IR 05000454/1985002

Enforcement Conference Repts 50-454/85-02 & 50-455/85-01 on 850429.Major Areas Discussed:Failure to Maintain Operability of Overtemp & Overpower Delta T Channels

ML20129H391
Person / Time
Site:	Byron
Issue date:	05/31/1985
From:	Streeter J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20129H359	List: IR 05000454/1985002 ML20129H355 ML20129H368
References
50-454-85-02, 50-454-85-2, 50-455-85-01, 50-455-85-1, NUDOCS 8506070563
Download: ML20129H391 (23)

Text

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.I U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Report Nos.

50-454/85002(DRP); 50-455/85001(DRP)

Docket Nos.

50-454; 50-455 License Nos.

NPF-37; CPPR-131 l Licensee:

Commonwealth Edison Company Post Office Box 767 Chicago IL 60690 Facility Name:

Byron Station, Units 1 and 2 Inspection At:

Byron Station, Byron, IL Enforcement Conference At:

Region III Office, Glen Ellyn, IL Inspection Conducted: January 1 through March 26, April 6, 9,10 and 12,1985 Enforcement Conference Conducted: April 29, 1985 Inspectors:

J. M. Hinds Jr.

K. A. Connaughton P. G. Brochman R. M. Lerch M. Ring D. Hills

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T. Reidinger D. Williams M. Farber B. Burgess

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L. Hueter C. Gill 5/3l!Bb Approved By:

J. F. Streeter, Technical Assistant-Division of Reactor Safety Date Inspection and Enforcement Conference Summary

' Inspection on January 1 through March 26, April 6, 9, 10 and 12, 1985 and Enforcement Conference on April 29, 1985 (Report Nos. 50-454/85002(ORP);

50-455/85001(DRP)).

Areas Inspected:

Routine,-unannounced safety inspection by resident and regional inspectors of licensee action on previous inspection findings;'SER items; Part 21 reports; startup test witnessing; electrical distribution voltage verification; comparison of as-builts with technical specifications and FSAR/SER; nonroutine events; initial criticality witnessing; LERs; operational safety verification; diesel generator surveillance testing; Regional Administrator's tour; plant tours / housekeeping; meetings between NRC and licensee management personnel were held on January 2, 16 and 30 and February 14 and 27, 1985, to discuss Unit 1 facility status and licensee corrective actions for nonroutine events; BDPS actuation reportability and other activities.

An enforcement conference was conducted on April 29, 1985, related to those issues addressed in Paragraph 8.b.

Criticality on Unit I was achieved at 2323 hours0.0269 days <br />0.645 hours <br />0.00384 weeks <br />8.839015e-4 months <br /> on February 2,1,985, and full power Operating License NPF-37 was issued for Unit 1 on February 14, 1985, authorizing power-levels up to 100 percent of full power.

The inspection consisted of 684 inspector-hours onsite by 12 NRC inspectors including.266 inspector-hours during off-shifts.

Results:

In the areas inspected, four items of noncompliance were identified (failure to verify the acceptability of electrical distribution system bus voltages - Paragraph 6; failure to follow ECCS operating procedures -

Paragraph 8.a; failure to perform a 50.59 evaluation and submit to the NRC for review and approval and associated violation of GDC 2 - Paragraph 8.b; failure to maintain operability of Overtemperature and Overpower delta T channels - Paragraph 8.b).

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DETAILS 1.

Persons Contacted-Commonwealth Edison Company

+*R. Querio, Station Superintendent

+*R. Tuetkin, Startup Coordinator

+*R. Ward, Assistant Superintendent, Administrative & Support Services

+*R. Pleniewicz, Assistant Superintendent, Operating

+*L. Sues, Assistant Superintendent, Maintenance

• M. Lohmann, Project Construction Assistant Superintendent

• V. I. Schlosser, Project Manager

• T. Tulon, Operating Engineer

• T. Higgins Training Supervisor

+*R. Poche, Technical Staff

+*D. St. Clair, Technical Staff Supervisor

+*W. Burkamper, QA Supervisor (Operating)

• S. Barrett, Station Chemist

• G. Stauffer, Station Nuclear Engineer

• S. Dresser, Technical Staff

• P. Anthony, Technical Staff

+*T. Maiman, Manager of Projects

-+P. Boyle, Project Engineering Department

+D. Sible, QA Engineering The inspectors also contacted and interviewed other ifcensee and contractor personnel during the course of this inspection.

• Denotes those present during one or more of the management meetings on January 2, 16, and 30 and February 14, 27, 1985.

+ Denotes those present during the exit interview on February 28, 1985.

The inspector conducted a subsequent exit interview with Mr. R. Querto on April 12, 1985, following the evaluation of additional information.

2.

Licensee Action on Previous Inspection Findings a.

(Closed) Violation (454/84032-02(DRP); 455/84025-02(DRP)): Material false statement concerning corrective actions taken for equipment supplied by Systems Control Corporation.

This item was identified in NRC Inspection Report 454/84032(DRP); 455/84025(DRP) as an unresolved item.

Subsequently, a Notice of Violation and Proposed Imposition of Civil Penalty was issued to the licensee for this item on December 4, 1984.

The licensee's response letter indicated that to avoid further violations of this nature additional training would be conducted.

for personnel involved in preparing responses to NRC items.

This training was to emphasize the individual's responsibility for

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i 4 assuring that information submitted to the NRC was accurate.

The training was also to include a review of circumstances surrounding

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-this time.

The inspector verified by interviews with licensee personnel and

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i a review of training handouts that two training sessions were held on January 15, 1985, for licensee operation and construction personnel.

These sessions covered.those topics enumerated in the licensee's January 4, 1985,' response letter.

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(Closed) Violation (454/84055-01(DRP); 455/84038-01(DRP)):

Failure to account for remote valve position indication inaccuracies in engineered safety features response time measurements.

Corrective

' actions taken by the licensee relative.to this ites were reviewed

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and found acceptable in NRC Inspection Report 454/84070(DRP);

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455/84048(DRP).

This item remained open pending receipt of the

' licensee's formal written response.

The inspector reviewed the

licensee's response letter dated December 13,'1984, and found that

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-it accurately described corrective actions previously reviewed E-and accepted by the inspector.

-c.

(Clesed) Unresolved Item (454/84062-01(DRP)):

FSAR Figure 6.3-2

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f inc6rrectly indicated that valves 1RH610-1 and 1RH611-2 were motur-operated globe valves.

FSAR Amendment 46 was submitted

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on February 2, 1985, and included a revised Figure 6.3-2 which

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'was previously reviewed and found acceptable by the inspector during an inspection' documented in NRC Inspection Report 454/84079(DRP).

d.

(Closed) Unresolved Item (454/84062-02(DRP)): Apparent lack of a well-defined program for determining the appropriate capping

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i requirements for test, vent, and drain connections and for ensuring that these requirements are implemented.

Examples were:

1) P&ID

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M-62 showing pipe from drain valve 1ZZ291V capped but pipe was not

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capped, 2) P&ID M-62 showing pipe from test / vent valve IRH014A capped but pipe was blocked with a blind flange.

.A licensee field inspection conducted on January 28, 1985, revealed that the pipe from valve 1ZZ291V had a pipe cap installed as required by the P&ID, but-that the-pipe from valve IRH014A had a blind flange installed-instead of a pipe' cap required by the P&ID.

Sargent and Lundy (S&L) drawing M-2538C, Sheet 2, Revision A, which was approved on May 8, 1980, indicates a pipe cap as the final closure for the pipe from valve IRH014A.

Engineering Change Notice (ECN)

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1750 which was approved on August 13, 1980, changed the pipe cap

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closure to a blind flange closure to comply with ASME Section III, Paragraph N8 3671.3, and S&L Byron Specification F-2739 which does

,not allow the use of threaded joints on S&L Class A piping.

ECN 1805 n

and Field Change Request 3634 approved on November 17, 1980, revised-

' dimensions and the. location so that valve 1RH014A could be used as a test connection and a vent.

Revision to the P&ID drawings to reflect the numerous changes to test, vent, and drain connections

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resulting from ECN 1750 was accomplished by a. change to the P&ID general notes, Revision AH to P&ID M-535 dated March 1,-_1985,-

ECN 24494 which states:

"67.

Where P& ids specify a Class A threaded. cap for 2" and under connections to Class A piping where no flow restrictor is used, per notes 47, 48, 49, and 50, a new

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welded cap or a blind flange shall be used.

The welded cap or blind flange shall be shown on the'as-built piping isometric."

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The inspector. concluded that the program for revising the physical-installation detail and configuration for safety-related and ASME piping is well defined and implemented through the application of

. approved design changes such as revised drawings, ECNs and FCRs.

e.

(closed) Open Item (454/84066-01):

Perform calibration /linearity checks with greater accuracy for process and radwaste effluent monitors by use of sources of sufficient strengths to perform calibration linearity checks of monitors over required ranges.

-The licensee completed the-calibration /linearity checks of these monitors in late October and early November 1984 and provided copies of the calibration procedures and data to the inspector for review.

No problems were identified during the review.

(Closed) Open Item (454/84066-02): ~ Install heat tracing on sample f..

lines to wide range gas monitor and in containment air. sample panel.

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Completed Nuclear Work Request Nos. 6HT005 and 6HT006 document that the licensee completed the subject installation.

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(Closed) Open Item (454/84066-03):

Complete a commitment-analysis for NUREG-0737 Items II.F.1 (Attachments 1, 2,.and 3) and II.B.3.

The licensee satisfactorily completed this item by:

(1) completing the commitment analysis, and (2) submitting to NRR proposed revisions to Appendix E of the FSAR which clarify or modify several licensee

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commitments to-NUREG-0737.

h.

(Closed) Open Item (454/84070-01(DRP)):

Completion of Auxiliary Building Ventilation system testing to verify compliance with IE Bulletin 80-06.

The inspector reviewed preoperational test results for Preoperational Test 2.84.11, " Auxiliary Building HVAC,"

> Sections 9.30,_9.31, 9.32, and 9.33.

These test sections included

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equipment actuation or supply breaker closure from the appropriate

l engineered safety features actuation system output relay and verification that equipment did not change state (e.g., dampers did not. reposition) upon reset of the actuation signal.

These test results were approved by the licenset on February 13, 1985.

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(Closed) Open Item (454/84077-01(DRP)):

ECCS valve position audible alarms not installed.

FSAR Table 6.3-3 and Section 6.3.2.2 indicated that certain valves in both ECCS trains were provided with visual

and audible alarms which would indicate when the valves were not in their normal. positions. _While visual indication was present and the

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= valve out-of position status was recorded by computer, audible alarms

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were not installed.

The-licensee issued Amendment 46 to the FSAR which deleted the audible alarm commitment for these valves.

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3.-

Byron Safety Evaluation Report (SER) Items

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^(Closed) SER. Item (454/83000-13):

Piping vibration test program.

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pletion of the test program required by Confirmatory Issue (4) contained

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in the-Byron SER was confirmed during inspections documented in NRC Inspection Reports 454/83013(DE), 454/83019(DE), and 454/84048(DRS).

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Closure of.this Confirmatory Issue was documented by the NRC Staff in c

Supplement 6 to the Byron SER.

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4.

10 CFR Part 21 Reports

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(Closed) Part 21 Report (454/83001-PP; 455/83001-PP):

Inter-

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mittent lockup of radiation monitor displays supplied by GA Technologies.

The inspector determined by interviews with ifcensee personnel and review of procurement documents (purchase F

orders) that the licensee had shipped the RM-23 display consoles originally supplied to the Braidwood facility to the vendor for

modifications-required to correct the reported defect.

These units were returned to the licensee for installation in Byron, r

Units 1 and 2.

The modified RM-23 display console for Byron,

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Unit 1, has been preoperationally tested and declared operational

. ithout experiencing the reported problem.

The units originally w

. supplied.to Byron were.to be modified by the vendor and

returned to the Braidwood facility for installation.

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(Closed) Part 21 Report (454/84005-PP):

Failure of Ruskin fire dampers to close under design airflow conditions.

The inspector reviewed the'Ifcensee's evaluation of this matter with respect

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to dampers supplied to Byron.

The licensee identified 21 dampers installed in Unit 1 and plant common systems m tentially affected by the reported failures.

Ten of these dampers had been tested

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under airflow conditions with no failures.

The remaining 11 dampers were successfully tested under no airflow.

The 10 dampers tested under airflow were shown by analysis to bound the service conditions p'

of the remaining 11 in that the remaining 11 would be subject to lower air velocities and were of smaller sizes than the largest of

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the 10 tested under airflow conditions.

Licensee personnel contacted at least five other utilities who also

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utilized Ruskin fire dampers.

Certain of those utilities had

. experienced damper failures attributable, in whole or in part, to

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improper installation involving misalignment of the damper assemblies.

• The licensee earlier became aware of the necessity to maintain p

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proper alignment of the damper assembly in the course of damper installation.

Construction and/or preoperational tests were performed by the licensee to verify that the dampers cycled properly.and were therefore properly aligned.

None of the information obtained by the licensee from contacts with other utilities conflicted with the licensee's evaluation and resolution of the reported deficiency.

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-(Closed) Part:21 Report (454/84007-PP; 455/84007-PP):

Potential

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for overpressurization'of the Component Cooling Water (CCW) system.

The inspector reviewed Westinghouse letter CAW 7949,. dated-September 28, 1984, which documented NSSS vendor: review and n-approval of a design change for the Byron Unit 1 and'2 CCW

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system to resolve the potential overpressurization condition.

Attached to the letter was a copy of Westinghouse Design Change-Notice (DCN) SET-CCE-043 which illustrated.the subject design

. change.. The. design change deleted the surge tank' relief valves,

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.added. loop ' seals to 'the relief lines, and'provided interconnecting piping for supplying. demineralized water.to establish the loop seals.

The inspector verified by drawing review that Piping and Instrumen-

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tation Drawing M-66, Sheet 4, reflected the subject design change.

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The inspector visually verified that installed piping was per the i.

P&ID and the DCN.

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LPart21: Report (454/84001-PP;455/84001-PP):

Environmental qualification of viton elastomer seals. utilized in hydrogen

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-recombiners manufactured by Rockwell International. As documented

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E in NRC Inspection Reports 454/84028; 455/84020, 454/84055, 455/84038 and 454/84079, 455/84053, the licensee was informed of the reported defect, provided with recommendations for seal replacement, and had

issued purchase orders to the replacement seal supplier.

At the time of this inspection the licensee had received and installed all but two of the replacement seals.

Nuclear Work Request (NWR) 6-VQ-025 was written to require replacement of the remaining two seals upon receipt.

The inspectors were provided with documentation of evaluations performed by Sargent and Lundy (the Architect Engineer) which concluded that the viton

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elastomer was qualified for harsher environments than posed by the hydrogen recombiner application and that seal replacement could be

i deferred until the end of the first manufacturer-recommended 5-year

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' seal replacement interval.

The inspectors concluded that the l

licensee had provided adequate assurance of acceptable hydrogen recombiner performance to support Unit ~1 operation.

However, this

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ften will remain open pending receipt and installation of the two i

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remaining replacement seals.

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5.

~ Startup Test Witnessino and Observation

- The-inspectors witnessed performance'of portions of the following

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l-startup test procedures in order to verify that testing was conducted

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in accordance with the operating license and all procedural require-i-

ments, that test results were acceptable, and that the performance of

. licensee personnel conducting the tests demonstrated an understanding

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- of assigned duties and responsibilities:

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2.45.31 Incore Flux Mapping at Low Power

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2.47.30 Isothermal Temperature Ctefficient Measurement 2.52.34-Reactivity Computer Checkout

2.64.30A Bank Worth Measurement at Zero Power

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2.64.33 Boron Endpoint Determination 2.68.30 Reactor Protection Logic 2.69.30 Pressurizer Spray Heaters and Bypass Flow Adjustment No violations or deviations were identified.

6.

Electrical Distribution System Voltage Verification The. inspector inquired as to whether the licensee had completed pre-operational testing necessary to. verify that electrical distribution system voltage levels would remain acceptable for the expected full load and minimum load conditions throughout the anticipated range of-voltage variations of the offsite power source.

A commitment to do such testing prior to fuel load was contained in the Byron FSAR, Table 14.2-11, " Auxiliary Power System (Preoperational Test)."

Specifically, testing was to consist of field measurement of bus voltages under various loading conditions, a correlation of these measurements with the results of a computer based analytical model, and use of the validated analytical model to predict bus voltages over the range of anticipated offsite power-system voltage levels.

The inspector determined by interview with licensee personnel that field measurements of bus voltage were completed in Preoperational Test 2.5.11, " Bus Loading and Independency." The inspector was provided letters dated January 5,1984, and September 6,1984, from the licensee's Station Electrical Engineering Department.

These letters documented the acceptable results of a comparison made between measured and calculated bus voltages for the specific offsite power system voltage levels and loading conditions established during the preoperational test.

The licensee had not utilized the' analytical model or other means to verify acceptable electrical distribution system voltage levels throughout the anticipated range of voltage variations of the offsite power source.

This is a violation of 10 CFR Part 50, Appendix 8, Criterion XI (454/85002-01(DRP)).

Subsequent to identification of this item, the licensee performed the required analyses and completed evaluations of the results on January 26, 1985.

The licensee determined the results to be acceptable.

The inspector reviewed the results and discussed them with licensee personnel to obtain clarification of the bases for assumptions used in the analyses.

Based upon the results.of the analyses and information provided by the licensee during these discussions, the inspector had no j

further concerns regarding the acceptability of the test results.

' Byron SER item 454/83000-15 which was used to track inspection of

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licensee actions concerning this matter was previously closed in

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an inspection documented in NRC Inspection Report 454/84079(DRP)

based upon validation of the analytical model utilized to predict l

electrical distribution system voltages.

It was the inspector's understanding at that time that the requisite licensee analyses had l

l been conducted.

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7.

Comparison of As-3uilt Plant With Technical Specifications and the Byron FSAR/SER A team of region-based and resident inspection personnel performed comparison of the as-built plant with the Technical Specifications and the. Byron FSAR/SER.

A large sample of the provisions of individual specifications in Sections 3/4.5 " Emergency Core Cooling Systems,"

3/4.6, " Containment Systems," 3/4.7.1, " Turbine Cycle," and 3/4.8,

" Electrical Power Systems," were chosen for verification.

The method of verification was to compare the wording of individual specifications to the FSAR/SER descriptions and utilize Piping and Instrumentation drawings (P& ids), Control and Instrumentation Drawings (C& ids) and other supporting drawings, as necessary, to verify consistency.

The technical specification provisions were then verified by physically checking components, instruments, flowpaths, labelings and location to gain assurance that the technical specification provisions were applicable to the Byron as-built plant.

Surveillance records were also utilized in some cases (e.g., where accessibility prevented physical verification).

The following specifications and surveillances were examined:

Specification Surveillance 3/4.5, " Emergency Core Cooling Systems" 3.5.1.a,b,c,d 4.5.1.1.a,b,c 3.5.2.a,b,c,d,e 4.5.1.2 3.5.3.a,b,c,d 4.5.2.a,c,d,e,f,g 4.5.3.1 4.5.3.2 3.5.4.a,b,c,d 4.5.4.a,b,c 3/4.6, " Containment Systems" 4.6.1.1.a,b 3.6.1.3.a 4.6.1.3.c 3.6.1.4 4.6.1.4 3.6.1.5 4.6.1.5 3.6.1.7.a,b 4.6.1.7.1 4.6.1.7.2 3.6.2.1 4.6.2.1.a,b,c.1,c.2,d 3.6.2.2.a,b 4.6.2.2.a,b.1,b.2,c,d.1,d.2 3.6.3 (verified 204 of 235 valves 4.6.3.1 listed in Table 3.6-1)

4.6.3.2.a,b,c 4.6.3.3 3.6.4.1 4.6.4.1 3.6.4.2 4.6.4.2.a,b.1,b.2,b.3 3. 7.1. 5 4.7.1.5

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Specification Surveillance 3/4.7.1, Turbine Cycle" 3.7.1.1 3.7.1.2 4.7.1.2.1 4.7.1.2.2 4.7.1.2.3 3.7.1.3 4.7.1.3.1 3.7.1.5 3/4.8, " Electrical Power Systems" 3.8.1.1.a,b 4.8.1.1.1 4.8.1.1.2 3.8.1.2 3.8.1.3 3.8.2.1 3.8.2.2 3.8.3.1 3.8.3.2 3.8.4.1 3.8.4.2 Thermal overloads verified for de-energized valves and spares only since cubicles could not be opened if the breaker was closed.

Two minor items were-identified - one regarding a wording change to Technical Specification 4.5.4.c to more correctly specify heat tracing on the Refueling Water Storage Tank vent line, and one regarding 5 typographical errors in Table 3.6-1 involving a change from I3 and 15

'to 13 and 15 where 13 and 15 were actually correct.

These items were discussed with the licensee and NRR and were reflected in the final

' Technical Specifications.

No violations or deviations were identified.

8.

Onsite Followup of Nonroutine Events at Operating Reactors a.

Inoperability of Both Intermediate Head Safety Infection (SI)

Trains During execution of Byron Operating Procedure (80P) SI-9, " Raising Accumulator Level With SI Pumps at all RCS Pressures," Revision 6, on January 11, 1985, while-in Mode 3, both trains of intermediate head safety injection were rendered inoperable for approximately 15 minutes due to valve misalignment.

The resident inspector

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interviewed ifcensee personnel and reviewed BOP SI-9, Revisions 6 and_7, operating logs, Deviation Report 06-01-85-022, Deviation Investigation Report dated January 17, 1985, and Licensee Event Report 454/85011.

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Prior to execution of the procedure the SI pumps were in their normal alignment to draw borated water from the Refueling Water Storage Tank (RWST) through a common suction header and individual branch suction lines.

The pump discharges were in their normal alignment to inject through individual lines which were cross-tied to a common RCS cold leg. injection header downstream of

. discharge check and motor-operated discharge isolation valves provided for each pump.

The SI accumulator fill line which is tied to the SI pump discharges between the 1A SI pump discharge check and motor-operated discharge isolation valve was isolated by a normally closed air operated isolation valve.

The procedure, in part, required opening the.SI' accumulator fill line isolation valve and closing the 1A SI pump discharge isolation valve.

These actions provide a flowpath from the.1A SI pump dis-charge to the SI accumulators and isolate the 1A SI pump discharge from the RCS cold leg injection header.

Execution of this procedure while in Modes 1, 2, or 3 utilizes the provisions of the action statement associated with Technical Specification 3/4.5.2, "ECCS Subsystems - Tavg > 350*F," since it renders the 1A SI train inoperable.

During execution of the procedure, RCS temperature and pressure were approximately 450*F and 800 psig.

The operator performing the evolution was apparently concerned with the possibility of RCS overpressurization resulting from SI pump operation and reliance on only one isolation valve (the 1A SI pump discharge isolation valve) to prevent injection of water into the RCS.

Therefore, the operator closed the IB SI pump discharge isolation valve.

The operator erred in the following respects:

(1) closure of the valve was not prescribed by the controlling procedure, and (2) closure of the valve did not provide additional isolation between the 1A SI pump discharge and the RCS.

Closure of the; valve rendered the 18 SI train inoperable.

Approximately 15 minutes after the operator closed the 18 SI pump discharge isolation valve the Station L

Control Room Engineer noticed that both the 1A and IB SI pumps were isolated from the cold leg injection header and immediately instructed the operator to open the IB SI pump discharge isolation valve.

The operator opened the valve restoring the 18 SI train to operable status which was within the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> provisions of Technical Specification 3/4.0.

Closing both the 1A and 18 SI pump discharge isolation valves deviated from Procedure BOP SI-9.

This is a violation of 10 CFR 50, Appendix 8, Criterion V (454/85002-02(DRP)).

Subsequent to this event the' licensee issued a Daily Order stressing

. the importance of procedural adherence. All department heads were rebriefed on the importance of utilizing established administrative controls for processing procedure changes.where deviations from procedures are desired.

Pr innel licensed at the Senior Reactor Operator level reviewed ope..ing procedures involving emergency

- core cooling systems to assure appropriate technical specification requirements were contained or referenced therein.

This review was

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Comments generated from'this review were evaluated and procedures,. including 80P SI-9, were revised where deemed necessary prior to the close of this inspection.

. Inspector followup of thic event is complete.

b.

Westinghouse 7300 Process Protection System NTC (Temperature Channel Test) Cards

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On August 5,-1983, the licensee submitted a 50.55(e) report to

. Region III concerning, in part,' a potential contact bounce problem with certain relays in the-Westinghouse (W) 7300 Process Protection System.

The potential problem was identi7ted during supplemental seismic testing. conducted,by W.

The relays exhibiting the potential problem were those installed on the temperature channel test (NTC)

cards'used in the Overtemperature and 0verpower delta T channels.

-There is a total of sixteen of these cards used at Byron - two (one for Tc and one for Th).in each of the four OTAT channels and the

.four OPAT. channels..The relays on the cards are only used for periodic-testing and are not necessary for normal operation of the channels.

The potential problem with the contact bounce was that-the intermittent signal resulting from bouncing could cause saturation of downstream RTD amplifier (NRA) cards and possibly prevent a channel trip from occurring on demand.

This matter was a subject of IE Information Notice 83-38 which was issued June 13, 1983.

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In a May 2, 1984, letter, the licensee submitted to the NRC a justification for interim operation (JIO) concerning, in part, the seismic qualification of the NTC cards.

This JIO was revised in an

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October 16, 1984, licensee letter which states, in part, "Until a

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permanent resolution is prepared, Field Change Notices have been issued which will provide a method of bypassing these [NTC card]

relays when in normal operation." (W issued Field Change Notice b

(FCN) CAEM-10756, which addresses mo3ffication of the NTC cards for normal operation [i.e., channel-on-line] by removing the relays and.

installing jumper wires in their place.

This interim action was determined by RIII to have been completed as documented in NRC Inspection Report 454/84023 dated June 6, 1984.) NRR reviewed the JIO and concluded that the interim modification was an acceptable E

basis for granting an exemption from General Design Criterion 2 which requires.that components important to safety be designed to withstand-the effects of natural phenomena such as earthquakes.

This conclusion was documented in Section 3.10 of SSER 5 and Paragraph D of_ Operating License NPF-23.

The modified NTC cards were-in place at the time Operating License NPF-23 was. issued on October 31, 1984, and remained in place until January 4, 1985.

At that time all sixteen of the modified NTC cards were removed and replaced with unmodified cards which had been F

installed in Unit 2.

This action was taken for testing purposes in accordance with a prerequisite of startup Nst (SUT) 2.47.33, "Incore

' Thermocouple (Core Exit Thermocouples - CET)," which was added to the procedure via major Test Change Request (TCR) No. 3 approved on

._. _ _ _ _ _ _ _

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h January 4,1985.

A 10 CFR 50.59 safety evaluation was completed in i

accordance with Byron Administrative Procedure 1310-T19, Revision 0, l

prior to the incorporation of the TCR into the procedure.

Since the OPAT and OTAT channels are not required to be operable until Mode 2,

'

substitution of the modified relays with unmodified relays in modes other than Modes 1 and 2 was not contrary to the license provisions.

TCR No. 3 also provided in Step 10.7 for the restoration of the modified cards when SUT 2.47.33 testing was complete.

However, that restoration action was not taken.

A handwritten note by the shift test engineer (STE) on Page 37a of SUT 2.47.33 at Step 10.7 on January 25, 1985, states " NOTE - this page not performed, see AIR 6-85-031.

This AIR tracks proper NTC card replacement." AIR 6-85-031 was initiated on January 25, 1985, for the purpose of track-ing the restoration of the modified relays and indicated a completion date of July 1,.1985.

Subsequently, the completed test package was reviewed and approved by both the onsite (TRB) and offsite (PED)

review groups prior to initial criticality.

During the approach to initial criticality on February 2, 1985, the reactor startup was halted due to a question raised by licensee I&C personnel regarding the lack of seismic qualification data for the installed unmodified NTC cards.

The licensee reviewed the matter and

'

concluded that the status of the seismic qualification of the NTC cards was acceptable and under apprcpriate administrative controls.

Based on that conclusion, the approach to initial criticality was resumed and criticality was achieved at 2323 on February 2, 1985.

Both the licensee and the inspectors agreed that the modified NTC cards were required to be installed during " normal operations";

however, the licensee and the inspectors had different understandings as to what constituted " normal operations." The licensee understood the term to mean operations of the plant following completion of the entire startup test program, whereas the inspectors understood the term to mean any time the plant was operated when the OTAT and OPAT channels were required by the Technical Specifications to provide a safety function (i.e., Modes 1 and 2).

After discussing the different understandings, the licensee acknowledged that its understanding was the least conservative of the two views and the licensee adopted the NRC understanding.

Therefore, on February 5, 1985, the ifcensee removed the unmodified NTC cards and replaced them with modified cards.

During the period that the unmodified cards were installed, the plant was not operated above 1% power and Operating License NPF-23 prohibited operation above 5% power.

The inspector identified the following problems with the NTC card issue:

(1) Approval of AIR 6-85-031 and the SUT 2.47.33 test package, which clearly indicated that the unmodified NTC cards were to remain installed during Modes 1 and 2, demonstrated a h

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lack of understanding of JI0s by both corporate and plant

[

personnel and draws into question the adequacy of the a

licensee's technical review of test results.

g (2) Leaving the unmodified NTC cards installed during Mode 2 opera-

l tion was contrary to the provisions of the JIO which was used as A

a licensing basis for the plant.

The licensee failed to conduct

a 10 CFR 50.59 review of this action which would have revealed r

that leaving all of the unmodified cards installed during

'

Mode 2 constituted an unreviewed safety question in that the h

probability of a malfunction of equipment important to safety J

previously evaluated in the safety analysis report was increased.

This action constituted violation of GDC 2 of Appendix A to

-

10 CFR 50 and 10 CFR 50.59.

(454/85002-03(DRP))

(3) The violation of GDC 2 rendered the OTAT and OPAT channels

!

inoperable in that they were incapable of performing their i

specified functions, if required, during a seismic event;

-

therefore, the violation of GDC 2 resulted in a violation of

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Technical Specification 3.3.1 which requires the OTAT and OPAT

channels be operable during Mode 2 operations (454/85002-04(DRP)).

q

.:i (4) The JIO did not clearly address the use of any unmodified cards

for testing.

A revised JIO was submitted to NRR on March 5, g

1985, and NRR approved the submittal in a March 8, 1985, letter

to the licensee which allowed limited and controlled use of

-

unmodified cards for testing.

y (5) The licensee's approval of the completed test package for SUT

2.47.33 was based, in part, on the provisions of AIR 6-85-031

which controlled the replacement of the NTC cards.

This raised

-

a question regarding the level of review that AIRS receive.

In the NTC card case, the AIR was issued and reviewed with a

test package, but it could have been later revised by test I

engineers without review by the personnel who approved the

test results.

Such use of AIRS may not be appropriate for

!

l corrective actions involving safety-related items.

This is an

-

l unresolved item pending the inspector's review of licensee

actions regarding AIRS issued to control safety-related items

]

(454/85002-05(DRP)).

]i The licensee initiated the following corrective actions related to j

the problems identified:

J Station and corporate personnel were reminded of the requirements k

of the Byron Startuo Manual regarding issuance of TCRs when g

test steps are elie.inated which can be performed.

g Plant personnel who review and approve 50.59 reviews received

-

a JIO listing identifying all JI0s and providing a brief

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description of the subject matter of each JIO.

In addition,

-

personnel were provided with an indoctrination of the JI0s to ensure familiarity with the process of JIO review and approval.

34 i

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A checklist was implemented which included a review of JI0s against TCRs during post test review to identify any conflicts.

• Additional administrative controls were implemented for the Unit 1 Startup Test Program which require a checklist to be attached to a 50.59 safety evaluation to ensure the evaluation considers key issues such as the provisions of the FSAR, Technical Specifications, the license, and JI0s for compatibility to the change being prepared.

• A letter was issued to all Station personnel involved in the 50.59 review process which provided direction on how to perform a 50.59 review.

• Corporate personnel involved in the review and approval of test results were reminded of the provisions of all effective JI0s.

• An audit was conducted by the Station QA organization.

The

.

audit found that the Station procedure (QP 10-54) regarding

'

transfer of material between units had not been followed for the transfer of the unmodified Unit 2 NTC cards to Unit 1.

Additionally, the audit revealed that there was a lack of objec-tive evidence that the cards had been receipt inspected as required by Procedure QP 8-51.

The licensee is pursufr.g resolution of these matters.

There was no apparent technical significance of having the unmodified relays installed during Mode 2 operations at or below 1% power because of (1) the low probability of transient occurring in combination with a seismic event which would have required protective action by the channels during the short time period they were installed, and (2)

backup protective instrumentation which was operable that would have precluded any adverse safety effects.

It was fortuitous that the licensee had not operated at powers up to 100% with the potentially degraded instrumentation condition since such operation could have involved reduced safety margins during some analyzed transients.

9.

Byron Unit 1 Initial Criticality 8yron Unit 1 entered Mode 2 and achieved initial criticality on February 2, 1985.

NRC inspectors provided 24 hour-a-day coverage from January 31, 1985 to February 8, 1985.

The inspectors identified all technical specifications and licensee conditions requirements applicable during the initial approach to criticality and verified conformance with these requirements on a sampling basis.

The inspectors verified that:

startup test procedures were available, in use, and of the proper revision; prerequisities and initial conditions required by test Procedures 2.32.33, " Initial Criticality and Low Power Test Sequence," and 2.52.32, " Initial Criticality," were satisfied prior to execution; nuclear instruments

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were properly aligned and operating; shift crew requirements specified in the technical specifications were met; and reviewed inverse multi-plication plots were being maintained per procedural requirements.

l The inspectors performed daily reviews of operating logs, witnessed-several shift turnovers, witnessed several reactor coolant boron

>

concentration analyses, reviewed implementation of radiological protection and personnel access controls for the auxiliary building

_and Unit 1 containment, and verified that actual critical conditions

'

agreed with predicted conditions within tolerances.

i No violations or deviations were identified.

- 10.

Licensee Event Report (LER) Followup l-(Closed) LER (454/85011):

Inoperability of both intermediate head

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safety injection trains.

Inspector followup of this LER is discussed

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in Paragraph of 8.a of this report.

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11.

Operational Safety Verification

'

The inspector observed control-room operations, reviewed applicable logs and conducted' discussions'with control room operators during the months

~ f January and February.

The inspector verified the operability of o

'

selected emergency systems,, reviewed tagout records, and verified proper return to service of affected components.

Tours of containment, auxiliary building and turbine building were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations and to verify that maintenance requests had been initiated for equipment in need of maintenance.

.

These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under l

technical specifications, 10 CFR, and administrative procedures.

No violations or deviations were identified.

12.

Diesel Generator Surveillance Test History By letter dated November 20, 1984, from R. E. Querio to J. G. Keppler, the licensee reported diesel generator surveillance-test failures in accordance with Byron Unit 1 Operating License NPF-23, Appendix A, Technical Specification 4.8.1.1.3.

The letter summarized surveillance test results obtained since completion of preoperational testing utilizing the criteria for determining valid tests.and failures contained in NRC Regulatory Guide 1.108, Revision 1, August 1977, Regulatory

,

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Position C.2.e.

The 1A diesel generator had experienced 10 failures

.in 34 valid tests. The IB diesel generator had experienced 2. failures in 22 valid tests. When evaluated on a per-nuclear-unit basis, these

'

results yielded a total of 12. failures in 56 valid tests.

The sur-veillance test frequency required to establish the diesel generator

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operability was determined in accordance with Technical Specification 4.8.1.1.2 which adopted the requirements of NRC Regulatory Guide 1.108, Regulatory Position C.2.d.

Both the 1A and 18 diesel generators were

required to be tested at least once per 3 days.

r By letter dated February 8, 1985, from R. E. Quario to J. G. Keppler,

.

the licensee reported that diesel generator surveillance test results had been re-evaluat6d based upon discussions with personnel from the NRC Office of Nuclear Reactor Regulation concerning 9 of the 10 previously

. reported failures of the 1A diesel generator. The 9 failures involved

'

fuel oil leaks which resulted from improperly installed fuel supply

,

lines. Just prior to experiencing the_ failures the fuel supply lines had been replaced.

Agreement was reached between the licensee and NRR that 8 of the 9 failures were discovered in the course of

troubleshooting.

In accordance with Regulatory Guide 1.108, Position C.2.e.(8), tests performed in the course of troubleshooting should not-be considered valid tests. Therefore, only 1 of the 9 failures was detected-during a valid test and needs to be considered in determining surveillance. test frequency.

The results of the licensee's re-evaluation

.

in conjunction with additional valid tests performed since November 20,

_1984, yielded the following results:

the 1A diesel generator experienced

>

2 failures-in_58 valid tests and the 28 diesel generator experienced

!

2 failures in 47 valid tests.

From a nuclear-unit standpoint the results l

,

were a total of 4 failures in 105 valid tests or 3 failures in the last 100 valid tests.

The surveillance test frequency was therefore reduced to onceiper 7 days.

'

On February 14,1985,-Byron Unit 1 full power Operating License NPF-37 was issued.

The license contained revised requirements for. diesel i -

generator surveillance testing.

Specifically, Technical Specification 4.

4.8.1.1.2 was changed to relax the criteria for establishing surveillance test frequencies.

Based upon surveillance test results obtained as of

February 14, 1985, the test frequencies for each diesel generator were reduced to once per 31 days.

The overall reliability of the 1A and 18 diesel generators since fuel load has been 100L

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13.

Regional Administrator's Inspection Tour On February 7, 1985, NRC Region III Administrator, James G. i.eppler

,

l accompanied by J. F. Streeter, Director, Byron Project Division, and the Senior Resident Inspector toured the Byron Station including the

,

technical support center, shift engineer's office, control room,

i auxiliary electrical equipment rooms, Unit 1 containment personnel-hatch area, the fuel storage area, primary system pump rooms, remote shutdown panel, and diesel generator 1A room.

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14.

Plant ~ Tours / Housekeeping

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The inspectors conducted plant tours on January 3, 8, 15, 16, 17, 18, 21,

22, 23, 25, 29 and February 5, 12, 19, 25 and 26, 1985.

The areas of the plant observed during the tours included Unit 1 and 2 containments, fuel handling and storage areas, auxiliary building areas including the

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control room, primary system pump cubicles, and diesel generators A and

>

B rooms. Areas were inspected for work in progress, state of cleanliness,

_overall' housekeeping, state of fire protection equipment and methods-

being employed, and the care and preservation of safety-related com-ponents and equipment.

The inspectors.were accompanied by licensee personnel on portions of the tours for the purpose of identifying areas L

where additional housekeeping efforts should be concentrated to bring

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the overall. cleanliness state of Unitsll and 2 spaces up to par with

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the respective stages of construction.

Inspector concerns were related to the licensee.

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No violations or deviations were identified.

15.

Management Meetings On January 2,16, and 30 and February 14 and 27,1985, Regional and NRC resident inspector office personnel met with licensee management and supervisory personnel denoted in Paragraph 1-of this report. -These

,

working meetings were held to assess overall facility status,- readiness of. Unit ll-for criticality (Mode 2) and operation above 5% of rated thermal power, and other areas such as the source range monitor noise problem, diesel generator testing, process radiation monitors, startup F

testing schedule and delays, and Byron LER actions.

,

16.

Containment Tendon Anchor Head The recent failures of posttensioned containment tendon anchor heads at Farley Unit 2 were discussed with a licensee representative since the Byron Station uses tendons of the same design manufactured by the same vendor (INRYCO)._ The Farley problem was the subject of IE Information Notice No. 85-10 dated February 6, 1985, and Supplement 1 to that IN dated March 8, 1985.

The licensee representative stated that Ceco was-l aware of the Farley problem and was following developments with that

Llicensee and with Sargent & Lundy.

The licensee representative stated

!

that no tendon anchor head failures had occurred at Byron since those in 1979 identified in IN 85-10, and that the normal surveillance program

'

would continue unless future developments in the Farley matter indicated a need for other actions.

(Closed - 454/85001-PP; 455/85001-PP.)

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17. Jam Nuts on Structural Steel Sliding Connections The licensee's torquing criterion for jam nuts on structural steel

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sliding connections inside containment was discussed with licensee representatives since the criterion was different than the criterion-used at LaSalle Station which had been reviewed and found acceptable

by Region III.

(The Byron criterion was snug tight whereas the LaSalle

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criterion was a specified amount of bolt tension.) The licensee stated that both criteria were acceptable because the only reason for the jam nut is to provide additional assurance that the bolt will not become loose since the load nut alone is sufficiently tight to prevent loosening.

The licensee also stated that the AISC which is the governing code for structural steel connections is silent on the use of jam nuts and, therefore, the licensee has the latitude to develop jam nut torquing criteria in its design specifications as was done for Byron.

The licensee's positions on the use of jam nuts on structural steel sliding connections are delineated in a February 17, 1985, letter from Ceco to Region III.

-In order to demonstrate the adequacy of the licensee's snug tight criterion, the licensee selected more than 100 relatively easily accessible jam nuts inside containment and measured the breakaway torque.

The torque values varied from a minimum of 5 ft. 1bs to a maximum of more than 100 ft. lbs.

Those results indicated that the snug tight criterion was not resulting in uniform torquing of the jam nuts; however, the licensee reviewed the results and concluded that they indicated the torquing criterion was always resulting in sufficient torque for the intended purpose of the jam nut.

The inspector had no further questions concerning this matter at this time.

18.

Electrical Cable Pulling In Paragraph 267 of the ASLB's Supplemental Initial Decision of October 16, 1984, the ASLB addressed the acceptability of cables installed in conduits C0A 6158, C0A 6192, and C0A 6193. The ASLB noted a paradox related to the cable pull direction and calculated forces for the cables in conduits C0A 6192 and C0A 6193 and requested that the Staff examine that paradox.

In response to the ASLB's request, the licensee in a October 23, 1984, letter to Region III provided related information.

The information provided by the licensee indicated that (1) the cable manufacturer's calculations showed that the cables pulled from IJB261A to IJ8262A through conduit COA 6193 experienced acceptable pulling tensions and sidewall pressures, and (2) the pull records for cables in conduit C0A 6192 showed that the pull direction was toward rather than away from IJ8261A a.'d, therefore, the cable manufacturer's position was that with that pull direction those cables experienced acceptable pulling tensions

,

l and sidewall pressures.

Region III personnel reviewed the information i

presented by the licensee and concluded that it clarified the basis for the licensee's conclusion that all cables pulled in conduits COA 6158, 6192, and 6193 experienced acceptable pulling tensions and sidewall pressures.

Region III had previously evaluated this matter and came to the same conclusion as documented in NRC Inspection Reports 454/84009, Paragraph 3.d, and 454/84027, Paragraph 2.h.

Region III has no further questions regarding this matter.

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19.

Boron Dilution Prevention System (BDPS) Actuation Reportability The licensee documented-13 occurrences of the initiation of the BDPS resulting from noise spiking of the Source Range Nuclear Instrument Channels in LERs 454/84010, 454/84019, 454/84022 and 454/84031.

The inspectors discussed the reportability of these occurrences with the licensee and determined that although the BDPS operates components in an Engineered Safety Feature (ESF) System, the BDPS System is not classified in the Byron FSAR, Section 7.6,_as an ESF System.

It was therefore concluded, based on similar classifications established in

' Supplement 1 to NUREG-1022, " Licensee Event Report System," the

. classification of the BDPS in the Byron FSAR, and discussion with representatives of the NRC AE00, that. inadvertent initiation of the BDPS from noise spiking of the Source Range Nuclear Instrument Channels is not required to be reported..The inspectors requested the licensee to conduct a review to determine if other systems should be included in this classification and the justification for excluding these systems from LER reportability.

The licensee provided this information and is included in this: report as Attachment 1.

The inspectors agreed with the information in Attachment 1.

20.

Unresolved Items Unresolved items are matters about which more information is required in~ order to ascertain whether they are acceptable items, items of noncompliance, or deviations.

An unresolved item disclosed during the inspection is discussed in Paragraph 8.b.

21.

Exit Interview The inspector met with licensee representatives denoted in Paragraph 1 at the conclusion of the inspection on February 28 and on April 12, 1985.

The inspector summarized the purpose and the scope of the inspection and the 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

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identify any such documents / processes as proprietary.

- 22. ~ Enforcement Conference On' April 29, 1985, an enforcement conference was conducted in the Region.III office between Mr. T. J. Maiman and others of the Commonwealth Edison Company. staff and Mr. A. 8. Davis and others of the Region III staff. The purpose of the enforcement conference was to discuss-(1) the operation of Unit I with unmodified NTC cards, and (2) the adequacy of the technical review of test results.

The NRC views on these matters as discussed in Paragraph 8.b of this report were presented to the licensee.

The licensee presented its views on these matters as summarized -

-below:

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No analyzed' event is solely dependent on the OTAT and ORAT channels

. for a reactor. trip to mitigate the consequences of the event.

t

- Therefore,Lthe reactor. trip system as a whole remained capable of performing its intended. function with the unmodified NTC cards

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- installed during Mode 2 operations because of reactor. trip system

' functional diversity.

• A 50.59' evaluation of leaving the unmodified NTC cards installed during Mode 2 operations was not performed becauseaof the licensee's E

understanding of " normal operations."

The failure to. complete a Test Change Request Form for not completing Step 10.7 of SUT-2.47.33 did not constitute a violation of the Startup Manual because the step'was deferred to July 1, 1985,-

and under the control of an AIR and was not eliminated.

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The NTC card-issue does not draw into question the adequacy of the technical review of. test results.

Furthermore, a licensee review of

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- the NTC card issue along with past adverse NRC findings in the test

' results review area did.not reveal any indications of a developing pattern with inadequate test results-evaluations.

LThe NRC representatives indicated that they would consider the information presented by the licensee representatives when assessing the

.

need for further escalated enforcement action.

Subsequent to the

'

-enforcement conference, Region III concluded that the further escalated-enforcement action would not be pursued based on the lack of safety significance.

However, Region III also concluded that it was fortuitous

'

that NRC action led to the removal of the unmodified NTC cards before the

' plant was operated at full' power when safety margins could have been reduced during some analyzed transients.

Furthermore, Region III c

concluded that even in the absence of a negative pattern in the quality l

of technical-evaluations of test results, licensee personnel need to be

' sensitized to the need for thorough, rigorous and completely documented

. reviews of test results.

y Attachment 1:

Licensee Positions on Certain Reportability Matters

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ATTACHMENT 1 LICENSEE POSITIONS ON CERTAIN REPORTABILITY MATTERS

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A.

BDPS.

l 1.

How would an actuation be reported?

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Contrary to past practice, inadvertent actuations would not.be.

. reported pursuant to 50.73(a)(2)(IV) as an ESF/RP actuation,

since it is described as "other" in the FSAR, regardless that

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it does use SSPS.

If BDPS actuated due to an actual positive reactivity insertion, then it would be reported as a courtesy.

2.

How would a detected failure be reported?-

A failure would be reported under 50.73(a)(2)(VII)(A) or (D),

since this system is described in the FSAR accident analysis as.needed to mitigate the consequences of an accident. -This i

reporting would be dependent on the nature and extent of the

failure.

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8.

VCT Level Lolo Switch to RWST Suction l

1.

How would an actuation be reported?.

"

Charging pump switch over on lolo VCT level is not discussed

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in the FSAR under ESF instrumentation, and would not be reported.

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2.

'How would a detected failure be reported?

>

A failure would be reported under 50.73(a)(2)(VII)(A) or (D).

Since 112D, E receive a confirmatory "SI'! signal to open, a

' failure of;one or more of these valves could prevent mitigating

>

the consequences of-an accident.

If the instrument loop failed, this would be reported under 50.73(a)(2)(V) since a possible loss of suction could prevent these pumps from fulfilling their safety function.

This reporting would be dependent on the~ nature and' extent of the failure.

C.

'Hi Pressure Interlock with RH Suction Valves

1.

How would a actuation by reported?

An actuation would not be reported pursuant to 50.73(a)(2)(V)

since this instrument loop is described as "other" in chapter 7

.of the FSAR.

The only exception would be an inadvertent isolation where 2 RH trains are required to be operable per Tech Specs (i.e., Mode 5 loops not filled, Mode 6 cavity less than 23',

Mode 4 with e RCPs operable).

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2.

How would a failure be reported?

This instrument loop is designed to protect the low pressure piping of the RH system.

A failure of this protection could result in preventing the fulfillment of the safety function of the RH system and as such would be reported pursuant to 50.73(a)(2)(V) (B) or (D).

Again, this reporting would be dependent on the nature and extent of the failure.

D.

0T, OPat Rod ' tops 1.

How would an actuation be reported?

Rod stops are discussed in Chapter 7.7 of'the FSAR, " Control Systems Not Required For Safety," and as such their actuation would not be reported.

2.

How would a detected failure be reported?

A detected failure of a rod stop would not be reported, based on their description in the FSAR, and due to the fact that rod stops are backed up by Rx trips.

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