IR 05000277/1989020

Insp Repts 50-277/89-20 & 50-278/89-20 on 890730-0902.No Violations Noted.Major Areas Inspected:Onsite Regular, Backshift Insp (236 H Unit 2,135 H Unit 3) of Accessible Portions of Unit 2 & 3,operational Safety & Security

ML20248A432
Person / Time
Site:	Peach Bottom
Issue date:	09/21/1989
From:	Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20248A415	List: IR 05000277/1989020 ML20248A411
References
50-277-89-20, 50-278-89-20, NUDOCS 8910020215
Download: ML20248A432 (19)

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U. S. NUCLEAR REGULATORY COMMISSION'

REGION-I

' Docket / Report N /89-20 License No. DPR-44 50-278/89-20 DPR-56

~ Licensee: Philadelphia Electric Company Correspondence Control Desk

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P. O. Box 7520 Philadelphia, Pennsylvania 19101 Facility Name: ' Peach Bottom Atomic Power Station Units 2 and 3 Inspection At: Delta, Pennsylvania Dates: July 30 - September 2, 1989 Inspectors: -T.-P. Johnson, Senior Resident Inspector R. J.-Urban, Resident Inspector L. E. Myers, Resident. Inspector C. E. Sisco, Operations Engineer J. Gadzala, Resident Inspector L. L. Scholl, Resident Inspector M. J. Riches, Licensing Examiner

'T. W. Dexter, ecuri Specialist

' Approved Dy: [L960rflein Ch ef, .

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eactor Proje s S ction 28, j Division of.R a or Projects Summary-Areas Inspected: Special, on site regular, backshift and deep backshift inspection (236 hours0.00273 days <br />0.0656 hours <br />3.902116e-4 weeks <br />8.9798e-5 months <br /> Unit 2; 135 hours0.00156 days <br />0.0375 hours <br />2.232143e-4 weeks <br />5.13675e-5 months <br /> Unit 3) of accessible portions of Unit 2 and 3, operational safety,-radiation protection, physical security, control room activities, licensee events, surveillance testing, refueling and outage activities, maintenance, and startup testing activitie Results: The NRC concluded its around-the-clock coverage of Unit 2 startup activities. Oparator performance continued to be effective with noted improvements in periodic walkdowns of control room panels (section 4.1). The

. licensee observed flow oscillations on Unit 2 (section 4.2.1). A personnel error by a' test engineer caused an inadvertent opening of a safety relief valve

O215 890925

.PDR ADOCK 05000277

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, (sectioni4.2.2). ~The Unit'2. test' review group comp 1_eted their review of_ powe Jascensionitesting (section 5.1). The licensee's chemistry program to minimize-copper concentration was reviewed (sections 3.0.and 5.2). The-licensee iden-tified a failure to test fire ~ detectors. (section 6.2.1). . Licensee response to three bomb threats and an Unusual Event was effective (sections 10.2 and 4.2.4).

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L TABLE OF CONTENTS Page 1.0 Persons Contacted............................................ 1-2.0 Facility and Unit Status..................................... 1 l 3. 0 Chemi stry and Feedwater Copper Contro1. . . . . . . . . . . . . . . . . . . . . . . 2 4.0 Plant Operations Review...................................... 2 4.1 Operational Safety Verification, Shift Coverage and Station Tours.............................. 2 4.2 Follow-up on Events..................................... 3-4.3- Logs and Records............ ........................... 9 5.0 Engineering and Technical Support Activities................. 9 5.1 Power Ascension Test Results............................ 9 Modifications.......................................... 10 6.0 Review of Licensee Event Reports. . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 6.1 LER Re v i ew . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 6.2 L E R Fo 1 1 ow- u p . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 7.0 Surveillance Testing........................................ 13 8.0 Maintenance Activities...................................... 13 9.0 Radiological Controls....................................... 14 10. 0 P hy s i c a l S e c u ri ty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 10.1 Routine Observations................................... 14 ,

10. 2 Bomb T h re a t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

. 11.0 Assurance of Quality........................................ 15 12.0 Review of Periodic and Special Reports. . . . . . . . . . . . . . . . ... . . . . 15 13.0 Management Meetings......................................... 16

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DETAILS 1.0 Persons Contacted G. A. Bird, Nuclear Security Specialist J. B. Cotton, Superintendent, Operations T. E. Cribbe, _ Regulatory Engineer G. F. Daebeler, Superintendent, Technical

• J. F. Franz, Plant Manager D. P. LeQuia, Superintendent Services D. R. Meyers, Support Manager

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F. W. Polaski, Assistant Superintendent, Operations K. P. Powers, Peach Bottom Project Manager J. M. Pratt, Manager, Peach Bottom QA G. R. Rainey, Superintendent, Maintenance D. M. Smith, Vice President, Peach Bottom Atomic Power Station Other licensee and contractor employees were also contacte *Present at exit interview on site and for summation of preliminary finding .0 Facility and Unit Status 2.1 Unit 2 At the beginning of the period, the unit was at 90% power. On August 4, 1989, Unit 2 achieved 100% power and around-the-clock NRC shift coverage was suspended in accordance with the NRC restart inspection plan. On August 10, 1989, a shutdown was initiated and terminated when a surveillance test failed with the high pressure coolant injection (HPCI) system out of service. On August 13, 1989, the licensee reduced power to 30% to repair a turbine control valve scram pressure switch. The unit was returned to full power on August 15, 1989. The unit remained at or near full power for the rest of the period.

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2.2 Unit 3 Unit 3 continued in its refueling outage. Outage work, maintenance, modifications, and system restorations progressed. Preparations for core reload continue .3 Common The Lieutenant Governor of Pennsylvania toured Peach Bottom on August 21, 1989. The NRC Region I Regional Administrator and Projects Branch Chief toured the facility on August 31, 1989. An l Unusual Event was declared when the licensee noted vandalism to a number of Unit 3 motor control center breakers (section 4.2.4). . __ _______ _ _-_-__ _ _ _

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1 3.0 Chemistry and Feedwater Copper Control (71707)

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Some of.the Unit 2 reload fuel rods may be susceptible to crud' induced localized corrosior.L(CILC) which is-induced by copper. The fuel is of the same manufacture lot as the failed fuel at Limerick. It was l' manufactured in the same time frame and had common manufacturing

. techniques and testing method The licensee has taken a conservative approach to control coppe :An action plan was developed to control copper to 0.3 parts per billion (ppb) which is less than the fuel' warranty specification Unit 2 has historically operated at about 0.2 ppb at steady state 100% power after restart from an outage. To ensure that the copper would be efficiently removed from feedwater at restart, the action plan was to: (1) use a premix resin of increased efficiency; (2) use a longer precoat which was -found at Limerick to improve performance of the condensate demineralized filters (demin); (3) remove the demin from service when the differential pressure exceeds 20 psid;-(4)

' increase copper surveillance by installing an on-line ion chromato-graph for continuous copper analysis; and (5) maintaining power at less than 80% when copper exceeds 0.3 ppb in feedwater. Studies at Limerick provided the recommendations for the demins. CILC occurs at high power levels hence the basis for restricting power when copper is hig Chemistry action plans are formalized in procedure CH-10, Revision Parameters can be exceeded by writing a variance specified by the procedure. A. variance was written to exceed 0.3 ppb copper above 80%

power while the demins removed copper in the system. On August 18, 1989, copper was 0.315 ppb and was trending downward. At the end of the inspection period, copper was less than 0.3 ppb. The on-line ion chromatograph has been unsuccessful for analysis of copper because of standardization difficulties. The inspector reviewed procedure CH-10, the variance, and chemistry feedwater sampling methods and analysis. The inspector had no further question .0 Plant Operations Review 4.1 Operational Safety Verification, S_hift Coverage and Station Tours (71707,71715)

The inspector completed the requirements of NRC inspection procedure 71707, " Operational Safety Verification," by direct observation of activities and equipment, tours of the facility, interviews and discussions with licensee personnel, independent verification of safety system status and limiting conditions for operation, corrective actions, and review of facility records and log _ - _ - - _ _ _ _ - _ - - _ _ _ _ _ _ - _ _ _ __-__ _ _______-__--__ -___ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ - _ - _ _ _ _ - _ _ _ __

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The inspectors performed 157 total hours of on site backshift time,

' including 66 hours7.638889e-4 days <br />0.0183 hours <br />1.09127e-4 weeks <br />2.5113e-5 months <br /> of deep backshift and weekend tours of the facilit Deep backshift inspections included around-the-clock coverage in place at the beginning of the period from July 30 through August 4,198 This shift coverage during the Unit 2 restart power testing program 3 inspection was concluded once the unit achieved full power on August E

4, 198 Previous shift observations were documented in NRC Inspec-tions 277 and 278/89-15, 89-16 and 89-19. During this period the unit achieved full power. Operator performance continued to be effective with good procedure and technical specification complianc Shift turnover activities were noted as being -thorough. Communications, teamwork, and test control were good. Shift Managers and $hift i Supervisors continue to demonstrate effective command and control of their respective shifts. Problem identification and subsequent followup were noted as being thorough.

l Improvements were noted in operator attention to and periodic walkdown of control room panels. Weaknesses in this area were noted during NRC Inspection 277 and 278/89-19. For example, during the 11:00 p.m. to-7:00 a.m. shift on Augst 3-4, 1989, the licensed operators noted the following during periodic walkdowns (i.e., not during shift turnover):

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run light for "2B" condensate pump motor had extinguished, j --

"2B" APRM recorder was not responding to power increases,

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one channel of the main stack radiation monitor spiked apparently due to electrical nois Each of these abnormalities was quickly identified and effective corrective actions were taken. One area of pessible improvement in this area is for the licensee to ensure.that operators are produc-tively occupied during slow periods on backshift On August 2 and 31, 1989, the inspectors made entries to the Unit 3 drywell'to observe on going work activities, housekeeping, and radiological controls. The inspector reviewed several radiological work permits (RWP), protective clothing requirements and activities at the step-off pad. All drywell elevations were inspected. Hese-keeping and radiological controls were adequate. The inspector had no further question .2 Follow-up On Events Occurring During the Inspection (93702)

4. Unit 2 Reactor Recirculation Flow Oscillations Shortly after achieving full power on Unit 2, between 8:00 a.m. and 10:00 a.m. on August 8, 1989, the reactor operator observed small random step changes (600 gpm)

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- on'the "B" recirculation pump flow recorder. He then correlated.the flow steps to sma11' changes in core thermal power'(10-15 MWth) and informed the Shif t Manager. . I&C was contacted ~to determine the source of the random step. changes. The licensee determined that the recirculation flow control system was not-causing !

the. flow thanges. Analysis of plant revealed that 34 H steps had occurred.during.a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. period, with ten of 'l those occurring between 8:00 p.m. and 10:00 Reactor' Engineering was then consulted and they recalled GE SIL.467 dated July 22, 1988, which reported on a bi-stable

, flow phenomenon that had been experienced by other GE BWR Also, NRC Information Notice 86-110 dated December 31, 1986 addresses this behavio At 4:12 p.m., the "B" recirculation motor generator scoop tube was locked up to ensure that recirculation motor generator speed was not changing. Two more step changes in W flow were then observed and additional jet pump data were taken. The jet, pump data confirmed that.the flow steps were indeed due to'the bi-stable flow phenomeno Operations management was informed of these conclusions at 7:00 p.m., and this knowledge was turned over to subsequent

- shift A more detailed review of the data also revealed step changes of flow in.the "A" loop as well. But, since the flow steps occur much more frequently (38 per hour for A versus .75 per hour for B) and have a much shorter average duration (30 sec. for A versus 28 min. for B), the flow steps in the "A" loop appear as noise on the control room recorder. The SIL states that this phenomenon of turbulence induced flow oscillations is not a safety concern, but GE has been asked by the licensee to review the data and to perform a plant specific safety analysi The inspector followed up on this event by performing these actions:

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Reviewed control room chart recorders including recirculation drive flow, total core flow, generator MWe output,

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Reviewed process computer core thermal output calculations (P-1),

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Discussed oscillations with operators and engineers,

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Reviewed GE SIL 467 and NRC Information Notice 86-11 The inspector had the following questions:

(1) Was this bi-stable flow considered or observed last cyc16 for Unit 2 (1985 - 1987) after the recirculation pipe replacement?

(2) Did PORC review the bi-stable flow phenomena?

(3) Will the licensee (or GE) perform a safety analysis as recommended by the SIL?

The licensee adequately responded to the inspector's questions. The licensee stated that the bi-stable flow phenomena was considered by PORC and licensee engineering on restart after the Unit 2 pipe replacement outag It was apparently not observed; however, the licensee is reviewing past control room chart recorders to confirm this. The licensee has requested GE to perform the recommended safety analysi The inspector had no further questions at this tim .2.2 Inadvertent Opening of a Unit 2 Safety Relief Valve (SRV)

On August 9, 1989, at 6:38 p.m., Unit 2 SRV No. 71J was opened for 0.75 seconds during surveillance testing (ST) of the automatic depressurization system (ADS)

logi ST 1.9, ADS Logic System Functional Test, was being performed daily while the high pressure coolant injection (HPCI) system was out of service for maintenance. Two engineers performing the test failed to note a change in cable spreading room panels, and this resulted in momentarily jumpering terminal points in the wrong panel (20C33 vice 20C32).

Operator response to the open SRV was appropriate. The plant responded as expected. The ST was stopped and the licensee performed a critique and wrote an incident repor In addition, the. Plant Manager personally reviewed the event. The licensee determined that the root cause was a personnel error compounded by a poorly human factored procedure. The licensee made an

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Corrective actions included discussing the event with other test engineers reiterating the need for attention to detaii. The ST will be revised'to highlight the change in panel number. The. licensee.is also pursuing a project to install alligator clips on terminal' point that are routinely jumpered during testin '

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Subsequent licensee. review determined that the SRV lifting event was not reportable. The basis for this determination was the FSAR does not list the SRVs.as engineered safeguards features (ESF) system. The inspector discussed this item with licensee engineer 'The inspector concluded that.the SRV lifting does not technically meet the FSAR criteria for an ESF actuatio The inspector reviewed this event by performing the following:

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Reviewed incident report #2-89-62,

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. Discussed event with operators, engineers and management,

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Reviewed ADS logic prints,

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Reviewed ST 1.9,

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Reviewed control room chart recorders, alarm typer log and operator log The inspector verified that licensee actions were appropriate and were in accordance with TS requirement . High Pressure Coolant Injection (HPCI) System and Automatic Depressurization System (ADS) Inoperable for Unit 2 Due to recent performance tracking of the HPCI system, .the licensee determined that HPCI pump vibration was higher (about 3 mils) than it should be. From a review of past vibration data, the licensee concluded that vibration had always been high. The licensee removed the HPCI system from service to troubleshoot the vibration problem and to laser align the pum Due to removal of HPCI from service, technical specifications require testing of the ADS. At 11:36 p.m. on August 10, 1989, with Unit 2 at 100% power, the "B" channel of the ADS nine minute timer was found to be inoperable. The licensee made a one hour ENS phone call to report that Unit 2 was

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being shut down so that it could be in cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> since both HPCI and ADS were inoperable at 2:51 on August 11, 1989. The shutdown was terminated at 97%

power when the licensee successfully replaced and tested a new ADS time On August 11, 1989, a one-half gallon per minute oil leak was identified on the control piping to the HPCI governor valve during post-maintenance testing. The leak was found to emanate from a crack at a reducer fitting. The operations shift then declared the system inoperable and an ENS phone call was made to the NR On August 15, 1989, the licensee made an ENS phone call to retract the reportable call on August 11, 1989. After further investigation, the licensee determined that the oil leak was not reportabl After repairing the crack, a successful post-maintenance test was performed, laser alignment of the HPCI system only improved vibration slightly. Further investigation traced the HPCI pump vibration to the booster pump. Through discussion s;th the pump manufacturer (Byron Jackson) and other utilities, the licensee determined that the design of the booster pump impeller was causing the vibration proble Peach Bottcc as the original designed HPCI booster pump that util11c= a 4 vane inline impelle To reduce vibration, later booster pumps use a 4 vane staggered impeller, while the most recent booster pumps use a 5 vane staggered impelle The licensee is planning a modification to replace the existing impeller with a 5 vane staggered impelle The inspector spoke with system engineers, reviewed the ST, vibration data and the deportability evaluation for The inspector agreed with retracting the ENS phone cal HPCI pump vibrations will continue to be monitored by the inspector along with plans for the modification to the l HPCI booste .2.4 Unusual Event and ESF Actuations on August 29, 1989 The licensee declared an Unusual Event at 10:40 a.m. on August 29, 1989 when multiple damaged motor control center (MCC) breakers on Unit 3 were discovered. Maintenance l

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n personnel were' preparing to test an installed breaker for a Unit 3 cnndensate valve motor when they noticed cut wires

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insidefthe breaker unit. Maintenance supervision was notified and subsequently discovered other damaged breakers in a Unit 3 storage area in the SC feedwater heater room-

. located in the turbine building. The Shift Manager was then notified and declared an Unusual Event in accordance

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with emergency plan procedure ERP-101. The licensee inspected installed breakers on both Units 2 and 3 for potential abnormalities. None was found on Unit 2;-

however, one additional damaged breaker was found for a Unit' 3 dywell fan. An ENS. call was made at 11:01 The licensee also inspected other electrical equipment and control panels in the plant. Unit 2 and 3 control

. indications were also continuously monitored. Control room panel indications were normal. No apparent affect on Unit 2 was noted. The licensee heightened onsite security, notified the FBI, briefed operators on this event and initiated a claims security investigation (see section 10.3).

The licensee terminated the Unusual Event at 2:35 The inspectors were informed of this occurrance and responded by reporting to the control room. Independent panel walkdowns for Units 2 and 3 did not detect any abnormalities. The inspector toured most accessible areas-for Unit 2 and common systems and again nothing abnormal was noted. The inspector examined the damaged breakers in the feedwater heater room. Each affected breaker had multiple wire strands cut in random locations. A security specialist reported to the site to assist in the followu Between 11:00 a.m. and 10:30 p.m. the inspector made periodic walkdowns of control room panels and tours of plant aret Nothing abnormal was noted. The inspector also held discussions with licensee and NRC managemen At 5:20 p.m., maintenance on a Unit 3 reactor water level transmitter resulted in ESF actuations on both Units 2 and Unit 2 was at 100% and Unit 3 was in refueling with the core offloaded. A Unit 3 loss of coolant accident (LOCA)

signal was initiated. .No actuations occurred on Unit 3 because ESF systems were blocked for existing plant conditions. An expected Unit 2 RHR pump trip signal and alarm also occurred due to the Unit 3 LOCA signal as designed. No Unit 2 RHR pumps were running and therefore no actual trips occurred. The licensee reset the Unit 3 and 2 trip signals. In addition, the 3 operating cooling towers

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tripped as expected on a load shed condition. The cooling towers were restarted and an ENS call was mad l

The inspector concluded that licensee followup for these events was in accordance with plant procedure Notifications were consistent with the regulations. The licensee's completed investigation into the breaker vandalism will be reviewed in a future inspection. The LERs will also be reviewed. The inspe: tor had no further questions at this tim .3 Logs and Records (71707)

The inspector reviewed logs and records for accuracy, completeness, abnormal conditions, significant operating changes and trends, required entries, correct equipment and lock-out I-status, jumper log validity, conformance with Limiting Conditions ;

for Operations, and proper reporting. The following logs and '

records were reviewed: _ Control Room Shift Supervisor Log, . j Reactor _ Engineering Logs, Unit 2 Reactor Operator Log, Unit 3 l Reactor Operator Log, Control Operator _ Log, STA Log, QC Shift Monitor Log, Radiation Work Permits, Locked Valve Log, Maintenance Request Forms, Temporary Plant Alteration Log, Special Procedures Log, Information Tag Log, Annunciator Mode Log, Plant Status List, and Ignition Source Control Checklist Control Room logs were compared with Administrative' Procedure l A-7, " Shift Operations," and the Operations Manual. Frequent i initia11ng of entries by licensed operators, shift supervision, j and licensee site management constituted evioence of licensee !

review. No unacceptable conditions were identifie .0 Engineering and Technical Support Activities 5.1 Power Ascensic., Test Results (72700) l

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The licensee initiated a Test Review Group (TRG) to review completed !

power ascension test results for Unit Weekly meetings have been !

occurring since Unit 2 initial criticality. TRG membership includes ;

operations, system engineers, nuclear engineering department, I&C i engineers, specialized consultants and maintenance personnel. The !

TRG reports to the Plant Operations Review Committee (PORC). !

l The inspector attended the August 15, 1989, TRG weekly meetin At this meeting, power ascension tests for the 100% transient period were reviewed. Tests included the following: 1 I

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SP-1296, Reset the Runback Limiters

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SP-1227, Feedwater Heat Cycle Monitoring

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MAT 1695, RFP Min Flow Valves

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ST 26.1-2, Feedwater. Stability

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MAT 1790, IA Feedwater Heater Replacement

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MAT 5040, 2C Feedwater Heater Divider Hole '

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MAT 1457, Reactor Vessel Level

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MAT 1418, CAC Low Flow

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MAT 1834, Generator Seal 011 Vacuum Pump

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MAT 580, Post Accident Sampling .

The responsible engineer presented the test results, including test procedure completion, data acquisition system charts and data evaluations. All tests met their respective acceptance criteria. Open items and unexpected results were discusse The. inspector reviewed each completed test including test data and charts. No unacceptable conditions were noted. The-inspector concluded that the TRG performed a thorough revie Subsequent to this TRG Meeting, PORC concurred in TRG review and conclusion .2 Modifications.(37700,37828)

5. xygen Addition to Control Soluble Iron The licensee temporarily installed oxygen injection into the feedwater to the reactor. Electric Power Research Institute models of feedwater pipe erosion / corrosion have indicated that maintaining dissolved oxygen at 35 parts per billion (ppb) minimizes pipe erosion. Unit 2 has historically operated with a dissolved oxygen concentration of less than 15 ppb. The fuel warranty specifies a feed-water dissolved oxygen concentration of 10 to 200 ppb. The plant chemist stated that converting iron from a soluble to insoluble form will extend the life of the ion exchange mixed resins in the condensate demineralized filters and will show increased capacity for dissolved copper on the resi The licensee installed piping to the suction of the condensate pumps, located the oxygen at an acceptable location, and provided safety devices to prevent any malfunction from adversely affecting the plant. An on line feedwater continuous oxygen analyzer monitors the dissolved concentration. The oxygen addition rate is monitored to maintain the concentration at 30 to 40 pp ,

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The inspector reviewed-the safety evaluation per 10 CFR

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50.59, special procedure (SP) 1295, walked down accessible installed piping, discussed the oxygen injection with various cognizant individuals and observed the continuous oxygen analyzer when oxygen injection was initiated. The inspector had no further question .0 Review of Licensee Event Reports (LERs) -

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6.1 LER Review -(90712)

The inspector reviewed LERs submitted.to the NRC to verify that the

. details were clearly reported, including the accuracy of th description and corrective action adequacy. The inspector determined whether further.information was required, whether generic implications

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were indicated, and whether the event warranted on site follow-u .The following LERs were reviewed:

LER N LER Date Event Date Subject S-89-02~ Improperly filed safeguards information 08/10/89 07/11/89 2-88-12, Rev. 2 Failure to submit report required b .08/15/89 Technical Specifications (TS)

04/02/88-2-89-12, Rev. 1 Automatic scram due to FWLCS switch 08/15/89 05/19/89

• 2-89-13 Fire detectors not tested within TS 07/21/89 requirements 06/26/89

• 2-89-14 Fire detectors not tested within TS 07/20/89 requirements-06/20/89

• 2-89-15 Automatic scram due to EHC malfunction 8/18/89 7/21/89

• 2-89-16 Shutdown scram caused by a spiking neutron 8/18/89 monitor channel 7/22/89

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6.2 LER. Follow-up(92700)

l For LERs selected.for follow-up and review (denoted by asterisks above), the inspector verified that appropriate corrective action

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was taken or responsibility was assigned and that continued operation of the facility was conducted in accordance with .

Technical Specifications (TS) and did not constitute an unreviewed

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L safety question as defined in 10 CFR 50.59. Report accuracy, compliance with current reporting requirements and applicability to other site-systems and components were also reviewe .2.1' LERs 2-89-13 and 14 both concern licensee identified violations of.TS for failing to perform surveillance testing of fire detector LER 2-89-13 was due to poor communication of surveillance test (ST) status to shift management, and LER 2-89-14 was caused by a scheduling error. The first LER concerned a detector in the diesel generator Cardox room and the other concerned a detector in the radwaste laundry room. Both detectors were successfully tested upon discovery of noncomplianc Carrective action for LER 2-89-13 consisted of providing shift management with " overdue reports", and recently created "omitted reports". Omitted reports contain a list of deferred STs due to: 1) plant conditions; 2) blocked systems; or 3) not required to be operabl Shift management will now review these reports before declaring a system operable. The inspector determined the corrective action to be adequate to prevent recurrenc Corrective actions for LER 2-89-14 consisted of reviewing other STs to determine that grace periods were correct. Also, an administrative guideline will be revised to indicate that equivalent STs may have different grace periods. The inspector determined the corrective actions to be adequate to prevent recurrenc The inspector concluded that these two LERs meet the criteria of 10 CFR 2 Appendix C for a licensee identified violation and no Notice of Violation will be issued (277/89-20-01; 278/89-20-01).

6. LERs 2-89-15 concern a Unit 2 scram from 79% on July 21, 1989 and a shutdown scram on July 22, 2989, respectivel Both events were reviewed in NRC Inspection 277/89-19. The inspector had no further questions relative to these events and LER _ _ - _ _ _ _ _ _ _ _ _ _ - _ _ _ - _ _ _ _ _ _ _

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l 7.0 Surveillance Testing (61726,71707)

The inspector observed surveillance tests to verify that testing had been properly scheduled, approved by shift' supervision, control room operators were. knowledgeable regarding testing in progress,. approved procedures were being used, redundant systems or components were available for service as required, test instrumentation was calibrated, work was. performed by qualified personnel, and test acceptance. criteria were met. Daily surveillance including instrument channel checks, jet pump operability, and control rod operability were verified to be adequately performe Parts of the following tests were observed:

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ST 6.5-B, "HPCI Torus Suction Check Valve Operability (IST)," Rev. 8, April 8, 1989, performed on July 30, 1989,

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ST 3.3.1, "APRM Functional & Calibration Test (Scram & Rod Block)," Rev 21, March 31, 1989, performed on July 31, 1989,

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ST 9.7, "MSIV Partial' Closure and RPS Input Functional Test," Rev. 11, April 16, 1989 performed on July 31, 1989,

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ST 3.3.2, " Cal of the APRM System," Rev.13, November 15, 1988, performed on August 1, 1989,

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ST 8.1, " Diesel Generator Full Load Test," Rev. 33, June 8, 1989, performed on August 2, 1989,

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SI 2-L-2-72-BIFM, " Functional Test of ECCS B Compensated Trip System," Rev. 3, May 2, 1989, performed on August 2, 1989,

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SP 1296, " Upper Recirc Flow Limiter Calibration," Rev. O, July 21,1989, performed on August 3, 1989,

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SP 1295, " Oxygen Injection Into Unit 2 Condensate System,"

Rev. O, July 24, 1989, performed on August 3, 1989,

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" Main Steam Line Rad Monitor Functional and Calibration Test," Rev. 17, April 21, 1989, performed on August 4, 1989,

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ST 6.5-2, "HPCI Pump, Valve, Flow & Cooler," Rev. 3, July 18, 1989, performed on August 4, 198 ST 6.8-2, " Unit 2 A RHR Loop Pump, Valve, riow and Unit Cooler Functional," Rev. 2, August 4, 1989, performed on August 25, 198 No inadequacies were identifie .0 Mair.tenance Activities (62703)

The inspectors reviewed administrative controls included blocking permits, fire watches and ignition source controls, QA/QC involvement, radiological controls, plant conditions, Technical Specification LCOs, equipment alignment and turnover information, post maintenance testing and deportabilit Documents reviewed, if appropriate, included maintenance procedures (M), maintenance request forms (MRF), troubleshooting control forms (TCF), radiation work permits (RWP), material certifications, and receipt inspection . _ _ -____ ___ ___-________-__ - _ - _ _ _ _ _ -

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Portions of work on the following maintenance activities were observed:

Document Equipment Date Observed MR TIP Withdrawal Problem July 7,1989 TCF Scoop Tube August 3, 1989 TCF EHC July 22,1989 No inadequacies were identifie .0 Radiological Controls (71707)

.During the report period, the inspector examined work in progress in both units, including health physics procedures and controls, ALARA implementation, dosimetry and badging, protective clothing use, adherence to. radiation work permit (RWP) requirements, radiation surveys, radiation protection instrument use, and handling of potentially contaminated equipment and material The inspector observed individuals frisking in accordance with HP procedures. A sampling of high radiation area doors was verified to be locked as required. Compliance with RWP requirements was verified during each tour. RWP line entries were reviewed to verify that personnel had provided the required information and people working in RWP areas were observed to be meeting the applicable requirements. The inspector accompanied a radiation specialist on a tour of the facility. The purpose of this tour was to look for potential unacceptable radiological conditions in rooms in the facilit None were found. Additional details are described in NRC Inspection 277/89-21, 278/89-21. No unacceptable conditions were identified.

l 10.0 Physical Security (71707)

i 10.1 Routine Observations The inspector monitored security activities for compliance with the accepted Security Plan and associated implementing procedures, including: security staffing, operations of the CAS and SAS, check of vehicles to verify proper control, observation of protected area access control and badging procedures on each shift, inspection of protected and vital area barriers, checks on control of vital area access, escort procedures, checks of detection and assessment aids, and compensatory measures. No inadequacies were identifie .2 Bomb Threat A telephone bomb threat was received by the licensee at 1:21 p.m. on August 25, 1989. The call was received on a licensee phone lin _- - - - _ - _ _ -- _ _ _ _ - -

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L The Nuclear Security Specialist (NSS) was briefed, and a search was conducted by security personnel, even though.the licensee considered the threat to be non-credibl At 1:41 p.m., a second call was received on the same phone lin During this call, plant background noise was heard. The licensee

. then performed additional searches. The . licensee also positioned guards in specific areas of the plant to monitor activitie At 2:16 p.m., the NSS received a third call from the person. As a precaution, the licensee performed another searc The' resident inspector spoke with licensee security personnel and reviewed licensee response actions. The inspector also reviewed reportabiity requirements. Actions taken by the licensee were appropriate.for the circumstances and the inspector had no further question .0 Assurance of Quality Management Oversight Team (MOT) Meetings (40500)

The inspector attended the licensee's M0T meetings to review Unit 2 performance as follows:

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August 17, 1989 - 100% transient period,

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August 30, 1989 - 100% steady state perio Licensee personnel in attendance included M0T members (corporate and station management, and an industry observer) and line management personnel who made presentations. The August 30th meeting included a Plant Operations Review Committee Meetin The inspector attended these meetings and concluded that the licensee effectively evaluated their performance to date. This included both personnel and equipment evaluations. The licensee formulated strengths and weaknesses, defined follow-up action items, and concluded that Unit 2 has performed satisfactorily to date and that they were ready for two unit operatio .0 Review of Periodic and Special Reports (90713)

The inspector reviewed the following for accuracy, timeliness and acceptability:

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Unit 2 Inservice Inspection, dated July 25, 1989,

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Diesel Fire Pump Special Report, dated August 10, 1989, l

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Monthly Operating' Report for July 1989,

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Discharge of Ethylene Glycol, dated August 10, 198 The inspector had no questions regarding these report .0 Management Meetings 13.1 Preliminary Inspection Findings (30703)

A verbal summary of preliminary findings was provided to the '

Manager, Peach Bottom Station at the conclusion of the inspection. During the inspection, licensee management was periodically notified verbally of the preliminary findings by th resident inspectors. No written inspection material was provided to the licensee during the inspection. No proprietar information is included in this repor .2 Attendance at Management Meetings Conducted by Region Based Inspectors (30703)

Inspection Reporting Date Subject Report N Inspector

'8/28-9/1 HP routine 89-21/21 Dragoun 13.3 Regional Administrator Tour On August 31, 1989, the NRC Regional Administrator toured the Peach Bottom facility and met with licensee management. The inspector accompanied this. tour and attended the exit meeting.

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