IR 05000454/1989014

Safety Insp Repts 50-454/89-14 & 50-455/89-16 on 890518-0630.No Violations or Deviations Noted.Major Areas Inspected:Operational Safety,Esf Sys Walkdown,Fire Protection,Event Followup & Maint/Surveillance

ML20246L682
Person / Time
Site:	Byron
Issue date:	07/11/1989
From:	Hinds J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20246L676	List: IR 05000454/1989014 ML20246L673
References
50-454-89-14, 50-455-89-16, NUDOCS 8907180493
Download: ML20246L682 (20)

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U. S. NUCLEAR REGULATORY 1 COMMISSION REGION III I Report Nos. 50-454/89014(DRP);50-455/89016(DRP)

Docket Nos. 50-454; 50-455 License Nos. NPF-37; NPF-66 Licensee: Commonwealth Edison Company-Post Office Box 767 Chicago, IL 60690 Facility Name:. Byron Station, Units 1 and 2

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Inspection At: Byron Station, Byron, Illinois

Inspection Conducted: May 18 through June 30, 1989 Inspectors: P. G. Brochman W. J. Kropp N. V. Gilles D. R. Calhoun- i R. N. Sutphin - ' -

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Approved By: J. M. Hindi dr. 'CInief JUL11 Reactor Prcjects Section 1A Date Inspection Summary Inspection from May 18 through June 30, 1989 (Report Nos. 50-454/89014(DRP);

50-455/89016(DRP))

Areas Inspected: Routine, unannounced safety inspection by the resident and regional inspectors of licensee action on previous inspection findings; operational safety; engineered safety features system walkdown; fire protection; event follow-up; maintenance / surveillance; Technical Specification required testing of Diesel Generators; follow-up on Region III requests; licensee event reports; Part 21 report follow-up; follow-up on allegations concerning contractor QC activities; evaluation of licensee performance; and meeting Results: No violations or deviations were identified, nor were any items identified which could affect the public's health and safety.

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DETAILS l '. - Persons Contacted

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Commonwealth Edison Company R. Pleniewicz, Station Manager

• G. Schwartz, Production Superintendent

• R. Ward, Technical Superintendent

• J. Kudalis, Service Director

• T. Higgins, Assistant Superintendent, Operating

• T. Tulon, Assistant Superintendent, Maintenance D. St. Clair, Assistant. Superintendent, Work Planning J.-Schrock,-Operating Engineer, Unit 1 T. Gierich, Operating Engineer, Unit 2 T. Didier, Operating Engineer, Unit 0 D. Brindle, Operating Engineer.. Administration

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• D. Winchester, Quality Assurance Superintendent

• M. . Snow Regulatory Assurance Supervisor

• R. Flahive, Technical Staff Supervisor S. Barret, Health Physics Supervisor S. Wilson, Chemistry Supervisor P. O'Neil, Quality Control Supervisor D. Goble, Security Supervisor A. Chernick, Training Supervisor

• A. Javorik, Assistant Technical Staff Supervisor

• D. Wozniak, Engineering Project Manager

• E. Zittle, Regulatory Assurance Staff

• M. Marchionda, Regulatory Assurance Staff

• Dean, Onsite Nuclear Safety

• S. Kraus, Quality Assurance Auditor The inspector also contacted and interviewed other licensee and contractor personnel during the course of this inspectio * Denotes those present during the exit interview on June 30, 198 . Action on Previous Inspection Findings (92701)

(Closed) Unresolved Item (454/87039-03(DRP); 455/87036-D3(DRP)): Design of Auxiliary Feedwater (AF) diesel day tank causes air entrainment. The inspectors reviewed the results of Special Test Procedure SPP-89-046,

" Demonstration of Unit 2 'B' Train Auxiliary Feedwater Pump Operability during a fill of the 2B AF Pump Diesel Oil Day Tank." This procedure was designed to establish the appropriate procedural restrictions or alleviate unnecessary procedural restrictions for filling the Diesel Oil

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(D0) day tank with the 28. Auxiliary Feedwater pump running at low day i

tank oil levels. The acceptance criteria for this test were: (1) Record I the AF 00 day tank oil level at which the speed of the 2B AF pump begins to oscillate and (2) Record the minimum AF D0 day tank oil level at which l

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a fill of the day tank can be initiated without. adversely affecting pump operation. During the test, the level at which the 2B AF pump began to operate erratically, characterized by severe speed oscillations (700 rpm), was at an indicated. level of 25%. However, subsequent .

investigation ' revealed that the actual oil level in the tank was 4 inches above'the bottom of the tank (8% level). The cause of this discrepancy was due to air entrapment in the sensing.line to the indicator (10% of error) and variation in D0 specific gravity (7%.of error). The 7%

deviation which is due to the D0 specific gravity is within the +/-11.25%

accuracy required by the calibration test repor Operations management issued a daily order to maintain the level in the 2B day tank above the 86% level to ensure level remained above-the Technical Specification limit of 420 gallons (approximately 70% level)..

An operator aid has been placed at the 2B AF pump day tank level indicator to alert operators that the day tank level must be maintained above 86%

and a similar aid was placed at the IB FF pump day tank level indicato The licensee is in the process of- revising their procedures to incorporate these requirements to ensure that the day tank levels are maintained above the Technical Specification limit. . A modification request has been initiatad to change the 1B and 2B AF diesel oil day tank level indication to invall a means of indication that is independent of specific gravity changes in the diesel fuel and is not as susceptible to air entrapment as the current indicatio Based on the results of the special test procedure and the actions outlined above, . this item is cor.sidered close .P_lant Operations Unit 1 operated at power levels up to 100% for the entire report perio Unit 2 was shut down (Mode 4) for a maintenance outage until 2:51 on May 23, 1989, when the reactor was taken critical. The unit was synchronized to the grid at 10:09 p.m. the same day and operated at power levals up to 95% for the rest of the report perio Operational Safety (71707)

The inspectors observed control room operation, reviewed applicable  !

logs and conducted discussions with control room operators during May and June 1989. During these discussions and observations, the  !

inspectors ascertained that the operators were alert, cogniiant of j plant conditions, and attentive to changes in those conditions, and that they took prompt action when appropriate. The inspectors verified the operability of selected emergency systems, reviewed tagout records, and verified the proper return to service of affected components. Tours of the auxiliary, fuel-handling, 4 rad-waste, and turbine buildings were conducted to observe plant I equipment conditions, including potential fire hazards, fluid leaks, l

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and excessive vibrations, and to verify that maintenance requests had been initiated for equipment in need of maintenanc The inspectors verified by observation and direct interviews that the physical security' plan is being implemented in accordance with the station securityLpla The inspectors observed plant housekeeping / cleanliness conditions and verified implementation.of~ radiation protection. controls. The -

inspectors also witnessed portions of the radioactive waste system'

controls associated with rad-waste shipments and barrelin The inspector identified the good operating practice of placing caution. tags on valves.that have or potentially could have white:

Melamine. torque switches in the motor operators. The caution tags state that the. valves might not open (or close) due.to potential torque switch problems. For further details see paragraph The observed facility operations were verified to be in accordance with the requirements established under Technical Specifications, 10 CFR, and administrative procedure Engineered Safety Features System Walkdown (71710)'

The inspectors performed an independent verification'of the status of the 1A Auxiliary Feedwater System to ensure its operabilit The inspectors verified that pumps and valves were properly labeled;-

lubricating oil was at proper levels; cooling water was properly aligned; valves were in their proper position and without gross packing and grease leaks; there were no bent valve stems or missing-handwheels; housekeeping was adequate with combustible materials controlled; circuit breakers were in their proper position; instruments were in service, within the calibration interval, and providing correct indication; and hangers and structural supports were properly installed. No problems were note The inspectors also performed an. independent verification of the lineups of the remote shutdown panels (RSP) for both Unit 1 and-Unit 2. Procedures 1(2) BGP 100-1T7, IT8 and IT9, Revision 1, the RSP panel lineups for 1(2)PLO5J, 1(2)PLO6J and 1(2)PLO6J were utilize The inspectors identified the following concerns:  !

• A caution tag was not on the RSP controller for 2MS018D, the main steam power operated relief valve (PORV). The controller for 2MS018D on the Main Control Board had a caution tag due to a problem with position indication that resulted in 2MS018D being isolated by 2MS019D, the isolation block valv * Unit 1 PORV control switches were in the "close" position rather than " auto" as delineated in IBGP 100-1T7 and 1T i

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Flow control valve controllers for AFW valves 1AF005A-H were set at 0% opening versus 15%, as delineated in 1BGP 100-1T7 l and.1T The licensee initiated corrective actions to place a caution tag on the controller for PORV 2MS018D, at the RSP. Also the-licensee placed the control switches for_ the Unit 1 PORVs and AFW flow .

control valves in the-required position.

l A 'further review of_ the BGPs determined'that there was no required

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verification to ensure that the RSPs-were lined up in accordance with 1(2)BGP 100-1T7, 1T8 and IT9 prior to entering Mode 3. The RSP .

instrumentation is required to be operable by. Technical Specifica -

tions in Modes 1, 2 and 3 and it would be good operating practice to ensure that the RSP control switches were in the position established by; station operating procedures prior to entering

. Mode Fire Protection (64704)

During a walkdown of the Unit I control room panels, the inspectors noted that the door alarms for the upper and lower cable spreading rooms were "off" on fire protection panel 1PM09J. Also, doors D398 and D399 for the lower cable spreading rooms indicated "open". Th ,

Shift Foreman investigated the status of doors D398 and D399 and determined that both doors were closed. In addition, door D398 had a missing door knob with impairment tag # 1669 hung on the doo A review of the impairment log identified that tag # 1669 was

- closed and did not appeared to be_ applicable to the missing door knob. The Shift Foreman initiated an impairment form to identify the missing door knob. The inspectors determined through discussions with the fire watch supervisor and a review of documentation that hourly fire watches were in effect:for the upper and lower cable spreading rooms as required when the door alarms were "off" at panel 1PM09 Onsite Event Follow-up (93702)

The inspectors performed onsite follow-up activities for an event which occurred in May 1989. This follow-up included reviews of operating logs, procedures, Deviation Reports, Licensee Event Reports (where available), and-interviews with licensee personne For the event, the inspector developed a chronology, reviewed the functioning of safety systems required by plant conditions, and reviewed licensee actions to verify consistency with procedures,-

license conditions, and the nature of the event. Additionally, the'

inspector verified that the licensee's investigation had identified-the root causes_of equipment malfunctions and/or personnel errot3 and that the licensee had taken appropriate corrective actions prior to restarting the uni Details of the event and the licensee's i corrective actions developed through inspector follow-up is provided in the paragraph below:

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Unit 2 - Feedwater System Isolation At'3:56 a.m. on May' 23, 1989, with Unit 2 in Mode 3, a feedwater-isolation signal was generated when the train B reactor trio breaker (RTB) was being racked in. The operators had.c p ad su closed the train B RTB as part of the normal startup-procedure. .The. reactor :

operator- (RO) noticed that the indicator for " Reactor Trip, P-4"- '

flashed on and off several times. The R0 instructed the equipment operator (EO) to rack out the RTB and then rack it back in. When the E0 racked the RTB back in, a feedwater isolation signal wa generated. (At Byron, a feedwater' isolation signal occurs concurrent-with.a reactor trip signal.) Any open feedwater. isolation valves closed. The feedwater isolation signal was reset and the operators entered Technical Specification Action Requirement 3.3.2.c for one channel of the Reactor Trip, P-4 interlock, inoperable and. a work request.was written to investigate the problem. The. breaker was removed from the cubicle and tested and no problems were found. ,No o specific cause for this event could be identified. The. licensee surmised that the cause was a failure of a breaker cubicle contact which provides indication of RTB position to the Solid State

. Protection System to actuate properl .As corrective actions, the licensee's electrical maintenance department performed a full inspection of the RTB. A special

- procedure was ' performed to try to recreate the incident, but attempts to reproduce .the event were unsuccessful. Prior to returni_ng the RTB to service, a surveillance was performed to verify proper operation of the undervoltage and shunt trip functions. To prevent similar events. in the future, the licensee will verify the P-4 signal before racking the RTB through utilization of a voltmeter on the front of the breaker cubicl Temporary caution cards were placed on the front of each RTB to check'the voltmeter prior to racking the breaker. Permanent labels with this caution will be placed;on the breaker cubicle No violations or deviations were identifie . MAINTENANCE / SURVEILLANCE (61726 & 62703) Station maintenance and surveillance activities of th safety-related systa-s and components listed below were observed or reviewed to asce cain that they were conducted in accordance with approved procedures, regulatory guides, and industry codes or standards, and in conformance with Technical Specification * Torque switch replacement on Limitorque operator for valve ISI8923A

• Valve signature and Votes testing of valve ISI8923A l

• IB Auxiliary Feedwater pump monthly operability surveillance

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• Repairs to 1A Essential Service Water pump strainer

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• Unit 1 "B"' Diesel Generator (DG) Monthly Surveillance

• Repair to 1B Main Feed Pump (MFP) recirculations line elbo ]

• Unit 1 Remote Shutdown Panel control power check 18 month l >

surveillance and monthly channel check' surveillanc * SPP on 1A AF pump SI auto-start feature with RSP transfer in ,

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The following' items were considered during this review: the limiting conditions for operation were met while affected components ,

or. systems were removed from and restored to service; approvals  !

were obtained prior to initiating work or testing; quality control records were maintained; parts and materials used were properly certified; radiological and fire prevention controls were accomplished.in accordance with approved procedures; maintenance and testing were accomplished by qualified personnel'; test instrumentation was within its calibration interval; functional testing and/or calibrations were perfornied prior to returning components or systems to service; test results conformed with Technical Specifications and procedural requirements and were reviewed by personnel other than the individual directing the test; any deficiencies identified during the testing were properly documented, reviewed, and resolved by appropriate management personnel; work requests were reviewed to determine the status of outstanding jobs and to assure that priority was assigned to safety-related equipment maintenance which may affect system performanc The following concerns were identified that require further follow-up in future inspections:

• Immediately prior to performing the IB DG Monthly Surveillance on June 7,1989, the licensee cross-connected the outlet of the air start receivers at the drain on the moisture separators. This allowed the air receiver normally supplied by the "A" air compressor, which at the time was out of service (00S), to equalize with the air receiver supplied by the "B" air compresso Prior to cross connecting the air receier normally supplied by the 00S "A" air compressor, it was at 215 psi and the other air receiver supplied by the "B" air compressor was at 250 psi. As a result of the cross connection, the pressure dropped below 240 psi in both air receivers which caused the "B" air compressor to auto start and charge both air receivers to 250 psi. Therefore, the surveillance was performed with both air receivers at 250

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psi rather than one at 215 psi and the other at 250 psi. Based on the design of the air start system, which requires only one air receiver to start a DG, the inspectors did not question the operability of the IB DG. However, the inspectors were concerned with the licensee's approach of improving the status of degraded subsystems immediately prior to performing a surveillance. The inspectors will monitor future surveillance to ascertain if the licensee's approach to surveillance could mask the effects of degraded components / subsystems on a system's operability status.

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• Each DG' has two fuel oil transfer pumps that auto-start when the DGs I start. The purpose of the pumps is to transfer fuel oil from the storage. tanks to the DG's day tank. . Under full load conditions the fuel oil in the day ~ tank would last approximately 72 minutes without L replenishment from a fuel oil transfer pump.- One fuel oil transfer pump is of sufficient capacity to maintain the day tank level during DG full load operations. Technical Specification surveillance requirement 4.8.1.1.2.a.3 requires the licensee to' verify once ever days.that the fuel oil transfer pump auto starts and transfers fuel from the storage system to the day tank. Surveillance procedures 1(2) BOS 8.1.1.2.a-1(2),. step F .4.3, requires verification that only one fuel oil transfer pump auto starts. The surveillance procedures do not require the licensee to identify which fuel oil transfer pump is declared operable per Technical Specification 4.8.1.1.2.a.3. Therefore, if a fuel oil transfer pump were subsequently taken 00S, the licensee would need to prove operability of'the other fuel oil transfer pump since the surveillance procedure did. not verify that each fuel oil transfer. pump by itself was capable of transferring oil to the day tank. The licensee initiated immediate corrective action by placing caution tags on the local switches for each transfer pump that required operability verification if the other transfer pump for the DG was taken 00 The licensee also initiated appropriate revisions to surveillance procedures 1(2) BOS 8.1.1.2.a-1(2) to ensure that operability of both' transfer pumps is adequately documented'and performe *- The inspectors witnessed portions of the repair to a 90 degree elbow in the IB Main Feed Pump (MFP) 14-inch recirculation line performed by a contractor. The repair was required due to a pinhole leak in the elbow caused by localized erosion. The localized erosion was a result of leakage past valve, IFWO12B. This valve is subjected to main feed pressures of approximately 1000 psi upstream of the valve and condenser vacuum downstream with the plant in Mode 1 and the IB MFP in operation. The elbow is located approximately 2 feet down- l stream of the valve. The licensee has a history of localized erosion problems with.similar elbows in the 1C and 28 MFP recirculation lines. To correct the localized erosion problem, the licensee had previously replaced the elbow with elbows with 5% chrome-and also removed a directional cone from valve 1FW0128. However, based on this recent problem, the station's technical staff is re-evaluating the situation with the assistance of the licensee's corporate engineering organization. The inspectors will monitor the progress of the resolution of the erosion to the elbows in MFP recirculation line The review of the work package, B68086, by the inspectors for the repair of the elbow identified the following concerns:

(1) There was no sketch of the installed elbow in the package to identify the size and location of the pinhol ,

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(2) The size of the patch to cover the pinhole was not specified in the work packag (3) A complete ultrasonic examination.(UT) of the installed elbow was not performed prior to welding the patch on the elbo The licensee did an UT of the elbow to the extent necessary to locate the pinhole. However, there was no documentation in the work package. The licensee was confident that the piahole was a result of localized erosion based.on previous problems encountered with the elbows and a UT that was performed on the elbow being repaired in November 1988. However, based on discussions with NRC regional specialists, the inspectors determined that, regardless of the licensee's confidence that the failure mode was localized erosion, a prudent approach would still have dictated a complete UT of the' installed elbow prior to repair. The licensee has initiated action to monitor the material condition of this elbow and all similar Unit 1 and Unit 2 Main Feedwater recirculation elbows on a periodic basis by UT examinations. This UT would not consist of mapping, but, rather, an assessment of the overall condition of the elbo The inspectors will monitor future maintenance activities to ensure that information in work packages such as items 1 and 2 above, is maintained for adequate work histor * Periodic tests of the safety injection (SI) auto-start features for pumps that could be controlled from the RSP during control room inaccessibility have not been performed. When the Auxiliary Feedwater (AFW), Essential Service Water (SX), Component Cooling Water (CC), and Centrifugal Charging (CV) pumps' transfer switch at the RSP were placed in " local" (pumps controlled from RSP), the SI auto-start circuits utilize different contacts on the transfer switch to initiate pump starts. The Technical Specifications (TS)

18-month surveillance to verify operability of the pumps' SI auto-start feature has only been performed with the transfer switch in " remote" (pumps controlled from Main Control Board). Also, a review of test reports by the licensee, requested by the inspectors, identified that documentation did not exist on all pumps to substantiate that verification of the SI auto-start circuitry with i the transfer switch in " local" was performed during pre-operational tests. Adequate pre-operational test data did not exist for the 1A AFW and the IA, 1B, 2A, and 2B CV pump Preliminary investigation by the licensee determined that the design basis as stated in the FSAR for a control room evacuation did not consider a concurrent Condition II, III or IV event, nor a single failure. Therefore, the licensee's preliminary position was that surveillance tests were not required to verify operability of the SI auto-start circuit with the RSP transfer switch in " local".

However, Byron Abnormal Operating procedure,1(2) BOA ELEC-5, " Local l Emergency Control of Safe Shutdown Equipment-Unit 1(2)," Revision l l

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52, identified that damage to the RSP may cause a loss of SI sequencing ability. The issue of periodically testing the RSP SI auto-start feature in " local" appeared inconclusive as to the specific or desired test requirements. The licensee committed to the issuance of a final position on any test requirements by August 1, 1989. This matter is considered an open item pending further review by the NRC. (454/88014-01; 455/88016-01)

.To resolve the lack of pre-operational test documentation for the 1A AFW and 1A, IB, 2A and 2B CV. pumps, the licensee developed special test-procedures to test the SI auto-start circuits with the respective pump's transfer switch in " local". All pumps were successfully tested with the 1A AFW test witnessed by the inspectors. The inspectors also reviewed the pre-operational test documentation on the 1A CC pump and verified that the SI auto-start circuit was tested in " local".

• TS require a monthly channel check of specific RSP instrumentatio A review of surveillance procedure, IBOS 3.3.5, " Remote Shutdown Instrumentation Monthly Surveillance", Revision 52, identified that the pressurizer pressure instrument readout on the RSP was not compared with an independent channel measuring the same paramete This comparison would need to be with a independent channel displayed on the main control board (MCB), since the RSP consists of only one i readout of pressurizer pressure (1PI-455B). Discussions with the i licensed operators indicated that comparisons with the MCB pressurizer pressure instruments (IPI-456-458) were performed during RSP monthly instrument channel checks but were not documented. The licensee is re-evaluating surveillance procedures 1(2) BOS 3.3.5 to ensure channel checks are appropriately documented and effectively accomplished. The inspectors will continue to monitor the licensee's performance in this are Technical Specification Required Testing of Diesel Generators (61726)

On May 3, 1989, Region Il! requested that the resident inspectors obtain information from the licensee concerning Technical Specification required testing of the Diesel Generators. This information was requested in response to an issue which had arisen at the LaSalle Station during an NRC Maintenance Team Inspectio The information requested concerned two testing issues. The first was whether or not the licensee was accomplishing the semi-annual diesel generator operability tests by perfonning a fast start of the diesel generators from an ambient condition in accordance with Technical Specification surveillance requirement 4.8.1.1.2. Through discussions with the licensee and review of surveillance procedures, the inspectors determined that the licensee was performing a fast start of the diesel generators frcm an ambient condition during the semi-annual operability tests at Byro _ - _ _ _ _ _ _ _ _ _ _ -

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The second issue concerned testing to verify that all automatic diesel generator trips, except engine overspeed and generator differential, were automatically bypassed upon loss-of-voltage on the emergency bus concurrent with a Safety Injection signal, in accordance with Technical Specification surveillance requirement 4.8.1.1.2.f.6.c. The inspectors requested that the licensee provide information which demonstrated that this testing was satisfactorily accomplished at Byron. The licensee informed the inspectors that this testing was accomplished in the 18-month operability surveillance procedures, 1(2) BVS 8.1.1.2.f-9(10).

During review of these procedures and schematics of the DG electro-pneumatic protection circuit and subsequent discussions with a regMnal electrical specialist, the inspectors had concerns with the testing methodology being used. After discussion of these concerns with the licensee it was determined that surveillance procedures 1(2) BVS 8.1.1.2.f-9(10) did not fully test the cap-ability of the DG protection circrit to verify that all automatic trips, except engine overspeed and generator differential, were automatically bypassed in the emergency mod The inspectors determined that the licensee was not providing full test overlap from the electrical circuit into the pneumatic controls in these surveillance procedures. Only the electrical portion of the protection control circuit was being tested for those trips which had an input into both the electrical and pneumatic control Under this testing methodology, the licensee was never challenging the emergency fuel control valves. These are the valves which are energized dormg an emergency start of the DGs and act to prevent the automatic trips, except engine overspeed and generator differential, from tripping the DG in the emergency mode. However, the inspectors learned that the licensee does test the emergency fuel control valves every time the DGs are run and shut down through the design of the DG cooldown circuit. After a DG run is completed and the DG is unloaded, it goes through a five minute cooldown cycle before the engine is shut dowr.. During this cooldown cycle, one of the two emergency fuel control valves is energized for the first two and a half minutes while the second valve is de-energize Then the second valve is energized and the first valve de-energized for the second two and one half minutes. This ensures that each of these valves is operating croperly to prevent the DG from tripping in the emergency mode. If either of these valves was not functioning properly, the DG would trip during the cooldown I cycle and an " Incomplete Sequence" alarm would be generated at the local DG control panel, which would alert the operators that one of the emergency fuel control valves was malfunctioning. However, there was no method for documenting the testing of these valves during the cooldown cycl In response to this concern, the licensee revised procedures 1(2)

BVS 8.1.1.2.f-9(10). The inspectors reviewed these procedure !

revisions and verified that the surveillance now tests both the electrical and pneumatic portions of the protection circuit and that the emergency fuel control valves are challenged to ensure

, that they prevent the DG from tripping in the emergency mode.

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. FollowuponReoionIIIRequests(92701)

In accordance with a memorandum from W. L. Forney, dated June 14, 1989, the inspectors requested the licensee to provide responses to questions that pertained to the automatic trips of the diesel generators (DG). The specific questions and the licensee's responses were:

• What DG trips are active during manual / maintenance / test modes of operations?

The licensee identified 16 trips which were active in the test mode. These specific trips were transmitted to the Region via telecop * What DG trips are active during ESF actuation / loss of offsite power / degraded voltage automatic starts of the DGs?

In the emergency mode, with the DG started as the result of an SI signal and/or bus undervoltage signal, only overspeed, generator differential, and the emergency stop pushbutton engine trips are active. If the DG is running in the emergency mode without an SI signal present, the generator trips (i.e.,

loss of field, generator ground fault, generator overload, reverse power and underfrequency) will trip the DG output breaker but not the engin * If present in the design, is the bypass function tested?

The non-emergency trip bypass function is tested every 18-months, with an SI and ESF bus undervoltage signal presen * Are the exception trips, such as overspeed and generator differential, tested to ensure that they will perform their function?

The overspeed trip test is performed every 18-months, during the cooldown cycle. The emergency stop pushbutton is tested every 18-months by verifying that the DG will not start with the pushbutton depressed. The generator differential relays are tested every 18-months by 0AD as non-Technical Specification relay The above information was transmitted to the Regional Office via telecop No violations or deviations were identifie . Safety Assessment / Quality Verification Licensee Event Report (LER) Follow-up (90712 & 92700)

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(Closed)LERs(454/89005-LL;454/89006-LL;455/89005-LL)): Through direct observation, discussions with licensee personnel, and review of records, the .following 'LERs were reviewed to determine that.the-deportability requirements.were fulfilled, immediate corrective action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with Technical Specification 'LER Na Title Unit 1 454/89005 Diesel Generator inoperable due to deficient post-maintenance testing 454/89006 ESF ventilation actuations due to voltage transient on offsite lines Unit 2 455/89005 Feedwater isolation during reactor trip breaker testing With regard to LER 454/89005, this LER describes an event where the 1A Diesel Generator (DG) failed to load to 5500' kW within 60 seconds-as required by Technical Specifications. This event was discussed in Inspection Report No. 454/89010; 455/89012. The licensee's investigation determined that the DG did not load adequately because-the maintenance which had been performed on the fuel control system inadvertently lowered the maximum fuel setting. In this condition, the DG could not reach 5500 kW in 60 seconds. The fuel control settings were corrected and the DG was tested and declared operable on May 1, 198 The licensee determined that the root cause of this event was inadequacies in maintenance procedures and post-maintenance testing.

_ On April 19, 1989, the fuel control cylinder (bimba. cylinder) was l replaced because it was showing signs of degradation. The licensee I believes that replacing the bimba cylinder. affected the fuel rack span and zero reference with the net affect being a slight reduction in the maximum fuel setting. The post-maintenance testing

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activities verified proper temperature balance on the exhaust cylinders and that the DG could be gradually loaded to 5500 k However, the proper minimum and maximum fuel settings were not verifie The licensee's corrective actions included proper adjustment of the fuel control system using the vendor's original set up procedure. Proper startup, fast loading and maximum design loading (6050 kW)

I were verified during maintenance testing. The semi-annual l

operability surveillance was then successfully performed. The

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licensee plans to incorporate the vendor instructions into the Byron Station Maintenance Procedures to require that all fuel control system parameters be checked whenever maintenance is performed on the fuel control syste The inspectors were concerned that inadequate post-maintenance testing was one of the root causes of this event, since other recent events had similar root causes. The inspectors will perform further evaluations of this and other recent events to determine if there is a recurring problem in this area. This will be tracked as an

. unresolved item (454/89014-02(DRP); 455/89016-02(DRP)).

With regard to LER 454/89006, this LER describes an event where the fuel handling building fuel handling incident area radiation monitor and the main control room outside air intake process radiation monitors (train B) sensed a voltage transient condition and transferred to the interlock mode. These interlock signals caused the main control room ventilation system, the OB fuel handling building charcoal booster fan and its associated dampers to transfer to their Engineered Safety Feature (ESF) position The ESF fans were secured and the dampers reset. The voltage transient occurred when 345 kV line 0622 was energized from Transmission Substation 156 (Cherry Valley) while grounds were installed on the line. The grounds were installed to permit work on oil circuit breakers in the Byron switchyard. One set of grounds was incorrectly placed on the line side of the line disconnect switch due to a communications erro As immediate corrective action, Rock River Division personnel, who had installed the grounds, removed them from line 0622. The Rock River Division investigated the incident to determine the root cause and division personnel will conduct a training seminar to prevent the recurrence of this type of event by September 1, 198 ,

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With regard to LER 455/89005, this event is described in detail in paragraph Part 21 Report Follow-up: Limitorque White Melamine Torque Switches (36100)

On May 19, 1989, the resident inspectors were informed of an issue which had originated at the LaSalle Station involving a deficiency report under 10 CFR Part 21 concerning Limitorque white Melamine I

torque switches. Limitorque Corporation issued the 10 CFR Part 21 Notification on November 3, 1988. The notification identified potential failures of Limitorque operators containing white Melamine torque switches in "SMB-00" and "SMB-000" operators that could ,

either prevent the valves from opening or closing on demand. Two failure mechanisms were identified in the Part 21 notification. One was readily identifiable during routine valve stroke surveillanc The other was attributed to temperature / age related shrinkage of the white Melamine material used in construction of the torque switc This mechanism was predictable by means of trending valve motor current trace ________D

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The licensee.had reviewed Limitorque SMB-00 and SMB-000. operators and determined the population of valves that potentially had white Melamine torque switches. The licensee' changed out approximately 10-14 Melamine torque switches during.the last Unit 2. refueling c

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' outage (Jar.uary March 1989). The licensee's corporate production

. services department which was handling the Psrt 21 report,-had recommended switches-in Marchactions 1989.for These eachactions plant to.take included: regarding)these'

(1 prioritizing torque of all affected valves according to accessibility and ability to work on and stroke'the valve during plant operation;-(2) identification of all valves from this list which were required.to operate during a design basis accident and replacement uf torque. switches in these valvesassoonaspossible;(3)reviewofthemostrecentvalve signature from valve stroke testing; (4) including a current trace in all future' valve stroking surveillance of potentiall

! valves for future reviews of motor current changes;-(5) foryvalves affected with an affected serial number, performance of a valve stroke surveillance which included a current signature trace at the earliest convenient time; (6) completion of a check list.for all

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future valve operator maintenance for identification of torque switch materials; (7) forwarding of a new and used torque switch to the Operational-Analysis Department (OAD) for evaluation; and (8).

use of Fiberite brown torque switches for all future replacements ~

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in Environmentally Qualified Limitorque actuator On May 18, 1989, Byron. received instructions from their corporate nuclear engineering department that the review of records and completion of additional current traces should receive priority attention due to discussions with the NRC. Subsequently, on May 19, 1989, the licensee provided the resident inspectors with information on affected valves for both Byron units and wrote a Justification for Continued Operation addressing those EQ valves which were believed to contain_ white Melamine torque switches. This included five valves in Unit 1 and two valves in Unit 2. Of the two Unit 2 valves, one was found to not contain a white Melamine switch upon operator disassembly and the other had its torque switch replaced during the Unit 2 maintenance outage in May 1989. Of the affected Unit I valves, 2 have had their torque switches replaced and 3 will be replaced as soon as plant conditions allo The licensee is also pursuing with Limitorque Corporation, the possibility of this deficiency affecting Limitorque operators with serial numbers other than those identified in the original Part 21 Repor . Follow-up on Allegations Involving Contractor QC Activities (RII1-89-A-0016) (99024)

Background: On February 1, 1989, the NRC resident inspectors received an allegation involving alleged inadequate Quality Control (QC) during installation of fire and radiation seals by the Hunter Corporation (a CECO contractor) and alleged intimidation of workers

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for voicing safety concerns. In response to the allegations, the-resident inspectors observed a fire seal repair for location P/Q 23/25 in the Unit 2 auxiliary electrical equipment room on February 15, 1989. On February 17, 1989, the resident inspectors met with QA personnel in the Project and Construction Services (PACS) organization to review records and discuss QA/QC practice On February 22, 1989, the resident inspectors met with Byron Station management to discuss the alleged concerns. On February 22 and 23, 1989, the resident ir.spectors met with managers and supervisors from both the Hunter and PACS organizations to discuss the alleged concern Summary: As a result of the inspection conducted, no violations or deviations were identified. The inspectors did note, however, that some improvement may be warranted in the documentation of QC inspection requirements, training of temporary workers, and performance of in-process QA audit Concern (1): In-process QC inspections of fire and radiation seal repair work by Hunter QC inspectors have been slipped. Inspections are not performed the same as when he previously worked here (initial construction) and now there are inadequate in-process inspection during installation of fire and radiation seal NRC Review: The resident inspectors witnessed the repair and QC inspection of a fire seal in the Unit 2 auxiliary electrical equip-ment room. The RIs reviewed the work package which contained the Field Take-Off, Installation and Inspection Record, the Electrical Equipment Entry Authorization, the Fire Protection Impairment Permit, the Seal Removal Request, and the Nuclear Work Request and held discussions with the QC inspector. The RIs learned that, in cases where the seal repair area is not obstructed by the installation of the damming material, the QC inspector typically performs the cleanliness inspection and the inspection of the damming at the same time, after the damming has been installed, and signs off for both of these inspection points. The QC inspector informed the RI that in cases where the installation of the damming material makes the seal repair area inaccessible, the QC inspector will perform the cleanliness inspection prior to the damming material being instclied. Subsequent to the observation of this repair work, the RIs ruiewed Hunter's Quality Assurance Program Site Work Instructions (SWI) No. 23A, Revision 1, "Firecode CT Gypsum Cement," No. 23, Revision 1, " Penetration Dams," and No. 25, Revision 0, " Installation of Regulatory Related Assemblies, "SWI No. 23A requires that 100% of seals identified as repairs shall be inspected by QC." In addition SWI No. 23A states, " Specific conditions to be observed during these inspections shall include, but will not be limited to: cleanliness, verification of proper lot numbers, spreading of cables to ensure proper flow of the gypsum and maintenance of and compliance to the Field Takeoff, Installation and Inspection Record. Results of these inspections shall be documented on the field Takeoff, Installation and Inspection Record.* Form HC-286 of SWI No. 23A entitled " Field Take-Off, Installation and Inspection Record" contains the QC inspection requirements for fire

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seal repairs. The QC inspection points identified are: (1)

Initial inspection (penetration clean of debris, identified / ready for damming operation); (2) Dam incpection/ released for sealing, l (3) Verification of gyp:,um lot number and slump test; and (4) Final j Inspection.

L During discussions with Hunter and PACS management, they informed ,

L the RIs that inspection points (1) and (2) above may be inspected "

simultaneously unless installation of the damming makes the seal area inaccessible for the initial cleanliness inspection. They also L 'said that, typically, there would be some method of indicating the-difference between QC hold points, witness points, and monitor points because each requires different levels of QC involvement.

, The RIs noted that there were no such indications of Form HC-286 -l and that this may be misleading to workers using the form.

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Conclusions: The RIs determined that the concern was not substantiated and that Hunter QC inspectors were in compliance with Hunter's procedures and practices for the inspection of fire seal repairs. The RIs pointed out to Hunter management that the Field Take-Off, Installation and Inspection Record (Form HC-286)

which is used in the field for documentation of repair and inspection activities may be misleading because there is no distinction between a mandatory QC hold point which must be signed off before work can proceed and a-QC inspection point which may be performed at QC's discretion.. Hunter management agreed to review the need for revisions to this form to more. clearly define QC inspection requirement In March 1989, Hunter revised Form HC-286 to add a section which defines a QC hold point, witness point, and monitor point. In addition, a note was added stating that the initial cleanliness inspection and the dam inspection may be inspected togetherUNLESS(emphasisorig.)theperformanceofthedam installation made the seal inaccessible for the cleanliness inspection. The RIs also suggested that improvements may be warranted in the training program for temporary worker Concern (2J: Hunter management is not providing adequate numbers of QC pe.'sonnel and is pressuring QC inspectors to put quantity ahead of qualit NRC Review: The RIs held discussions with a Hunter QC inspector, the Hunter Project Manager, the PACS QA Supervisor, the PACS Lead Construction Supervisor, and the PACS Construction Superintendent concerning the number of QC inspectors covering fire and radiation seal work and management's philosophy with regard to what is expected of QC inspectors. Hunter and PACS management informed the RIs that quality and safety were the top pricrity for everyone in their organizations, including QC and that no one was being directed to put quantity ahead of quality. This philosophy was conveyed during training and in day-to-day communications among supervisors and workers. Hunter management told the RIs that they were confident that they had provided an adequate number of QC inspectors to cover fire and radiation seal work and that these inspectors were not being overworke ,

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Conclusions: The concern was not: substantiated. . It appears that I L the alleger's. perception that there was an inadequate number of QC inspectors covering seal work stems from the fact that the alleger

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I thought that the inspectors were not performing all of the required QC inspections. The RIs concluded that there was adequate QC  !

L, inspection coverage for fire and radiation seal work performed u-during the Unit 2 refueling outag i, Concern (3):' One of the QC inspectors who was inspecting fire seal work was not qualified for this task due to insufficient training

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and experienc NRC Review: The RIs discussed the qualifications of the subject QC inspector with Hunter management and the Hunter QA Administrative Supervisor. The RIs reviewed Hunter Site Implementation Procedure (SIP) ~1.702, Revision 4 " Qualification of Inspection, Examination, Testing and Auditing Personnel," to determine the qualification and training requirements for a QC inspector in the area of fire and radiation seals." The RIs reviewed the subject inspector's training and qualification file including the certifications, education and experience records, and training records. The subject-inspector was certified as a Level II Civil and Structural' inspector with almost four years experience under a QA/QC program with a

'different contractor performing similar work.. The subject inspector met all of the education and experience requirements of SIP 1.702 for the. inspection of fire and radiation seals. The subject inspector id received formal training on the involved procedures and actices in addition to on-the-job training with a Level III QC '

inspecto Conclusions: The concern was not. substantiated. The subject QC inspector had adeauate qualification, experience, and training to perform the required inspections properl Concern (4): Hunter supervisory personnel ' engaged in intimidation oT a worker who expressed safety concern NRC Review: The RIs held' discussions with Hunter and PACS-management concerning the movement of the alleger from work on fire seals to work on insulation following his expression of concerns to his supervision. Hunter management informed the RIs that Hunter's procedures and practices were explained to the alleger to try to alleviate the alleger's concerns. Hunter management also stated that the alleger was @ en the opportunity to speak with Hunter  !

Quality Assurance personnel. When the alleger continued to express '

unwillingness to perform fire seal repairs in accordance with Hunter's procedures, the alleger was assigned to insulation wor The alleger did not suffer any loss of pay or position due to this action. The RIs also discussed alleged statements made by supervisory personnel which was perceived by the alleger as '

intimidation. Hunter and PACS management in turn held discussions with the named supervisory personnel concerning the alleged statements. All the supervisors denied making any of the alleged statements. Hunter and PACS management reiterated their policies

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r regarding workers who bring up concerns and how t. hose concerns are ,

to be' addressed. In addition, Hunter management published a memo to all production supervision outlining Hunter's policies in this area and providing a form to be filled out_when additional assistance,

' beyond answering of a question', is needed to address a worker's Concer Conclusions: This concern was neither substantiated nor refute The RIs could not reconcile the differenca in the statements made by the alleger and statements made by the subject supervisor The RIs did point out to PACS and Hunter management that it is-imperative that their philosophy with regard to workers' concerns-be understood throughout their organization Concern (5): Fire seal material (gypsum cement) with an expired

- shelf life was used in fire seal installation and repair work done during the' Unit 1 refueling outage (September - November 1988) and was possibility (January - Marchbeing)used 1989 . during the Unit 2 refueling outage NRC Review: The RIs held discussions with PACS persotnel concerning the use of outdated gypsum cement in fire Aal installations and

. repairs. The RIs were informed that the gy sum p cement being used had previously been certified with a shelf life of one year which had expired on January 12, 1989. The RIs reviewed Transco Products, Inc., Certificate of Compliance for.the Firecode CT Gypsum Cement being used for fire seal repairs and verifl_ed that the shelf-life expiration date was January 12, 1989, along with Nonconformance Report No. 6-89-03 stating that the' gypsum material had reached its expiration'date and that acceptance of the use of this material would be based on the results of a three hour rated fire test. The licensee had been working with the manufacturer of the gypsum, Transco Products, Inc., to extend the certified li k 9f the gypsum through testing. The licensee received certificatica from Transco dated February 16, 1989, extending the useful life of the gypsum to January 31, 1991, which the RIs reviewed along with the accompanying test report. Although the licensee had been using the expired gypsum for fire seal installation and repair work prior to receiving the certification, a nonconformance report had been written and the licensee had committed to track installation of the expired gypsum at every location it was use Conclusions: The concern was partially substantiated. The licensee did have expired gypsum cement installed in Unit 1 and they were using expired gypsum for installations and repairs during the Unit 2 outage. However, the licensea did have documentation of the nonconformance and were actively pursuing certification of the gypsum for a longer shelf life while at the same time keeping track of each location where the expired gypsum had been used. The licensee has received certification for extending the life of the gypsum and the RIs have no further concerns at this time.

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During ' llow-up of this allegation, the RIs inquired whether Hunter's QA organization had performed any in-process audits of fire or radiation seal work. The most recent in-process audit which could be produced took place from February 23 - 26, 198 The RIs also inquired whether the licensee's QA organization had performed any in-process audits of this type of activity. The last in-process audit of fire seal work was performed on April 21, 1988. This indicated that no in-process audits were performed by either the Hur.ter or Conrnonwealth Edison QA organizations during either the Unit 1 or Unit 2 refueling outages, whc0 the majority of fire ud radiation seal work was accomplished. The RIs noted that increasing the frequency of in-process audits by these organizations may be warrante Based on these reviews. this allegation is cohsidered close No violations or deviations were identifie . Evaluation of Licensee Performance (35502)

A rulew of site operations for the second quarter of 1989 was conducted to evaluate the performance of the licensee as it may require adjustment of the NRC inspection plan. The review included operational events and trends indicated by monthly status report ;

No violations or deviations were identifie . Meeting ManagementMeetings(30702)  !

On June 1,1989, Messrs. H. R. Denton, Director, Office of Governmental and Public Affairs, B. K. Grimes, Dire wor, Division of Reactor Inspection and Safeguards, NRR, C. J. Paperiello, Deputy Regional Administrator, Region III, E. G. Greenman, Director, Division of Reactor Projects, Region III, and the NRC Resident Inspectors attended the 05 ART Exit Meeting and press briefing along with Messrs. C. Reed, Senior Vice President, Nuclear Operations, R. Pleniewicz, Byron Station Manager and :nembers of their staff Egit Interview (30703)

The inspectors met with the licensee representatives denoted in paragraph 1 at the conclusion of the inspection on June 30, 198 The inspectors summarized the purpose and scope of the inspection and the findings. The inspectors also discussed the likely  ;

informational content of the inspection report, with regard to dccuments or processes reviewed by the inspectors during the inspection. The licensee did not identify any such documents or processes as proprietar l l

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