IR 05000456/1997012

Insp Repts 50-456/97-12 & 50-457/97-12 on 970414-0815. Violations Noted.Major Areas Inspected:Maint & Engineering

ML20211Q865
Person / Time
Site:	Braidwood
Issue date:	10/17/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20211Q839	List: IR 05000456/1997012 ML20211Q832 ML20211Q848
References
50-456-97-12, 50-457-97-12, NUDOCS 9710230033
Download: ML20211Q865 (46)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION Ill

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Docket Nos:

50-456;50-457 l

License Nos:

NPF 72; NPF-77 Report Nos:

50-456/97012;50-457/97012 i

Licensee:

Commonwealth Edison Company

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i Facility:

Braldwood Nuclear Power Station, Units 1 and 2 l

Location:

RR#1, Box 84 s

Braceville,IL 60407

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Inspection Dates:

July 14 through August 15,1097 4-t inspectors:

J. Nelster, Team Leader -

i D. Chyu, Reactor Engineer j

E. Duncan, Reactor Engineer

N. Hilton, Resident Inspector, Byron Station G. O'Dwyer, Reactor Engineer i

a Approved By:

R. G.srdner, Chief d

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Engineering Specialist Branch 2 j '

Division of Reactor Safety i

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9710230033 971017 PDR ADOCK 05000456 O

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EXECUTIVE SUMMARY Braidwood Nuclear Power Station, Units 1 and 2 NRC Inspection Reports 50-456/97012; 50-457/97012

- Th's inspection reviewed and evaluated the effectiveness of the engineering organization in the performance of routine and reactive site activities, including the identification and resolution of technicalissues and problems.

Maintenance e

The team identified two cases where components were preconditioned prior to surveillance testing. In one case, an electrical maintenance procedure inappropriately preconditioned breakers prior to breaker overcurrent protective device testing to meet technical specification requirements. (Section M3.1)

Engineering The modifications and temporary alterations reviewed were dealgned, installed, and

tested with no significant deficiencies. (Sections E1.1 and E1.2)

e The team concluded that the operability evaluations reviewed were acceptable.

However, the team noted that in one case information in an operability evaluation was inaccurate which indicated a lack of attention to-detail by licensee personnel performing and documenting the evaluation. (Section E1.3)

The team identified that licensee personnel failed to assume appropriate flow resistance e

values in the feedwater line break analysis. (Section E1.4)

e Overall, the team concluded that identification of material condition deficiencies and housekeeping items in frequently accesseJ areas Was good. However, the team also concluded that identification of material condition problems in infrequently traveled areas was poor since a significant and obvious Unit 1 refueling water storage tank (RWST)

heater mounting deficiency had not been Identified although the condition had existed since originalInstallation. (Section E2.1)

The team concluded that overall, the problem identification forms (PlFs) and root cause e

evaluations reviewed by the team identified, evaluated, and corrected the problems documented. However, the team concluded that the licensee's response to an abnormally high 2A Si lube oil filter inlet pressure was poor in particular, problem identification was slow, compensatory actions were inadequately documented, the operability evaluation was weak, and the cause determination evaluation (CDE) did not

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address all potential root causes, in addition, two cases were identified in which a root cause Investigation did not address a concern because system engineering personnel did not carefully evaluate the identified pmblem. (Section E2.2)

The team concluded that the surveillances reviewed met all applicable acceptance e

criteria. However, the team also identified a few cases where surveillance data was incomplete or missing which indicated a lack of attention-to-detall during the -

performance and review process. (Section E3.1)

The team identified that the licensee had inadvertently preconditioned breakers prior to

performing technical specification (TS) surveillances and had inappropriately applied vendor guidance to under/oltcge relay acceptance criteria. (Section E3.1).

Overall, the team concluded that lube oil coolers were inspected as committed to in o

Generic Letter 89-13 and that the results of those inspections indicated that the condition of the heat exchangers was good. The team also noted that inspection cleanliness reports were not slways completed in accordance with the iniplementing procedure which Indicated a lack of attention-to-detail. (Section E4.1)

The team reviewed the licensee's commercial grade dedication program and Identified e

that licensee personnelinvolved with the replacement of the 'i A residual heat removal (RHR) pump minimum flow valve circuit breaker failed to exercise adequate attention-to-detail which resulted in the Installation of a non-environmentally qualified breaker in a narsh environment. (Section E7.1)

The team reviewed the status of commitments pertaining to Braldwood's March 28, e

1997 response to the NRC's request for information pursuant to 10 CFR 50.54(f). The team concluded that the licensee had made good progress in addressing these commitments. (Section E7.2)

- The team concluded that although corrective actions in response to concerns regarding e

cross tying of safety injection accumulators were acceptable, operator training regarding the issue would have been beneficial. In addition, the team concluded that the development and review of the Licensee Event Report (LER) lacked an appropriate attention to-detail since stat 3ments in the abstract differed from the LER details.

(Section 8.1)

The team noted strengths regarding licensee programs to identify, resolve and prevent e

problems. These strengths included the implementation of the electronic PIF process, senior martagement participation at the event screening committee meeting, and some self-assessments. Several areas of good performance were also identified and included the trending program, the Operational Experience (OPEX) program, most site quality verification (SQV) audits and independent safety engineering group (ISEG) activities, certain offsite review reports, and the plant onsite review committee (PORC) conduct of onsite reviews.

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However, the team also concluded that documentation of activities was frequently marginal. The shift manager's documentation of operability status was not always clear on PlFs, Supervisory review of PlFs was not always timely. Root cause reports did not always clearly document the development of inappropriate actions and corrective actions. Some department self assessments contained little performance assessment.

(Section E8.4)

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REPORT DETAILS The NRC performed a team inspection of engineering and technical support (E&TS) activities at the Braidwood Nuclear Power Station. During the inspection, the team focused primarily on the auxiliary feedwater, safety injection, containment spray, diesel generator, and auxiliary power systems and reviewed the adequacy of selected modifications, temporary alterations,10 CFR 50.59 safety evaluations, operability evaluations, and root cause investigations associated with these systems. The team also conducted walkdowns and interviews with licensee personnel responsibl6 for those systems and reviewed audits, surveillances, and self assessments related to those systems.

In addition, the team evaluated the effectiveness of the licensee's controls in identifying, resolving and preventing issues that could degrade the quality of plant operations or safety; and reviewed the status of the licensee's commitments in their March 28,1997, response to the NRC's request for information pursuant to 10 CFR 50.54(f).

11. MAINTENAtiGE M3 Maintenance Procedures and Documentation M3.1 Preconditioning of Electrical Eauloment a.

Insoection Scoce The team reviewed the surveillance procedures implemented to satisfy the surveillance requirements of technical specificatien (TS) 4.8.4.1, " Electrical Equipment Protective Devices."

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Observations and Findinos The team reviewed BwHS 4009-035," Containment Penetration Conductor Overcurrent Protective Devices From 480 Volt (V) Switchgear," which the licensee implemented to satisfy the surveillance requirements of technical specification (TS) 4.8.4.1, " Electrical Equipment Protective Devices." During that review, the team identified a step in the procedure which would precondition the 480V switchgear. Specifically, step 5 of the procedure required an operator to manually cycle the breaker associated with the overcurrent protective device being tested to ensure that no excessive binding or friction existed in the breaker operating mechanism. Instructions following step 5 were associated with the overcurrent protective device testing. The team reviewed these steps and concluded that performance of the steps in the order prescribed would result in a preconditioning of the breaker since actions to cycle the breaker could potentially affect overcurrent protective device test results. Following discussions of this concern with licensee personnel, Problem Identification Form (PlF) A1997-03355 was initiated to document the deficiency. Subsequently, the team determined that on February 29, 1996, the licensee had performed BwHS 4009-035 on the 2D reactor containment fan cooler (RCFC) high speed fan breaker and on April 19,1997, the licensee had performed BwHS 4009-035 on the 1D RCFC low speed fan breaker, and as a result,

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preconditioned the breakers prior to the performance of overcurrent protective device testing.

10 CFR 50, Appendix B, Criterion XI," Test Centrol," requires that a test program be established to assure that all testing required to demonstrate that structures, t,ystems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which include provisions for assuring that the testing is performed under suitable environmental conditions. Preconditioning of the 2D RCFC fast speed fan breaker and 1D RCFC low speed fan breaker prior to overcurrent protective device testing was an example where suitable environmental conditions were not established prior to the test and was an example of a violation (50-456/97012-01(DRS)l 50-457/97012-01(DRS)).

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Conclusions The team concluded that the procedure used to satisfy TS 4.8.4.1 surveillance requirements was poor and inappropriately preconditioned breakers prior to breaker overcurrent protective device testing. A violation of 10 CFR 50, Appendix B, Criterion XI was identified.

Ill. Engineering E1 Conduct of Engineerhg E1.1 Mod.ification Review a.

Insoection Scooe The team reviewed the following recently installed modifications:

E20195-2151Sl8811A/B Bonnet Relief Line and Relief Valve

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E20-2 96 234 Installation of Safety injection (SI) Accumulator Access Galleries

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E20196 255 Refualing Water Storage Tank (RWST) Level Transm?ter

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Reference Leg Modification E20 2-96-261 Diesel Generator Fuel Oil Filter / Strainer Replacement

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E20-1-96-256 Temporary Battery Charger Power Connection

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E20-195-211 Unit 1 Solid State Protection System Cabinet Fuses

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E20-2 97 255 Replace Undervoltage Mechanical A0astat Timers

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E20-193-293 Add Cooling Fans to 400V Substation Transformers

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Documents specifically reviewed included the following, where applicable:

10 CFR 50.59 safety evaluation

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Onsite and offsite review documentation

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Operating and emergency operating procedure chtng0s

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Operator training

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Revisions to as built drawings

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Revisions to the Updated Final Safety Analysis Report (UFSAR)

Design change calculations, analyses, and design output documents

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Observations and Findings Overall, the recently completed modifications reviewed by the team were adequately designed, installed, and tested with no significant deficiencies, in one case, however, some errors occurred which are discussed below.

1Sl8811 A and 1Sl83.11B Bonnet Relief Line and Relief Valve Modifical!QD The team reviewed modification E20-195 215 which provided a relief line and relief valve from the bonnet of valves 1Sl8811 A and 1Sl88118 to the downstream piping.

These relief valves were installed to eliminate pressure locking concems identified in NRC Information Notice (IN) 9514," Susceptibility of Containment Sump Recirculation Gate Valves to Pressure Locking," and NRC Generic Letter (GL) 95-07, " Pressure Locking and Thermal Binding of Safety Related Power Operated Gate Valves."

During the review, the team noted that design drawings were not properly updated.

Specifically, critical control room piping and instrumentation drawing (P&lD) M-61, sheet 4, Diagram of Safety injection Unit 1," did not properly identify a flange connection on the relief line. In addition, the P&lD Indicated that the normal relief valvo position was open vice closed. Similarly, P&lD M 136, sheet 4, for the same modification on Unit 2, also indicated that the normal relief valve position was open vice closed.

The team concluded that although other aspects of the modification were acceptable, appropriate attention to-detail had not been exercised during the generation and management review of these P&lD revisions.

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Conclusions Overall, the team concluded that modifications installed or planned by the licensee were acceptable. One deficiency was noted in which appropriate attention-to-detail was not exercised by engineering management and staff personnel during the generation and processing of drawing revisions.

E1.2 Temocrarv Alteration Review a.

Insoection SrQag The team reviewed recently installed temporary alterations associated with the safety injection (SI) system, b.

Observations and Findings The team reviewed the following temporary alterations:

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96-2-017 2Sl8851 Relief Valve Gagged

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95 1-016 Refueling Water Storage Tank Reference leg Check Valve Blind

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Flange Documentation specifically reviewed included the following, where applicable:

10 CFR 50.59 safety evaluation

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Temporary alteration installation procedures

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Temporary alteration installation records

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Temporary alteration functional testing results

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Operator training

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Onsite and offsite review documentation

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Temocrarv Alteration 96 2-017 The team reviewed temporary alteration 96 2-017, which gagged relief valve 2Sl8851 closed.

As discussed in NRC inspection report 50-456/96012(DRP); 50-457/96012(DRP) and Licensee Event Report (LER) 50-456/96009, on July 29,1996, during 2A SI pump surveillance testing, safety injection relief valve 2Sl8851 lifted prematurely. As a result, both trains of SI were rendered inoperable since the relief valve was on a common header for both Si trains. In response, the licensee implemented a temporary alteration to gag closed 2Sl8851 and declared the Si system operable based on the engineering judgement that the two remaining relief valves in the system were sufficient to provide overpressure protection. The licensee planned to replace the relief valve in the Fall 1997 refueling outage.

During this inspection, the team reviewed temporary alteration 96 2-017 which gagged 2Sl8851 closed including the 10 CFR 50.59 evaluation which was completed on July 30, 1996. During that review, the team identified that although American Society of Mechanical Engineers (ASME) code requirements for relief valves (Article NC-7000)

would not be met with 2Sl8851 gagged closed, this issue was not addressed in the licensee's 10 CFR 50.59 evaluation. The team concluded that due to this omission, the safety evaluation failed to adequately provide the basis for the determination that the change did not involve an unreviewed safety question, which was an example of a violation of 10 CFR 50.59 (50-456/97012-02(DRS); 50-457/97012-02(DRS)).

No other deficiencies were identified. Licensee Event Report 50-456/96009 is closed.

Temocrary Alteration 95-1-016 The team reviewed temporary alteration 95-1-016 which removed check valve 1Sl020 and replaced it with a blank flange to prevent potential backflow into tne RWST overflow line and level instrumentation reference leg. No deficiencies were identified.

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c, Conclusions The team concluded that the temporary alterations reviewed by the team were adequately installed and tested, and that personnel were trained when appropriate.

However, one example of an inadequate 10 CFR 50.59 safety evaluation was identified.

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E1.3 Ooerability Evaluation Review a.

Insoection Scone The team reviewed recently completed operability evaluations.

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Observations and Findinas The team reviewed the following operability evaluations:

96-031 Containment Spray Additive Tank Overpressure Protection

97-031 Containment Spray Pump Head Capacity Calculation

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97 011 2CS020B Check Valve Improperly Oriented

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96110 1C RCFC Fan Failed to Start Due to 480V Breaker Degradation

.97-090 Failure to Pe:Torm Activities Related to CS Type Breaker Refurbishment

97-098 Non-Qualified Replacement Breaker Installed in 1E Application

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97 054 Auxillary Feedwater Diesel Fuel Shutoff Valve

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96137 2B Auxiliary Feedwater Pump Failed to Meet UFSAR Requirements

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Overall, the operability evaluations reviewed by the team provided adequate justification for operability of the system evaluated, in one case, however, the team identified v

inaccurate information in an operability evaluation which is discussed below.

Ooerability Evaluation 96-051 Review The team reviewed operability evaluation 96-051 regarding containment spray additive

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tank (CSAT) overpressure protection. Specifically, during an engineering investigation regarding the CS system design, Byron identified that the relief valve for the CSAT contained un intervening stop valve and was therefore not configured in accordance with the applicable American Society of Mechanical Engineers (ASME) code requirements governing relief valves (Article NC-7000). As a result, operability evaluation 96-051 was generated to evaluate whether the configuration was acceptable.

The team reviewed the operability evaluation and noted that statements in the operability evaluation were inaccurate:

Nitrocen.Clanket Verification inaccuIacles To demonstrate periodic system alignment checks, the operability evaluation stated that verification of the CSAT nitrogen blanket was accomplished through the performance of Braidwood Operating Surveillance (BwOS) 6.2.1.a-1. The team reviewed this

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surveillance and determined that the nitrogen valve alignment was not performed by this surveillance as stated in the operability evaluation, but instead was verified every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> during operator rounds. The team also identified that Byron Operating Surveillance 6.2.1.a 1 included a nitrogen blanket verification and that a eimilar statement was contained in the Byron operability evaluation. The team concluded that licensee personnel did not exercise appropria's attention to-detail and verify that information from FJyron correspondence ar ed to Braldwood prior to incorporating it as part of their own operability evaluation.

Alternate Flow Path Inaccuracies in addition, the operability evaluation faiteu to accurately describe the alternate flow path identified for relief protection. This alternate flow path also contained an intervening stop valve which was not identified in the operability evaluatlon.

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Conclusionfi The team concluded that the operability evaluations reviewed were acceptable.

However, although of minor safety consequence, the team noted that information in operability evaluation 96-051 was inaccurate which indicated a lack of attention to-detail by personnel performing and documenting the evaluation.

E1.4 Review of Braidwood Minimum Auxiliarv Feedwater Flow for Feed Line Break Analysis a.

Insoection Scone The team reviewed portions of Pressurized Water Reactor (PWR) Safety Analysis PSA-B-95-13, Revision 0, " Byron /Braldwood Minimum Auxillary Feedwater Flow for Feed Line Break Analysis."

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Observations ed Findings The tearr reviewed PSA-B-96-13, Revision 0," Byron /Braidwood Minimum Auxiliary Feedwater Flow for Feed Line Break Analysis," Revision 0, and noted that flow resistance values used to calculate steam generator flows appeared to be non-conservatively low. The team discussed.his concem with engineering personnel who agreed and generated PIF C1997-00235 to document the error. Subsequently, the licensee revised PSA-B-95-13 and included appropriate flow resistance values. The team reviewed the revised resistance assumptions and concluded that the new assumptions were reasonable. The team also verified that the revised calculations demonstrated that sufficient flow would be supplied to the intact steam generators in the feed line break event.

Licensee personnel stated that no other analyses were affected by the use of incorrect flow resistances in the auxiliary feedwater (AF) flow determination. The licensee had

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instituted an ongoing program of validating calculations that support critical design basis parameters for accuracy and completeness, However, this program had not yet validated calculations for the AF system.

10 CFR 50, Appendix B, Criterion Ill, requires that design control measures shall provide for verifying the adequacy of design by the performance of design reviews. The failure to identify the use of inappropriate flow resistance values in a design calculation was a violation (50-456/97012 03(DRS); 50-457/97012-03(DRS)).

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Conclusions The team concluded that licensee personnel failed to use appropriate flow resistance values in the feedwater line break analysis. A violation of 10 CFR 50, Appendix B, Criterion lli was identified.

E2 Engineering Support of Facilitates and Equipment E2.1 System Walkdown Observations a.

Insoection Scopa The team coriducted a walkdown of the accessible portions of the safety injection (SI),

conainment spray (CS), and aur.iliary feedwater (AF) systems to assess the effer.lveness of system engineering efforts to identify problems, b.

Observations and Findinas The team reviewed " Common Comed System Engineering Handbook," dated September 25,1996, which provided guidance regarding identification of problems during system walkdowns. Items contained in the handbook for observation during system engineer walkdowns included the following:

Any signs of oil, water, air, steam, or chemical leakage

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Proper equipment identification (labeling and tagging)

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Missing bolts or thumbscrews

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Instruments or gauges (out of calibration, inoperable, or bent pointers)

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Lines or pipes (loose, unbracketed, vibrating, or damaged)

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Fasteners and bolts (loose, stripped, or missing)

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The team conducted independent walkdowns of the SI, CS, and AF systems and identified numerous cases where potential problems identified in the system engineering handbook were not identified in the field by an action request tag. These problems included:

Boric Acid Leaks

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The team identified about 20 boric acid leaks following a walkdown of accessible areas of the Sl and CS systems. The leaks identified had not been identified by an action request tag, although the condition warranted identification in accordance with the system engineering handbook. Subsequently, licensee personnel determined action requests had been written and entered into the electronic work control system for some of these leaks, although a tag did not exist in the field.

The team concluded that although numerous rnaterial condition deficiencies had been identified, in some cases system engineering walkdowns did not identify plant equipment deficiencies; and in other cases did not take action to properly tag equipment identified as requiring maintenance, Housekeeping Deficiencies o

The team identified a variety of housekeeping problems which had not been addressed. These included tools staged in areas without appropriate " equipment in use" tags in place; debris such as razor blades, foreign material exclusion caps, screws, and tie-wraps lying in inconspicuous locations in the rooms; and graffiti on walls and safety related piping, in addition, the team identified scaffolding erected arou id the Unit 1 containment spray additive tank without documentation to identify its purpose and without the knowledge of the system engineer. A work request was subsequently written to remove this scaffolding which was no longer in use.

The team concluded that although, in general, the areas inspected were clean and free from debris, system engineering walkdowns did not identify numerous housekeeping concerns which indicated a lack of attention-to-detail.

Loose or Missing Fasteners

The team identified missing Si pump motor junction box screws, and loose or missing U-bolt nuts on piping supports and air-operated valve air supply lines. In addition, the team identified that the Unit 1 RWST heater was freestanding although the original design required that it be bolted to the RWST tunnel floor.

Additional discussion of this item appears below.

On July 22,1997, during a systern we'k+"a, the team identified that the Unit 1 RWST heater was not bolted to t'..o m -, tunnel floor, although bo't holes were present in the heater support feet. The team was concerned that during a seismic event, the heater piping could fall, resulting in draining the RWST.

Further, since the RWST heater recirculation piping was located in a relatively low traffic area, isolation of the tank following receipt of an RWST low-level alarm following a piping failure.ay not be promptly accomplished. The team determined that the Unit 2 RWST heater was properly bolted to the RWST tunnel floor,

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The team informed the licensee of the heater mounting configuration deficiency and, as a result, PlF A1997-03101 was generated to document the condition.

Subsequently, the licensee determined that the heater had not been mounted in accordance with design drawings since initial plant construction. A cart of their immediate corrective actions, the licensee isolated the RWST heating system until the heater could be restored to its design configuration. A work request was generated to properly mount the heater to the tunnel floor. Since the RWST heating system was designed to maintain water temperature at or above 40 degrees fahrenheit and, at the time of the ! spection, ambient temperatures would remain significantly above the RWST minimum temperature of 35 degrees fahrenheit, the licensee concluded that this was not presently a concern. The licensee performed an operability evaluation and concluded that the system was operable. The team reviewed this evaluation and had no concerns. However, a detailed operabilitv evaluation, including calculations to support seismic loading considerations, had not been completed at the end of the inspection.

Failure to identify that the Unit i RWST heater was not properly mounted to the RWST tunnel was an example where the requirements of 10 CFR 50, Appendix B C iterion XVI, " Corrective Actions," were not met and was a violation (50-456/97012-04(DRS)).

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The team also concluded that the failure to identify this problem indicated that a

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significant weakness in the thoroughness of system engineering walkdowns may exist since this rather obvious problem existed in an infrequently accessed area.

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Other Miscellaneous items During a tour of the Unit 1 and Unit 2 CS pump rooms, the team noted that the nonsafety-related instrument air line for 2CS010B had a relatively long span.

The licensee subsequently determined that the instrument air supply line to 2CS010B exceeded the allowable span length in Sargent & Lundy piping specification L-2739. As a result, PlF A1997-03158 and action request 970058973 were initiated to correct this condition.

During a review of 2A SI pump lube oil pressure concerns (Section E2.2) the team inspected gauges used to measure the lube oil filter inlet and outlet pressure and identified that the inlet pressure gauge range was 0-60 psig in 5 psig increments although typical recorded inlet pressure was only 10-15 psig (less than 25 percent of full scale). In addition, the team determined that these gauges were not included in the calibration program and had never been calibrated. Finally, the team noted that the 2B inlet pressure gauge was reading about 5 psig although the system was idle.

During a 2B Si pump ASME surveillance the team noted that 1SX207B and 1SX208B, the essential service water isolation valves to the bearing oil cooler, could not be cycled as required by the surveillance due to mechanical binding.

The team also noted that this condition had been identified by action request

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tags on the valves dated June 30,1995. Subsequently, the licensee determined that these valves had been repaired, the tags had not been removed as required, and the problem had recurred.

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Conclusions Overall, the team concluded that identification of material condition deficiencies and housekeeping items in frequently accessed areas was good, with the notable exceptions discussed above. However, the team also concluded that identification of material condition problems in infrequently traveled areas was poor since a significant and obvious Unit 1 RWST heater mounting deficiency had not been identified although the condition had existed since original RWST heater installation.

E2.2 Problem Identification and Evaluation Review a.

Insoection ScQ22 The team reviewed recent PlFs associated with the Si and CS systems to identify problems associated with the systems which the team had not addressed during other reviews, such as operability evaluations, temporary alterations, and modifications.

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Qbiervations and Findings The team reviewed the following PlFs, including the Cause Determination Evaluation (CDE) and corrective actions:

456 201 95-0455 Depressurize the S1 Piping by Opening 1Sl8964 456-201-97-065102 Potential S1 Pump Runout 456 200-95-08501 A Oil Leak on 1B St Pump 456 20197-CAQ0018201 1C SI Accumulator Pressure Dropping 457 201 97-0008 2A S1 Pump Relief Valve Failure Overall, the PIFs reviewed adequately identified, evaluated, and corrected the problems documented. However, during a review of PlFs 457 20197-0088 and 456 20195-0455, the team noted the problems discussed below, in addition, the team identified a case where a formal root cause investigation was not performed, although warranted, which is also discussed below.

2A S1 Pumo Relief Valve Failure The team identified that a system engineer review of Braidwood Surveillance Procedure (BwVS) 5.2.f.2-1 on February 21,1997, identified that the 2A Si pump lube oil filter inlet pressure was 22 pounds per square inch gauge (psig) although a typical value was about 11 15 psig. As a result, PlF 457 20197-0088 was generated to document the concern.

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During the initial review, the system engineer verified that applicable ASME acceptance criteria were met. In addition, the licensee contacted the pump vendor representative who indicated that on a temporary basis, high lube oil pressure would not adversely impact system performance.

As part of their corrective actions, the licensee planned to monitor pump vibration, lube oil temperatures, and oil leakage during routine quarterly ASME surveillance testing until the relief valve could be replaced during the next refueling outage.

The team reviewed the licensee's identification, investigation, and corrective actions for this event and identified the following:

o Problem Identification Was Slow The Si system engineer identified that the. lube oil filter inlet pressure was abnormal, although no lube oil pressure acceptance criteria existed in the procedure, which was good. However, the team determined that although the system engineer identified the problem on February 21,1997, a PlF to document the issue (which may have affected pump operability) was not generated until after the vendor was contacted on February 25. Braidwood Administrative Procedure (BwAP) 1250 2," Problem identification and Investigation Procedure,"

Revision 5, dated July 2,1996, required that a person identifying a problem that may affect the operability of plant equipment shall immediate y notify the shift engineer. The team concluded that the licensee failed to inform the shift engineer when a problem regarding 2A Si lube oil filter inlet pressure, which may

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have affected the operability of the 2A Si pump, was identified on February 21,

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which was a violation of 10 CFR 50, Appendix B, Criterion V (50-457/97012-05(DRS)).

In addition, the inspector reviewed previous surveillances and determined that the licensee did not identify that a similarly high lube oil filter inlet pressure was recorded on November 26,1996. The team concluded that the licensee's identification of the problem was slow and did not determine how long the condition had existed.

Surveillance Testing Procedures Did Not Encompass Compensatory Actions

As part of their compensatory actions, the licensee planned to monitor pump vibrations, lube oil temperatures, and oil leakage during quarterly surveillance testing to ensure that there were no adverse trends. However, the team reviewed the quarterly surveillance procedure and determined that oil leakage and bearing temperatures were not recorded or trended during the test. As a result, the tesm concluded that actions to monitor these parameters may not be accomplishad. The team discussed these concerns with licensee personnel.

Following this discussion, the licensee revised the surveillance procedure to include the compensatory actions discussed.

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Operability Evaluation Weaknesses Were Noted

During discussion with the pump vendor following identification of the high lube oil filter inlet pressure, the vendor provided the licensee with a letter which stated that on a * temporary basis" the current lube oil pressure would not adversely affect the performance of the pump. However, the licensee did not evaluate the input in a quantitative manner such as pump operating time limits since

" temporary basis" was not defined by the vendor. In addition, the licensee did not discuss the possibility or potential effects of further relief valve degradation in the initial pump operability evaluation.

Cause Determination Evaluation Did not Adequately identify the Root Cause

The licensee's cause determination evaluation (CDE)lentified the root cause of the high lube oil pressure as a failed relief valve. During followup discusslore with licensee personnel, the team determined that a failuro of the relief valve was extremely unlikely and the possibility existed that the relief valve set screw used to establish system pressure may have been inadvertently manipulated during maintenance. However, this possibility was not discussed in the CDE. As a result, other potential root causes for the problem, other than a failure of the relief valve, were not documented for management review.

1S18964 Position Effects on Safety Inlection System Ooerability Problem Identification Form 456-201 95-04550 was written on March 13,1995, and identified that opening 1Sl8964 to depressurize the discharge of the Si pumps in accordance with Braidwood Operating Procedure SI 5, " Raising SI Accumulator Level With Sl Pumps," may render the SI system inoperable. The basis for this statement was that the valve lineup established in the procedure provided a 3/4-inch line from the discharge of the Si pumps to the recycle holdup tanks which bypassed the reactor coolant system. Therefore, in the event of an accident in this configuration, the potential existed that the SI system may not be able to provide adequate flow to mitigate an accident, in response to this concem, the licensee performed CDE 20-195-0455 and concluded that opening 1Sl8964 did not affect the operability of the Si pumps since 1Sl8964 was required to close within 10 seconds of receiving a phase "A" containment isolation signal. As a result, the PlF was closed.

The team reviewed the CDE and determined that the CDE failed to adequately address the issue since the resolution of the concern presupposes that Sl8964 will close when a phase "A" signalis received and d;d not consider single failure criteria. Further, the evaluation did not identify whether or not 1Sl8964 could be considered a " support component" as discussed in Generic Letter 91-18 " Operability," and therefore required to be operable in order for the Si system to be considered operable.

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i The team discussed this issue with licensee personnel who agreed that the CDE did not adequately address the concern. Subsequently, the licensee re-evaluated this issue and determined that flow through 1Sl8964 was acceptable. The team reviewed this evaluation and had no additional concerns regarding this issue.

Root Cause Investigation Not Performed Although Warranted in March 1996, while performing BwHS 4002 91, " Time Delay Relay Surveillance," the licenseo identified that the Division 22,4160V degraded voltage time delay relay could not be calibrated to within established acceptance critoria. As a result, the relay was replaced and the licensee initiated Engineering Request (ER) 9600604 to purchase a different model of Agastat timers. The new timers were scheduled to be installed in Fall 1998.

The team reviewed this issue with licensee personnel who indicated that these relays had a long history of failures. The team determined that prior to 1993, these relays were exercised once every 3 years. Since 1993, the frequency was changed so that each relay would be exercised once overy refueling outage. From reviews of previous surveillance results since 1994, the team determined that the relay failures were unique to Division 22 and ' hat the other three divisions were not affected. # the time of the Division 22 relay failure in March 1996, the licensee had not performed a root cause investigation to ensure that the relay failures were not due to a condition external to the relay itself. Informally, in two documents, the licensee discussed potential root causes for the failure, in the engineering evaluation, the licensee discussed that these timers were not exercised frequently enough to ensure optimum performance. In WR 960031807, the licensee discussed the root cause to be age. However, the corrective actions that the licensee had taken could not be evaluated because the root cause was indeterminate.

c.

Conclusions The team concluded that overall, the PlFs and root cause evaluations reviewed by the team identified, evaluated, and corrected the problems documented. However, the team concluded that the licensee's response to an abnormally high 2A Si lube oil filter inlet pressurs was poor, in particular, problem identification was slow, compensatory actions were inadequately documented, the operability evaluation was weak, and the CDE did not address all potential root causes. In addition, two cases were identified in which a root cause investigation did not address a concern because system engineering personnel did not carefully evaluate the identified problem.

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E3 Engineering Procedures and Documentatie,i E3.1 Surveillance Review a.

Insoection Scone

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The team reviewed recently completed surveillanccs on the Si, CS, AF, and AP systems.

c.

Observations and Findings The team reviewed SI, CS, AF and AP surveillances as well as various operating surveillances performed to meet TS and ASME Section XI requirements. Overall, the g

surveillance results were within required acceptance criteria. However, the following discrepancies were noted:

Required Surveillance Data Was Either Improperly Recorded or Missing, or Was

Not Evaluated Appropriately The team identified instances where required surveillance data was either improperly recorded or missing, or was not evaluated appropriately. Specifically:

The team identified that system engineering personnal who performed

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1BwVS 6.2.2.D-1," Containment Spray Additive Flowrate Verification," on April 2,1997, did not properly identify (by circling) a valve throttled in the procedure.

The team identified that system engineering personnel who performed

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2BwVS 0.5.2.f.2-2 on September 17,1996, recorded an inlet tube oil pressure lower than the outlet pressure. In addition, licensee personrel who reviewed this surveillance did not identify this impractical result and did not identify this as a negative differential pressure. However, this error was of minimal safety significance since lube oil differential pressure was not an acceptance criteria for pump operability.

The team identified that operations personnel who performed 2BwOS

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0.5.SI.4," Safety injection Accumulator Discharge Motor-Operated Valve Stroke and Position Indication Quarterly Surve.llance," on May 9,1996, did not record status light indication for the stroke test of 2Sl8808A.

The team identified that operations personnel who performed 1BwOS

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6.2.E.1-1," Emergency Core Cooling System (ECCS) Subsystems Automatic Valve Actuation Test," on April 9,1997, recorded the time that a section of the surveillance was performed in lieu of the date as required by the procedure.

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In addition, operations and engineering personnel did not identify these errors during their review of the completed surveillances.

Surveillance Procedure Steps Were Not Always Strictly Followed

The team identified several cases where procedural steps were not strictly followed. Specifically:

The team noted that several CS surveillances required that the words

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"lST (Inservice Testing) Coordinator" be placed in the " Review of Results" section of the survelliance data package coversheet. The team identified, however, that although this step was initialed by the system engineer as having been performed, in many instances a " Review of Results" section did not exist and tnat the words were entered into the " Comments" section of the procedure.

Similarly, other CS uurveillances reviewed by the team required that the words "lST Coordinator" be placed in the " Work Description" section of the surveillance data package coversheet. The team identified, however, that although this step was initiated by the system engineer as having been performed, in many instances a " Work Description" section did not exist and the words were entered in the " Review of Results" section of the procedure.

The team concluded that although the safety significance was minimal, system engineers did not strictly adhere to the surveillance procedures.

Subsequently, the team determined that actions had been initiated to ensure consistency between the data package cover sheet and the surveillance procedure.

Braidwood surveillance BwVS 6.2.1.b-2 contained steps which provided

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for an optional measurement of oil bearing temperatures. These steps required that following a minimum 5-minute stabilization period after pump startup, the recorded bearing temperature be obtained by ensuring that 3 successive bearing temperature readings at least 10 minutes apart were within 3 percent of one another. Therefore, a bare minimum of 25 minutes of pump run time was required in order to meet this surveillance procedure requirement.

The team reviewed 1BwVS 6.2.1.b-2 performed on June, 19,1997,and

noted that although a bearing temperature was recorded, the pump run time as recorded in the procedure was less than the minimum 25 minutes. The team discussed this issue with the system engineer who performed the surveillance. The system engineer stated that this requirement may not have been met since the bearing temperature was recorded for information only. The team subsequently determined that a relief from ASME Section XI code requirements had been granted for

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annual bearing temperatura measurements. However, although of minimal safety significance, the team concluded that the system engineer had riot adhered to the procedure.

Equipment Preconditioning Was identified

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The team identified that while performing BwHS 4002-91, " Time Delay Relay Surveillance," the licensee identified that the Division 22 4160 volt degraded voltage time delay relay could not be calibrated to within established acceptance criteria. During the review of this surveillance, the team determined that the licensee implemented a second surveillance, BwVS 3.2.2-4, "Undervoltage Time Response 18-Month Surveillance," to meet TS surveillance requirements.

The team questioned the licensee on the relationship and the difference between q

BwHS 4002-091 and BwVS 3.2.2-4. The licensee subsequently identified that

,__1 from about 1994, BwHS 4002-091 was performed just prior to BwVS 3.2.2-4.

The team determined that the puroose of BwHS 4002-091 was to inspect and operationally check the time delay relays, and was performed by electrical maintenance department (EMD) personnel. Similarly, the purpose of BwVS 3.2.2-4 was to verify operation of the 4160V undervoltage relays to satisfy the requirements set forth in TS Table 4.3 2," Engineered Safety Features Actuation

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System Instrumentation Surveillance Requirements," and was performed by operational analysis department personnel. The team concluded that due to the duplication of the surveillance procedures and the sequence of performing these surveillances, the TS required surveillance was preconditioned and the data obtained in BwVS 3.2.2-4 was not representative of the as-found data. The licensee indicated that tne as-found data for BwVS 3.2.2-4 was obtained in BwHS 4002-091 since 1994. However, this practice of obtaining as-four.d data was not consistent because Division 12 relays were not preconditioned by BwHS 4002-091 in March 1994 and October 1995. Specifically on April 6,1997; April 20,1997; April 8,1996; and March 26,1997; division 11,12,21 and 22 degraded voltage timers were preconditioned by performing BwHS 4002-091,

" Time Delay Relay Surveillance," just prior to performing Braidwood Surveillance Procedure (BwVS) 3.2.2-4, "Undervoltage Time Response 18-Month Surveillance," to meet requirements set forth in Technical Specification Table 4.3-2.

In addition, this practice of crediting as-found data was not known to the licensee untilidentified in this inspection peried. The licensee initiated PIF A1997-03195 to document this deficiency. Failure to ensure that the degraced voltage time delay relays were not preconditioned before the performance of the TS surveillance was an example of a violation of 10 CFR 50, Appendix B, Criterion XI, " Test Control" (50-456/97012-01(DRS); 50-457/97012-C 1(DRS)).

Vendor Guidance Was Incorrectly App!ied in Breaker Testing Procedures

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Vendor Guidance Was incorrectly Applied in Breaker Testing Procedures

The team reviewed BwHS 4009 035," Containment Penetration Conductor Overcurrent Protective Devices From 480 Volt Switchgear," Revision 2, and

BwHS 4002128," Inspection and Maintenance of 480 Volt Type DS Circuit

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Breaker anc Switchgear Cubicles," Revision 15, and noted that 25 milliseconds

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were added to the maximum times specified in the relay setting orders (RSOs)

for testing these Westinghouse DS-type breakers.

The team discussed this issue with licensee personnel who indicated that due to the characteristics of amptectors used to detect fault current and the licensee's methods of testing these breakers, Westinghouse 480V DS-type breakers were unable to meet the instantaneous trip time testing acceptance criteria.

Specifically, the amptector's time-current characteristic curve was based on a

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three-phase bolted fault current. However, the licensee was testing the

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instantaneous trip unit utilizing a single phase primary injection current. The licensee discussed this issue with the vendor who subsequently issued a letter to the licensee stating that the time measured from the application of the single phase primary injection current to the breaker opening should not exceed 75 milliseconds, vice the three-phase bolted fault current value of 50 milliseconds.

The team reviewed this information and concluded that although the addition of 25 milliseconds was appropriate for the instantaneous trip time testing acceptance criteria, the licensee also has incorrectly incorporated this margin to the long and short time de!ay trip acceptance criteria.

The team discussed this finding with licensee personnel who subsequently generated a PIF to identify the issue and revised the applicable procedures. The licensee also determined that the misapplication of the vendor information did not result in any breaker coordination problems.

The team attributed this misapplication of 25 milliseconds to inattention-to-detail.

However, since the procedural revision occurred in 1984, this example was not considered a current performance indicator.

c.

Conclusions The team concluded that the surveillances reviewed met all applicable acceptar,ce criteria. However, the team also identified a few cases where surveillance data was incomplete or missing, or was not evaluated appropriately which indicated a lack of attention-to-detail during the performance and review process.

The team also concluded that the licensee had inadvertently preconditioned breakers prior to performing TS surveillances and had inappropriately applied vendor guidance to undervoltage relay acceptance criteria.

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h EG.2 - Procedure. UFSAR. and Technical Soecification Review a.

Jaspection Scooe The team reviewed various operating procedures, the UFSAR, and Technical Specifications (TSs) governing the SI, CS, AF, DG, and AP systems, b.

Observations and Findings The team identified the following discrepancies following a review of operating procedures, UFSAR, and TSs, governing the Si, CS, AF, DG, and AP systems:

Safety Inlection Pumo Performance Curve Develooment Errors The team identified that the minimum Si pump differential pressure on recirculation reqeired by TS 3.5.2, "ECCS Subsystems - Tavg > 350 F," was below the safety injection pump curve used for ECCS analysis as contained in UFSAR Figure 6.3-5. As a result, the team was concemed that a potential condition existed in which the SI system would meet TS requirements, but not be able to deliver adequate flow to mitigate an accident. The team discussed thb 4ssue with licensee personnel who provided additional calculations which demonstrated adequate pump capacity, and a planned UFSAR pump curve revision. The team reviewed the methodology which was used to develop the revised calculation as well as the revised pump curve. The following deficiencies were noted:

Pump Degradation Allowances Were incorrectly Calculated

The team noted that the calculation which established the allowable degradation for pump performance was incorrectly calculated. However, the team also noted that the calculational error was fortuitously in the conservative direction.

Revised Pump Performance Curves Were Inadequately Derived

The team noted that the x-axis of the revised pump performance curve was plotted incorrectly and resulted in a curve which did not adequately exhibit the actual expected pump performance. The team discussed this issue with -

licensee personnel who stated that this error would be reviewed for potential UFSAR revision re-submittal. The team also noted that since this curve was to be used for information only, the error was of minor significance.

Technical Soecification and Technical Soecification Basis Error The team identified that TS 3.6.3, " Containment Isolation Valves," Table 3.6-1

inaccurately described the function of Sl8964 and Sl8888. Sl8964 was described as performing an accumulator fill function, vice a recycle holdup tank discharge function. Also, Sl8888 was desci, bed as performing a hot leg safety injection function, vice a safety injection accumulator fill function.

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The team identified that TS Basis 3/4.6.1.4," Internal Pressure," stated that the

maximum increase in peak pressure expected to be obtained from a cold leg double-ended break event was 44 A psig. The team reviewed UFSAR Table 6.2-1 regarding this information and determined that the 44.4 psig peak containment

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pressure was obtained from a double-ended pump suction break. The team concluded that the TS basis statement was inaccurate. However, since the error

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was only administrative in nature, it was of only minor significance.

Procedure Error BwVS 6.2.1.d-1, " Containment Spray System Nozzle Flow Test," Revision 1, e

dated February 19,1991, stated that the CS nozzle ficw surveillance would be

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performed every 5 years, although TS 3.6.2," Containment Spray System," was

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revised to decrease the test frequency to once every 10 years. The team

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subsequently determined that BwVS 6.2.1.d-1 had not been revised to reflect this change, c.

Conclusions The team concluded that overall the procedures, TSs, and UFSAR were acceptable.

However, the team identified some minor errors in description of the function of valves in

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TSs, an error in TS basis information, and an error which occurred in the procedure revision process which indicated a lack of attention-to-detail during the performance of engineering activities.

E4 Engineering Staff Knowledge and Performance E4.1 Service Water System Performance Monitoring Program Review a.

Insoection Scone The team reviewed the licensee's implementation of Braidwood Inservice Inspection Procedure (BwVP) 850-15," Service Water System Performance Monitoring Program."

b.

Observations and Findinos The team reviewed BwVP 850-15 which the licensee implemented to control and monitor fouling of service water system piping and components, and heat exchangers as describeci in Generic Letter (GL) 89-13, " Service Water System Problems Affecting Safety-Related Components."

The team reviewed recent results from Un;i 1 and Unit 2 SI pump luce oil cooler heat exchanger inspections and noted that overall the results were extremely favorable, with no appreciable heat exchanger fouling identified. However, the team identified some deficiencies with the implementation of the program as discussed below.

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4 One incomplete Inspection Was identified

Regarding general heat exchanger inspection and cleaning, BwVP 850-15, Section 2.2.4, stated that it was important to inspect the inlet and outlet piping connections on both sides of the fluid-to-fluid heat exchangers.

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Hcwever, during the most recent 1B SI pump lube oil cooler inspection performed on February 3,1997, the team identified that an inspection of the inlet head of the heat exchanger was not documented in the heat exchanger inspection report. The team discussed this finding with the heat exchanger coordinator and determined that the head was not inspected at the heat exchanger coordinator's discretion due to the cleanliness of the tubes. The team

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concluded that although the cleanliness of the tubes was an indicator of overall

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heat exchanger cleanliness, a complete inspection of the heat exchanger as required by BwVP 850-15 would have been prudent to ensure that the heat

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exchanger could perform its intended function. The team discussed this view with licensee personnel who agreed and stated that in the future heat exchanger

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heads would be removed regardless of tube cleanliness. Therefore, due to the previously favorable heat exchanger inspection results, and the licensee's future inspection plans, the team considered the decision to not inspect the heat exchanger head in this one case to be of only minor significance.

Inspection Results Were Not Always Appropriately Documented

The team identified numerous examples where as-found heat exchanger cleanliness information was not entered onto the heat exchanger laspection report form. For example, heat exchanger as-found conditions related to macrofouling, tube erosion and corrosion, and tube obstruction were not always documented as required. In addition, heat exchanger as-left head orientation drawings were not always completed and photographs of the as-left orientation of the heat exchanger was not always labeled as required t y BwVP 850-15.

c.

Conclusions Overall, the team concluded that the Si tube oil coolers were inspected as committed to in Generic Letter 89-13 and that the results of those inspections indicated that the condition of the heat exchangers was good. The team also noted that inspection cleanliness reports were not always completed in accordance with the implementing procedure which indicated a lack of thoroughness and poor attention-to-detail.

E4.2 Surveillance Observations a.

Insoection Scoce The team observed the performance of quarterly ASME surveillances associated with the SI, CS, and AF systems.

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b.

C3servations and Findings.

The team observed the performance of system engineers who emducted quarterly ASME surveillances on the SI, CS, and AF systems. During the surveillance observations, the team noted that all required acceptance criteria were met and the system engineer performing the surveillance was generally knowledgeable of the

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equipment location, function, and expected surveillance results. However, deficiencies wore identified by the team during the performance of 2BwVS 5.2.f.2-2,"ASME Surveillance Requirs;T.ents for the 2B Safety injection Pump," on July 22,1997 and are discussed below.

Equipment Identified in the Surveillance Did Not Always Match Plant Labels

The team identified that plant instrumentation identified in the surveillance did not exactly match plant equipment labels.

Personnel Did Not Promptly Record Completed Surveillance Steps

Following the completion of the surveillance, the system engineer conducting the surveillance identified tha; a step in the surveillance was not initialed as required.

Although the step had been completed, the team concluded that this error indicated a lack of attention-to-detail on the part of the system engineer performing the test.

Data Was improperly Recorded

The team identified that the system engineer conducting the surveillance incorrectly recorded pump run time on the surveillance data sheet. The team discussed this concern with the system engineer, who subsequently recorded the data properly, c.

Conclusions The team concluded that although some deficiencies were identified, overall the ASME surveillances observed by the team was performed in an acceptable manner and the system engineer was knowledgeable of the equipment and expected results.

E6 Engineering Organization and Administration

- E6.1 Thermocraohv Proaram-a.

Insoection Scoce (37551)

The team reviewed the Braidwood ihermography program.

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b.

Observations and Findings The team reviewed the thermography program and noted that the licensee had established the program in January 1997 in which all critical electrical breakers would be examined annually and that an anomaly report, PlF, and WR would be generated to track deficiencies when identified.

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The team reviewed selected PIFs and WRs which resulted from thermography examinations. No deficiencies in the reporting and corrective actions to address identified problems were identified, in addition, coordination between engineering, operations, and maintenance departments appeared good.

c.

Conclusions The team concluded that the thermography program effectively identified and corrected problems.

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E7 Quality Assurance in Engineering Activities E7.1 Commercial Grade Dedication Program Review a.

Insoection Scoce (37551)

The team reviewed the Braidwood commercial grade dedication program.

b.

Observations and Findings The team reviewed the commercial grade dedication program. In particular, the following commercial grade dedication evaluations were reviewed:

Sl767C27 (circuit breaker),

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Sl778D27 (starter motors)

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Sl768F42 (contact blocks)

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Sl779C64 (valve diaphragms)

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c Following that review, the team identified an issue regarding the dedication of a circuit breaker which is discussed below.

The team reviewed the commercial grade dedication requirement for circuit breakers and determined that commercial grade dedication requirements were used only for receipt inspections and failed to address the end-use application. The team questioned a material engineer where circuit breakers procured as Sl767C27 were installed in the plant. As a result, the licensee identified that the 1 A residual heat removal (RHR) pump minimum flow valve circuit breaker was located in a radiologically harsh environment for which the breaker was not qualified. In response, the licensee initiated PlF A-1997-03351 and Operability Evaluation 97-98 to address this concern, and initiated action request 970062009 to replace the existing breaker with a qualified breaker.

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The team reviewed the operability evaluation and determined that a similar model of breaker was tested successfully in an environment more severe than that expected for the breaker in question. Therefore, although the breaker installed was not qualified to be installed in a harsh environment, due to the similarity between the tested and the untested breakers, the team concluded that the non-qualified breaker would not degrade during an accident.

The licensee conducted a root cause investigation and dciermined that the non-qualified breaker was installed on February 18,1997, and that an engineer mistakenly specified an incorrect part number for the breaker to be installed in the 1 A RHR pump minimum flow valve circuit breaker cubicle.

The team reviewed the work package which installed the incorrect breaker and

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determined that although the work package specified that the breaker be EQ certified, the material tracking tag accompanying the breaker would have identified the breaker to be non-EQ certified.

The team concluded that licensee personnelinvolved with the replacement of the 1 A RHR pump minimum flow valve circuit breaker failed to exercise adequate attention-to-detail which resulted in the installation of a non-environmentally qualified breaker in a harsh environment.

10 CFR 50, Appendix B, Criterion XV," Nonconforming Materials, Parts, or Components," requires that measures shall be established to control materials, parts, or components which do not conform to requirements in order to prevent their inadvertent use or installation. The failure to prevent the installation of a non-EQ breaker in a harsh environment as described above was an example where this requirement was not met and was a violation (50-456/97012-06(DRS)).

c.

Conclusions The team concluded that personnel involved with the replacement of the 1 A RHR pump minimum flow valve circuit breaker failed to exercise adequate attention-to-detail which resulted in the installation of a non-EQ breaker in a harsh environment.

E7.2 10 CFR 50.54ff) Letter Commitment Review a.

Insoettion Scoce The team reviewed the status of commitments pertaining to Braidwood's March 28, 1997 response to the NRC's request for information pursuant to 10 CFR 50.54(f). The following commitments related to enginecring and the corrective action program were reviewed by the team. The commitment numbers correspond to those used by the licensee in their March 28,1997 response.

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b.

Qbservations and Findings b.1 Commitment 19: "For Byron and Braidwood, specific tools (topical roadmaps) will be developed to assist engineers in obtaining needed design basis information."

The team verified that the specific tools had been developed and implemented by May 12,1997. The developed tools appeared to be acceptable for engineering staff

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support in obtaining and processing design basis documentation, b.2 Commitment 29: " Project controls are being developed for all site enginee,-ing groups.

Common safety, cost and production performance indicators have been developed and goals are being establishea."

The team verified through procedure reviews and performance indicator reviews that the licensee was meeting established goals.

b.3 Commitment 31: "The engineering backlogs are being defined, characterized and a plan established to reduce backlogs."

The team reviewed the engineering backlog and determined that the licenseu's backlog reduction plan was reducing outstanding engineering items, b.4 Commitment 55: "In order to ensure that corrective actions and responses to lessons leamed are consistently and vigorously implemented throughout NOD, a new corrective action program has been developed by representatives of all six nuclear sites and the NOD central office."

The team verified that the licences had implemented procedure NSWP-A-15,

" Integrated Reporting Program." The procedure contained appropriate steps that should ensure corrective actions were completed in a timely manner.

b.5 Commitment 56: "The new process includes several improvements over the current program, it clearly delineates and standardizes the threshold for problem identification through Problem Identification Form (PIF) initiation, and establishes common PIF screening criteria that provide greater abi!ity to analyze PlF data."

The team determined that proceoure N3WP-A-15 included these improvements.

b.6 Commitment 57: "The new corrective action p'ocess will include human error reduction methodology, including standardized cod:.19, problem identification, trend analysis, and root cause analysis techniques."

The team determined that the implementation of procedures NSWP-A-15, NSWP-A-10,

" Station Performance Trending / Monitoring," and NSWP-A-13, " Root Cause Investigation," fully satisfied this commitment.

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b.7 Commitment 59: " Groups of these trained individuals (root cause analysts) will be stationed at each of the nuclear sites and in the NOD central office."

The team verified that root cause analysts were stationed at Braidwood.

b.8 Commitment 60: * Personnel will be trained or. the new corrective action process and ll human error reduction techniques."

Procedure NSWP-A-15, Exhibit L, " Integrated Reporting Progran; Training Matrix,"

identified the training requirements for the corrective action and human error techniques.

The team verified that the training matrix had been implemented and that personnel performing root cause analyses had been trained, b.9 Commitment 61: "The remaining sites have developed plans to implement this process

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(corrective action program) during 1997."

The team verified that the revised corrective action program had been implemented at

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Braidwood.

b.10 Commitment 63: " Initial performance indicators have been selected for each stage r f the corrective action process and baseline data has been taken. The information will be taken monthly and used to evaluate the effectiveness of corrective action process improvements as well as participation of each site in the process."

The team reviewed the monthly corrective action program effectiveness data evaluations and determined that the licensee was meeting this commitment, b.11 Commitment 64: " Pen'ormance indicators have also been developed to monitor the timeliness of implementation, quality of the corrective actions, and the number of significant events which are repeated. These indicators are being tested at Byron. Site and NOD central management will take appropriate actions based upon performance and results."

The team reviewed recent corrective action performance indicator data for 16 indicators and determined that the licensee was meeting this commitment.

b.12 Commitment 88: "Each site also has a group that evaluates the severity of events, and determines whether a root cause analysis is warranted. Processes are being implemented for evaluation of the effectiveness of corrective action."

The team verified that procedure NSWP-A-16," Effectiveness Reviews," had been implemented. In addition, an Event Screening Committee has been established to oversee this program. The team determined that the licensee had satisfied this commitment.

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b.13 Commitment 89: " Monitoring of performance indicators, corrective action records, and industry experience, and review of site self assessments will also be conducted by SQV."

The team reviewed periodic Site Quality Assessment (SOA) reports and determined that SQV was monitoring performance indicators, corrective action records, industry

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experience and Braidwood self-assessments. The licensee used procedure NO-19,

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" Integrated Analysis Process," to conduct these reviews. The team determined that the assessment reports were satisfactorily performed and fulfilled this commitment, b.14 Commitment 91: "The SRBs evaluate station safety performance, corrective actions, and improvement plans. The SRB chairman will also provide input to the NOC of the Board. The site gains outside perspective and critical review of performance from this body."

The team verified that the Braldwood SRB had been established and that their activities were being conducted in accordance with the Safety Review Board Charter, Revision 1, dated July 25,1997, and implemented on August 10,1997. The team determined that the chartor had been satisfactorily implemented and that the licensee met this commitment.

b.15 Commitment 232: "The Corrective Action Plan incorporated the following salient features. Senior management sponsorship of events requiring root cause investigations with the investigation reports reviewed and approved by the PORC committee; clear expectations and responsibilities for root cause investigations; completion dates for all Level 111 and above corrective actions; station manager review of overdue corrective actions, and station manager approvi ' required for due date extensions; and senior management participation in the Event Screening meeting."

The team raviewed procedures NSWP-A-12, " Root Cause Roport," NSWP-A-13, NSWP-A-15 and NSWP-A-16, and recent PORC meeting notes. The team determined that the licensee was following station procedures and that station management were involved with the root cause investigations.

b.16 Commitment 234: "With respect to improving CAP effectiveness, strong senior management support has been provided to improve the problem classification, investigation thoroughness, and appropriateness of the corrective actions.

Effectiveness reviews for these corrective actions are routinely performed. Line management ownership of the issues is ensured, and the daily screening meeting provides senior management the forum to review the problems reported on a daily basis. This meeting also allows the proper priority to be assigned for problem resolution."

The team determined that the licensee was following station procedures NSWP-A-12, NSWP-A-13, NSWP-A-15 and NSWP-A-16, and that station management were involved with the CAP process.

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S.17 Commitment 287: "A standardized corporate corrective action program based on a review of industry programs is being implemented throughout NOD."

The team determined that the new corrective action program included specific performance measures to gauge program effectiveness. A corporate corrective action group was being established to ensure appropriate site response to industry events as well as to other Comed site events in addition, the team reviewed procedures NOD-OA.39, " Performance Indicators for Nuclear Operations Division," NO-19, " Integrated Analysis Process and Routine Reporting," and NSWP-A-06," Operating Experience (OPEX)," and interviewed cognizant licensee s;aff. The team determined that appropriate procedures were in-place to ensure appropriate event evaluations would be performed at each site, b.18 Commitment 3Q.1: "An NOD-wide formal program for evaluating, sharing, and assassing the effectiveness of responses to lessons learned at both Comed and other nuclear stations is being implemented to assure lessens learned are being shared and responded to throughout NOD."

The team determined that procedure NSWP-A-06 satisfactorily implemented this commitment.

b.19 _ Commitment 304: " Standardized perfo:mance measures are being implemented to gauge processes and effectiveness of correcilve actions."

The team determined that procedures NOD-OA.39, and NSWP-A-16 satisfactorily implemented this commitment, b.20 Commitment 327: "A revised corrective action program is bc -

implemented at the sites and throughout the division which ensures a more com. 2pproach to identification, intemal communication, and solutions to problems that are identified within the division. The new program includes a human error reduction methodology that utilizes problem identification, coding, trend analyses, and root cause analysis techniques."

The team reviewed Nuclear Operations Division and Nuclear Station Work procedures, the common binning process for deficiencies and selected root cause investigation reports, and determined that the licensee had satisfactorily implemented this commitment.

c.

Conclusions The team concluded that the licensee had made good progress in addressing 10 CFR 50.54(f) commitments. No deficiencies were identified.

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E8 Miscellaneous Engineering issues

- E8.1 (Closed) Licensee Event Reoort (LER) 50-456/96005: Operation of Safety injection Accumulators Outside Design Basis, a.

Insoection_ Scope The team reviewed LER 50-456/96005," Operation of Safety injection Accumulators Outside Design Basis."

b.

Observations and Findinos On March 18,1996, Braldwood Station received notification that another licensee had exceeded the bounds of their safety analysis by cross-tying several Si accumulators using the common fill header. On April 23,1996, Braidwood determined that the plant licensing basis did not consider the effects of having more than two accumulators cross-i tied during a design basis accident. Subsequently, the licensee determined that although records documenting such actions could not be identified, greater than two accumulators may have been cross-tied in the past. As a result, a 13 CFR 50.72 notification was made.

Comed's Nuclear Fuel Services (NFS) department performed an evaluatbn of the safety significance of the issue and concluded that it was likely that the licensing basis limits would not be exceeded in a large break loss-of-coolant-accident with two accumulators cross-tied. In addition, the licensee determined that having two accumulators cross-tied for less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> was no more limiting than having one accumulator inoperable for up to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> as allowed by TS 3.5.1, " Accumulators."

However, NFS also concluded that in the event that all four accumulators were cross-tied, peak cladding temperature would exceed limits established in 10 CFR 50.46,

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" Acceptance Criteria for Emergency Core Cooling Systems for Light-Water Nuclear Power Reactors."

The licensee conducted a root cause investigation and determined that an inadequate review of the design basis during the generation of original procedures and revisions did not identify concems regarding accumulator cross-tie operation. In addition, procedures for adjusting water levels and nitrogen pressures in the accumulators did not appropriately restrict cross-tying accumulators.

As part of the licensee's immediate corrective actions, operating procedures were revised to delete all steps that allow cross-tying of accumulators in modes that require

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the accumulators to be operable. As part of the licensee's long-term corrective actions, all personnel who performed 50.59 safety evaluations were required to receive fortnal qualification training.

The team reviewed this LER including the licensee's corrective actions. The team identified the following deficiencies:

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The abstract in the LER did not correctly describe the issue.

• The LER abstract stated that cross-tying more than two Si accumulators for greater than a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period placed the plant outside the licensing basis.

However, the NFS calculation results concluded that cross-tying more than two accumulators for any period potentially placed the plant outside the licensing basis. The main body of the LER correctly reported this conclusion.

• Corrective Action Enhancements Were identified As part of the licensee's corrective actions, procedures were immediately revised to delete those steps that allowed cross-tying of the Si accumulators in modes that required the accumulators to be operable. This was actually accomplished prior to the formal identification that this issue pertained to the Braidwood facility.

As such, since affected procedures were classified as " reference use" procedures, personnel utilizing these procedures were required to review them prior to use. As a result, proper procedure use and adherence would prevent cross-tying two or more accumulators.

However, the team noted that the licensee's corrective actions did not include operator training to discuss the basis for the sudden procedure change although the practice of cross tying accumulators had been commonly used to equalizo pressure and level between two or more acnmulators. The team concluded that although the licensee's corrective actions were adequate to prevent recurrence, training to inform operators of the basis for the procedure change would have been beneficial.

Licensee Event Report 50-456/96005," Operation of Safety injection Accumulators Outside Design Basis," is closed.

c.

Conclusions The team concluded that although the licensee's corrective actions in response to concerns identified regarding potential cross-tying of Si accumulators were acceptable, operator training regarding the issue would have been beneficial. In addition, the team concluded that the development and review of the LER lacked an appropriate attention-to-detail since statements in the abstract differed from the LER details and the NFS report.

E8.2 (Closed) insoection Follow-uo item 50-456/96014-03(DRPH 50-457/96014-OP'DRPt RCFC and DG Supply Fan Breaker Failures.

a.

Insoection Scoce The inspectors reviewed Inspection Follow-up Item 50-456/96014-03; 50-457/96014-03.

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Observations and Findinas -

As discussed in inspection report 50-456/96014; 50-457/96014, the licensee identified that on September 24,1996, the 1C RCFC fan failed to automaticall) start in slow speed during performance of 1BwOS 6.2.3.a-1, "RCFC Monthly Surveillance." In addition, on October 10,1996, the 1B DG supply ventilation fan failed to start during a routine DG surveillance. The licensee performed a root cause investigation and determined that both breakers were Westinghouse series DS 480V circuit breakers. The licensee also determined that the RCFC breaker had a failed charging motor cutoff switch and the DG supply fan breaker had an overheated spring release coll. The RCFC and DG breakers were sent to Westinghouse for a detailed failure analysis. Inspection followup item 50-456/96014-03; 50-457/96014-03 was opened pending the results of that analysis.

During this inspection, the team determined that following the RCFC and DG breaker failures, the licensee formulated a breaker pilot program. The purpose of this program was for Westinghouse to determine the extent of future breaker refurbishment. The licensee sent 10 DS 480V and 12 DHP 4160V breakers to Westinghouse for refurbishment.

On April 15,1997, after the breakers were refurbished by Westinghouse and installed in the plant, Westinghouse informed the licensee that correct procedures were not used during their refurbishment process which resulted in the omission or poor documentation of required tests and inspections. The specific items omitted or poorly documented included the performance of timing tests, contact resistance checks, re-application of lubricant, opening force margin tests, and weld inspections. As a result, Westinghouse halted work at one of its facilities on April 25,1997, and issued a 10 CFR 21," Reporting of Defects and Noncompilance," notification on May 14,1997, documenting the problems in their breaker refurbishment process detailed above.

Subsequently, Westinghouse and the licensee determined that the previously refurbished breakers were operable for an additional 25 cycles or 6 months from the date of the test. The basis for the operability of these breakers *.vas documented in Operability Evaluation 97-040. The tearr' reviewed the operability evaluation and agreed with the licensee's conclusions, c.

Conclusions The team concluded that licensee actions to address RCFC and DG fan breaker failures were acceptable. This inspection follow-up item is closed.

E8.3 (Closed) Insoection Follow-uo item 50-456/96008-03(DRPH LER 50-456/%003-00:

Forced Unit 1 Shutdown Caused by 125 V DC Battery 112 Failing to Meet Capacity Requirements of Technical Specifications Due to Equipment Degradation

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Insoection Scooe The team reviewed inspection followup item 50-456/96008-03(DRP) and LER 50-456/96003.

b.

Observations and Findinos

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As discussed in inspection report 50-456/96008(DRP); 50-457/96008(DRP), and LER 50-456/96003, following a modification which installed AT&T roundeell batteries in the safety related 125 V direct current (DC) system in March 1984, on October 30,1995, battery 112 faile/J a modified performance test. Subsequently, further tests were conducted which confirmed that premature and unexpected battery cell degradation had occurred. As a result, inspection followup item 50-456/96008-03(DRP) was opened to track the results of the licensee's root cause investigation and corrective actions.

During this inspection, the team determined that the licensee identified the root causes for the premature battery capacity degradation. These causes included the failure to perform adequate battery testing, multiple discharges of the battery within a 30-day period, failure to fully recharge the battery following discharge, and the battery's unique electrochemical characteristic. The team also determined that the other three divisions of safety-related 125 VDC batteries had not experienced a premature loss of capacity since they had not been subjected to the frequent deep discharges and recharges as was the case for battery 112.

As part of their long-term corrective actions, the licensee planned to replace the presently installed AT&T roundcell batteries with an improved design. Prior to this replacement, the licensee's interim corrective actions included minimizing unnecessary discharges of the affected batteries, conducting a detailed evaluation for each discharge of 300 ampere-hours or greater, and revising the battering charging procedure to establish a more effective re-charge method.

c.

Conclusions The team concluded that the licensee's investigation and corrective actions were acceptable, inspection followup item 50-456/96008-03(DRP)is closed. Licensee Event Report 50-456/96003 is closed.

E8.4 Licensee Identification. Resolution. and Prevention of Problems (40500)

a.

Insoection Scoce The team reviewed the licensee's ability to identify, resolve, and prevent problems, included in the team review was the Integrated Reporting Program (IRP); supporting functions of the IRP such as root cause evaluations, trending, and effectiveness reviews; operating experience piogram, and self-assessment programs. The team reviewed the following BwAPs and Nuclear Station Work Procedures (NSWPs):

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NSWP-A-15 Revision 1 Comed Nuclear Division Integrated

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Reporting Program

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b.

Observations and Findings

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Corrective Actions Proaram The team reviewed various facets of the licensee's corrective actions program implemented to identify and resolve problems. The findings are discussed below.

Problem Identification Observations The team determined that electronic PIF generation was recently implemented at Braidwood. The electronic PIF process required that an individual who identifies a problem document the issue including any immediate corrective actions tal(en.

Subsequently, a review by a supervisor cognizant of the issue and an operability review by the shift manager was performed.

The team reviewed this process and was concemed that the supervisor review could delay an immediate operability determination by the shift manager and/or intimidate the PlF originator. Subsequently, the team determined that the shift manager received all PlFs when they were originated and the supervisor review was nct required before operators reviewed the issue. The team also determined that the individual who performed the supervisor review was determined by the issue, not the originator.

Therefore, the supervisor that reviewed a PlF was not necessarily originator's supervisor. The team did not have any additional concems.

The team also identified that the PIF contained a section for the shift manager to document his/her review for operability, limiting condition for operation action requirement entry, and requests for operability determination. The team noted that the shift manager frequently did not check the appropriate box for the conditions described on the PIF. An example was the " Equipment Operable" item was "N/A" when an operability determination was clearly required to be made by the shift manager. The

"N/A" response was the default value for the computer program. However, the team noted that the comments section usually provided sufficient explanation to identify the operability status. The team was concerned that proper documentation was not always

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provided for operabiliy evaluations and other similar decisions. The licensee had previously identified the concern, concluded that the problem was primarily a human

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factors issue, and was preparing a revision to the computer program.

The team noted that the licensee was generating approximately 425 PIFs per month for the first half of 1997. The new electronic version of the PIF was implemented during this period without a notable change in the PIF generation rate. The team reviewed a 3 month period and noted that the PIF generation rate was well balanced over operations, maintenance, and engineering. The team concluded that, as a group, licensee personnel were identifying problems via the integrated reporting program.

Event Screening Meetino Observations The team observed an Event Screening Committee (ESC) meeting. The team noted that the station manager, the system engineering supervisor, and many other senior station managers were the primary members of the ESC. Active participation by all

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members was observed by the team. Without attempting to solve the problem, th committee members provided discussion of the issue's significance. The team noted that ESC approval was also required to extend a commitment date. This minimized %

number of extension requests. Additionally, the IRP coordinator was a significant contributor, providing the meeting agenda and reminders of overdue supervisory reviews. The team concluded that the ESC was a strength primarily due to the good senior management involvement.

Root Cause investioation Observations The team reviewed not cause analysis packages and interviewed root cause analysts.

The team noted during one review that an LER was prepared without any additional formal documentation. The package contained various requirements, the original PlF and procedures, but the team did not identify any additional conclusions reached by the root cause investigator. During the interviews, the root cause investigators indicated that additional information was retained in their personal notes and that frequently the information was verbally discussed during the LER approval process. The team was concemed that potentially valuable information and lessons learned by the root cause

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investigator may not be retained. During the reviews, the team also noted that the root cause reports generally contained good information and reasonable corrective actions.

However, the team found that, occasionally, the development of inappropriate actions and corresponding corrective actions was not well documented.

Problem Identification Form (PIF) Trendino Procram Observations Trending for individual PIFs was conducted by analysis of the root or apparent cause(s). The trending coordinator evaluated each root or apparent cause and identified categories to trend. The team reviewed several trend reports with the trend coordinator. The team considered the trends to be of good quality with relevant information provided in the report. The team considered the trend coordinator knowledgeable. However, during a review of NSWP-A-10. " Station Performance

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Trending / Monitoring" the team noted that the procedure did not provide detailed instructions for conducting a trend analysis. Specifically, the procedure stated that "the Trend Analyst will conduct horizontal monitoring of appropriate trend code data to determine common, generic or global adverse, potential adverse or improving trends."

The remainder of the procedure described normalizing data, PlF initiation, and reporting results and report formats. The trend analyst agreed with the team that more specific instructions could be provided in the procedure to ensure more consistent results.

Effectiveness Review Observations The team reviewed a sample of effectiveness reviews. Corrective actions were identified as ineffective in several instances. The team considered the use of the effectiveness reviews good. However, the formal program was recently revised to implement the corporate procedure, NSWP-A-16,"tiffectiveness Review." NSWP-A-16 required a more structured review of corrective action'and consistent presentation of findings. The team generally considered the procedure good; however, a sufficient number of effectiveness reviews had not been completed by the station for the team to determine actual performance improvements provided by the procedure.

The team concluded that the IRP and corrective actions program was generally good.

Inte views identified knowledgeable personnel and appropriate processes. The ESC was a strength. The team also concluded that documentation was an area that could be improved in most areas of the corrective action program, including depth and content of root cause reports, and procedure content in trending. Often, the recent implementation of the corporate corrective action program procedures prevented an adequate review of results achieved.

Ooeratino Exoerience Feedback The team reviewed the licensee's operating experience (OPEX) procedure and discussed the program with the OPEX coordinator. The team observed that gene ally, incoming documents were appropriately coordinated and distributed for action.

However, the team noted that Electric Povver Research Institute (EPRI) documents were not coordinated by the OPEX coordinator. Following the teams questions, the licensee identified that the EPRI documents were distributed directly to the appropriate reviewer.

At the end of the inspection, the licensee planned to place the OPEX coordinator on the EPRI document distribution list. The team considered this issue minor and the OPEX k

program good overall.

Self-Assessment Activities The team reviewed self-assessments from the operations, maintenance, and

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engineering departments. The self-assessments all contained strengths and

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weaknesses, actions taken from previous self-assessments, and actiors required as

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identified during the self-assessment. The team noted that the content d each assessment generally provided self-critical information for the respective department.

However, the quality of assessment was mixed. The actions required as identified

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during the self-assessment were not obviously aligned with weaknesses identified in the report. The engineering assessment consisted almost exclusively of indicator graphs and did not typically provide any additional assessment of performance. None of the department self-assessments tracked all open items in a formal tracking system.

Actions related to significant station commitments and indicators typically are tracked; however, most actions are tracked using a review of previous actions in a current report.

The team fw:nd that the department self assessments were useful; however, significant improvements could be made to the program.

In addition to the operations department self-assessments, operators used a program, called Scorecard, that provided a supervisory review of various operating facets. These reviews provided immediate feedback to operators on performance and increased the amount of direct supervisory review. The results were collected and reviewed to identify potentialissues. The team considered the program a strength.

The station did not have a formal procedure for conducting self-assessments. However, a procedure was being developed. A dedicated self-assessment coordinator was also assigned.

The team reviewed department assessments prepared by the Independent Safety Engineering Group (ISEG) for Maintenance (April 1997) and Operations (June 1997).

The ISEG also developed station wide assessments for April and May 1997. The assessments were generally consistent with department self-assessments and more comprehensive. The ISEG was focused on safety-related and performance-based issues more than the department self-assessments. Generally the team considered the ISEG assessments very good.

The team reviewed several site quality verification (SQV) audits and the resulting corrective action records (CARS). Typically the audits identified substantive issues. The team concluded that the audits were generally good. The team reviewed the audits scheduled by the SQV audit group. The audits required by the Comed Quality Assurance Manual were scheduled. However, the team noted that only two audits were scheduled for 1997 that were not required by a regulation. Based on the apparent quality of the audits and the shortage of discretionary audits, the team concluded that the audit group could provide additional oversight for the station.

An SQV corrective actions audit (QAA 20-96-03) in early 1996, was a significant contributor to the station beginning to improve the corrective action process. The team reviewed corrective actions record 20-96-011 and noted significant SOV findings. The audit included the following findings: poor timely completion of corrective actions; recurrent problems due to apparently ineffective corrective actions; poor tracking of significant commitments; and failure to establish due dates for corrective actions. The licensee took significant corrective actions for the issues identified. The team concluded that this audit was one factor in the licensee beginning to implement improvements to the corrective actions program.

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Onsite and Offsite Safety Review Committee.%ctivities The team reviewed the onsite review (OSR) program, including the plant operation review committee (PORC). During review of the ')SR procedure, BwAP 1205-3,

• On-site Review and Investigative Function," the taam noted that the PORC was designated as the OSR committee. During review of the PORC procedure, BwAP 1205-

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13," Plant Operation Review Committee," the team noted that appropriate disciplines were required when the PORC functioned as the OSR committee. Additionally, the procedure stated that if the station manager was present, an independent overview of the issue must be maintained.

The Commonwealth Edison Quality Assurance Program Manual, Topical Report CE-1-A, Revision 65f, Section 20, Paragraph 3.3.1 stated that the station manager shall independently review and approve the findings and recommendations developed by personnel performing the Onsite Review and investigative Function. The team questioned how the station manager maintained independence while also being the chairman of the PORC. The station manager discussed the issue with the team and stated that he attempted to observe and not participate directly in OSR discussions during a PORC meeting. Additionally, he noted that the actual approval of PORC reviewed issues occurred after corrections and improvements were inserted into the reviewed document. This approval was typically conducted a day or two after a meeting, thus giving the station manager an additional opportunity to independently approve actions. The station manager also noted that the review process that included the PORC was actually a more stringent process than the OSR, in that multiple senior station managers were involved. The OSR process did not necessarily receive multiple senior management reviews. The team agreed that the improvements provided by the PORC were significant.

The team requested the safety evaluation that reviewed the procedure changes implementing the OSR and PORC as described in the Comed QA Manual. A safety evaluation screening was performed and concluded that the changes did not affect a proceduro described in the UFSAR. However, the team noted that 10 CFR 50.34(b)(6)(ii), " Content of Applications; Technical Information," stated, in part, that the Final Safety Analysis Report shall include " managerial and administrative controls to be used to assure safe operation," and that,"The information on the controls to be used for a nuclear power plant shall include a discussion of how the applicable requirements of [10 CFR 50] Appendix B will be satisfied." Additionally, the Byron /Braidwood Updated Final Safety Analysis Report, Revision 6, Chapter 17, stated that the quality assurance program for the Byron and Braidwood Stations was conducted in accordance with the Commonwealth Edison Company Quality Assurance Program for Nuclear Generating Stations [QA Manual).

The team also noted that 10 CFR 50.59, " Changes, tests, and experiments," stated, in part, that the licensee may make changes in the proceo.Jres as described in the safety analysis report without prior Commission approval, unless the proposed change involves a change to technical specifications or an unreviewed safety question. Part 50.59(b)(1),

stated the licensee shall maintain records of changes to procedures made pursuant to

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this section and that these records must include a written safety ovaluation which provides the bases for the determination that the change, test or experiment does not involve an unreviewed safety question.

The team noted that on March 31,1997, BwAP 1205-3, Revision 12, *On-site Review and Investigative Function," was approved, allowing the PORC to fulfill the OSR function described in the QA Manual, without performing a written safety evaluation. The team concluded the failure to perform a written safety evaluation was an example of a violation of 10 CFR 50.59, " Changes, Tests, and Experiments" (50-456/97012-02(DRS);

50-457/97012-02(DRS)).

The team reviewed four offsite review reports and discussed the offsite review function w'th the lead reviewer. The sample of offsite review reports indicated that the reviews provided substantial comments to the station on the quality of the products submitted to the offsite review board. One report documented conference calls, meetings, and previous written correspondence regarding abandonment of the off-gas filter plenum.

The team also noted that the lead reviewer made routine site visits and frequently attended pertinent meetings such as the PORC meeting. The lead reviewer noted that the offsite committee was also working to improve certain areas of station performance through added emphasis, including root cause investigations and the safety evaluation procedure and documentation.

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Conclusions Certain strengths were noted by the team and included electronic PIF generation, senior management participation at the event screening committee meeting, and some self-assessments (the Scorecard program and some ISEG assessments in particular).

Several areas of good performance were also identified and included !ba trending program, the OPEX program, most SQV audits and ISEG activities, certain off-site review reports, and the PORC conduct of on-site reviews.

However, the team also concluded that documentation of activities was frequently marginal. The shift manager's documentation of operability status was not always clear on PIFs Supervisory review of PIFs was not always timely. Root cause reports did not always clearly document the development of inappropriate actions and corrective actions. Some department self assessments contained very little performance assessment. The team also concluded that some procedures were marginalincluding NSWP-A-10, and the station self-assessment procedure.

The team concluded that the licensee's ability to identify, resolve, and prevent problems was mixed. The team concluded that significant improvements were made during the previous 18 months. Several new programs and procedures initiated in the previous 6 months appeared to be good. However, full implementation was not complete in all areas and the number of products from the new programs were insufficient to effectively evaluate the actual results of the programs.

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V. MANAGEMENT MEETINGS X1, Exit Meeting Summary The team presented the inspection results to members of license management at the conclusion of the inspection on August 15,1997. The licensee acknowledged the findings presented.

The team asked the licensee whether any enaterials examined during the inspection should be

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PARTIAL LIST OF PERSONS CONTACTED Licensen M. Cassidy, NRC Coordinator, Regulatory Assurance

- C. Dunn, System Engineering Supervisor M. Kluge, ISEG Engineer F. Lentine, Support Engineering Supervisor J. Meister, Engineering Manager J. Nalewajka, ISEG Supervisor D. Radice, Design Engineering Supervisor D. Riegel, Assistant Manager, SQV&A D. Skoza, Assictant System Engineering Supervisor H. Stcnley, Site Vice President, Braidwood B. Viehl, Engineering Assurance Supervisor P. Zolan, Compliance Supervisor htlC J. Adams Resident inspector C. Phillips Senior Resident inspector

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INSPECTION PROCEDURES USED IP 37550 Engineering IP 37551 Onsite Engineering _

IP 40500 Effectiveness of Licensee Controls in Identifying, Resolving and Preventing Problems ITEMS OPENED. CLOSED AND DISCUSSED Ooened 50-456/457/97012-01 VIO Preconditioning Electrical Equipment 50-456/457/97012-02 VIO Inadequate 10 CFR 50.59 Safety Evaluation 50-456/457/97012 33 VIO Inadequate Design Controlin Feed Line Break Analysis 50-456/97012-04 VIO Unit 1 RWST Heater inadequately Mounted 50-457/97012-05 VIO Failure to inform Shift Management of Problem 50-456/97012-06 VIO Installation of Non-EQ Breaker in Harsh Environment C1019.d 50-456/96003 LER 125 VDC Battery 112 Failed to Meet Capacity Requirements 50-456/96005 LER Operation of Safety injection Accumulators Outside Design Basis 50-456/96009 LER Safety injection Relief Valves Lifted and Failed to Reseat 50-456/96008-03 IFl 125 VDC Battery 112 Failed to Meet Capacity Requirements 50-456/457/96014-03 IFl RCFC and DG Supply Fan Breaker Failures

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LIST OF ACRONYMS USED AF.

Auxiliary Feedwater ASME American Society of Mechanical Engineers BwAP Braidwood Administrative Procedure BwHS Braidwood Electrical Maintenance Department Surveillance BwOS Braidwood Operating Surveillance-BwVP-

. Braidwood inservice Inspection Procedure BwVS

- Braidwood Surveillance Procedure CDE Cause Determination Evaluation CFR Code of Federal Regulations Comed Commonwealth Edison CS Containment Spray CSAT Containment Spray Additive Tank DG Diesel Generator ECCS Emergency Core Cooling System EMD Electrical Maintenance Department EPRI Electric Power Research Institute

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EQ Equipment Qualification ER Engineering Request ESC Event Screening Committee E&TS Engineering and Technical Support gpm gallons per minute IN Information Notice IRP Integrated Reporting Process ISEG Independent Safety Engineering Group IGT Inservice Testing LER

- Licensee Event Report MCC Motor Control Center N/A Not Applicable NFS Nuclear Fuel Services NOD Nuclear Operating Division NSWP Nuclear Station Work Procedure OPEX Operating Experience OSHA Occupation Safety and Health Administration 03R Onsite Review PDR Public Document Room P&lD Piping and Instrumentation Drawing PIF F-roblem Identification Form PORC Plant Onsite Review Committee PSA Pressurized Water Reactor Safety Analysis psig pounds per square inch PWR Pressurized Water Reactor QA Quality Assurance QC Quality Control RCFC Reactor Containment Fan Cooler RHR Residual Heat Removal

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RSO Relay Setting Order RWST Ret'ueling Water Storage Tank SG Steam Generator SI Safety injection System SQA Site Quality Assessment SQV Site Quality Verification SRB Safety Review Board I

TS Technical Specification UFSAR Updated Final Safety Analysis Report V

Volt VIO Violation WR Work Request c

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