ML20033F494
| ML20033F494 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 03/12/1990 |
| From: | Davis A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20033F493 | List: |
| References | |
| EA-89-253, NUDOCS 9003210224 | |
| Download: ML20033F494 (3) | |
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NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY Cleveland Electric Illuminating Docket No. 50-440 Company License No.
NPF-58 Perry Nuclear Power Plant Unit 1 EA 89-253 During an inspection conducted from November 21, 1989 through January 11, 1990, violations of NRC requirements were identified.
In accordance with the " General
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Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2, Appendix C (1989), the Nuclear Reculatory Commission proposes to impose a civil penalty pursuant to Section 234 of the Atomic Energy Act of 1954, as amended (Act), 42 U.S.C. 2282, and 10 CFR 2.205. The particular violations and the associated civil penalty are set forth below:
1.
10 CFR 50, Appendix B, Criterion XI, " Test Control," requires in part that test results be evaluated to assure that test requirements have been satisfied.
Contrary to the above, the licensee failed to properly evaluate test results following the scram time test of control rods on July 30, 1989, and again on November 25, 1989, a.
On July 30, 1989, control rods 34-47 and 34-51 were scram time tested.
Control rods 34-47 and 34-51 did not insert within the time required by Technical Specification 3.1.3.2 but were declared operational based on a successful second scram time test without an evaluation of the-test failures and without perfom'.ng any corrective maintenance, b.
On Novemb2r 25,1989, control rod 34-47 was scram time tested and twice did not insert within the time required by Technical Specification 3.1.3.2.
However, the licensee declared control rod 34-47 operable based on two subsequent successful scram time tests, but without first performing an evaluation of the prior two test failures and without perfoming any corrective maintenance.
II.
10 CFR 50, Appendix B, Criterion XVI, " Corrective Action," requires in i
those instances where significant conditions adverse to quality have been
-identified that corrective actions be taken to assure the cause of the condition is determined and corrective action is taken to preclude L
repetition.
L Contrary to the above, the licensee did not identify the cause of the condition or take adequate corrective action to preclude repetition following the July 30, 1989, scram time test failure of control rods l
34-47 and 34-51.
9003210224 900312 PDR ADOCK 05000440 Q
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1 Notice of Violation Ill.10 CFR 50, Appendix B, Criterion XV, "Nonconfonning Materials." requires measures be established to control components which do not confom to requirements in order to prevent their inadvertent use or installation.
Contrary to the above, on June 7,1985 a nonconfomance report was written concerning ASCO pilot valves containing urethane seat material rather than the required viton material. However, twelve ASCO pilot valves containing the nonconfoming urethane seat material were not adequately controlled. This resulted in five ASCO pilot valves containing the urethane seat material being installed in control rod drive mechanisms, during the 1989 outage, including control rods 34-47 and 34-51.
Collectively these constitute a Severity Level III problem (Supplement I).
Cumulative civil penalty -~ $100,000 (assessed equally among the three violations).
Pursuant to the provisions of 10 CFR 2.201, the Cleveland Electric Illuminating Company (Licensee) is hereby required to submit a written statement of explanation to the. Director, Office of Enforcement U. S. Nuclear Regulatory Commission, within 30 days of the date of this Notice of Violation and Proposed Imposition of Civil Penalty (Notice). This reply should be clearly marked as a
" Reply to A Notice of Violation" and should include for each alleged violation:
(1) admission or denial of the alleged violation, (2) the reasons for the violationifadmitted,andifdenied,thereasonswhy,(3)thecorrectivesteps that have been taken and the results achieved, (4) the corrective steps that will be taken to avoid further violations, and (5) the date when full compliance will be achieved.
If an adequate reply is not received within the time specified in this Notice, an order may be issued to show cause why the license should not be modified, suspended, or revoked or why such other action as may be proper should not be taken. Consideration may be given to extending the response time for good cause shown. Under the authority of Section 182 of the Act, 42 U.S.C. 2232, this response shall be submitted under oath or affirmation.
Within the same time as provided for the response required above under 10 CFR 2.201, the Licensee may pay the civil penalty by letter addressed to the Director, Office of Enforcement, U. S. Nuclear Regulatory Comission, with a check, draft, or money order payable to the Treasurer of the United States in the amount of the civil penalty proposed above, or the cumulative amount of the civil penalties if more than one civil penalty is proposed, in whole or in part by a written answer addressed to the Director, Office of Enforcement, U.S.
Nuclear Regulatory Commission. Should the Licensee fail to answer within the time specified, an order imposing the civil penalty will be issued.
Should the Licensee elect to file an answer in accordance with 10 CFR 2.205 protesting the civil penalty, in whole or in part, such answer should be clearly marked as an
" Answer to a Notice of Violation," and may:
(1) deny the violations issued in this Notice in'whole or in part, (2) demonstrate extenuating circumstances, (3) s l
show error in this Notice, or (4) show other reasons why the penalty should not be imposed.
In addition to protesting the civil penalty in whole or in part, l
such answer may request remission or mitigation of the penalty.
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In requesting mitigation of the proposed penalty, the factors addressed in Section V.B of 10 CFR Part 2, Appendix C (1989), should be addressed.
Any written answer in accordance with 10 CFR 2.205 should be set forth separately irom the statement of explanatio7 in reply pursuant to 10 CFR 2.201, but may incorporate parts of the 10 CFR 2.201 reply by specific reference (e.g. citing page and paragraph numbers) to avoid repetition. The attention of the Licensee is directed to the other provisions of 10 CFR 2.205, regarding the procedure l.
for imposing a civil penalty.
Upon failure to pay any civil penalty due which subsequently has been determined in accordance with the applicable provisions of 10 CFR 2.205, this matter may be referred to the Attorney General, and the penalty unless compromised, remitted, or mitigated may be collected by civil actica pursuant to Section 234c of the Act 42 U.S.C. 2282c.
The response noted above (Reply to Notice of Violation, letter with payment of civil penalty and Answer to a Notice of Violation) should be addressed to:
Director, Office of Enforcement, U.S. Nuclear Regulatory Commission ATTN:
Document Control Desk, Washington, DC 20555 with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region III, and if applicable, a copy to the NRC Resident Inspector at the facility which is the subject of this Notice.
FOR THE NUCLEAR REGULATORY COMMISSION bM e
A. Bert Davis Regional Administrator Dated at Glen Ellyn, Illinois the 12th day of March, 1990 i
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J U.S. NUCLEAR REGULATORY COMMISSION REGION III
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Report No. 50-440/89028(DRP)/EA 89-253 Docket No. 50-440 License No. NPF-58 i
Licensee:
Cleveland Electric Illuminating Company Post Office Box 5000 j
Cleveland, OH 44101 Facility Name:
Perry Nuclear Power Plant, Unit 1 Inspection At:
Perry Site, Perry, Ohio Inspection Conducted: -November 21, 1989 through January 11, 1990 Inspectors:
P. L. Hiland -
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G. F. O'Dwyer Approved By:
M. A. Ring, Chiek/4[Mw' Yh/f'd o
Reactor Projects Se6 tion 3B U
Date Inspection Summary t
Inspection on November 21, 1989 through January 11, 1990 (Report
.No. 50-440/89028(DRP))
Areas Inspected:
Routine, unannounced safety inspection by resident inspectors of licensee action on previous inspection items; monthly J
surveillance observation; monthly maintenance observations; operational' safety L
verification; onsite followup of events;" evaluation of licenseo self 4
assessment capability; and monthly plant status meeting.
Results: Of the seven areas inspected, four potential violations were identified in the area of surveillance testing (Paragraph 3.a)' and two potential violations were identified in the area of maintenance (Paragraph 4.a).
Those six potential violations are planned to be.the subject of an Enforcement e
Conference. The four potential violations identified in the area of surveillance
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testing concerned inadequate test control (Criterion XI) and inadequate corrective action (Criterion XVI) which resulted in the licensee's failure to declare control rods INOPERABLE after failing to meet scram insertion times when tested, failure to comply with Technical Specification (TS) ACTION statement regarding the proximity of inoperable control rods and the failure to enter TS 3.0.3 due to more than one control rod heing untrippable. The two potential violations in the area of maintenance concerned the licensee's failure to adequately control nonconforming material (Criterion XV) which resulted in environmentally unqualified and nonconforming scram pilot valve components being installed in reactor trip systems.
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' Licensee management was aware of the above potential violations and was addressing long term corrective actions at the close of the inspection period, i
- Short term corrective _ action included replacement of unqualified scram pilot valves, scram time surveillance testing on an expanded sample, and personnel training.
The inspectors considered the licensee's.short term corrective actions to be prompt and appropriate with the proper level of management attention.
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j DETAILS 1.
Persons Contacted a.
Cleveland Electric Illuminating Company (CEI)
- L. Phillips, President, C.E.I.
- A. Kaplan, Vice President, Nuclear Group
- M. Lyster, General Manager, Perry Plant Operations Department (PPOD)
- W. Coleman, Manager, Operations Quality Section (NQAD)
&*M. Gmyrek, Manager, Operations Section (PPOD)
&*H. Hegrat, Compliance Engineer (NSD)
- S. Kensicki, Director, Perry Plant Technical Department (PPTD)
- R. Newkirk, Manager, Licensing and Compliance Section (NSD)
R. Stratman, Director, Nuclear Engineering Department (NED)
- D. Takacs, Acting Director, (NQAD)
- F. Stead, Director, (NSD) b.
U. S. Nuclear Regulatory Commission
- C. Paperiello, Deputy Regional Administrator, RIII
- J. Partlow, Associate Director for Projects, NRR
- P..Hiland, Senior Resident I.nspector, RIII i
'*G. O'Dwyer, Res~ident Inspector, RIII-
- R. Knop, Chief, DRP Branch 3, RIII
- J. Zwolinski, Assistant Director Region III Reactors, NRR
- T. Colburn, Perry Project Manager, NRR s.
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- Denotes those attending the management meeting _ held on De_cember 5,
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1989.
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- Denotes those attending the exit meeting held on January 3,1990.
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'& Denotes those attending the exit meeting held on January 11, 1990.
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2.
Licensee Action on Previous Inspection Findings (92701) a.
(0 pen) Open Item (440/89022-21(DRP)): Design Change Packages. As L
detailed in Section 3.6.4.1 of the Perry Diagnostic Evaluation Team (DET) Report dated May 1989, the licensee had not established a long t
term implementation schedule to reduce the number of outstanding design change packages (DCPs).
i The licensee responded to this item in letter PY-CEI/NRR-1043L, i
Section 2.1.6.10, dated July 29, 1989. That response stated that a DCP review committee had been created and that priorities had been established.
Further, results from that effort would be factored l,
into their five year plan.
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.,9 During this report period, the inspectors discussed the current-status of the licensee's progress on this item with the Manager -
Nuclear Engineering Department. As part of this discussion, the inspectors reviewed the draft charter of the established DCP review committee.
The. inspectors noted that the DCP review committee was comprised of'nine managers from the engineering, technical, and.
operations departments.
The inspectors noted that the membership on
=the DCP. review committee was adequate to perform the assigned task.
The established priorities for use by the DCP committee were well defined and covered a1 wide range of design change. requests.
The inspectors reviewed the initial / draft five year engineering
-plan.
That plan had progressed to the point of establishing the goal of completing 106 DCPs during. cycle II. At the time of this review, the licensee identified about one-half of those 106 DCPs were ready to work.
The remainder were scheduled to complete
. planning in the Spring of 1990.
The balance of proposed design changes were still under review and the " final" schedule for those L
items had not yet been incorporated into the engineering five year l
. plan; The' licensee stated that once efforts were completed on
' planning the cycle II design change work', cycle III and IV plannidg l
would be incorporated.
L This item will remain open pending the inspectors review of the licensee's completed five year planning effort and review of p
selected DCPs.
. No violations or deviations were identified.
3.
. Monthly Surveillance Observation (61726)
For the below listed surveillance activities the inspectors verified one i
or more of the following:
testing was performed in accordance.with l
procedures; te'st instrumentation was calibrated; limiting conditions for operation were met; removal and restoration ~of the affected components were properly accomplished; test results conformed with technical specifications and piocedure requirements and were reviewed by personnel other than the individual directing the test; and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
Exceptions are noted in the following paragraphs.
Surveillance Test No.
Activity SVI-C11-T0225A, Revision 2
" Rod Pattern Controller System High Power Setpoint Channel A Calibration for IC11-N054C" SVI-M51-T0321-B, Revision 6
" Hydrogen Analyzer Calibration" SVI-C11-T1006
" Scram Timing" 1'l 4
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Details.
O During the performance of Surveillance Instruction (SVI)-C11-T1006, Revision 2, !' Control Rod Maximum Scram Insertion Time," on November 25, 1989, the licensee identified two control rods that failed to meet l
their scram time acceptance criteria.
The surveillance test was being performed to meet the requirements of Technical Specification 4.1.3.2.c.
That Technical Specification required that 10 percent (18) of the control rods be tested to verify their maximum scram insertion times were within Technical Specification limits at least once per 120 days of power operation.
l The first scram time test failure occurred when Control Rod 34-47 I
was tested and failed to insert at 1:37 p.m. on November 25.
A second attempt'to test Control Rod 34-47 was made at 1:40 p.m. and the control rod inserted but failed to meet the required acceptance criteria.
At 1:56 p.m. a third attempt to scram time test Control 1
Rod 34-47 uas made with acceptable results.
At 2:04 p.m. a fourth L
attempt to scram time test Control Rod 34-47 was made with acceptable results.
Based on the., test results from the third and fourth scram time tests performed oh Control Rod 34-47, the shift supervisor and personnel performing the testing considered Control Red 34-47 to be OPERABLE and continued with the surveillance test.
r The second scram time test failure occurred when Control Rod 34-51 was tested at 2:13 p.m. and failed to insert. A second attempt to scram time test Control Rod 34-51 was performed at 2:33 p.m.. and it againEfailed to inseit'.
At 2:39 p.m., Control: Rod 34-51 was 1
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declared INOPERABLE due to being untrippable. At the time Control Rod 34-51 was declared INOPERABLE, Control Rod 34-47 (an ' adjacent rod) was considered an OPERABLE control rod; therefore, the plant operators followed Technical Specification 3.1.3.1 ACTION statement L '.,
a.1 and 2 by verifying separation from other inoperable control.
_ rods, hydraulically disarming Control Rod 34-51, and initiating i
action t5 verify adequate shutdown margin existed.
At 6:15 p.m.
O after analysis indicated an inadequate shutdown margin, Control l
Rod 34-51 was fully inserted.
l-After further review of actions taken in response to the first test failure that had occurred while testing Control Rod 34-47, that I
control rod was declared inoperable at 9:30 p.m.
Control Rod 34 :
was fully Sserted at 10:08 p.m.
The licensee concluded that the most likely cause for the two test failures discussed above was due to failure of the scram pilot valve to adequately perform its function when the associated scram solenoids were deenergized. As immediate corrective action, the licensee replaced the scram pilot valves on Control Rod 34-47 and j,
34-51. Both control rods were successfully. scram time tested and subsequently declared OPERABLE at about 5:15 a.m. on November 26, F
1989. The licensee initiated Condition Report (CR)89-404 which t
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documented the scram time test failures of Control Rods 34-47 I
and 34-51, documented the immediate corrective. action taken, and provided for future documentation of the root-cause failure mechanism.
Additional actions taken by the licensee included expanding the population of control rods scram time tested.
Initially, 18 (10 percent) control rods had been selected for testing.
After 1
reviewing the test failures associated with Control Rods 34-47 and 1
34-51, the licensee noted that these two control rods were part of a larger population that had been reworked during the 1989 refueling outage.
The licensee performed scram time testing on an additional j
55 control rods to verify that a generic failure mechanism had not been introduced during the refueling maintenance effort.
The inspectors witnessed portions of that test performance and reviewed all test results.
All 55 " expanded scope" control rods tested met
'the Technical Specification acceptance criteria which initially indicated a generic failure mechanism had not been introduced; however, during the root cause investigation as to the failure mechanism for the scram. pilot valves ' associated.with Contiol Rods 34-47 and.34-51, a potentially gener.ic failure mechanism was identified and is discussed further in paragraph 4 of this report.
The inspectors noted that the inclusion of Control Rods 34-47 and 34-51 into the original 10 percent test population of November 25-was based on corrective action to previous scram time test failures that had occurred on July 30, 1989.
Licensee Condition Report-(CR)89-301 documented scram time test _ failures on Control _ Rods 34-47 and-34-51 during required surveillance testing performed after the 1989-q refueling outage.
As documented in CR 89-301, Control Rods 34-47 and 34-51 failed to_ meet the Technical Specification acceptance criteria for maximum scram. insertion times when tested on July.30, 1989, during the performance of Surveillance Instruction'(SVI)-C11-T1006.
Following'those test failures,, the licensee's immediite corrective I
action was to reperform the scram time test surveillance.
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second scram time test on Control Rods 34-47 and 34-51 performed on l
July 30 met the Technical Specification acceptance criteria and both L
control rods were considered OPERABLE and the initial test failures were attributed to " sticky scram valves." The followup investigation which was approved on October 11, 1989, required that L
Control Rods 34-47 and 34-51 be included in the next sample of control rods tested in accordance with Technical Specifications.
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noted above, Control Rods 34-47 and 34-51 were subsequently tested l
on November 25, 1989.
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Conclusions 10 CFR 50, Appendix B, Criterion XI, " Test Control," required in part that test results shall be documented and evaluated to assure that test requirements have been satisfied.
Contrary to that requirement, the licensee failed to adequately evaluate test results following the performance of scram time testing on July 30 and November 25, 1989, in that:
(a) following the failure of Control o
Rods 34-47 and 34-51 to meet the required maximum scram insertion l
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time when tested on July 30, the licensee declared the two control rods OPERABLE based _on a successful second-attempt. test without adequately evaluating the first test failure or without performance of any corrective maintenance; (b) following the-failure on two s
occasions of Control Rod 34-47 to meet its required maximum scram L
insertion time on November 25, the licensee considered Control Rod I.
34-47 to be'0PERABLE based on a " successful" third and' fourth test without adequately evaluating the first and second test failures or without performance of any corrective maintenance.
The above two examples of-the lice.nsee's failure to adequately evaluate test results is considered an apparent violation of 10 CFR 50, Appendix B, Criterion XI (50-440/89028-01(DRP)).
i 10 CFR 50, Appendix B, Criterion XVI, " Corrective Action," required in part that in cases of significant conditions adverse to quality, corrective action measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition.
Contrary to that requirement, the corrective action taken after s
Co.ntrol Rods 34-47 and 34-51 failed to meet their scram time, acceptance criteria on July 30, 1989, was ihadeq'uate in that the.cause of the E
condition Whs not determined and a'ctions did not preclude repetition.'
, As a result, when Control Rod 34-47 was scram time tested on j
November 25, 1989, as corrective action to the July 30 test failure, that control rod was considered an OPERABLE component after two successive test failures even though those failures exhibited similar, if not identical, characteristics of the ' July 30 test failures.
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licensee's failure to, identify the cause for the failure of Cor; &
Rod 34-47 to meet its niaximum scram insertion time on July 30,,
November 25, 1989, is considered an~ apparent violation of 10 C' Appendix B, Criterion XVI (50-440/89028-02(DRP)).
Technical Specification 3.1.3.1, ACTION statement a.1.a required the licensee to verify Within one hour that the inoperable control rod, if withdrawn, was separated from all other control rods by at r
least two control cells.
Contrary to that requirement, at 2:39 p.m.
on November 25, 1989, Control Rod 34-51 was declared inoperable and remained withdrawn until 6:15 p.m.
Control Rod 34-47 (adjacent rod to 34-51) was subsequently declared inoperable based on test-failures that had occurred about 1:40 p.m. on November 25.
Control Rod 34-47 was inserted at 10:08 p.m.
Therefore, from 3:39 p.m. until 10:08 p.m. the licensee operated in apparent violation of Technical Specification 3.1.3.1, Action a.1.a. with two adjacent, withdrawn, inoperable control rods (50-440/89028-03(DRP)).
1 Technical Specification 3.1.3.1 does not have an associated Action statement for more than one inoperable control rod due to being untrippable; therefore, with more than one inoperable control rod due to being untrippable, Technical Specification 3.0.3 required that action be initiated within one hour to place the unit in an OPERATIONAL CONDITION in which.the Technical Specification does not 7
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apply.
Contrary to that requirement, the licensee operated in OPERATIONAL CONDITION 1 between 2:39 p.m. and 6:15 p.m. on November 25, 1989, with more than one inoperable control rod due to being untrippable in apparent violation (50-440/89028-04(DRP)) of-Technical Specification 3.0.3.
Four apparent violations were. identified that were to be the subject of an Enforcement Conference scheduled for January 18, 1990.
4.
Monthly Maintenance Observation (62703)
Station maintenance activities of safety related systems and components listed below were observed / reviewed to ascertain that they were conducted in accordance with approved procedures,' regulatory guides and industry codes or standards and in conformance with technical specifications.
.The following items ' ere considered during this review:
the limiting w
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 innd were inspected as applicable; functio'nal 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; l
radiological controls were implemented; and, fire prevention controls were implemented.
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Wo'rk r'eque'sts'were reviewed to determine status'of outstanding jobs and to assure that priority is assigned to safety related equipment maintenance which may affect system performance.
l The following specific maintenance activities were observed / reviewed:
a.
' Details As discussed above in paragraph 3, the licensee replaced scram pilot valves for Control Rods 34-47 and 34-51 following scram time test failures observed on November 25, 1989.
The inspectors observed-portions of those maintenance activities as discussed below.
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The scram pilot air solenoid valve pack (IC11-F139) for control rod l
(CR) 34-47 was disassembled on November 27, 1989, in accordance with L
Work Order 89-7191. The seating surface of the disc holder r
sub-assembly should have been viton as stated in the environmental 1:
qualification (EQ) packages for these valves and should have been black, flat and hard. The seating surface was red and appeared soft, " chewed-up", rough and deformed.
On November 28, 1989, upon the inspector's request, maintenance personnel placed the disc I
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holder sub-assembly in its design position which was on the "B" solenoid orifice and held the valve so that the orifice pointed at the floor.
Gravity should have caused the disc holder sub-assembly to fall off of-the orifice but it did not.
The seating surface j
apparently deformed, assumed the shape of the orifice and stuck to the orifice.
This was repeated twice and the disc holder sub-assembly did not fall off as it should have.
On November 28, the scram solenoid pilot air valve pack (IC11-F139) for CR 34-51 was disassembled.
The seating surface on its disc holder sub-assembly was also red vice black and although the seating surface was flat the vendor (ASCO) representative stated that it was glazed in 'a manner-that he had not seen on other seating surfaces.
Furthermore, the surface on the opposite side of the disc holder sub-assembly was tacky as evidenced by the fact that the stem was stuck to it and then was removed and restuck several times.
At the.
close of the inspection period the licensee was awaiting the results of laboratory analysis to determine root cause of failures, identity of seating materials and foreign material.,
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After identification t. hat the ' disc ho'1 der sub'-as.sembly seatirig
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material 'was not made of the EQ required "viton" material, the licensee, through discussions with the scram pilot valve manufacturer (ASCO), recognized that the two scram pilot valves associated with Control Rods 34-47 and 34-51 had been part of a 1985 recall.
The recall was due to the potential for the disc holder assemb. lies having urethane seating material and not the required.
viton material._
In response to the 1985 recall, the licensee had initiated Nonconformance Report (NR) OPQC-1516, dated June 7, 1985.
That report documented the licensee's corrective action after being informed that 34 scram p'ilot valves had been identified as potentially nonconforming.
Twenty-two of ttle 34 suspect components were returned to the supplier, General Electric. Objective. evidence to support this fact was noted by the inspectors to be contained in the NR closure package.
The remaining twelve of the 34 suspect components were thought to have been reworked during the construction phase.
The basis for that conclusion was a memorandum attached to NR OPQC-1516 from the General Electric Site Manager that stated the twelve remaining scram pilot valves had been reworked.
Since the two scram pilot valves which had been installed on Control Rods 34-47 and 34-51 were found to contain urethane seat material, the licensee assumed that the remaining ten pilot valves that had not been returned to the vendor in response to the 1985 recall were potentially nonconforming components. The licensee reviewed maintenance records and performed a field walkdown of all 177 control rod scram pilot valves. The licensee identified an additional five suspect pilot valves installed in the plant.
The remaining five pilot valves were accounted for through review of maintenance records.
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3 For the five pilot valves found to be installed, the licensee replaced them with qualified spares and they were sent to an offsite laboratory:for analysis. - The results of that analysis were to be provided in a supplemental report to Licensee Event Report 50-440/89030.
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Conclusions-10 CFR 50, Appendix B, Criterion XV, " Nonconforming Materials,
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Parts, or Components," required in part that measures shall be established to control components which do not conform to c
requirements in order to prevent their inadvertent use or installation.
Failure of the licensee to control nonconforming components resulted in the installation and use of scram pilot valves'that did not meet the requirements of their associated environmental qualification package and is an apparent violation (50-440,/89028-05(DRP)) of_10 CFR 50, Appendix B, Criterion XV.
t 10 CFR 50.49 required in part that electrical equipcient important to safety be' qualified by testing and/or analysis. The scram pilot valve assemblies were identified in thb licensee's EQ list as equipment number 1C1100001. The licsnsee qualified the scram pilot' valve by testing with viton seat material on the disc holder assembly and had not performed a qualification test with urethane seat material. Therefore, from the time of their. installation during the 1989 refueling outage until their replacement in November, 1989, the licensee operated with installed scram-pilot valves that had not be'en tested and/or anslyzed in apparent violation, of 10 CFR 50.49'(50-440/89028-06(DRP)).
In addition, the inspectors noted that the apparent violation of EQ requirements imposed by 10 CFR 50.49 was the dii'ect result of the apparent violation of Appendix B, Criterion-XV discussed above.
Two apparent violations were identified that were to be tije subject of a January 18,1990,-Enforcement Conference.
5.
Operational Safety Verification (71707) r a.
General The inspectors observed control room operations, reviewed applicable logs, and conducted discussions with control room operators during this inspection period.
The inspectors verified the operability of
. selected emergency systems, reviewed tag-out records and 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 conditions including potential fire hazards, fluid leaks, and 4:
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excessive vibrations, and to verify that maintenance requests had been initiated for certain pieces of equipment in need of maintenance. The inspectors by observation and' direct interview verified that the physical security plan was being implemented in accordance with the station security plan.
The inspectors observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls.
i These reviews and observations were conducted to verify that facility operations were in conformance with the requirements -
established under technical specifications, 10 CFR, and administrative procedures, b.
Details
'(1) 'On December 6,1989, while operating at 100 percent reactor
. power, plant operators identified steam issuing from containment drain lines.
Investigation identified the source 7
t'o be a stuck open relief valve 1n the reactor water' cleanup '
(RWC,U) system. The licens'ee belie 0ed the most likely cause for l'
the initial opening of the relief valve was a pressure transient due to an unexpected RWCU system isolation that had i
occurred earlier that day (see details for that event in paragraph 6.b.(1) below).
The licensee was able to gag shut the stuck open relief valve.
The necessary ove'rpressure. protection'for the RWCU system'was' still' available from a second relief valve installed in the same piping run.
The inspectors noted that the licensee had-consulted the system designer (General Electric) to assure adequate overpressure protection was still available with the gagged relief valve.
. (2)' On December 6, 1989, a radioactive l'iquid spill of about 4,000 gallons occurred in the radwaste building.
The cause of the.
spill was a failed level sensor in a settling tank that was indicating available volume when in fact the tank was full.
When plant operators commenced pumping water to the settling tank, the overflow was directed to the floor drain' system and eventually backed up through the drain system and onto the floors.
Plant operators suspended processing operations after identification of the drain system overflow.
The inspectors toured the affected area of the radwaste building following cleanup activities and noted that no standing water was present. The. licensee initiated Condition Report (CR)89-418 to document this event and to provide.the documentation of corrective actions taken to prevent recurrence.
(3) On December 7,1989, while operating at 100 percent reactor power, a loop-seal was lost on the offgas system "A" dryer skid. The initial indications to plant operators that a loop-seal had been lost were " alert" alarms received in the 11 W
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%.4 control room on the gaseous ~, iodine, and particulate radiation y
monitors for the offgas building ventilation exhaust.
Plant-operators refilled the "A" dryer' skid loop seal ~ which restored r
normal system flow and reduced radiation levels.
The licensee initiated Condition Report (CR)89-417 to' document this. event occurrence and to provide documentation of corrective action '
taken. The peak total body dose rate during.this event-was 3.5 mrem per year which was well below the Technical Specification limit of 500 mrem per year.
During this report period, several additional loop-s'eal.
-failures occurred in the offgas. system.
The details of those-failures are discussed below in paragraph 6.b.(5)(6)(7).
For each'of those events, the inspectors noted-that increased gaseous effluent releases were maintained below Technical Specification limits.
A more detailed review of the, licensee's dose assessments for recent offgas loop-seal failures was being performed by a Region III specialist inspector and will be q
documented in Inspection Report 50-440/89029.
1 (4) On~ December 22, 1989, the licensee expe'rienced a valid test-failure of the Division-1 emergency diesel engine.
The required surveillance test was being performed due to a failure L
of the Division-3 emergency diesel discussed below in paragraph 6.b.(4).
The licensee initiated Condition Report (CR)89-433 to document this event and to provide documentation of.
g the corrective action taken.
Division-1 emergency diesel was' L
returned to service on December 23, 1989,.following maint'enance.
H The cause for.the test failure was a failed relay in the voltage regulator that was replaced.
The inspectors will review the required Special Report due to this valid test failure in a
' subsequent inspection report.
.No Vi61ations or Deviations were identified. '
6.
Onsite Followup of Events at Operating Power Reactors (93702)
L a.
General The inspectors performed onsite followup activities for events which occurred during the inspection period.
Followup inspection included one or_ more of the'following:
reviews of operating logs, procedures, condition reports; direct observation of licensee actions; and interviews of licensee personnel.
For each event, the inspectors reviewed one or more of the following:
the sequence of I
4; actions; the functioning of safety systems required by plant conditions; licensee actions to verify consistency with plant procedures and license conditions; and verification of the nature of the event. Additionally, in some cases, the inspectors verified j
that licensee investigation had identified root causes of equipment malfunctions and/or personnel errors and were taking or had taken appropriate corrective actions.
Details of the events and licensee i
corrective actions noted during the inspectors' followup are provided in Paragraph b. below.
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Details 1
(1)' Reactor Water Cleanup Isolation J
k On Decemb'er 6,1989, while operating at 100 percent reactor _
power, the. licensee experienced an unexpected isolation of the reactor water cleanup (RWCU) system.
The isolation: occurred during the performance of routine plant surveillance rounds when recording temperatures -in the leak detection. system.
The apparent cause for the. isolation was a small change in the plant ventilation system lineup allowing the differential temperature sensed for the RWCU pump room to exceed _ the trip -
setpoint of 23 degrees F.
A".ar verification that an actual system leak was not present, plant operators adjusted auxiliary building' ventilation to reduce the RWCU pump room differential temperature.
Since the RWCU pump room differential temperature had-been averaging about 20 degrees F,-the licensee had been evaluating' possible plant modifications.- Subsequent to this event, a plant m'odification was implemented during~this repo'rt period -
which reduced the ambient differential temperature to about 10 degrees F.
The licensee notified the NRC Operations Center of this event via the ENS at about 1:00 p.m. on December 6,1989.
(2) Reactor-Water Cleanup Isolation
~
On December.8,.1989, while' operation'.at.100; percent reactor' power, the licensee experienced an unexpected isolation.of the
(
reactor water cleanup-(RWCU) system.
The isolation occurred l
due to a. sensed high differential flow during system-startup following a planned maintenance activity. The apparent cause s
l-for the sensed high differential flow was the flow elements for
'the return paths being below their cutoff setpoint resulting in-a generated signal based on suction flow only.
At the time of attempted system restoration a RWCU system relief valve had been _ stuck open and the system was momentarily secured in an attempt to gag that relief valve shut.
Subsequent to this-event, that RWCU relief valve (G33-F504) was successfully gagged shut. The licensee reported this event to the'NRC' Operations Center via the. ENS at about 11:45 p.m. on December 8, 1989.
(3) Reactor Water Cleanup Isolation b
On December 15. 1989, while operating at 100 percent reactor power, the licensee experienced an unexpected isolation of the reactor water cleanup-(RWCU) system.
The system had isolated on high RWCU pump room temperature due to a loss of normal auxiliary building ventilation. The loss of auxiliary building ventilation was caused by.a sensed low temperature in the supply plenum due to' a buildup' of snow (caused by severe winter.
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weather).
Af ter verification of proper system isolation, plant operators restored the auxiliary building ventilation and returned the RWCU system to service.
The licensee informed the NRC Operations Center of this event via the ENS at.about 7:50 p.m. on DecemberL15, 1989.
(4) Loss of Division-3 Battery On December 22, 1989, while operating at 100 percent reactor power, the licensee experienced a loss of the Division-3 battery when the inservice battery was found to have an 4
electrolyte temperature of,69 degrees F which was below the
-Technical Specification limit of 72 degrees F.
The cause for the low battery temperature was a blown fuse in the battery room ventilation system heaters.
Since the affected Division-3 battery was the.only available support system for Division-3 120 Volt DC, the licensee declared the high pressure co're spray (HPCS) system and the Division-3 emergency diesel inoperable.
The licensee replaced the blown fuse.s for the battery room L
ventilation heaters and the battery electrolyte temperature was.
. restored to normal about 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> aft'er initial discovery.
Division-3 components were then declared operable.
One anomaly I
occurred while performing required emergency diesel testing following the discovered inoperability of Division-3.
When 1
'first tested, the Division-1 emergency diesel failed to l
function properly..The licensee complied with the appropriate Technical Specification Action statements associated with both Division-3 an' Division-1 emergency diesels inoperable.
d 3-The Division-1 emergency diesel was returned to an operable status, following corrective maintenance, about 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> after its. initial test failure.
The inspectors will review the licensee's root cause determination. for the Division-1 emergency diesel test failure during the review of the required Licensee Event Report for this event.
The licensee reported o
L this event to the NRC Operations Center via'the ENS at about L
2:00 p.m. on December 22, 1989.
(5)
Loss of Offgas Dryer Skid "A" Loop-Seal At about 2:00 p.m. on December 28, 1989, while the plant was at 100 percent reactor power, alert alarms were received in the control room on the gaseous, particulate, and iodine radiation i
L monitors for the offgas building ventilation exhaust ducting L
(not a release point) and the licensee entered Off-Normal L
Instruction ONI-D17, "High Radiation Levels Within Plant."
l_
Operators noted about a four standard cubic feet per minute B
(scfa) decrease in offgas system process flow. About the same l
time the "C" offgas dryer (which is located on the "A" offgas l
dryer skid) went into its regeneration mode.
Plant operators H
began filling the loop-seals, starting with the "A" dryer skid loop seal whereupon offgas process flow increased back to 1
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' normal and radiation levels started leveling off and decreasing.
Radiation monitors for the offgas vent pipe (a release point) indicated increased radiation levels but no alert alarm levels were reached.
Chemistry personnel indicated that the grab
.l samples-that were taken at the release point did not indicate any levels above normal.. Chemistry estimated that the total body dose rate had peaked at about 1.2 mrem / year (Technical
-l Specification limit is 500 mrem / year) and the whole body dose was less than one tenth of one per cent of the Technical-1 Specification limit.
It was not necessary to ~ evacuate' any personnel from any buildings.
The licensee exited ONI-D17 at 5:50 p.m.
Control room operators responded rapidly and correctly in accordence with their off-normal instructions.
At the close of this inspection period, licensee personnel were 7
still investigating the root cause of the loss of this loop-seal.
t (6) Loss of Offgas Dryer Skid. "B" Loop-Seal
. At about' 5:50 p.m.' on De'cember 29, 1989, while,the. plant was'atl.
100 percent reactor power, the "B" offgas dryer was beginning its. regenerative cycle when the control room received an i
indication that the regenerative blower had tripped'on high current. The auxiliary operator that was sent to investigate-reported that the regenerative blower suction valve (IN64F16908) was closed when it should have been open and that there'.was.the -
smell' of ov'erheated insulation.
Since the regenerative flowpath.-
I is' essentially ~a closed loop,-the blower probably pressurized d
the piping up-to its suction valve to about 14 pounds per square inch (psi) and the blower-then failed whereupon the pressurized air then rushed back through the blower and the "B" dryer chiller l-and blew out the "B" dryer chiller loop seal. The' auxiliary 1
L.
. operator opened, as directedu the blower suction valve via a manual switch and (unknown to operations personnel at the time)
L this allowed the air purge valve (IN64F16948) to open which normally allows excess air in the regenerative loop to be routed back to the offgas process flow. However, since the blower had failed, offgas process flow apparently entered the regenerative flowpath and.went out the empty "B" dryer chiller loop-seal into the-turbine power complex.
After about-10 seccnds the auxiliary operator placed the control switch back in the " auto" position and the blower suction valve and air purge valve closed which stopped additional offgas process flow from escaping into the L
turbine power complex. About 15 minutes later " alert" alarms were received on "offgas building ventilation exhaust" radiation monitors for. gaseous, iodine and particulate.
Plant operators entered their off normal. instruction ONI-D17, "High Radiation Levels Within Plant." Thelpeak levels reached were: for
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" gaseous" - 140 counts per minute (cpm) (alert setpoint - 150),
for " iodine" - 10,000 cpm (alert setpoint - 3,000) and for
" particulate" - 20,000 cpm (alert setpoint - 15,000).
The It e
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1 radiation monitors for the offgas vent pipe (a' release point) did not-indicate an increase in activity.- Operators secured the regeneration process manually.
The inspectors noted the releases were below Technical Specification limits.
The licensee notified the State and three local counties in accordance with:
separate agreements and notified the NRC in accordance with-10 CFR 50.72(b)(2)(vi), " notification to other government Lagencies has been or will be made.",At the conclusion of this report period, the licensee was troubleshooting the valve controller logic for the offgas dryer regeneration process.
(7) Partial loss of Offgas Holdup Pipe Loop-Seal At~ about 8:05 a.m. on January 1,1990, control. room operators noticed increases'on the gaseous, iodine and particulate radiation monitors for the turbine building / heater bay vent (a release point).
Control room operators entered ONI-D17 due to unexplained changes in plant radiation monitors. A plant.-
operator found the offgas holdup pipe loop-seal level at about -
2 feet instead of its normal 7 t'o 8 feet.
The loop-seal was fefilled and radiation le'vels began to. level off and comb'down.
No " alert" levels were reached on any radiation monitors and releases were well below Technical Specification limits.
The licensee notified the State and local counties and the NRC in accordance with 10 CFR 50.72(b)(2)(vi).
The licensee believed that the low level in the holdup pipe loop seal allowed offgas process flow to bubble through the loop seal and.o.ut into the
- Turbine building.
The drain yalve for the loop' seal was found
?
to have been leaking and lowering the _ level by 2 feet per hour.
The licensee was also refilling it frequently.
At the close of this report period, the licensee was considering replacing the drain valve with'a new design..
A Region III radiation protection specialist reviewed licensee L
calculations for events which involved offgas loop-seal problems.
The results of that review will be documented in Inspection Report 50-440/89029.
No Violations or Deviations were identified.
L 7.
Evaluation of Licensee Self-Assessment Capability (40500) o i
During this report period, the inspectors observed the function of the
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licensee's offsite review committee to evaluate the depth of review by that organization of overall plant performance.
The inspectors observed.
- the Nuclear Safety Review Committee meeting Number 65 conducted on December 13, 1989.
L In preparation for the subject meeting observation, the inspectors reviewed the meeting agenda and discussion topic handouts.
Items reviewed included the subcommittee reports prepared by the Audit and L
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Quality Assurance Subcommittee; thel Operations and Maintenance L
Subcommittee; the Radiological, Environmental, and Chemistry Subcommittee; and the Engineering Subcommittee.- The inspectors noted'
.that those subcommittee reports contained current items of interest for the offsite review committee.
The inspectors noted by observing the
.offsite committee meeting held on December 13 that subcommittee reports 1
were presented in a clear manner with opportunity for the committee members to address specific areas of interest or concern.
In-addition to the subcommittee reports, the: inspectors observed the offsite review committee' discussion of proposed changes to the Perry Technical Specifications.. The inspectors noted that the offsite committee was provided sufficient information to act on those proposed changes.
The inspectors noted that the of,fsite committee meeting conducted on December 13 was well formatted with the required quorum of committee members in attendance.
In general, the planned agenda was.followed with an appropriate level of review.
The inspectors concluded that the depth
.of review for the overall plant performance as discussed at' the Decembet 13
- meeting was adequate.
Further evaluation of the licensee's self-assessment capabilities will be documented in a subsequent routine inspection report.
No-Violations or Deviations. were identified.
8.
Plant S'tatus. Meetings. (30702)',
NRC management-met with CEI management on December 5, 1989, at NRC headquarters in Bethesda, Maryland.
Personnel attending that meeting are designated by (#) in paragraph I of this report.
The purpose of the meeting was to review the recent performance of Perry Unit 1.
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Licensee management. discussed actions taken in response to scram pilot valve failures that occurred'on November 25, 1989.
The licensee then presented selected plant performance indicators for the months of October / November 1989.
A presentation on the licensee's quarterly assessment program was provided by the licensee's QA representative.
In addition, a_ brief description of planned actions to control the
-population of Zebra Mussels in the Perry service water systems was provided.
1 NRC management acknowledged the licensee's plans and current plant status.
9.
Exit Interviews (30703)
The inspectors met with the licensee representatives denoted in Paragraph 1 throughout the inspection period and on January 3,1990. The inspector summarized the scope and results of the inspection and discussed the likely content of the inspection report. The licensee did not indicate 17
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.that any of;the'information disblosed during the. inspection could be!
considered ~ proprietary in nature.
The inspectors met with the licensee representatives' denoted in= Paragraph I' on January 11, 1990, to discuss.-
the status of the six ~ apparent violations'which will be the subject of-'
the' January 18, 1990, Enforcement Conference.
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