance with 10 CFR'

l 2, Appendix C,Section V.G.1 because:

the violation was

identified by the licensee; this specific violation would-i normally be classified at a Severity Level IV or V; the i

violation was-reported by the licensee via the ENS as discussed f

below and an LER will be provided; the violation was promptly I

corrected by the same individual who made the error; and it was -

not a willful violation.

l The-licensee informed the NRC operations center of this event

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via the ENS at about 2:00 p.m. on-April 11.

In accordance with'

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10 CFR 50.72(b)(2), "four-hour reports," the licensee should

have reported this event no later than 12:45 p.m. which was l

4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> past the " discovery" time noted on licensee Condition

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Report 90-085.

The failure to report this event within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of event recognition is a Violation of 10 CFR 50.72(b)(2)

(440/90005-04(DRP)).

However, a Notice of Violation was not i

issued in accordance with 10 CFR 2,' Appendix C,Section V.G.1 because:

the failure to report was identified by the licensee; this specific violation would normally be classified at a

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Severity Level IV or V; the failure to report on time was reported during the event notification discussed above; the violation was corrected by self-reporting; and it was not a willful violation.

The inspectors noted that while a notice of

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violetion was not issued for the licensee's failure to meet the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> reporting requirement, the licensee had been issued a notice of violation (50-440/88015-03) in November 1988 for failure to report the identical event.

The licensee's self identification and prompt reporting (about I hour late) was the primary basis for the NRC not issuing a notice of violation for

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this event.

'(6) Loss of Control Room Ventilation Safety Function On April 11, 1990, at about 11:10 p.m. (EDT), with the plant operating at 100 percent power, the licensee experienced a

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second-(see paragraph 11.b.(5)) loss of control room ventilation safety function. While performing pre-shift panel walkdowns, the oncoming control room operators noted that the OPERABLE control room ventilation train "B" was not running. At the time of discovery, the "A" control room ventilation train was inoperable following planned maintenance activities. The shif t supervisor took action within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to commence an orderly plant shutdown in accordance with Technical Specification 3.0,3.

In addition, the shift supervisor directed that a priority work request be initiated to troubleshoot failure of the "B" control room ventilation train and that necessary inspection personnel be called in to review the completed work packages on the "A" control room ventilation train.

At about 3:00 a.m. on April 12 the licensee restored train "B" of the control room ventilation system to service and exited Technical Specification 3.0.3.

The cause for the train failure was identified.to be a failed relay (K-103) in the "B" train's supply fan circuit.

That relay was replaced with a spare under Work Order 90-1927. At about 3:15 a.m. on April 12 required inspection activities were completed on the "A" train of the control room ventilation system and it was returned to an operable condition.

The licensee informed the NRC operations center of this event at about 2:57 a.m. on April 12 within the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> requirement of 10 CFR 50.72(b)(2).

The inspectors will review the final root cause determination and the licensee's corrective actions to

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prevent recurrence af ter issuance of the required licensee event report.

Two violations were identified for which Notices of Violation were not issued in accordance with 10 CFR 2, Appendix C, V.G.I.

12. Violations For Which A "Notiye of Violation" Will Not Be Issued The NRC uses the Notice of Violation as a standard method for formalizing the existence of a violation of a legally binding requirement.

However, because the NRC wants to encourage and support licensee's initiatives for self-identification and correction of problems, the NRC will not

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b generally issue a Notice of Violation for a violation that meets the i

p tests of 10 CFR 2,' Appendix C,Section V.G.

These tests are:

(1) the

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violation was identified by the licensee; (2) the violation would be

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categorized as Severity Level IV or V; (3) the violation was reported

to the NRC, if required; (4) the violation will be corrected, including

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measures to prevent recurrence, within a reasonable time period; and

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(5):it was not'a violation that could reasonably be expected to have

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vioiation.

Violations of regulatory requirements identified during the

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inspection period for which u Notice of Violation will not be issued were

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discussed in Paragraphs 6 and 11.b.(5).

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Unresolved Items

Unresolved items are o tters about which more information.is required in l

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order to ascertain whether it is an aceptable item, a violation or a

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deviation. An unresolved item is identified in Paragraph 9.b.

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Exit: Interviews (30703)

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The inspectors met with the licensee representatives denoted in Paragraph 1

n throughout the inspection period and on April 18, 1990. The inspector

.i summarized the scope and results of the inspection and discussed the

likely. content _of the inspection report.

The licensee did not indicate s

that any of the information disclosed during the inspection could be considered proprietary in nature.

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Inspector Exit Date

W. Liu 3/8/90

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