ML20247C505
| ML20247C505 | |
| Person / Time | |
|---|---|
| Site: | Clinton  |
| Issue date: | 07/20/1989 |
| From: | Davis A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20247C497 | List: |
| References | |
| EA-89-059, EA-89-59, NUDOCS 8907240363 | |
| Download: ML20247C505 (3) | |
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NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTIES Illinois Power Company Docket No. 50-461 Clinton Power Station License No. NPF-62 EA 89-59 During inspections conducted on February 6 through March 3 and March 16 through May 30, 1989., violations of NRC requirements were identified. In accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions,"
10 CFR Part 2, Appendix C 53 Fed. Reg. 40019 (October 13,1988), the Nuclear Regulatory Commission proposes to impose civil penalties 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 penalties are set forth below:
A. 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," requires that measures be established to assure that conditions adverse to quality, such as nonconformances, are identified and corrected. In the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition. The corrective action taken shall be documented and reported to appropriate levels of management.
Contrary to the above, the licensee failed to assure that conditions adverse to quality, including nonconformances, were promptly identified and corrected after an NRC inspection identified significant environmental qualification (EQ) deficiencies with Kynar splices and junction boxes that resulted in the imposition of a $75,000 civil penalty (EA 88-90) on October 20, 1988. Specifically, an NRC inspection conducted on February 6 through March 3, 1989 determined that the licensee's corrective action program had failed to identify six additional unqualified Kynar butt splices and 15 junction boxes inside containment that were not provided with required weep holes.
This is a Severity Level III violation (Supplement I).
Civil Penalty - $25,000 B. 10 CFR 50.49(f) requires, in part, that each item of electric equipment important to safety be qualified by testing identical or similar equipment under environmental conditions identical or similar to those postulated for an accident, with analysis to show that qualification based on similarity is acceptable.
Contrary to the above, as of April 20, 1989, the following equipment important to safety was not oualified in that:
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Notice of Violation 2 July.20, 1989
- 1. The field connections for 95 of the 116 hydrogen igniters
'had unqualified taped splices,
- 2. Numerous. instrument circuits affecting multiple safety systems landed on terminal. blocks on General Electric instrument racks inside of containment were not analyzed for leakage current,
- 3. The ASCO-solenoid valves associated with 16 main, steam safety.-
relief valves had unqualified connectors,
- 4. One standby gas treatment system' train A reactor water cleanup pump room damper assembly was not-qualified for the- postulated humidity condit1on, and
- 5. Some Conax electrical penetration enclosures were installed in an unqualified condition that would allow containment spray to impinge on termina1' blocks having' instrument and control circuits.
This is a Severity Level III violation (Supplement I).
Civil Penalty - $50,000 Pursuant to the provisions of 10 CFR 2.201, Illinois Power Company (Licensee) is hereby required to submit a written statement or explanation to the Director, .
Office of Enforcement, U.S. Nuclear Regulatory Commission, within 30 days of i the date of this 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 deaial of the alleged violation; (2) the reasons for,the violation if admitted; (3) the corrective ~ actions that have been taken and the results achieved; (4) the corrective actions 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 'j taken. Consideration may be given to extending the response time for good '
cause shown.- Under the authority of Section 182 of the Act,142 U.S.C. 2232, this response shall be submitted under oath or affirmation.
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Within the: same time as provided for the response required under 10'CFR 2.201, the Licensee may pay the civil penalties by letter to the Director,-Office of Enforcement, U.S. Nuclear Regulatory Commission ~,- with a check,. draft,:or- ;
money order payable to the Treasurer of the United States in the cumulative '
amount of the civil penalties proposed above, or may protest imposition of l the civil penalties in whole or in part by a written answer addressed to-the j l Director, Office of Enforcement, U.S. Nuclear Regulatory Commission. _ Should 1 the Licensee fail to answer within the time specified, an Order imposing the 'j civil penalties will be issued. Should the Licensee elect to file an ansker (
in accordance with 10 CFR 2.205 protesting the civil penalties, in whole or j in part, such answer should be clearly marked as an " Answer to a Notice of ;
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Notice of Violation 3 July 20, 1989 I Violation" and may: (1) deny the violations listed in this Notice in whole or in part; (2) demonstrate extenuating circumstances; (3) show error in this Notice; or (4) show other reasons why the penalties should not be imposed. In addition to protesting the civil penalties, in whole or in part, such answer may request remission or mitigation of the penalties.
In requesting mitigation of the proposed penalties, the factors addressed in Section V.B of 10 CFR Part 2, Appendix C, should be addressed. Any written-answer in accordance with 10 CFR 2.205 should be set forth separately from the statement or explanation 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 for imposing a civil penalties.
Upon failure to pay any civil penalties due which subsequently have been determined in accordance with the applicable provision of 10 CFR 2.205, this matter may be referred to the Attorney General, and the penalties, unless compromised, remitted, or mitigated, may be collected by civil action pursuant to Section 234c of the Act, 42 U.S.C. 2282c.
The responses to the Director, Office of Enforcement, noted above (Reply to a Notice of Violation, letter with payinent 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, D.C. 20555, with a copy to the Regional Administrator, Region III, U.S. Nuclear Regulatory Commission, 799 Roosevelt Road, Glen Ellyn, Illinois 60137 and a copy to the NRC Resident Inspector at the Clinton Power Station.
FOR THE NUCLEAR REGULATORY COMMISSION N
A. Bert Davis Regional Administrator Dated at Glen Ellyn, Illinois this 20th day of July 1989 i
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' 1 U.S. NUCLEAR REGULATORY COMMISSION - )
q REGION III h,,C- .i Report No. 50-461/89006(DRS) "
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Docket No. 50-4c". .W.'>> 4
. LicenseN / o7NPF 2 6$ $.WL N.c 4 Licensee: Illinois Fcasr Company "'
I 500 South 27th Street ;
Decatur, IL 62523 !
Facility Name: Clinton Power Station -
Inspection At: Clinton, IL 61727 Glen Ellyn, IL 60137 Inspection Conducted: Frbruary 6 through March 3,1989 (Clinton)
Inspector: A. S. Gautron "
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Date Also contributing to this report is:
R. Larson, Idaho National Engineering Laboratories h-Approved By: R. N. Gardner, Chief 3/ l/Elk Plant Systems Section Date Inspection Summary Inspection on Februsiy 6 through March 3,1989 (Report No. 50-461/89006(DRS)) )
Areas Inspected: Routine, announced safety inspection of licensee actions j i on previously identified findings, Licensee Event Reports (LERs), Re 3 I G11de 1.97 commitments, and torque ' switches (Modules 92701 ,. and 92702gulatoryI Results: Of the areas inspected, one apparent violation was identified .l (failure to perform adequate corrective actions - Paragraph 3).
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. DETAILS !
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- 1. Persons Contacted
- 1 l i l a. Illinois Power Company (IPCo) ]
1 l *D.P. Hall,(VicePresident-q
- J. S. Perry,' Assistant Vice President q
- R. D. Freeman, Manager, NSED
-s J. G. Cook, Manager, Nuclear Planning and Support .
- J. Greenwood, Manager, Power Supply i R. E. Campbell, Manager, QA
- J. W. Wilson,' Manager, CPS.
R. E. Wyatt, Manager Nuclear Training D. L. Holtzcher, Acting Manager, Licensing .and Safety J. D. Weaver, Director, Licensing
- E. R. Bush, Director, Nuclear Program Scheduling j
- E. P. Vaughan, Director, Operations and Maintenance
- M. C. Hallon, Acting Director, Nuclear Programs M. E. D' Haem, Supervisor, Engineering W. S. Iliff, Supervisor, Licensing Administration
- K. A. Baker, Supervisor, I&E Interface
- S. L. Clary, Supervisor, Procurement
- K. Graff, Director, Operations Monitoring
- F. C. Edler, Director, Training P. Thompson, Supervi~sor, Electrical Systems !
T. Butera, QC Engineer
- b. U.S. Nuclear Regulatory Commission (USNRC)
P. L. Hiland, Senior Resident Inspector
- S. P. Ray, Resident Inspector
- Denotes those attending the site exit interview on February 10, 1989.
- 2. Licensee Action on Prei J .y Identified Findings
- a. (Closed) Violation (50-461/87026-03a(DRS)): This item addressed the incorrect qualified life of ASCO solenoid valve ORA 027.
The calculat*d qualified life was originally based on the valve being enero'ted for less than one hour a month while actual plant conaitions required the valve to be continuously energized.
Subsequent to the inspectio'n , the licensee revised their EQ binder (EQ-CLO24) to. reflect the correct qualified life of 9.13 years. The licensee has also completed further actions to prevent recurrence of this finding by reviewing all appropriate solenoid valves in regard to their qualified life, and have reported full compliance. No further concerns were identified.
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- b. -(Closed)_ Violation (50-461/87026-03b(DRS)): This item addressed a
. Junction box containing terminal blocks tfut having no weep hole
.. m. ga . . . . < , for removal of accumulated water and condensed. moisture during^ - 9T c .an accident.. Corrective action for this item is discussed under'
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- Section 2.f of.this report. ' '
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- , c. , (Closed) Violation (50-461/87026-03c(DRS)):".This..ites' addressed:l y
.a byJ.p. an oil leak: found on the motor case under the upper,moter' bearing ' . W-
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l'Np'4%m . drain. plug of the Low Pressure Core' Spray Motor IE21-C001. The-
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- . licensee performed an inspection on Auguste26,~1987, and' reported i that oil had not>1eaked from the~ drain plug. The inspector determinet.
that the oil previously found~on'the floor was'in fact a housekeeping deficiency that'has'since been corrected. No further concerns were identified.
l l d. (Closed) Violation (50-461/87026-03d(DRS$):.Thisitesaddressed-deficiencies found on the Fuel Pool Cooling Pump 1FC02PA. Deficiencies j included a missing bolt on the motor connection boxf rust on the !
motor connection box sealing surface, a~ broken thermocouple connection box cover with no. gasket indeterminate oil in the pump inboard bearing,andapoolofoIlunderthepumpoutboardbearing. Subsequent to the inspection the licensee took immediate corrective action'and ;
completed repairs. !
The inspector reviewed corrective actions taken to prevent the i recurrence of any such maintenance deficiencies. The licensee . :
provided records of their preventive. maintenance program that 1 periodically (about every .18 months) requires appropriate activities i to be performed to preserve the qualification of the equipment. The licensee also provided details of surveillance regularly performed by plant operators and by quality assurance inspectors. However, during a brief plant walkdown, the NRC inspector noted a rusty Limitorque valve stem, a leaky valve, a corroded pipe and a housekeeping deficiency which had not yet been identified by the
. plant's surveillance program. The inspecto'rs had no immediate safety concerns regarding these deficiencies.and the licensee took immediate corrective action. The licensee was informed that implemen-tation of their maintenance and surveillance programs would be further reviewed during an upcoming Region III maintenance inspection. No further concerns were identified.
- e. (Closed) Violation (50-461/88010-03(DRS)) and Unresolved Item (50-461/87026-01(DRS)): These items identified the lack of environmental qualification documentation'for two hundred and seventy Thomas and Betts nylon wire caps installed on the 480 V motor leads.of Limitorque operators. .. Subsequent.to this finding, the .
licensee performed a LOCA test at Wyle (January 29,1988) where '
it was detemined that these wire caps were . qualified for 9.9 years.
The licensee reported reworking some of the wire caps with qualified Okonite tape and scheduling replacement of others prior to the end of their qualified life.
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The inspector reviewed corrective steps taken by the licensee to prevent recurrence of such a deficiency. The NRC had identified
. . the wire caps as unqualified because there was no evidence in the s
licensee's EQ files that these components were tested along with Limitorque actuators. The licensee has now implemented checklist
- NF-208 for future EQ reviews which requires the reviewer to ensure c,. that the tested equipment is identical to the installed equipment
. , and that the equipment has been tested in its installed configuration.
The licensee also indicated that reviews are being conducted of significant event reports submitted by the Institute of Nuclear Power Operations, and that IPCo is tracking various other industry EQ information and data so as to be aware of any potential impact on the EQ of the equipment at Clinton. No further concerns were identified.
- f. (Closed) Violation (50-461/88010-02(DRS)); LER 87-066-00: This item addressed the lack of Weep holes in EQ junction boxes. These weep holes are required to drain accumulated water so as to prevent shorting of electrical circuits in the-junction box enclosures.
Subsequent to this NRC finding, the licensee reported installing weep holes in one hundred and fifty six junction boxes. This work was reported to be complete on November 12, 1987.
The inspector reviewed corrective steps taken to prevent recurrence.
The root cause of this deficiency was defined by the licensee as an unclear installation specification for the junction boxes by the architect / engineer Sargent & Lundy (S&L). Consequently, Engineering Change Notices were issued to correct drawings for this requirement and S&L specifications were reviewed to identify other discrepancies.
The licensee indicated that a training program was implemented to ensure that " appropriate personnel responsible for reviewing nonconformance documents and defining corrective actions are !
aware of the need to look for possible. generic implications of problems and take a broad view of remedial actions for hardware deficiencies."
During this review the inspector identified certain deficiencies in the licensee's corrective action and determined that full compliance has apparently not yet been achieved. Deficiencies regarding inadequate corrective action shall be tracked as a separate item and are described in Section 3.b of this report.
- g. (Closed) Violation 50-461/88010-01(DRS)); Unresolved Item T50-461/87026-02(DRS)): This item addressed unqualified AMP Kynar I
electrical butt splices found to be installed on EQ valve actuators, l solenoid valves 'and electrical junction boxes affecting multiple safety systems. Subsequent to this finding, these splices failed a LOCA test conducted by the licensee at Wyle Labs on October 9 through November 19, 1987. Upon learning of these test results, ,
the licensee immediately located these installed splices in the .
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- plant and reported to the NRC that 196 Kynar splices had been b.i4ph> iehMq reworked with qualified tape or Raychem tubing.' This work;wase cfWi % a 1, reported te be complete on. November 18, 1987. '
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W4 The inspector reviewed corrective step's taken by theblice;;see.ito n prevent recurrence of suchia deficiency.N The:NRC;h'ad; identified?- PM Kynar splices as. unqualified because there:was?no;evidencsM Qth$
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licensee's EQ files that these comporient(weni3eisteddnithsir'c$#L.. W installed configuration. '
NF-208 which requires the reviewer to ensure that'thb equi) ment is identical to the tested equipment and that thelequipment 4 has .)een tested in its installed configuration. The' licensee also .
indicated that reviews are.being conducted of significant event a ..
~4 reports submitted by the Institute 'of Nuclear Power Operations and ;
that IPC is tracking various other industry EQ information and data -
so as to be aware of 'any potential impact on the EQ of the equipment- ,
at Clinton.
During this current review, the NRC inspector reviewed several licensee identified deficiencies in the corrective action process. Based on- .
details described in Section 3.a of this report, full complianct has apparently not yet been achieved. Deficiencies regarding inadequate i corrective action shall.be tracked as a separate item. l
- h. (Closed) Open Item (50-461/07026-04(DRS)): This item addressed the inappropriate location of a "T" drain in Limitorque actuator ISX095A such.that the "T" drain would not provide drainage during an ,
accident. The licensee stated that actuators ISX095A and B were part of the combustible system gas control is no longer required
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systemany
'to ' perform roomsafety coolers functionand.that durin this.'g an accident; thus the actuators are being removed from the EQ list.
The NRC inspector ncted that the rooms associated with these coolers are now adequately ventilated by the containment and that no associated
. EQ equipment or operator action would be compromised. No further concerns were identified.
- 3. Licensee Corrective Action on Kynar Splices and Junction Boxes' During the periods of August 17 through October 12, 1987, and February 25 through March 31, 1988., Region III conducted inspections to verify the environmental qualification (EQ) of electrical equipment at the Clinton Station (Inspection Reports No. 50-461/87026(DRS) and No. 50-461/88010(DRS)).
As a result of these inspections, a $75,000 civil penalty was imposed on Illinois Power Company (IPCo) on June 1,1988. The Notice of Violation !
(NOV) that accompanied the civil penalty identified the following two deficiencies:
j 10 CFR 50.49(f) requires, in part, that each item of electrici equipment -
important to safety be qualified by testing and/or analysis under: .. e< a;' :
postulated environmental conditions.
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- " l f' NU w Contrary to the above, as of August 19, 1987, ment $
l important to safety was not qualified by appropriate testing and /orll the following equip ,
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analysis which reflected the installed configuration:v A - M'.x.b ; .1 M R m
- One hundred and ninety-six AMP Kynar electr ~ical butt' splice h * % %a. *Yik m installed in valve actuators, solenoid valves and electrical 6 '
t junctionboxesaffectingmultiplesafety. systems,';#.Mi.e-
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- One hundred and fifty-six junction boxes without.d'rainage. openings -
(weep holes) affecting multiple safety systems. ' m As a result of this violation, the licensee was required to take corrective steps and report the results achieved. On June 29, 1988, ~
IPC submitted a response to the NOV (DPM-0621-88) stating that the
- following steps had been taken to coreact the problem
I Kynar Splices:
"Upon learning of these test results on November.10, 1987, while CPS was in cold shutdown, IP immediately initiated a walkdown of electrical dev*ces in areas where 100% humidity could occur. During this walkdown, 196 AMP Kynar butt splices in these areas were located. Each of these was reworked using qualified tape or Raychem tubing, resulting in a l configuration that the NRC agrees is qualified.. See NRC Inspection Report No. 88010, Item 88010-01. The walkdown and rework of all butt l splices in high humidity areas was completed on November .18,1987, l prior to the time power ascension from the shutdown commenced."
l Junction Boxes:
"This problem was identified as a generic condition on November 5, 1987, while the plant was in cold shutdown. IP ordered that the plant remain in cold shutdown until a11~ of the junction boxes were repaired. A wikdown was conducted to identify all junction boxes lacking required weep holes. A total of 156 boxes were identified as lacking weep holes, These were reworked by drilling a drain hole in each. box. This work was completed on November 12, 1987, prior to initiating power ascension from the shutdown."
Summary of NRC Findings
- a. KYNAR Butt Splices:
In December 1988, during routine maintenance activities, the licensee-identified two limitorque operators containing unqualified AMP KYNAR butt splices. These valves were included in'the population of devices walked down by the licensee in 198L Subsequently, the licensee initiated a complete walkdown of all EQ devices having KYNAR butt splices and has identified a current total of six poA 6
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. i unqualified..KYNAR butt splices u five Limitorque operators. As l a result, these five 10 CFR 50.44 designated valves were inoperable during, plant operation. y +.
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In' determi'ning:the,fr'oot cause of the: inadequate inspections 3 2
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- ioccurred prio;.1987/.:the licensaeinspections rJ.to th'e.first walkdown.
detemined that planning
.in 1987 wase that.- - . ,
-+ ;:aincompletehWTheh M2Clinspector determined that.iniregard to these ". v' s ; '
1987 inspections":the"IPC administrative controls;and measures'were -
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inadequate .in :the areas ,
controls,' documentation,.of planning' accountability,
' communication,' . training-of inspectors, and quality conformance to. inspection procedures.' Consequently, there was a certain degree of confusion and some errors made during 'the q licensee's inspection process.
- b. Junction Boxes:
During this current review, the NRC inspector identified missing q we'ep holes in six boxes i';. stalled inside the Unit 1 containment and 1 in high energy line beca areas. The licensee later confirmed that ~
fifteen 10 CFR 50.49 designated EQ junction bcxec did not have weep holes for drainage of accumulated water. The licensee indicated that weep holes were only installed in boxes having terminal blocks, and the contents of the six boxes were qualified for submergence.
All fifteen be.es are inside' the containment or high energy line break areas (HELB) and are exposed to spray during an accident. Since the box is not sealed, water is postulated to pour into the box from top and side conduit entries and from unsealed covers. Moisture is also introduced during the accident through the box cover to condense and accumulate in the box. The inspector requested the licensee to verify whether the contents of the boxes without weep holes were ,
qualified for submergence. The following items in the boxes were l identified as requiring qualification for submergence:
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- Raychem splices.
- Okonite Wire, Single Conductor No.1619X with 0.015" Okozel (Tetzel .280) insulation (Instrumentation Cable; Okonite Report No. SL-IP-1081 dated October 29,1981).
- Conax Electrical Conductor Seal Assembly (ECSA) with Kapton insulated leads (Conax Report IPS-1079, Revision D, May 2%,
1984).
- Okonite T-95 and T-35 splicing tapes (Okonite Report No.
NQRN-3).
The Raychem splices were found adequately tested for submergence, however,'the inspector noted that based on the documentation in the licensee's EQ files, the Okonite wire, Kapton leads and Okonite tapes -
were not qualified for submergence. The inspector also noted that
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.' the summary sheets .in the EQ files for Okonite cable and tapes .
stated " Submergence - N/A" and that there was no apparent evaluation
- for submergence in these files.-
- Subsequentf to th'e NRC concer'ns identified in Paragraphs 3a and'3h of'
, this report, the licensee provided additional documentation in'an? '
attempt to establish-qualification.of the Kapton leads,-the Okonite r, < cable, and the.0konite-tape' for post LOCA ' submergence; LIn regard to
, the ECSA Kapton leads, the licensee submitted Conax 3eport-IPS-1079, Revision D,:May 21.-1984 and Canax Installation Manual IPS-725,.
Revision G, February 15, 1985 to address submergence...The inspector
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noted that in the Conax test, Kapton leads were encased in a tight polyolefin tube.and then inserted in a flex conduit before being. .
immersed in water. It was not clear whether the pigtails were wet in such a configuration. This is significant because.the Kapton leads-l insta11ed'in the plant have no polyolefin tube or flex conduit in the i
postulated submerged condition in the field. Further,- one of two-
. samples failed the test requiring modification of the test circuit j .for the second sampw. It was not clear how the measurements were taken and whether they were taken while the leads were submerged.
Based on a lack of adequate test. documentation, the NRC inspector concluded that the Kapton leads here unqualified for submergence and that their appropriate junction box enclosures required weep holes'.
In regard to the Okonite cable and; tapes, the licensee submitted Okonite test reports SL-IP-1081,' October 29, 1981-and NQRN-3 which indicated that a voltage withstand. test at 80 volts / mil was performed on post LOCA test samples immersed in tap' water for five minutes. The inspector informed the licensee that.to demonstrate qualification for submergence, the specimens must be submerged during the test for the duration required during and after an accident. The licensee also provided a water absorption test.for both Okonite cable.and . tapes; however, this test did not subject the samples to. thermal or radiation aging prior to submergence. Based on a lack of adequate test documentation, the NRC inspector concluded that the Okonite cable and tapes were unqualified for. submergence, and that their appropriate junction box enclosures required weep holes. Subsequent to these findings, the licensee immediately installed weep holes in the boxes to mitigate any immediate safety concerns.
10 CFR 50, Appendix B, Criterion XVI, " corrective Action" requires, in part, that measures be established to assure that conditions adverse to quality such'as defective material and equipment are promptly' identified and corrected. In the case of significant conditions adverse to quality the. measures sha11' assure that the cause of the condition is determined and corrective action taken to preclude repetition. The identification ci1the significant condition adverse to quality, the cause of the condition, and the corrective
' action taken shall be documented and reported to appropriate levels of management. Based on the NRC review, the licensee failed to perform adequate corrective action in repairing the previously _.
identified unqualified Kynar electrical butt splices and junction 8
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-l boxes without weep holes. This was evidenced by the licensee's e t ~l failure to ensure that corrective actions taken included adequate. " '-
l design control (weep holes), document control, quality controle. q.M;s-oM q and conformance to intoection procedures. The licensee's / failure toms ~ 4 i perform adequate' corrective action .is considered an' apparent violation W ' 4 i of 10 CFR 50, Appendix B, Criterion XVI (50-461/89006-01(DRS)). - @ %
- 4. Regulatory Guide 1.97 Commitments ~a . c. . % .:4.+k,7w - WMc . I '!
The Clinton Station' Regulatory Guide '(RG) 1.97 SER identified two' -}.
outstanding commitments in regard to the neutron flux detectors and I the reactor pressure vessel water level fuel zone range. indicators.
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- a. The licensee is committed to upgrade their. neutron flux setectors to-the requirements.of RG 1.97, Category 1. The inspector infomed the licensee that systems were currently available for such applications, . i and that the , licensee was required by RG 1.97 to. initiate reviews of I these systems. The licensee stated that they were currently in the !
process of reviewing available systems and shall inform the NRC of their' progress in this area. 1
- b. The licensee is committed to' provide Class 1E pewrr to. reactor ,
water level fuel zone. range indicator 821-R610-(Division 2) and J recorder B21-R615 (Division 1). The inspector reviewed appropriate I schematics for independence of power supplies and appropriate j isolation. I No concerns were identified.
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- 5. Replacement of Limitorque Mela W e Torque Switches' ' '
A 10 CFR 21 report issued by Limitorque alerted the industry to potential functional failures of Melamine torque switches installed .in certain actuators. According to the report, the Melamine shafts of these torque switches are very susceptible to high temperatures and may have become slightly warped during production. . This could cause these shafts to break during operation. The licensee took immediate corrective action and replaced all appropriate EQ valve torque switches with qualified Fiberite torque switches.
No further concerns were identified.
- 6. Mixed Lubricants in Limitorque Actuators On February 6,1987, the licensee identified mixed lubricants in a limitorque actuator limit switch gear box. The mixture ,was :apparently 50% Beacon 325 and 50% Mobil 28. These lubricants are not compatible. 1 The licensee subsequently issued Special Procedure 8451.01 (current Revision 17) to ensure mixing would not occur in the future. The licensee also checked all appropriate valves for mixing and replaced lubricants where necessary. . ,_.
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f-On September 15, 1987, the licensee issued Condition Report CR 1-87-09-053, Revision 0, regarding valves 1FP051 and 1FP054 because maintenance found Exxon Nebula in these valves while the preventive maintenance. document W -
required Sun Oil EP-50. The licensee reported, however, that'lthere was . . *' - ,
no mixing of lubricants and that Exxon Nebula is a qualified 2 grease'; ' A' i '
similar concern was identified on November 18, 1988 regarding valve 1FC036;?O however, there was.no mixing of lubricants reported. e ;t ;p ' ' -
No further concerns were identified. - i
- 7. Exit Interview The Region III inspector met with the licensee's. representatives (denoted in Paragraph 1) during a site exit on February 10, 1989. The inspector summarized the purpose and findings of the inspection and the licensee acknowledged this information. The licensee did not identify any documents / processes reviewed during the inspection as proprietary.
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( c ,, i U. 3. NUCLEAR REGULATORY COMMISSION REGION III l Report No. 50-461/89014(DRP) License No. NPF-62 Docket No. 50-461 1 Licensee: Illinois Power Company 500 South 27th Street Decatur, IL 62525 Facility Name: Clinton Power Station 1 Inspection At: Clinton Site, Clinton, IL Inspection Conducted: March 16, 1989, through May 30, 1989 Inspectors: P. Hiland S. Ray . A. Gautam I Approved By: M. A. Ring, Chie [ Date Reactor Pro.jects Section 3B Inspect fon Sumary Inssection on March 16, 1989, through May 30, 1989 (Report No. 50-461/89014 Inspected: Routine, unannounced safety inspection by the resident inspectors of licensee action on previous inspection findings; regional requests; NRC compliance bulletin and generic letter followup; operational safety verification; monthly maintenance observation; monthly surveillance observation; onsite followup of events at operating reactors; environmental qualification of electrical equipment; and Temporary Instruction 2515/100. Results: Of the nine areas inspected, five violations and an apparent violation were identified. One was in the area of followup of. previous inspection findings concerning improper mountin Diesel Generator Service Water Heat Exchanger Paragraph 2d).(g Three of thewere Division'III in the area of operational safety verification concernin adequately control the Service Air System (Paragraph Sc)g failure to
, failure to bypass thermal overload protection on active safety-related valves (Paragraph 5d),
' and failure to control locked valves (Paragraph 5f). The remaining violation was in the area of onsite followup of events at operating reactors concerning inadequate procedures for control of plant testing (Paragra One apparent violation of 10 CFR 50.49 (eith several examples) ph concerning failure 8b(1)) Octn im m >, ? < < / v tvowvi 't Q'. - c
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{ to qualify electrical equipment important to safety for postulated harsh ) environments during an accident was also identified (Paragraph 9). In I addition, one " licensee-identified" violation was discussed in the area of { operational safety verification concerning inadequate testing of Average Power I Range Monitors. One unresolved item was identified in the area of operational i safety verification concerning missing conduit seals in secondary containment penetrations. i l l 1 2
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, (;' ( ' DETAILS ]'
I j
- 1. Personnel Contacted Illinois Power Company (IP)
W. Kelley, President W. Gerstner, Executive Vice President
*fD. Hall, Vice President - Nuclear J. ' Perry, Assistant Vice President'
** K. Baker, Supervisor - I&E Interface
**fR. Campbell, Manager - Quality Assurance ., 3 j
- J. Cook, Manager - Nuclear Planning and Support R. Freeman, Manager - Nuclear Station Engineering Department
* #D. Holtzcher, Acting Manager - Licensing & Safety J
- J. Miller, Manager - Scheduling & Outage Management R. Schultz, Director - Flanning & Programing
- J. Weaver, Director - Licer. sing
- J. Wilson, Manager - Clinton i>o.icr Station
- R. Wyatt, Manager - Nuclear Training Soyland J. Greenwood, Manager - Power Supply Nuclear Regulatory Commission R. Cooper, Chief Engineering Branch, Region III
**fP. Hiland, Senior Resident Inspector, Clinton fH. Miller, Director, Division of Reactor Safety Region III .
*fS. Ray, Resident. Inspector, Clinton
#M. Ring, Chief, Division of Reactor Projects, Region III
- Denotes thor,e attending the monthly exit meeting on May 12, 1989.
i
- Denotes those attending the exit n:eeting on May 30, 1989.
# Denotes those attending the management meeting on March 21, 1989.
The inspectors also contacted and interviewed other licensee and contractor personnel. l l l 2. Previously Identified Items (90712)(92700)(92701)(92702) I i a. (Closed) Oyen Item (461/88014-03): Defective Installation of Secondary ;ontainment Boot Seals. ._ This item was discussed in Inspection Report 50-461/88014, Paragraph 8.b. The item remained cpen pending installation of backing rings to several secondary containment boot seals during l I 3
( ( the current refueling outage. Inspectors' field observations during the outage confirmed that the backing rings have been installed. This item is closed.
- b. (Closed) Unresolved Item (461/88030-02}: Uninsulated Butt Splices in Environmentally Qualified Equipment.
Followup of this item was documented in Inspection Report 50-461/89006, Paragraph 3, by a regional specialist and was being tracked by Unresolved Item 461/89006-01. Unresolved Item 461/88030-02 is closed. ,
- c. (Closed) Open Item (461/88030-03): Licensee Response to Part 21 Notification Concerning White Melamine Torque Switches.
This item was adequately addressed and the tsue closed in Inspection Report 50-461/89006, Paragraph 5, by a regional specialist. This item is closed.
- d. (Closed) Unresolved Item (461/89008-04) and LER 89-017-00 (461/89017-LL): Failure of Division III Diesel Generator Heat Exchanger to Meet Seismic Qualifications.
This item was previously discussed in inspection report 50-461/89008, Paragraph 5.g. At the time of that inspection the item was left unresolved pending the licensee's determination of the cause of the missing mounting hardware and its effect on diesel generator (DG) operability. The licensee completed their investigation and issued Licensee Event Report (LER) 89-017-00 dated April 27, 1989. The LER reported that the Division III DG and therefore the High Pressure Core Spray (HPCS) System had been technically inoperable since the beginning of plant operation. Three of the four mounting bolts for the diesel's Shutdown Service Water (SX) System Heat Exchanger had not been installed properly. The result was that the diesel did not meet seismic qualification requirements and may not have been able to perform its design function. Thus in the case of a loss of offsite power, a design basis earthquake, and a loss of coolant accident, the HPCS system might not have been available. Technical Specification 3.8.1.1.b required that three separate l ' and independent diesel generators be OPERABLE. Technical Specification 3.5.1.c further required that the HPCS system be OPERABLE. Failure of the licensee to maintain the Division III DG and the HPCS system OPERABLE from initial plant operations in February 1987 until the SX Heat Exchanger was properly mounted on March 2, 1989, is considered a Violation (461/89014-01). 4
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- The inspectors reviewed the licensee's evaluation of the cause j of the event and the corrective action taken as described in LER 89-017-00. The cause was believed to be the bolts being removed {
and not properly reinstalled during construction. Records of i the material receipt _ inspection showed that the heat exchanger i was specifically inspected with satisfactory results. No ] maintenance activities had been performed that would have resulted 1 in the removal of the bolts after plant operations began. l Corrective actions included installing the bolts under Maintenance i Work Request D05148 and inspecting the other DGs to verify that similar conditions didn't exist. Both actions have been completed. ' Based on the inspectors' review of the corrective actions for this violation, no additional response is required and this violation is closed. Related Unresolved Item 461/89008-04 and LER 89-017-00 i (461/88017-LL)arealsoclosed.
- e. (Closed)_UnresolvedItem(461/89008-08): Fotential Deviation ,
From Regulatory Guide 1.105. I This item was discussed in Inspection Report 50-461/89008 Paragraph 5.j. The issue involved the licensee's discovery that their architect-engineer, Sargent and Lundy Engineers (S&L), had used a six month calibration frequency when calculating the drift rate and setpoints for many Technical Specification instruments ; and other instruments in systems important to safety. The Technical i Specifications required that the instruments be calibrated on at i least an 18 month frequency. Regulatory Guide 1.105, Revision 1, to which the licensee was committed by Section 1.8 of their Updated Safety Analysis Report, required that setpoints on instruments important to safety be established with sufficient margin between l the Technical Specification limit for the process variable and the i nominal trip setpoint to allow for the instrument drift that l could occur during the interval between calibrations. Thus for instruments that were being calibrated every 18 months, the setpoint may have drifted beyoni the allowed Technical Specification limit. The licensee originally documented the concern in Condition Report 1-87-12-071 dated December 29, 1987. The inspectors reviewed the engineering disposition and action plan for the condition report dated April 5, 1989. The licensee included 268 instruments in the original Regulatory Guide 1.105 scope after accounting for additions and deletions due to modifications. Of l these, 146 instruments were not included in the Technical l Specifications. Because of certain ambiguities in the wording I of Regulatory Guide 1.105 Revision 1, concerning the scope of instruments it covered, the licensee contacted the NRC's Instrumentation and Control Systems Branch Chief in NRR on March 9, 1989. These comments were documented in Record of Coordination Y-210304 by the licensee. NRR stated that the intended scope of Regulatory Guide 1.105, Revision 1, was instruments that are listed in the plant Technical Specifications. This scope was clarified in Revision 2 of the Regulatory Guide. . 5
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.NRR stated that the remainder of plant instruments should be maintained under a program umbrella which exercised sound engineering judgement for establishing setpoint and calibration criteria.
For the Technical Specification instruments, the licensee found that 50 had setpoints that would support the 18 month surveillance interval listed in the Technical Specifications. The remainder had setpoint calculations that would support only a six month interval. For those instruments the licensee l instituted a six month calibration frequency. They also intended to submit a proposed change to the setpoints in the Technical Specifications to support an 18 month calibration ) frequency by late 1989. The Itcensee investigated the safety { significance of allowing surveillance intervals for Technical i Specification instruments that were longer than the intervals that could be supported by the setpoint drift calculations. Their conclusion was that none of the Technical Specification j s instruments had "as found" setpoints that were outside the j allowed range even when calibrations had been performed at longer than six month intervals. The inspectors reviewed the i' licensee's findings and determined that their conclusion that the issue had not been safety significant was reasonable.
'During the licensee's investigation of this issue they discovered that over 100 instruments in non-Technical Specification systems did not have any existing surveillance or preventative maintenance procedures. Most of these instruments were on vendpr supplied equipment such as air conditioning refrigeration units. Most of j the equipment affected was considered support equipment for 1 Technical Specification systems such as switchgear heat removal systems and area room coolers. The licensee calibrated all the affected instruments in the current refueling outage and was developing appropriate preventative maintenance programs to maintain their calibration at frequencies supported by sound engineering judgement. The licensee also upgraded the seismic !
qualifications of some of the support instruments. l The root cause for the problems identified in instrument setpoints was attributed to poor communication between the Itcensee and S&L concerning calibration intervals and inadequate review by the licensee's engineering and maintenance staffs of $&L's scope and ' i the results of their calculations. Although the condition was originally identified on December 29, 1987, aggressive corrective action did not begin until February,1989. The reason for the delay was that the Nuclear Station Engineering Department had made . a preliminary determination that the instruments' setpoints would l support an 18 month calibration interval based on recalculating i r
e c 1 the drift for two randomly selected ir.struments. S&L was then tasked to perform all the applicable drift calculations again but was given until February 15, 1989, to complete the task. The licensee apparently did not become aware that the drift calculations , for many of the instruments showed that an 18 month interval could 1 not be supported until the entire task was completed. Once the , l licensee became aware of the problem, the inspectors noted that-rapid, extensive, and sound actions to resolve the issues were taken. The licensee kep* the inspectors informed of the progress with periodic updates. This item is closed.
- f. (Open) Violation (461/89008-09d): Spill of Reactor Water.During Restoration of System from Testing.
This event was discussed in Inspection Report 50-461/89008, Paragraph 8.b.(9). The associated Notice of Violation required that the licensee respond within thirty days of the date of the. Notice (April 12,1989) pursuant to tha provisions of 10 CFR 2.201. In light of similar events discussed in this inspection report, NRC regional management suggested that the licensee ilay the response to Violation 461/89008-09d and submit it concurrently with the ' response to the violations identified in this report. ' One violation was identified.
- 3. Followup of Reuional Requests (92701)
- a. Due to problems noted at the. Perry Nuclear Plant with high temperatures in the upper portion of the drywell, the inspectors reviewed the licensee's response to those concerns. General i
Electric issued Rapid Information Communication Service Information Letter No. 41 on March 31, 1989, to report the problem. The licensee responded with meuorandum Y-91151 from ' R. D. Freeman dated April 10, 1989. The memorandum discussed actions the licensee had previously taknn to monitor drywell temperatures and improve temperature costrols. The memorandum also discussed inspections of equipraent in the drywell as c result of the drywell wetting event dis:ussed in Paragraph 5.c below. No evidence of damage to electrleal cables was noted. The inspectors conducted a field walkdown of the area of. interest and noted that Clinton has very few safety-related ! cables or other devices in this area that could be affected by radiative heat from the refueling bellows. The inspectors did r.ote one safety-related mechanical snubber in the zone. Discussions i with the licensee indicated that the snubber (1RE315295) had been one of the ones that had failed during the inspection program in the refue' ling outage. The failure was thought to be similar to other snubber failures and was attributed to construction activities. The inspectors suggested that this particular snubber failure be 7
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reexamined in light of the fact that. Perry had found two similar snubbers that had failed due to excessive temperatures.' The licensee provided memorandum Y-91279 from S.-R. Bell dated April 21, 1989 which documented observations noted about the condition of the snJbber during disassembly. 'No damage' attributed to excessive heat was noted. .The replacement snubber was required to be ratested during'the next refueling outage. The results of.that testing were to determine if additional actions were needed.
- b. In response to a potential safety problem with the location of.
hydrogen storage tanks identified at the Trojan Nuclear Plant,. NRC regional management requested that the inspectors confirm
.that a similar problem did not exist at Clinton. Details of the roblem'at Trojan were contained in-IE Information Notice 89-44, gHydrogen Storage on the Roof of the Control Room."
Specifically regional management requested that the inspectors obtain the following information: (1) The distance from the hydrogen storage facility to the nearest safety-related structure or air intake; (2) The maximum volume of gaseous or liquid hydrogen stored onsite in standard cubic feet or gallons respectively. The licensee provided the following information: ; (1) The distance from the hydrogen storage facility to the nearest safety related structure was 432 feet. 'The distance to the nearest safety-related air intake was about 560 feet. The distance to the nearest non safety-related air intake was about 190 feet; (2) The maximum volume of gaseous or liquid hydrogen stored 4 onsite was 60,800 standard cubic feet. , The inspectors confirmed the above information by direct field observation. No violations or deviations were identified. l;
- 4. 1E Bulletin and Generic Letter Followup (92703) 1 Audibility Problems L a. (Closed) IE Bulletin 79-18 (461/79018-BB):
Encountered on Evacuation of Personnel From High-Noise Areas. This bulletin was previously discussed in the following' Inspection Reports: 50-461/84019, Paragraph 2.a; 50-461/86048, Faragraph 2.f; 50-461/86055 Paragraph 4; 50-461/86059, Paragraph 2.d; 50-461/86060, Paragraph 2.1; and 50-461/86072, Paragraph 2.d. The remaining ! commitments were to conduct surveys of high noise areas during the 1 8 3 l
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( (' y , ~! startup test' program and complete all necessary corrective actions l prior to the end of the first refueling outage. The inspectors. reviewed Maintenance Work Requests (MWRs) C50374, C40941, C55233, and D00329 as well as Field Problem Report 201794, and Field ~ Alteration CQF001. In some areas of the plant the licensee was - unable to provide adequate public address coverage due to high j noise.- For those areas a sign was installed at the entrances stating " CAUTION LIMITED GAITRONICS AREA USE ALTERNATE COMMUNICATIONS." The inspectors noted that no training commitments were in place to ensure plant personnel were trained on the meaning of the signs and the actions they should take if working in the high noise areas. The licensee provided Memorandum Y-210673 which committed to add training on the meaning and use of the signs to i their training program. Based on the licensee's commitment this item is closed.
- b. (Closed) Generic Letter 88-11 (461/88011-GL): NRC' Position on l Radiation Embrittlement of Reactor Vessel Materials and Its Impact on Plant Operations.
The licensee submitted Letter U-601317 dated December 6, 1988, in response to the generic letter. :The letter outlines the licensee's 1 intended actions to comply with Regulatory Guide 1.99, Revision 2. In a letter dated May 8, 1989, John Hickman, NRR Project Manager-for Clinton, stated that the staff considered the commitments satisfactory. This item is closed.
- c. (0 pen) Generic Letter 88-14 (461/88014-GL): ' Instrument Air Supply Systm Problems Affecting Safety-Related Equipment.
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The licensee submitted Letter U-601384' dated April 6,1989, in -
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response to the generic letter. The letter outlined the-licensee's review of NUREG-1275 and action they had taken and intended to take to maintain proper instrument air quality. In a letter dated May 3,1989, John Hickmani NRR Project Manager for Clinton, stated that the issue would be closed when the staff was informed of the completion of modifications (IAF007) which will help alleviate moisture accumulation and allow testing of individual dryer air quality.
- 5. Operational Safety Verification (71707)
The inspectors observed control room operations, attended selected pre-shift briefings, reviewed applicable logs, and conducted discussions with control room operators during the inspection period. The inspectors verified the operability of selected emergency systems and verified tracking of LCOs. Routine tours of the auxiliary. fuel, containment, control, diesel generator, and turbine buildings and the screenhouse were conducted to observe plant equipment conditions including the potential for fire hazards, fluid leaks, and operating e. 9
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( conditions (i.e., vibration, process parameters, operating temperatures, etc). .The inspectors verified that maintenance requests had been initiated for discrepant conditions observed. The. inspectors verified by direct observation and discussion with plant personnel that security procedures and radiation protection (RP) controls were being properly I implemented. Inspections were routinely performed to ensure that the licensee conducted activities at the facility safely and in conformance with regulatory requirements. The inspections focused on the implementation and'overall effectiveness of the licensee's control of operating activities, and the performance of licensed and nonifcensed operators and shift technical advisors. The following items were considered during these inspections:
- Adequacy of plant staffing and supervision.
- Control room professionalism, including procedure adherence, operator attentiveness and response to alarms, events, and off-normal conditions.
- Operability of selected safety-related systems, including attendant alarms, instrumentation, and controls.
- Maintenance of quality records and reports.
During the satire inspection period the plant remained in OPERATIONAL CONDITION 4 (Cold Shutdown) for the first refueling outage.
- a. On March 12, 1989, while conducting Surveillance Procedure CPS No. 9080.03, " Diesel Generator 1A(1B) Operability - 24 Hour and LOP Test," the Division II Diesel Generator (DG) experienced a valid test failure. The failure was attributed to reduced fuel oil pressure. The licensee reported the failure as Special Report U-601421 dated April 12, 1989, in accordance with Technical Specification 6.9.2.
The licensee reported that the fuel oil problem was caused by a crack in the 5/8" diameter inlet tubing on the engine-driven fuel oil pump of the 16-cylinder engine. The crack was located on the inner radius of a bend in the tubing which was bent beyond an acceptable limit (kinked) during installation. The root cause of the crack was believed to be fatigue due to normal vibration during operation. This event was the second valid failure of the Division II DG in the last 20 valid tests of the unit. Thus the test frequency for the DG was changed from at least once per 31 days to at least once per 7 days in accordance with Technical Specification Table 4.8.1.1.2-1. - 10
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( .[ The inspectors 'noted that IE Information Notice 89-07 issued January 25, 1989, discussed similar failures in small diameter tubing in fuel oil' systems as well.as other safety-related
. systems. .The insper.tcrs confirmed that the licensee had-received the Information Notice and that it was.being evaluated by the Nuclear Station Engineering Department.
- b. On March 13, 1989, the licensee identified that.the Average Power Range' Monitor (APRM) surveillance, which had been conducted'on March 11, 1989, had_been conducted improperly. ..Thus the APRMs were all considered inoperable and the plant had been in violation of its Technical Specifications.
- The' licensee reported the event = as Licensee Event Report (LER) 89-015-00 dated April 10, 1989.. The cause of.the event was attributed to -inadequate review of the Technical Specification requirements by the Line' Assistant Shift Supervisor (LASS). On March 11.1989, the LASS had directed Section 8.3 of theControlRoomOperatortoperformonigAPRMChannel Surveillance Procedure CPS No. 9031.12, Functional." . Section 8.3 provided instructions for performing APRM neutron flux "setdown' scram and rod block functional testing. Section 8.4 of the same procedure, which provided the instructions for performing APRM " inoperative" scram and-rod block functional testing, should also have been specified. The completion of both sections of the. surveillance was necessary to demonstrate APRM operability f or the existing plant conditions.
Technical Specification 4.3.1.1 required, in part, that~ each reactor protection instrumentation channel be demonstrated OPERABLE by the-performance of CHANNEL FUNCTIONAL TESTS for the OPERATIONAL. CONDITIONS and at the frequencies shown in Table 4.3.1.1-1. That table required that in OPERATIONAL CONDITIONS 3,4,and 5, the two APRM protective features discussed above be demonstrated at least ; weekly. The time limit for the surveillance had expired at 6:50 p.m. on March 11, 1989. Section 8.4 of the surveillance was. l not completed until 3:15 p.m. on March 13. Since all control rods. l were inserted during that entire time period, and the. surveillance performed on March 13 indicated that the APRMs had been functional between March 11 and March 13, the safety significance of the .! violation was minor. This event-was considered a " licensee-identified" Violation (461/89014-02). for which a notice of violation was not issued in accordance with 10 CFR 2, Appendix C,. Section _V.G.I. ! i This item is closed. The inspectors will review the corrective actions for the LER separately. l t
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- c. On March 20, 1989, with the reactor plant in OPERATIONAL CONDITION 4 (Cold Shutdown), about 40,000_ gallons of water was gravity drained from the containment refuel pool into the.
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( [ ] u drywell. The gravity drain of water into the drywell occurred I when Service Air (SA) was isolated to the containment rcsulting ] in.a loss of seals on the gate separating the dryer storage pool 4 from the reactor cavity pool. The drywell head was installed j but'not fully torqued. i At the.ti~ af event occurrence, the inspector was monitoring control ,,.,a activitie.s and observed plant operators respond to ; the event Plant operators attempted to' reduce the ingress of j water into the drywell by draining the reactor cavity to the main' condenser. In addition, appropriate announcements were l made over the plant public address system to advise personnel of ] the event and direct them to stay clear of the drywell. Plant l operators restored SA to the containment, wtich was effective in i l stopping the leakage past the gate seals. A subsequent critique of this event identified that the SA tagout had not been adequately evaluated.for plant impact prior , to implementation. In addition, the schedule for hanging the SA ' tagout showed the activity was not to be performed prior to q filling both upper poolr. ,q l Technical Specification 6.8.1.a required that. written procedures be established, implemented, and maintained covering the Authorities-and Responsibilities for Safe Operation and Shutdown. ' Administrative Procedure CPS No. 1401.01, " Conduct of Operations," Revision 16, _ j art,-that dated December 14, 1988, Paragraph 8.5.5.1.b,-required, in p/ Assistant prior to removing a system from service the Shift Supervisor i Shift Supervisor evaluate the impact on other equipment and on plant operations. Failure of the Shift Supervisor / Assistant Shift Supervisor to adequately evaluate the impact of removing the Service Air system from service is a Violation (461/89014-03). The inspectors noted that the licensee established and implemented an inspection plan to verify that no damage to safety-related components occurred as a result of this event. That plan included a visual inspection of the following equipment located in the drywell: j ASCO solenoid valves; Valcor solenoid valves; NAMCO limit switches; Drywell pull boxes; Drywell junction boxes; Motor operated valves; Hydrogen ignitors; and HVAC components. The preliminary result ( of that inspection identified no equipment damage'from the drywell spray event; however, three 1E pull. boxes, three non-1E pull boxes, ' and two non-1E junction boxes were found to contain standing water
- d. On April 6,1989, the licensee identifieda number of motor' .
operated valves with installed thermal overload protection that, 4 12 ,
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( , ( contrary to the licensee's commitment to Regulatory Guide 1.106, were not bypassed when required to perform an active safety function. As documented in Condition Report 1-89-04-026, the following valves were found by the licensee to have installed thermal overloads that were not bypassed in the direction noted: VALVE NUMBER- SYSTEM DIRECTION 1E32-F001A,E,J,N MSIV LEAK CONTROL OPEN 1E32-F002A,E,J,N OPEN 1E32-F003A,E,J,N OPEN 1E32-F006,7,8,9 OPEN IC11-F083 CONTROL ROD DRIVE CLOSE 1HG-001 COMBUSTIBLE GAS CONTROL CLOSE 1E12-F009 RESIDUAL HEAT REMOVAL OPEN. Clinton Power Station Updated Safety Analysis Report (USAR), Paragraph 8.1.6.1.19 detailed the licensee's commitment to Regulatory Guide 1.106. That commitment was stated "Clinton Power Station complies with position C.I.a continuously bypassing in the safety direction (i.e., open or closed circuit) the thermal overloads ..." In addition USAR Table 6.2.47 identified the following " POST LOCA" valve positions for containment penetration isolation valves: i VALVE POST LOCA POSITION 1E32F001A,E,J,N OPEN/ SHUT i IC11-F003 OPEN/ SHUT 1HG-001 OPEN/ SHUT CPS Technical Specification Table 3.8.4.2-1 listed motor operated valves with thermal overloads bypassed continuously. All of the above motor operated valves (except IC11-F083) were listed in Table 3.8.4.2-1 as having thermal overloads bypassed in one direction only. - 10 CFR 50, Appendix B, Criteria III stated, in part, that measures l shall be established to assure that applicable regulatory require- l 13
c ( _,' ments and the design basis as speci::ed in the license application are correctly translated into specifications. Failure of the licensee to translate from their design basis and commitment to Regulatory Guide 1.106 the requirement to bypass thermal overloads
'in the safety direction of the above motor operated valves is a Violation (461/89014-04).
- e. 'On April 10, 1989, while in the process of drilling weep holes in electrical pull boxes, the licensee discovered air blowing out of two pull boxes in the.secendary gas control boundary.
extension area in the southeast corner of the 781' elevation of the Auxiliary Building. The licensee's investigation determined that five conduit penetrations through the secondary containment in that area did not have internal ventilation seals -installed. The licensee installed the penetration seals under Maintenance Work Request D01060. The licensee determined that the condition had existed since initial plant construction but had not been safety significant because, although leakage paths existed through the secondary containment, any bypass leakage had already been accounted for in preoperational secondary containment drawdown tests. In addition periodic surveillance testing had. verified that secondary containment bypass leakage was less than the design basis and low enough that the Standby Gas Treatment system was able to perform its design function. The inspectors reviewed the licensee's actions in response to the finding and noted that the licensee had not reported the event to the NRC even though LER 89-006-00 had been issued to report three similar secondary containment penetrations which I were missing their internal ventilation seals. Corrective actions for that LER included a review of an additional 127 secondary containment electrical penetrations to insure they had their internal ventilation seals. However, the scope of that corrective action was limited to penetrations through sec,ondary containment airlock walls and not other walls in the secondary containment. The inspectors also noted that there was no indication that the licensee had. investigated other. penetrations in the secondary l gas control boundary extensions to see if internal ventilation seals were installed. The inspectors' field verifications j' ' indicated that other penetrations in the four boundary extension areas appeared to be identically constructed to the ones that i were found to be missing their seals. The inspectors also noted that the five penetrations were among nine that had been noted , to have their external boot seals improperly installed as discussed in Inspection Report 50-461/88014, Paragraph 8.b. Unresolved Item 461/88014-04 was written pending the licensee's determination of the root cause of the improper boot seals. !
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- The inspectors requested that the licensee further evaluate the potential generic implications of missing conduit seals. This was considered an Unresolved item (461/89014-05) pending further review of licensee actions.
- f. On April 20, 1989, the inspectors notified the Shift Supervisor- l I
that they had noted several valves in the Scram Discharge Volume (SDV) instrumentation that were not locked in position. The J valves noted were IC11-155A&B, IC11-158A&B, IC11-362A&B, IC11-163A&B, ~1C11-164A&B, and IC11-165A&B. All the valves had
" Locked Valve" signs attached. The inspector's review determined that both Operating Procedure CPS No. 3304.01V001,
" Control Rod Hydraulic and Control Valve Lineup," performed on February 24, 1989, and CPS No. 3001.01V001, " Locked Valve List,"
performed on April 11, 1989, indicated that the valves were , locked in position. The licensee performed the entire CPS No. 3301.01V001 procedure again and noted that all other valves were locked in their proper positions. They initially indicated that they were unable to determine the cause of the SDV va'Ives being unlocked. This finding was similar to a previously identified Violation (461/87031-05) discussed in Inspection Report 50-461/87031, Paragraph 8.f in which the inspectors noted several of the same i valves unlocked. Corrective actions for that violation included installation of the " Locked Valve" signs and training of operating and maintenance personnel. That violation was also discussed in Inspection Report 50-461/87032, Paragraph 2.g, and closed in Inspection Report 50-461/67039, Paragraph 2.c. Technical Specification 6.8.1.a required that written procedures ' be established, implemented, and maintained covering equipment control (e.g. , locking and tagging). Administrative Procedure CPS No. 1401.01, " Conduct of Operations," required, in part, the Shift Supervisor / Assistant Shift Supervisor authorize the manipulation of a locked valve, through either the safety tagging program, or an approved operating or surveillance procedure that contains the proper controls to ensure that valve is returned to its proper position and relocked. At some time between April 11, and April 20, 1989, 12 locked valves in the 2 Scram Discharge Instrument Volume were unlocked without proper controls to ensure they were relocked. Failure to properly . implement Administrative Procedure 1401.01 is a Violation (461/89014-06). Although the valves involved in this violation were found to be in their correct positions, the apparent lack of rigorous administrative controls over locked valves despite a previously identified violation is considered significant. In their 15
(' response to this violation the licensee was requested to provide the results of their investigation into the specific cause of the valves being unlocked.
- g. During the report period, a NRC maintenance team inspection was conducted at CPS. The results of that inspection were documented in Inspection Report 50-461/89003. During that inspection effort it was noted that calibrations were being performed on Intermediate Range Monitors (IRMs) with test equipment (M&TE) that specified a
" limited use calibration." The NRC maintenance team inspector identified that plant technicians did not verify the required 123 VAC +/- 1 VAC line voltage prior to using the M&TE for the IRM Mean Square Analog Module. That observation was considered a procedural violation in Inspection Report 50-461/89003 for which the licensee was taking corrective action by revising the calibration procedure and training plant technicians.
The inspectors, with support from a Region III specialist, reviewed the impact on past IRM calibrations with the licensee assuming that the M&TE for the Mean Square Analog Module was not esed within the desired line voltage range. As documented in IP Memoranda Y-91087, dated April 3,1989, the licensee evaluated the' impact on IRM calibrations assuming a 5 VAC deviation of the power supply used by the M&TE. That evaluation showed that a maximum deviation of 9 milli-volts (mv) would occur with a 5 VAC power supply deviation. The 9 mv deviation was within the design value acceptable deviation of 50 mv. After the Mean Square Analog Module was calibrated with its specific M&TE, the card was reinstalled into its proper drawer and a loop calibration was performed to rekove any errors. Based on the above evaluation, the inspectors concluded that the past IRM calibrations would not have been significantly impacted by using the Mean Square Voltage Test Fixture with a power supply voltage 5 VAC outside the 123 +/- 1 VAC specified range. One Three violations and one unresolved item were identified. acditional violation was identified for which a Notice of Violation was not issued in accordance with 10 CFR 2, Appendix C, Section V.G.I.
- 6. Monthly Maintenance Observation (62703)
Selected portions of the plant maintenance activities on safety-related systems and components were observed or reviewed to ascertain that the activities were performed in accordance with approved procedures, regulatory guides, industry codes and standards, and that the performance of the activities conformed to the. Technical Specifications. The inspection included activities associated with preventive or corrective maintenance of electrical, instrumentation 16
e q 1 4 and control, mechanical equipment, and systems. .The following items
-were. considered during these . inspections:- the limiting conditions for operation were met _while components;or systems were removed from-servicc;; approvals were obtained prior to initiating the work; 1 activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibration was performed prior to returning the components or systems to service;-
parts and materials that were used were properly. certified; and appropriate fire prevention, radiological, and housekeeping conditions were maintained. 1' The inspectors observed / reviewed the following work activities: Maintenance Work Activity - Procedure No. D04722 . Installation of Raychem Splices in Hydrogen Igniters D14375 Installation of Raychem Splices in H22 Panels CPS No. 8502.14 CEH Relay Inspection, Calibration and Functional Test-D02951 Annunciator ground fault D06288 Pull Box and Junction Box-Inspection D04673 Overspeed Test of Division I Diesel i D04673 Overspeed Test of Division III Diesel i D02961 SRM-C Troubleshooting l Several additional maintenance activities were observed by regional -j inspectors during this period including a Maintenance Team Inspection documented in Inspection Report 50-461/89003. ; No violations or deviations were identified. ,
- 7. Monthly Surveillance Observation (61701) (61720) (61726) i An inspection of inservice and testing activities was performed to ascertain that the activities were accomplished in accordance with i i
applicable regulatory guides, industry codes and standards, and in conformance with regulatory requirements. Items which were considered during the inspection included whether i adequate procedures were used to perform the testing, test instrumentation was calibrated, test results conformed with Technical Specifications and procedural requirements, and tests were performed . 17
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within'the required time limits. :The inspectors determined that the .j
- test results were reviewed by someone other than the personnel involved with the performance of the. test, and that any deficiencies identified during the testing were reviewed and resolved by.
appropriate management' personnel. The inspectors observed / reviewed the following activities: . Surveillance / Test Activity Procedure No. CPS No. 9861.020025 Drywell Air Lock Barrel Leak Rate Test CPS No. 9861.07 Drywell Bypass Leak Rate Test CPS No. 9080.01 Diesel Generator 1A Operability - Manual l CPS No. 9053.03 ECCS Division 2 Simulated Auto Actuation CPS No. 9432.23 Primary and Secondary Containment Isolation Logic System Functional u CPS No. 9438.04 Feedwater Reactor Vessel Water Level Logic System Functional Test CPS No. 9479.01 Steam Bypass and Pressure Regulations System Functional and Time Response Test CPS No. 9843.01 ISI Category "A" Valve Leak Rate Test on 1B21F032A CPS No. 9981.01 Diesel Fuel Oil Sampling and Analysis (Div. III) Several additional surveillance activities were' observed by regional i i inspectors during this period including a Maintenance Team Inspection documented in Inspection Report 50-461/89003, 4 No violations or deviations were identified.
- 8. Onsite Followup of Events at Operating Reactors (93702)
- a. General The inspectors performed onsite followup activities for events '
l 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 i i 18 ,
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f; J-f' of the following: the sequence of actions; the functioning of-i 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 _that licensee investigation had identified root causes of equipment malfuncti_ons-and/or personnel errors and were taking'or had taken appropriate' corrective actions. Details of the events and licensee corrective actions noted during the inspectors' followup are 1 provided in paragraph b below.
- b. Details (1) Safety Relief Valve Actuation and Containment Isolation due to Pressure Transient from a' 5 cram in " Solid" Plant ,
[ ENS.No.- 15060] On March 19, 1989, the licensee informed the NRC via the- . q Emergency Notification System (ENS) of the unexpected automatic , actuation of the Safety Relief Valves (SRVs) and Containment Isolation System. ' The plant was in OPERATIONAL CONDITION 4 (Cold Shutdown) with a Reactor Coolant System Leakage Test in progress. The test required the reactor pressure vessel (RPV) i to be completely filled with water (" solid") and pressurized. ) ' Concurrently with the leakage test, the operators.were conducting individual control rod scram testing since the prerequisites for-the scram time testing also required that the RPV be pressurized 1 to greater than or equal to 950 psig. Restoration from the scram testing required that the reactor mode switch be moved from the Refuel to the Shutdown position. The operators knew that this would cause a reactor scram signal, which would cause the opening of all scram inlet and exhaust valves. Believing.that the i scram would result in the addition of water to the vessel and a possible pressure increase, the operators lowered RPV pressure to 900 psig and instructed the operator stationed ) at the local test gauge for the leakage test to discharge water as necessary to maintain RPV pressure less than 1000 psig. When the reactor mode switch was placed in Shutdown and the scram signal was generated, the resultant pressure increase , was more rapid than the operators had anticipated. Pressure , increased at a rate of about- seven psig per second. Pressure reached the setpoint of the SRVs and four of the valves opened and shut as designed to relieve pressure. The scram was immediately reset and pressure stabilized at about 800 psig. ! The maximum pressure reached was 1130 psig as noted at the local test gauge for the leakage test. . 4 i 19
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",' As a result of the SRVs lifting and shutting, a high differential pressure condition occurred in the main steam 4
lines causing the actuation of the Group 1 Containment Isolation valves. The inboard Main Steam Isolation, Main Steam Drain, and Main Steam Bypass valves closed as designed. The outboard isolation valves were already closed for the leakage test. . The licensec documented the event in Licensee Event Report (LER) 89-016-00 dated April '18,1989. The licensee attributed the cause of the event to inadequate procedures. Surveillance ' Procedure CPS No. 9813.01, " Control Rod Scram Time Testing," was inadequate in that it did not' contain a restoration section or provide cautions associated with performance of the {' surveillance test during " solid" plant conditions. Technical Procedure CPS No. 2800.03, " Reactor Coolant System Leakage Test," was inadequate in that it did.not provide precautions l concerning the implications of " solid" plant conditions or ' limit other evolutions which.would be allowed to be performed concurrently with the leakage test. Technical Specification 6.8.1.d required that written procedures be established, implemented, and maintained covering surveillance and test activities of safety-related equipment. Failure of the licensee to have adequate procedures for the control of the Reactor Coolant System l Leakage Test and Control Rod Scram Time Testing is a Violation (461/89014-07). The inspectors will review the ! LER in a subsequent report. (2) Possible News Media Interest in Transportation Accident [ ENS No. 15295) On April 12, 1989, the licensee reported to the NRC via ine ENS that they expected possible news media interest'and a news release about a transportation accident that had occurred approximately 30 miles from the plant. The licensee was informed by the Illinois State Police that a radwaste container had fallen from a truck that was enroute to Clinton Power Station. Since the initial report was not clear as to the type of container, the on-duty Shift Supervisor directed that plant health physics personnel respond to the scene of the accident and provide assistance to the State Police. The inspectors observed health physics technicians conduct surveys on the radwaste container, which was determined to be new and not radiologically contaminated. The accident occurred at about 3:00 a.m. and involved loss of the radwaste container from the transport truck only. ' No other vehicles were involved. 20
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. l The inspectors noted that the decision of the Shift Supervisor to send health physics personnel to the accident scene was conservative. i (3) Control Room _ Ventilation System Operating Outside of the 1 Design Basis LENS No. 15335]
On April 14, 1989, the licensee informed the NRC via the ENS that the Main Control Room Ventilation System (VC) had been operating outside its design basis because under certain conditions unmonitored airborne radioactivity could 4 have entered the ductwork. As documented in Condition Report No. 1-89-04-073, the 1 licensee identified that the storage location for contaminated material may present a concern for the Control Room environment in the event of a fire. During the currer.t first refeeling outage, the licensee had established a work area at the 702' elevation in the- .j Control Building to prepare contaminated equipment for i shipment. In particular, the Main Steam Safety Relief Valves which had been replaced during the refueling outage were being worked on in that area prior to shipment to an l offsite lab. l The licensee's evaluations of the effects of a fire at the j 702' elevation in the Control Building concluded that airborne radioactive material could enter the negative pressure VC i
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ductwork and enter the Control Room. The ductwork was not welded or sealed with silicone sealant material.. The ventilation system radiation monitors were located outside - the building near the air intake openings and would not have 1 been able to detect the radioactivity. l The licensee considered the above condition to be unanalyzed and reported this event in accordance with 10 CFR 50.72. Immediate action included removal of the contaminated material from the area of concern. More appropriate areas for storage of contaminated material have been designated. Later analysis by the licensee concluded that the potential for airborne radioactivity in the Main Control Room could be limited to less than the Maximum Permissible Concentrations in 10 CFR 20 provided certain administrative controls'were ' instituted. In Memorandum JW-0243-89, the Manager - Clinton Power Station committed to revise Administrative Procedure CPS No. 1024.30 (CCT 050737) to limit the maximum amount of loose surface contamination on material stored on the 702' and 825' elevations of the Control Building to 50,000 dpm/100 cm squared. 21
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- Fixed and loose contamination was to be limited to 100,000 dpm/ I
- 100 cm squared. As an interim measure, the above limits were incorporated in Radiation Protection Hight Orders. ,
(4) Unanticipated Reactor Scram during Troubleshooting on . Source Range Monitors [ ENS No. 15336] On April 14, 1989, the licensee informed the NRC via the ENS that an unexpected reactor scram had occurred during troubleshooting of the "C" channel of Source Range Neutron ' Monitors (SRM). The reactor was in OPERATIONAL CONDITION 4 (Cold Shutdown) with all control rods fully inserted at the time of the event so no actual rod motion occurred. The licensee's initial evaluation of the cause of this event was described in LER 89-018-00 dated May 11, 1989. The scram signal was generated when a high r.earon flux l signal occurred on Intermediate Range Monitor (IRM) "C" l while troubleshooting SRM "C" in the same cabinet. The licensee concluded that the most probable cause of the high' flux signal on IRM "C" was a recessed connector center pin for the IRM "C" signal lead. It was believed that while troubleshooting in the cabinet, the technician moved the IRM "C" signal lead which caused intermittent contact and i the resultant high flux signal. Since IRM-D had been l previously placed in a trip condition, the 2 out of 4 i coincidence logic was satisfied, resulting in a scram l signal. The inspectors will review the required Licensee Event Report in a subsequent inspection report. (5) Unanticipated Reactor Scram during Turbine Control and Stop ' Valves Scram Response Time Testing [ ENS No.15347] On April 15, 1989, the licensee informed the NRC via the ENS that an unexpected reactor scram had occurred during the performance of Surveillance Procedure CPS No. 9431.21,
" Turbine Control and Stop Valves Scram Response Time Test."
The reactor was in OPERATIONAL CONDITION 4 (Cold Shutdown) with all control rods fully inserted at the time of the event so no actual rod motion occurred. The licensee's evaluation of the cause of this event, as reported in LER 89-020-00, dated May 11, 1989, concluded that plant technicians performing the above surveillance ' inadvertently shorted test leads to ground causing loss of the Division 2 Reactor Protection System (RPS) power supply. Since a Division 4 RPS trip signal was present I (IRM-D in trip), the 2 oui,of 4 coincidence logic was 22 L-_--___
..e .
satisfied resulting in a scram signal. The LER reported ;
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that the root cause was attributed to personnel error on the part of the technician's supervisor. He was aware that the surveillance had the potential to cause a short while attaching or detaching test leads but had failed to : properly evaluate the possible consequences. i The inspectors will review the corrective actions alscussed in the LER in a subsequent report. (6) Unanalyzed Condition due to Com)onents not Being Environmentally Qualified [ ENS No. 15474]
- On April 28, 1989, the licensee informed the NRC via the i, ENS the the plant had operated in an unanalyzed condition due to the Safety Relief Valves (SRVs) not being installed in the same configuration in which they had been environmentally qualified. j Subsequent to the above ENS notification, the licensee submitted IP Letter U-601443, dated May 4, 1989, in ;
accordance with 10 CFR 21. As discussed in that letter, i l the licensee identified that the SRV air pilot valve solenoid power supply connection was not installed with a "Raychem" heat shrink sleeve. The licensee identified the as-installed configuration during review of EQ files in response to NRC inspections discussed below in Paragraph 9. l One violation was identified in the reviews of this functional area. \
- 9. Environmental Qualification of Electrical Equipment (92702) (71707)
During the report period, a number of issues regarding the Environmental Qualification (EQ) of electrical eon' ment had been discussed between the licensee and the staff. At Jumented in Inspection Report 50-461/89006(DRS), a Region III specialist inspector performed onsite inspections between February 6 and March 3, 1989. That inspection effort resulted in the identification of an apparent violation due to inadequate corrective action to a previous j EQ violation (ref: Inspection Reports Nos. 50-461/87026(DRS) and
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50-461/88010(DRS)). The apparent violation was discussed at an Enforcement Conference held at the Region III Office in Glen Ellyn, Illinois on March 21, 1989. The results of that enforcement action were under staff review and will be presented in subsequent communications to the ifcensee. i
- a. Subsequent to the enforcement conference and during a Region III review (including an April 20-21 plant walkdown) which was l
performed to assure the adequacy of the licensee's corrective action for previously identified EQ deficiencies several new deficiencies were identified by the NRC and the licensee. Details are noted below:
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{ { Hdrogen Igniters: Field connections for numerous hydrogen (1) 1 ' igniters were found to have unqualified taped-splices. EQ files required Raychem splices. In addition, an engineering review had approved the use of these unqualified splices. The licensee has subsequently reported the completion of the replacement of these_ splices with Raychem splices. l
-(2) Vendor Termination Boxes On MSIVs:: Design required Raychem _
splices for solenoid valve leads. Further, the field ! review did not replace these splices as required by MWR. The .; licensee has subsequently reported to have installed Raychem
- splices.
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' I (3) GE Instrument Racks: Numerousinstrumentcircuitslandeh '. {
on terminal blocks inside the containment were not , 'l justified for leakage current during an accident. The licensee has subsequently reported to have installed Raychem splices. (4) Perforated Taped Splice: Oversized taped splice found 4 perforated in condulet due to penetration of condulet cover bolt. The licensee replaced the, damaged splice and reviewed ] other condulets for similar deficiencies. I (5) Solenoid Valve Leads: ASCO solenoids: associated with safety relief valves have leads connected to Cannon plugs. Tested configuration requires Raychem splices on the plugs 7 , for postulated environment. The licensee has reported ; installing Raychem splices and reviewing other such ! installations for similar deficiencies. The licensee has also reported filing a report pursuant to 10 CFR Part 21 concerning : this condition. (6) Damper Assembly: Damper assembly not qualified for use in ' 100% relative humidity.- Qualification required sealing of electrical connections on the limit switches from moisture ' intrusion. In addition, this damper was excluded from the EQ program. The licensee reported installing seal assemblies on the affected circuits and reviewing other installations for similar deficiencies. l (7) Magnatrol Level Switches: Leads landed on terminal blocks i in switch enclosure. Enclosure is' subject to submergence but is installed _ with no drain holes. - Licensee. reported subsequently installing seal assemt *es on all appropriate Magnatrol Level switches. (8) ITT Valve Actuator: Leads landed on terminals in actuator
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enclosure. Enclosure is subject to submergence but 1s installed with no drain holes. Licensee reported subsequently providing drainage for all appropriate ITT actuators. 24
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. . - 4 (9)' Electrical
Enclosures:
, Numerous junction boxes, pull boxes, condulets and end use equipment enclosures, whose contents are subject to submergence were found installed with no drain holes. The. licensee has subsequently installed drain holes in appropriate enclosures. t1 (10) Posting Of FCN/ECNs: 'One.FCN identifying an EQ enclosure j was not posted on the appropriate design drawing. The licensee has reported this to be an isolated deficiency. d (11). Vacuum Breaker Limit-Switches: ' Field connections were-found to have unqualified Kynar butt. splices. Work l requests did not' allow these boxes to be opened. . The licensee jl
.has reported installing Raychem splices and reviewing other. 1 equipment for similar deficiencies'
-l (12) Motor Heaters On ECCS Pump Motors: Unqualified Kynar butt j' splices found on. leads for pump motor heaters. The licensee has subsequently. reported installing Raychem splices and-reviewing other equipment.for similar deficiencies.
(13) Conax Electrical Penetration
Enclosures:
Some enclosures
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found installed with top cable entry in a configuration ' that allows containment spray to impinge on terminal blocks having instrument'and control circuits. Two enclosures with bottom. cable entry were found to be slightly warped along flanges which could allow containment spray to impinge , on terminal blocks. In additional numerous instrument circuits found landed on Kulka terminal blocks on the penetrations could not be adequately justified .for. leakage current. This is further addressed in Section 9.b of this ! report. This licensee acknowledged the above deficiencies and took immediate, ' aggressive corrective action. For the items listed above the licensee provided a root cause analysis in a May 16, 1989 letter which also discussed corrective actions and an implementation. schedule for the noted deficiencies. .In this letter the licensee committed to completing corrective action prior to entering Mode 2 (Startup). and notifying the Region III Regional Administrator of the results of that effort. The licensee subsequently confirmed the corrective action had been completed,
- b. Qualification of KULKA terminal blocks for' Instrument Circuits During review of electrical enclosures in the containment, the inspectors noted that various instrument circuits were terminated on ;
KULKA terminal blocks mounted on the Conax penetrations. On review l of Conax test reports IPS-692 and IPS-650, the inspectors were 25
[ f concerned that the test did not simulate the coridensation expected
? due to the 100T humidity, 185'F, and subsequent containment spray-postulated during an accident.
Resolution of this issue was deferred to NRR. A meeting was held between the licensee and the NRC on May 9, 1989 at the NRC office
-in White Flint, Maryland. This meeting was te discuss NRC concerns '
regarding excessive leakage current compromising instrument circuits terminating on Conax penetration KULKA terminal blocks. In
.particular, the NRC was concerned that-the leakage current' anticipated during accident conditions may compromise the required accuracy or cause a failure of the'affected instruments for_ plant applications.
As a result of this meeting, the licensee was required to address the following areas: (1) Provide documentation on acceptance threshold of leakage current for'the affected instruments. (2) Provide a qualitative or quantitative analysis that compares the containment environment under accident conditions to the test chamber environment and how the differences may affect - test results. (3) Provide documentation of the moisture'depos'ition' tests run on 5/8/89 at Conax and their applicability to.the qualification test run on the electrical penetration. (4) What is Illinois Power's course of. action to resolve NRC concerns 1 on the qualification testing involving terminal blocks? ' Provide the scope and schedule. The licensee submitted a " Basis for Plant Startup" and committed to ) installing Raychem splices on all affected circuits.during their ; next refueling outage. NRR is continuing to review concerns on i this issue. The concerns described in Section 9.a.(1), (3), (5), (6) and (13) are considered examples of an apparent violation - (50-461/89014-08(DRS)) of 10 CFR 50.49, Paragraph (f),- failure to , qualify elec.trical equipment important to safety for postulated 4 harsh environments during an accident. The' evaluation and disposition of this apparent violation will be addressed in future communications.-
- 10. Temporary Instruction 2515/100: Proper Receipt, Storace, and Handling of Emergency Diesel Generator (EDG) Fuel Oil i During the report period, the inspectors reviewed the licensee's program to maintain adequate quality of emergency diesel generator ;
(EDG) fuel oil that was stored on site. The inspectors' conducted I i 26 _ _ _ _ _ _ _ _ .~
1 l 0 ( 1'
- this review through interviews with cognizant licensee personnel,
. direct field observation of installed equipment, and. observation of
- fuel oil surveillance activities. ,
I Results of the inspector's review are discussed below and correspond-with Temporary Instruction (TI) 2515/100, Appendix A, questions I through 15. I
- a. (TI 2515/100 Q1): The licensee completed their; review of Information Notice 87-04 as-documented in IP Memorandum Y-206322, dated October 29, 1987. The inspectors had previously reviewed the licensee's actions in response to Information Notice 87-04 in Inspection Report 50-461/87030, Paragraph 3.a. '
As documented in that . report, the licensee.had adequately. reviewed Information Notice 87-04.
- b. (TI 2515/100 Q2): The licensee did not have a " permanent" Fuel- J 011 (FO) storage tank recirculation system to remove accumulated particles. However, Operating Procedure _ CPS No. 3506.01, Revision 13, dated March 20,'1989, Paragraph 8.1.7, detailed the method'used to recirculate F0 storage tanks to disperse the NALCO 8256 biocide. The method described used the F0 transfer pump in an appropriate lineup to recirculate the F0 storage tank.
- c. (TI 2515/100 Q3): The licensee had prepared Surveillance Procedure' CPS No. 9281.05, " Emergency Diesel Fuel Oil Storage Tank Cleaning," revision 21, dated March 7,1988, to clean and inspect F0 storage tanks. Since Clinton Power Station was a recently licensed plant, the 10 year inspection had not yet been performed. The inspectors verified the surveillance was -
scheduled to be performed in March 1995 and March 1996. l The licensee's F0 storage tanks were sampled !
- d. (TI 2515/100 Q4):
on a quarterly basis. The inspectors witnessed sampling of the Division III F0 storage tank in accordance with Surveillance Procedure CPS No. 9981.01, '! Diesel Fuel 011 Sampling and
.i Analysis," revision 23, dated August 9,1989. The inspectors observed that the sample collected from the F0 storage tank was l i
taken from about 6 inches from the tank's bottom, the middle, and the surface. Drawing a sample about 6 inches from the F0 storage tank bottom was performed since the F0 transfer pump , suction is located about 6" from the bottom. Sampling for accumulated water in the F0 day tanks was performed after each monthly surveillance as required by CPS No. 9080.01, " Diesel Generator Operability," revision 31, dated March 17, 1989, l~ Paragraph 8.2.15. During the report period, the inspectors witnessed plant operators test for water in the F0 day tank , after a maintenance run. 27
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.a .
- e. (TI 2515/100 QS): The licensee added N,'.LCO 8256 biocide as .
.a fuel stabilizer. 1
- f. (TI.2515/100 Q6): Once per quarter.the licensee sampled all
.F0 storage' tanks for high particulate concentrations. The .
inspectors concluded that these quarterly samples had been q effective as evidenced by the' licensee identifying degraded 1 fuel oil in the Division III FO storage tank.in August 1987.- 1 (
- g. (TI 2515/100 Q7):: Day. tanks were checked for water monthly in 1 accordance with Surveillance Prbcedure CPS No. 9080.01, .]
Paragraph 8.2.15.. In addition, Operating Procedure CPS No. 3506.01,. J
" Diesel Generator and Support Systems," Revision 13, dated March 20, 1
1989, required in Paragraph 8.1.5.10 that the F0 day tank-be checked l for accumulated water after.each diesel operation. .j 1
- h. (TI 2515/100 Q8): Procedure instructions' discussed above for checking day tanks for accumulated water required immediate .i removal of any water found.
.{
- i. '(TI 2515/100 Q9): The inspector's review noted that the Division III Fuel Oil storage tank inventory was replaced in four days after degraded fuel was identified in August 1989.
- j. (TI 2515/100 Q10): Fuel Oil filters were inspected on a periodic basis (annually) through the licensee's Preventive Maintenance program (ref: PMMDGA026,7,8).
- k. (TI 2515/100 Q11): The licensee had recommended the addition of Preventive Maintenance activities to clean and inspect F0-strainers every other refuel outage (ref: CR #2-88-12-079).
- 1. (TI 2515/100 Q12): The Clinton Power ~ Station F0 system used dual element filters that permitted on-line cleaning. However, .
the F0 strainers were not dual elements. j l
- m. (TI 2515/100 Q13): The Clinton Power Station-F0 system duplex )
filter had a differential pressure indicator which provided local indication and control room alarm..
- n. (TI 2515/100 Q14): Fuel Oil alarms were incorporated into a general control' room trouble alarm "TROU8LE DG1A [B/C)" with local individual alarms.
- c. (TI 2515/100 Q15): ;The licensee stated that the six level' transmitters (two per division) that perform a control function were seismically qualified.
No violations or deviatlons were identified. 28
c c ,
- 11. Management Changes (30702)
During the report period, the licensee anncunced the following changes in their corporate management: Mr. Larry D. Haab was elected President of Illinois Power. Mr. Haab succeeded Mr. Wendell J. Kelley as company president. Mr. Kelley was to continue as Chairman of the Board and Chief Executive Officer. In addition, Mr. William C. Gerstner, Executive Vice President, had elected to retire July 1,1989. Upon the retirement of Mr. Gerstner, Mr. Donald P. Hall, Senior Vice President responsible for Clinton Power Station will report directly to Mr. Kelley.
- 12. Management Meeting (30702)
On March 21, 1989, following an enforcement ccnference, Illinois Power Company senior management r.at with the NRC Region -III management (denoted in . Paragraph 1) at the Region III offices. The purpose of the meeting was to allow the parties to discuss recent events at the plant, particularly the drywell flooding event of March 20, 1989. The licensee provided their initial assessment of the causes of the events and agreed to provide a letter clarifying the causes and corrective actions for this and other operator induced events that occurred during the first refueling outage. The licensee submitted Letter U-601431 dated April 24, 1989, detailing their conclusions. The letter dealt primarily with three operational events that were the subjects of Violations 461/89008-09d, 461/89014-03, and 461/89014-07. The inspectors discussed the lett e with the licensee's staff and requested that clarifications of some points be included in the response to the violations. Specifically the inspectors asked that the licensee clarify and expand their discussion of corrective actions to mitigate the " subjective factors" which influenced the performance of employees. Also the inspectors requested that the licensee clarify the letter's statement, "It is noted that the causes of these events are different than the causes of the refueling errors that occurred earlier in the outage." NRC management noted that some of the earlier refueling events were quite similar to the more recent events and were attributed to errors by operating shift supervision.
- 13. Violations For Which A " Notice 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 generally _ issue a Notice of Violation for a violation that meets the tests of 10 CFR 2, Appendix C, Section V.G.I. These tests are: (1) the violation was identified by the licensee; (2) the violation would be categorized as Severity _ Level IV or V; (3) the violation was reported to the NRC, if required; (4) the L violation will be corrected, including measures to prevent recurrence, I
29
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i U. S. NUCLEAR REGULATORY COMMISSION REGION III Report No. ,50-461/89015(DRS) ) I
-Docket No. 50-461 License No. NPF-62 j 1
Illinois Power Company Licensee: 500 South 27th Street
-Decatur, IL- 62525 Facility Name: Clinton Power Station Meeting At: Region III Office, Glen Ellyn, Illinois Meeting Conducted: March 21, 1989 Type of Meeting: Enforcement Conference Inspector: A. S. Gautam /
- Date-Approved By: R. N. Gardner 3f18!8f Date i Inspection Summary Meeting on March 21, 1989 (Report No. 50-461/89015(DRS)
Matters Discussed: . Apparent violations of 10 CFR 50_ Appendix B, Criterion XVI in regard to inadequate licensee corrective. action to correct.and prevent recurrence of previously identified environment 1' qualification (EQ).. deficiencies affecting 10 CFR 50.49 designated electrical butt splices and junction boxes. The analysis and disposition of the apparent violations will be presented in subsequent communications. 4 i 0 $ s lf I I h M L[ (( l y i,
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DETAILS
]
- 1. Persons Contacted ]
- a. Illinois Power Company (IPCo)
C. W. Wells, Executive Vice President D. P. Hall, Vice President i R. D. Freeman, Manager, NSED 1 R. E. Campbell, Manager, QA : D. L. Holtzcher, Acting Manager, Licensing and Safety i'
- b. Consultants R. D. Raheja, Mechanical Supervisor, Sargent and Lundy T. M. McCan11ey, Senior Electrical Project Engineer, :
Sargent and Lundy G. L. Edgar, Attorney, Newman and Holtzinger , R. J. Lauer, Attorney, Schiff Hardin and Waite j i
- c. U. S. Nuclear Regulatory Commission (USNRC)
C. E. Norelius, Acting Deputy Regional Administrator H. J. Miller, Director, DRS D. R. Muller, Project Director, NRR l J. B. Hickman, Project Manager, NRR ' J. A. Grobe, Director of Enforcement R. N. Gardner, Chief, PSS A. S. Gautam, EQ Lead Inspector i W. H. Schultz, Enforcement Specialist B. Drouin, Project Inspector i P. Hiland, Senior Resident Inspector (Clinton) S. Ray, Resident Inspector (Clinton) H. Walker, Senior Reactor System Engineer, NRR B. Berson, Regional Counsel M. Ring, Projects Section Chief (Clinton) D. Lei, Co-op Student, Region IV
- 2. Enforcement Conference As a result of apparent violations of NRC requirements, an Enforcement i Conference was held in the Region III office on March 21, 1989. The preliminary findings, which were the bases for these apparent violations of NRC requirements, were documented in NRC Inspection Report No. 50-4.61/89006(DRS) and were transmitted to the licensee by letter dated March 16, 1989. The attendees of this Conference are noted in ,
l Paragraph 1 of this report. The purpose of this conference was to discuss:
- a. What controls were established to ensure the effective on site implementation of equipment qualification (EQ) violation corrective action (procedures, records, training, etc.)?
l 2
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( _ _ i
- b. . What type of verification was established to ensure that the corrective action was completed?' ;
- c. What was the root cause of the failure to correct all previously - l identified electrical butt splice and weep hole, discrepancies? i
- d. -What type of controls are in place lto ensure that-responses /submittals to.the NRC are accurate? -
r e. What'is the competence level of the EQ staff in light of the' most recent butt splice and weep hole inadequacies?' In opening the conference, the NRC representatives ~ identified the following apparent violations .of .10 CFR 50,' Appendix B: l
- Criterion XVI - Corrective Action: Failure to identify and repair / replace all unqualified AMP Kynar electrical butt splices; and failure to identify and correct all instances -in which weep holes were '
not installed in electrical junction boxes. The~ licensee presented a summary of. their review of the NRC findings, the root-cause analysis, and immediate corrective actions taken. The. licensee also presented specific and general corrective. actions to prevent recurrence of these violations relative.to personnel and IPC quality-programs (See attachment- 1). l During this conference the licensee took issue with the violation-concerning the lack of weep holes'in junction boxes. A followup.NRC. -) meeting was conducted with the. licensee's technical staff to answer.any licensee questions regarding submergence of cables and splices in the junction boxes.' The licensee acknowledged the NRC concerns and comitted to submit additional EQ documentation regarding the qualification of the i affected cables and splices in the junction boxes. The licensee also committed to review the qualification of any box containing cable and/or splices that may be subject to submergence. i The evaluation and disposition of the apparent violations will be documented in subsequent communications. J
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' U.S. NUCLEAR REGULATORY COMMISSION REGION III I
Report No. 50-461/89023(DRS) ! Docket No. 50-461 License No. NPF-62 Licensee: Illinois Power Company 500 South 27th Street l Decatur, IL 62525 l Facility Name: Clinton Power Station j~ Meeting At: Region III Office, Glen Ellyn, Illinois 1 1 Meeting Conducted: June 14, 1989 Type of Meeting: Enforcement Conference D. b l! Af Inspector: R. N. Gardner Date
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Approved By: R. W. Cooper, II, Chief j Engineering Branch Date / j j i j Meeting Suninary i
-Meeting on June 14, 1989 (Report No. 50-461/89023(DRS))
Matters Discussed: Apparent violation of 10 CFR 50.49 Paragraphs (f) and (g) Ei regard to hydrogen igniter field connections, instrument circuits landed on terminal blocks in GE instrument racks, SRV solenoid valve leads, limit switches on a damper assembly, and electrical penetrations enclosures. The . l analysis and disposition of the apparent violation will be presented in subsequent communications. 1 i i Il
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.l " . DETAILS
- 11. M sons Contacted
- a. Illinois Power Company (IPCo) 1 j
J. S. Perry, Assistant Vice President R. D. Freeman, Manager, NSED R. E. Campbell, Manager, QA D. L. Holtzcher, Acting Manager, Licensing and Safety l J. A. Miller, Manager, Scheduling.and Outage Management {
- b. Consultants G. L. Edgar, Attorney, Newmann and Holtzinger ;
i R. J. Lauer, Attorney, Schiff, Hardin and Waite S. Frantz, Attorney, Newman and Holtzinger
- c. U.S. Nuclear Regulatory Comission (USNRC)
C. J. Paperiello, Deputy Regional Administrator f H. J. Miller, Director, DRS J. Lehman, Office of Enforcement (telephonically) 3 J. B. Hickman,' Project Manager, NRR j J. A. Grobe, Director of. Enforcement R. N. Gardner, Chief, PSS A. S. Gautam, NRR ! B. Wiseman, Office of General Counsel (telephonically) S. Ray, Resident Inspector (Clinton) M. Ring, Projects Section Chief (Clinton) R. W. Cooper, II, Chief. Engineering Branch, DRS R. C. Knop, Projects Branch Chief
- 2. Enforcement Conference i As a result of an apparent violation of NRC requirements, an Enforcement Conference was held in the Region III Office on June 14, 1989. The preliminary findings, which were the bases for this apparent violation of NRC requirements, were documented in NRC Inspection Report No.
50-461/89014(DRP) and were transmitted to the licensee by letter dated ' June 12, 1989. The attendees of this Conference are noted in Paragraph 1 of this report. The purpose of this conference was to discuss: l
- a. The safety significance of the EQ discrepancies identified in the following plant equipment:
(1) Hydrogen Igniters 2
( (2) GE Instrument Racks (3) Solenoid (ASCO) Yalve Leads (4) Damper Assembly on the Standby Gas Treatment System (5) Electrical Penetration Enclosures.(i.e...the construction of the enclosures could subject the terminal blocks to direct spray for which the terminal blocks are not environmentally qualified).
- b. A summary of action taken to correct the above discrepancies as I outlined in the May 16, 1989 IP Letter to Region III, " Environmental Qualification Issues at Clinton Power Station."
In opening the conference, the NRC representatives identified the following j apparent violation of 10 CFR 50.49 Paragraphs (f) and (g) (see Attachment 1): ) 10 CFR 50.49, Paragrapns (f) and (g): Failure to environmentally qualify the following 10 CFR 50.49 designated equipment by test and/or analysis. (1) Hydrogen igniter field connections . (2) Instrument circuits landed on terminal blocks in GE instrument l! racks (3) SRV solenoid valve leads (4) Limit switches on damper assembly (5) Electrical penetration enclosures with top entry cable penetrations or warped with bottem entry cable penetrations The licensee presented a summary of their review of the EQ discrepancies including root cause analysis and corrective actions taken. The licensee also discussed the safety significance ci the EQ discrepancies (see : Attachment 2). In addressing safety significance, the licensee stated that, based on engineering judgement, the hydrogen igniters and the , instrument circuits landed on terminal blocks in the GE instrument racks and in the electrical penetration enclosures would have performed satisfac-torily in an accident. However, the licensee indicated that the Automatic Depressurization System and one of the two 100% capacity Standby Gas Treatment System (SGTS) filter trains would not have been available in a postulated accident. The licensee also stated that the remaining SGTS filter train had, on occasion,.been out of service during previous plant operations. The NRC informed the licensee that due to the lack of acceptable environmental qualification tests to substantiate the licensee's position, there was no assurance that the five items listed above would have properly functioned i in postulated accidents. The staff has expressed particular concern with the instrument circuits landed on terminal blocks. ~ Leakage current in these l circuits due to moisture and spray may affect'the function of RPS and ECCS-l system actuation required to mitigate the consequences of an accident. , ! The evaluation and disposition of the apparent violation will be documented in subsequent communications. 3
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N E M P . I U Q E D . E i E C C E N 'D F E E F S I T A E R E I D E L Y E P P L K E T A X E M O B I I L C S C O Q S I S E E O - F I R R P E E O E E C D D F R W R A F N O E E A D M S H R H - E - N T E T D E R O O T S E N O I N R F R . F T F A I O O E E C O Q T T T D A Q C T T A N Y E N O E A S A C A E C C O T F O C I N V A N I G S Q M S D L O I U A S E N E G N I I T - Q T I C I G N D Y I A T C E E S V N R A T I T E L T C E R D I R E E K T L , E A R A A S E I E C S A R A E D RW M S P R N A T G O R L E O D F A A U E I P I P E O O V C R 0 R S P G T E N H T I A - G T X N Q T I ' M R EW T L IH N O R D E S E E G - N C O R E N E / Y A OI E T D I P P A Q R E F A L E R N E T X E U C 0 N T R S T R U T A Q E F D N P E A N O . C C E F H E A Y P MW E C N E I E A T CI N C T O A , T W F F O D T O E A
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r C EhVIR0ffENTAL QUALIFICATION DEFICIENCIES CLI FON NUCLEAR POWER STATION
- ON APRll 20-21, 1989, AN NRC INSPECTION WAS ttHFORMED TO VERIFY TE ADEQUACY OF TE LICENSEE'S CORRECTIVE ACTION IN EGARD TO TE SUB OF ELECTRICAL CIRCUITS IN ELECTRICAL ENCLOSURES. DURING. AND SU TO THIS INSPECTION, A NLNBER OF 10 ER 50.49 DEFICIENCIES WERE IDENTIFIED 2
BY DIE NRC AND TE LICENSEE. A. HYDROGEN IGNITERS l TE LICENSEE IDENTIFIED WIAT TE FIELD CONNECTIONS FOR NLEROUS ; HYDROGEN IGNITERS UTILIZED OKONITE TAPED SPLICES. DESE TAPED SPLICES WERE (A) NOT COMPATIBLE WITH 1BE TEFLON LEADS OF TE IGNITER, AND (B) BY DESIGN EPE REQUIRED TO BE RAYCHEM SPLICES. B. GE INSTRlFENT RACKS NUEROUS GE INSTRLNENT RACKS, LOCATED INSIDE TE CONTAltfENT AND SUBJECT TO PRESSURE, STEAM, AND CONTAltfENT SPRAY, WERE FOUND TO CONTAIN SAFE SHLITDOWN INSTRLENT CIRCUITS (NSSS, RPS) LANDED ON ( TERMINAL BLOCKS, THESE BOXES HAVE TOP ENTRY 00NDUlTS AND AE SUBJECT TO POSTULATED SUBMERGENCE. TE BOXES HAVE WEEP H0LES, HOWEVER, BASED ON ED DOCtPENTATION, THE TERMINAL BLOCKS IIAD NOT BEEN ~ SUCCESSFULLY TEsitu TO JUSTIFY LEAKAGE CURRENT FOR DE EQUIRED f 4-20 MA INSTRlNENT CIRCulT APPLICATIONS. i
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. EWIROTENTAL QUALIFICATION DEFICIENCIES CLINTON NUCLEAR POWER STATION
- ON APRIL 20-21, 1989, AN NRC INSPECTION WAS PERFORIED TO _ VERIFY TE ADEQUACY OF TE LICENSEE'S CORRECTIVE ACTION IN EGARD TO M SUIFE OF ELECTRICAL CIRCUITS IN ELECTRICAL ENCLOSURES. DURIE AND SUBSE TO THIS INSECTION, A NTBER OF 10 CFR 50.49 DEFICIENCIES WERE IDENTIFIED BY TE NRC AND TE LICENSEE.
A. HYDROGEN IGNITERS TE LICENSEE IDENTIFIED WAT TE FIELD CONNECTIONS FOR NLFEROUS WDR0 GEN IGNITERS UTILIZED OKONITE TAPED SPLICES. TESE TAPED SPLIES WERE (A) NOT COMPATIBLE WITH THE TEFLON LEADS OF TE IGNIlER, AND (B) BY DESIGN WERE REQUIRED TO BE RAYCHEM SPLICES. B. GE INSTRlFENT RACKS f NLFEROUS GE INSTRLENT RACKS, LOCATED INSIDE TE CONTAIWENT AND f SUBJECT TO PRESSURE, SlEAM, AND 00RTAIWENT SPRAY, WERE FOUND TO CONTAIN SAFE SHLITDOWN INSTRlENT CIRCUITS (NSSS, RPS) LANDED ON TERMINAL BLOCKS. TESE BOXES HAVE TOP ENTRY CONDUITS AND AE SUBJ TO POSTULATED SilfPLGNCE. TE BOXES HAVE WEEP HOLES, HOWEVER, BASED ON EQ DOClPENTATION, TE TERMINAL BLOCKS HAD NOT BEEN
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SUCCESSFULLY itsitu TO JUSTIFY LEAKAGE CURRENT FOR THE REDVIRED 4-20 MA INSTRLFENT CIRCUIT APPLICATIONS.
~~ '
.pme e APPARENT VIOLATION
- 10 CFR 50.49, PARAGRAPHS (F) AND (G) EQUIE EQUIPENT IPPORTANT.TO .
SAETY TO BE QUALIFIED BY TESTING AND/0R ANALYSIS PRIOR TO TE EQ DEADLINE OF NOVEMBER 30, 1985. CONTRARY TO TE ABOVE, AS OF APRIL 20,1989, THE FOLLOWING 10 CFR 50.49 DESIGNATED EDUIPIGT WAS NOT ENVIR0tNENTALLY 00ALIFIED BY TEST AND/0 ANALYSIS:
- 1. HYDR 0 GEN IGNITER FIELD C0tNECTIONSs
- 2. INSTRLIOT CIRCUITS LANDED ON TERMINAL BLOCKS IN GE INSTRitENT RACKSs 4
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- 3. SRV SOLEN 0ID VALVE LEADS; I
- 4. LIMIT SWITCES ON DAMPER ASSEMBLYs AND ,
- 5. ELECTRICAL PENETRATION ENCLOSURES WITH TOP ENTRY CABLE PENETRAT ,
OR WARPED WilH BOTTOM ENTRY CABLE PENETRATIONS. [ t a
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( , ENVIR0tFENTAL QUALIFICATION 2 DEFICIENCIES C. SOLENDID VALVE LEADS THE LICENSEE IDENTIFIED THAT CANNON PLUG C0ff4ECTORS, UTIOZED ON T TERMINATIONS OF SOLENDID OPERATED AIR PILOT VALVES FOR H MA STEAM SAFEIY RELIEF VALVES, WERE NOT COVERED WITH RAYCHEM HEAT SHRI!6( . ElBING AS INDICATED IN THE SRV BWIR0ffENTAL QUALIFICATION PACK D. DAMPER ASSEMBLY > 1HE LICENSEE IDENTIFIED THAT LIMIT SWITCHES ON TFE ACRIATOR FOR STANDBY GAS TREATENT DAMPER ASSEMBLY LOCATED IN A HARSH BW WERE QUALIFIED FOR HIGH RADI ATION BWIR0ff0RS Blir NOT FOR 1000 R
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. ELECTRICAL PENETRATION ENCLOSURES A NtNBER 0F ELECIRICAL PENETRATION ENCLOSURES WERE FOUND INS WITH TOP ENTRY CABLE PENETRATIONS THAT ALLOW 00NTAllfENT SPRAY IMPINGE ON TERMINAL BLOCKS M TEININAL BLOO(S WERE IM QUALIFIED
IN FOR LEAKAGE CURRENT RESULTING FRCN ItPINGING 00lGAltfENT SPRAY ADDITION, TWO ENCLOSURES WITH BOTTOM BURY CABLE PBETRATIONS WERE FOUND TO BE SLIGRILY WARPED, WHICH UMLD ALLOW CONTAltfENT SPRAY TO
-IMPINGE ON THE TONINAL BLOCKS.
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