IR 05000387/1996011

Insp Repts 50-387/96-11 & 50-388/96-11 on 961022-1202.No Violations Noted.Major Areas Inspected:Operations, Maintenance,Engineering & Plant Support

ML17158B905
Person / Time
Site:	Susquehanna
Issue date:	12/27/1996
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17158B904	List: IR 05000387/1996011 ML17158B903
References
50-387-96-11, 50-388-96-11, NUDOCS 9701030145
Download: ML17158B905 (48)

Text

U. S. NUCLEAR REGULATORY COMMISSION REGION I

Docket Nos:

License Nos:

50-387, 50-388 NPF-14, NPF-22 Report No.

50-387/96-1 1, 50-388/96-1

Licensee:

Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 19101 Facility:

Susquehanna Steam Electric Station Location:

P.O. Box 35 Berwick, PA 18603-0035 Dates:

October 22, 1996 through December 2, 1996 Inspectors:

K. Jenison, Senior Resident Inspector B. McDermott, Resident Inspector E. King, Physical Security Inspector Approved by:

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

'P701030i45 9hi227 PDR ADOCK 05000387

PDR

EXECUTIVE SUMMARY Susquehanna Steam Electric Station, Units 1 & 2 NRC Inspection Report 50-387/96-11, 50-388/96-11 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support.

The report covers a 6-week period of resident inspection, and a routine security inspection by a regional specialist.

~Oerations

~

An erosion corrosion related leak was identified by the licensee and vigorously pursued through the condition report (CR) and the Event Review Team (ERT)

processes.

Each of the processes was strongly supported by senior licensee (PP&L)

management on and off site.

Site management made a conservative determination based on their interpretation of plant and personnel safety.

~

A plant upset condition resulted from a failed level controller on the 'C'eactor feedwater pump.

The operators responded adequately to this upset condition and there was no impact on the safe operation of the unit.

~

Operators failed to enter the limiting condition for operation (LCO) of Technical Specification (TS) 3.2.2 at the time that the Unit 1 T-factor was indicated to be less than 1 by the plant computer.

This was a violation of minor consequence.

An event involving the failure of a battery charger, resulted in a TS LCO entry.

However, the inspector determined that the effective time to document entry into the TS LCO preceded the time chosen by the operators.

No violation of NRC requirements occurred.

However, with a clear indication of the initiation of the event, the selection of the later time for LCO entry was not conservative.

Operators failed to take the actions required by TSs after they declared all Unit 1 scram accumulators inoperable due to a loss of associated control room alarms.

In review of this event it was determined that entry into the TS Action statement was not specifically required, however operators made this determination and did not follow through with all actions required.

PP&L has initiated suitable corrective actions and provided better guidance in control room procedures.

The inspector concluded that the operators'ational for not taking the TS actions, once they concluded the specification was applicable, was inappropriate.

The operators'ustification for not initiating compensatory measures was viewed as nonconservative and demonstrated a weak safety perspective.

Since the operability of the scram accumulators was not challenged, and no applicable TS action statements were exceeded, no violation NRC of requirements occurred.

While performing incore monitoring activities, the Unit 1 reactor operator noticed that the traversing incore probe (TIP) withdrew beyond its normal position and appeared to being traveling at an excessive speed.

The operator took good actions

Reactor Engineering failed to provide operators with an adequate procedure, in the form of a correct core map, to control the positioning of the Unit 1 control rods.

The incorrect core map was accompanied by a correct rod withdrawal sequence (pull sheet) procedure with which the map varied.

The error was identified by the insightful actions of the control room operators.

Because of the operator actions, the violation involving an inadequate procedure is being treated as a licensee identified, non-cited violation.

~

Based on a selected sample of Nuclear Assurance Services (NAS) surveillance activities, the inspector determined that the activities performed by the NAS surveillance group were weighted towards customer requested activities.

The findings did not display a wide scope of technical areas and were generally related to process and administrative areas.

There were no indications that the sampled surveillance activities as a whole had a major impact on the quality of plant operations.

Maintenance Most maintenance activities were performed adequately.

The activities associated with work authorization (WA) 61853 were especially well performed, in that the controlling documentation was prescriptive, was carefully implemented, and included first line management oversight.

The licensee identified a pin hole leak on a main steam (MS) drain line, that was determined to be the result of impingement erosion from an RCIC drain line piping T-connection. The licensee's erosion program met the current expectations for the program established by EPRI.

However, two programmatic weaknesses contributed to this erosion related fault: the licensee's program did not account for this type of impingement damage; and the program did not account for changes in normal operational configurations that may alter flow considerations used in the original erosion program calculations.

The licensee's response to the pin hole leak was very aggressive and no additional locations of excessive damage were identified.

The licensee adequately tracked, trended, resolved and prioritized the existing maintenance backlog.

The Unit 1 'B'irculating water pump suffered a maintenance-related failure, caused in part, by the sequence in which the lug was attached to the motor.

Although the licensee evaluated the failure, corrective action to prevent recurrence was not well documented and incomplete.

PPSL's identification, evaluation, and disposition of a failed Reactor Building Zone III ventilation back draft damper were very good.

Corrective actions planned to prevent recurrence, specifically the improvements to routine surveillances, were viewed as reasonable and PPSL's classification of the damper failure was consistent with their maintenance rule implementing procedure Safety related activities on the standby gas treatment system (SBGTS) were performed in an adequate manner.

However, the related documentation of as left measurements was not completed in a contemporaneous manner.

This was determined to be a poor practice, since it could challenge the accuracy of these quality records.

Safety related activities on the TIP were performed in an adequate manner.

However, trouble shooting and repair activities were not prescribed distinctly, and the data recorded in the work authorization did not include an indication of as-left acceptance criteria and was not adequate to determine the cause of the failure, or the acceptability of the as-left TIP condition.

The performance of the'quarterly channel calibration and channel functional test for a safety related pressure switch was appropriately controlled, technically complete, and well performed.

~En ineerin Two initial attempts to justify operability of the high pressure coolant injection (HPCI) pump were weak and incomplete.

As a result of NRC review, improvements were made to the operability determinations.

The weaknesses identified did not have a safety significant impact because the operability of the HPCI pump was

'learly supported and stated in the licensee's second operability determination.

However, the programmatic aspect of poor quality operability determinations was discussed with Nuclear System Engineering management.

~

The licensee adequately determined and documented the design basis availability of the ultimate heat sink cooling medium.

~

A selected sample of modifications were adequately drafted, controlled, implemented, and applied in the fiel TABLE OF CONTENTS I. Operations...

~

~

~

~

02

07

Conduct of Operations

. ~...... ~..........,.........

~ ~...

01.1 Main Steam Drain Line Pin Hole Leak...;..

~.,.....

~ ~...

01.2 Failure of the Unit 1 'C'eactor Feedwater Pump (RFP) Level Control Function 01,3 Failure of the 2D613 125 Vdc Battery Charger............

01,4 T-Factor Less than 1.00 During the Unit 1 Startup Operational Status of Facilities and Equipment....... ~....

~ ~...

02.1 Unit 1 Seismic Monitor...

~.

~ ~........

~ ~...

~ ~...

~

~

~

~

02.2 Unit 1 Acoustic Monitor Operability.............. ~.....

Operator Knowledge and Performance ~........ ~....... ~.....

04.1 Loss Of Control Rod Scram Accumulator Alarms Quality Assurance in Operations.... ~........ ~....... ~.....

07.1 Nuclear Assessment Services (NAS) - Self Initiated Surveillance Actlvltles e

~..

a s.

s.

~ ~....

~

~

~

o e. o.....

s s

s e

~

~

o

~

~.

o Miscellaneous Operations Issues...... ~......... ~.....

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

3

6

8

9

10 I. Maintenance I

M2 M3 Conduct of Maintenance M1.1 General Comments Maintenance and Material Condition of Facilities and Equipment M2.1 Main Steam (MS) Drain Line Erosion M2.2 Corrective Maintenance Backlog

~ ~...

~ ~..........

M2.3 Minor Maintenance Activity/Trouble Shoot and Repair M2.4 Circulating Water Pump Repair...... ~........,..

Maintenance Procedures and Documentation.............

M3.1 Standby Gas Treatment System (SBGTS) Preventive Maintenance.. ~.... ~.......................

M3.2 Observation of Instrument Calibration Maintenance Staff Training and Qualification........ ~....

M5.1 Unit 2, 13.8 kV Switchgear Leads Not Landed....

~..

Miscellaneous Maintenance Issues

19

20

21

23

25

27

27 III. Engineering E1 E3 E7 E8 Conduct of Engineering E1.1 Impact of Bolting Preload on HPCI Operability E1.2 Impact of Suppression Pool Level on HPCI Operability E1.3 Engineered Safeguards System (ESS) Spray Pond...

Engineering Procedures and Documentation.........

~..

E3.1 Design Control of Modifications................

Quality Assurance in Engineering Activities E7.1 NSE Engineering Self Assessment..

~ ~..........

Miscellaneous Engineering Issues E8.1 UFSAR Review

27

28

30

31

31

v

TABLE OF CONTENTS (Continued)

IV. Plant Support......

~

~.

~

~.

~

~

~

\\

s

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

S1 Conduct of Security and Safeguards Activities.............

S 1

~ 1

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

s

~

~

~

~

~

~ \\

~

~

S2 Status of Security Facilities and Equipment S2.1 Protected Area Detection Aids S2.2 Alarm Stations and Communications...............

S2.3 Testing, Maintenance and Compensatory Measures S5 Security and Safeguards Staff Training and Qualification 55.1 Job Task Duty/Training and Qualification~81700 S6 Security Organization and Administration

. ~....

~..,.. ~....

S6.1 Management Support S7 Quality Assurance in Security and Safeguards Activities

~..

~..

S7.1 Effectiveness of Management Controls S8 Miscellaneous Security Issues..........,...........

~

~

~

S8.1 Previously Identified Items (81700).. ~.......

~..

~

~.

S8.2 Review of Updated Final Safety Analysis Report (UFSAR)

F7 Quality Assurance in Fire Protection Activities F7.1 Fire Protection Audit

32

33

33

34

35

~

~

35

36

37

V. Management Meetings......... ~............

~

~.

~

~

~

~

~

~

~

~

~

~

~

~

~

X2 Exit Meeting Summary...........................

~

~

~

37

Re ort Details Summar of Plant Status Unit 1 began this inspection period in a reactor startup from refueling.

The reactor was made critical on October 22.

Between October 22 and 28 power was increased up to 37%, however on October 28 the Unit was shutdown to repair main steam drain line piping.

Upon completion of repairs, power ascension was begun on November 3.

Problems with the 'A'eactor feed pump required corrective maintenance and limited power to 75% until November 12.

The Unit operated at essentially 100% power throughout the rest of this inspection period, with one exception.

On November 23, power was reduced to 95% to support an 18 month calibration of the reactor recirculation pump high speed stops.

Unit 2 operated at 100 percent power throughout this inspection period with the exception of November 23, when power was reduced to approximately 75% to accomplish corrective maintenance on the 'C'ondensate pump.

I. 0 erations

Conduct of Operations'1.1 Main Steam Drain Line Pin Hole Leak a.

Ins ection Sco e 71707 The licensee's response to an unanticipated pin hole leak on a main steam (MS)

drain line was observed and evaluated.

b.

Observations and Findin s On October 23, 1996, the licensee identified a pin hole leak on a MS drain line.

This plant condition was documented in condition report (CR) 96-1980.

The licensee established an event response team (ERT) to evaluate the issue.

The pin hole leak was determined to be the result of impingement related erosion from the reactor core isolation cooling (RCIC) drain line piping, which joins the MS pipe at this location.

On October 28, 1996 the licensee conducted a Unit 1 shutdown from approximately 37% power, in response to the need to repair the drain line leak.

Two issues were involved with the erosion related pipe degradation repair:

(1)

Susquehanna Station (SSES) management determined that an on-line repair scheme for the drain line piping was not appropriate.

The inspector

~

~

~

~

'Topical headings such as 01, MS, etc.. are used in accordance with the NRC standardized reactor inspection report outline.

Individual reports are not expected to address all.outline topic discussed the shutdown with SSES management and determined that the decision to shutdown was made based on conservative interpretations of previous submittals to the NRC; a desire to maintain long term availability of the unit, and a desire to reduce the risk of personnel injury. The SSES submittals to the NRC addressed secondary bypass leakage and the qualification of the lines, including this pipe, covered by the secondary bypass leakage calculations.

(2)

There was a potential for other similar problems, because this pipe leak was not identified by the SSES erosion corrosion program.

Further, this pipe was not included in the monitoring portion of the erosion corrosion program.

On October 30, technicians identified additional portions (approximately 15 feet) of this drain line that required replacement.

The original portion to be replaced was approximately 12 feet.

c.

Conclusions The plant condition was identified by the licensee and vigorously pursued through the CR process and the ERT process.

Each of the processes was strongly supported by senior PPSL management on site and off. Site management made a conservative determination based on their interpretation of plant and personnel safety.

This particular piping was not included in the monitoring portion of the SSES erosion corrosion program (see paragraph M2.1 of this report).

01.2 Failure of the Unit 1 'C'eactor Feedwater Pum RFP Level Control Function a.

Ins ection Sco e 71707 The operator's response to a plant transient involving the failure of the 'C'FP controller was evaluated by the inspector.

b.

Observations and Findin s On October 23, 1996, the licensee experienced a transient related to the failure of the automatic level control function of the 'C'FP.

Unit 1 was in the process of power ascension after completing its ninth refueling outage.

When the operator attempted to place the 'C'FP in automatic reactor water level control, feedwater demand failed to zero, stopping feed flow from this pump.

Attempts to recover the loss of level control with the 'C'FP were unsuccessful and the 'B'FP was placed into service.

Reactor water level was recovered at or about 29 inches.

Reactor power level fluctuation during the event was about 1%. Although there was a fluctuation in power level and reactor water level, there was no safety impact as a result of the even Conclusions An upset condition resulted from a failed level controller on the 'C'FP.

The operators responded adequately to this upset condition and there was no impact on the safe operation of the Unit.

Failure of the 2D613 125 Vdc Batter Char er Ins ection Sco e 71707 On October 22, at approximately 10:15 p.m., the Unit 2 control room received an annunciated alarm (AR206-A12), indicating trouble with the functions associated with battery charger 2D613. At 10:50 p.m., the battery charger was declared inoperable.

At 11:50 p.m., the associated battery was declared inoperable based on several low cell voltage readings.

At 6:20 a.m., the licensee exited the applicable limiting conditions for operation (LCOs) having repaired the battery charger and recharged each cell above the required individual cell voltage.

The inspector reviewed and evaluated the October 22 event involving the failure of battery charger 2D613.

Observations and Findin s The battery charger failed as a result of a faulted silicon rectifier. The failure mechanism resulted in an instantaneous fault that was annunciated in the control room.

At 10:15 a.m., it was not clear to the operators that the battery charger was inoperable, and the inspector would consider it unreasonable to enter an LCO at this point in the event.

At 10:50 p.m., there was a clear understanding by the operators that the battery charger was not available to perform its intended purpose, and the time that it effectively became unavailable was when the annunciator alarmed (10:15 p.m.) ~ However, the operators determined that the appropriate time to document entry into the TS action statement was at 10:50 p.m.

However, the selection of the 10:50 p.m. time to document entry into the TS LCO was not indicative of the actual availability of the battery charger, once its failure had been determined at 10:50 p.m.

No violation of NRC requirements occurred because with either start point the LCO action statement requirements were met.'owever, there was a clear indication of the initiation of the event at 10:15 p.m.

Conclusions An event involving the failure of battery charger 2D613 resulted in an LCO entry and the battery charger being declared inoperable.

However, the inspector determined that the appropriate time to document entry into the TS LCO was at 10:15 p.m. vice 10:50 p.m.

No violation of NRC requirements occurred.

However, with a clear indication of the initiation of the event, the selection of the later time for LCO entry was not conservative.

A similar issue is discussed in section 01.4, belo t

01.4 T-Factor Less than 1.00 Durin the Unit 1 Startu a.

Ins ection Sco e 71707 During the Unit 1 startup on October 24, at approximately 38% power, a core flux parameter (T-factor) was calculated to be less than 1.00.

Variation in the T-factor is a function of the rod program and was an anticipated condition by SSES Reactor Engineering.

The inspector evaluated the operators'esponse.

b.

Observations and Findin s The inspector observed and reviewed a Unit 1 startup, in which the T-factor was calculated to be less than 1.00.

The T-factor is defined in Unit 1 Technical Specifications as the fraction of thermal power divided by maximum fraction of limiting power density (MFLPD). The rod program (bank position withdrawal sequence)

in use at the time combined with the core power history (Xenon pattern)

caused the core power to be peaked towards the bottom of the core.

The T-factor was monitored by a reactor engineer, at the powerplex typwriter, on a control room back panel

~ When the T-factor drops below 1.0, entry into limiting condition for operation (LCO) 3.2.2 is required by Unit 1 TS.

It is unclear to the inspector whether or not the operators were notified immediately by the reactor engineer when the T-factor dropped below 1.0 at 7:49 p.m, but the operators were notified at 7:55 p.m.

When the operators entered LCO 3.2.2, at 8:12 p.m., they performed the appropriate rod insertion steps to meet the requirements of the TS.

The inspector determined the following time sequence with respect to operator action:

Typer alarm for calculations of T less than

7:49 p.m.

T-factor less than

LCO entered LCO exited 7:55 p.m.

8:12 p.m.

9:39 p.m.

The ultimate long term corrective actions of the shift operators were determined to be adequate and were completed within the requirements of the TS.

However, the operators did not enter the appropriate LCO when the T-factor was determined to be less than 1 at 7:55 p.m. The failure to enter TS LCO 3.2.2 at the time that the T-factor was initially indicated to be less than 1, by the plant computer, constitutes a violation of minor significance and is being treated as a Non-Cited Violation consistent with Section IV of the NRC Enforcement Polic The following aspects of the T-factor issue and associated reactor engineering/operations issues were reviewed to determine whether there was adequate control over plant reactivity and flux shape.

(1)

Adequacy of the Pull Sheet Procedure/Core Map In response to a previous reactivity addition control problem (described in condition report CR 96-1035), the licensee initiated a number of corrective actions among which was a reactive training task (Hot Box 96-123), and a strengthened Unit SRO oversite function for reactivity addition manipulations.

As a result of these activities the licensee identified that the rod configuration on the core map, associated with procedure RE-OTP-101, Rod Sequence, was inconsistent with the rod sequence procedure.

The incorrect core map was accompanied by a correct pull sheet procedure with which it varied.

Reactivity manipulations were halted by the control room operator and a correction to the core map was attained.

The inspector determined that the operators actions were insightful and were focused on the safe operation of the unit, and as a result identified the procedural error.

Operator performance in this case was an example of the effective and successful implementation of corrective actions to a previous weakness.

Because of the operator actions discussed above, this licensee identified and corrected violation is being treated as a non-cited violation, consistent with Section VII.B.1 of the NRC Enforcement Policy (2)

Independent Verification of the Pull Sheet Procedure/Core Map The independent verification performed on the pull sheet procedure and the core map was not a peer review.

The review was conducted by a first line supervisor during the review and approval process.

Although no violations of NRC requirements were identified, the performance of review, approval and independent verification functions by the same individual reduces the number of barriers available to eliminate personnel error from the calculational process.

(3)

Operations/Reactor Engineering Interface During reactor startups and scram time testing a reactor engineer assumes the function of a test director.

The functioning of the reactor engineer as a test director blurs the lines of communication between the reactor operator in the control room (PCO) and the reactor operator in the field. This issue was identified concurrently and independently by the inspector and the SSES Operations Superintendent.

Operations shift supervision initiated CR 96-1981 to document and resolve this issue.

No violations of NRC requirements were identified.

Conclusions Control room operators failed to enter TS LCO at 3.2.2 at the time that the Unit 1 T-factor was indicated to be less than 1 by the plant computer, which constitutes a

violation of minor significance, Reactor Engineering failed to provide an adequate

procedure, in the form of a correct core map, to control the positioning of the Unit 1 control rods.

The error was identified by the insightful actions of the control room operators.

Because of the operator actions, the violation involving an inadequate procedure is being treated as a licensee identified non-cited violation.

Operational Status of Facilities and Equipment 02.1 Unit 1 Seismic Monitor a.

Ins ection Sco e 71707 The inspector observed the physical condition of the Unit 1 seismic monitor, reviewed the surveillance used by the licensee to determine seismic monitor operability, and evaluated the equipment deficiency history associated with the seismic monitor.

b.

Observations and Findin s Through a review of Surveillance SI-099-201, it was determined that a history of test surveillance failures did not exist for the Unit 1 Seismic Monitor. Based on a review of recent condition reports (CR), it was determined that two CRs, 96-1735 and 96-781, were issued to describe licensee identified conditions requiring resolution.

Action item ¹1, response resonance frequency, of CR 96-781 is still open.

The general condition of the system was discussed with the system engineer who informed the inspector that the modification DCP 94-9075 was scheduled to resolve the above listed CR action item.

The inspector noted a divergence from the excellent project/system cognizance that is normally maintained by SSES Nuclear System'Engineering (NSE).

System performance, maintenance, surveillance, and training data did not appear to be trended, tracked or evaluated for overall system condition.

NSE normally plays a pivotal role in operability determinations that are performed in support of SSES TS compliance questions.

It may be more difficultfor NSE to establish an adequate basis for a future operability determination of the seismic monitoring system without the data that NSE normally maintains for each TS related system.

c.

Conclusions The Unit 1 seismic monitor was determined to be operable, in good physical appearance, and not the subject of significant adverse maintenance or condition report histor O22 Unit 1 Acoustic Monitor 0 erabilit Ins ection Sco e 71707 Following an October 19, 1996, event, the inspector observed the operable status of the 16 safety relief valve (SRV) acoustic monitors in accordance with TS 3.3.7.5, reviewed the surveillance used by the licensee to determine acoustic monitor operability, monitored the corrective actions associated with CR 96-1940 and evaluated the equipment deficiency history associated with the SRV acoustic monitors.

b.

Observations and Findin s On October 19, 1996, Unit 1 control operators received an indication that the

'L'afety relief valve (SRV) had possibly lifted. The inspector determined that the operators responded appropriately, that the SRV had not actually lifted, and that the false indication was the result of a failed acoustic monitor.

The inspector reviewed the licensee's corrective actions to this event and reviewed the status and corrective actions for two additional acoustic monitor failures ('R'nd

'G'). The 'G'coustic monitor displayed no response during a recent automatic depressurization system (ADS) 150 psig lifttest.

The 'G'coustic monitor was typical of approximately 5 of the 16 SRVs that have a low sensitivity response.

The licensee determined that the 'G'coustic monitor was operable, despite the absence of an indication during the ADS test, based on its acceptable response to mechanical perturbation.

The 'R'coustic monitor was determined by the licensee to have a failed charge converter during verification activities that followed'he 'L'coustic monitor failure.

The.'R'coustic monitor failure was determined by the inspector to be nonconservative in that the failure did not cause an alarm in the control room, was not identified by the licensee prior to the implementation of corrective actions for the 'L'coustic monitor, and resulted in an inoperable acoustic monitor.

Because of the failure mode of the 'R'coustic monitor, the absence of an alarm indication upon failure, the method of discovery by the licensee, and the operating condition Unit 1 was in when the failure was identified, no violation of NRC requirements were identified.

The inspector determined that the licensee's return to service of the acoustic monitors was adequate.

C.

Conclusions The Unit 1 acoustic monitors were determined to be operable, the licensee's corrective actions regarding recent acoustic monitor failures were adequate, and no violations of NRC requirements were identifie Operator Knowledge and Performance 04.1 Loss Of Control Rod Scram Accumulator Alarms a.

Ins ection Sco e 71707 On September 5, 1996, at 6:00 p.m., with Unit 1 at 100% power, the common power supply for all control rod scram accumulator alarms failed. The inspector noted an associated LCO log entry during a routine control room tour and subsequently reviewed the licensee's actions in response to the failure and compliance with TS requirements.

b.

Observations and Findin s Each control rod scram accumulator alarm provides indication of either water in-leakage or loss of nitrogen pressure on a given hydraulic control unit (HCU).

These alarms are tested every 18 months under TS Surveillance 4.1.3.5.

In response to the loss of all scram accumulator alarms, the Unit Supervisor (US)

declared all of the accumulators inoperable.

TS 3.1.3.5, Action a.2(b), directed operators to insert the inoperable control rods and disarm the associated directional control valves, otherwise, be in at least Hot Shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

According to CR 96-1358, "Since it was impractical to insert and hydraulically disarm the control rods, the twelve hour to hot shutdown portion of the action statement was entered."

The inspector reviewed TS 3.1.3.5 and noted that Action a.2 requires operators to declare the associated control rods ino erable and: insert and hydraulically disarm the control rods, otherwise be in hot shutdown within twelve. hours.

According to the Unit 1 LCO log, the action statement for TS 3.1.3.1, Control Rod Operability, was not entered and the associated control rods were not declared inoperable.

The inspector determined that the otherwise clause of TS 3.1.3.1 Action b.1 would be applicable and directed operators to insert the inoperable withdrawn control rods and disarm the associated directional control valves.

This action was not implemented by the operators.

The annunciator power supply was replaced in approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> and then functionally tested during a "burn in" period prior to its being declared operable.

When power was restored to the alarms,'the licensee discovered that the accumulator pressure for control rod 14-31 had dropped below the 940 psig required for operability.

Following the power supply "burn in" period, and restoration of nitrogen pressure for control rod 14-31, the accumulator alarms were declared operable and the TS 3.1.3.5 action statement was cleared at 11:50 p.m.

on September The inspector determined that the entry into TS 3.1.3.5 was not specifically required for the loss of the alarms, but since the operator concluded that the specification was applicable, he was then required to follow through with the TS Actions.

The inspector discussed the occurrence with a cognizant Unit Supervisor and was told that although compensatory measures to verify scram accumulator operability were known to exist in a related Alarm Response procedure, these actions were not taken because the particular annunciator had not alarmed.

In review of this event, Operations management determined that an error was made when all scram accumulators were initially declared inoperable.

PPRL's position is that the TS Action statement was not applicable for the loss of indication.

Operations management shared the inspector's concern regarding the operators'ecision to not implement the TS Actions, once they had declared the accumulators inoperable.

As corrective actions, the operators involved in this incident have been counseled, lessons learned training is planned for all Operations shifts, and changes have been made to Alarm Response procedure AR-103-001 to clearly describe the expected compensatory measures for loss of the scram accumulator alarms.

C.

Conclusion Operators failed to take the actions required by Technical Specifications after they declared all Unit 1 scram accumulators inoperable due to a loss of associated control room alarms.

In review of this event it was determined by the inspector that entry into the TS Action statement was not specifically required, however operators made this determination and did not follow through with all actions required.

PP&L has initiated suitable corrective actions and provided better guidance in control room procedures.

The inspector concluded that the operators'ational for not taking the TS required actions, once they concluded the specification was applicable, was inappropriate.

The operators'ustification for not initiating compensatory measures was viewed as nonconservative and demonstrated a poor safety perspective.

Since the operability of the scram accumulators was not challenged, and no applicable TS action statements were exceeded, no violation NRC of requirements occurred.

Quality Assurance in Operations 07.1 Nuclear Assessment Services NAS - Self Initiated Surveillance Activities a e Ins ection Sco e 71707 The inspector reviewed a summary of surveillance activities performed during the last three years, selected specific findings to discuss/review, held discussions with a sample of SSES first line management, and held discussions with site and corporate NAS representatives.

These inspection activities were performed in order to assess the impact of NAS self initiated Quality Surveillance Group surveillance activities on SSES quality activities and the safe operation of SSE Observations and Findin s The selected sample included only self initiated, defined, and implemented surveillance activities performed by the SSES NAS Quality Surveillance (QS) Group.

The selected sample did not include surveillance activities that were requested by SSES line management, nor did the sample include activities that were referred to NAS through some other third party (ex. PPRL corporate management, SSES employee concerns, SSES ISES, third party allegations made to PPRL). Based on the previously mentioned breadth of licensee surveillance activities, including those NAS QS self initiated surveillance activities, the licensee appears to meet its programmatic requirements.

Based on the selected sample, the inspector determined that the activities performed by the NAS surveillance group was weighted towards referred activities vice broad based self-initiated surveillance activities.

Aside from those referred activities the impact of the NAS surveillance activities was limited to specific areas (ex. cranes, refueling activities) and did not display a wide scope of technical areas.

The findings and recommendations from the surveillance activities were generally related to process and administrative areas.

Although some good technical issues were identified, on a whole there did not seem to be a substantial visible impact in the technical, operational and/or professional areas.

C.

Conclusions Based on a selected sample of NAS surveillance activities the inspector determined that the activities performed by the NAS surveillance group were weighted towards referred activities.

The findings did not display a wide scope of technical areas and were generally related to process and administrative areas.

There were no visible indications that the sampled surveillance activities, as a whole, had a major impact on the quality of plant operations.

Miscellaneous Operations Issues (92700)

08.1 U date EEI 50-387 96-08-03: 'E'G misalignment related to failure to follow procedures NRC Inspection Report 50-387/96-08 discussed the misalignment of the 'E'G auxiliary equipment supply breaker on June 14, 1996.

Several examples were identified in Section 01.1 of that report where PPSL personnel failed to implement station procedures, contributing to the misalignment itself or the delay in its identification.

These apparent violations were identified as being considered for escalated enforcement (reference EEI 96-08-03).

One example concerned the failure of shift personnel to complete written statements before leaving the site as required by Ol-AD-080. The inspector determined that the Shift Supervisor failed to initiate the status control investigation required by Ol-AD-080 and that this was the reason the written statements were not completed by the shift personnel.

This information is provided for clarification of the example originally describe.2 Closed Violation VIO 50-388 96-01-01:

Secondary Containment Damper a.

Ins ection Sco e 71707 On February 15, 1996, with Unit 2 at 100% power, stroke time testing was performed on secondary containment Zone III dampers.

After a series of test failures an inoperable damper was returned to service.

It was later determined that a non-licensed operator assisted the movement of a damper, invalidating one of the tests.

b.

Observations and Findin s The licensee instituted a number of immediate corrective actions including shift training and the communications of management expectations.

The inspector completed a review of a sample of the immediate and long term corrective actions and determined that they were performed and were performed in an adequate manner.

c.

Conclusions The licensee completed adequate immediate and long term corrective actions for this violation. Violation 50-388/96-01-01 is closed.

08.3 Closed VIO 50-388 95-17-01: Failure to enter TS 3.0.3 during LOCA/LOOP testing

~

~

~

~

On April 29, 1995, PPSL failed to enter TS 3.0.3 during the performance of a surveillance which disabled auto-close permissive relays for the primary and alternate supply breakers to Engineered Safeguards System (ESS) buses 18 and 1D.

PPSL committed to corrective actions in a letter dated September 28, 1995, that included procedure revision, training, and submittal of a proposed TS change.

The inspector verified implementation of the procedure changes and reviewed records from training conducted for licensed operators and test directors.

A TS change request was submitted to NRR to allow performance of the surveillance without entering TS 3.0.3, however the change was not approved in time for the Unit 1 9th refueling outage and is being retracted.

PPSL stated that the electrical specification proposed under the Improved Technical Specification (ITS) submittal will provide the desired allowance for this TS required surveillance test.

The inspector concluded that PPS.L had taken appropriate actions in response to the violation that can reasonably be expected to preclude recurrence.

This violation is close.4 Closed Unresolved Item URI 50-387 94-09-02:

Reactor Feed Pump Turbine Trip Logic Ground a.

Ins ection Sco e 71707 On May 9, 1994, a 125 volt DC ground was identified that disabled all electrical trips for the Unit 1 'A'eactor Feed Pump Turbine (RFPT) ~

b.

Observations and Findin s The disabling of all automatic and remote electric trips for the 'A'FPT was not well responded to by the control room operators and not well communicated to plant management.

An Unresolved Item (URI) was opened in order to review licensee final corrective actions including actions to prevent recurrence.

The licensee's corrective actions were reviewed by the inspector and determined to be adequate with one exception.

The exception accounted for entering into TS 3,0.3 when there is an operability question that could affect both trains of feedpump equipment.

The TS are not specific in this case.

The exception was resolved during a meeting with PPSL Operations Management which resulted in a change to an SSES procedure that referenced the licensee's improved TS submittal

~

C.

Conclusions Subsequent to the meeting and the TSI change, the licensee's corrective actions were determined to be adequate.

Due to the ambiguity of the TS, and an adequate action by the licensee, it was determined that no violation of NRC regulations occurred.

This URI is closed.

08.5 Closed URI 50-387 388 96-08-04:

Failure to Perform Alarm Panel Test NRC Inspection Report 50-387,388/96-08 addressed weaknesses in the performance of TS surveillances and nuclear plant operator (NPO) rounds.

The identified weaknesses in these areas will be tracked and addressed by escalated enforcement item (EEI) 50-387, 388/96-08-03.

This item is administratively closed to allow it to be tracked and resolved under EEI 50-387/96-08-03.

Violations of NRC requirements will be addressed under the EEI ~

This URI is closed.

08.7 Closed URI 50-387 388 96-03-02 and 96-03-03:

NRC Inspection Report 50-387,388/96-06 addressed specific design conditions in the Standby Gas Treatment System (SBGTS).

On March 13, 1996 NRC Region I

submitted a task interface agreement (TIA) to NRR in order to evaluate the design conditions.

The TIA resulted in NRR Task Action Commitment (TAC) M94994 and M94995.

In June 1996 the NRC informed the licensee, by letter, that the NRC would resolve whether or not these design conditions met NRC design criteria.

These URls are administratively close.8 Closed Ins ector Followu Item IFI 50-387 92-23-03 NRC Inspection Report 50-387,388/92-23 addressed specific design conditions in the use of Kaowool for fire barriers and the calculations that supported the use of Kaowool. NRC Region I submitted a task interface agreement (TIA) to NRR in order to evaluate the design conditions.

The TIA resulted in NRR TAC's M84770 and M84771.

These Task Actions have been incorporated into the NRR Fire Protection Task Actin Plan (TAP) which will address these and other issues on a generic industry basis.

The NRR TAP will resolve whether or not these design conditions meet NRC design criteria. This IFI is administratively closed.

08.9 Closed Licensee Event Re ort LER 50-387 96-09 a.

Ins ection Sco e 71707 On August 13, 1996, with Unit 1 at 100% power, the licensee concluded that a condition prohibited by the plant's TS had been entered when a primary containment isolation valve was involved in a maintenance activity.

b.

Observations and Findin s The inspector determined that the subject valve (Core Spray containment isolation valve) functions in a single isolation valve design which credits a liquid loop seal as a second isolation function.

Because the licensee failed to recognize the impact of the single isolation valve design on compliance with TS 3.6.3 the subject TS action statement time was exceeded.

The licensee included this issue in the TS program, issued a formal TS interpretation and conducted operator training.

c.

Conclusions The licensee properly reported the event and took adequate immediate corrective actions. The determination of whether or not a violation of NRC requirements occurred, will be resolved under EEI 50-387/96-09-01.

This LER is closed.

08.10 Closed LER 50-387 96-06 a.

Ins ection Sco e 71707 On August 1, 1996, Unit 1 experienced a reactor trip which resulted from a turbine high vibration trip.

b.

Observations and Findin s The inspector determined that the Unit responded as designed and the operators performed adequately.

The inspector determined that the trip resulted from an equipment failure to which the licensee had been previously alerted.

The licensee's response to the balance of plant, nonsafety related precursor alarm and indications for this transient was wea c.

Conclusions The licensee properly reported the event and took adequate immediate corrective actions. The failure to adequately respond to balance of plant conditions does not constitute a violation of NRC regulations.

This LER is closed.

08.11 Closed LER 50-387 96-04 The, licensee properly reported the event and took adequate immediate corrective actions. Violations of NRC requirements will be addressed under EEI 96-08-03.

This LER is closed.

08.13 Closed LERs 50-387 95-15-00 and 95-15-01 a.

Ins ection Sco e 71707 On December 11, 1995, with Units 1 and 2 at 100% power, the licensee determined that a non-conservatism in the heat balance equations had resulted in exceeding the licensed shift average core thermal power by up to 1.8 MWt.

b.

Observations and Findin s

This issue was documented on CR 95-0719.

The inspector reviewed the corrective action indicated in the condition report and the information provided in the LER.

On June 26, 1996 the licensee updated the original LER and determined that the actual core thermal power was less than that calculated in the heat balance reported in the original LER. The licensee further determined that the license limit was never exceeded on a shift basis and that it was appropriate to retract the original LER.

c.

Conclusions The licensee properly reported the event and took adequate immediate corrective actions.

Long term considerations are still in progress.

No violations of NRC requirements were identified. This LER is closed.

08.14 Closed LER 50-387 94-15-01 a.

Ins ection Sco e 71707 On September 12, 1994, with both units operating at 100% power, two postulated single failure events were discovered which could cause the plant to be outside of its design basis during a postulated Loss of Coolant Accident (LOCA).

b.

Observations and Findin s These issues were originally identified by the licensee in August 1990 and documented in Engineering Deficiency Report (EDR) G00153.

The issues were reported in LER 94-15, and inspected in NRC Inspection Reports 94-20/94-21 and 96-03.

The results of the above inspections were EEI 96-03-01, URI 96-03-02, URI 96-03-03, and EEI 96-03-04.

As a result of the above NRC inspections and PPRL initiatives, the licensee performed additional analysis of the reactor building recirculation system and the SBGTS. A modification was performed to place a time delay relay into the SBGTS outside air damper circuitry that is intended to ensure that the postulated single failures in the SBGTS will not impact reactor building draw down time requirements.

In addition, the licensee determined that the single failure originally identified in LER 94-15 was not credible based on an engineering calculation.

c.

Conclusions t

the above indicated EEI and 08.15 Closed LER 50-388 96-08 The licensee properly reported the event and took adequate immediate corrective actions (after reporting the event) to resolve the technical issues in the short term.

Lon term considerations and enforcement actions will be resolved as a function of URI actions.

This LER is closed.

This LER reported PP&L's entry into TS-3.0.3 on October 8 and 9, 1996, during the performance of an 18 month TS surveillance which disabled. the auto-close permissive relays for the primary and alternate supply breakers to ESS buses 1B and 1D. The necessity for PPRL to enter TS 3.0.3 is discussed in NRC Inspection Report 50-387/95-17, Section 6.1 under LER 50-388/95-06.

The inspector noted that PPRL's ITS submittal contains provisions for having more than one Unit 1 load group not energized at the same time without entering TS 3.0.3.

The inspector determined that the LER provided adequate information to assess the occurrence and that no violation of NRC requirements occurred.

08.16 Closed LER 50-388 96-07 a.

Ins ection Sco e 71707 On October 1, 1996, the license determined that a condition prohibited by TS had occurred as a result of maintenance activities on the Unit 1 secondary containment Zone III isolation dampe b.

Observations and Findin s The inspector determined that operability testing did not occur because the maintenance activity was associated with Unit 1 outage activities and it was not determined by the licensee that the work activity affected Unit 2. This resulted in TS LCO 3.6.5.2 being exceeded for a short period of time.

c.

Conclusions The licensee properly reported the event and took adequate immediate corrective actions. The failure to adequately perform the required TS surveillance during the reactor startup procedure constitutes a violation of minor significance and is being treated as a Non-Cited Violation consistent with Section IV of the NRC Enforcement Policy. This LER is closed.

08.17 Closed LER 50-388 96-06 This LER reported PPRL's entry into TS 3.0.3 due to both loops of the Containment Radiation Monitors (CRMs) for RCS leak detection being isolated at the same time.

Entry into TS 3.0.3 was necessary in support of a maintenance related transfer of the Reactor Protection System power supply because of CRM isolation logic design and the fact that TS 3.4.3.1 does not address having both loops isolated.

This issue was addressed in NRC Inspection Report 50-387/96-09.

The Action Statement of TS 3.0.3 was exited when the CRMs were returned to an operable status.

The inspector determined no violation of NRC requirements occurred.

08.18 Closed LER 50-388 96-05 a.

Ins ection Sco e 71707 On July 30, 1996, with Unit 2 at 0% power, the licensee failed to perform a TS required surveillance.

b.

Observations and Findin s During a reactor startup the licensee failed to perform a rod control surveillance after the first in-sequence control rod had been selected and withdrawn to position 48.

Instead, the licensee continued with the startup sequence and withdrew a second rod to position 10. The condition was identified by the Unit 2 Supervisor, the second rod was returned to position 00, and the startup activities halted to affect corrective actions.

e The inspector reviewed the event and the licensee's corrective actions.

It was determined that the licensee failed to meet TS surveillance requirement 4.1 4.2.b.

It was further determined that: the licensee's initial corrective actions were adequate; the root cause of the error was a combination of the failure of a Unit Supervisor to follow the prescribed procedure and a failure of the Unit Supervisor to

oversee and control the prescribed procedure; and training and experience weaknesses were also present.

Although the failure,resulted in a reactivity addition not in sequence the proscribed steps of an approved procedure, the reactivity addition was controlled and accounted for in the Unit 2 restart analysis.

Although the failure to adequately supervise, second check and/or control rod movement was considered a significant weakness in reactivity control, a minimum physical impact on plant safety was identified by the inspector.

c.

Conclusions The licensee properly reported the event and took adequate immediate corrective actions. The failure to adequately perform the required TS surveillance during the reactor startup procedure constitutes a violation of minor significance and is being treated as a Non-Cited Violation consistent with Section IV of the NRC Enforcement Policy. This LER is closed.

08.19 Closed LER 50-388 96-04 a.

Ins ection Sco e 71707 On July 14, 1996, Unit 2 was manually scrammed from 100% power on decreasing reactor water level.

The plant condition resulted from a maintenance induced trip of two condensate pumps.

The subject maintenance involved the improper termination of two leads on a 13.8 kV bus cubicle breaker.

b.

Observations and Findin s The licensee implemented a large number of corrective actions including an inspection of all 13.8 and 4 kV cubicle internals for lifted leads and signs of obvious tampering.

The inspector determined the licensee's corrective actions to be adequate.

It was determined by the inspector that the significance of the inadequately performed maintenance was minor. However, the consequences of the inadequately performed maintenance activity was an unexpected plant transient that remained within the design basis.

c.

Conclusions The licensee properly reported the event and took adequate corrective actions to the reactor scram and the identified weaknesses in the maintenance activity. This analyzed transient resulted from an inadequately performed maintenance activity on nonsafety related balance of plant equipment.

Therefore, the failure to perform adequate maintenance does not constitute a violation of NRC requirements.

This LER is close a.

Ins ection Sco e 71707 On May 1, 1996, while Unit 2 was at 100% power the licensee discovered that the reactor water cleanup system penetration room'differential temperature channels were inoperable for approximately 56 days, in violation of TS 3.3.2.

b.

Observations and Findin s These issues were originally identified by the licensee in EDR 93-115.

The conditions were addressed in January 1991 through a TS change request.

The TS change was granted in October 1992, and new setpoints were implemented in April 1993.

The NRC inspected the above issues in April 1996.

The licensee implemented corrective action (repositioned supply louvers) in June 1995.

The results of the above inspection was EEI 96-03-01.

As a result of the above NRC inspections and PPSL initiatives, the licensee performed additional analysis and determined that the differential temperature channels were operable.

The inspector reviewed the operability determination and found it to be administratively adequate.

c.

Conclusions The licensee properly reported the event and took adequate immediate corrective actions.

The timeliness of the corrective actions is subject of current enforcement actions.

Long term considerations and enforcement actions will be resolved as a function of the above indicated EEI action.

This LER is closed.

08.21 Closed LER 50-388 96-02 a.

Ins ection Sco e 71707 On February 15, 1996, with Unit 2 at 100% power, stroke time testing was performed on secondary containment Zone III dampers.

After a series of test failures it was determined that an operator assisted the movement of a damper during one of the tests.

b.

Observations and Findin s This issue was inspected in Inspection Report 96-01 and a notice of violation was issued (VIO 50-388/96-01-01).

The licensee instituted a number of immediate corrective actions including shift training and the communications of management expectation c.

Conclusions The licensee properly reported the event and took adequate immediate corrective actions.

Long term considerations and enforcement actions will be resolved as a function of the above indicated violation. This LER is closed.

II. Maintenance M1 Conduct of Maintenance M1 ~ 1 General Comments a.

Ins ection Sco e 62703 The inspectors observed/reviewed portions of work activities which included preplanned, preventive and emergent maintenance.

In addition selected maintenance rule requirements were inspected.

The inspectors observed/reviewed portions of surveillances to; ensure conformance with TS, verify that instrumentation was properly calibrated, evaluate the appropriateness of LCO entry, and review the quality of data and equipment performance.

In some of the surveillance activities the inspector evaluated the use of permit tagging and return to service to ensure equipment/personnel safety and equipment availability, b.

The followin licensee activities were observed reviewed:

~

P64024

~

S67663

~

S67567

~

P61853 Explosive Monitor Maintenance Loose Parts Monitor, Unit

Safety Relief Valve, Unit 1,

'L'tandby Gas Treatment System Alison Fire Detection System

~

SO-155-001

~

SI-1 83-326

~

OP-1 93-002

~

OP-273-001

~

OP-149-002

~

SC-116-102 Scram Time Testing, Unit 1 Acoustic Monitoring Logic, Unit 1 Turbine Test, Unit 1 Containment Atmosphere Control, Unit 2 Shutdown Cooling, Unit 1 RHR Service Water Monitor, Unit 1

~

OP-149-001 RHR Depressurizing, Unit

c.

Conclusion Those maintenance activities discussed in this section of the report were performed adequately.

The activities associated with WA 61853 were especially well performed in that the controlling documentation was prescriptive, were carefully implemented, and included first line management oversight.

M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Main Steam MS Drain Line Erosion a.

Ins ection Sco e 62703 On October 23, the licensee identified a pin hole leak on a MS drain line. This plant condition was documented in condition report CR 96-1980.

The licensee established an ERT to respond to the issue.

The pin hole leak was determined to be the result of impingement erosion from RCIC drain line piping.

b.

Observations and Findin s The affected areas were cut out, replaced and analyzed by the licensee.

The erosion was in the form of a cup shaped two inch circle directly across from the RCIC tap into the MS drain line. A second eroded area of similar shape was identified at the high pressure coolant injection (HPCI) tap into the MS drain line.

The inspector observed the replacement, and analysis of the piping and determined that the erosion across from the RCIC tap was approximately twice the damage suffered across from the HPCI tap.

The cause of the erosion appeared to be flow impingement and the difference between the two taps appeared to be related to a flow configuration change instituted by the licensee to eliminate a high level condition in the RCIC steam line drain pot.

In order to eliminate a continuously alarmed'condition corresponding to high level in the drain pot the licensee permanently bypassed flow around the pot, This effectively increased the flow rate into the steam line RCIC tap and therefore the impingement rate.

The inspector determined that the licensee's program met the expectations of the program established by EPRI and accepted by the NRC. It was further determined that two programmatic weaknesses contributed to this erosion related fault:

(1)

The licensee's program did not account for this type of impingement damage and did not track through Ultrasonic Testing (UT) the condition of the T connection tap because of low expected flow rates.

(2)

The licensee's program did not account for changes in normal operational configurations (such as the continuous bypassing of the drain pot) that may alter flow considerations from the original erosion program calculation As a result of a very aggressive response to the pin hole leak, PP&L management determined that there were approximately four additional locations that could suffer the same type of damage.

Each of the locations was subjected to UT and no additional excessive damage was identified.

The PP&L program was updated to include the subject locations in the monitoring phase of the program.

The inspector forwarded the generic aspects of this issue through the NRC Region I

office to the NRR Chemical Engineering Branch office to determine industry wide impact.

c.

Conclusion The licensee identified a pin hole leak on a MS drain line, that was determined to be the result of impingement erosion from an RCIC drain line piping T connection.

The affected areas were cut out, replaced and analyzed.

The licensee's erosion program met the current expectations of the program established by EPRI ~ However, two programmatic weaknesses contributed to this erosion related fault: the licensee's program did not account for this type of impingement damage; and the program did not account for changes in normal operational configurations that may alter flow considerations used in the original erosion program calculations.

The licensee's response to the pin hole leak was very aggressive and no additional locations of excessive damage were identified.

M2.2 Corrective Maintenance Backlo a.

Ins ection Sco e 62703 A review of the maintenance backlog not associated with outage activities was conducted by the inspector.

The review was based upon upper tier summary sheets and lists provided by the licensee and a sample of the backlog work authorizations (WA).

b.

Observations and Findin s The inspector determined that the licensee adequately tracks, trends and prioritizes the existing uncompleted maintenance.

Safety related maintenance activity appears to be given the correct emphasis with approximately 80% of the emerging work completed in approximately one week.

Many of the WAs were associated with condition reports and had operability determinations performed.

c.

Conclusions The inspector concluded that the licensee adequately tracked, trended, resolved and prioritized the existing maintenance backlo M2.3 Minor Maintenance Activit rouble Shoot and Re air a.

Ins ection Sco e 62703 A review/inspection of a sample of minor maintenance activities and trouble shooting activities was performed.

Because of the potentially severe exposure consequences to SSES maintenance and/or operations workers, the activities performed under WA 67622, for the Traversing In-core Probe (TIP), were chosen for a detailed review.

b.

Observations and Findin s On November 5, 1996, while performing incore monitoring activities, the Unit 1 reactor operator noticed that the TIP withdrew beyond its normal position and appeared to have moved at an excess speed.

When the TIP was withdrawn, it traveled to the 9747 position rather than the expected 0000 position.

The operators ensured that the TIP was withdrawn and that personnel access to the TIP area was limited and controlled.

The inspector reviewed/inspected the event and determined:

~

The operator's actions were good and the impact on worker exposure was carefully controlled.

~

The trouble shooting and repair activities described on the WA were not prescriptive in nature.

~

The data recorded in.the WA was adequate to determine which component was replaced.

The data recorded in the WA did not include an indication of as left acceptance criteria and was not adequate to determine the cause of the failure, or the acceptability of the as left condition of the TIP. Specifically, the as left position for the TIP was 9762 compared to the expected position of 0000.

There was no indication on the WA whether the as left position was acceptable or guaranteed that the TIP was fully withdrawn and would not present a personnel exposure problem.

The inspector further determined that the TIP system is a TS related system which requires an operability determination prior to its use, there was no safety consequence to the public from the failure, and no HP related consequences occurred as a result of good operator response to the event.

Therefore, no violations of NRC regulations were identified.

c.

Conclusions While performing incore monitoring activities, the Unit 1 reactor operator noticed that the TIP withdrew beyond its normal position and appeared to being traveling at

an excess speed.

The operator took good actions to identify and correct the cause of the condition and to limitthe possible exposure consequences of a not fully withdrawn TIP.

M2.4 Circulatin Water Pum Re air Ins ection Sco e 62703 On September 4, 1996, the Unit 1, circulating water pump failed, causing a reactor recirculation pump runback, a reduction of reactor power to 59% power, the loss of auxiliary equipment and an analyzed plant transient.

The failure was determined to be maintenance related.

On October 21, 1996, during the performance of an initial uncoupled post maintenance start of the Unit 1 'B'irculating water pump, the motor tripped on overcurrent, generating traces of smoke and an indication of a motor fault.

b.

Observations and Findin s The inspector reviewed/inspected the maintenance activity (conducted on WA S60704) and determined that Unit 1 did not suffer a transient associated with the most recent circulating water pump failure, as a result of the corrective action taken by the licensee in response to the previous transient.

The root cause of the maintenance related failure was determined to be an incorrectly assembled Elastimold connection.

The licensee performed a root cause evaluation and determined that the maintenance related failure was caused, in part, by the sequence in which the lug was attached to the motor.

The inspector reviewed MT-GE-022 section 8.5 which addressed the appropriate sequence'of maintenance activities on November 15, 1996 and determined that the procedure had not been updated.

Discussions with the responsible System Engineer and first line Maintenance Department supervision indicated that no documented crew training had taken place, that there were no procedure improvements underway and none were planned with respect to the sequence of assembly.

Although the licensee did evaluate the failures and prevented the second failure from affecting the unit operation in the second instance, corrective action to prevent recurrence of this type of failure was weak.

Because this maintenance activity involved non safety related equipment, and there was no present impact on the health and safety of the public, no violation of NRC regulations was identified.

C.

Conclusions on Conduct of Maintenance The Unit 1 'B'irculating water pump suffered a maintenance related failure, caused, in part, by the sequence in which the lug was attached to the motor.

Although the licensee evaluated the failure, corrective action to prevent recurrence of this type of failure was weak.

No violations of NRC regulations were identifie M2.5 a 0

Reactor Buildin Zone III Ventilation Dam er Failure Sco e 62707 61726 On September 22, 1996, operators discovered that the 'A'eactor Building Recirculation (RBR) fan did not automatically start in response to a Secondary Containment isolation signal.

PP&L's investigation found that a back draft damper (BDD27521) for the non-safety related Unit 2, Zone III exhaust system had failed open, allowing it to defeat a start permissive for the 'A'BR fan.

The inspector reviewed the maintenance history and surveillance testing for the failed back draft damper, and PP&L's corrective actions.

Observations and Findin s The RBR system is common to both SSES Units and is required to mix the atmosphere in the reactor building to obtain a lesser and more uniform concentration of radioactivity following a design basis Loss of Coolant Accident or refueling accident.

The recirculation system is comprised of two redundant fans that automatically start on a reactor building isolation signal.

The RBR system control logic starts the standby RBR pressure fan on a reactor building isolation signal coincident with loss of differential across the RBR supply and return plenums.

The loss of differential pressure is used as an indication that the lead RBR fan has failed.

BDD27521 and three similar dampers serve to isolate the RBR return plenum from the non-safety related Unit 1 and 2 Zone III exhaust fans (2 fan trains per Unit).

When functioning properly during normal operations, the BDDs prevent the Zone III exhaust fans from drawing a vacuum on the RBR return plenum which is normally not in service.

On September 22, the failed BDD27521 allowed the Unit 2 Zone III exhaust fan to draw a vacuum of 2 inches water gauge on the RBR return plenum and caused the pressure instrumentation to sense greater than 0.5 inches water gauge.

The differential pressure sensed provided a false indication to the RBR logic that the lead fan was running.

The inspector's review of the routine surveillance test procedures SE-159-200 and SE-124-107/207 for the RBR fans confirmed that these tests do not verify closure of the BDDs, but do confirm the dampers can open by running the fans, There are no remote indications for the position of the Zone III exhaust system's BDDs and access to BDD27521 for visual inspection is limited due to its location.

There are no preventive maintenance activities performed for these dampers.

A weld repair of BDD27521 was completed on September 24, and proper operation of the damper was confirmed by a post maintenance test.

An investigation by NSE determined that the remaining three Zone III BDDs were functioning properly.

PP&L

determined that the September 22 failure was a Maintenance Rule (10 CFR 50.65)

functional failure. PPRL's actions to prevent recurrence include:

~

A revision to the RBR fan differential pressure switch preventive maintenance to specifically check the plenum static pressure for indication of a BDD failure (this is performed twice per year).

~

Implementation of a 4 year preventive maintenance activity to verify the Zone III BDD positions, grease their bearings, and exercise the damper.

~

Investigation of the counterweight design to determine whether design enhancements are appropriate.

~

Evaluation of the surveillance testing program to determine if component testing in the standby alignment should be included.

The inspector discussed the Safety Assessment for this damper failure (reference CR 96-1599) with cognizant NSE personnel and supervision.

In order to impact the RBR system automatic start, more than one independent single failure would have to be assumed.

PPSL's corrective actions are directed at providing a routine method of detecting a future damper failure of this nature.

The inspector determined that the damper failure was not a condition that alone could prevent the system from performing its intended safety function.

PPRL's corrective actions for this failure provide a reasonable assurance that future damper degradation or actual failures will be detected in a timely manner.

c.

Conclusion PPRL's identification, evaluation, and disposition of a failed Reactor Building Zone III ventilation back draft damper were very good.

Corrective actions planned to prevent recurrence, specifically the improvements to routine surveillances, were viewed as reasonable and PPRL's classification of the damper failure was consistent with their maintenance rule implementing procedures.

M3 Maintenance Procedures and Documentation M3.1 Standb Gas Treatment S stem SBGTS Preventive Maintenance a.

Ins ection Sco e 62707 The inspector observed/reviewed maintenance activities associated with WA P61254 on the SBGTS.

b.

Observations and Findin s

These safety related activities were determined to be performed in an adequate manner.

However, the documentation of the activities was not accomplished during the performance of the maintenance.

Data sheet MT-GM-017 was observed by the

inspector to be blank despite the completion of the maintenance activities.

The inspector reviewed the completed data sheet after a discussion with the maintenance personnel and did not identify any safety concerns.

During the portion of this maintenance activity observed by the inspector, first line supervision was not observed in the field.

The failure to complete the maintenance data sheet during the performance of maintenance activities was viewed as a poor practice, since the accuracy of information could be less reliable.

C.

Conclusions Safety related activities on the SBGTS performed in an adequate manner.

However, the related documentation of as left measurements was not completed in a contemporaneous manner.

The inspector determined this was a poor practice since it could challenge the accuracy of these quality records.

M3.2 Observation of Instrument Calibration a 0 Ins ection Sco e 61726 On November 13, 1996, the inspector witnessed a quarterly channel calibration of a pressure switch for the Anticipated Transient Without Scram - Recirculation Pump Trip (ATWS-RPT) / Alternate Rod Insertion (ARI) reactor scram logic.

b.

Observations and Findin s The inspector witnessed performance of surveillance SI-262-302 for the high vessel pressure channel PS-B21-1N045C, which provides both the quarterly Channel Functional Test and the Channel Calibration required by TS 4.3.4.1.1.

The inspector verified the activity was conducted at the required frequency, in accordance with the surveillance procedure, and that applicable Technical Specification requirements for allowed performance time were met.

The instrument was appropriately removed from service and good communication with control room operators was noted.

A technical review of surveillance SI-262-302, Revision 9, was performed and confirmed that the procedure demonstrates, to the extent possible, that the tested portion of the logic willfunction as designed.

Following completion of the calibration, the inspector observed that the instruments were properly returned to service.

The inspector confirmed that the test equipment was within its current calibration cycle and that all surveillance acceptance criteria were met, No equipment discrepancies were identified.

C.

Conclusion Performance the quarterly channel calibration and channel functional test for the safety related pressure switch PS-B21-1N045C (ATWS-RPT and ARI) was observed.

The surveillance activity was appropriately controlled, technically complete, and well performe M5 Maintenance Staff Training and Qualification M5.1 Unit 2 13.8 kV Switch ear Leads Not Landed The inspector reviewed the qualifications, training and experience of the individuals involved in the maintenance activities which led to the July 14, 1996, Unit 2 transient, and found no indication of training or qualification deficiencies.

M8 Miscellaneous Maintenance Issues (92902)

M8.1 Closed Unresolved Item URI 96-10-01:

This URI addresses questions of operability related to the safety relief valve acoustic monitoring system.

The acoustic monitoring system provides a post event indication function and does not perform a control or a protective function.

The inspector reviewed the licensee's operability determination associated with condition report CR 96-1940.

This issue was reviewed in Section 02.2 of this report and closed.

No violation of NRC requirements were identified.

III. En ineerin E1 Conduct of Engineering E1.1 Im act of Boltin Preload on HPCI 0 erabilit a.

Ins ection Sco e 73051 The licensee issued an operability determination for an adverse condition identified by CR 96-1968.

The document addressed a plant condition that resulted from an improperly calibrated torque wrench.

As a result of the improper calibration some number of studs were torqued to approximately 2.5 times their normal torque during the reassembly of the HPCI turbine and casing.

b.

Observations and Findin s The following weaknesses with the operability determination were identified by the inspector:

The operability of the HPCI pump was not confirmed uniquely, in that two historical tests were referenced and used as justification for operability without a written consideration of the future effect of the identified condition on pump operability.

The operability of the HPCI pump did not consider the impact of thermal cycling on the additional torque applied to the stud ~

A determination of whether or not to replace the affected studs was not made.

~

The assumption was made that the improperly applied torque was universally applied to all the potentially affected studs.

This in fact, may not have been the case and may not be a conservative assumption.

~

The statements attributed to the manufacture of the HPCI pump were non-committal and did not support an argument for operability.

After discussions with the inspector, the licensee generated an updated operability determination, dated October 25. This operability determination rectified the above weaknesses and included supporting calculations for stud toughness.

Operability of the HPCI pump was clearly supported and stated in this second case.

c.

Conclusions p

p was discussed with licensee management.

E1.2 Im act of Su ression Pool Level on HPCI 0 erabilit The initial attempt to justify operability of the high pressure coolant injection pump was weak and incomplete.

As a result of the inspector's review improvements were made to the operability determination.

The weaknesses identified by the

'nspector did not have a safety significant impact because the operability of the HPCI pump was clearly supported and stated in the licensee's second operability determination.

However, the ro rammatic as ect of this operability determination a.

Ins ection Sco e 73051 The licensee issued an operability determination for an adverse condition identified by CR 96-1977.

The document addressed a plant condition that resulted from a suppression pool level greater than 26 feet and the impact that this plant condition would have on the operability on the HPCI pump.

b.

Observations and Findin s The inspector reviewed the operability determination which accompanied CR 96-1977.

The document addressed a plant condition that could result from a suppression pool level greater than 26 feet.

The following weaknesses with the operability determination were identified by the inspector:

~

The operability of the HPCI pump was not confirmed uniquely, in that the possibility of reaching 26 feet in the suppression was not determined and the impact on the HPCI pump from a level of 26 feet was not determine ~

The ability to meet a design basis accident and/or the requirements of the emergency operating procedures was not clearly determined.

After discussions with the inspector, the licensee generated an updated operability determination, dated October 25. This operability determination rectified the above weaknesses and included supporting calculations and a bounding analysis, EDR 94-046, dated January 20, 1995.

Operability of the HPCI pump was clearly supported and stated in this second case.

Conclusions The initial attempt to justify operability of the high pressure coolant injection pump was weak and incomplete.

As a result of the inspector's review improvements were made to the operability determination.

The weaknesses identified by the inspector did not have a safety significant impact because the operability of the HPCI pump was clearly supported and stated in the licensee's second operability determination.

However, the programmatic aspect of this operability determination was discussed with licensee management.

En ineered Safe uards S stem ESS S

ra Pond Ins ection Sco e 37551 The availability of the design basis ultimate heat sink for the required thirty day period was reviewed.

The ESS Spray Pond is an eight acre concrete basin that contains approximately 25 million gallons of water.

Its maximum uniform depth is approximately 10 feet with the exception of the pump suction plenum, which is about 20 feet deep.

The results of contractor survey reports (Ecology III) dated October 11, 1988, August 18, 1988, July 11, 1988, May 5, 1988, October 15, 1990, and November 11, 1994 were reviewed along with the SSES FSAR and other design basis verification documentation.

Observations and Findin s The volume within the ESS Spray Pond is impacted by the accumulation of sediment, which settles on the bottom and sides of the pond.

The principle sources of the sediment are river makeup, cooling tower recirculating water, and erosion of earthen slopes surrounding the pond.

Surveys between 1990 and 1994 indicated an accumulation of approximately 286 cubic yards of sediment on the bottom of the pond to a total of 2456 cubic yards.

One of the areas of increased accumulation of sediment was in the sparger bays.

The conclusion of the 1994 survey report was that sediment removal would not be necessary for approximately ten years.

The licensee and the contractor survey reports considered the sediment as a miscible liquid that had only a volumetric impact on the ultimate heat sink. The licensee considered the impact of entrained sediment on plant equipment in a post accident situation with a loss of offsite power.

In that situation the pond would be evaporating and the impact of entrained sediment would increase as the relative

concentration of the entrained sediment increased and the approach velocity toward the Emergency Service Water (ESW) pump suction increased.

The licensee concluded that there was sufficient water in the pond to meet the design basis cooling needs of the plant and that with the maximum amount of sediment in the pond that there would be no excessive impacts on pump and/or heat exchanger operation.

c.

Conclusions The inspector determined that the licensee had adequately documented and determined the design basis availability of the ultimate heat sink cooling medium.

E3 Engineering Procedures and'Documentation E3.1 Desi n Control of Modifications a.

Ins ection Sco e

37551 The licensee's engineering design control process was inspected to determine that there was a program in place that ensured the original design basis was not altered without proper NRC notification, that modifications included adequate post modification testing, and that operability determinations were performed adequately.

b.

Observations and Findin s Nuclear Department Administrative Procedure (NDAP) - QA-1202, establishes and controls the performance of modifications and design changes at SSES.

This process is supported by approximately 20 subtier program implementation procedures.

An example of this subtier type procedure is NDAP-QA-0464, Bypass Control Program.

The following modifications, bypasses and supporting documentation were reviewed/inspected:

~

DCP 95-038, Containment Instrument Gas (CIG) Pressure Band Change, Unit 1 TS Interpretation 1-86-007, Automatic Depressurization System Operability TP-125-009, CIG Nitrogen Bottle Leakdown Leakdown

~

Reactor Recirculation Thyrite Installation, Unit 1

~

ECO 95-6002, Reactor Recirculation Motor Generator Set Brush Replacement, Unit 1

WA S63441, End Bell Modification WA S51371, Brush Change out WA S51372, Brush Change out WA S54246, Collector rings WA S54247, Collector rings

~

ECO 91-3025, 4.16 kV Isolator Modification Breaker 1A20106 WA V40067, Heart-Breaker Modification

~

DCP 94-3049, 4.16 kV Incoming Feeder Breaker Modification c.

Conclusions The modifications selected in the above sample were adequately drafted, controlled by SSES processes, implemented, and applied in the field.

E7 Quality Assurance in Engineering Activities E7.1 NSE En ineerin Self Assessment The inspector reviewed a sample of Nuclear System Engineering (NSE) self assessment activities performed over that last six months.

Each of the assessments was performed with an appropriate work scope and addressed a

sufficiently wide range of engineering and modification activities.

Several minor technical and programmatic issues were identified during the self assessment process and adequate corrective actions were applied.

No violation of NRC requirements were identified.

E8 Miscellaneous Engineering Issues (92902)

E8.1 UFSAR Review 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.

No specific inconsistencies were noted between the wording of the UFSAR and the plant practices, procedures and/or parameters observed by the inspector IV. Plant Su ort S1 Conduct of Security and Safeguards Activities S1.1 Securit Pro ram Im lementation a 0 Ins ection Sco e 81700 The inspector reviewed the security program during the period of November 4-8, 1996.

Areas inspected included:

previously identified items; effectiveness of management control; management support; protected area detection equipment; alarm stations and communication; testing, maintenance and compensatory measures; and training and qualification.

The purpose of this inspection was to determine whether the licensee's security program, as implemented, met the licensee's commitments in the NRC-approved security plan (the Plan) and NRC regulatory requirements.

b.

Observations and Findin s Management support is ongoing as evidenced by the procurement of two new X-ray machines for warehouse package processing, the near completion of an assessment aids upgrade, procurement of additional training aids to add realism during contingency response training, and the allocation of monetary resources for hiring four additional security officers (SOs).

Alarm station operators were knowledgeable of their duties and responsibilities and security training was being performed in accordance with the NRC-approved training and qualification (TSQ) plan.

Management controls for identifying, resolving, and preventing programmatic problems were effective as demonstrated by a reduction in security-related events.

Protected area (PA) detection equipment satisfied the NRC-approved physical security plan (the Plan) commitments and security equipment testing was being performed as required by the Plan.

Maintenance of security equipment was being performed in a timely manner as evidenced by minimal compensatory posting associated with non-functioning security equipment, and two items identified during a previous security core inspection conducted in February 1996 were closed.

However, an inspector follow-up item associated with marginally effective assessment aids will remain open pending final adjustments to the assessment aid upgrade project (see also Section S2.2).

C.

Conclusions The inspector determined that the licensee was conducting its security and safeguards activities in a manner that effectively protected public health and safet t S2 Status of Security Facilities and Equipment S2.1 Protected Area Detection Aids a.

Ins ection Sco e 81700 The inspector conducted a physical inspection of the PA intrusion detection systems (IDSs) to verify that the systems were functional, effective, and met licensee commitments.

b.

Observations and Findin s On November 9, 1996, the inspector determined by observation that the IDSs were functional and effective, and were installed and maintained as described in the Plan.

c.

Conclusion The PA intrusion detection aids met the licensee's Plan commitments.

S2.2 Alarm Stations and Communications a.

Ins ection Sco e 81700 Determination whether the Central Alarm Station (CAS) and Secondary Alarm Station (SAS) are:

(1) equipped with appropriate alarm, surveillance and communication capability, (2) continuously manned by operators, and that (3) the systems are independent and diverse so that no single act can remove the capability of detecting a threat and calling for assistance, or otherwise responding to the threat, as required by NRC regulations.

b.

Observations and Findin s Observations of CAS and SAS operations verified that the alarm stations were equipped with the appropriate alarm, surveillance, and communication capabilities.

The inspector determined by observations that the assessment aid upgrade, which is near completion, has greatly improved the assessment capability for the operators.

Additionally, the licensee has installed a video capture program to further enhance the assessment upgrade.

However, the inspector determined, by observations, that minor weaknesses existed with several pan-tilt-zoom and fixed cameras, in that picture quality was not as good as in other monitors.

The licensee stated that the electrical maintenance department is in the process of making adjustments and that the assessment aids upgrade, including the adjustments, will be completed by December 1996.

As noted in Section S1, an inspector follow-up item associated with marginally effective assessment aids will remain open pending the completion of the assessment aid upgrade and will be reviewed during a subsequent inspection.

Interviews with CAS and SAS operators found them knowledgeable of their duties and responsibilities.

The inspector also verified through observations and interviews that the CAS and SAS operators were not

required to engage in activities that would interfere with the assessment and response functions, and that the licensee had exercised communications methods with the local law enforcement agencies as committed to in the Plan.

C.

Conclusion The alarm stations and communications met the licensee's Plan commitments and NRC requirements.

S2.3 Testin Maintenance and Com ensator Measures aO Ins ection Sco e 81700 Determination whether programs were implemented that will ensure the reliability of security related equipment, including proper installation, testing and maintenance to replace defective or marginally effective equipment.

Additionally, determination whether security related equipment failed, the compensatory measures put in place was comparable to the effectiveness of the security system that existed prior to the failure.

b.

Observations and Findin s Review of testing and maintenance records for security-related equipment confirmed that the records were on file, and that the licensee was testing and maintaining systems and equipment as committed to in the Plan.

A priority status was assigned to each work request and repairs were normally being completed in a timely manner for all work, necessitating compensatory measures.

C.

Conclusions Security equipment repairs were timely. The use of compensatory measures was found to be appropriate and minimal.

S5 Security'nd Safeguards Staff Training and Qualification S5.1 Job Task Dut rainin and Qualification 81700 a 0 Ins ection Sco e

Determination whether members of the security organization were trained and qualified to perform each assigned security related job task or duty in accordance with the NRC-approved TSQ plan.

b.

Observations and Findin s On November 6, 1996, the inspector observed night familiarization training for weapons and determined that the training was conducted in accordance with the TRQ plan and that the range was controlled in a safe manner.

On

November 7, 1996, the inspector met with the security training staff and discussed training plans for implementing enhanced contingency response drills and tentative revisions to the TSQ plan.

Further, the inspector observed classroom requalification training and determined that the instructor's presentation was good, all course material was properly covered, and the examinations were properly administered and proctored, Additionally, the inspector interviewed a number of SOs to determine if they possessed the requisite knowledge and ability to carry out their assigned duties.

C.

Conclusions The inspector determined that training had been conducted in accordance with the TRQ plan.

Based on the SOs responses to the inspector's questions, the training provided by the security training staff was considered effective.

S6 Security Organization and Administration S6.1 Mana ement Su ort a.

Ins ection Sco e 81700 A review of the level of management support for the licensee's physical security program was conducted.

b.

Observations and Findin s The inspector reviewed various program enhancements made since the last program inspection, which was conducted in February 1996.

These enhancements included the procurement of two new X-ray machines for warehouse package processing,

~

the near completion of the assessment aid upgrade, procurement of additional training aids to add realism during contingency response training, and the allocation of monetary resources for the hiring of four additional SOs.

c.

Conclusions Management support for the physical security program was determined to be excellent.

S7 Quality Assurance in Security and Safeguards Activities S7.1 Effectiveness of Mana ement Controls a.

Ins ection Sco e 81700 A review was conducted to determine if the licensee had controls for identifying, resolving and preventing programmatic problem b.

Observations and Findin s The inspectors determined that the licensee had controls for identifying, resolving, and preventing security program problems.

These controls included the performance of the required annual quality assurance (QA) audits, an ongoing suggestion program which addresses programmatic concerns, performance of benchmarking exercises, and ongoing security shift supervisory oversight.

The licensee also utilizes industry data, such as violations of regulatory requirements identified by the NRC at other facilities, as a criterion for self-assessment.

c.

Conclusions A review of documentation applicable to the licensee controls, including results, indicated that performance errors were being minimized and that controls were effectively implemented to identify and resolve potential weaknesses.

S8 Miscellaneous Security Issues S8.1 Previousl Identified Items 81700 (Closed) VIO 50-387/96-02-01

& 50-388/96-02-01 The licensee failed to have adequate measures in place to prevent undetected personnel access into several vital areas.

(Closed)

VIO 50-387/96-02-02 & 50-388/96-02-02 The license failed to establish an appropriate vital area barrier.

With respect to the above violations, the inspector determined that the corrective actions described in the licensee's March 29, 1996 letter, in response to the NRC's Notices of Violations, were reasonable, complete, and appeared to be effective.

S8.2 Review of U dated Final Safet Anal sis Re ort UFSAR A recent discovery of a licensee operating its facility in a manner contrary to the UFSAR description highlighted the need for a special focused review that compares plant practices, procedures, and parameters to the UFSAR description.

Since the UFSAR does not specifically include security program requirements, the inspector compared licensee activities to the NRC-approved physical security plan, which is the applicable document.

While performing the inspection discussed in this report, the inspector reviewed Section 7.4 of the Plan, Revision JJ, dated April 30, 1996, titled, "Vital System Manholes/Handholes."

Based on discussions with security management, reviews of procedures, and observations, the inspector determined that the vital system manholes/handholes were being maintained, tested, and controlled as described in the Plan and applicable procedure F7 Quality Assurance in Fire Protection Activities F7.1 Fire Protection Audit During independent inspection activities discussed in NRC inspection report 287,288/96-10 it was determined that an approved safe shutdown fire plan did not exist at this facility. This issue was discussed with the licensee and NRC NRR. The licensee proposed program has yet to be approved by the NRC, but is currently being reviewed.

In response to this finding the inspector reviewed fire protection Audit 96-079 in order to determine what additional weaknesses existed in the SSES fire protection program.

The audit identified a moderate number of existing condition reports and their associated corrective action.

The inspector determined that the audit was adequately performed and that no significant fire threat was apparent.

V. Mana ement Meetin s

X2 Exit Meeting Summary Following conclusion of the security inspection, the inspector met with the licensee representatives at the conclusion of the inspection on November 8, 1996. At that time, the purpose and scope of the inspection were reviewed, and the preliminary findings were presented.

The licensee acknowledged the preliminary inspection findings.

The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on December 3, 1996.

The licensee acknowledged the findings presented.

The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.

No proprietary information was identifie INSPECTION PROCEDURES USED IP 40500:

IP 62703:

IP 64704:

IP 71707:

IP 73051:

IP 73753:

IP 81700:

IP 83729:

IP 83750:

IP 92700:

IP 92902:

IP 92903:

IP 93702:

Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems Maintenance Observation Fire Protection Program Plant Operations Inservice Inspection - Review of Program Inservice Inspection Physical Security Program for Power Reactors Occupational Exposure During Extended Outages Occupational Exposure Onsite Foltowup of Written Reports of Nonroutine Events at Power Reactor Facilities Followup - Engineering Followup - Maintenance Prompt Onsite Response to Events at Operating Power Reactors

ITEMS OPENED, CLOSED, AND DISCUSSED Closed 50-388/96-01-01 50-388/95-17-01 50-387/94-09-02 50-387;388/96-08-04 50-387,388/96-03-02 50-387/388/96-03-03 50-387/92-23-03 50-387/96-09 VIO VIO URI URI URI URI IFI LER 50-387/96-06 50-387/96-04 LER LER 50-387/95-1 5;95-1 5-01 LER 50-387/94-1 5-01 LER 50-388/96-08 50-388/96-07 LER LER LER LER LER LER URI VIO VIO 50-388/96-06 I

50-388/96-05 I

50-388/96-04 50 388/96-02 50-387/96-1 0-01 50-387;388/96-02-01 50-387;388/96-02-02 Secondary Containment Damper Not Functioning Properly Failure to Enter TS 3.0.3 During LOCA/LOOP Testing Reactor Feed Pump Turbine Trip Logic Ground Failure to Perform Alarm Panel Test SGTS Single Failure Issues Failure to Analyze Degraded Conditions-10CFR50.59 Grandfathering of Kaowool Condition Prohibited by TS during Contain Isolation Valve Work Evolution Both LOOPS of CRMS Removed from Service during Planned Maintenance Circuit Breaker Mis-Alignment Resulted in Emergency DG Inoperable Non-Conservative Heat Balance Calculation Impact on CTP Postulated Failures of SGTS Components Outside Design Basis LOCA/LOOP Testing Inoperable Secondary Containment Isolation Damper-Prohibited by TS Both Loops of CRMS Removed from Service During Planned Maintenance Surveillance Missed for RSCS During U2 Restart U2 Manual Scram-Loss of Aux Bus 12A Due to Wiring Condition Prohibited by TS - Zone III Damper Weaknesses During Unit 1 Restart Control Structure Elevator Access Not Controlled Freight Elevator Portals Not Bullet Proof/Electricaily Locked Discussed 50-387;388/96-08-03 EEI

'E'G Misalignment Related Failure to Follow Procedures

LIST OF ACRONYMS USED AR ARI ADS ATWS CFR CR CRM EDR ERT ESS ESW HPCI IFI ITS LCO LER MFLPD IVIS NRC NRR NSE OE Ol PIPB PPR RA RCIC RFP RHR RP RPT RP&C SALP Sl SRV SSES TAC TAP Tl TIA TIP TS UT Alarm Response procedure Alternate Rod Insertion Automatic Depressurization System Anticipated Transient Without Scram Code of Federal Regulations Condition Report Containment Radiation Monitor Engineering Deficiency Report Event Review Team Engineered Safeguards System Emergency Service Water High Pressure Coolant Injection Inspection Follow-Up Item Improved Technical Specification Limiting Condition for Operation Licensee Event Report Maximum Fraction of Limiting Power Main Steam Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Nuclear System Engineering Office of Enforcement Office of Investigations Inspection Program Branch Plant Performance Review Regional Administrator Reactor Core Isolation Cooling Reactor Feedwater Pump Residual Heat Removal Radiation Protection Recirculation Pump Trip Radiological Protection and Chemistry Systematic Assessment of Licensee P

International System of Units Safety Relief Valve Susquehanna Steam Electric Station Task Action Commitment Task Actin Plan Temporary Instruction Task Interface Agreement Traversing In-core Probe Technical Specification Ultrasonic Testing Density erformance