Text

Insp Rept 50-461/87-11 on 870224-0406.Violations Noted: Failure to Follow Administrative Procedures in Areas of Operational Safety Verification & Event Followup
	ML20212R533
Person / Time
Site:	Clinton
Issue date:	04/17/1987
From:	Knop R; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:	;
Shared Package
ML20212R501	List: IR 05000461/1987011; ML20212R499; ML20212R508;
References
	TASK-2.B.4, TASK-TM 50-461-87-11, NUDOCS 8704270225
	Download: ML20212R533 (37)
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U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Report No. 50-461/87011(DRP)

Docket No. 50-461 License No. NPF-55 Licensee:

Illinois Power Company 500 South 27th Street Decatur, IL 62525 Facility Name: Clinton Power Station

Inspection At: Clinton Site, Clinton, IL Inspection Conducted:

February 24 through April 6,1987

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Inspector:

P. L. Hiland B. A. Azab C. H. Brown S. G. DuPont J. M. Jacobson R. D. Lanksbury M. L. McCormick-Barger P. R. Rescheske R'Fidad &

Approved By:

R. C. Knop, Chief

$6dh5/ 7)F Projects Section IB Date '

Inspection Summary

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Inspection on February 24 through April 6,1987 (Report No. 50-461/87011(ORP))

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J Areas Inspected:

Routine, unannounced safety inspection by the resident inspectors and region-based inspectors of licensee action on previous inspection findings; generic letter followup; licensee action on TMI action plan requirements; licensee action on part 21 reports; licensee action on part 50.55(e) reports; licensee event report review and followup; monthly main-

tenance observation; operational safety verification; engineered safety feature system walkdown; onsite followup of events at operating reactors; startup test witnessing; and management meeting.

Results: Of the 12 areas inspected, no violations or deviaitons were identified in 10 areas. One violation with 2 examples in the area of operational safety verification (paragraphs 9.a. and 9.f.) and one example

in the area of event followup (paragraph 11.b.(15)) was identified. These

examples of failure to follow administrative procedures had minor safety i

significance; however, the licensee needs to stress the importance of procedural adherence.

8704270225 870417

PDR ADOCK 05000461 G

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DETAILS 1.

Personnel Contacted Illinois Power Company (IP)

K. Baker, Supervisor - I&E Interface, Licensing and Safety (L&S)

T. Camilleri, Manager - Scheduling Outage and Maintenance

R. Campbell, Manager - QA

W. Connell, Manager - Nuclear Station Engineering Department (NSED)

J. Cook, Assistant Manager - Clinton Power Station (CPS)

@# G. Edgar, Attorney J. Fertic, Director, Quality Systems & Audits R. Freeman, Assistant Plant Manager, Maintenance

@# W. Gerstner, Executive Vice President

@#*D. Hall, Vice President, Nuclear E. Kant, Assistant Manager, NSED

@# W. Kelly, Chairman of the Board & President

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J. Miller, Assistant Manager - NSED J. Palchak, Supervisor - Plant Support Services

J. Perry, Manager - Nuclear Program Coordination

@ *F. Spangenberg, Manager - L&S

E. Till, Director Nuclear Training

J. Weaver, Director - Licensing

J. Wilson, Manager - CPS Soyland/WIPC0

J. Greenwood, Manager Power Suppl /

Nuclear Regulatory Commission

@# R. Bernero, Director, Division of BWR Licensing

@# B. Davis, Regional Administrator, Region III

W. Forney, Chief, Projects Section IA

@#*P. Hiland, Senior Resident Inspector, Clinton

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@# R. Knop, Chief, Projects Section IB M. McCormick-Barger, Project Inspector, RIII

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D. Muller, Director - BWR Project Directorate #2 i

C. Norelius, Director, DRP

J. Partlow, Director of Division of Reactor Inspection & Safeguards

@# B. Siegel, NRR, Clinton Licensing Project Manager

J. Sniezek, Deputy Director - NRR

R. Warnick, Chief, Projects Branch 1

Denotes those attending the management meeting on March 13, 1987.

@ Denotes those attending the management meeting on April 2, 1987.

Denotes those attending the monthly exit meeting on April 6, 1987.

The inspector also contacted and interviewed other licensee and contractor personnel.

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2.

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

a.

(Closed) Open Item (461/85005-12):

Verify that preoperational test and prototype tests of Divisions 1 and 2 diesel generators were performed in accordance with Regulatory Guide 1.108 as required by SER 8.3.1.

The inspector reviewed the completed and approved test results for preoperational tests PTP-DG/00-01, " Division 1 Diesel Generator and Fuel 011" and PTP-DG/00-02, " Division 2 Diesel Generator and Fuel 011".

The inspector verified that the completed

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preoperational tests met Regulatory Guide 1.108, Regulatory Position 2, " Testing," in that the following tests were completed successfully:

35 reliability starts, air capacity testing, minimum air starting, 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months full load run, demonstration of automatic starting on a simulated loss of voltage, demonstration of load

sequence, demonstration of ability to synchronize with offsite power j

while carrying emergency loads and demonstration that the diesel generators were capable of supplying emergency power within the required time without being impaired during periodic testing.

In addition, the inspector reviewed the manufacturer supplied prototype testing data and verified that the testing met the requirements of Regulatory Guide 1.108.

This item is closed.

I b.

(0 pen) Open Item (461/85005-28):

SER, paragraph 12.3.1 - Verify that procedures and a scheduled maintenance program are implemented

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to monitor leakage and reduce detected leakage outside containment (TMI Item III.D.1). The licensee had established a program which

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satisfied the requirements of SER 12.3.1, FSAR III.D.1.1, and j

Technical Specification 6.8.4.a..

Clinton Power Station (CPS)

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Procedure No. 1019.07, " Leakage Reduction and Monitoring Program",

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provided the instructions for implementing the program to reduce.

leakage to as low as practical levels from those portions of systems outside containment that could contain highly radioactive fluid

i during serious transients or accidents. The program included preventive maintenance and periodic visual inspection requirements

and integrated system test requirements for each system at refueling cycle intervals or less. The systems to be monitored in the leakage reduction program include Low Pressure Core Spray (LPCS), High Pressure Core Spray (HPCS), Residual Heat Removal (RHR), Reactor Core Isolation Cooling (RCIC), Suppression Pool Makeup, Combustible Gas Control, Containment Monitoring, and Post-Accident Sampling.

CPS Procedure No. 1870.02, " Leakage Identification and Control",

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provided a method of identification, tracking, and controlling leakage and spills. The inspector reviewed the licensee's program and determined that it was adequate and that the required training was completed by the appropriate personnel.

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SSER5 12.3.1 stated that the licensee committed to provide the initial leak rate test results 120 days after fuel load to the NRC.

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IP letter U-600818, dated January 27, 1987, requested an extension for submittal to 30 days after the 5% power milestone (i.e.,

obtaining a full power license). The inspector confirmed that this i

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extension was approved by the NRC via a telecon with NRR on March 19, 1987. The reason for the extension request was that some of the systems to be inspected by the licensee require reactor pressurization to provide adequate leakage measurement results (such asRCIC). The inspector noted that the licensee is currently in the process of gathering leakage data and that testing on some systems has been completed.

SSER5 12.3.1 further stated that an acceptable leakage program will satisfy the TMI Action Plan Item III.D.1 when the initial leak rate test results are forwarded to the NRC. Therefore, this item will remain open pending completion of the testing by the licensee, and submittal of the test results to the NRC for review.

c.

(0 pen) Open Item (461/86074-02):

Review the licensee's corrective actions and verify that the plant staff is adhering to CPS Procedure No. 1005.01 regarding the use and control of Ccmment Control Forms (CCFs). The inspector reviewed the status of the licensee's actions subsequent to the followup inspection documented in Inspection Report 50-461/87002, paragraph 2.h.

The licensee revised CPS Procedure No. 1005.01, " Preparation, Review, Approval, and Implementation of and Adherence to Station Procedures and Documents," on January 8,1987, to include requirements concerning control of CCFs initiated against issued station procedures (Section 8.1.13). The procedure changes were responsive to the NRC concern.

In addition, all CPS departments reviewed outstanding CCFs to determine if any were of sufficient significance to warrant revision of the affected procedure prior to the normal biennial review. A small number of CCFs were identified which resulted in the initiation of procedure revisions. The licensee's QA organization performed surveillances of the Operations Department procedure files to determine how CCFs generated against issued procedures were handled.

Surveillance Q-09456 was performed on December 15-16, 1986, and a followup surveillance (Q-09482) was conducted on February 12, 1987. The initial surveillance verified the information discussed above and also determined that the procedure files were not up to date (i.e., the files contained CCFs which had already been resolved, contained CCFs against procedures that had been cancelled, etc).

The followup surveillance concluded that a significant improvement was evident; however, additional surveillances will be performed prior to the closure of the identified concern (Concern # C0-87-001).

The inspector reviewed the QA surveillances and a sample of outstanding CCFs.

Discussions with the licensee indicated that the appropriate personnel were aware of the concern and were taking proper actions to correct the deficiencies. The inspector noted that supervisors and department heads had completed training prior to issuance of the revision to CPS Procedure No. 1005.01. This issue will remain open pending completion of the additional QA surveillances and verification that the plant staff is adhering to CPS Procedure No. 1005.01 regarding the use and control of CCFs.

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d.

(0 pen) Open Item (461/86054-14): Deferred Testing Activities.

The Clinton Power Station Operating License paragraph 2.D. granted a number of scheduler exemptions to the performance of test activities. These exemptions deferred testing to a specific milestone. The status of these deferred test activities was previously reviewed by the inspector as documented in Inspection Report 50-461/87002, paragraph 2.g.

That report identified that three deferred tests remained to be completed prior to power ascension above 5%.

During this report period, the licensee completed two of the three remaining deferred test activities.

The inspector reviewed completed test summaries for deferred tests on the Traversing Incore Probe (PTP-TP-01) and Fuel Pool Cooling and Cleanup (PTP-FC/SM-01).

This review verified that test results were reviewed and approved in accordance with the licensee's program.

The one remaining deferred test activity identified in the Clinton Power Station Operating License paragraph 2.0, was for the Fuel Handling system (PTP-FH-01).

Illinois Power letter U-600732, dated October 24, 1986, requested further deferral of the Fuel Handling system testing prior to offloading irradiated fuel.

The inspector verified the acceptance of this deferral with the NRR Licensing Project Manager (LPM). The LPM (Mr. B. Siegel) stated that acceptance of this deferral would be documented in supplement 8 of the Clinton Power Station (CPS) Safety Evaluation Report. Based on the above, the inspector noted that all deferred testing activities identified in paragraph 2.D of the CPS Operating '_icense required before power ascension above 5% had been completed.

This item will remain open pending completion of preoperational testing on the fuel handling system (PTP-FH-01) which must be performed prior to offloading irradiated fuel.

e.

(Closed) Open Item (461/86048-04):

Review of integrated plant operating procedures. During a previous inspection, it was identified that, based upon a review of the procedure purpose alone, the operation covered by Regulatory Guide 1.33, Appendix A, paragraph 2.c, 2.d, and 2.g were not procedurally addressed.

The inspector reviewed the following procedures to determine if they included instructions to cover the areas noted above (i.e.,

Recovery From Reactor Trip, Operation At Hot Standby, and Power Operation and Process Monitoring):

(1) CPS No. 3001.01, Approach To Critical, Revision 5 (2) CPS No. 3002.01, Heatup And Pressurization, Revision 5

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i (3) CPS No. 3003.01, Heatup And Pressurization, Condenser Isolated..

i And Condenser Recovery, Revision 5

j (4) CPS No. 3004.01, Turbine Startup And Generator Synchronization,

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Revision 4

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l (5) CPS No. 3005.01, Unit Power Changes, Revision 4 i

j (6) CPS No. 3006.01, Unit Shutdown, Revision 5 i

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(7) CPS No. 4100.01, Reactor Scram, Revision 4

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Based upon this review, the inspector determined that the Itcensee i

had in place integrated operating' procedures to cover the ceas of concern. This item is closed.

f.

(Closed) Violation (461/86048-03): The CPS screenhouse was not floodproof as required. The licensee's quality assurance program

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j implementation had not identified this violation, i

i This violation was previously inspected as documented in Inspection j

Reports 50-461/86054 (paragraph 2.J.) and 50-461/86060 (paragraph

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2.s).

This violation resulted in escalated enforcement action as

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described in the Notice of Violation (NOV) and_ Proposed Imposition

of Civil Penalty dated March 3, 1987. This item appeared as item

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A.3 in that NOV.

During this report period, the licensee formally responded to the

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NOV in a timely manner.

IP letter U-600893, dated March 31' 1987,

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taken to correct the violation and the actions taken to prevent

further violations.

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The licensee submitted a final report under the provisions of i

10 CFR 50.55(e) by IP letter U-600765 dated November 24, 1986; a i

supplemental final report by letter U-600825 dated' January 26, i

1987; and additional quality records related to corrective actions

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taken (ref.10 CFR 50.55(e) Item 461/86006-EE). The submitted

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information was reviewed by the inspector and the referenced 10 CFR 50.55(e) report was closed in Inspection Report 50-461/87002, s

i paragraph 3.a..

Based on the inspector's review of the licensee's response t'o the I

NOV and the previous inspections referenced above, this item is I

closed.

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g.

(Closed) Violation (461/86065-04): Three examples of inadequate j

surveillance procedures.

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i This item was previously reviewed as documented in Inspection Report.

l 50-461/87002, paragraph 2.m.

That review identified that the j

licensee's response (IP letter U-600806) was not complete to address other than first time performance of mode 1, 2, and 3 surveillances.

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During this report period, the licensee provided a revised response by IP letter U-600851, dated February 26, 1987. The revised

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response stated that the Plant Manager had instructed the appropriate department heads to solicit from their staffs any outstanding procedural deficiencies that they_were aware of. The revised response further stated that all known deficiencies had been

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corrected or documented for incorporation into the next revision.

These actions adequately addressed the inspector's concerns. This

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item is closed.

h.

(Closed) Violation (461/86065-06): Two examples of plant operations without approved procedures.

This item was previously reviewed as documented in Inspection Report 50-461/87002, paragraph 2.o.

That review indicated that the licensee had not adequately addressed the apparent violation of CPS No. 1011.01, Test Programs and Control. The licensee stated that CPS No. 1011.01 would be revised to provide controls over the types of activity described in the Notice of Violation.

During this report period, the licensee provided a revised response by IP letter U-600851, dated February 26, 1987. That response indicated that procedural controls would be provided by March 27, 1987, to define when select evolutions can be performed with the verbal approval of the Manager - CPS, Assistant Plant Manager, or i

the Assistant Plant Manager - Operations.

The inspector reviewed Plant Manager Standing Order No. 043 (PMS0-043), dated March 3, 1987. That PM00 defined the circumstances and the authorization limitations that were to be

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followed when performing evolutions under verbal directions.

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The inspector's review indicated that the licensee had established procedural controls over verbal instructions as stated in the revised _ response to_the NOV. This item is closed.

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(Closed) Unresolved Item (461/85012-02A): CPS procedures had not received an independent technical review.

Several administrative procedures reviewed by the inspector did not reflect the applicable

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requirements of ANSI N18.7-1976, the CPS technical specifications, and other regulatory requirements.

This item was previously reviewed in Inspection Reports Nos.

50-461/85043, 85057, 86048, and 86060. At the conclusion of the inspection documented in Inspection Report No. 50-461/86060, the licensee had not completed the identification of procedures that departments other than plant staff relied upon to meet ANSI N18.7-1976 requirements.

In addition, the licensee had not completed actions necessary for closure of Condition Report (CR)

No. 1-84-09-053, and the licensee's completion of a centralized commitment tracking (CCT #043179) item to require revision of affected procedures to incorporate the ANSI N18.7-1976 requirements.

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'During this report period, the licensee presented this item to the

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IP memorandum Y-204408, dated March 11, 1987, distributed revision 0 of the ANSI N15.7-1976. Implementation-

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Matrix; This memorandum also defined the controls that had been established to maintain the-Implementation Matrix

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t noted that all actions had been completed for Condition Report 1-84-09-053 and it was closed in January 19, 1987.

In' addition,

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Centralized.Commitmens Tracking item.043179-was closed.

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g The inspe:: tor noted:that all required actions had been completed a

to resolve this item;.however, an implementation review was not.

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performed by the inspector since the program established by the licensee had not been in place a sufficient length of. time.. An

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implementation review of the licensee's ANSI N18.7-1976 matrix is

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considered an Open Item (461/87011-01) that will be addressed by

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Region III. specialists in a future--inspection. This item is closed.

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(Closed) Unresolved Item (461/87002-02): Degraded Seal'.on Secondary Gas Control Boundary. During a routine plant tour, the inspector identified to the licensee a secondary gas boundary seal that had

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been degraded.

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The results of the licensee's investligation of this item were l

documented in Condition Report 1-87-01-033. The degraded seal was

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l repaired in accordance with Maintenance Work Request C c8972. - The '

licensee conducted a thorough investigation as documented in the-l

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above condition report but were unable to. identify the. specific root-cause for the condition identified by the inspector. A walkdown of secondary containment boundary ~ seals was conducted 'on January 26,

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19E7, by IPQC and no additional penetration seal violations were identified.

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Parallel with the investigation of CR 1-87-01-033, IPQA performed an audit of the controls in place for penetration seal removal and reinstallation. The audit performed (Q-38-87-06) 1dentified two.

findings where the applicable instructions contained in Maintenance

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Standing Order (MS0) 025 were not being complied with.' The two

findings dealt with the request forms and logs used for controlling

seals. The audit finding responses were accepted by IPQA on-

February 2,1987. The results of this audit were contained'in a related 10CFR50.55(e) report (461/86005-EE) which was reviewed by.

the inspector and closed as discussed below in paragraph 6.b.

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The. inspector concluded that the licensee had taken adequate steps to correct the identified deficiency (i.e.,-the seal was repairedf

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i via MWR C-28972); the licensee had conducted an adequate investiga-i tion to determine a root cause; the licensee'had conducted a'

walkdown of secondary gas boundary seals and identified no additional discrepancies; the audit ~ findings identified by the-

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licensee-were being properly ~ addressed.- This item 11s closed.

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(Closed) Open Item (461/86054-11): Changes to Main Control Room Isolation Valve _ Group Annunciator Display Tiles (SSER6, paragraph

7.5.3.2).

Prior to exceeding 5% of rated power, the licensee was to complete changes to annunciator display tiles and primary

. containment isolation valve regrouping into 13 valve groups.

i During this report period, the licensee completed plant modification

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CX-7 which implemented required SPDS display groupings and changes to annunciator tiles. The inspector reviewed the vaulted modifi-

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cation package and selected a representative sample of the changes made to the SPDS display and annunciator tiles.

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The inspector verified by direct field observation that the i

containment isolation valves had been regrouped into 13 valve

groups.

However, the proper group identification on annunciator

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display tile for Reactor Level Low (P601-18A[A-2]) was not l

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. incorporated in the field. The inspector requested the licensee

to reverify other annunciator tiles had the appropriate isolation

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groups identified.

I IP memorandum Y-83898, dated March 30, 1987 was reviewed by the

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-inspector. That memorandum detailed the total number of. valves not

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addressed by SPDS prior to implementation of plant modification CX-07. Of the 57 valves identified, 53 have been included on the l

4-SPDS display. The remaining 4 valves (1VR035, IVR036, IVR040, and i

IVR041) were to be included in the SPDS display bedfore startup i

after the first regularly scheduled refueling outage.

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The licensee stated that the one annunciator tile identified by the inspector would be replaced with the proper tile display by April 10, 1987, in accordance with Maintenance Work Request (MWR)

C-30519.

In addition, the licensee reverified all other annunciator tiles had the proper group display. This item-is closed.

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(0 pen) Open Item (461/86072-02): Review the results of the l

licensee's evaluations regarding the General Electric (GE) Co.

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Service Information Letter (SIL) No. 445. The inspector reviewed the status of the licensee's actions subsequent to the inspection documented in Inspection Report 50-461/86072. GE SIL 445, l

Intermediate Range Monitor (IRM) Fuse Failure, dated July 26, 1986,

identified a condition whereby the IRMs may be inoperable due to a blown fuse in the -24 VDC power supply without immediate operator detection. This SIL was preceded by a GE Rapid Information Communication Services Information Letter (RICSIL) No. 007, dated June 26,.1986. The licensee received SIL 445 on September 26, 1986, and assigned the Nuclear Station Engineering Department (NSED)

primary responsibility for evaluation of the SIL. Their evaluation was documented in IP letter Y-82326, dated October 20, 1986. NSED concluded that the IRM fuse failure identified in RICSIL 007 would have no adverse safety impact on CPS; however, two.of the three recommendations made by GE in SIL 445 were directly a'pplicable to CPS. One recommendation involved evaluation of the need for annunciation of loss of the -24 VDC IRM power supply. NSED initiated modification No. NR-006 on February 16, 1987, to add-9 i

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voltage sensing relays which would monitor each IRM channel and provide an "RPS System IN0P" trip on a loss of the negative power supply. The licensee ~ plans to _ implement' this modification prior to startup after the second refueling outage. A second recommendation

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involved evaluation'of licensee procedures for establishing

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operability of a safety related instrument channel.after its ~ loss.

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- GE. recommends that a channel functional test be performed fcilowing-return to operability. The inspector noted that the procedure

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review had not been completed by the plant staff technical

department. Therefore,- this item will remain open pending NRC

review of the licensee's evaluations when they are complete.

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No violations or deviations were identified.

3.

Generic Let.ter Followup (92703)

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(Closed) Generic Letter 85-06 (461/85006-HH): Quality Assurance Guidance

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for ATWS Equipment that is not safety-related. This Generic Letter provided specific NRC QA guidance to be considered for nonsafety-related

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components.

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This item was previously reviewed as documented in-Inspection Report

50-461/86037, paragraph 4.c.

At the conclusion of that inspection, this item remained open pending additional ' review by the licensee.

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During this report period, the licensee presented this item for review.

IP memorandum Y-204488, dated March 20, 1987, identified the reviews j

conducted by the licensee in response to the subject generic letter.

i As-previously noted in Inspection Report 461/86037, the licensee had

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responded to the subject Gener!c Letter in IP letter'U-600279, dated i

October 16, 1985. As' noted in IP memorandum Y-204488, the licensee j

was informed by the NRR t.icensing-Project Manager (Mr. B. Siegel) on February 25, 1987, that no additional information was requested and that the response (U-600279) was acceptable.

The inspector confirmed the acceptance of the licensee's response to this generic letter via telecon

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with Mr. B. Siegel on April 3, 1987. This item is closed.

No violations or deviations were identified.

4.

Licensee Action on Three Mile Island (TMI) Action Plan Requirements

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i The NRC Office of Inspection and Erforcement issued Temporary Instruction i

(TI) 2514/01, Revision 2, dated December 15,-1980, to supplement the i

Inspection and Enforcement Manual. 'The TI provides TMI-related'

inspection requirements for operating license applicants during the phase between pre-licensing and licensing for full power operation.

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Part I lists requirements that were closed prior to fuel load. Part 2 i

lists requirement that must be closed prior to full power operation.

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Part 2 of the TI was used as the basis for inspection of the following

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TMI item found in NUREG-0737, " Clarification of TMI Action Plan

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Requirements".

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(Closed) Item II.B.4.2: Training for Mitigating Core Damage. The licensee was to complete training prior to full power operation.

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During a previous inspection (50-461/86023), part 1.(II.B.4.1) of this TMI action item was closed based on the licensee's established Mitigating Reactor Core Damage (MRCD) training program.

During a followup inspection (50-461/87002), part 2 (II.B.4.2) was not considered to be completely satisfied by the licensee. Training had been provided to licensed individuals and the Power Plant Manager. Specific topical-training had been completed by most non _ licensed technicians. However, several technicians had not received the required training and the licensee was unable to provide evidence that these technicians would be trained as committed in Section 13.2 of the FSAR.

During this report period, the inspector verified that the licensee had a program in place to insure that the appropriate non-licensed technicians will be trained prior to full power operation.

Illinois Power (IP)

Memorandum No. EAT-035-87, dated February 17, 1987, identified the personnel required to complete the training from the Control and Instrumentation, Radiation Protection, and Chemistry Departments.

In addition, a computer generated commitment tracking system was used by the Training Department to verify that the required training had been completed. On March 20, 1987, the licensee notified the inspector that by utilizing the tracking system, approximately fifty (50) technicians were identified who had not completed the training, and that a trainirg schedule for these individuals would be initiated. The inspector determined that the actions taken by the licensee to complete the MRCD training were adequate and confirmed that part 2 of the TMI action ~1 tem was complete.

No violations or deviations were identified.

5.

Licensee Action on Part 21 Report (92700)

(0 pen) 10CFR, Part 21 Item (461/86006-PP): Two motor-operated valves failed during preoperational testing of the High Pressure Core Spray System (HPCS). Valve No. 1E22-F010 experienced a sheared stem and valve no. 1E22-F011 experienced a separation of the stem from the disc.

The original valve stems supplied by the manufacturer had high hardness valves with resultant high residual stress, typical of 410 stainless steel.

The licensee's corrective action included hardness testing of all 166 safety-related valves with type 410 stainless steel stems or check valve pins.

Fifteen valves were found to have stems or pins with a hardness in excess of the General Electric recommendation. General Electric-performed a safety evaluation which demonstrated.that a common mode failure of the valves in question would not impact safe shutdown and accident response functions.

Since type 410 material cracking requires a combination of high hardness and high applied stress, GE has concluded that it is acceptable to leave-the fifteen type 410 items in service until the first refueling outage.

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D Due to the low stress levels involved with normal valve operations along with the licensee's program to assure that no improper back seating of the valves will occur (i.e., causing high tensile stress), the NRC inspector found the GE conclusions to be acceptable. This item will remain open pending verification of replacement of the stems or pins for the following valves:

Valve No.

1.

1E22-F001 6.

1E22-F015 11.

1E12-F041C 2.

1E22-F004 7.

IE51-F010 12.

1E51-F066 3.

1E22-F010 8.

IG33-F040 13.

IB21-F032B 4.

IE22-F011 9.

ISX-105A 14.

1E12-F050B 5.

1E22-F012 10.

1E21-F006'

15.

1821-F032A No violations or deviations were identified.

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6.

Licensee Action on 10CFR50.55(e) Report (92700)

a.

(Closed) 10CFR50.55(e) Report (461/86007-EE):

Broken Tack Welds on Anchor Darling Globe Valves.

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This matter was previously reviewed as documented in Inspection Reports 50-461/86060 (paragraph 3.a) 50-461/86072 (paragraph 5) and 50-461/87002 (paragraph 3.b).

Those reports document the licensee's planned corrective action and the justification for operation of 32 potentially affected valves during the first operating cycle. One remaining item still open at the conclusion of the inspector's last review (50-461/87002) was the licensee's engineering justification i

for removal of administrative controls on two valves (1E12-F003A/B)

that may be operated in a throttled mode during long term decay heat removal after a postulated accident.

During this report period, the inspector reviewed IP memorandum Y-83353, dated February 5,1987, that documented the licensee's

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evaluation for operating valves IE12-F003A/B in the throttled mode during long term decay heat removal. That evaluation concluded that valves 1E12-F003A/B should not be throttled less than 13%

open (i.e., 3900 GPM flow). The licensee revised the Residual' Heat Removal Operating Procedure CPS No. 3312.01, paragraph 8.3.7.8 to include a caution that instructed valves 1E12-F003A/B were not to be throttled less than 13% open.

The licensee provided an amended final report on this matter in letter U-600824 dated February 9, 1987. That report provided a more detailed justifici

- for removal of administrative controls on GE designated valo perform a throttling function. Based on the evaluations ps.

i by the licensee and the procedural change discussed above, the inspector concluded that actions taken by the licensee were sufficient to remove administrative controls that had been established by the licensee.

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E.

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In their amended final report, the licensee stated that 32 valves

_ ould be inspected at the first refueling outage.

In. addition,-

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the licensee would monitor valve'1E12-F022 for excessive vibration L

during the startup: phase (CCT #43942). sThese actions are considered-an Open Item (461/87011-02).pending the inspector's review of

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vibration testing on valve IE51-F022 during the'startup phase and the inspector's review of inspection results on the 32 valves prior

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to plant startup after the first refueling outage. This item is

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closed.

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-b.

(Closed) 10 CFR'50.55(e) Report (461/86005-EE): Unsealed Gaps (0penings) in 3 Hour Rated Fire Wall.

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This matter was previously addressed in Inspection Report

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50-461/86015, paragraph 2.e.

That-report identified an ongoing

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program by Bisco (vendor performing seal installation work) to

,

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reseal penetration openings..The licensee's interim report, letter

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i U-600687 dated August 18, 1986, committed to complete all~ actions regarding this_ issue prior to 5% power.

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The licensee provided a final report on this matter in their letter i

U-600750 dated October 31, 1986..That report stated that failure.

to correct the deficiencies would have resulted in the inability of j-several fire walls in the plant to perform their intended design function. On this basis, the matter was evaluated to be reportable-under-the provisions _of 10 CFR 50.55(e).

)-

l The licensee grouped the penetration seals into two categories:

i category 1 (external seals) and category 2 (internal seals). The licensee performed visual checks to identify possible deficiencies

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in category 1 and determined 61 seals to be deficient. The category 2 seals were surveyed '(seals identified in the Fire Protection Report) and of the approximately 4000 seals,.275 were j

identified as damaged.

J The inspector reviewed by direct field observation the following

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sample of Category 1 seals:

l Maintenance Work Request l

(MWR) Number Seal Location J

l i

C08061 Aux / Fuel /Catmt. Elevation 762'

C08023 Aux / Fuel /Cntmt. Elevation 771'

)

C08003 Aux / Fuel /Cntmt. Elevation 778'

C08004 Control /DG

. Elevation 702'

,

i i

C21780

' Control /DG

. Elevation 751'

^l l

C21780 Control /DG Elevation 756'

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C08031 Control Elevation 800'-

C08033 Control Elevation 800'

C08035-Control Elevation 800'

C08063 Radwaste Elevation 702'

C08037 Radwaste Elevation 702'

C08043 Radwaste-Elevation 762'

C08023 Turbine Elevation 800'

The inspector also reviewed a sample of the Maintenance Work Requests (MWR) used to perform the resealing.

Five category 1 and three category 2 MWRs were reviewed for proper signoffs, completion dates, and remarks. The following is a list of MWRs reviewed:

Category 1:

MWR - C08023 Category 2:

MWR - C31891 MWR - C08033 MWR - C08097 MWR - C08040 MWR - C08347 MWR - C08002 MWR - C31894 The licensee took corrective actions to eliminate future seal violations by issuing Maintenance Standing Orders (MS0) 23 and 25 to identify the mechanism for proper control of fire seals. Training was conducted for maintenance planners and craft personnel on the above MS0s.

Based on the above review, this item is closed.

No violations or deviations were identified.

7.

Licensee Event Report (LER) Review and Followup (90712 & 92700)

a.

In-Office Review Of Written Reports Of Nonroutine Events At Power Reactor Facilities (90712)

For the LERs listed below, the inspector performed an in-office review of each LER to determine that reporting requirements had been met; that the corrective action discussed appeared appropriate; that the information provided satisfied the applicable reporting requirements; to determine if appropriate actions had been taken on any generic issues present; and to determine if any additional NRC inspection, notification, or other response was appropriate. Where determined appropriate, the LER was scheduled for onsite followup inspection or other necessary action by cognizant NRC personnel.

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During the review of the following LERs.and a selective review of the other Clinton 1987 LERs the inspector noted that the licensee had consistently failed to include the Energy Industry Identification System component identifier and system name of each component and system identified in the LER.

10 CFR 50.73b.2.it.(F)

required that this be included in the narrative description of each LER. The Energy Industry Identification System is defined in the Institute of Electronics and Electrical Engineers (IEEE) Standard 803-1983, Recommended Practice for Unique Identification Plants and Related Facilities - Principles and Definitions. The licensee committed to review their procedure for generation of LERs for any necessary changes and to ensure that future LER submittals would include the required identifiers.

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(1) (Closed) LER 87-001-00 and 87-001-01 (461/87001-LL) [ ENS

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No. 07359]: Automatic Initiation of Division II Emergency Core Cooling System (ECCS) Due to Spurious Reactor Vessel Low Water Level Signals.

The licensee's investigation of this event did not identify any equipment / component malfunction or failure, or any evolution in progress at the time of this event whicn could have caused or contributed to the event.

On this basis, the cause of the event was attributed to random spurious reactor vessel water level signals initiated by two level sensing instruments. The inspector noted during the review of this LER that 10 CFR 50.73 had not been fully complied with in that it was submitted four days late (34 days after the event) and that the narrative portion of the LER did not contain the plant status prict to the event (though it was contained in the abstract). This was discussed with licensee management who stated they would take appropriate actions to ensure that future submittals would be in full compliance. This LER is closed.

(2) (Closed) LER 87003-00 (461/87003-LL) [ ENS Nos. 07799 and 07802]: Main Control Room Ventilation System Train "B" Shifted to the High Chlorine Mode Due to Chlorine Detector Failure.

Investigation by the licensee determined that the root cause of the two actuations of the high chlorine mode of the control room ventilation system was the failure of a grounding pin in an electrical connector. The connector pin was replaced and the system restored to service. This LER is closed.

(3) (Closed) LER 87-012-00 (461/87012-LL) [ ENS Nos. 08002 and 08003]: Main Control Room Ventilation System Train "B" Shifted to the High Chlorine Mode Due to Depletion of the Chlorine Sensing Tape Cassette.

The licensee determined that the root cause of the event was an increased frequency in the surveillance that replaced the cassette combined with failure to increase procurement i

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o frequency. This led to not having a replacement for the subject cassette until after it had been depleted. The licensee has increased the frequency and quantity of replacement cassettes to ensure a sufficient quantity will always be available. This LER is closed.

No violations or deviations were identified.

b.

Onsite Followup Of Written Reports Of Nonroutine Events At Power Reactor Facilities (92700)

For the LER listed below, the inspector performed an onsite followup inspection of the LER to determine whether response to the event was adequate and met regulatory requirements, license conditions, and commitments, and to determine whether the licensee had taken corrective actions as stated in the LER.

(1) (Closed) LER 87-002-00 (461/87002-LL) [ ENS No.07744]: Main Control Room Ventilation System Train "A" Shifted to the High Chlorine Mode Due to Utility Operator Error.

The licensee determined through investigation that the root cause of the event was attributed to personnel error in that the " optics" functional light bulb was removed without anderstanding that this would cause a system initiation.

The cause was also attributed to a lack of procedural or visual caution for the operator. As part of the corrective action the licensee placed caution tags on all four chlorine detectors warning that a system initiation would occur if the " optics" functional light bulb were removed. The inspector verified by direct field observation that those cautions tags had been hung. The licensee also committed to the following:

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Prepare a preventive maintenance activity to replace the three bulbs in each detector at six-month intervals.

Revise procedures CPS 9000.02, Unit Attendant Surveillance

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Log, and CPS 3402.01, Control Room HVAC, to caution the operator on replacement of the bulbs in the detectors.

Initiate a plant modification to replace the caution tags

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with permanent warning signs.

Determine if there are other cases where removal of an

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indicating light would cause a system actuation.

Investigate and evaluate possible changes to the chlorine

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mode initiation logic.

These corrective actions were not yet implemented at the conclusion of this report period. However, the inspector verified that the licensee had a mechanism in place to track

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the above and that these items were included. This LER is closed.

No violations or deviations were identified.

8.

Monthly Maintenance Observation (62703)

Station maintenance activities of safety related systems and components listed below were observed / reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides and industry codes or standards, and in conformance with technical specifications.

The following items were considered during this review:

limiting conditions for operation were met while corponents or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approvea procedures and were inspected as applicable; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and fire prevention controls were implemented.

As documented below in paragraph 9.d., the licensee experienced a malfunction in the control rod drive system that caused control rod 12-25 to " skip" a notch while being withdrawn. The licensee's corrective maintenance activities for this failure were reviewed by the inspector as follows:

During the investigation of the occurrence by the licenseeg the operator noted that while withdrawing rod 12-25 to the position 24, the settle indicating light momentarily flashed as the rod withdrew past position 24 to position 26. Expected operation of a control rod being withdrawn in

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single notch mode would be to complete the settle mode after the control

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rod drive mechanism had moved slightly less than one notch position then

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closing the withdrawal drive directional control valve and opening the withdrawal exhaust directional control valve (this valve manipulation is automatically interlocked). Additionally, the test engineer, present at the Hydraulic Control Units (HCU) during the occurrence, noted that a chattering noise was experienced during the rod withdrawal. The licensee with assistance from General Electric (GE) determined that the chattering noise was associated with the cooling water check valve (138).

]

On March 5, 1987, the licensee held a meeting with members from engineering, GE, startup, maintenance, and quality assurance to determine the possible causes of the double notch rod movement. The licensee used

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the GE document GEK-75640A for guidance. This initial meeting determined the following possible causes and evaluations:

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Rod motion timer in rod action control system defective. Determined not to be possible because the computer printout during the occurrence indicated that the rod motion timer provided the proper

'iming for the in-out-settle sequence (approximately nine seconds

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total).

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The flow directional control valves (DCV) (withdrawal drive and

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withdrawal exhaust DCVs) were out of adjustment. This was also determined not to be possible because of direct observation that.

verified the correct flow (approximately 2.5 gpm drive flow).

Excessive drive water header pressure. The drive header pressure

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was observed to be normal throughout the occurrence.

Internal leakage in HCU scram valves. GE determined that this

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cause only applies to double notch movement during rod insertion.

Both stabilizing valves deenergized and closed for rod withdrawal.

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This possible cause also did not apply since no large increase in differential pressure was observed.

After the licensee evaluated the above possible causes, as contained in GEK-75640A, without determining a suspected cause, the HCU valve 122 was determined to be an additional possible cause of the occurrence. The 122 valve is the withdrawal supply valve on the HCU and if it momentarily remained in the open position longer than expected, the rod would have been driven more than one notch.

The licensee proposed to evaluate the performance of the 122 valve as referenced in Steps 8.3.7.5 and 6 of operating procedure CPS No. 3304.01, " Control Rod Hydraulic and Control",

by performing waveform traces and comparing them to the reference waveform traces contained in GEK-75640A.

.

The licensee accomplished this evaluation by performing maintenance j

procedure 8611.45, " Control Rod Drive (CRD) Differential Pressure Test" i

on March 6, 1987. This evaluation verified that the 122 valve was not defective; however, after comparing the obtained waveform to'the referenced waveforms contained in GEK-75640A (figure 40-30), the licensee determined that approximately.8gpm leakage occurred through the CRD flange check valve (a ball type check valve). The licensee also adjusted flow through the HCU valve 120, which increased the settle duration to allow completion of the settle mode. GE agreed with the licensee's conclusion that the flange check valve was suspected as the most likely cause of the double notching since the other possible reverse leaking valve 138 was isolated during the differential pressure test. GE also concluded that the flange check valve may have its function partially impaired because of foreign matter.

However, GE also determined that for the reactor vessel pressure (125 psig) at the time of failure, it was not possible to purge the flange check valve of foreign matter until pressure had been increased to normal operating pressure.

Based upon the above results and discussions, the licensee was able to determine the root cause (possible foreign matter in the flange check

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valve), corrective action (to purge the flange check valve at normal operating pressure) and the generic corrective action on March 7, 1987.

The licensee determined that no generic corrective action was applicable because of recent rod testing and various rod motions prior to and after the occurrence did not indicate double notching on any other control

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rod.

In addition, control rod 12-25 was tested satisfactorily twice on March 6,1987, after drive flow had been adjusted with valve 120.

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In addition to the double notching occurrence, the valve chattering was determined to be caused by air in the cooling water line and resulting in the HCU cooling water check valve (138) to chatter against its seat.

This occurrence had been previously evaluated on February 22, 1986, during preoperational testing. The results of the previous evaluation, supplied by GE and station engineering, was based upon experience at other Boiling Water Reactors as follows: the air in the cooling water line will be eliminated with operation of the system over a period of time and that no recurrence of the chattering has been experienced after the reactor plant had been at normal operating pressure for extended periods.

The inspector reviewed the condition report, differential pressure test data, the licensee's conclusion and the GE documents and concluded that all of the actions taken by the licensee were appropriate and in a timely manner that demonstrated good management, engineering support, and operation staff involvement. Discussed below are the bases for the inspector's conclusion:

The immediate actions taken by management to suspend further rod

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motion was valid and demonstrated management's knowledge of various safety design bases (see paragraph 9.d. below).

The inspector reviewed Condition Report (CR) 1-87-03-053 and found

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that the processing and completion of the condition report, including the corrective actions (both generic and specific) met the requirements of administrative procedure CPS No. 1016.01, " CPS Condition Reports".

The inspector reviewed and independently compared the obtained

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differential pressure waveform traces to the referenced waveform traces in GEK-75640A and agreed with the licensee's conclusion that the flange check valve was the most likely suspect of leaking and causing double notching.

It should be noted that the waveform for leakage through the flange check valve has two distinct indications that does not appear on other waveforms. The " drive down" duration has a gradual decay or decrease which is usually constant for normal rod withdrawal and relatively constant with some oscillations with leakage through the 138 valve. Also the " settle" duration is shorter and distorted while other abnormal waveforms have no significant waveform distortion compared to a normal waveform trace.

No violations or deviations were identified.

9.

Operational Safety Verification (71707)

The inspector 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

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conducted to observe plant equipment conditions including potential for fire hazards, fluid leaks, and operating conditions (i.e., vibration, process parameters, operating temperatures, etc). The inspector verified that maintenance requests had been initiated for discrepant conditions observed. The inspector verified by direct observation and discussion with plant personnel that security procedures and radiation protection (RP) controls were being properly implemented.

The inspectors reviewed the following events to ascertain the licensee's corrective actions and applicability to the requirements of the technical specifications. The results of this review are discussed as follows:

a.

During the daily shift supervisor review of technical specification required surveillances on February 28, 1987, the shift supervisor noted that step 8.8.1.1 of CPS No. 9000.010001, " Control Room Operator Surveillance Log - Mode 1, 2, 3 Data Sheet" for February 27, 1987, was initialed by the day shift as meeting the Primary to Secondary Containment differential pressure (dp) of between

.25 and +.25 psid as required by Technical Specification 3.6.1.

However, the actual recorded value was +.28 psid which is outside of the specification.

In addition to the first out of specification reading, the next shift (swing) recorded a value of

+.321 psid and noted that the dp was out of specification but did not notify the shift supervisor or make a log entry into the control room log. The shift supervisor informed the inspector and CPS management of the Limiting Condition for Operation (LCO).

The specification was verified to be satisfactory on the first shift on February 28, 1987. However, at first the dp also appeared to be out of specification because of the accuracy of the computer derived value. This accuracy was dependent upon the range of compression of the source information.

The computer derived value was used in a manual calculation to verify that the specification was met.

The compression range was altered to produce a more accurate value and the manual calculation was reperformed.

This calculated value met the specification.

The inspector attended the critique of this potential violation of Clinton Technical Specifications conducted at 8:00 a.m. on February 28, 1987. At the time of the critique, the licensee concluded that the events described above were reportable under 10CFR50.73(a)(2)(1)(B) as an item or condition prohibited by the

plant technical specifications. The initial critique was unable to retrieve sufficient information from plant computers or other data sources that would verify the technical specifications required differential pressures were maintained during the " day" and " swing" shift on February 27, 1987.

Subsequent to the events described above, the licensee's Nuclear Station Engineering Department (NSED) evaluated the plant conditions at the time out of specification readings were recorded (i.e. day and swing shift on February 27).

The NSED evaluation documented

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in IP memorandum Y-83666 concluded that the differential pressure between primary and secondary containment were within the technical specification limits at the time of interest based on additional instrumentation and alarms that were available and in use. The inspector's review of the engineering evaluation and conclusion (Y-83666) that the primary containment to secondary containment differential pressure was within technical specification limits indicated that sufficient information was provided to support that fact. Therefore, the licensee's decision not to report this event under the provisions of 10CFR50.73 was reasonable.

The on duty day shift and swing shift on February 27, 1987, did not realize that a LCO had been entered which required the Primary to Secondary Containment dp to be restored within one hour or the reactor was to be placed in Hot Shutdown within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and Cold Shutdown with 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Administrative Procedure CPS No. 1401.01, revision 11, dated December 31, 1986, paragraph 8.4.3.2.f. required the status of any current Limiting Condition for Operation (LCO) be conveyed at shift relief. Technical Specification 6.8.1.d. required that written procedures shall be established, implem3nted and maintained for surveillance of safety-related equipme.t.

Failure of the day and swing shift operators on February 27, 1987, to convey the status of out of specification differential pressure readings at shift relief is a violation (461/87011-03A).

b.

On March 6, 1987, the inspector noted that the licen:;ee determined that the Division 3 diesel generator (IC) room ventilation fan's (1VD01CC) automatic trip and start function was inoperable because of an inadequately connected spade type lug in the Division 3 HVAC/ BOP miscellaneous control panel (IH13-821/822). The determination was based upon the final analysis by engineering of an identified deficiency during a panel electrical verification on February 19,1987 (Verification Exception No. 8 to IP821).

The licensee issued a maintenance work request (MWR C49505) on February 19, 1987 to identify the found deficiency and to address technical specification requirements. The shift supervisor reviewed the deficiency and determined that no LCO was entered and processed the MWR as required by the appropriate administrative procedure CPS No. 1029.01. The lug was repaired per maintenance procedure CPS No. 8492.01 and verified by quality control on March 7, 1987.

The inspector reviewed this event to ascertain whether the licensee's determination of the deficiency's application to

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technical specification was correct, or if diesel generator 1C was inoperable between February 18 and March 7,1987.

During the event, the reactor was in Operational Conditions 4 (Cold Shutdown) between February 18 and 26, 1987 and Condition 2 between February 26 and March 7, 1987.

Listed below are the applicable

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technical specification LCOs for Operational Conditions 2 and 4.

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(1) Technical Specification LCO 3.8.1.2.b required, as a minimum, diesel generator 1A or 18, and diesel generator 1C (when the HPCS system was required to be OPERABLE), each with: a separate day fuel tank, a separate fuel storage system and a fuel transfer pump, while in Operational Conditions 4 (Cold Shutdown) and 5 (Refueling).

(2) Technical Specification LC0 3.8.1.1.b required, as a minimum, three separate and independent diesel generators, each with:

a separate day fuel tank, a separate fuel storage system and a separate fuel transfer pump, while in Operational Condition 1 (Power Operation), 2 (Startup), and 3 (Hot Shutdown).

In addition to the LCOs, Technical Specification Definition 1.27 provided the following:

"A system, subsystem, train, component or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified function (s) and when all necessary attendant instrumentation, controls, electrical power, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component or device to perform its function (s) are also capable of performing their related support function (s)."

The function of the diesel room ventilation (VD), as defined in Section 9.4.5 of the Final Safety Analysis Report (FSAR), was to limit the diesel room temperatures to 130 degrees Fahrenheit (F)

in order to conform to equipment (instrumentation and controls)

requirements.

In general, the VD system provided ventilation cooling for the diesel generator support equipment in order that they are capable of perforning their related support functions.

In relation to Technical Specification Definition 1.27 above, the VD system was not clearly applicable; however, the VD system cooling the instrumentation and controls was applicable.

The VD system was designed to accomplish its function by automatic start when its respective diesel generator starts and can be controlled by hand switches (manual) located in the control room or at local control panels. Therefore, the design of the system included manual operation to maintain the room temperatures to support the room equipment (excluding the engines) in performing their related support function to the engines. This design feature was also supported by Table 9.4-10 of the FSAR, " Diesel Generator Facilities Ventilation System Failure Analysis" in that for a loss of air flow through the Diesel Generator Room Ventilation Fan, an alarm in the control room was actuated after a 30 second delay, allowing operator action to restore air flow without exceeding the design bases temperature of 130 degrees F.

In addition to the review of the above design and requirements, the inspector reviewed operating procedure CPS No. 3506.01, " Diesel Generator and Support Systems" to ascertain whether the loss of the automatic starting of the room fan would render the diesel generator

...

inoperable. The procedure directed the control room operator to verify that the room fan starts during automatic (Step 8.1.2.1.b)

and during manual (Step 8.1.3.9) starting of the respective diesel generators.

In addition, an operator was required by the procedure to be stationed in the local diesel generator room prior to any

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manual start and during an automatic start of the diesel generator.

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The inspector determined that the procedure adequately required the operator to monitor room fan starting and to take action on loss of fan flow to satisfy the support equipment functions.

,

The inspector concluded after reviewing all of the technical

,

specification requirements and definitions, design bases and operating procedures that the loss of the automatic starting interlock of the diesel generator room ventilation fan did not

,

render the fan inoperable because the design of the fan starting circuits allowed manual operation to meet the design bases. Since the room ventilation fan was not a direct supporting system to the diesel generators (the fan supports the diesel generator instrumentation and controls which are diesel generator supporting subsystems), the Technical Specification Definition 1.27 did not appear to apply to the diesel generator room ventilation subsystem and did not clearly apply to the requirements of the LCOs 3.8.1.1.b or 3.8.1.2.b.

Therefore, this event was not considered to be a violation of technical specifications; however, because of the vagueness of the requirements as applicable to the diesel generator room ventilation fans, this is considered an open item (461/87011-04).

The inspector and Region III will discuss with the Office of Nuclear Reactor Regulation (NRR) the application of technical specifications to the diesel generator room ventilation system and other systems and subsystems that are not clearly

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defined as support systems to technical specification required systems.

c.

On March 9, 1987, at 3:45 p.m. the licensee identified that the requirements of Technical Specification 3.3.2, "...the containment and reactor vessel isolation control system (CRVICS) channels shown

in Table 3.3.2-1 shall be operable with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.2-2 and with Isolation System Response Time as shown or Table 3.3.2-3" were not met in that the Main Steam Line Tunnel

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Temperature Timers (Division 1 and 2), as required by 4.1. of Table 3.3.2-1, were not operable. The licensee met the requirements of the Action Statement 3.3.2.2 at 4:31 p.m. (within one hour of identifying that the channel was inoperable) by tripping the channel and isolating the valves associated with the timer. The licensee also initiated a LC0 review (LCO 87-3-28) and issued Condition Report 1-87-03-062. The licensee determined that the timers were inoperable because surveillance procedure CPS No. 9432.10, Revision

21, "RCIC and Main Steam Tunnel Differential Temperature E31-N605A (B,E,F) Channel Functional / Calibration" was inadequate to meet the technical specification requirements.

The procedure did not

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functionally test the Main Steam Line Tunnel Temperature Timers.

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The timers were part of the Reactor Core Isolation Cooling system (RCIC) isolation subsystem for high-energy line break considerations.

After taking the technical specification required actions, the licensee calibrated the timers per surveillance procedure CPS No. 9432.22, Revision 21, "RCIC Steam Tunnel Temperature Timer E31-R617E(F) Channel Calibration" and restored the system to normal with the valves open.

The inspector verified that the procedure met the requirements of Technical Specifications 4.3.2.1 and Table 4.3.2-1, Item 4.1.

The inspector reviewed the event and found the licensee's actions appropriate. The inspector also determined that Technical Specification LCO 3.3.2 was violated; however, the licensee met

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the requirements of 10CFR2, Appendix B, Paragraph W in that; (1)

the violation was identified by the licensee and met the action requirements of Technical Specification 3.3.2.2; (2) the violation fits in Severity Level IV of Supplement I (failure to meet regulatory requirements that have more than minor safety significance - the LCO was violated but the action statement was satisfied); (3) it was reported, if required (was not required by 10CFR50.72); (4) the violation was immediately corrected by completing the appropriate calibration and the functional surveillance procedure was corrected to prevent recurrence, and (5) the violation could not have been prevented by the licensee's corrective ac. ion, since there had not been any previous violations of this nature. As discussed in 10CFR2, Appendix B, the "NRC will not generally issue a notice of violation for violations that meet the above requirements to encourage and support licensee initiative for self-identification and correction of problems." In addition, during the event, RCIC was not required to be operable because of low reactor vessel pressure and, as such, mitigated the significance of the violation.

Therefore, a notice of violation will not be issued.

d.

On March 5, 1987, during rod withdrawal of control rod 12-25 from position 22 to position 24 in the single notch withdrawal mode, the control rod overshot or skipped past the position 24 and settled at position 26. The control room operator immediately inserted control rod 12-25 to position 22.

The licensee issued Condition Report (CR) No. 1-87-03-053 to investigate and resolve the deficiency. As an immediate action, in addition to the operator's action above, all rod movement was suspended except for rod motion approved by the plant manager.

Further actions taken by the licensee included entering and completing the requirements of the action statement of Technical Specification LC0 3.1.3.1, which required, within one hour, verifying that the inoperable withdrawn control rod (12-25 at position 22) was separated from all other inoperable control rods

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(no other control rods were inoperable during the event) and to

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demonstrate the insertion capability of the inoperable withdrawn control rod by inserting the control rod at least one notch by drive water pressure within the normal range, which was done as stated above, and then the inoperable control rod can be withdrawn to a position no further than its position when found to be inoperable (position 22). The inspector found these actions to be appropriate for immediate actions on the part of the licensee. The inspector's review of the licensee's corrective maintenance to this event is documented above in paragraph 8.

e.

During observation of the day shift to swing shift control room shift turnover on March 26, 1987, the inspector noted that the departing Line Shift Supervisor had failed to sign the Shift Turnover and Relief - Status Report (CPS No. 1401.01F002) and the departing Control Room Operator failed to date and time his signature. Subsequent review of other Shift Turnover and Relief Status Reports back through March 22, 1987, revealed that on numerous occasions departing and/or incoming members of the operating crew failed to sign, date and/or time their signature.

In addition, one instance was noted where the block indicating the annunciators had been tested was not checked and in all but one instance listed LCO's did not have their expiration date and time recorded as required. The inspector brought the above to the attention of licensee management who took immediate corrective action. The corrective action consisted of directing each crew, via the night orders, to ensure that the Shift Turnover and Relief Status Report was completely filled out and signed and that the shift supervisor was responsible for implementing this. The operations department also requested assistance from the QA department to ensure that administrative requirenants concerning shift turnover were being fully met.

The inspector witnessed a shift turnover subsequent to the above corrective actions and noted that the shift supervisor covered this during his briefing of the oncoming crew.

f.

On March 08, 1987, the inspector observed the licensee exercising the Traversing In-Core Probes (TIP) in preparation for startup.

The TIP system was being operated in accordance with Clinton Operations procedure CPS No. 3322.01, Traversing In-Core Probe (TIP), Rev hion 3.

The controls were being manipulated by a control rue.a operator (CRO) and being supervised by the shift supervisor (SS).

Step 8.1.2.12 of 3322.01 required the CR0 to push the AUTO-START button and verify that the LOW 1 amp and FORWARD lamp illuminated and that the IN-SHIELD lamp extinguished.

The CR0 performed this step and observed that the TIP ran out to the 0001 position and stopped.

The next step of the procedure, 8.1.2.13 required the CR0 to make some additional verifications once the detector was beyond position 0010 but since the probe had stopped at 0001 he could not do this. The inspector observed that both the CR0 and the SS were not sure if the TIP was operating correctly and did not know if they should just push the AUTO-START button again. The CR0 consulted with other operators in the control

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room who had experience operating the TIP system and determined that the equipment was operating as expected and that all that was required to continue was to push the AUTO-START button again. At this point the SS made the decision that a minor change was needed to the procedure to allow the work to continue.

Upon return to the control room, the inspector found that the TIP exercising was complete.

The inspector questioned the CR0 who had operated the TIPS if the minor procedure change had been processed without any difficulty.

The CR0 stated that the SS had subsequently decided that a procedure change could be processed in conjunction with continuing work. The inspector questioned the SS as to the justification for this in light of the requirements of Clinton administrative procedure CPS No. 1401.01, Conduct of Operctions, revision 11, which stated in step 8.4.1.3 that in other than emergency situations, when a procedural step cannot be completed as stated, the procedure shall be changed per CPS No. 1005.07, Temperary Changes to Station Procedures, prior to work continuing.

The SS stated that he had discussed the issue with the staff assistant SS who told him that the Plant Manager had stated in a meeting that if the problem was minor, and if what was needed to be done was clear, that the procedure change could be processed in conjunction with the work continuing. The inspector noted that this management philosophy appeared to be in violation of the approved

procedure.

Subsequent to the above, the inspector was contacted by the SS who stated that he had misunderstood the Plant Manager's position on procedure changes and therefore had miscommunicated it to the inspector.

He explained that the Plant Manager had taken the position that it was within the SS's authority to decide if a procedure change was necessary or if the procedure was adequate as-is. He further stated that this was the decision that he should have made (i.e., a procedure change had been required).

The inspector noted that since it was obvious, based upon observation at the time of the problem, that neither the SS or the CR0 knew for sure if the equipment was operating correctly and did not know for sure what the next step to make it work was, that it would appear that a procedure change was in order so that how to operate the TIP system would be clear to the operator.

Clinton Technical Specification 6.8.1.a stated that written procedures shall be established, implemented, and maintained covering activities referenced in Appendix A of Regulatory Guide 1.33, revision 2, February 1978.

Regulatory Guide 1.33, Appendix A, revision 2,1.d lists Procedure Adherence and Temporary Change Method. Clinton procedure CPS No. 1401.01, Conduct of Operations, revision 11, paragraph 8.4.1.3 stated "...in other than emergency situations, when a procedural step cannot be completed as stated, the procedure shall be changed per CPS No. 1005.07, Temporary Change to Station Procedures, prior to work continuing". Based on this, the above is considered to be a violation (461/87011-038).

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g.

During routine inspection of LCOs in effect, the inspector noted that administrative controls in place for meeting the required action statements were not consistently applied. The inspector noted that in one instance the Reactor Water Cleanup system isolation valves had been " danger" tagged closed to meet an action statement and an earlier instance where the Reactor Water Cleanup system isolation valves were closed to meet an action statement but were not " danger" tagged. The inspector discussed this inconsistency with the licensee who agreed to review the controls that were being implemented.

This is considered an Open Item pending the inspector's review of the administrative controls established (461/87011-05).

Two violations were identified.

10. Engineered Safety Feature System Walkdown (71710)

The inspector performed a complete walkdown of the division 2 Low Pressure Coolant Injection (RHR-B and C) system during the report period to verify the system status. At the time the walkdown was performed, the licensee had identified the division 2 Low Pressure Coolant Injection system as an operable Emergency Core Cooling system meeting all the requirements of the plant's technical specifications.

For the purpose of this walkdown, the inspector utilized the following system drawings and the checklists contained in the system operating procedure:

CPS No. 3312.01V001, revision 4, RHR Valve Lineup CPS No. 3312.01E001, revision 4, RHR Electrical Lineup P&ID M05-1075, sheet 2, revision Y P&ID M05-1075, sheet 3, revision T P&ID M05-1075, sheet 4, revision S For the inspection performed, the following attributes were observed:

System lineup procedures matched the plant drawings.

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Valve and electrical switch / breaker positioning agreed with the

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lineup checklists.

Valves were locked when required.

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Equipment conditions appeared correct with no evidence of

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damage.

Equipment and components were properly identified.

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Interiors of electrical and instrumentation cabin,ets were free

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of debris, loose material, uncontrolled jumpers, with no evidence of rodents.

Instrumentation was properly installed and functioning.

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Lubrication was provided, where observable.

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Housekeeping was adequate and appropriate levels of cleanliness

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were being maintained.

Support sys tems essential to system actuation (Division II

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Shutdown.C,.*vice Water and Division II Emergency Diesel) were operationi.1.

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In conjunction with the above, the inspector reviewed the results of current surveillances performed on the LPCI system to verify technical specification requirements were met. The following surveillance test results were reviewed:

Surveillance No.

Title Frequency Test Date CPS No. 9053.01 LPCI OPERABILITY CHECK Monthly 03/03/87 (LPCI A/8)

CPS No. 9053.02 LPCI OPERABILITY CHECK Monthly 03/17/87-(LPCI C)

CPS No. 9053.03 ECCS DIV 2 SIMULATED 18 Months 08/31/86 AUTO ACTUATION CPS No. 9053.04 RHR (A/8/C) VALVE Quarterly 2/7-10/87 (Stroke Time)

OPERABILITY CHECKS 18 Months -

(Position Indication)

CPS No. 9053.07 RHR PUMPS OPERABILITY Quarterly 2/8-10/87 The inspecter concluded that the LPCI (division 2) system was operable based on direct field observations of the above lineups and inspection attributes.

In addition, the inspector's review of current surveillance tests for the LPCI system indicated the plant's technical specifications were being met.

No violations or deviations were identified.

11. Onsite Followup of Events at Operating Reactors (93702)

a.

General The inspector performed onsite followup activities for events which occurred during the inspection period.

Followuo 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 inspector reviewed one or more of the following: the sequence of actions; the functioning of safety systems required by plant conditions; licensee actions to verify consistency with plant procedures and license conditions; and attempted to verify the nature of the event. Additionally, in some cases, the inspector verified that licensee investigation had identified root causes of equipment malfunctions and/or personnel errors and were taking or had taken appropriate corrective actions. Details of the events and licensee corrective actions noted during the inspector's followup are provided in paragraph b. below.

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b.

Details (1) Fuel Building Ventilation Damper Closed Causing A High Differential Pressure In The Secondary Gas Control Boundary

[ ENS No. 07976]

At about 6:30 p.m. CST on March 6, 1987, a ventilation damper (IVF04Y) actuated closed in the licensee's fuel building ventilation system (VF). This closure resulted in a high differential pressure in the secondary gas control boundary.

In accordance with plant technical specifications, the licensee manually actuated one train of the standby gas treatment system to maintain the secondary gas control boundary pressure limits.

The licensee identified the cause of the VF damper closure was due to a failed solenoid.

Repairs were made and the VF system was returned to its normal lineup at about 4:00 a.m. on March 7, 1987. The reactor plant was in mode 2 at the time of this event.

The licensee notified the NRC Operations Center of this event via the ENS at 8:50 p.m. CST on March 6, 1987.

(2) ESF Actuation Due to Automatic Shift of Control Room Ventilation [ ENS No. 07990]

At about 3:00 a.m. CST on March 8, 1937, the licensee experienced an ESF actuation when the control room ventilation system (VC) shifted to its chlorine mode. The licensee identified that one of the four local chlorine detection panels had alarmed; however, actual chlorine limits were not exceeded.

The one local panel was taken out of service and the VC system was returned to its normal lineup while troubleshooting continues. The reactor plant was in mode 2 at the time of this event. The licensee notified the NRC Operations Center of this event via the ENS at 4:44 a.m. CST on March 8, 1987.

(3) ESF Actuation Due to Automatic Shift of Control Room Ventilation [ ENS Nos. 08002, 08003]

At about 2:22 a.m. CST and again at 6:07 a.m. on March 10, 1987, the licensee experienced ESF actuations when the control room ventilation system (VC) shifted to its chlorine mode.

The first shift occurred during the performance of a routine surveillance while attempting to shift VC trains.

The licensee believed the first actuation was due to flow oscillation detected at a local chlorine detector panel. The licensee returned the VC system to its normal lineup following the first actuation at 2:52 a.m.

The second actuation occurred when a chlorine detection tape cartridge ran out in one of the four local chlorine detector panels.

The VC system was left in the chlorine mode following the second actuation until the licensee replaced the chlorine detector tape cartridge. The reactor plant was in mode 2 at the time of this event. The licensee notified the NRC Operations Center of the first event via the ENS at 5:40 a.m. CST on March 10, 1987.

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(4) ESF Actuation Due to Reactor Water Cleanup System Isolation

[ ENS No. 08006]

At approximately 8:35 a.m. on March 10, 1987, the licensee experienced a reactor water cleanup (RT) system isolation.

The system isolated due to a high differential flow condition.

The plant was in mode 2 at the time of the occurrence. At 10:45 a.m. the RT system was placed back into service. At approximately 11:15 a.m. on March 10, 1987, the licensee notified the NRC Operations Center of the RT system isolation.

(5) ESF Actuation Due to Automatic Shift of Control Room Ventilation [ ENS No. 08025]

At about 9:50 p.m. CST on March 11, 1987, the licensee experienced an ESF actuation when the control room ventilation

system (VC) shifted to its chlorine mode. The licensee identified the cause for this actuation was a local chlorine

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detection panel that was alarmed due to a high flow rate

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(950cc).

Plant operators adjusted the flow rate to its normal range (700cc) and the alarm cleared.

The VC system was

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returned to its normal lineup at 2:13 a.m. on March 12, 1987.

The reactor plant was in mode 2 at the time of this event.

The licensee notified the NRC Operations Center of this event

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j at 9:10 p.m. CST on March 11, 1987.

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(6) ESF Actuation Due to Automatic Shift of Control Room Ventilation [ ENS No. 08035]

f At 5:15 a.m. CST on March 13, 1987, the licensee experienced an ESF actuation when the control room Ventilation (VC) System shifted to its chlorine mode. The event occurred during the conduct of a routine operation to change the chlorine detector paper tape. When the operator placed the local panel switch to the unload position, VC train B shifted to the chlorine mode.

Placing the local switch into the unload position was a routine operation and the subsequent shift to the chlorine mode was unexpected.

The reactor plant was in mode 2 at the time of these events. The licensee notified the NRC Operations Center of this event at 6:30 a.m. CST on March 13, 1987.

(7) ESF Actuation Due to Actuation of Division III ECCS Components

[ ENS No. 08050]

At about 3:20 p.m. CST on March 15, 1987, the licensee experienced an actuation of Division III ECCS components.

The event occurred during restoration of a wide range level transmitter (821-N081C) following performance of a routine surveillance. While placing the wide range level transmitter

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back into service, a hydraulic transient was experienced on the common reference leg shared by the Division III low level 2 transmitters.

This actuated Division III ECCS logic and

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started the Division III Emergency Diesel Generator, High Pressure Core Spray (HPCS), and Division III Shutdown Service Water pumps. HPCS did not inject into the reactor due to a high reactor water level 8 (because of temperature effect)

that was reflecting plant conditions. Plant operators verified

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an actual low water level condition did not exist and restored all Division III equipment to a standby status at about 3:30 p.m.

The reactor plant was in mode 2 at the time of this event. The licensee notified the NRC Operations Center of this event via the ENS at about 6:30 p.m. CST on March 15, 1987.

(8) ESF Actuation Due to Lifted Lead Error Durino Routine Surveillance [ ENS No. 08066]

At about 12:30 a.m. CST on March 17, 1987, the licensee experienced an inadvertant ESF actuation.

During the performance of a routine surveillance, a C&I technician lifted i

an incorrect lead.

The surveillance being performed instructed the lifting of a lead to the Reactor Water Cleanup pump room 2 temperature sensor.

Personnel performing the surveillance mistakenly lifted a lead to the Residual Heat Removal equipment

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area 1 temperature sensor. This caused a group 2, 3, 5, 6, and 20 isolation signal. Only one valve (E31-F063) actually closed as all other valves in those groups were already in the closed position. The licensee reset the group isolation logics and restored normal lineups at about 1:45 a.m.

The surveillance that was being performed was successfully completed at 3:00 a.m.

The reactor plant was in mode 2 at the time of this event. The Itcensee informed the NRC Operations Center of this

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j event via the ENS at 2:00 a.m. CST on March 17, 1987.

(9) ESF Actuation Due to Reactor Wate.r Cleanup System Automatic Isolation [ ENS No. 08088]

At about 12:50 p.m. CST on March 18, 1987, the licensee i

experienced a reactor water cleanup (RT) system isolation.

The system isolated due to a high differential flow condition caused by manipulation of the feedwater system at low flow

conditions. At 1:55 p.m. the RT system was placed back into service. The plant was in mode 2 at the time of the occurrence. The licensee notified the NRC Operations Center

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of this event via the ENS at 4:40 p.m. CST on March 18, 1987.

(10) ESF Actuations Due to Reactor Water Cleanup System Automatic i

Isolation [ ENS 08122 and 08126]

At about 9:40 a.m. and again at 5:23 p.m. CST on March 21, 1987, the licensee experienced a Reactor Water Cleanup (RT)

system isolation. The system isolated due to a high differential flow condition caused by manipulation of the feedwater system at low flow conditions.

The plant was in

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,,e mode 2 at the time of each occurrence. The licensee notified

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the NRC Operations Center of these events via the ENS at 11:40 a.m. and 6:40 p.m. CST on March 21, 1987.

(11) Manual Reactor Trip Initiated Due To Control Rod Drifts

[ ENS No. 08128]

At about 4:20 a.m. CST on March 22, 1987, the licensee

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initiated a manual reactor trip when all control rods were observed drifting in. Prior to the event, the licensee was

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performing a routine surveillance on reactor water level

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instrumentation.

Sometime during the conduct of this i

surveillance, instrument air containment-isolation valves (11A005 & IIA 008) went shut. Closure of these valves allowed air pressure to bleed off the scram air header.

The reactor

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operator responded to indications of all rods drifting in by manually tripping the reactor. At 4:27 a.m. the shift supervisor declared an unusual event. The unusual event declaration was terminated at 5:38 a.m.

All systems responded i

as expected to the manual reactor trip. However, water leakage i

from a vent on the charging water header in the Rod Drive i

system required operators to reclose a vent valve (1C11-F324A)

before Control Rod Drive Cooling Water could be restored. At the time of occurrence, the plant was in mode 2.

The licensee notified the NRC Operations Center of this event via the ENS at about 5:19 a.m. CST on March 22, 1987.

(12) ESF Manual Actuation Due to Operator Error [ ENS No. 08133]

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At about 4:20 p.m. CST on March 22, 1987, tha licensee manually actuated an ESF when a control room operator started Division I Shutdown Service Water Pump. While restoring from a routine surveillance on the Division II diesel generator, the control room operator mistakenly closed the Plant Service Water (SW)

to Shutdown Service Water (SX) Cross Connect (SX014A). The

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operator immediately identified the error and started the

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Division I SX pump to prevent a loss of pressure in the Plant i

Service Water system. After the cross connect valve (SX014A)

completed its closure cycle, the operator reopened the valve i

and returned the SX system to a standby condition. The plant was in mode 4 at the time of this event. The licensee notified

the NRC Operations Center of this event via the ENS at about

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7:35 p.m. CST on March 22, 1987.

(13) ESF Actuation Due to Safety Relief Valve Actuation [ ENS No. 08153]

At about 3:30 p.m. CST on March 24, 1987, while in mode 4 (Cold Shutdown) the licensee experienced an ESF actuation when a safety relief valve (1821-F0410) unexpectedly lifted during

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the performance of a routine surveiliance. At the time of this l

event the licensee was performing a monthly channel functional i

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test of the reactor pressure high analog trip module (ATM) that makes up a portion of the logic for the subject SRV. The SRV

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cycled several times over a two minute period. The licensee identified the root cause for this actuation was 4 failed " load driver" in the trip logic circuit. The licensee implemented short term corrective action to prevent additional actuations during performance of this surveillance.

The inspector verified that the licensee's corrective action was in place prior to returning the plant to mode 2 on March 29, 1987.

The licensee was evaluating long term corrective actions to eliminate the failure mechanism experienced by the " load dri ve r". The licensee notified the NRC Operations Center of this event via the ENS at 6:24 p.m. CST on March 24, 1987.

(14) ESF Actuation - Reactor Water Cleanup Isolation Caused by Reactor Water Level Transient [ ENS No. 08197]

At about 4:40 a.m. CST on March 30, 1987, the licensee experienced an ESF actuation when the Reactor Water Cleanup system isolated in response to a pressure transient in the reactor vessel. The licensee was in the process of opening the inboard Main Steam Isolation Valves (MSIV) in accordance with plant operating procedures. Upon opening the "C" MSIV with reactor pressure at about 60 psig, a pressure surge was sensed downstream that caused the turbine #1 and #2 bypass valves to open.

The opening of the turbine bypass valves caused a pressure decrease in the reactor vessel and subsequent increase

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in reactor pressure when the operators closed the MSIV. The pressure transient was sensed by the Reactor Water Cleanup system as a high delta flow and isolated the system. The plant was in mode 2 at the time of this event.

The licensee notified the NRC Operations Center of this event via the ENS at 6:23 a.m. CST on March 30, 1987.

(15) ESF Actuation - Reactor Core Isolation Cooling System Isolation

[ ENS No. 08207]

At about 2:42 p.m. CST on March 30, 1987, the licensee experienced an ESF actuation when the Reactor Core Isolation Cooling system isolated during the performance of a routine i

surveillance.

The licensee was in the process of performing a channel functional test on the RCIC Main Steam supply pressure trip logic. When a trip signal was inserted in accordance with the procedure, the RCIC system isolated.

The licensee determined the cause of this event was a deficient procedure that was being performed for the first time with the RCIC isolation valves open. The plant was in mode 2 at the time of i

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this event. The licensee notified the NRC Operations Center of this event via the ENS at 5:40 p.m. CST on March 30, 1987.

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. s During the critique of this event, it was identified that personnel performing surveillance procedure CPS No. 9030.01C035 had not implemented Plant Manager Standing Order (PMS0) No. 30.

This PMS0 was the basis for corrective action to Violation 50-461/86065-04 as identified in the licensee's response to that violation (ref. IP letter U-600806 dated January 6, 1987).

Technical Specification 6.8.1.d required that written procedures shall be established, implemented, and maintained for surveillance and test activities of safety related equipment.

Failure of personnel performing surveillance CPS No. 9030.01C035 on March 30, 1987, to implement the instructions contained in PMSO-30 prior to the conduct of that surveillance is a violation of CPS technical specifications (461/87011-03C).

(16) [ESF Actuation Due to Reactor Water Cleanup System Isolation Ells No. 08213]

At about 6:10 a.m. CST on March 31, 1987, the licensee experienced an ESF actuation when the Reactor Water Cleanup system isolated in response to a condition caused by manipulation of the Feedwater system at low flow conditions.

The plant was in mode 2 at the time of this event.

The licensee notified the NRC Operations Center of this event via the ENS at 6:30 a.m. CST on March 31, 1987.

Of the 16 events discussed above, 4 were due to chlorine monitor problems.

Previous to this report period, the inspector had documented 4 additional ESF actuations (i.e., control room ventilation shift to chlorine mode) directly attributable to the unreliability of the licensee's chlorine monitors. The licensee has initiated action to resolve or reduce the number of unnecessary actuations caused by the chlorine monitors.

Of the remaining 12 events discussed above, 5 were due to isolation of the Reactor Water Cleanup system.

Previous to this report period, the inspector had documented 4 additional events involving isolation of the Reactor Water Cleanup system.

The licensee believed the primary cause for these events to be the low feedwater flow conditions under which they occurred. The licensee was continuing to evaluate whether or not the Reactor Water Cleanup system was responding as intended for the plant conditions.

One violation was identified.

12. Startup Test Witnessing - Full Core Shutdown Margin Determination.

Initial Criticalitya and Intermediate Range Monitor / Source Range Monitor Overlap (72302,72526)

The inspectors witnessed the conduct of the following Startup Test Procedures (STPs):

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STP-04-0, " Full Core Shutdown Margin" STP-06-0, "Jource Range Monitor (SRM), Performance and Control Rod Sequence" STP-10-0, ' Intermediate Range Monitor (IRM) Performance - SRM/IRM Overlap" STF-06-H, "SRM Performance and Control Rod Sequence" STP-10-h, "IRM Per 'ormance - IRM Range 6/7 Overlap and Initial IRM/APRM Overlap" The inspectors determined by direct observation that:

licensee operating and test personnel were knowledgeable in their individual roles and responsibilities, adequate communications were established and maintained throughout the tests, and the approach to criticality was conducted in a cautious, deliberate, and professional manner.

Prior to, during, and subsequent to the subject tests the inspectors verified the following:

Conformance with selected technical specification requirements and

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license conditions applicable during the initial approach to critical.

SRM and IRM nuclear instruments had been properly calibrated and

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were operating with required count rate and signal-to-noise ratio.

Crew requirements were being met as defined in plant procedures,

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and staffing satisfied requirements of technical specifications regarding.lcensed operators.

The proper versions of the test procedures were in use and were

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being followed. All referenced procedures had been reviewed and approved.

Each of the prerequisites had been satisfied.

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Inverse multiplication plots were adequately computed and plotted.

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In addition, the inspector verified the inverse multiplication plot calculations by performing independent calculations.

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Onsite technical support appeared to be adequate.

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Changes or revisions to the test procedures were properly reviewed

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and approved.

Data sheet entries were legible and recorded in permanent ink.

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Proper rod pattern was maintained and verified throughout the

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approach to criticality.

Review of the test results will be conducted during a future inspection.

No violations or deviations were identified.

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13. Management Meeting (30702)

a.

On March 13, 1987, NCR management met with IP management at the Region III Office in Glen Ellyn,. Illinois to discuss concerns identified by an " Operational Readiness Assessment Team inspection conducted March 2 through March 6, 1987.

The.results of that team inspection are documented in Inspection Report 50-461/87010. Key personnel attending this meeting are identified by (#) in paragraph 1 of this report.

The licensee discussed their evaluation of the concerns expressed by the inspection team at the exit conducted at the Clinton Power Station on March 6, 1987. The licensee's presentation included their plans to address all of the concerns expressed by the inspection team. The licensee requested the Region III inspection

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team to return to the Clinton Power Station and conduct another inspection.

b.

On April 2, 1987, NRC management met with IP management at the Clinton Power Station to discuss the results of~the Operational Readiness Assessment Team inspection conducted March 30 through April 2, 1987. The results of that team inspection are also included in Inspection Report 50-461/87010. Key personnel attending this meeting are identified by (@) in paragraph 1 of this report.

The licensee discussed their readiness to request a full power license. NRC management stated that concerns expressed at the meeting described in a. above had been adequately addressed and that the full power license proceedings would be scheduled.

14. Open Items Open items are matters which have been discussed with the licensee, which will be reviewed further by the inspector, and which will involve some action on the part of the NRC or licensee or both.

Four open items disclosed during the inspection were discussed in paragraphs 2, 6, and 9.

16. Exit Meetings (30703)

The inspector met with licensee representatives (denoted in paragraph 1)

throughout the inspection and at the conclusion of the inspection on April 6. 1987. The inspector summarized the scope and findings of the inspection activities. The licensee acknowledged the inspection findings.

The inspector also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspectors during the inspection. The licensee did not identify any such documents / processes as proprietary.

The resident inspector attended exit meetings held between Region III based inspectors and the licensee as follows:

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Inspector (s)

Date W. L. Forney 3/6/87 Z. Falevits 3/26/87 W. L. Forney 4/2/8/

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v t e Inspection Report - Clinton - 1987011
80 \| 81 \| 82 \| 83 \| 84 \| 85 \| 86 \| 87 \| 88 \| 89 \| 90 \| 91 \| 92 \| 93 \| 94 \| 95 \| 96 \| 97 \| 98 \| 99 00 \| 01 \| 02 \| 03 \| 04 \| 05 \| 06 \| 07 \| 08 \| 09 \| 10 \| 11 \| 12 \| 13 \| 14 \| 15 \| 16 \| 17 \| 18 \| 19 \| 20 \| 21 \| 22 \| 23 \| 24 \| 25 \|
1987 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 7(0) 8(0) 9(0) 10(0) 11(0) 12(0) 13(0) 14(0) 15(0) 16(0) 17(0) 18(0) 19(0) 21(0) 22(0) 23(0) 24(0) 25(0) 26(0) 27(0) 28(0) 29(0) 30(0) 31(0) 32(0) 34(0) 35(0) 36(0) 37(0) 38(0) 39(0) 40(0) Security Operator Exams Emergency Planning Other

IR 05000461/1987011

Text

REGION III

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