IR 05000387/1997001

Insp Repts 50-387/97-01 & 50-388/97-01 on 970114-0224. Violations Noted.Major Areas Inspected:Operations, Engineering,Maint & Plant Support

ML20136J393
Person / Time
Site:	Susquehanna
Issue date:	03/14/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17158B998	List: IR 05000387/1997001 ML20136J365
References
50-387-97-01, 50-387-97-1, 50-388-97-01, 50-388-97-1, NUDOCS 9703200099
Download: ML20136J393 (38)

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U. s. NUCLEAR REGULATORY COMMISSION -

REGION I

I Docket Nos: 50-387, 50-388 License Nos: NPF-14, NPF-22

Report N /97-01, 50-388/97-01 i

Licensee: Pennsylvania Powar and Light Company l 2 North Ninth Street t Allentown, Pennsylvania 19101 i

l Facility: Susquehanna Steam Electric Station Location: P.O. Box 35 Berwick, PA 18603-0035 Dates: January 14,1997 through February 24,1997 L

'1 Inspectors: K. Jenison, Senior Resident inspector

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B. McDermott, Resident inspector J L. Eckert, Radiation Specialist i

J. Jang, Sr. Radiation Specialist )

J. Lusher, Emergency Preparedness Specialist l l

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Approved by: Walter J. Pasciak, Chief Projects Branch 4 Division of Reactor Projects

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9703200099 970314 PDR ADOCK 05000387  !

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EXECUTIVE SUMMARY Susquehanna Steam Electric Station, Units 1 & 2 NRC inspection Report 50-387/97-01, 50-388/97-01 This integrated maintenance, and plant inspection suppor included aspects of licensee operations, engineering

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in addition, it includes the results of announced inspections by Region inspectors for radiological effluent control and emergency preparedness .

Operations

An accumulation of hydrogen gas in excess of the Technical Specification (TS)

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concentration limit occurred in the Unit 2 main condenser offgas system. The the use of jumpers in the high hydrogen isolation circuit. system d Operators did not manually initiate a system isolation when a TS required alternate sample showed the hydrogen concentration to be 400% of the automatic system's . The setpoint operators' failure to implement the actions of the high hydrogen alarm response procedure violatio in response to multiple indications of a high concentration is cited as a

A Unit 2 RHR pump failed to start when a limit switch on it's suction valve did not operate properly. As a result of the switch failure, the 'D' RHR pump was inoperable with the reactor in Condition 1 for greater than the 7 days and 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowed by Technical Specifications. PP&L has implemented appropriate correctiv actions. NRC review of the event determined the failure was beyond reasonable licensee control and, as such, the failure to meet TS is being treated as a non cite -

violation, consistent with section VI.A. of the NRC Enforcement Polic *

PP&L identified that operators made a reactor mode switch change placing Unit 1

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in wereCondition not met. 2 (Startup), when the limiting conditions for operation of TS 3 51 . .

PP&L determined that human performance was the root cause of the event and implemented corrective actions focused on procedural enhancemen and training. This violation of TS 3.0.4 is being treated as a licensee identified non-cited violatio _ Maintenanc *

Problems with the material condition and reliability of the condensate transfer system and the Unit 1 reactor core isolation cooling (RCIC) system steam line drain pot have not been resolved by PP&L, despite their recurrence over the last year .

PP&L's failure to maintain a reliable condensate transfer system necessitates into off normal procedures for loss of emergency core cooling system (ECCS)

fill pressure and unplanned starts of certain ECCS pumps. The failure to resolve t additional steam leaks and RCIC system unavailability. reactor c ii

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• The failure to properly perform maintonance activities on the 'B', 'C' and 'E' .

emergency diesel generators resulted in degradation of their generators' slip ring assemblies. Although operability of the diesel generators was not challenged, the potential existed for common cause degradation due to inadequate performance of maintenance. The failure to properly perform this maintenance, in accordance with procedures, constitutes a violation of minor consequence and is being treated as a non-cited violation consistent with Section IV of the NRC Enforcement Policy.

e The Susquehanna Unit 1 and Unit 2 switchyards are considered to be within the scope of the maintenance rule program and are being monitored by PP&L on the plant level. The inspector found that PP&L was meeting the maintenance rule requirements with regard to monitoring of the switchyards.

Enaineerina e Nuclear System Engineering provided a through revision of an operability determination for a degraded power supply impacting low pressure coolant injection valves. Although the initial operability determination made by operators on a backshift was upheld, the initial justification for the degraded condition did not have a technical basis and relied entirely on meeting a Technical Specification surveillance requirement.

• On December 10 and on December 21,1996, the 'E' emergency diesel generator (DG) failed a functional test. The cause of'the first f ailure was a high resistance contact on the DG bridge transfer switch which was not maintained as recommended by the manufacturer. The second test failure was caused by two damaged gate firing circuits. The gate firing circuits were damaged during inadequate troubleshooting and testing activities performed by the license The initial Nuclear System Engineering (NSE) operability determination following the first f ailure was determined to be weak, but the NSE activities following the second failure were determined to be very strong and aggressive. Causal factors for the failures included inadequate control of vendor recommendation for preventive maintenance and vendor manual documentation, and inadequate control of pre-exercising equipment that may mask weaknesses that would affect TS surveillance testing activities. A violation was issued for inadequate corrective actions in response to the vendor's notification and previous like conditions, and the licensee's troubleshooting and testing activities following the first failure.

Plant Sucoort e Oversight of the Radiological Effluent Technical Specifications program was goo Corrective actions for audit findings were considered to be appropriate; the effluent radiation monitoring system calibration program was well maintained; and maintenance and surveillance of air cleaning and ventilation systems were very good. The Offsite Dose Calculation Manual and Annual Radioactive Effluent Release Report were well-detaile iii

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The licensee continues to maintain a good emergency preparedness program. The

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emergency response plan and implementing procedures were current and effectively implemented. The emergency facilities, equipment, instruments and supplies were found to be maintained in a state of readiness. All required inventories were completed. A sampling of emergency response organization personnel tram.'ng records and the records pertaining to on-shift dose assessment indicated the training and qualifications were current. A review of quality assurance reports found that quality assurance audits were thorough and that they satisfied NRC requirements.

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TABLE OF CONTENTS ..

1. O p e r ati o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 1 O1 Conduct of Operations ................................... 1 01.1 Offgas System Recombiner Hydrogen Accumulation ......... 1 02 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . 3 02.1 Unit 2 'D' RHR Pump Start Failure . . . . . . . . . . . . . . . . . . . . . 3 04 Operator Knowledge and Performance ........................ 5 04.1 Operator Response to Operational Occurrences . . . . . . . . . . . . . 5 08 Miscellaneous Operations issues ............................ 5 08.1 Mode Change Requirement Not Met . . . . . . . . . . . . . . . . . . . . . 5 08.2 Review of Licensee Event Reports ...................... 6 11. Maintenance .................................................. 8 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . ............. 8 M 1.1 Planned Maintenance Activity Review . . . . . . . . . . . . . . . . . . . . 8 M1.2 Surveillance Test Activity Sample Reviews . . . . . . . . . . . . . . . . 9 M2 Maintenance and Material Condition of Facilities and Equipment ..... 10 M2.1 Material Condition of Plant Equipment and Systems . . . . . . . . . 10 M4 Maintenance Staff Knowledge and Performance ................ 11 M4.1 Review of Emergent Maintenance 'E' Diesel Generator Preventive Maintenance ............................ 11 M6 Maintenance Organization and Administration . . . . . . . . . . . . . . . . . . 12 M 6.1 Verification of Maintenance Rule Requirements - Switchyards . . 12 111. Engineering . . . .............................................. 14 E2 Engineering Support of Facilities and Equipment ................ 14 E2.1 Operability Determination For RHR Swing-bus MG Set ....... 14 E2.2 Engineering Support of Diesel Generator Maintenance ....... 15 E2.3 Bypass Indication System (BIS) Design . . . . . . . . . . . . . . . . . . 18 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 E Review of FSAR Commitments ....................... 19 I V . Pl a n t S u p p o r t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 R1 Radiation Protection and Chemistry Controls (RP&C) ........ .... 19 R Implementation of Radioactive Liquid and Gaseous Effluent C o nt rol Pr o g r a m s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 R2 Status of RP&C Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . 20 R2.1 Calibration of Effluent / Process Radiation Monitoring Systems (RMS)......................................... 20 R2.2 Calibration of Area Radiation Monitoring Systems (ARMS) .... 21 R2.3 Air Cle a ning System s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 R3 RP&C Procedures and Documentation ....................... 23 R6 RP&C Organization and Administration . . . . . . . . . . . . . . . . . . . . . . . 23 R7 Quality Assurance (QA) in RP&C Activities . . . . . . . . . . . . . . . . . . . . 24 R8 Miscellaneous RP& C lssues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 R Review of FSAR Commitments . ..................... 25 v

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TABLE OF CONTENTS (Continued)

P1 Conduct of Emergency Preparedness (EP) Activities . . . . . . . . . . . . . . 25 P2 Status of EP Facilities, Equipment, and Resources . . . . . . . . . . . . . . .

P3 26 P5 EP Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Staff Training and Qualification in EP . . . . . . . . . . . . . . . . . . . . . . . . 28 P6 EP Organization and Administration . . . . . . . . . . . . . . . . . . . . . . . . .

P7' 29 Quality Assurance (QA) in EP Activities ...................... 29 P8 Miscellaneous EP Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 P Review of FSAR Commitments ....................... 30 V. Manageme nt Meeting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 X1 Exit Meeting Summary .................................. 30 l

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Report Details ,

Summarv of Plant Status Unit 1 began this inspection period at 100 percent power. On January 24, a traffic accident near the plant caused a loss of the Emergency Notification system, however commercial phone lines were still available. Subsequently PP&L discovered that the call back portion of the Tele Notification System for emergency responders was not functional and made a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> NRC notification as required by 10 CFR 50.72. On February 1, PP&L made an a telephone notification to the NRC after a Unit 1 reactor recirculation pump controller failed, causing a reactor power increase to 103.5% of the rated core thermal power limit. Operators reduced power to less than 100% within approximately 65 seconds of the f ailure. Planned power reductions were made during this inspection period in support of control rod stroke testing, control rod pattern adjustment, and routine turbine valve testing.

Unit 2 began this inspection period at 100 percent power with all control rods fully withdrawn. Power reductions were made during this period in support of repairs for a main condenser tube leak and control rod hydraulic control unit maintenance. On February 15, Unit 2 was at 95% power when a damper for the 'B" emergency switchgear room cooling train failed. On February 16, the 'A' emergency switchgear room cooling fan failed. The loss of both trains of emergency switchgear room cooling was reported to the NRC on February 16, as required by 10 CFR 50.7 . Operations 01 Conduct of Operations'

01.1 Offaas System Recombiner Hydronen Accumulation Inspection Scone (71707)

On December 19,1996, hydrogen gas accumulated in the off gas recombiner system after problems occurred during a swap of the recombiner train serving the Unit 2 main condenser. The inspector observed the response of control room operators to this event and subsequent meetings held to evaluate the occurrenc Observations and Findinas At 7:45 a.m., operators began to swap alignment of the Unit 2 main condenser from the Unit 2 offgas train to the common offgas train in accordance with procedure OP-222-OO1. In accordance with procedures, the automatic Hi- Hi

' Topical headings such as 01, M8, etc., are used in accordance with the NRC standardized reactor inspection report outline. Individual reports are not expected to address all outline topic l

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.- 2 hydrogen isolation signals for both the Unit 2 and common offgas trains were manually bypasse i At 8:15 a.m., a chemistry grab sample was taken from the Unit 2 offgas recombiner train as required by TS Action Statement 3.3.7.11 when the automatic ,

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isolation circuit is inoperable. The grab sample contained a hydrogen concentration of 0.24%. ,

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At 10:00 a.m., two automatic valves for the Unit 2 offgas train failed to close as expected when operators attempted to isolate the Unit 2 offgas trai Consequently, the Unit 2 train was not completely isolated. Operators placed the transfer evolution on hold pending an investigation of the valves that failed to close by maintenance personne l At 12:18 p.m., Chemistry informed the control room that an offgas sample showed {

an 8% hydrogen concentration. Based on this sample, operators began preparations to manually close valves for the Unit 2 recombiner lines in order to complete the isolation of the Unit 2 trai At 12:45 p.m., chemistry personnel informed the control room that a confirmatory sample indicated a 9% hydrogen concentration. Operations management was informed and preparations were made to back out the recombiner transfer procedure and place the Unit 2 recombiner train back in servic The inspector discussed the offgas system alignment and the results of the'

chemistry samples with Operations management. Specifically, the inspector questioned whether the offgas system procedures required operators to manually initiate a system isolation since the automatic system isolation setpoint had been exceede At 1:08 p.rn. operators manually initiated an offgas system isolation in accordance with AR-231-001 based on confirmation of a hydrogen concentration greater than the hi-hi hydrogen setpoint of 2%.

TS 3.12.2.6 requires the hydrogen concentration in tha main condenser offgas system to be limited to less than or equal to 4% by volume. With the concentration of hydrogen greater than 4%, the concentration must be restored to below the limit within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. During this event, the hydrogen concentration in the offgas system exceeded the 4% hydrogen limit of TS 3.11.2.6 for less than 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. However, operators failed to recognize entry into this limiting condition for operatio Based on review of this event, the inspector determined the following:

• Operators did not implement the actions of AR-231-001 when the first grab sample showed the hydrogen concentration at 400% of the automatic isolation setpoint (2% hydrogen).

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• Operators failed to recognize entry into the TS limiting conditions for operation (LCO) when the hydrogen concentration exceeded 4%.

• A manual bypass of the offgas system's automatic high hydrogen isolation signal is routinely made to inhibit spurious isolations from moisture in the system during transfer activities. The inspector determined that although this activity is not precluded by TS, the use of alternate grab samples during a routine evolution is not a conservative method to compensate for a design proble * The operational practice of bypassing the automatic isolations and history of hydrogen detection system problems led to a general understanding that the hydrogen indication in the control room was unreliable during recombiner transfer evolution NRC Region I has requested a review of the SSES TS for the offgas system automatic high hydrogen isolation by the Office of Nuclear Reactor Regulatio Specifically, the review was requested to determine the adequacy of: 1) the current TS requirements for alternate grab samples,2) the SSES practice of bypassing automatic system isolations signals during transfer of recombiners, and 3) the applicability of the standard improved Technical Specifications to the SSES desig Conclusions Hydrogen gas accumulated in the Unit 2 offgas recombiner train, reaching a concentration greater than Technical Specification limits and the system did not

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automatically isolate, as designed, prior to reaching this concentration because

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operators bypassed the isolation circuit. Operators did not manually initiate a

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system isolation after both an alarm and an alternate grab sample showed a

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hydrogen concentration in excess of the automatic isolation setpoin The operators' failure to manually initiate an offgas system isolation as required by the alarm response procedure for high hydrogen concentration is cited as a violation. (VIO 388/97-01-01)

02 Operational Status of Facilities and Equipment O 2.1 Unit 2 'D' RHR Pumo Start Failure Insoection Scoce (92700)

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The inspector conducted an on site review of the subject plant condition in order to verify that PP&L had met the reporting requirements cf 10 CFR 50.73, that PP&L had taken or planned appropriate corrective actions, and that continued operation of the facility is being conducted in accordance with Technical Specifications and other regulators; requirements.

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b. Observations and Findinas I On November 21,1996, the 'D' RHR pump automatically tripped when operators attempted to start it for suppression pool cooling. A protective circuit for the pump was found energized and would have prevented a start of the pump in either the shutdown cooling or low pressure coolant injection (LPCI) mode )

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PP&L's investigation determined that Rotor #3 of the 'D' RHR pump's suction valve motor actuator (F004D) did not operate consistently with the rotors used for valve control. Contacts on Rotor #3 continued to show the valve was not full open after its companion rotors had reached their full open alignment, cutting off power to open the valve. This sequence difference caused the 'D' RHR pump trip relay E11 A-K22B to remain energized, enabling the pump's protective tri PP&L determined that Rotor #3 of the actuator for valve F004D had been in this condition since November 14,1996, when the valve was last operated for a routine surveillance. Based on the control room log entries, the inspector determined that the 'D' RHR pump was inoperable for greater than 7 days and 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />. TS 3.5.1, Action b.1, allows 7 days for restoration of a single inoperable RHR pump, if the 7 day period is exceeded, Action b.1 further requires that the unit be in hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Operators were not aware of the failure and therefore no action was take PP&L's initial response to this event was to verify the proper condition of all other Unit 1 and Unit 2 RHR pump trip relays. Based on a recommendation from NSE, operators cycled valve F004D and the pump's protective relay deenergize Additional strokes of F004D in an attempt to repeat the original failure were not successful. The root cause was later determined to be a minor variances (0.135 seconds) in the drop out time of Rotor #3 relative to Rotor #1. As an interim action, temporary procedure changes were implemented to require verification that the RHR pump trip relays are deenergized following routine RHR valve surveillances and system alignments. Long term corrective actions consist of enhancements to maintenance procedures for valve actuator limit switches and rework of all the RHR pump suction valve actuator switche The inspector concluded that PP&L's failure to place the unit in hot shutdown after 7 days and approximately 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> was a violation of the TS requirement However, the safety significance of this violation was minor due to the fact that all other ECCS sub-systems were operable during this time and the operability of the

'B' RHR pump maintained 100% functional capability in the affected LPCI sub-system. Corrective actions for this event were reviewed and found to be goo This violation resulted from an equipment failure that was not avoidable by reasonable licensee quality assurance measures or management controls, and therefore is not being cited, consistent with section VI.A. of the NRC Enforcement Polic ..

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5 , Conclusions A Unit 2 'D' RHR pump failed to start when a limit switch on it's suction valve did not operate properly. As a result, the 'D' BHR pump was inoperable with the reactor in Condition 1 for greater than the 7 days and 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowed by Technical Specifications. The licensee implemented appropriate corrective actions and NRC review of the event determined the failure was beyond reasonable licensee control. This issue is being treated as a non cited violation, consistent with section VI.A. of the NRC Enforcement Polic ,

04 Operator Knowledge and Performance 04.1 Operator Response to Operational Occurrences Control room operators were observed during performance of their on-shift responsibilities throughout the inspection period. The inspectors verified that appropriate alarm response procedures were implemented and that the required actions were completed. The following activities were observed and the inspector determined that operators responded well to these occurrence ON-158-001 Loss of Reactor Protection System, February 19,1997 OP-257-004 SPDS UPS, February 14,1997 AR-106 HVAC Reactor Building Fan Damper Trouble, February 24,1997 08 Miscellaneous Operations issues 08.1 Mode Chanae Reauirement Not Met Insoection Scope (92700)

As on site follow up of this event, the inspector verified that the reporting requirements of 10 CFR 50.73 had been met, that appropriate corrective action had ;

been taken, and that continued operation of the facility was conducted in 4 accordance with Technical Specifications and other regulatory requirement I Observations and Findinas During the restart of SSES Unit 1 on October 19,1996, following it's 8th refueling outage, operators repositioned the reactor mode switch to "Startup," changing the I reactor's operating mode from " Cold Shutdown" (Condition 4) to "Startup" (Condition 2). TS 3.5.1 requires two operable LPCI subsystems in Condition 2, and at the time operators changed the mode switch position, the 'B' loop of LPCI had not been made operable. Making a reactor mode change to Condition 2 when an applicable LCO is not met constitutes a violation of Technical Specification 3. I

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. 6 The error was identified by the Unit Sup3rvisor (US), who then directed operators to align the 'B' LPCI subsystem. The alignment was completed and the subsystem was declared operable 44 minutes after the mode switch had been placed in

"Startup."

PP&L attributes the event to human error. While in Condition 4, the US determined !

that an LCO was not required for the RHR pumps during the process of aligning it I for the standby LPCI mode. However, the US later f ailed to recognize that the RHR :

realignment was not complete when he authorized the mode change. In the LER, I PP&L reported that the US lost focus on the requirement of TS 3. In response to this event, PP&L counseled the US, reviewed the event with all of.arations personnel, and implemented procedural enhancements to the operating procedure which controls the "Startup" mode change. Actions to prevent recurrence described in the LER include a review of this event with operations personnel during Training Cycle 96-6, and an evaluation to determine if modifications that would allow faster transition from shutdown cooling to the LPCI l mode would be cost beneficia '

The inspector reviewed changes PP&L made to procedure GO-100-002 in response to this event. The procedure now provides steps to alert the US that LPCI must be

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l restored and the LCO must be cleared, prior to making the mode change. The inspector also reviewed the lesson plan for Manager of Operations Agenda

, discussion for training cycle 96-6. As with the procedures, this training focused on i a US responsibility to maintain an overall view of plant conditions, evolutions in progress, and the goals to be achieve As discussed, making a reactor mode change to Condition 2 when an applicable LCO is not met constitutes a violation of TS 3.0.4. This licensee-identified and corrected violation is being treated as a non-cited violation, consistent with Section Vll.B.1 of the NRC Enforcement polic Conclusions PP&L identified that operators made a reactor mode change, placing Unit 1 in Condition 2 (Startup), when the limiting conditions for operation of Technical Specification (TS) 3.5.1 were not met. PP&L determined that human performance was the root cause of the event and implemented corrective actions focused on procedural enhancements and training. This violation of TS 3.0.4 is being treated as a licensee identified non-cited violatio .2 Review of Licensee Event Reoorts Insoection Scoce (90712)

The inspector reviewed Licensee Event Reports (LERs) submitted to the NRC to verify that the details of the event were clearly reported, including the accuracy of description of the cause and adequacy of corrective action. The inspector

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determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite followup. The following LERs were reviewed during this inspection period.

b. Observations and Findinas (Closed) LER 50-387/96-008: Alternate Continuous Gaseous Effluent Sampling On August 2,1996, Unit 1 was in Condition 3, when the 'A' Engineered Safeguard System (ESS) bus was inadvertently deenergized during maintenance work (reference LER 50-387/96-007). Loss of the 'A' ESS bus caused a loss of the normal effluent sample flow from the Unit 1 turbine building and reactor building vents. TS 3.3.7.11-1 Action 112, states that effluent releases via this pathway may continue for up to 30 days provided samples are continuously collected with auxiliary sampling equipment. PP&L determined that the alternate sampling was not implemented in a timely manner because personnel f ailed to question the effects of alarms that indicate a loss of vent flow, and placed priority on restoration of the 'A' ESS bu The failure to follow procedures is a violation of NRC requirements. This licensee identified and corrected violation is being treated as a non-cited violation, consistent with section Vll.B.1 of the NRC Enforcement Polic (Closed) LER 50-387/96-014: Completion of Technical Specification Required Shutdown On October 19,1996, with Unit 1 starting up, the acoustic monitor for the 'L' main steam safety / relief valve (SRV) began to indicate the SRV was open when alternate control room indications showed that it was closed. The acoustic monitor was declared inoperable in accordance with TS 3.3.7.5. Since it was not expected that the monitor could be repaired without a drywell entry, the unit was shutdown in accordance with TS 3.3.7.5, action 80 This issue was previously reviewed in NRC Inspection Report 96-11, section O (Closed) LER 50-388/96-009: Unit 2 'D' RHR Pump Start Failur The event is discussed in section O2.1 of this report and the LER is therefore close (Closed) LER 50-387/96-013: Mode Change Requirement Not Met The event is discussed in section 08.1 of this report and the LER is therefore close .

,. 8 Conclusions The events reported by PP&L in the Licensee Event Reports (LER) reviewed during this period were appropriately reported and provided an accurate description of their causes and corrective actions. The inspector determined that for the LERs discussed in brief, the corrective actions were reasonable, that no generic implications were involved, and that these events require no additional onsite followup. Two of the LERs listed were reviewed in greater detail as discussed in sections 02.1 and 08.1 of this repor II. Maintenance M1 Conduct of Maintenance M 1.1 Planned Maintenance Activity Review insoection Scone (62707)

A variety of maintenance activities were reviewed on the basis of their complexity, safety (or risk) significance, or other considerations. A sample of work permits,

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equipment tagouts, procedures, drawings, and vendor technical manuals associated with these maintenance activities were reviewed as part of the inspection. Through observation of the maintenance activities and interviewing maintenance personnel, the inspector sought to verify that the activities were performed in accordance with procedures and regulatory requirements, that personnel were appropriately trained and qualified, and that appropriate radiological controls were followe Observations and Findinas The fcitowing maintenance activities were reviewed through direct observation and/or review of the completed work packages:

WA S70402 Unit 1 Battery Charger 1D633 Corrective Maintenance, February 14,199 WA S72516 'B' Diesel Generator Slip Ring Brush investigation, February 5,199 WA S72517 'C' Diesel Generator Slip Ring Brush Investigation, February 6,199 WA V70291 High Pressure Coolant injection (this WA is associated with CR 96-2240)

WA S70254 High Pressure Coolant injection WA S79015 Destructive Examination of Thermolag Material

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WA V70300 Safety Parameter Display System-Uninterruptible Power Supply Conclusions in general, the work activities were adequately controlled and observed portions were performed in accordance with station procedures. In some cases,it was not apparent to the inspector that work groups were using procedures as discussed in NDAP-QA-500, Conduct of Maintenance. The licensee's followup for problems  !

identified with the diesel generator slip rings is discussed in section M2 of this ,

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M1.2 Surveillance Test Activity Samole Reviews Insoection Scope (61726)

The inspectors observed portions of selected surveillance tests involving different technical disciplines for safety-significant system ' Observations and Findinos Through observation and review of records, the inspectors verified that the test activities were properly released for performance, that the test instrumentation was within its current calibration cycle, and that it was being performed by qualified i personnel in accordance with approved test procedures. The inspectors also verified that the tests conform to TS requirements and that applicable LCOs were taken. The following activities were reviewed during this period:

SO-024-001 'A' Diesel Generator Monthly Surveillance, February 3,1997  ;

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SO-259-OO2 Quarterly Suppression Chamber Vacuum Breaker Test, February 14,1997 SI-280-308 18 Month Calibration of RWCU, MSIV, PCIS, Secondary Containment isolation Reactor Vessel Water Levels, February 21,1997 Conclusions The routine surveillance activities observed during this inspection period were adequately performe .

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M2 Maintenance and Material Condition of Facilities and Equipment M 2.1 Material Condition of Plant Eauioment and Systems Insoection Scone (62707)

During routine observations of plant operations the general condition of equipment was examined to determine the effectiveness of licensee controls for identification and resolution of maintenance related problem Observations and Findinas The non-safety related condensate transfer system (CTS)is shared by both SSES units and provides the keep-fill system for the emergency core cooling systems'

(ECCS) discharge piping full. The CTS is designed to keep the systems' discharge ,

piping full to preclude water hammer transients that could prevent the ECCS ;

' systems from providing their intended safety function. Since January 1996, the CTS has experienced seven functional failures that have caused some ECCS subsystems to loose keep-fill pressure. During these events the ECCS subsystems were either declared inoperable or operators started the ECCS pumps to prevent voids in their discharge piping when the keep-fill pressure decreased to approximately 50 psig. Although PP&L determined that none of the 1996 failures l were repeat maintenance preventable functional failures, the events. resulted in i entries into off-normal operating procedures, inoperable ECCS equipment, and ;

unnecessary starts of ECCS equipment. In one case, a human error led to loss of j the Unit 1 'B' loop of RHR and the 'B' loop of core spray, placing the unit in TS l 3.0.3. One 1997 failure is still under review by PP&L as a possible repeat maintenance preventable functional failure. Based on review of these events, the inspector determined that PP&L is not maintaining the CTS such that it will provide the minor, but continuous inflow into the discharge lines to make up for leakage across the ECCS pump discharge check valves as described in the FSA The Unit 1 reactor core isolation cooling (RCIC) system steam line drain pot has not worked properly since June 1995. To compensate for the non-functional steam line drain pot, a manual bypass valve was opened by operators in accordance with alarm response procedures and recommendations from Nuclear System Engineerin Following the unit's restart from the Fall 1996 refueling outage, s stears leak developed as a direct result of the drain pot bypass valve being continually open (Reference NRC Inspection Report 96-11). Although the licensee has made several attempts to solve the drain pot problem, these maintenance activities have not been successful. The inspector determined that PP&L has not been effective in correcting this long standing problem with the potential create additional steam piping leaks and render the RCIC system inoperabl Conclusions The material condition and reliability of the condensate transfer system and the reactor core isolation cooling system steam line drain pot have not been corrected

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by PP&L, despite continued problems over the last year. PP&L's failure to maintain a reliable condensate transfer system continues to necessitate entry into off normal procedures for loss of ECCS keep-fill pressure and unplanned starts of certain ECCS pumps. The failure to correct the RCIC drain pot has the potential to cause additional steam leaks and RCIC system unavailability.

M4 Maintenance Staff Knowledge and Performance M4.1 Review of Emeraent Maintenance 'E' Diesel Generator Preventive Maintenance Inspection Scope (62707)

On January 17,1997, during inspection of the partially disassembled 'E' diesel generator, the inspector found that one of generator's stationary brushes was not in contact with its respective collector ring. In response to the inspector's observation, the licensee initiated a condition report (CR 97-0096) to documented the problem. The inspector reviewed PP&L's operability determination, maintenance procedures, and ' subsequent investigations related to this observatio Observations and Findinas Each generator has two slip rings and eight brushes connecting the field wiring to the rotating assembly. The four brushes for each slip ring are each held in contact with the ring by a spring arm. A retaining clip is used to keep the brush from moving completely out of its holder, but does not normally contact the brus Based on interviews with electrical maintenance personnel, the inspector determined that the problem with one 'E' DG brush had been recognized during a maintenance run earlier that week. Licensee personnel stated that the condition would be corrected during the routine maintenance surveillance SM-024-E01,

" Diesel Generator 'E' 18 Month inspection." The inspector noted that the 'E' DG was not considered operable between the time the maintenance personnelidentified the problem and the maintenance surveillanc The inspector discussed the generator brush binding with an electrical group supervisor and subsequently he initiated a CR to evaluate the degraded conditio The inspector noted that it was not clear how the retainer clip oecame misaligned, what the operability impact was, and whether the problem existed on the other emergency diesel generator CR 97-0096 documented the brush problem and provided an operability determination. However, the operability determination did not address the potential for, or effects of, a loss of brush contact during extended operation. A subsequent revision of the operability determination included additional inspections by NE personnel, contacts with the voltage regulator manufacturer and another Cooper Bessemer owner who experienced similar problems, and an assessment of the potential for common mode f ailur ,

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Additional inspection by PP&L under WA S72516 and S72517 found that the 'B'

and 'C' diesels each had one brush retainer clip misaligned to the point where it impacted the free movement of the brush. PP&L determined the restricted movement of one brush on each of the two generators would not impact operability. However, the loss of multiple brushes for a single collector ring has the potential to cause a loss of generator field, depending on the number of remaining brushes and their conditio The brush binding was caused by misalignment of its retaining clip. Based on the as-found condition, the retaining clip rotated clockwise with the torquing of its fastener. The inspector reviewed SM-024-E01, Revision 6, " Diesel Generator 'E'

18 Month inspection" and MT-GE-002, Revision 12, " Brush, Commutator And Slip Ring Inspection And Maintenance." SM-024-E01, steps 6.18.1 and 6.18.1, require checks to ensure the brushes are properly positioned. MT-GE-002, step 8.4.1 also contains a step to ensure freedom of movement of the brush in its holder. Based on review of the, procedures and the as-found condition, the inspector determine that the root cause of the problem was inadequate work performance and oversigh The inspector determined that the licensee's failure to adequately perform checks of the generator brushes constitutes a violation of minor significance and is being treated as a non-cited violation consistent with Section IV of the NRC Enforcement Polic Conclusions The failure to properly perform maintenance activities on the 'E', 'B' and 'C'

emergency diesel generators resulted in degradation of their generators' slip ring '

assemblies. Although the operability was not challenged prior to identification, the ,

potential existed for common cause degradation due to inadequate performance of t maintenance. The failure to properly perform safety related maintenance activity in accordance with established procedures constitutes a violation of minor ;

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consequence and is being treated as a non-cited violation consistent with Section IV of the NRC Enforcement Polic M6 Maintenance Organization and Administration M6.1 Verification of Maintenance Rule Reauirements - Switchvards {

, Inspection Scoce (62707)

l During review of emergent maintenance on the 500 kV switchyard air system, the inspector sought to verify that the basic requirements of the maintenance rule have *

been satisfied with regard to the SSES switchyard ..ll l

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b. Observations and Findinas

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The 500 kV switchyard air systsm is comprised of a single air manifold which supplies air pressure to maintain the switchyard breakers in their closed positio Check valves for individual breakers are relied upon to sustain the required air pressure at individual breakers short duration air supply problem On January 23, a leak developed on the air manifold, causing an alarm at both SSES and the Power Dispatcher office. A temporary fix was implemented, however on January 24 the problem resurfaced. While permanent repairs were being effected on January 25, the air supply to 5 of the 6 breakers in the switchyard had to be isolated from their air supply. During this time, the breakers'

check valves were relied upon to maintain the air pressure and consequently their positions. The inspector reviewed PP&L's actions in response to this incident because both the air leak, and actions necessary to repair it, had the potential to cause a load reject for SSES Unit In accordance with the PP&L maintenance rule implementing procedures, GDS-18,

" System Scoping for Maintenance Rule Applicability," and GDC-14, " Determining Levels of Monitoring Required for Structures, Systems, and Components Within The Scope of 10 CFR 50.65," the switchyards are classified as non-risk significant systems and are monitored using plant level performance criteria. These criteria are:

• Unplanned Capability Loss Factor - 0%

• Unplanned Scrams while Critical over last 12 months - 0

• No repetitive Maintenance Preventable Functional Failures i The inspector found that PP&L system engineers are performing quarterly system

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reviews for the switchyard system as required by NDAP-QA-0501. However, the inspector noted that the problems that occurred on January 23 are not counted for maintenance rule purposes since the switchyards are monitored on the plant leve !

, PP&L does address this type of failure under the corrective action process due to l l the potential for such a problem to cause a plant transien c. Conclusions

The Susquehanna Unit 1 and Unit 2 switchyards are considered to be within the

! scope of the licensee's maintenance rule program and are being monitored on the l plant level. The inspector found that PP&L was meeting the maintenance rule requirements with regard to monitoring of the switchyard I

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. . Enaineerina E2 Engineering Support of Facilities and Equipment E2.1 Operability Determination For RHR Swina-bus MG S_e_1 Insoection Scoce (37551) ,

Or. February 10,1997, PP&L initiated CR 97-0225 after discovering that the Unit 2, Division 11 RHR swing-bus motor generator (MG) set voltage was reading lo During routine rounds, an NPO found that the MG set output voltage was reading 460 Vac vice the expected 480 Vac. The inspector reviewed the licensee's actions in response to this discovery and the support provided by Nuclear Systems Engineering (NE). Observations and Findinas The Division ll RHR swing-bus MG set provides the normal power supply for valves that must reposition for proper Division 11 (the 'B' RHR loop) LPCI injectio Specifically it supplies power to the RHR injection valve, the RHR minimum flow valve, the reactor recirculation pump discharge valve and the recirculation pump discharge bypass valv The operability determination for CR 97-0225 is based on an assessment of TS 3.8.3 which requires the preferred power source, a preferred power source M/G set, alternate power source, and automatic transfer switch. The licensee determined that there was no impact on operability since the surveillance requirements for TS 3.8.3 do not specify a minimum voltage, the TS only requires that the load groups be energize In review of CR 97-0225, the inspector found that PP&L's initial operability determination was based on the RHR swing-bus motor generator set having power available and did not address whether the degraded voltage output would affect operability of downstream components. This issue was immediately discussed with the Shift Supervisor and subsequently, Nuclear System Engineering personne According to the guidance in Generic Letter 91-18, when it is not clear that a system can perform as described in its current licensing bases, performance of the TS surveillance alone may not verify operability. The inspectors determined that the initial operability evaluation did not address whether the system could perform as required by licensing basi On February 11, the licensee completed a supplemental operability deterr+atior. to address the minimum voltage necessary for operability of the subject motor operated valves. The supplemental evaluation gave appropriate consideration to the capability and design basis requirements of the valves for the degraded voltage condition. PP&L determined that the connected equipment will meet its design basis and operate as expected down to 90% of equipment rated voltage (460 Vac).

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The inspector determined that although the supplemental operability determination provided a sound technical position, the initial operability determination by the operations shift and shift technical advisor did no Conclusions Nuclear System Engineering provided a through revision of an operability determination for a degraded power supply impacting low pressure coolant injection valves. Although the initial determination made by operators on a backshift was upheld, the initial determination did not provide any technical justification and relied on meeting the verbatim requirements of Technical Specifications.

E2.2 Enaineerina Supoort of Diesel Generator Maintenance Insoection Scope (62707)

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On December 10 and 21,1996, the 'E' DG failed surveillance SO-024-014, Monthly Functional Test. The inspector reviewed the SSES engineering activities in ;

response to the failures, licensee's activities to resolve the root cause of the DG ;

failures, evaluated the licensee's corrective action, and performed an independent

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limited root cause evaluation of the failure !

' Observations and Findinas At 8:3C .m. on December 10,1996, approximately 20 seconds after the 'E' DG began suruillance SO-024-014, Monthly Functional Test, a generator loss of field alarm annunciated. The alarm was followed by a master trip lock out relay. The .;

inspector reviewed the associated work authorizations, the SSES trouble shooting l plan dated December 10, CR 96-2198 and the SSES 'E' DG operability '

determination associated with this failure. Subsequent to the December 10 failure and the initial corrective actions by the licensee, testing activities were performe These activities were followed by a second surveillance failure on December 21, 1996. The inspector further reviewed the licensee's corrective actions through ]

February 24,1997 involved with the second diesel failur '

The following WAs were reviewed / evaluated by the inspector:

WA A63686, Work Activity l WA 262350, Status Activity for 'E' DG Availability WA S61863, investigate and Troubleshoot WA S61896, Investigate and Troubleshoot The inspector determined that the 'E' DG was not credited as the power source for any SSES class 1E system during either of the test failures, and the test failures had no effect on the TS operability requirements of either unit. It was further determined that each of the other four diesels (A through D) was properly aligned in the control room throughout the tests and was available to perform its intended TS functio _ .. . . _ - - - - _ _ - = . - - _ - _ - - . - -

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Even though the f ailures did not have an immediate impact on the operability of l either unit, several safety significant issues were identified by the inspector during

the event reviews.

{ The licensee was not able to identify a specific cause of the December 10, f ailure, immediately following the failure. The f ailure was similar to one that occurred on August 8,1993, and described in Significant Operations i Occurrence Report (SOOR) 93194 and a third one described in SOOR 192-293. The operability determination that was written following the December 10,1996, failure did not fully explain the cause of the failure, and did not l fully explain why successful completion of a surveillance test following the December 10 failure supported the position that the equipment was operable. The inspector concluded that the operability determination was not complet . SSES Operations management came to a similar conclusion following their review of the operability determination and requested additional testing and

evaluation of the 'E' DG. The inspector determined that the actions taken by Operations management were aggressive, technically based and very l conservativ ~ The testing that was performed on the 'E' DG following the first failure was not well controlled, was not approved by the manufacturer, was not described in the DG vendor manual (IOM 79), and did not receive a rigoious formal engineering safety evaluation. Following the second 'E' DG 1 surveillance test failure, the licensee and a vendor representative concluded that the trouble shooting and maintenance activities conducted following the l

first failure caused the failure of two gate firing circuits, which resulted in )

l the second DG surveillance test failure in addition, it was concluded that l l the testing outlined in TP-024-149, Diesel Surveillance did not adequately test the components affected by the trouble shooting activitie The inspector determined that the licensee failed to adequately control DG maintenance and testing activities during the execution of the trouble shooting plan following the first failure. Very aggressive and comprehensive l corrective actions were undertaken by the licensee following the second DG l test failure. These actions included a return to service component testing l

matrix prepared with the help of vendor representative CFR 50 Append lx B states that measures shall be established to assure that conditions adverse to quality such as failures, malfunctions, deficiencies, defective ;

material and equipment and nonconformances are promptly identified and I correcte Contrary to the above, )

i i The licensee failed to implement adequate corrective actions in response to a I 1991 vendor letter that identified a deficiency on the contact surfaces of the I

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'E' emergency diesel generator bridge transfer switch. As a result of the i licensee's failure to implement corrective actions to preclude the condition t identified by the vendor, the transfer switch failed to perform its function on ,

December 10,1997, during an 'E' emergency diesel surveillance tes . The licensee's corrective actions in response to the failed 'E' diesel generator l transfer switch included the development of a trouble shooting plan dated .

December 10,1996, that was associated with CR 96-2198, The trouble ,

shooting activities conducted under the plan were not adequately j implemented, controlled, nor reviewed in that the activities resulted in the ,

failure of additional equipment and a second 'E' emergency diesel generator surveillance test failur These two issues are considered examples of inadequate corrective action and are i being cited as a violation. (VIO 50-387/97-01-02)

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The licensee performed an extensive root cause and engineering evaluation of the two failures and identified the following two additional contributing f actors in i addition to a number of issues of lessor importance. Each of the licensee identified !

issues is associated with a condition report with required corrective action and ,

management review milestone f The cause of the first failure was a failure of an DG bridge transfer switch to make an effective contact upon receiving a start signal. This susceptibility ,

was identified by the vendor in 1991 and communicated to the licensee by letter. The licensee included the letter in the vendor manual but did not ;

include the maintenance recommendations of the vendor in ths 'E' DG  !

preventive maintenance program nor did it perform an engineering evaluation determining that the preventive maintenance recommendations of the vendor were not necessary, Normal surveillance activity of the 'E' DG included an allowance for manipulating the bridge transfer switch prior to the performance of the surveillance. This switch manipulation masked the lack of the vendor recommended preventive maintenance by mechanically removing an oxide .

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coating on the transfer switch contacts.

c. Conclusions On December 10 and 21,1996, the 'E' DG failed surveillance S0-024-014, Monthly Functional Test. The cause of the first failure was a high resistance ,

contact on the DG bridge transfer switch which was not maintained as recommended by the manufacturer. The second test failure was caused by two damaged gate firing circuits. The gate firing circuits were damaged during ,

inadequate troubleshooting and testing activities performed by the licensee. The initial SSES engineering operability determination following the first failure was determined to be weak, but the SSES engineering activities following the second failure were determined to be very strong and aggressive. Additional causal factors

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. 18 include the control of vendor recommendation for preventive maintenance and vendor manual documentation, and the control of pre-exercising equipment that may mask weaknesses that would affect TS surveillance testing activities. A violation was issued for inadequate corrective actions to the vendors notification and previous like conditions, and the licensee's troubleshooting and testing activities following the first failur .

E2.3 Bvoass Indication System (BIS) Desian Inspection Scoce (37551)

As follow up to the Unit 2 RHR pump start f ailure discussed in section 02.1, the inspector reviewed the alarm circuitry that provides indication of the RHR pump's proper standby alignmen Observations and Findinas During discussions with NE personnel the inspector learned that the bypass indication system (BIS) annunciator for the RHR pump is energized when the pump's suction valve is fully closed, in contrast, the RHR pump trip signal occurs when the valve in not full ope The Institute of Electrical and Electronic Engineers (IEEE) " Criteria for Nuclear Power Plant Protection Systems," Standard 279-1971, requires that when the protective action of some part of a system has been bypassed, this fact shall be continuously indicated in the control room. Regulatory Guide 1.47 provides additional guidance, and requires that the indication of a bypass condition should be at the system level, whether or not it is also at the component or channel leve The inspector determined that the BIS alarm does not, in all cases, indicate when the automatic start of the RHR pump is inhibited by the suction valve interloc CFR Part 50, Section 50.55a, " Codes and Standards," requires the SSES design to meet IEEE 279 standard and failure to meet this requirement is a violatio (VIO 97-01-03)

Based on this finding, the inspector questioned whether the licensee's design basis review project in response to the October 9,1996, NRC request for information under 50.54(f) had previously identified this discrepanc , Conclusion The NRC has identified that the bypass indication system (BIS) does not alarm when a protective trip is active for individual residual heat removal pumps. NRC regulations require that when a system is bypassed, that it shall be continuously alarmed at the system levelin the control room. The failure to provide an alarm for this bypass is a violation of 10 CFR 50.55a, " Codes and Standards."

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.E8 Miscellaneous Engineering issues (92902)

E Review of FSAR Commitments

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A recent discovery of a licensee operating their facility in a manner contrary to the Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters to the UFSAR description. While performing the inspections discussed in Section 08.2 this report, the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The inspector determined that the Bypass indication System for the RHR system does not meet the FSAR Section ,

3.13 commitment to Regulatory Guide 1.47, May 19,1973. Section 08.2 of this

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inspection report contains addition information on this issu ;

IV. Plant Support R1 Radiation Protection and Chemistry Controls (RP&C)

R Imolementation of Radioactive Liauid and Gaseous Effluent Control Proorams Inspection Scoce (84750-01)

The inspection consisted of: (1) tour radioactive liquid and gaseous effluent-pathways and its process facilities, (2) review of radioactive liquid and gaseous effluent release permits, (3) review of Condition Reports compiled by the Operations, and (4) review of unplanned or unmonitored release pathways, i Observations and Findinos Radioactive liquid effluents from the site were released into the cooling tower blowdown line for dilution prior to reaching the Susquehanna river. Cooling tower i blowdown line flow rates varied depending on the river flow rate which was a !

minimum of about 5,000 gpm during radioactive liquid releases. Radioactive gaseous effluents from the site were released through five rooftop vents on the reactor building. Radioactive gaseous effluents (i.e., noble gases, particulates, arid radiciodines) were monitored at each ven '

The inspectors toured the above release pathwayrs and selected radioactive liquid and gas process f acilities and equipment; including (1) radioactive liquid and ,

gaseous effluent radiation monitoring system (RMS), (2) air cleaning systems, and (3) the control roo ,

The inspectors noted that the effluent control procedures were detailed, easy to follow, and Offsite Dose Calculation Manual (ODCM) requirements were

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incorporated into the appropriate procedures. The inspectors also determined that the liquid and gaseous discharge permits were complete, and met the Technical Specification (TS)/ODCM requirements for sampling and analyses at the frequencies ;

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! . 20 and lower limits of detection established in the TS/ODCM. There were no unplanned releases during 199 Conclusions Based on the above observations, reviews, and discussions, the inspectors determined that the licensee established, imple,mented, and maintained effective radioactive liquid and gaseous effluent control program R2 Status of RP&C Facilities and Equipment R2.1 Calibration of Effluent / Process Radiation Monitorina Systems (RMS) Inspection Scone (84750-01)

The inspectors reviewed the most recent calibration results for the following selected effluent / process RMS and its system flow rates for both units. The inspectors also reviewed the licensee's RMS self-assessment and RMS work order The inspector also reviewed selected l&C calibration procedure * Liquid Radwaste Effluent Monitor (Common to both units)

• Liquid Radwaste Effluent Line Flow Rate

• Cooling Tower Blowdown Flow Rates

• Service Water Effluent Monitors

• Residual Heat Removal Service Water Radiation Monitors

• Main Steam Line Monitors

• Standby Gas Treatment Vent Monitors (Common to both units)

• Reactor Building Vent Noble Gas Monitors (low, mid., and high ranges)

• Reactor Building Vent Noble Gas Monitoring System Flow Rate

• Turbine Building Vent Noble Gas Monitors (low, mid., and high ranges)

• Turbine Building Vent Noble Gas Monitoring System Flow Rate

• Main Condenser Offgas Pre-Treatment Noble Gas Monitors Observations and Findinas The I&C Department and Chemistry Department had the responsibility of performing electronic and radiological calibrations, respectively, for the above effluent / process radiation monitors. The System Engineer had the responsibility to maintain the operability for the above RMS and upgrade the system, as necessary. All calibration results reviewed were within the licensee's acceptance criteria. During the review of the above RMS radiological calibration efforts, the inspectors

independently verified several calibration results, including linearity tests and l conversion factors. The comparison results were very good.

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During the previous inspection conducted in July 1995, it was noted that the radiological calibration techniques implemented by the licensee were excellent, such as energy calibration and five solid sources for the conversion factors and the I

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linearity test (See inspection Report Nos 50-387/388/95-19 for detail). No changes in radiological calibration methodology were note Conclusions Based on the above review, the inspectors determined that the licensee had maintained an excellent RMS calibration program.

R2.2 Calibration of Area Radiation Monitorina Systems (ARMS) inspection Scope (83750)

The inspectors reviewed the most recent calibration results for the following selected ARMS for both units. Section 12.3.4 of FSAR describes many aspect of the ARMS and the inspectors reviewed selected aspects including: (1) ARMS locations, (2) selection criteria for energy dependence, accuracy, and reproducibility, (3) calibration method and testability, and (4) alarm set point * Reactor Building Area High Radiation Monitors (Units 1&2)

• Turbine Building Area High Radiation Monitors (Units 1&2)

• Spent Fuel Pool Area High Radiation Monitors (Units 1&2)

• Refueling Floor Area High Radiation Monitors (Units 1&2)

The following l&C calibration procedures were reviewed to determine their adequac * IC-079-010 Channel Calibration of Area Radiation Monitors

• SI.179-305 18 Month Calibration of Spent Fuel Storage Pool Area Radiation RE-23714 Monitor

• SI 279-337 18 Month Calibration of Spent Fuel Storage Pool Area Radiation RE-13714 Monitor Observations and Findinas The l&C Department had the responsibility to perform electronic and radiological calibrations for the above ARMS. The expected dose rates of the radiological calibration equipment were calculated by radiation protection (RP) personnel. The inspectors noted that the above calibration procedures were easy to follow. All reviewed calibration results y ;re within the licensee's acceptance criteri The inspectors discussed ARMS locations; selection criteria for energy dependence, accuracy, and reproducibility; calibration method and testability; and alarm set points with representatives from l&C and RP. The inspectors noted that the

- licensee had good knowledge in the above areas. The inspectors also discussed free air calibration methodology described in "ANSl/ANS HPSSC-6.8.1-1981, Location and Design Criteria for Area' Radiation Monitoring Systems for Light Water Nuclear Reactors." The licensee stated that they would consider this refesence for potential program enhancement . - - - - - - _ _ _ _ _

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22 Conclusions Based on the above reviews and discussions, the inspectors determined that the licensee established and implemented a good ARMS calibration progra R2.3 Air Cleanina Systems Inspection Scone (84750-01)

The inspector reviewed the licensee's: (1) most recent surveillance test results, (2) work orders, system performance summaries, and interviewed system engineers, as needed, to determine the implementation of TS requirements for the following system e Control Room Emergency Outside Air Supply System e Standby Gr; Yreatment System The inspectors reviewed the following surveillance test results for the above noted ventilation system e Visual Inspection, e In-Place HEPA Leak Tests, e in-Place Charcoal Leak Tests, e Air Capacity Tests, o Pressure Drop Tests, and Laboratory Tests for the lodino Collection Efficiencie Observations and Findinas The licensee has chosen to assign a group of individuals within system engineering to oversee each of the ventilation systems. As a group of individuals had been assigned, the individuals were not solely dedicated to ventilation system oversigh One of these individuals supervised the other system engineers assigned to the station ventilation system Test procedures provided good guidance. Surveillance test results of the above systems were within the licensee's acceptance criteria established by the test procedures and TS. Discussions with the system engineers and review of performance summaries indicated that a good level of attention had been placed on ventilation systems. Most importantly, the inspectors noted that there had been no turnover among the ventilation system engineers over the past several year Conclusions Based on the above reviews and discussions, the inspectors determined that the above noted ventilation systems were well maintaine .-

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R3 RP&C Procedures and Documentation a. Irispection Scope (84570-01)

The inspectors reviewed the ODCM implemented at the SSES including: (1) dose factors, (2) setpoint calculation methodology, and (3) bioaccumulation factors for aquatic sample media. The inspector reviewed the 1995 Annual Radioactive Effluent Report to verify the implementation of T .

b. Observations and Findinas The ODCM proviced cescriptions of the sampling and analysis programs, which are established for quantitying radioactive liquid and gaseous effluent concentrations, and for calculating projected doses to the public. All necessary parameters, such as effluent radiation monitor setpoint calculation methodologies, site-specific dilutio factors, and dose f actors, were listed in the ODCM. The licensee adopted other necessary parameters from Regulatory Guide 1.10 The 1995 Annual Radioactive Effluent Report provided total released radioactivity )

for liquid and gaseous effluents. The report also contained any changes to the j ODCM as necessary and meteorological data. There were no obvious anomalous measurements, omissions or trends. The 1995 projected dose assessment report I contained maximum individual and population doses resulting from routine i radioactive airborne and liquid effluents. Doses were well below the regulatory i

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limits. The inspectors reviewed selected 1996 monthly projected dose assessment results and noted that there were no trend c. Conclusions Based on the above review, the inspectors determined that the licensee's ODCM contained sufficient specification, information, and instruction to acceptably implement and maintain the radioactive liquid and gaseous effluent control programs. The licensee met all TS/ODCM reporting requirements.

R6 RP&C Organization and Administration a. inspection Scoce (84570-01)

The inspector reviewed the organization and administration of the radioactive liquid and gaseous effluent control programs and discussed with the licensee changes made since the last inspection, conducted in July 199 b. Observations and Findinas The chemistry staff had primary responsibility for conducting the radioactive liquid and gaseous effluent control programs. Operations, Engineering, Radwaste Operations, and Instrumentation and Controls organizations supported the radiological effluent control programs relative to air cleaning systems, radioactive

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.. 24 liquid discharges, and radiation monitoring system calibrations. The Chemistry Supervisor remained under operation Since the last inspection of this program area, the following organizational changes were mad * The reactor water cleanup and fuel pool system engineers were reassigned to system engineering from chemistr * Chemistry was eeassigned to the Operations Manage * The Chemistry Department lost one technician and one scientist positio No degradation of the effluents control program was noted as a result of these changes, c. Conclusions The RP&C organiz*ation assigned oversight of the radioactive effluents control program was well staffe R7 Quality Assurance (QA)in RP&C Activities ,

i Intoection Scooe (84750-01) l

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The inspection consisted of a review of Quality Assurance (QA) Audit Reports' ;

required by the TS and a review of corrective actions implemented to address audit t findings. The inspectors reviewed QA Audit Report Nos.95-033 and 95-114 which were reports regarding the chemistry and effluents programs, respectively. The inspectors also reviewed QA Audit Report No.95-159 which pertained to an audit of a vendor who supplied chemistry analytical services to the license !

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The inspectors also reviewed (1) QA policy of the measurement laboratory; (2) i implementation of the measurement laboratory quality control (OC) program for radioactive liquid and gaseous effluent samples; and (3) internal memorandum, QA I Requirements for Radiological Programs, Observations and Findinas The inspectors noted that individuals with appropriate backgrounds were used to i

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conduct the audit. No " technical" issues of regulatory significance were identified by the licensee audit team. Licensee corrective actions ;o audit observations and recommendations were considered to be appropriate. The inspectors noted that the frequency by which QA audits was changed from yearly to once per every two years according to the UFSA '

The inspectors noted that QC for gamma measurements were maintaine Comparisons of QC samples (blind, spike, and duplicate) were in good agreemen l

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25 ,, Conclusion Based on the above reviews, the inspectors determined that the licensee met the QA audit requirements and implemented a very good QC program for chemistry measurements.

R8 Miscellaneous RP&C lssues R8.1 Review of FSAR Commitments A recent discovery of a licensee operating their facility in a manner contrary to the Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters to the UFSAR description While performing the inspections discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameters.

P1 Conduct of Emergency Preparedness (EP) Activities Inspection Scoce (82701)

The inspector reviewed the licensee's action item tracking system and the emergency planning self-assessment program to determine the effectivene's s of licensee controls, Observations and Findinas An action item is initiated by a CR and tracked in the licensee's action item tracking system. The inspector reviewed 14 emergency preparedness items listed in the action item tracking system that resulted from condition reports, recommendat ons from the 1996 audit, and comments from emergency drills. Those items were appropriately assessed and were being tracked. Corrective action completion dates were assigned and being me The Supervisor, Nuclear Emergency Preparedness performed self- assessments using tracking system items to determine whether corrective actions were adequate and whether enhancements could be made to the emergency preparedness program. An area that has been under review is the licensee's emergency action level (EAL) classification scheme, i.e., whether to continue to seek NRC approval for the Nuclear Management and Resources Council, Inc. (NUMARC) National Environmental Studies Project (NESP)OO7 EALs or retain and enhance the Criteria for Preparetion and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, NUREG 0654/ FEMA-REP-1, Revision 1, EALs that comprise the current classification scheme. (This matter is discussed further in section P3.) The licensee also initiated a self- assessment into

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why the maintenance group had performed work and made changes to EP ,

equipment and facilities without informing the EP group and why emergency plan procedure changes were not always complete. The licensee determined that the  ;

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problem appeared to be in the ownership of the EP progra Conclusions

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The inspector determined through interviews with emergency personnel and review of CRs that the action item tracking system was appropriately used

to identify and track currective action items. Additionally, self-assessments were being performed to evaluate the appropriateness of corrective actions j for identified items and to identify areas for improvement in the EP progra P2 Status of EP Facilities, Equipment, and Resources

' Insoection Scoce (82701) ,

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The inspector conducted an audit of the licensee's emergency facilities and equipment by touring the Control Room, Operations Support Center (OSC), i Technical Support Center (TSC), the Emergency Operations Facility (EOF). The j inspector reviewed facility equipment inventories and surveillances conducted j during the last quarter of 1996, for completeness and accurac ;

! Observations and Findinos l The inspector found the emergency facilities to be operationally ready and emergency equipment as described in the emergency plan. The inspector noted J that the inventories and surveillances of the facilities and equipment were properly completed and that any identified discrepancies were either immediately corrected or documented, with work orders written for repair or replacemen Conclusions The inspector found that emergency facilities and equipment were as described in the emergency plan, survey instruments were within the calibration requirements, inventories and surveillances were completed, and the facilities and equipment were in a state of readines ,

P3 EP Procedures and Documentation insoection Scoce (82701)

l The inspector reviewed recent emergency response plan changes to assess the  ;

impact on the effectiveness of the EP progra l l

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b. Observations and Findinas The inspector reviewed Revision 25 to the emergency plan during the inspectio The changes made to the emergency plan were: changes in alarm panel designation; changes in staffing of the new organization due to the relocation of the EOF to the East Mountain Business Center; changes in management and facility titles; corrections of typographical errors, and other minor correction Additionally, the inspector discussed an unresolved item with the licensee that had been opened in 1990, during inspection 50-387,388/90-18, and subsequently closed based upon the licensee's submittal of NUMARC EALs. The unresolved item involved a review of the NUREG 0654 EALs to assure that all EALs in use at that time were clear and unambiguous (50-387,388/90-18-01). When the licensee decided to convert to the NUMARC NESP007 EAL guidance, the unresolved item became moo The licensee submitted the NUMARC NESP007 EAL scheme to the NRC for approval in January 1993. The NRC responded with a request for additional information in January 1994. The licensee met with the NRC in June 1994 to discuss the EALs and resubmitted them for approval in October 1995. The NRC requested additional information in July 1996. In response,-the licensee sent a letter in October 1996 requesting an extension of time for the response and another meeting with the NRC early 199 The unresolved item was closed in inspection report 50-387, 388/95-25, because the licensee had submitted the NUMARC NESP007 EALs to the NRC and the matter was being tracked as a licensing issu During the inspection, the inspector determined that the licensee continued to make changes to the current (NUREG 0654) EALs to meet the NUREG 0654 EAL guidance throughout the period. Identified ambiguities were also reduced through l the 10 CFR 50.54(q) process for emergency plan changes. However, the licensee j indicated to the inspector that it is uncertain about whether it will continue to seek i NRC approval for the NUMARC NESP007 EALs or update the current EALs.

c. Conclusions The inspector concluded that Revision 25 to the plan met 10 CFR 50.54 (q)

requirements and did not reduce the effectiveness of the emergency pla With regard to the NUMARC versus NUREG EAL matter, this will be tracked as an inspector followup item. (IFl 50-387,388/97-01-04) -

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The inspector interviewed the Vice President Nuclear Operations, the Plant Manager, Health Physics Supervisor, Supervisor Nuclear Emergency Planning, Recovery Managers, and training personnel to determine the effectiveness of training. Additionally, the inspector reviewed EP training records, training procedures, lesson plans, emergency plan, and position specific procedures associated with on-shift dose assessment to evaluate the licensee's EP training progra l Observations and Findinas

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The inspector interviewed personnel who were qualified members of the emergency

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response organization. All of the personnel interviewed indicated that the licensee conducted integrated mini drills in the TSC and the EOF and found them to be very effective for training and keeping personnel current in their EP dutius and re'sponsibilities. Additionally, the inspector reviewed approximately 30% of the emergency response organization (ERO) training records and verified that qualification and training were in accordance with the training matrix and were curren The inspector determined that all on-shift level 11 health physics tech'nicians were trained in dose assessment and protective action recommendations for providing support to the shift supervisor prior to the manning and activation of the TSC. The technicians performed on-shift dose assessments using real time meteorological and source term conditions. Training does not include performing "what if" calculations I because those calculations would be performed at the TSC and/or EOF, once they are activate The inspector also reviewed the dose calculator training and dose assessment and protective actions lesson plans, Conclusion The inspector found, through interviews and the review of training records, that the ERO, and radiation protection personnel were being adequately trained as required l by the emergency plan, the training was current and that the training program was being effectively implemented. The inspector also found that dose calculator training and dose assessment and protective action lesson plans were acceptable.

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P6 EP Organization and Administration a. insoection Scope (82701)

The inspector , reviewed the licensee's EP group staffing and management to ,

determine what changes have occurred since the last program inspection

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(September,1994) and if those changes had any adverse effect on the progra ;

b. Observations and Findinos , j l

Since the last program inspection (September 1994), the position of i Supervisor, Emergency Preparedness was refilled, one of the EP staff retired and the position was eliminated During that period of time, the licensee moved its EOF to a location that is about 23 miles from the plan Additionally, the licensee streamlined its ERO by eliminating some of the administrative positions. The move and changes to the ERO were approved by tne NRC. A demonstration drill was performed in July 199 :

c. Conclusions

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The inspector concluded that management involvement and control of the EP program was good. Changes made since the last program inspection did not appear j to have any adverse effects on the progra l P7 Quality Assurance (QA) in EP Activities a. Inspection Scope (82701)

The inspector reviewed QA audit (10 CFR 50.54(t)) reports of the EP program, conducted in 1995 and 1996. Additionally, the inspector interviewed a director of '

an off-site agency to determine the effectiveness of the licensee's off-site interfac b. Observotions and Findinos The inspector reviewed audit reports95-023 and 96-057. Audit report 95-023 contained no items that rose to the level necessitating a CR, but included 18 recommendations. Audit report 96-057 contained three items requiring a CR and six recommendations. The three CRs identified the -

following deficiencies: (1) annual preventive maintenance on the public notification system wtr. not preformed in 1995 (CR 96-1118); (2) some emergency procedures were not current (CR 96-1132); and (3) three individuals "on-call" had been removed from the qualification syste The inspector also compared the reports of the audits and noted negative trends in the maintenance of training records (both-on and off-site), in maintenance of facilities and equipment, and in emergency plan and position specific procedure changes. These negative trends had also been identified by the licensee and corrective actions were being take 'O

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The inspector interviewed the Director, Luzerne County Emergency Management Agency, to determine the effectiveness of the licensee's off site interface. The Director indicated that the licensee was very supportive in training county and local municipality representatives, and in assisting the county with emergency plan changes. The Director also indicated that many of the emergency county personnel are volunteers and the licensee's extra efferts and time expended for training these personnel was very much appreciated. Additionally, the inspector was given a tour of the Luzerne County Emergency Operations Center and the emergency response mobil command unit and its associated emergency equipmen Conclusion The inspector concluded that the licensee had conducted audits in accordance with 10 CFR 50.54(t), as required, and that the off-site interf ace was effectiv P8 Miscellaneous EP issues P Review of FSAR Commitments A recent discovery of a licensee operating its f acility in a manner contrary to the UFSAR description highlighted the need for a special focused review that compares plant practices, procedures, and/or parameters to the UFSAR description. Section 13.6 of the UFSAR refers to the emergency plan. Since the UFSAR does not specifically include emergency plan requirements, the inspector compared licensee activities to the emergency plan.' The inspectors specifically reviewed on shift dose assessment capabilities and training. This is discussed in Section P5. No discrepancies were note V. Manaaement Meetinas X1 Exit Meeting Summary inspectors presented the Effluent Control Program inspection results to members of the licensee management at the conclusion of the inspection on January 17,1997. The licensee acknowledged the findings presente The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on February 26,1997. The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie _ . . _ _ _ - - - - . . .

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ITEMS OPENED, CLOSED, AND DISCUSSED II

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Opened 50-388/97-01-01 VIO Operators' failure to implement actions of high hydrogen alarm response procedure in response to multiple indications of a high concentration 50-387,388/97-01-02 VIO Adequacy of BIS alarm circuits for the RHR systems 50 387/97-01-03 VIO 50-387,388-97-01-04 Corrective Action For 'E' DG Maintenance lFI Completion of corrective action for EAL scheme Closed 50-387/96-008 LER Alternate Continuous Gaseous Effluent Sampling 50-387/96-013 LER Mode Change Requirement Not Met 50-387/96-014 LER Completion of Technical Specification Required 50-388/96-009 LER Unit 2 'D' RHR Pump Start Failure

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LIST OF ACRONYMS USED l .*

ARMS Area Radiation Monitoring Systems CFR Code of Federal Regulations CR Condition Report CTS Condensate Transfer System DG Diesel Generator EAL Emergency Action Level ECCS Emergency Core Cooling System EOF Emergency Operations Facility -

EP Emergency Preparedness ERO Emergency Response Organization HVAC Heating, Ventilation, and Air Conditioning l&C Instrumentation and Controls LCO Limiting Conditions for Operation LER Licensee Event Report LPCI Low Pressure Coolant injection MG Motor Generator MSIV Main Steam Isolation Valve NCV Non-Cited Violation NOV Notice of Violation NRC Nuclear Regulatory Commission NRR Office of Nuclear Reactor Regulation NE Nuclear Systems Engineering NUMARC Nuclear Management and Resources Council, In NESP- National Environmental Studies Project 007 EALs NUREG 0654 Criteria for Preparation and Evaluation of Radiological Emergency

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Response Plans and Preparedness in Support of Nuclear Power Plants,

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NUREG 0654 FEMA-REP-1, Revision 1, EALs ODCM Off-site Dose Calculation Manual OE Office of Enforcement

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01 Office of Investigations OSC Operational Support Center QA Quality Assurance QC Quality Control RCIC Reactor Core Isolation Cooling RHR Residual Heat Removal RMS Radiation Monitoring System RP Radiation Protection RPC Radiological Protection and Chemistry SALP Systematic Assessment of Licensee Performance Sl International System of Units SOOR Significant Operations Occurrence Report SRV Safety / Relief Valve SSES Susquehanna Steam Electric Station TS Technical Specification TSC Technical Support Center UFSAR Updated Final Safety Analysis Report l

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