IR 05000461/1987031

Insp Rept 50-461/87-31 on 870630-0804.Violations Noted.Major Areas Inspected:Previous Insp Findings,Seismic Monitoring Instrumentation,Scram Discharge Vol Capability,Employee Concerns & Monthly Maint Observation

ML20237L433
Person / Time
Site:	Clinton
Issue date:	08/20/1987
From:	Knop R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20237L423	List: IR 05000461/1987031 ML20237L420 ML20237L429
References
50-461-87-31, NUDOCS 8708280101
Download: ML20237L433 (30)

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U.S. NUCLEAR REGULATORY COMMISSION

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REGION III

i Report No. 50-461/87031(DRP)

Docket No. 50-461 License No. NPF-62 l

Licensee:

Illinois Power Company 500 South 27th Street

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j Decatur, IL 62525 Facility Name: Clinton Power Station Inspection At: Clinton Site, Clinton, Illinois Inspection Conducted:

June 30 through August 4, 1987 l

Inspectors:

P. Hiland i

S. Ray l

M. Jordan M. McCormick-Barger

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Approved By:

R. C. Knop, Chief

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i Projects Section IB Date

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l Inspection Summary Inspection on June 30 through August 4, 1987 (Report No. 50-461/87031(DRP))

Areas Inspected:

Routine, unannounced safety inspection by the resident

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inspectors and region-based inspector of licensee action on previous inspection findings; seismic monitoring instrumentation; scram discharge volume capability; employee concerns; monthly maintenance observation; monthly surveillance observation; operational safety verification; training effectiveness; onsite followup of events at operating reactors; startup test witnessing; and management meeting.

Results: Of the 10 areas inspected, two violations were identified in the operational. safety verification area; two violations were identified in the onsite followup of events area; one unresolved item was identified in the seismic monitoring area; and one unresolved item was identified in the monthly maintenance observation. All of these items are receiving licensee management attention. Additionally, five Technical Specification violations were identified in the onsite followup of events area for which a. Notice of Violation was not issued in accordance with 10 CFR 2, Appendix C, Paragraph V (failure to satisfy technical specification action statement requirement within allotted time - Paragraphs 10.c.(2) and 10.c.(5); local leak rate tests on'five containment isolation valves performed with air medium instead of water -

Paragraph 10.c.(3); failure to perform channel check surveillance of radiation monitor - Paragraph 10.c.(7); and failure to perform shiftly channel checks on APRM neutron flux high - Paragraph 10.c.(13).)'

8708280101 870821 PDR ADOCK 05000461 G

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Personnel Contacted Illinois Power Company (IP)

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

1. T. Camilleri, Manager - Scheduling Outage and Maintenance

• R. Campbell, Manager - QA

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

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

1. E. Corrigan, Director, Quality Engineering & Verification J. Fertic, Director Quality Systems & Audits

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Ferguson, NRAG Member, Consultant

• R. Freeman, Assistant Plant Manager, Maintenance

• 1. W. Gerstner, Executive Vice President

• 1. D. Hall, Vice President, Nuclear D. Holesinger, Assistant Manager - Startup

.j E. Kant, Assistant Manager, NSED

1. W. Kelley, Chairman and President, Illinois Power

• J. Miller, Manager, Scheduling & Outage Management J. Palchak, Supervisor - Plant Support Services i

• 1. J. Perry, Manager - Nuclear Program Coordination

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1. S. Rasor, Project Manager, Material Improvement I

R. Schultz, Director, Planning & Programming-

• 1. F. Spangenberg, Manager - L&S q

P. Telthorst, Licensing and Safety E. Till, Director Nuclear Training

• J. Weaver, Director - Licensing

• 1. J. Wilson, Manager - CPS

1. R. Wyatt, Director-Nuclear Program Assessment j

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S_yland/WIPC0

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1. J. Greenwood, Manager Power Supply Nuclear Regulatory Commission

• 1. P. Hiland, Senior Resident Inspector, Clinton

• S. Ray,' Resident Inspector, Clinton

1. M. McCormick-Barger, Project Inspecter, Region III M. Jordan, Senior Resident Inspector, LaSalle

1. B. Davis, Regional Administrator, Region III

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1. R. Knop, Chief, Section IB,. Region III

1. D. Muller, NRR PD32, Director

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1. C. Norelius,. Director, DRP, Region III j

1. G. Holahan, Assistant Director, Region III & V Reactors

1. B. Siegel, Project Manager, Clinton

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1. W. Forney, Chief, Projects Branch 1, Region III y

1. H. Miller, Director, DRS

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1. Denotes those attending the management meeting on July 13, 1987.

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• Denotes those attending the monthly exit meeting on August 3, 1987.

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The inspector also contacted and interviewed other licensee and

contractor personnel.

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Previously Identified Items (92701)(92702)

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(Closed) Open Item (461/86074-02):

Procedure comment control forms (CCFs) were being used to identify suggested procedure improvements.

This use was not controlled by plant administrative procedures, and

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the inspector was concerned that the CCFs had not been reviewed to.

determine their technical impact and the need for immediate

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procedure revision.

r This item was previously reviewed as documented in Inspection Report 50-461/87002, Paragraph 2.h.

At the time of that' inspection, this item remained open pending completion of the licensee's actions and verification that the plant staff was adhering to the revised administrative procedure CPS No. 1005.01 for control of CCFs.

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l During the. report period, the licensee provided the inspector with

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results of two Quality Assurance Surveillance reports that had been

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performed since this item was previously reviewed.

Surveillance

Reports Q-09482, dated February 12, 1987, and Q-09559, dated April 7,

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1987, documented the inspections performed by the licensee's Quality l

Assurance department.

Those inspections confirmed that corrective action taken by the licensee in response to this item and Surveillance Report Q-09456, dated December 16, 1986,'were adequate.

This item is closed.

b.

(Closed) Open Item (461/86074-03):

Lack of formal procedures to define responsibility and the mechanisms to assure identification and completion of new non-licensed operator (NLO) qualifications.

This item was previously reviewed by the inspector as documented in Inspection Report No. 50-461/87015, Paragraph 2.c.

At the time of that inspection, this item remained open pending resolution of two specific questions raised by the inspector concerning responsibilities defined in Nuclear Training Department procedure (NTD) 2.15.

During this report period, NTD 2.15, Revision 1, dated July 1,1987, was issued.

That revision defined in section 5.3.2 requirements for

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revising in process training checklists for NL0s and further defined the responsibility for reviewing "NLO Training Addendum Sheets."

These procedural changes addressed the questions previously raised

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by the inspector.

This item is closed.

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c.

(Closed) Open Item (461/87007-02):

Unannunciated seal-in logic

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closed the inboard Residual Heat Removal (RHR) suction valve 1E12-F009 when restoring the system following an operational pressure test. The inspector asked the licensee to evaluate the unannunciated seal-in' logic with respect to another event (LER-86-004-00) where components were unexpectedly actuated due to l

an unannunciated seal-in logic.

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l During this report period, the licensee provided the inspector i

results of their engineering evaluation of this item.

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IP memorandum Y-83793, dated March 23, 1987, documented the

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licensee's evaluation that since the trip signal which caus

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1E12-F009 to close was not part of the Low Pressure Coolant

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Injection (LPCI) mode of the RHR system, a specific-seal-in light was not present.

However, the licensee revised the applicable

' i Technical Procedure CPS No. 2800.03, " Reactor Coolant System Leakage Test," to include instructions for resetting the seal-in logic when i

restoring from an operational pressure test.

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In addition, the licensee revised Surveillance Procedure CPS No. 9920.72, " Channel Functional Testing of Safety Related Process L

Radiation Monitors," via POR 87-1130, dated July 7, 1987, to include provisions to reset seal-in circuits during performance and i

restoration of surveillance activities on Process Radiation Monitors (LER-86-004-00).

Based on the inspector's review of the licensee's i

engineering evaluation and confirmation that the applicable

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implementing procedures had been revised, this item is closed.

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(Closed) Violation (461/87011-03):

Three examples of failure to

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implement written procedures as required by Technical Specification 6.8.1.

j The licensee responded to the Notice of Violation in IP letter U-600932, dated May 17, 1987, in,a timely manner.

During this report period, the inspector reviewed the licensee's corrective action as described in U-600932.

(1)

In response to the failure of licensed operators.to properly-convey the status of out-of-specification readings identified by the operator, the licensee disciplined the individuals

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involved, and the Power Plant Manager discussed the need for appropriate action with the remaining shift operators.

The inspector observed several shift turnovers where the Power

Plant Manager discussed this item with shift personnel.

The

inspector concluded that the licensee had taken appropriate corrective action for this item.

(2)

In response to the failure to properly revise Operating i

Procedure CPS No. 3322.01, " Traversing In-Core Probe (TIP),"

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the licensee revised lesson plans in their Nuclear Training

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Department for proper operation of the TIP system.

In addition, Operating Procedure CPS No. 3322.01 was revised in Revision 4, dated June 10, 1987, to provide clear instructions for system operation. The insp6ctor concluded that the licensee had taken appropriate corrective action for this item.

(3)

In response to the failure of personnel to properly implement Plant Manager's Standing Order No. 30 while performing j

Surveillance Procedure CPS No. 9030.01C035, the licensee counseled the individuals involved.

In addition, the licensee identified all instruments that provided a one-out-of-one trip logic and reviewed the associated surveillance procedures to assure implementing procedures adequately addressed this item.

IP Memorandum RFS-154-87, dated June 16, 1987, documented the licensee's review and conclusion that corrective actions had

been completed. The inspector concluded that the licensee had j

taken appropriate corrective action for this item.

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Based on the reviews performed as discussed above and confirmation by the inspector that corrective actions as described in the licensee's response to this NOV were completed, this item is closed.

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(Closed) Unresolved Item (461/87015-01):

Support systems not being adequately reviewed for their impact when determined to be-inoperable.

As discussed below in Paragraph 6., a similar example of this concern was identified during the report period.

Unresolved Item No. 50-461/87015-01 is closed and resolution to the issues addressed in Inspection Report No. 50-461/87015, Paragraph 10.b. and the issues addressed in Paragraph 6. below will be tracked as Unresolved Item No. 50-461/87031-03.

No violations or deviations were identified.

3.

Periodic Inspection Of Seismic Monitoring Instrumentation - Regional Request (92701)

During the report period, the inspector performed a review of recent maintenance and surveillance data on seismic monitoring instrumentation.

The purpose of that review was to verify that the equipment was operable; that required tests were on the licensee's test schedule; that any needed maintenance had been scheduled; and that equipment failures had been properly documented.

In addition, the inspector performed an inspection

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by direct field observation of accessible instrumentation for any evidence of deterioration or inoperability, j

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References and Guidance Documents i

(1) CPS Technical Specification 3.3.7.2 - Seismic Monitoring i

Instrumentation

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r (2) Administrative Procedure CPS No. 1337.05, Revision 0, dated August 11, 1986, " Seismic Event Response and Reporting"

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(3) Operating Procedure CPS No. 3323.01, Revision-3, dated April 22,1987, " Seismic and Environmental Monitoring" (4) Off-Normal Procedure CPS.No. 4301.01, Revision 4, dated October 13, 1986, " Earthquake" (5). Annunciator Procedure CPS No. 5009.10,- Revision 20, dated'

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April 8, 1986, "ACCL EXCDED SEIS SW/ BAS EARTHQKE" (6) Annunciator Procedure CP5 No. 5009.19, Revision 20, dated April 8, 1986, " ACTIVATED SEIS RCDR" i

(7) Surveillance Procedure CPS No. 9437.04, Revision 21, dated-

June 13,1986, " Triaxial Respons: Spectrum Recorder Channel I

Calibration" (8) IP letter U-600964, "Special Report - Seismic Event'.at Clinton Power Station," dated June 19, 1987 l

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IP letter U-600941, "Special Report:

Inoperability of Seismic Monitoring Instrumentation," dated May 22, 1987 (10) Surveillance Test Data Packages:

CPS No. 9437.02, April 1986 and June 1987 CPS No. 9437.04, May 1986 and June 1987

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CPS No. 9437.21, August, September, and' October, 1986, and May

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and June, 1987 b.

Discussion (1) The inspector noted that procedures CPS No. 5009.10 and No. 4301.01 referenced Operating Procedure CPS No. 3323.01 for instructions concerning gather.ing and analyzing s.eismic data after an earthouake.

The instructions in CPS No. 3323.01 were

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not detailed and, in fact, contained some errors.

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instance, the procedure did not use the latest calibration data to analyze readings from the passive peak accelerographs.and passive spectrum response recorders.

Administrative Procedure CPS No. 1337.05 contained more detailed and correct information about gathering and analyzing the data, but this procedure was never referenced by any procedure the operators would have been expected to use'

following a seismic event.

(2) The location given for instrument IVR-EM013 in CPS No. 1337.05, Revision 0, Appendix B was not correct.

The instrument was on Diesel Generator 1A 011 Storage Tank, not on Diesel Generator 1B 011 Storage Tank.

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(3) The conversion factor used in Section 8.5.1 of CPS No. 1337.05 and page 2 of CPS No. 1337.05D001 was incorrect.

The actual response of the instruments is 0.51 mm/G so the conversion factor should have been t.hu inverse (i.e., 1.97 G/mm).

(4) The channel calibration procedures for the passive peak accelerographs and passive spectrum response recorder appeared to be inadequate to demonstrate operability of the instruments.

Clinton Power Station Technical Specification 1.4 defined a channel calibration, in part, as "... the adjustment, as necessary, of the channel output such that it responds with the necessary range and accuracy to known values of the parameter which the channel monitors." The key words' appeared to be

"necessary range" and "known values." This definition implied

that channel calibrations should be accomplished using'several

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values of the input parameter in the range for.which the instrument is intended to respond.

The channel calibrations for the passive seismic instruments used only one input data point, the acceleration of gravity (19).

The instruments were designed to respond to a wide range of accelerations and frequencies.

The trigger point for reporting a seismic event

was 0.02g or 50 times smaller than the acceleration'for which the instruments were calibrated.

The acceleration expected during the Operational Basis Earthquake is approximately one-tenth the acceleration at which the instruments are calibrated.

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(5) There was evidence that the calibration procedure for the passive spectrum response recorder had been accomplished

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incorrectly.

Specifically, Step 8.6.4 of CPS No. 9437.04,.

l Revision 21, stated "If adjustments are made to a particular -

reed, reperform Steps 8.3, 8.4, and 8.5 until data. is within the allowable limits on the data sheet." In addition, Step 2.1.3 states, in part, that "The Scriber Preload calibration is the'

only adjustment that can be made... this will make small

't adjustments to sensitivity and damping." In the calibration of 1VR-EM010 (Serial No. 1066), completed on June 16, 1987,-

comparison of the "as-found" and "as-left" data for damping, J

recorded in CPS No. 9437.04D001, page 3, indicated that reeds 5, 6, 8, 9,10,11, and 12 were adjusted to bring the percent damping within the allowable limits. Comparison of the

"as-found" to "as-left" data, for sensitivity recorded on page 2 of the same procedure indicated that the sensitivities were not rechecked after the adjustments to the reeds.

In addition, the inspector noted in the calibration of IVR-EM010 (Serial No. 1071),

completed on June 16, 1987, that the "as-found" frequency for reed 1 recorded on page 2 of CPS No. 9437.04D001 was not within 1% of the desired value as required by the acceptance criteria of '

the procedure.

This fact was apparently not recognized during j

the performance or review of the surveillance.

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(6) Several errors appeared to have been made in the data reported in Special Report U-600964 concerning the earthquake of June 10, 1987.

Specifically, the calibration data used on pages 1, 2, and 3 of CPS No. 1337.05D005 was not the most current as required by Step 5.3 of CPS No. 1337.05.

In addition, the calculated acceleration for reeds 1, 2, and 3 of instruments IVR-EM010, Serial No. 1071 and No. 1066 was not divided by two as required by Section 8.5.2 of CPS No. 1337.05.

(7) Special Report U-600964 concluded that the data obtained from the passive peak accelerographs was in error because the results were inconsistent and much higher than expected. These instruments were in calibration before the earthquake and were successfully recalibrates shortly after the earthquake, yet no detailed analysis was done to determine why the data was in error or whether the instruments could be depended upon to give reliable data during any future seismic event.

(8) During the physical walkdown of the system, the inspector noted that the cover on instrument IVR-EM011 was loose enough that dirt and moisture could have entered the instrument.

In addition, housekeeping in the area of instrument IVR-EM010 was not satisfactory.

A hose was wrapped several times around the instrument and loose debris was laying on top of the instrument.

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Results As noted above. the inspector identified a number of apparent discrepancies in the licensee's programs for satisfying seismic monitoring requirements of Clinton Technical Specifications.

Additional questions asked by the inspector during the conduct of this review were satisfactorily answered by cognizant licensee personnel.

The staff review of the licensee's Special Report on the June 10, l

1987 seismic event at Clinton Power Station was still in progress i

at the conclusion of the report period.

Since some of these l

apparent discrepancies have also been identified by the NRR staff reviewer, the items discussed above will remain an unresolved item pending completion of further review by the staff (461/87031-01(DRP)).

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One unresolved item was identified.

4.

Scram Discharge Volume Capability (25590)

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In March 1987, the Nuclear Regulatory Commission's Office of Insoection j

and Enforcement issued Temporary Instruction 2515/90.

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provided outdance on inspection followup of the licensee's activities to ensure scram discharge volume (SDV) capability in accordance with commitments concerning Multiplant Action (MPA) Item B-58.

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I During the report period, the inspector performed a review of the SDV l-capability in accordance with Temporary Instruction (TI) 2515/90.

Each actionitem([])inTI 2515/90 was addressed separately:

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Scram Discharge Header Size [04.04]

The inspector determined that the size of the SDV was adequate. GE-letter OER 54, dated March 14, 1972, and GE Specification 23A4175AA

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i required that a minimum SDV of 3.34 gallons per drive be provided.

Clinton Power Station has 145 Control Rod Drives, thus the M zimum SDV was 485 gallons.

Sargent and Lundy calculation 0/RD 05, dated March 15, 1985, determined the available SDV was 643 gallons.

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addition, Clinton Power Station Preoperational test, PTP-RD-01, l

which was reviewed by the inspector, physically masured the SDV by

a waterfill. The actual volume was 744,c,an ons, not including the Instrument Volume (IV).

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t Additional SDV piping physical recommendations are in GE Specification 23A4175. The principal recommendations are that the header piping should be a minimum of eight inches diameter and that no reductions in pipe size of the header pipe should exist.

The inspector visually confirmed that all the SDV header piping was ten inches diameter.

b.

Automatic Scram on High SDV Level

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The inspector confirmed by review of the FSAR, Technical Specifications, and drawings in the E02-IRD99 series that a scram function existed on a high SDV level.

c.

Instrument Taps Not on Connected Piping

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The inspector determined by visual inspection that'the lower taps for the safety-related level instruments were on the vertical portion of the IV.

The upper taps were on the horfzental SDV piping above the vertical portion.

The inspector confirmed that this arrangement had been evaluated by the Reactor Systems Branch and determined to be satisfactory.

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Detection of Water in the IV [04.04]

I The inspector determined by visual inspection that the SDV level instrumentation was diverse and redundant. The detection system consisted of both float switches and level transmitters using j

pressure. The two sets of instruments used separate sensing taps.

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Each of four channels of instrumentation was powered from-independent power supplies.

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I Ve9 and Drain Valves System Interfaces [04.05]

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k The inspector determinec by visual inspection that the SDV is dedicated to receive and contain only water discharged by the

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Control Rod Drives during a scram.

No other plant systems drained into the SDV.

The inspector determined by review of drawings r

CNL-001, Sheet 2, Revision II, M05-1046, Sheet 3, Revision G, and

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M05-1047, Sheet 3, Revision H, that the drain piping from the IV was (

routed directly to the containment equipment drain sump, and the vent L

piping from the IV was routed directly to the containment HVAC vent system with no other plant system connections which could cause wate-backup into the IV.

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Vent and Drain Valves Close on Loss of Air [04.06]

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The inspector determined by visual inspection that the SDV ver.t and drain valves were of a design that fail closed on loss of air.

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addition, direct field observation noted that valve position indication for the vent and drain valves was provided in the control room.

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Operator Aid [04.07]

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The inspector determined by direct field observation that an alarm t

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The alarm setpoint was three gallons as sensed on instruments IC11-N602A or IC11-N602B, A procedure existed (CPS No. 5006.04, Revision 20) for operator action in the event that this annunciator alarmed, h.

Active Failure in Vent and Drain Lines [04.08]

The inspector determined by visual inspection that a single active failure would not defeat isolation of the SDV vent and drain valves.

The vent and drain lines each contained two redundant series isolation valves contr;11ed by redundant solenoid pilot valves.

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Periodic Testing of Vent and Drain Valves

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The inspector determined by procedure review that surveillance procedures existed to test the operability of IV vent and drain valves.

Specifically, CPS No. 9012.01, Revision 22, verified quarterly that vent and drain valves cycled properly using test switches.

As part of that test, closing time was verified to be less than 30 seconds.

CPS No. 9012.02, Revision 20, verified once every 18 months that the vent and drain va'.ves cycled properly upon receipt of a scram signal. As part of that test, closing time was verified to be less than 30 seconds.

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Periodic Testing of Level Detection Instrumentation [04.10]

l The inspector verified by procedure review that surveillance procedures existed to periodically test the level detection instrumentation.

Specifically, the following procedures tested the SDV high level alarm, scram, and rod block features by conducting i

channel checks, functional test, and calibrations in accordance with Clinton Power Station Technical Specifications:

CPS No. 9000.01, Revision 24 CPS No. 9030.01C017, Revision 22 CPS No. 9030.01C018, Revision 22 CPS No. 9431.05, Revision 22 CPS No. 9431.22, Revision 22 CPS No. 9436.03, Revision 21 CPS No. 9436.04, Revision 21 CPS No. 9531.22, Revision 21 The procedures included provisions to test the level alarm and trip instrumentation in place and included steps to restore the system configuration, k.

Periodic Testing Operability of the Entire System [04.11]

This criterion required that the operability of the entire system as an integrated whole shall be demonstrated periodically and during each operating cycle as required by the plant technical specifications. The inspector reviewed the Clinton Power Station Technical Specifications and surveillance procedures and found that no such test whs required or performed.

Such a test was apparently not required by any of the recently licensed BWR-6 plants. This is considered an open item pending resolution by NRR (461/87031-02(DRP)).

One open item was identified.

5.

Employee Concerns (99014)

The inspector reviewed concerns expressed by site personnel from time to time throughout the inspection period. Those concerns related to regulated activities were documented by the inspector and submitted to Region III. One concern was transmitted to the regional office during this report period.

No violations or deviations were identified.

6.

Monthly Maintenance Observation (62703)

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Selected portions of the plant maintenance activities on

safety related systems and components were observed or reviewed to i

ascertain that the activities were performed in accordance with approved procedures, regulatory guides, industry codes and standards, and that the performance of the activities conformed to

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the technical specifications.

The inspection included activities associated with preventive or corrective maintenance of mechanical equipment and systems.

The following items were considered during these inspections:

the limiting conditions for operation were met

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while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibration was performed prior to returning the components or systems to service; parts and materials that were used were properly certified; and maintenance of appropriate fire prevention, radiological, and housekeeping conditions.

The inspector observed / reviewed the following work activities:

l Maintenance Work Request No.

Activity C-50616 Repair Activities For Essential Switchgear Heat Removal Refrigerant Compressor IVX06CA On August 1, 1987, the above maintenance activity was observed by the inspector. The inspector noted that the maintenance activity was initiated on July 11, 1987, when the licensee identified a failure of the compressor unit in the Division 1 Essential Switchgear Heat Removal System (VX).

The compressor unit is a part of the safety-related portion of the VX system described in Clinton Power Station FSAR section 9.4.5.2.

This " Engineered Safety Feature" provided the heat removal requirements for the Division 1 Switchgear during abnormal plant operation.

The inspector noted that the licensee had not identified any Limiting Conditions for Operation (LCO) associated with the Division 1 VX compressor being out of service.

The inspector discussed the support function provided by this ESF with the Assistant Plant Manager. The Assistant Plant Manager directed that the maintenance work request be elevated to " Priority 1" work which required 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> per day work effort until job completion.

The maintenance effort was completed and the VX compressor returned to service on August 2, 1987.

Since the safety-related portion of the VX system was clearly defined in the FSAR as an Engineered Safety Feature, the inspector was concerned that the licensee had apparently not considered the

effect the loss of this support system had on systems it was intended to cool under abnormal plant conditions.

Specifically, the i

licensee apparently did not consider extending the LCO of systems identified in the Clinton Technical Specifications that the safety-related portion of VX was designed to support. The

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definition of " Operable-Operability" is contained in Clinton j

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Technical Specification 1.27.

That definition clearly states that all necessary auxiliary equipment required for the " system" to perform its intended function must also be opercble.

The inspector noted that a similar discussion with the licensee was previously documented in Inspection Report No. 50-461/87015, Paragraph

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10.b.

Unresolved Item 87015-01 was tracking the resolution of that i

issue.

Since the items discussed above appeared to be directly

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related to Unresolved Item 87015-01, that item is closed and the resolution of the inspector's concerns discussed above and the inspector's concerns discussed in Inspection Report No. 50-461/87015, Paragraph 10.b. will be considered one Unresolved Item l-(461/87031-03(DRP)).

b.

Illinois Power (IP) letter U-600958, dated June 18, 1987, informed the NRC of the licensee's plan to perform monitored evolutions between Startup Test Conditions 2 and 3 to evaluate operations, maintenance, and radiation protection personnel in the performance of their respective tasks.

NRC personnel witnessed portions of the operations and maintenance evolutions.

The maintenance evolutions observed by the inspector are discussed below.

The licensee performed monitored maintenance evolutions on July 7 and 8, 1987. On July 8,1987, the inspector witnessed the monitored maintenance evolutions associated with MWRC-30183 entailing repair of a regulator for Circulating Water Pump A (1CWO4MA), and MWRC-38797 entailing cleaning of the Circulating Water pump 1A

'i filters in accordance with the preventive maintenance program.

During the course of the inspection, the inspector noted the following:

The sample of maintenance activities monitored by the licensee

was small; few significant activities were available for review during the two day period designated for monitoring maintenance i

activities.

Some of the monitors lacked extensive expertise.

In a few cases, some of the important aspects of the maintenance activity being monitored (such as the job

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supervisor's briefing) were not observed by the monitors.

Licensee management indicated that they were aware of these

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limitations and agreed that the monitored maintenance evolutions did

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not constitute a thorough assessment of the maintenance program; but, at the same time, they felt that they had obtained some valuable insights from the process.

During the July 13, 1987, meeting between IP and NRC management, discussed below in Paragraph 12, IP management stated their intent to perform additional monitoring evolutions for

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maintenance activities in the future, but not prior to' entering J

Startup Test Condition 3.

Since NRC inspections of maintenance

activities following issuance of the full power license have' not identified any significant maintenance concerns, the licensee's

!

'l proposed course of action was considered acceptable.

One unresolved i't.m was identified, j

7.

Surveillance (61726)

An inspection of inservice and testing activities was performed to ascertain that the activities were accomplished in accordance with applicable regulatory guides, industry codes and standards, and in conformance with regulatory requirements.

Items which were considered during the inspection. included whether adequate procedures were used to perform the testing, test

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instrumentation' was calibrated, test results conformed with technical

specifications and procedural requirements, and that tests were performed l

within the required time limits.

The inspector determined that the test results were reviewed by someone other than the personnel involved with the performance of the test, and that any deficiencies identified during

the testing were reviewed and resolved by appropriate management

!

personnel.

The inspector observed / reviewed the following activities.

l Surveillance / Test Procedure No.

Activity CPS No. 9037.81 Fire Detector Channel Functional No violations or deviations were identified.

8.

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 inspector verified the operability of selected emergency systems and verified tracking of LCOs.

Routine tours of the auxiliary, fuel, ' containment, control, diesel generator, and turbine buildings and the screenhouse were conducted to observe plant equipment conditions including 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

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(RP) controls were being properly implemented.

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a.

On May 8, 1987, the 1C Diesel Generator failed to meet Technical Specification surveillance re virement 4.8.1.1.2 when it failed to energize the emergency bus within 12 seconds of the auto start signal.

This failure occurred during the performance of surveillance CPS No.9080.08, " Diesel Generator IC Operability - LOP With ECCS i

Actuation", Revision 21.

Surveillance CPS No. 9080.08 had been l

performed on.May 8, 1987, and had met the procedural acceptance

!

criteria as written. On May 22, 1987, during a results review, the licensee discovered that the acceptance' criteria was not in accordance with the Technical Specification requirement.

CPS No. 9080.08, Revision 21, Paragraph 9.1.2., required that.the IC Diesel Generator reach rated voltage and frequency in 12 seconds; however, the procedure did not require the output breaker to close and energize the emergency bus within 12 seconds.

During the surveillance performed on May 8, 1987, the IC Diesel Generator did not energize the emergency bus until approximately 15 seconds after the auto start signal.

.

The licensee declared the 1C Diesel Generator inoperable on May 22, 1987, and initiated troubleshooting efforts.

Ne apparent cause for the failure was found. On May.23, 1987, a diagnostic run indicated that the system functioned.normally. 'A partial surveillance using CPS No. 9080.08 was successfully completed on May 24,1987,(with the acceptance criteria corrected) and the IC Diesel Generator was declared operable on May 25, 1987.

On May 26, 1987, the licensee discovered that the cause for the original delay in breaker. closing was due to a feature in the.

breaker control circuitry that inserted a 15 second time delay in 1C Diesel Generator output breaker closure when the 1C1 bus feeder breaker handswitch (S15) was in the trip position.

This delay was not included when the feeder breaker handswitch was in the

" pull-to-lock" position.

CPS No. 9080.08 directed the operator to

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trip the breaker but did not specifically direct to place the handswitch in " pull-to-lock." During the diagnostic run on May 23, 1987, and the surveillance run on May 24, 1987, the licensee determined that the breaker was placed in " pull-to-lock" by the control room operator as a personal preference. During the report period, the inspector reviewed the above incident's causes and corrective actions with the licensee. The inspector noted that although the problem with the breaker handswitch position was discovered on May 26,1987,' a Comment Control Form (CPS No.1005.01F002) to implement a procedure change was not prepared until June 5, 1987, and a Procedure Deviation for Revision

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l (CPS No. 1005.07F001) was not submitted until June 26, 1987, after the

i inspector asked the licensee why the procedure had not yet been

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changed.

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The inspector reviewed the licensee's Condition Report (CR)

No. 1-87-06-010 and found the investigation of the causes and

corrective actions on this incident to be satisfactory.

In i

addition, the inspector reviewed the licensee's Special Report

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(U-600995) on the incident and noted that it failed to address the procedural deficiency in the acceptance criteria which allowed the failed surveillance to remain undetected for two weeks.

Other than the above mentioned weaknesses, the licensee's

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investigation and corrective actions appeared to be timely and

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correct.

b.

On June 29, 1987, the licensee identified that the temperature j

measuring devices (Tempilsticks) used to satisfy Technical

Specification surveillance requirement 4.6.7.3(b) had not been procured under the licensee's 10 CFR 50, Appendix B program.

Technical Specification 4.6.7.3(b) required that the hydrogen igniter assemblies be verified to reach a surface temperature of at least 1700 degrees Fahrenheit.

Surveillance Procedure CPS No. 9367.05, " Hydrogen Igniter Temperature Test," Paragraph 8.3.1 directed the use of a "Tempilstick crayon" to verify igniter glow plug temperature achieved at least 1700 degrees Fahrenheit.

Paragraph 7.3 identified the Tempilstick crayons to be used were 1750. degrees Fahrenheit +/- 1%.

)

The licensee initiated Condition Report (CR) 1-87-06-106 to document i

the identified deficiency, perform an investigation, and to provide

corrective action.

The inspector reviewed the disposition to CR 1-87-06-106 on July 2, 1987.

That disposition accepted the qualification of the Tempilstick crayon supplier (Big Three Industries, Tempil Division) performed by Florida Power and Light (FP&L).

Illinois Power Company Quality Assurance Procedure (QAP)

107.03, " Evaluation and Qualification of Suppliers," Revision 3, dated February 9,1987, provided for accepting the supplier qualification performed by FP&L.

The inspector concluded that the licensee took appropriate corrective action in a timely manner.

c.

On July 1, 1987, an individual employed by the on site maintenance contractor, Stone & Webster (S&W), was laid off due to a routine reduction in the S&W work force.

During the course of an exit interview with the S&W Resident Project Manager, the individual provided a 39 page handwritten list of discrepancies that had been identified by the individual over a 3 or 4 month period. The list contained about 500 total deficiencies most of which appeared to be housekeeping deficiencies.

An extensive review was commenced on July 1,1987, that properly j

evaluated, documented, and corrected 17 discrepant conditions. The

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licensee initiated a walkdown of those items that appeared to be more than just housekeeping deficiencies.

The types of deficiencies

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identified included:

unsealed penetrations (3); expansion anchor bolt

holes (2); unsealed field routed conduct penetrations (2); damaged

grout work (4); and other unsealed penetrations (6).

The licensee

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initiated Cordt tion Report (CR) 1-87-07-023 to document the identified deficiencies and to provide for corrective action.

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The inspector noted through discussions with the licensee and discussions with the individual that had prepared the deficiency list that the identification of discrepancies was performed by the individual at the request of supervision.

In March 1987, S&W

craftsmen were directed to identify housekeeping and other

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discrepant items to their management.

The licensee stated that an.

informal review was conducted prior to July 1, 1987; however, with one exception documented on CR 1-87-03-251, all were considered to be housekeeping items that were not required to be addressed in the

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I licensee's corrective action program. The licensee also stated that the individual had only provided 10 of the 39 pages to his

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I supervision prior to his termination.

The licensee did not document

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the reviews performed prior to July 1, 1987.

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10 CFR 50, Appendix B, Criterion XVI, as implemented by Illinois Power l

Company Operational Quality Assurance Manual (0QAM), Chapter 16,

'

" Corrective Action" requires that conditions adverse to plant safety and/or quality are promptly identified and corrected; and that i

significant conditions are evaluated, documented, corrected, reported, and independently reviewed.

Failure of the licensee to promptly evaluate, document, and correct conditions that had been identified between March 1987, and July 1, 1987, by site contractors is a violation (50-461/87031-04(DRP)).

i d.

On July 8, 1987, at about 1:45 p.m. CDT, a bank of control rods was withdrawn one notch beyond the position allowed by procedure.

The mispositioning was discovered about five minutes later and the appropriate corrective actions were taken.

The operators were in the process of raising power as part of a monitored training evolution.

The evolution was being controlled by the control room SRO, R0, and Nuclear Engineer. After a bank of rods was withdrawn to the proper position, there was a delay of about three to four minutes for data taking. During the delay, the operator and observers thought they had selected the next bank to be moved, but when the operator attempted to move them, they received a rod block alarm, and the original bank moved out one notch.

The operator and observers did not notice the rod movement.

After an unsuccessful investigation to determine the cause of the rod block, the block was cleared by

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deselecting the rod bank and deselecting the proper bank. The desired bark was then withdrawn three notches and the original bank was then selected for the next step in the procedure.

At this time the operators noticed the bank was out one notch more than expected and I

took corrective actions in accordance with their off normal j

procedures, j

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A critique was held later the same day to investigate the cause of this incident and determine additional corrective action.

The critique was timely and thorough and the corrective actions were

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appropriate.

Although not a reportable event, this incident received appropriate attention from upper management at the Clinton Power Station.

The incident was a topic of discussion at the management meeting discussed below in Paragraph 12. on July 13, 1987.

e.

On July 9,1987, the licensee identified the need to perform Technical Specification surveillance 4.7.2.b. on Control Room Ventilation System train A (VC-A). Technical Specification 4.7.2.b.

required a demonstration of " Operability" of VC-A by runtcing that

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train in the makeup mode for at least ten hours with the heaters operating. However, at the same time, the licensee was required to maintain operation of at least one VC train in the chlorine mode due to a failed chlorine detector (reference: Technical Specification a

3.3.7.8).

The VC system configuration did not provide for I

simultaneous operation of one VC train in the makeup mode and one VC train in the chlorine mode.

The licensee discussed their intention to place VC-A in the makeup

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mode to satisfy Technical Specification 4.7.2.b. with the inspector

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and the NRR Project Manager, Mr. Byron Siegel. The staff concluded I

that, in this particular case, maintaining the makeup mode operable I

was the preferred mode of operation.

The licensee conducted Surveillance Procedure CPS No. 9070.01 on July 14, 1987, and as

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discussed below in Paragraph 10.c.(a), VC-A was found to be inoperable.

VC-A was restored to an operable status on July 15, 1987.

J f.

On July 20, 1987, the inspector identified locking devices missing l

from nine valves in the scram discharge volume instrumentation portion of the control rod drive system. The inspector immediately brought this discrepancy to the attention of the Staff Assistant Shift Supervisor who initiated corrective actions to check the valve positions and install locks.

All nine valves were verified to have been in their correct position.

Technical Specification 6.8.1 requires that written procedures shall be established, implemented, and maintained covering the activities recommended in Appendix A of Regulatory Guice 1.33, Revision 2, i

February 1978.

Among the procedures established to meet that requirement was CPS No. 3304.01V001, Revision 5, " Control Rod Hydraulic and Control Valve Lineup," which required that valves 1C11-F155A, B, C, and D and IC11-158A, B, C, and D be locked open

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and that valve IC11-F361A be locked closed.

Contrary to the procedural requirements, those valves were discovered to be missing

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i their locking devices. The failure to implement approved procedures is a violation of Technical Specification 6.8.1. (461/87031-05(DRP)).

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g.

During the report period, the; inspector conducted' routine tours of

the containment building outside of the drywell and noted several I

concerns with housekeeping.

High pressure gas cylinders were I

unsecured or poorly secured in some areas, especially around the l

Control Rod Hydraulic Control Units.

These cylinders-had the

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potential to become missiles which could damage safety related equipment. Tools and loose equipment were left unattended in various work areas. Unnecessary tables, chairs, and files were l

inside the containment immediately over the suppression pool. A large amount of anti-contamination clothing, waste bags, and plastic i

was in the containment.

Several other items'of loose debris'were found.

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The inspector was concerned that these items had the potential of l

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either becoming missiles during an accident or falling into the suppression pool where this material could potentially clog the suction strainers for ECCS pumps.

The inspector expressed these

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concerns to the QA Department and the Plant Manager.

Followup inspections were conducted by QA on July 15, 1987, and IP Safety on July ~22, 1987. Both of these inspections confirmed that-

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the conditions noted by the inspector still existed and, as a L

result, corrective actions were initiated.

I The inspector will continue to monitor the progress of the i

corrective actions.

For the portable gas' cylinders that will remain

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in containment, the inspector requested the licensee to~ supply an analysis indicating that portable gas cylinder missiles would not damage safety equipment to the extent that its safety functions would be compromised or provide procedures to protect the cylinders and prevent them from becoming missiles. The analysis of gas cylinder missiles or procedures to control them. is considered an Open Item (461/87031-06).

Two Violations and one Open Item were identified.

9.

Training (41400 & 41701)

The effectiveness of training programs for licensed and nonlicensed personnel were re.iewed by the inspector during the witnessing of'the licensee's performance of routine surveillance,-startup testing, maintenance, and operational activities and during the review of the licensee's response to events which occurred during the month of July 1987.

Personnel appeared to be knowledgeable of the tasks being performed; however, as discussed above in Paragraph 6.a., additional training of the Technical Specification definition of

" Operable / Operability" appeared necessary.

No violations or deviations were identified.

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

a.

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

Followup inspection included one or more of the following:

reviews of operating logs, procedures, condition reports; direct observation of licensee actions; and interviews of licensee personnel.

For each event, the 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 bad 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 c. below.

b.

Discussion During this report period, the licensee identified several technical specification violations that were reportable events as defined in i

10 CFR 50.73.

However, some of those reportable events did not require the licensee to provide immediate notification as defined in 10 CFR 50.72.

The inspector discussed the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> reporting requirements contained in CPS operating license Paragraph 2.G with the licensee and the NRR Project Manager, Mr. B. Siegel.

That 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> reporting requirement specifically excludes violations of the requirements contained in Technical Specifications or Environmental Protection Plan.

In both cases, reportable events that do not require immediate notification as defined in 10 CFR 50.72 require a 30 day LER in accordance with 10 CFR 50.73.

For those events that the licensee determines are reportable under 10 CFR 50.73, but do not require immediate notification under 10 CFR 50.72, the inspector requested and the licensee ag-eed to continue their practice of informing the inspector when a 10 CFR 50.73 reportable event is identified.

c.

Details (1) Technical Specification Violation Due to Missed. surveillance

{~ENSNo.N/A]

At about 6:30 p.m. on June 4, 1987, the licensee identified that a stroke time test required by Technical Specification 4.6.4.1 had not been performed. Maintenance Work Request (MWR)

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C30675 had been initiated on May 16, 1987, to make repairs to

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containment isolation valve IVR001A.. Valve IVR001A is a 36"

'l air operated butterfly valve and is the outboard containment '

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isolation valve in the Containment Ventilation System (VR).

Subsequent to the work performed under MWR-C30675, the licensee failed to identify the required surveillance before entering into operational condition 2.at about 7:40 a.m. on June 4, 1987.

The inspector confirmed that the subject valve (1VR001A)

had remained in its closed position from 7:40 a.m. to 8:00 p.m.

on June 4, when the licensee completed the ACTION statement requirement.

The licensee complied with the ACTION statement of Technical Specification 3.6.4.a.2 by deactivating valve IVR001A in the closed position at about 8:00 p.m. on June 4.

The licensee had first attempted to perform the required surveillance, but the valve would not stroke open due to a failed solenoid.' The -

licensee completed repairs and successfully performed the

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required surveillance to return valve IVR001A to an " Operable" status on July 11, 1987.

.

As discussed below in Paragraph (10), a similar technical

specification violation was identified on July 15, 1987, when

the licensee failed to perform required stroke time testing, following maintenance, on containment isolation valve IVR001B.

The inspector concluded that the measures to prevent recurrence of the June 4 technical specification violation were not initiated within a reasonable time frame'.

Specifically, the event occurred on June 4,1987; however, the licensee did not conduct a critique of the event until June 24, 1987. The results of that critique including corrective actions were not distributed until June 30, 1987.

Technical Specification 4.6.4.1 required that containment isolation valves shown in Table 3.6.4-1 shall be demonstrated operable prior to returning the valve to service after maintenance... by cycling the valve and verifying the

specified isolation time.

Failure of the licensee to perform this surveillance prior to entering mode 2 (Applicable Operating Condition) on June 4, 1987 is a violation (50-461/87031-07a(DRP)).

l (2) Technical Specification Violation - Failure to Satisfy Action i

Statement Requirement Within Allotted Time [ ENS No. N/A]

I At about 10:45 p.m. on June 29, 1987, the licensee placed the HVAC Stack High Range Radioactivity Monitor (AXM) in an inoperable condition to perform required calibrations.

Technical Specification Table 3.3.7.5-1, Item 12, required ACTION 81 to be satisfied for this Limiting Condition of Operation. ACTION 81 of that Technical Specification required i

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restoration of the inoperable channel'within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or initiate preplanned alternate. method of monitoring and submission of a Special. Report within 14 days. As described in IP Letter U-600985, dated July 17, 1987, the' licensee failed to submit the Special Report within the required 14 days after the

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channel had been inoperable for more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

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t In addition, as described'in IP Letter U-600985, when the channel was returned to operation at 11:43 a.m. on July 3, 1987,-the preplanned alternate method of monitoring was taken out of effect. On July 10, 1987, it was discovered that the sample media (filter and cartridge) had not been installed since July 3,1987.

The media was installed and the channel declared operable on July 11, 1987.

Thus, during the period of July 3,1987, to July 11,.1987, the channel was inoperable, but the preplanned alternate method of monitoring was not in effect

<

as required by technical specifications.

This is a licensee identified violation (461/87031-08) which meets the criteria of-10 CFR 2, Appendix C, Paragraph V; consequently, no Notice of Violation will be issued, and this matter is considered closed.

(3). Technical Specification Violation - Local Leak Rate Tests on Five Containment Isolation Valves Performed with Air Medium Instead of Water [ ENS No N/A]

At about 5:30 p.m. on July 1,1987, the licensee identified

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that containment isolation valves 1E12-F436, IE12-F437,

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1E22-F376, ISF-004, and ISF-034 had been local leak rate tested using an air medium instead of the technical specification j

required water medium. The licensee performed calculations.to.

i convert the air leakage rate to a water leak rate to confirm i

that the valves did not exceed allowable water leak rates.

In addition, the licensee successfully performed the technical

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specification required leak rate tests using a water medium on-July 3, 1987.

Failure to perform required local leak rate. tests of the five containment isolation valves ~ identified above with the technical specification specified water medium is a licensee identified violation (461/87031-09) which meets the criteria of 10 CFR 2, Appendix C, Paragraph V; consequently, no Notice of Violation will be issued, and this matter is considered closed.

(4) RWCU Isolation On High Differential Temperature in HX Room

[ ENS No. 09210]

On the evening of July 5,1987, the Reactor Water Cleanup System (RWCU) isolated twice and on the morning of July 6 the.

RWCU received an alarm but did not isolate. The isolations and alarm indicating an isolation were due to a failure in a Riley

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indicator in the main control room for differentia 1' temperature in the west heat exchanger room, Division II..The RWCU was

. removed-from. service, the Riley indicator was replaced,'and.the system returned to service'on July 6, 1987, (5) Technical Specification Violation - Failure to Meet Action i

Statement Requirement in Allotted Time [ ENS No. N/A]

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At about 11:01 a.m. on July'7,1987, the licensee identified that Process Radiation Monitor IPR 042A had failed its channel functional test performed in accordance with Surveillance Procedure CPS No. 9920.72.

1PR042A provides isolation signals for Containment and Reactor Vessel Isolation Control System (CRVICS) by monitoring the Containment Building Continuous Containment Purge Exhaust'(Item 1.1. of Technical Specification

Table 3.3.2-1).

The licensee declared IPR 042A inoperable and attempted to comply with the applicable action statement.

Technical Specification 3.3.2 ACTION statement c. required placement of the inoperable channel (IPR 042A) in the tripped condition within one hour. The licensee did not satisfy the Action Statement within the time allotted by the Action Statement in that.it took 77 minutes to place the inoperable channel in the tripped condition.

This is a licensee identified violation (461/87031-10) which meets the criteria of 10 CFR 2, Appendix C, i

Paragraph V; consequently, no Notice of Violation will be

!

issued, and this matter is considered closed.

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(6) Fish Kill

[ ENS No. 09245] [ ENS No. 09536]

l On July 8, 1987, at about 2:15 p.m. CDT, the licensee identified a significant fish kill in their effluent canal.

Approximately 1000 to 2000 channel catfish, bluegill,' and shad were found dead in a pool area between two drop structures on the effluent of the plant.

Since the fish could not-have.

reached that area by coming up the canal from the lake, it is thought they came through the condenser as fingerlings years ago and grew up in the discharge canal. The fish were probably killed by high effluent temperatures due to recent isolation of a condenser water box for tube plugging.

The Illinois

Department of Conservation and EPA are investigating.

l On August 3, 1987, a similar event occurred. Approximately j

2,000 fish, predominately Lake Crappie, were killed in the same i

area.

These fish were thought to be_ survivors of the first

)

fish kill.

The kill was thought to be caused by the

combination of high ambient temperature and high power level of the plant.

The Illinois Department of Conservation was notified.

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(7) Technical Specification Violation - Failure to Perform Channel f

Check Surveillance of Radiation Monitor [ ENS No. N/A]

q On July 12, 1987, the licensee identified that a shiftly channel check surveillance on Continuous Containment Purge Ventilation Radiation Monitor 1RIXPR001C was not performed during the 0800-1600 shift nor the 1600-2400 shift on July 12, j

1987.

Technical Specification Table 4.3.2.1-1, Item 1.h.1 required a shiftly channel check of 1RIXPR001C.

Following identification of the missed channel checks, the licensee successfully performed a channel check of 1RIXPR001C at about 2:00 a.m. on July 13, 1987.

Failure to perform required shiftly channel checks of 1RIXPR001C is a licensee identified violation (461/87031-11) which meets the criteria of 10 CFR 2, Appendix C, Paragraph V; consequently, no Notice of Violation

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will be issued, and this matter is considered closed.

l (8) Reactor Scram

[ ENS No. 09288]

On July 13, 1987, at about 12:45 a.m. COT, the licensee experienced a reactor scram due to high neutron flux. At the time of event occurrence, the licensee was reducing power from

53% by closing the reactor recirculation flow control valves.

When the "A" flow control valve reached about 21% open, the reactor operator reset the flow control valve logic and the "A" flow control valve unexpectedly opened to about 30%.

The valve motion while opening was rapid and caused an increase in neutron flux.

The automatic reactor trip setpoint was 75% (i.e.,.20%

above the existing test condition power level of 55%). All plant systems responded as expected. The licensee informed the NRC Operations Center of this event via the ENS at about 3:30 a.m.

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CDT on July 13, 1987.

l The licensee identified the root cause for this event was a failed Linear Velocity Transducer (LVT) on the "A" Recirculating Flow Control Valve. The failed LVT was not providing the proper l

feedback to the Flow Control Valve control circuitry. The l

licensee completed repairs of the LVT and returned the plant to

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operation on July 15, 1987.

(9) Technical Specification Violation - Inoperable Control Room

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Ventilation Fan [ ENS No. N/A]

j On July 14, 1987, while performing surveillance procedure CPS No. 9070.01, " Control Room Makeup Air Filter Flow / Heater j

Operability Test," the licensee identified that Control Room i

Ventilation (VC) train A failed to meet its required air flow of 2700 to 3300 cfm.

Licensee investigation revealed that i

personnel performing Maintenance Work Request (MWR) C11278 on i

June 23, 1987, had reversed two power supply leads to the VC-A train fan and that error caused the fan to run backwards. While

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running backwards, the 1950 cfm air flow that was achieved during j

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the July 14 surveillance did not meet the surveillance procedure

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acceptance criteria, nor was it sufficient to energize the VC-A l

train heaters (heaters are interlocked to operate only with an j

air flow greater than 2200 cfm).

i From June 23 to July 15, 1987, the plant was operated in

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Operation Conditions 1, 2, and 3 with VC-A inoperable. Technical

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Specification 3.7.2 Action Statement requires restoration of an I

inoperable Control Room Ventilation System within seven days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Failure of the licensee to satisfy the Action Statement of Technical Specifica-tion 3.7.2 within the time allotted by the Action Statement

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(seven days) is a violation (461/87031-12(DRP)).

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l (10) Technical Specification Violation - Inoperable Containment j

Isolation Valve [ ENS No. N/A]

At about 7:00 p.m. on July 15, 1987, the licensee identified l

that required surveillance testing on containment isolation

valve IVR001B had not been performed.

Valve IVR001B is a

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I normally closed 36" air operated butterfly valve in the Containment Ventilation System (VR).

l On July 10, 1987, maintenance activities were performed on the

control and power circuits for valve IVR0018.

Subsequent to

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those maintenance activities, the licensee declared valve IVR0018 operable without performing Technical Specification surveillance 4.6.4.1.

That technical specification required that vahe IVR0018 be cycled to verify isolation time following maintenance on the control or power circuits. The licensee successfully performed the required surveillance test and declared valve IVR001B operable at about 7:45 p.m. on July 15, 1987. The inspector confirmed that the subject valve (IVR0018)

had remained in its normally closed position between July 10 and July 15, 1987.

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l As discussed above in Paragraph (1), a similar event occurred on June 4, 1987. The inspector concluded that the licensee had not initiated corrective action in a reasonable time following the June 4 event to prevent recurrence.

Technical Specification 4.6.4.1 requires demonstrated operability of containment isolation valves prior to returning the valve to service after maintenance on the valves control or power circuits by cycling the valve and verifying the specified l

1 solation times.

Failure of the licensee to demonstrate l

operability of containment isolation valve IVR001B prior to its I

return to service following maintenance on July 10, 1987, is a I

violation (50-461/87031-07b(DRP)).

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(11)ESFActuation [ ENS No. 09390]

At about 10:00 p.m. on July 22, 1987, the licensee experienced an unexpected automatic start of the Division III Shutdown Cooling Water Pump (SX).. The Division III SX pump supplies cooling water to the Division'III Cmergency Diesel Generator which in turn supplies emergency power to the High Pressure Core Spray. system (Division III ECCS). At the time of' event occurrence, the reactor plant was in operational condition 1 at about 40% reactor power.

Prior to the event, the licensee had taken the High Pressure Core Spray system out of service to

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conduct preplanned maintenance activities.

Following a calibration of the Division III Reactor Vessel Level-2 instrument transmitters, a " Level-2 Seal-In Reset Logic Card" l

was reinserted, which caused a momentary trip signal to start

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the Division III SX pump.

No other Division III ECCS components actuated since the remainder of the system (HPCS pump and Division III EDG) had been properly tagged out of service.

The licensee verified the Division III SX pump was operating properly before restoring the pump to its standby mode at about 11:00 p.m.

on July 22, 1987.

Subsequent to this event occurrence, the licensee determined that the event was not reportable under the rules of 10 CFR 50.72 or 10 CFR 50.73.

The inspector reviewed licensee memorandum Y-205551, dated August 4,1987, which concluded that since the Division III system (HPCS and Div. III EDG) had been properly removed from service, the actuation of the_ single component

(Division III Shutdown Service Water. Pump) during the maintenance activity was not a reportable event. The inspector concluded, based on review of NUREG 1022, supplement 1, question 6.9 and confirming discussions with the NRR Project Manager, that the licensee's decision not to submit an LER in accordance with l

10 CFR 50.73 was reasonable.

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(12) Reactor Scram [ ENS No. 09407]

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At about 6:00 a.m. on July 24, 1987, the licensee experienced a

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l reactor scram following a main turbine trip.. At the time of occurrence the reactor plant was operating at about 60% power

with 550 MWe being supplied from the main turbine generator.

l The cause of the turbine trip was a high vibration signal on the.

No. I main bearing.

About I second before the turbine trip signal, plant computers recorded a " failed high" signal from the No.1 l

bearing..No other increased vibration readings or increasing

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trends were observed prior to the turbine trip. The licensee was

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in the third day of Test Condition 3 Power Ascension testing which included power levels up to 75%.

The reactor scram resulting from the turbine trip was an automatic anticipatory scram signal that is present when operating above 40% power. The licensee notified the NRC Operations Center of this event via the ENS at about 7:30 a.m. on July 24, 1987,

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e The licensee identified the root cause of the bearing vibration sensor failure to be a broken wire in the amphenol connector-at the sensor connection point.

Repairs were completed on the l

vibration sensor connection and the plant returned to operation-on July 26, 1987.

l (13)_ Technical Specification Violation - Failure to Perform Shiftly l

Channel Checks on APRM Neutron Flux High [ ENS No. N/A]

l At about 11:55 a.m. on July 25,.1987, the licensee identified that the channel checks required by Technical Specification i

Table 4.3.1.1-1, Item 2.a. were not being performed on a shiftly bases. The implementing surveillance procedure, CPS No. 9000.010001 directed that the channel check be performed on a daily basis only.

The licensee identified that a typographical error had been made between Revision 20 and Revision 22 of the implementing procedure that changed the frequency from shiftly to daily.

The' licensee revised the procedure and commenced performance of this channel check on a shiftly basis.

Failure to perform the channel checks required by Technical Specification Table 4.3.1.1-1, Item 2.a.,-is a licensee identified violation (461/87031-13) which meets the criteria of 10 CFR 2, Appendix C, Paragraph V; consequently, no i

Notice of Violation will be issued, and this matter is i

considered closed.

(14) ESF Actuation Due to Failed Rad Monitor [ ENS No. 09470]

At about 3:40 a.m. on July 29, 1987, the licensee experienced an unexpected ESF actuation when the' Control Room Ventilation

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system (VC) shifted to the high rad mode.

The cause of the VC l

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l shift was identified to be a failed control room air intake rad i

monitor.

Upon receipt of the " Low Fail" signal the VC system shifted.

In accordance with the requirements of the plant technical specifications, the_ failed detector was placed in the tripped condition.

The licensee initiated a Maintenance Work Request to repair the failed detector. At the time of event-l occurrence, the reactor plant was operating at about 22% power.

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The licensee notified the NRC Operations Center of this event j

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via the ENS at about 7:15 a.m. on July 29, 1987.

For the events discussed above in Paragraph (2), (3), (5), (7),

and (13), the inspector concluded that the licensee _ met tha'

I requirements of'10 CFR 2, Appendix C, Paragraph V in that: -the events

were identified by the licensee; the technical specification violation fit a Severity Level IV or V; the violations have been'or will be reported in accordance with the requirements of;10 CFR 50.73; %

violations were or will be corrected, including measure to prevent recurrence, within a reasonable time frame; and they were not violations that could have reasonably been expected to have been-prevented by the licensee's corrective action to a~ previous violation.

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As discussed in 10 CFR 2, the NRC wants to encourage and support licensee initiative for self-identification and correction of problems; therefore, a Notice o'f Violation for the events discussed

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above in Paragraphs (2), (3), (5), (7), and -(13) will not be issued.

Two violations were identified for which Notices of Violation were issued.

Five violations were identified for which a Notice of Violation was not

'l issued in accordance with 10 CFR 2, Appendix C, Paragraph V.

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11.

Startup Test Witnessing and Observation (72302)

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During the report period, the inspector witnessed the performance of j

Startup Test Procedures (STP)-27-2, " Turbine Trip Within Bypass Capacity"

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and STP-28-2, " Shutdown From Outside The Control Room."

The inspector determined by direct observation that ' licensee operating and test personnel were knowledgeable in their individual roles and J

responsibilities. Adequate communications were established and maintained throughout the tests.

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

Crew requirements were being met as defined in plant procedures, I

and staffing satisfied requirements of technical specifications

regarding licensed 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 l

approved.

Each of the prerequisites had been satisfied.

l Changes or revisions to the test procedures were properly reviewed and approved.

• Data sheet entries were legible and recorded in permanent ink.

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

No violations or deviations were identified.

12.

Management Meeting (30702)

On July 13, 1987, NRC management met with IP management at the Region III Office in Glen Ellyn, Illinois, to discuss the results of the licensee's.

monitored evolutions that were conducted at the. conclusion of Test Condition 2.

In addition, the licensee's Monthly Performance Monitoring i

Management Report and actions taken to enhance the licensee's performance

were discussed.

Key personnel attending this meeting are identified by

(#) in Paragraph 1 of this report.

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As detailed in IP letter U-600958, dated June 18, 1987, the licensee scheduled an 11 day training period between Test Conditions 2 and 3.

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During that 11 day training interval, various plant evolutions were performed by plant operators and-their performance was evaluated against established safety,. operational, and excellence standards. Types of plant evolutions' conducted included:

steady state operation, power changes

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with control rods, power changes with recirc flow, shifting feedwater

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pumps, and start / stopping condensate pumps. At the time of the July 13

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meeting with NRC management, the licensee had completed eight days of their

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training effort.

The remaining three days of training (two of which were steady state operations) were completed prior to commencement of Test Condition 3 on July 22, 1987.

The licensee discussed the results of their training evaluations and the actions taken to improve weaknesses identified.

In addition to the plant evolutions conducted, the licensee also discussed.their evaluations of maintenance and radiation protection activities.that were monitored during the same time frame.

NRC management acknowledged the information presented by the licensee. The licensee's " Formal Report" of the

.i training evolution conducted between Test Conditions 2 and 3 was submitted to Region 'III via IP letter U-600995,. dated ' July 29, 1987.

The Region III review of that report will be documented in'a subsequent report.

The licensee also discussed ~ their LER history including personnel errors; discussed plant equipment that did not perform as planned; discussed their scram history; discussed the status of their' Maintenance Improvement Program; and discussed their maintenance backlog.

NRC management acknowledged the information presented by the licensee.

Region III management discussed the results of NRC overview of startup activities. The NRC augmented the Clinton Resident Inspection staff during l.he six weeks following the licensee's receipt of a full power license on April 17, 1987.

In addition, Region.III, management discussed the results of an oversight inspection conducted the week of June 15, i

1987 (reference Inspection Report No. 50-461/87019).

At the conclusion of the licensee's presentation, Mr. A. Bert Davis, Regional Administrator, summarized the decision reached by Region III management that Region III was in agreement with the licensee's decision to continue with their power ascension' program.

13. 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.

Two open items i

disclosed during the inspection were' discussed in Paragraph 4. and Paragraph 8.g.

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14. Unresolved Items

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Unresolved items are matters about which more information is required in l

l order to ascertain whether they are acceptable items, violations, or i

i deviations. Two unresolved items disclosed during this inspection were J

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discussed in Paragraph 3. and Paragraph 6.

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13.

Exit Meetings (30703)

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

j throughout the inspection and at the conclusion of the inspection on i

August 3, 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 inspector during the inspection.

The licensee did not identify any documents / processes as proprietary.

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l The resident inspector attended exit nieetings held between Region III j

l based inspectors and the licensee as follows:

Inspector Date J. E. Foster July 24, 1987 T. J. Ploski July 24, 1987 l

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