IR 05000387/1998006

Insp Repts 50-387/98-06 & 50-388/98-06 on 980609-0720.No Violations Noted.Major Areas Inspected:Operations, Engineering,Maintenance & Plant Support.Also Included Results of Insp by Regional Emergency Planning Specialist

ML17164A775
Person / Time
Site:	Susquehanna
Issue date:	09/02/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17164A774	List: IR 05000387/1998006 ML17164A773
References
50-387-98-06, 50-387-98-6, 50-388-98-06, 50-388-98-6, NUDOCS 9809090198
Download: ML17164A775 (48)

Text

U.S. NUCLEAR REGULATORYCOMMISSION REGION I

Docket Nos:

License Nos:

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

50-387/98-06, 50-388/98-06 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:

June 9, 1998 through July 20, 1998 Inspectors:

K. Jenison, Senior Resident Inspector J. Richmond, Resident Inspector

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Blarney, Resident Inspector D. Florek, Project Engineer W. Maier, Emergency Preparedness Specialist Approved by:

Clifford Anderson, Chief Projects Branch 4 Division of Reactor Projects 9809090i98 980902 PDR ADQCK 05000387

PDR

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EXECUTIVE SUMMARY Susquehanna Steam Electric Station {SSES), Units 1 & 2 NRC Inspection Report 50-387/98-06, 50-388/98-06 This integrated inspection included aspects of Pennsylvania Power and Light Company's (PP&L's) operations, engineering, maintenance, and plant support at SSES.

The report covers a 6-week period of resident inspection; in addition, it includes the results of announced inspections by a regional emergency planning specialist.

~Oerationa The licensee conducted plant operations in accordance with SSES procedures, and established effective equipment alignment and operability. The alignment of the residual heat removal and core spray systems was found to be adequate.

The material condition of both units was adequate with the exception of the Unit 1 acoustic monitor and the Unit 1 condensate filtration flow element.

(Section 01.2)

In the Unit 2 moisture separator drain tank high-high level turbine trip/reactor scram on June 29, 1998, and in the Unit 2 intermediate range monitor scram on July 2, 1998, the reactor achieved a stabl'e shutdown condition.

PP&L implemented initial corrective actions that prev'ented similar condition on the subsequent plant startup.

Since the intermediate range monitor scram involved a reactor period significantly shorter than normal, and involved two separate operators performing incorrect operator actions, an unresolved item will be opened to obtain further information to determine if the actions were acceptable, a deviation, a non-conformance or a violation. (Section 01.3)

o, The NRC identified a work control evolution that had removed redundant Emergency Switch Gear Coolers (ESGC) from service.

When brought to the licensee's attention, the licensee entered the appropriate Technical Specification Interpretation, secured the work evolution and returned one of the ESGC divisions within the required 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

(Section 01.4)

Twenty one condition report corrective actions were reviewed.

Each of the CRs contained an operability determination (OD). With the exception of the operability determination related to the acoustic monitor and water intrusion into the "A" emergency diesel generator fuel oil storage tank, the ODs were found to have been adequately performed.

(Section 04.1)

Maintenance PP&L requested enforcement discretion for Technical Specification requirements concerning a failed acoustic position indicator for the Unit 2 "J" Safety Relief Valve, to avoid an undesirable transient as a result of forcing compliance with a license condition.

The NRC approved PP&L's request, on June 15, 1998, after determining the action involved minimal or no safety impact and had no adverse radiological impact on public health and safety.

{Section M2.1)

Executive Summary (cont'd)

On July 3, 1998, the Unit 1 "S" safety relief valve (SRV) acoustic monitor had indication of a malfunction.

Maintenance was performed on this monitor and the monitor was returned to service.

On July 6, 1998, the Unit 1 "S" SRV acoustic monitor again malfunctioned, with the same indications that occurred on July 3, 1998.

Unit 1 was shutdown to repair the m'onitor. All Unit 1 acoustic monitors were modified during the shutdown to improve equipment reliability. The adequacy of acoustic monitor maintenance instructions and procedures, the adequacy of the operability determination for the "S" acoustic monitor, th'e adequacy of the diagnostic field techniques used to verify acoustic monitor operability and the adequacy of the corrective actions for previous acoustic monitor failures will be tracked as an URI to obtain further information to determine if the actions were acceptable or represent a violation of NRC requirements.

(Section M2.2)

~En ineerin On June 22, 1998, PPRL management shut down Unit 2 to repair a leak from a condensate flow sensing element end cap weld. The weld crack occurred because of a lack of fusion on the end cap weld base pass and unexpected high amplitude vibration. The vibration was the result of an error in the engineering analysis that resulted in a less than optimum installation of the flow sensing element.

PPSL took action to correct the Unit 2 failure and determined that Unit 1 does not have similar conditions that would lead to this type of failure.

Because of PPSL corrective actions and the low safety significance of this issue, no further actions are planned by the NRC.

No violation of NRC requirements were identified.

(Section E2.1)

During heavy rains, the Emergency Diesel Generator (EDG) Building sump room flooded, and as a result of foreign material lodged in a backflow preventer valve, the

"A" EDG room basement also flooded.

The licensee's initial actions for this event appeared reasonable.

Room flooding alarms and sump high-high level alarms failed to alert operations personnel of the flooding condition.

Although this presented a

single means to flood all of the EDG rooms from a single event, no violations of NRC requirements were identified.

(Section E2.2)

The heavy rains on June 23, 1998 resulted in significant quantities of water entering the "A" emergency diesel generator (EDG) storage tank through an unsealed penetration in the "A" EDG storage tank vault, due to in-progress modification work, and a loose flange on the "A" storage tank.

The "A" EDG was declared inoperable for a short period of time and remained in a degraded condition for several days, following rain water leakage into the "A" fuel oil storage tank.

This appears to have been the result of inadequate design control during the installation a diesel fuel oil storage tank sampling system, in conjunction with an inadequate maintenance activity which left a loose flange on the storage tank.

The design control and maintenance issues will be tracked as an unresolved item, to obtain further information to determine if the actions were acceptable or represented a violation of NRC requirements.

(Section E2.3)

Executive Summary (cont'd)

The emergency response facilities were very well maintained.

The licensee has enhanced the ability to assess plant and environmental conditions by. installing a recent computer data display modification and a remote radiation monitoring system.

Surveillances were accomplished, but a management expectation regarding communication surveillances created the possibility for a missed surveillance.

The surveillance was performed correctly despite the management expectation.

(Section P2)

Discrepancies in the recent revision of the emergency plan indicate that the licensee did not perform a sufficient level of review of emergency plan changes and had not given an adequate amount of attention to the annual reviews of the plan.

The reduction of the radiological assessment staff in the Emergency Operations Facility from three to two, after that staffing level had been increased to three during a recent revision of the plan was a reduction of the effectiveness of that plan.

Although this change was not in compliance with the requirements of 10 CFR 50.54(q), the actual level of preparedness was not reduced and the non-compliance is one of minor significance.

This violation, therefore, will not be subject to formal enforcement action.

(Section P3)

The licensee maintained a good Emergency Plan training program and ensurered completion of all required training.

Evaluation techniques for some elements of this program were unreliable, including the lack of annual re-examination of the entire spectrum of emergency action levels for decision makers and the use of the same evaluation scenario for radiological assessment personnel for the last six years.. The licensee was effectively using mini-drills to train on severe accident management concepts.

(Section P5)

The licensee maintained the Nuclear Emergency Planning staff at consistent levels with only brief periods of under staffing.

The recently appointed Senior Nuclear Emergency Planning Coordinator was well qualified to perform his assigned duties.

Nuclear Emergency Planning kept well informed of station issues and conducted appropriate interface with station management.

(Section P6)

The licensee's review of the emergency preparedness program was well structured and addressed all NRC requirements for conducting an independent review o e

f the emergency preparedness program.

Auditors evaluated the program against all of the attributes specified in 10 CFR 50.54(t) of NRC regulations.

The assessment of the adequacy of licensee interface with the offsite organization was not complete since it failed to evaluate interface with representatives of one'of the risk counties.

(Section P7)

TABLE OF CONTENTS EXECUTIVE SUMMARY TABLE OF CONTENTS v

Summary of Plant Status

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I. Operations...

Conduct of Operations...

01.1 Operator Shift Activities

~ 2 Operational Safety System Alignment 01.3 Unexpected Scrams During Reactor Startup....

01.4 Missed LCO Entry - 4kV Emergency Switchgear Room Cooling

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Operator Knowledge and Performance..

04.1 Operability Determinations and Condition Report Action Items

Miscellaneous Operations Issues 08.1 Licensee Event Report (LER) Review 08.2 Followup of Open Items

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.5.5.5 II ~ Maintenance M1

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Conduct of Maintenance M1.1 Pre-Planned Maintenance ActivityReview

, M1.2 Surveillance Test ActivitySample Reviews M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Unit 2:"J" Safety Relief Valve Acoustic Monitor Failure

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M2.2 Unit 1 "S" Safety Relief Valve Acoustic Monitor Failure

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MB Miscellaneous Maintenance Issues...

M8.1 Followup of Open Items

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10 III. Engineering E2 Engineering Support of Facilities and Equipment E2.1 Unit 2 Forced Shutdown Due to,a Cracked Weld on a Condensate Filtration Flow Instrument....

E2.2 Emergency Diesel Generator Building Sump Flood due to Heavy Rains E2.3

"A" Emergency Diesel Generator Inoperable due to Heavy Rains..

E.B Miscellaneous Engineering Issues E8.1 Followup of Open Items

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IV. Plant Support P2

'tatus of Emergency Preparedness Facilities, Equipment, and

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Emergency Preparedness Procedures and Documentation...

Staff Training and Qualification in Emergency Preparedness

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Emergency Preparedness Organization and Administration Quality Assurance in Emergency Preparedness Activities Miscellaneous Security Issues and Safeguards Procedures

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Table of Contents (cont'd)

S8.1 Followup of Open Items

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0 23 V. Management Meetings..

X1 Exit Meeting Summary

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~ 24 ATTACHMENT Attachment 1 - Inspection Procedures Used

- Items Opened, Closed and Discussed

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- List of Acronyms Used

Re ort Details Summar of Plant Status Susquehanna Steam Electric Station (SSES) Unit 1 began this inspection period in a refueling outage.

Startup commenced on June 4, 1998 with the unit achieving full power on June 10, 1998.

The unit continued to operate at full power until July 7, at which time the unit was shutdown due, to the failure of the "S" Safety Relief Valve Acoustic Monitor.

SSES commenced startup on July 14, and achieved full power on July 18. The unit remained at power during the balance of the inspection period.

SSES Unit 2 was operating at full power at the beginning of the inspection period.

On June 7, 1998, the unit was shutdown to replace the "A" Reactor Recirculation pump seal.

Unit 2 startup commenced on June 12, and on June 13, the "J" Safety Relief Valve Acoustic Monitor failed. The unit startup was placed on hold and PPKL requested enforcement discretion to continue with operation.

The NRC issued a notice of enforcement discretion (NOED) on June 15, and the unit resumed power ascension and reached full power on June 16.

On June 20, a leak was observed from the condensate filtration flow instrument sensing element, the unit was shutdown'on June 23, to repair the leak.

Repairs were completed and the unit start up commenced on June 27.

During startup, at 55% power the unit experienced a moisture separator drain tank high-high level which resulted in a turbine trip and reactor scram.

Unit startup re-commenced on July 2, and during the reactor startup a scram occurred due to Intermediate Range Monitor high-high level.

On July 3, reactor startup commenced and full power was achieved on July 6.

On July 17, power was reduced to 70% to investigate increased off gas flow rates and perform a sequence exchange.

The unit returned to full power on July 19.

I. 0 erations

Conduct of Operations

'1.1 0 erator Shift Activities a.

Ins ection Sco e 71707 Routine activities of plant control operators (PCOs), nuclear plant operators (NPOs)

and unit supervisors (USs) were observed throughout the inspection period.

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'Topical headings such as 01, Ms, etc., are used in accordance with tho NRC standardized reactor inspection rcport outline..

Individual reports are not expected to address all outline topic b.

Observations and Findin s In general, routine operator activities were prescribed, concisely communicated, and performed in accordance with SSES operations department procedures.

Shift turnovers were observed to be detailed and complete.

Operator activities surrounding two unanticipated trips are discussed in section 01.3 of this inspection report.

The inspectors discussed plant conditions with oncoming PCOs and USs following shift turnovers and observed that sufficient information and status were transferred to the oncoming shift to ensure the safe operation of the units.

c.

Conclusions

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In general, operator activities were adequate and conservative.

01.2 0 erational Safet S stem All nment a.

Ins ection Sco e 71707 The inspectors observed plant operation to verify that the facility was operated safely and in accordance with procedures and regulatory requirements.

Inspectors observed the control room alignment of selected safety related systems.

b.

Observations and Findin s

The inspectors observed, in general, the licensee conducted plant operations in accordance with procedures, and effective controls were implemented for safe plant operation.

Overall equipment operability, material condition, and housekeeping conditions were good.

The alignment/operability of the Residual Heat Removal and Core Spray systems including, engineered safety features and on-site power sources were verified.

Verification of the functioning of a ultimate heat sink was'performed in the field and the control room.

The inspectors identified several minor housekeeping and material condition items, that did not affect system operability, and communicated the items to the licensee for its review. With the exception of the Unit 1 acoustic monitors (see section M2.2 of this report), the material condition of the units was adequate.

One non-safety related material related condition, on the condensate system, resulted in an unscheduled shutdown (see section E2.1 of this report).

Conclusions The licensee conducted plant operations in accordance with SSES procedures, and established effective equipment alignment and operability. The alignment of the

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residual heat removal and core spray systems was found to be adequate, The material condition of both units was adequate with the exception of the Unit 1 acoustic monitor and the Unit 1 condensate filtration flow element.

Unex ected Scrams Durin Reactor Startu Ins ection Sco e 40500 71707 92901)

The inspectors reviewed the licensee's actions in response to two Unit 2 unexpected reactor scrams caused by a moisture separator drain tank high-high level on June 29, 1998 and an Intermediate Range Monitor (IRM) high-high level on July 2, 1998.

Observations and findin s:

Unit 2 "A" Moisture Se arator Drain Tank Hi h-Hi h Level Scram On June 29, 1998, Unit 2 was in startup at 55% power. At this time the "A" moisture separator drain tank high-high level was sensed by four instruments in three independent instrument loops.

This resulted in a main turbine trip and a subsequent reactor scram.

Shortly after the scram the resident inspectors reviewed the operator logs; interviewed control room personnel, including the system engineer and assessed plant status.

The inspectors concluded that the plant was in a stable shut down condition.

Prior to Unit 2 restart, the inspectors reviewed the preliminary root cause investigation, initial corrective actions taken, condition reports and plant status.

The inspectors concluded the post-trip review conducted by the Plant Operating Review Committee (PORC) was adequate.

Unit 2 Intermediate Ran e Monitor Hi h-Hi h Scram Unit 2 was in startup, returning to service from a moisture separator drain tank high-high level turbine trip/reactor scram three days earlier.

Unit 2 was taken critical and a short time later became subcritical below the point of adding heat, due to decay heat and recirculation pump heat.

The operators continued with plant startup and continuously withdrew control rods.

The second control rod that was continuously withdrawn increased reactor power and resulted in a short reactor period.

Two operators incorrectly down ranged IRMs, one in each reactor protection division, which resulted in a full reactor scram.

The resident inspectors interviewed control room personnel that were present during the scram and reviewed post scram plant conditions:

The inspectors'eview of post scram conditions concluded that the plant was in a stable shut down condition.

Prior to Unit 2 restart, the inspectors reviewed the PORC approved initial root cause and corrective actions, discussed the scram with the Event Review Team (ERT), and discussed start up preparations and plant conditions. The inspectors concluded the preliminary corrective actions were adequate to prevent re-occurrence during the subsequent startup.

Because this event involved a reactor period significantly shorter than normally achieved, and involved two separate operators incorrectly down ranging the IRMs, an unresolved item (URI) will be opened to obtain further

information to determine if the actions were acceptable, a deviation, a non-conformance or a violation.

(URI 50-388/98-06-01)

C.

Conclusions:

In the Unit 2 moisture separator drain tank high-high level turbine trip/reactor scram on June 29, 1998, and in the Unit 2 intermediate range monitor scram on July 2, 1998, the reactor achieved a stable shutdown condition.

PP5L implemented initial corrective actions that prevented similar condition on the subsequent plant startup.

Since the intermediate range monitor scram involved a reactor period significantly shorter than normal, and involved two separate operators performing incorrect operator actions, an unresolved item will be opened to obtain further information to determine if the actions were acceptable, a deviation, a non-conformance or a violation.

01.4 Missed I CO Entr

- 4kV Emer enc Switch ear Room Coolin (71707)

On July 16, 1998, with Unit 2 in condition 1 at 100% power, the Division II Emergency Switch Gear Cooling (ESGC) was inoperable for planned maintenance.

At 5 a.m., Operations removed the Division I Emergency Service Water (ESW)

from service for planned maintenance.

At 07:00 the NRC resident inspector questioned the unit supervisor (US) on the effects of having the Division I ESW and the Division II ESGC removed from service simultaneously, At approximately 7:15 a.m., the US completed his review and determined that Division I ESW was required for operability of the Division I ESGC.

Since both Division I and Division II ESGC were inoperable for planned maintenance,'he US entered a Technical Specification 3.8.3.1 and 3.8.3.2 limiting condition of operation (LCO) which required the plant to be in hot shutdown within 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, as required by Technical Specification Interpretation (TSI) 1-92-008. At 9:00 a.m., the Division I ESW and the Division I ESGC were returned to service and the TS LCO was exited within the required time.

The safety significance of this event is minor.

During the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> time period that both ESGC Divisions were inoperable, the ESGC was not required initiate or operate.

In addition, TS LCO was not exceeded.

However, this was an example of a planned work control evolution that removed redundant divisions of safety related equipment, and was identified by the NRC.

No violation of NRC requirements were identified.

Operator Knowledge and Performance 04.1 0 erabilit Determinations and Condition Re ort Action Items (71707)

The inspectors reviewed a sample of Operability Determinations (ODs) and Condition Report (CR) action items to determine if degraded conditions were identified, initially resolved with conservatism, and long term corrective actions were complete I Twenty one Condition Report (CR) corrective actions were reviewed.

Each of the CRs contained an operability determination (OD). With the exception of the ODs related to acoustic monitor operability {see section M2.2 of this report) and the "A" emergency diesel generator fuel oil storage tank operability (see section E2.3 of this report), the ODs were found to have been adequately performed.

Miscellaneous Operations issues 08.1 Licensee Event Re ort LER Review (92700)

CLOSED LER 50-388 97-001-00 Loss of Both Trains of Emergency Switchgear Room Cooling On SSES Unit 2 both Emergency Switch Gear Room Coolers (ESGC) were simultaneously inoperable.

The "A" ESGC fan breaker tripped due to an improperly size thermal overload, while the "B" ESGC was out of service due to an inoperable fan discharge damper.

The inspectors reviewed Condition Report 97-029'I, Work Authorization (WA) S72527, "B" ESGC Discharge Damper, WA V72513, "A" ESGC Breaker Thermal Replacement, and station procedure MT-GE-008, revision 16, 480 Volt and Under Circuit Breaker High Current Testing.

This in field review verified that the ESGC deficiencies were corrected, and procedure MT-GE-008 was modified to perform checks necessary to identify improperly sized thermal overloads during breaker testing to prevent similar conditions in the future.

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

08.2 Followu of 0 en Items (92901)

Closed VIO 50-387 97-03-02 Core Spray System Surveillance PP8cL was venting the core spray system before quarterly flow testing.

This resulted in the core spray pumps being tested in a condition different from the as-found condition.

PPSL originally denied the validity of this violation by PPSL letter, dated August 6, 1997 (PLA 4644). The NRC upheld the violation by NRC letter, dated August 26, 1997, since the NRC was concerned that the PPRL venting actions were not quantified.

On July 20, 1998, the inspector reviewed the current Quarterly Core Spray Flow Verification Division I{II)procedures SO-151-A02, SO-151-802 for Unit 1 and SO-251-A02, SO-251-802 for Unit 2. These procedures have been changed to'not allow venting before this test.

This violation is close Closed VIO 50-387 388 97-06-08 Emergency Diesel Generator Surveillance On April 18, 1997, the licensee conducted a TS 4.8.1.1.2 surveillance test to confirm EDG "B" operability without placing the EDG in an ambient condition.

The inspector reviewed updated PPSL periodic surveillance procedures and other documents, observed portions of a varied selection of the EDG surveillance tests and determined that'the licensee had implemented adequate corrective actions. This violation is closed.

Closed VIO 50-387 388 97-07-10 Essential Service Water (ESW) System and Ultimate Heat Sink (UHS)

On September 24, 1997 the NRC identified that the licensee had positioned a large floating platform on the UHS which serves as the post accident water source for the ESW system.

The'licensee removed the floating platform from the spray pond.

The licensee will not reinstall the platform until administrative controls and a 10 CFR 50.59 evaluation are approved and implemented.

The inspector observed portions of previous platform operations involving ESW spray header maintenance and determined that the licensee is implementing adequate corrective actions. This violation is closed.

II. Maintenance M1 Conduct of Maintenance M1.1 Pre-Planned Maintenance Activit Review a.

Ins ection Sco e 62707 The inspectors observed/reviewed selected portions of pre-planned maintenance activities, to determine whether the activities were conducted in accordance with NRC requirements and SSES procedures.

b.

Observations and Findin s Maintenance activities authorized by ten Work Authorizations (WAs) related to emergency diesel generator, residual heat removal service water, safety relief valve acoustic monitors, and standby gas treatment system were observed/reviewed during this inspection.

In addition, selected personnel qualifications, equipment permits (e.g., tagouts), procedures, drawings, and/or vendor technical manuals associated with the maintenance activities'were also reviewed and found to be acceptable.

In general, maintenance personnel were knowledgeable of their assigned activities.

Field supervision was present for some the observed activities.

Although the procedural guidance was general in nature, it referenced sources to obtain detailed informatio Of the WAs inspected, the inspectors determined the one WA for corrective maintenance activities associated with the "S" acoustic monitor repairs did not effectively repair or identify the cause of the monitor malfunction (see section M2.2 of this report).

The remaining pre-planned maintenance activities observed/reviewed were found to be appropriately conducted and controlled.

Overall, maintenance procedural controls were determined to be general in nature and did not prescribe some activities performed by maintenance personnel.

Specifically, there was no detailed guidance, and the lack of the detailed guidance may have resulted in equipment failure, for the reassembly instructions for the "S" acoustic monitor terminations (see section M2 ~ 2 of this report).

Conclusions In general, pre-planned maintenance activities observed/reviewed were found to be appropriately conducted and controlled.

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M1.2 S'urveillance Test Activit Sam le Rev'iews (61726)

The inspectors observed/reviewed selected portions of surveillance activities related to the emergency diesel generators, high pressure coolant injection system, safety related valve stroke testing, control room and standby gas treatment system ventilation.

The observed/reviewed surveillance activities were determined to conform to the requirements of TS and met PPRL administrative requirements (i.e.,

approvals, personnel qualifications, scheduling, and permits).

Components were properly removed from service and, when appropriate, the TS LCOs were documented and met.

The surveillance activities were determined to have been accomplished by qualified and trained personnel.

No violations of NRC requirements were identified.

IV)2 Maintenance and Material Condition of Facilities and Equipment M2.1 Unit 2 "J" Safet Relief Valve Acoustic Monitor Failure a ~

Ins ection Sco e 62707 92902 On June 13, 1998, with Unit 2 at 60% power, a control room annunciator alarmed indicating that a Division II safety relief valve (SRV) had opened.

Operators evaluated other plant parameters and confirmed that no SRV had opened, although the "J" SRV acoustic monitor status lights were illuminated. The inspectors reviewed the licensee's actions in response to the acoustic monitor failure.

b.

Observations and Findin s

An investigation and surveillance were performed by instrumentation and control

'technicians to evaluate the acoustic monitor failure.

In parallel with the investigation, the licensee began preparations for requesting enforcement discretion from the Technical Specifications that require an operable SRV acoustic monitor for

the "J" SRV. After reaching the conclusion that the acoustic monitor failure was inside containment, PPSL requested enforcement discretion, by letter dated June 15, 1998 (PLA-4926). PPSL requested enforcement discretion to allow continued operation of the unit with the inoperable acoustic monitor, until an outage of sufficient duration would allow drywell access, but no later than the Unit 2 ninth refueling outage.

A conference call was held between the NRC and PP5L on the morning of June 15, 1998.

The discussion focused on the technical issues, prior equipment failures, alternate means of detecting an open SRV, and prior enforcement discretion issued

- on the acoustic monitors.

The NRC issued a Notice of Enforcement Discretion (NOED) by letter dated June 16, 1998. An unresolved item, associated with a Unit 1 acoustic monitor failure (see section M2.2 of this report) willfollow this issue for future NRC review of the licensee's finalized root cause investigation and corrective actions.

c.

Conclusions PP5L requested enforcement discretion for Technical Specification requirements concerning a failed acoustic monitor for the "J" Safety Relief Valve, to avoid an undesirable transient as a result of forcing compliance with a license condition.

The NRC approved PPSL's request after determining the action involved minimal or no safety impact and had no adverse radiological impact on public health and safety.

This issue will be tracked as an URI, to obtain further information to determine if the actions were acceptable or represent a violation of NRC requirements for a similar acoustic monitor failure on Unit 1 (see section M2.2 of this report).

M2.2 Unit 1 "S" Safet Relief Valve Acoustic Monitor Failure a.

Ins ection Sco e 62707 92902 On July 3, 1998, and July 6, 1998, with Unit 1 at 100% power, a control room annunciator alarmed indicating that a Division II safety relief valve (SRV) had opened.

Operators evaluated other plant parameters and confirmed that no SRV had opened although the "S" acoustic monitor status lights were illuminated. The inspectors reviewed the licensee's actions in response to the acoustic monitor failure, b.

Observations and Findin s On July 3, 1998, with Unit 1 at 100% power, a control room annunciator alarmed indicating a Division II SRV had opened.

Operators evaluated other plant parameters and confirmed that no SRV had opened although its acoustic monitor status lights were illuminated.

PPSL entered a 48-hour TS Limiting Condition for Operation (LCO). The condition was cleared by deenergizing the circuit for the "S" acoustic monitor charge converter located in the drywell. Upon reenergization, the instrument returned to a normal status and successfully passed surveillance tests (CR 98-2276).

On July 6, 1998, a'control room annunciator alarmed indicating a Division II SRV had opened, similar to the July 3, 1998, event.

The operators verified that the "S" SRV did not open.

PP&L entered a 48-hour TS LCO. Based on PP&L investigation of this acoustic monitor failure and review of past acoustic monitor equipment problems, PP&L shutdown Unit 1 to facilitate repairs rather than request enforcement discretion as they had done for a similar acoustic monitor failure on Unit 2 on June 15, 1998.

During the outage, PP&L modified all Unit 1 acoustic monitors to improve equipment reliability.

The inspectors reviewed the July 3rd maintenance activities that were performed on the "S" acoustic monitor, evaluated previous acoustic monitor maintenance activities, and reviewed the OD written as part of CR 98-2276.

The inspectors observed that the instructions in the WAs for the initial troubleshooting, repair, modification of the "S" acoustic monitor were general in nature and did not prescribe some activities that were actually performed by maintenance personnel.

The instructions did not provide detailed reassembly instructions for the "S" acoustic monitor terminations, Incorrect acoustic monitor terminations may have caused the equipment problems.

In addition, the maintenance technicians did not document some of the maintenance activities that they performed.

The adequac f acoustic monitor maintenance instructions and procedures will be reviewed as acy part (a). of an unresolved item. (URI 50-387,388/98-06-02a)

The July 3rd OD for the "S" acoustic monitor concluded that the component was operable based on a continuity test and the failure to identify any problem or failed component during troubleshooting activities.

The inspectors determined that the OD lacked technical justification and was weak for two reasons.

First, the OD employed the same diagnostic field techniques that were used for the three previous acoustic monitor failures at SSES.

The diagnostic field techniques used to verify operability were not effective in the identification of degraded acoustic monitors.

Second, the "S" acoustic monitor subsequently failed on July 6, 1998, resulting in an unplanned shutdown.

The adequacy of the OD and the adequacy of the diagnostic field techniques used to verify acoustic monitor operability for the "S" acoustic monitor will be reviewed as part (b) of an unresolved item. (URI 50-387,388/98-06-02b)

As part of the inspectors'eview of the July 3rd "S" acoustic monitor operabilit a

g nd maintenance issues, the inspectors determined that PP&L had numerous I I y problems with acoustic monitors in the past.

The HRC has issued three previous NOEDs for acoustic monitor failures; January 1994; September 1997 and J une 1998.

PP&L had several opportunities to correct the degraded performance of I

I I

these monitors in the past.

10 CFR 50 Appendix B, Criterion XVI requires that conditions adverse to quality, such as failures and malfunctions are promptly identified and corrected.

Failure to adequately correct the acoustic monitor problems without the use of multiple NOEDs, will be reviewed as part (c) of an unresolved item to obtain further information to determine if the actions were acceptable or represent a violation of NRG requirements.

(URI 50-387,388/98-06-02c)

The LERs associated with the acoustic monitors (50-387/98-014-00and 50-388/98-008-00) will be closed and dispositioned through the review of URI 50-387,388/98-06-02.

C.

Conclusions On July 3, 1998, the Unit 1 "S" safety relief valve (SRV) acoustic monitor had indication of a malfunction.

Maintenance was performed on this monitor and the monitor was returned to service.

On July 6, 1998, the Unit 1 "S" SRV acoustic monitor again malfunctioned, with the same indications that occurred on July 3, 1998.

Unit 1 was shutdown to repair the monitor. All Unit 1 acoustic monitors were modified during the shutdown to improve equipment reliability. The adequacy of acoustic monitor maintenance instructions and procedures, the adequacy of the operability determination for the "S" acoustic monitor, the adequacy of the diagnostic field techniques used to verify acoustic monitor operability and the adequacy of the corrective actions for previous acoustic monitor failures will be tracked as an URI, to obtain further information to determine if the actions were acceptable or represent a violation of NRC requirements.

M8 Miscellaneous Maintenance Issues M8.1 Followu of 0 en Items (92902)

Closed IFI 50-387 388 97-09-01 Unexpected Half Scram During Reactor Pressure Switch Surveillance During performance of a reactor pressure switch surveillance calibration test, an unexpected half scram was received during instrument isolation valve operation.

The ISC technician present in the control room reported that the half scram annunciator alarmed approximately 5 seconds after the isolation valve was operated by the IRC technicians at the instrument rack.

The actuation of the pressure switch should have resulted in the annunciation of two control room alarms, however, only one alarm was received.

The condition report for this item was incomplete and required additional information from IRC personnel to close.

Condition Report (CR) 97-3745 performed a root cause evaluation and documented the cause as a pressure spike induced during the valve operation which resulted in a momentary actuation of the pressure switch. The CR did not document an evaluation or review of why there was a perceived delay in the alarm annunciation or why only one alarm annunciated.

Based on a discussion with the ISC personnel who performed the root cause evaluation, they stated that both prior and subsequent channel response time testing had been reviewed; the circuit used HFA relays, which have no sticking or binding failure history at SSES; and there was no component degradation issue.

The inspector noted that the complete basis, which had been evaluated for the root cause, was not documented in CR 97-3745, however, a root cause determination of a pressure spike during valve operation, as stated in the CR, appeared reasonabl The inspector had no further questions.

No violations of NRC requirements were identified. This Inspector Followup Item is closed.

III. En ineerin E2 Engineering Support of Facilities and Equipment E2.1 Unit 2 Forced Shutdown Due to a Cracked Weld on a Condensate Filtration Flow Instrument a.

Ins ection Sco e 37551 On June 20, 1998, an operator identified minor leakage from a crack in an end cap weld on a flow sensing element in the condensate system.

Over a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, the crack indication was observed to increase.

Based on the increase in crack size, an orderly shutdown on Unit 2 was scheduled and implemented.

The inspectors reviewed the licensee's actions in response to this leak on the condensate system.

b.

Observations and Findin s On June 20, 1998, an operator identified minor leakage from a

~/~ inch crack in an end cap weld on a flow sensing element (FE-20516) in the condensate system.

The initial leak rate was measured at approximately 0.125 gallons per minute (gpm).

Over a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, the crack indication was observed to increase to approximately 3/4 inch.

Leakage increased to approximately 0.20 gpm. A mechanical clamp was installed to prevent the flow element fiom dislodging.

On June 22, 1998, Unit 2 began an orderly shutdown to repair the leak.

The inspectors reviewed the in-process root cause analysis that was being conducted under CR 98-2163.

The preliminary metallurgical analysis of the end cap weld identified a lack of fusion on the vendor supplied weld root pass and cyclic fatigue that ultimately resulted in a weld crack.

This analysis determined that there was high amplitude vibration at the end cap because of an engineering design error.

The design calculation used an incorrect pipe wall thickness.

This error did not allow the flow element to be properly mounted in the pipe to minimize the high amplitude vibration.

The licensee's root cause analysis also reviewed the Unit 1 flow element installation and the preliminary results suggest that Unit 1 does not exhibit the high amplitude vibration that would lead to cyclic fatigue and weld cracking, such as the Unit 2 failure.

This was considered a Maintenance Rule Functional Failure because it resulted the shutdown of Unit l E

l

C.

Conclusions On June 22, 1998, PPRL management shut down Unit 2 to repair.a leak from a condensate flow sensing element end cap weld. The weld crack occurred because of a lack of fusion on the end cap weld base pass and unexpected high amplitude vibration. The vibration was the result of an error in the engineering analysis that resulted in a less than optimum installation of the flow sensing element.

PPRL took action to correct the Unit 2 failure and determined that Unit 1 does not have similar conditions that would lead to this type of failure; Because of PPSL corrective actions and the low safety significance of this issue, no further actions are planned by the NRC.

No violation of NRC requirements were identified.

E2.2 Emer enc Diesel Generator Buildin Sum Flood due to Heav Rains Ins ection Sco e 37551 On June 23, 1998, SSES experienced heavy rains.

This resulted in flooding of the EDG building sump pump room and the "A" EDG basement.

The heavy rains also resulted in water intrusion into the "A" emergency diesel generator (EDG) fuel oil storage tank and is discussed in section E2.2 of this report.

The inspectors reviewed the licensee's actions in response to this event.

b.

Observations and Findin s Emer enc Diesel Generator Sum Room Floodin At about 8 pm on June 23, 1998, the diesel building sump room flooded to about 5 feet, and the "A" EDG room basement flooded to about 15 inches.

No room flooding alarms or sump high-high level alarms were received.

No safety related equipment was directly impacted as a result of the flooding in either the diesel building sump or the "A" EDG room.

The EDGs remained operable through out the event.

The diesel building sump is located in the "B" EDG room basement, and has two sump pumps, which pump into the SSA (Admin) building sump.

The floor drains from the "A"through "D" EDG rooms and the diesel sump room gravity drain,

~ through backflow preventer valves, into the diesel building sump.

In addition, the catch basin run off from the safeguard transformers, the fuel oil tanker truck unloading dock, and over spill from adjoining areas all cascade into the diesel building sump.

All of the drains, coming into the'sump, go through flow limiting orifice FO-16012, located immediately upstream of the sump.

Each EDG room has a non-safety related flood alarm (float switch) located in the room's basement.

There is no safety related equipment in the "A" through "D" EDG room basements; the only equipment in the "A" EDG basement is the air-start dryer skid. Although the air-start dryer is non-safety related and not required for EDG operability, the "A" dryer appeared to continue to operate during the flooding event and the subsequent cleanup activitie On June 24, 1998, the EDG room flood alarms were functionally tested.

The "A" EDG room flood alarm was found inoperable, was repaired, functionally tested, and returned to service.

The "8", "C", and "D" EDG room flood'alarms were found in a satisfactory condition. Preventative Maintenance (PM) to functionally test the EDG room flood alarms, along with the PMs for the flood alarms in the circulating water pump house and turbine building condenser bay, had been canceled about 5 years ago.

Subsequent trouble shooting, by the system engineer, found a "bottle cap" stuck in backflow preventer valve 060007, for the floor drain from the "A" EDG room basement into the sump.

A "bottle cap" was also found partially blocking flow orifice FO-16012. At least one of the bottle caps appears to have entered the drain system through an outside storm drain grate.

Both sump pumps were found to be functional, but were operating at less than rated capacity.

Although the diesel building sump has had a prior history of flooding, the last time the sump flooded was about 5,years ago.

SSES does not have a plant flood control program.

The Final Safety Analysis Report (FSAR), section 3.4, Water Level (Flood) Design (i.e., flood analysis), and section 9.3.3, Equipment and Floor Drainage System, were reviewed.

No commitment to a flood control program, PM program, or testing program was identified.

The licensee's root cause determination for this event is in progress.

Changes to the PM program, and the storm drain and sump system are being reviewed.

The EDG building sump drain system, and the EDG room flood alarms are not in the scope of the Maintenance Rule; Maintenance Rule scoping, for this equipment, is being reviewed as a result of this event.

The licensee's initial actions for this event appeared reasonable.

No violations of NRC requirements were identified.

c.

Conclusions During heavy rains, the Emergency Diesel Generator (EDG) Building sump room flooded, and as a 'result of foreign material lodged in a backflow preventer valve, the

"A" EDG room basement also flooded.

Room flooding alarm and sump high-high level alarm failed and did not alert the operations personnel of the flooding condition.

The licensee's initial actions for this event appeared reasonable.

Although this presented a single means to flood all of the EDG rooms from a single event, no violations of NRC requirements were identified.

E2.3

"A" Emer enc Diesel Generator Ino erable due to Heav Rains Ins ection Sco e 37551 92903 71707 On June 23, 1998, SSES experienced heavy rains.

This resulted in water intrusion into the "A" emergency diesel generator (EDG) fuel oil storage tank.

The heavy rains also caused flooding of the EDG building sump pump room and the "A" EDG

i

.a

room basement and is discussed in section E2.2 of this report.

The inspectors reviewed the licensee's actions in response to this event.

b.

Observations and Findin s The following describes the events or conditions that resulted in water intrusion into the "A" EDG storage tank due to heavy rains.

The water entered the storage tank due to the an in-process modification and a loose flange connection.

At the time of this event, the "A" through "D" EDG fuel oil storage tanks were being modified, to add a fuel oil "sampling and water removal" system.

The in-progress modification had a ditch, about 5 feet deep, dug around all 4 storage tank vaults (the vault is a void area between the tank top and grade level, where all of the tank flanges and connections are located).

Penetrations, several feet below grade level, into each storage tank vault had been made by the modification, to route instrument tubing from the new sample system into the vault. The penetration into the "A"tank's vault was about 4 inches in diameter, and had not yet been sealed; the penetrations

. into the other vaults had already been, sealed.

At about 3 p.m. on June 23, 1998, maintenance personnel performing the modification work in the "A" EDG vault identified a loose flange on top of the "A" storage tank.

They documented their observation in Condition Report (CR) 98-2184.

The operability determination (OD) for CR 98-2184 concluded "sufficient bolting exists to maintain a tight seal at the mechanical joint."

At about 8 p.m. on June 23, 1998, heavy rains occurred at the site.

At about 3 a.m. on June 24, 1998, a Nuclear Plant Operator (NPO) reported the level indicators for the "A" and "C" diesel fuel oil storage tanks were indicating erroneously high and reported observing water in each storage, tank vault. At this time the extent of the water in the storage tank vault was not specifically determined.

CR 98-2183 documented this condition.

The OD associated with this CR stated "the proper oil level was verified by the preferred method in accordance with the Operating Procedure (OP-024-001).

There is no indication of water entering the storage tanks."

Early morning on June 24, 1998, a SSES operations inspection of the "A" tank vault found the vault flooded to about 3 foot above the top of the tank.

Water was flowing into the vault from the flooded ditch through the unsealed penetration.

The flooded vault resulted in shorting out the tank level instrument.

After the "A" vault was pumped down, an inspection identified a loose flange on the tank top (e.g., the same loose flange that had been previously identified by CR 98-2184, on June 23, 1998).

Midday on June 24, 1998, a sample taken from the bottom of the "A" storage tank showed an abnormally high amount of water present in the fuel

oil. The quantity of water in the "A" storage tank was not known, but the presence of some fuel oil in the bottom sample led SSES chemistry and operations personnel to believe'that there was only a thin layer of water (i.e.,

less than a few inches) on the tank bottom.

In the afternoon on June 24, 1998, after the "A" tank was sampled and the presents of water was identified, a significant amount of oil/water mixture was removed from the "A"tank. Water content of the mixture was estimated to be between 300 to 500 gallons.

During the water removal process, the "A" EDG was declared inoperable for about one hour, when the level in the storage tank decreased to below the Technical Specification minimum level.

~

On June 24, 1998, the "B", "C", and "D" tank vaults were inspected; the

"B" tank vault was dry, the "C" and "D" tank vaults had several inches of water, believed to be from ground water seepage.

All flanged connections on the "B", "C" and "D" tanks were checked and reported as tight. The "B",

"C", and "D" storage tanks were also sampled for water intrusion, no water was found in those tanks.

On June 26, 1998, fuel oil sampling again showed water present and additional tank bottom pumping was performed to remove all water.

On June 26 and 27, 1998 fuel oil samples from the "A" EDG storage tank were analyzed in accordance with SC-023-001 and indicated an acceptable quality for viscosity, water, sediment, and insolubles.

On June 27, 1998, the licensee revised the OD for CR 98-2183 and concluded that approximately 360 gallons of water had been removed from the "A" storage tank.

The licensee further concluded that the oil-water interface was about 1 3/4 inches below the suction point for the fuel oil transfer pump.

The inspectors had several concerns with the licensee's operability determinations or CRs:

The OD associated with CR 98-2184did not document an evaluation of the current conditions around the "A" EDG storage tank vault and the potential for water intrusion.

Specifically the OD did not consider the unsealed penetration below grade level or the presence of the ditch beside the "A" EDG storage tank vault and the potential for water intrusion into the EDG

'storage tank.

No maintenance activity was immediately performed to tighten

'the loose flange.

The OD associated with CR 98-2183 was not revised in a timely manner when additional degraded conditions were identified. The OD associated with CR 98-2183 had initiallyconcluded on June 24, 1998, that the EDGs were operable, in part, based on an initial belief that no water intrusion into

~

the EDG storage tanks had taken place.

However, the OD was not revised on June 24, 1998 when the licensee had information, in the early morning, that a loose "A" EDG storage tank flange had been submerged in 3 feet of water, and had not been revised when, during midday, test results confirmed the presence of water in the "A" storage tank.

In addition, the OD was not revised on June 26, 1998, when additional test results again provided positive indication of water in the "A" storage tank.

The heavy rains on June 23, 1998 resulted in significant quantities of water entering the "A" EDG storage tank through an unsealed penetration in the "A" EDG storage tank vault, due to in-progress modification work, and a loose flange on the "A" storage tank.

The unsealed penetration below grade level, that occurred during installation appears to be an example of inadequate design controls.

The loose flange appears to be a result of a prior inadequate maintenance activity. The loose flange was documented in an OD; however, this OD did not consider the combined effects of the loose flange and unsealed penetration.

The consequences of this event, resulted in the "A" EDG being inoperable for a short period of time on June 24, 1998, and to be in a degraded condition for several days, following the event.

This issue will be tracked as an unresolved item (URI), to obtain further information to determine if the actions were acceptable or represented a violation of NRC requirements.

(URI 50-387,388/98-06-03)

c.

Conclusions The heavy rains on June 23, 1998 resulted in significant quantities of water entering the "A" emergency diesel generator (EDG) storage tank through an unsealed penetration in the "A" EDG storage tank vault, due to in-progress modification work, and a loose flange on the "A" storage tank.

The "A" EDG was declared inoperable for a short period of time and remained in a degraded condition for several days, following rain water leakage into the "A" fuel oil storage tank.

This appears to have been the result of inadequate design control during the installation a diesel fuel oil storage tank sampling system, in conjunction with an inadequate maintenance activity which left a loose flange on the storage tank.

The design control and maintenance issues will be tracked as an unresolved item, to obtain further information to determine if the actions were acceptable or represented a violation of NRC requirements.

E.8 lVliscellaneous Engineering Issues E8.1 Followu of 0 en Items (92903)

CLOSED VIO 50-387 388 97-001-02 Adequacy of BIS Alarm Circuits for RHR System PPRL did not fully meet the Institute of Electrical and Electronic Engineers (IEEE)

"Criteria for Nuclear Power Plant Protection System" Standard 279-1971.

This standard requires that when the protective actions of a system have been bypassed, this status should be indicated in the control room. Contrary to this, the

I

Bypass Indication System (BIS) did not, in all cases, indicate when the automatic start of the residual heat removal pump is inhibited by its suction valve interlock.

PPSL performed modifications (DCN¹ 97-9033, 97-9034) to ensure that the BIS indication accurately reflects the effects from the suction valve on the RHR pump start logic. The modifications were completed in the last quarter of 1997. This violation is closed.

CLOSED VIO 50-387 97-006-12 Failure to Perform 50.59 Evaluation for Communications Test PPS.L performed communication system transmission demonstrations in the protected area, during September and November 1996, with out performing a 10 CFR 50,59 review. The inspectors noted that there were no plant transients that were directly attributable to the demonstration.

The inspectors reviewed procedure NDAP-00-0316, Station Communication Practices, and verified that the procedure was revised to clearly define the types of acceptable radio transceivers permitted in the protected area and verified that in at least one instance security did not allow an unauthorized radio transceiver on site.

The violation is closed.

IV. Plant Su ort P2 Status of Emergency Preparedness Facilities, Equipment, and Resources a.

Ins ection Sco e 82701 The inspector toured the major onsite emergency response facilities; the Control Room, the Technical Support Center (TSC), and the Operations Support Center (OSC), as well as the Emergency Operations Facility (EOF), located in the licensee's East Mountain Business Center in Wilkes-Barre, PA. The inspector performed spot checks of equipment operability at each of these facilities and reviewed completed equipment surveillances and locker inventories.

He interviewed a security officer responsible for initiating licensee emergency responder call out using the Telenotification System and observed a demonstration of this system.

b.

Observations and Findin s All equipment located in the emergency response facilities was as described in the licensee's procedures.

Communication circuits all functioned properly.

The Telenotification System demonstration was successful in paging a test pager used to monitor system performance.

The licensee had recently completed a computer system upgrade on Unit 1 that consolidated several data display systems into one.

Data links to the emergency response facilities had been made within the scope of this project.

Unit 2's computer systems had been similarly re-configured during an earlier outage and similarly routed to the emergency response facilitie I

The licensee had also recently acquired an on-line perimeter radiation monitoring network around the site that included sixteen remote radiation monitors which would read out in the TSC and EOF. This system was still undergoing preoperational testing at the time of the inspection.

All of the required equipment surveillances were completed as required by the licensee's procedures and NRC regulations; however, the June, 1998 test of the communication circuits for notification of and communication with the NRC

'Emergency Notification System and Health Physics Network) was nearly not performed as allowed by a licensee management memorandum.

This memorandum waives the monthly requirement to perform the test for months in which a drill or exercise is scheduled.

The reason for this waiver is that the circuits are assumed to be tested during the drill or exercise.

The licensee conducted a health physics drill on June 23, 1998. The licensee's response organization activated all the major facilities and made offsite notifications to the offsite authorities.

Communications with the NRC, however, were simulated in a control cell using other telephones and therefore not actually tested.

This would have resulted in a missed surveillance except for the fact that the person

~ responsible for testing the circuit had done so regardless of the waiver. The surveillance was not missed despite the erroneous assumption that the drill activities would have tested the circuits.

c.

Conclusions The emergency response facilities were very well maintained.

The licensee has enhanced the ability.to assess plant and environmental conditions by installing a recent computer data display modification and a remote radiation monitoring system.

Surveillances were accomplished, but a management expectation regarding communication surveillances created the possibility for a missed surveillance.

The surveillance was performed correctly despite the management expectation.

P3 Emergency Preparedness Procedures and Documentation Ins ection Sco e 82701 The inspector reviewed several changes the licensee made to selected emergency plan implementing procedures during the period of September, 1997 through June, 1998.

The inspectors reviewed these changes in the NRC Region I office. They conducted this review to verify that the changes made to the emergency plan implementing procedures were made in accordance with 10 CFR 50.54(q) of NRC regulations, i.e., that they did not decrease the effectiveness of the emergency plan.

The following procedures were reviewed EP-PS-101, Emergency Director-TSC; EP-PS-103, Operations Coordinator.; EP-PS-104, Radiation Protection Coordinator; EP-PS-113, Security Coordinator; EP-PS-131, Damage Control Team Coordinator; EP-PS-200, Recovery Manager; EP-PS-207, EOF Support Supervisor; and EP-PS-215, Radiation Support Manager.

The inspector also spot-checked copies of the emergency plan and implementing procedures located at the

emergency response facilities for completeness and to ensure they were the current revision.

b.

Observations and Findin s Revision 26 to the SSES emergency plan, approved in May, 1998, corrected several discrepancies between the emergency plan and the actual status of equipment described in the plan.

For example, the plan described, through Revision 25, some kitchen facilities in the TSC that had been removed approximately eight years earlier.

Also, the plan described a UHF radio system in the EOF that was used to monitor onsite repair team communications.

This radio system was retired two years ago when the EOF was re-located from near site to its present location

~

twenty-two miles from the plant. Thirdly, Table 6.2 of the plan, describing the minimum onsite and offsite emergency organization capabilities, was revised to eliminate a position for a Chemical Engineer because that position had not been subject to immediate call out and was instead a long-term augment position, These discrepancies went unidentified for varying lengths of time despite the fact that the licensee had been performing annual reviews of the emergency plan in order to identify and correct discrepancies.

In addition to these above changes, an additional change was made to Table 6.2 which reduced the minimum radiological assessment staff in the EOF from three individuals to two. The licensee's stated reason for this change was that this part of the plan also did not reflect the current configuration of emergency responders and reduction of the radiological assessment staff was inadvertently omitted from an earlier revision of the plan.

The table was, in fact, accurate in describing the three staff members actually on the EOF radiological assessment staff; the EOF dose assessment staffer, the radiological field team director and the radiological liaison to the state organizations.

None of these positions had been eliminated from the licensee's emergency response organization.

Furthermore, the staffing level had been raised from two to three in an earlier submittal of the plan that accompanied the relocation of the EOF two years ago.

The change to the staffing numbers made in Revision 26 to the emergency plan reduced the committed minimum staffing level in the EOF for radiological assessment below the actual staffing level.

While pursuing the above finding, the inspector learned that the radiological assessment staff at the EOF was secondary to the radiological assessment staff at the TSC, which was primarily tasked with the calculation of offsite radiological dose consequences.

This was another change to the emergency response organization made in support of the EOF relocation, and it was made to ensure continuity of the dose assessment function throughout the time interval needed to staff the EOF.

When the emergency plan was updated in 1996 to reflect the changes required for the EOF relocation, the additional staff assigned to the TSC for radiological assessment and the mention of the assignment of the dose assessment function to the TSC were not included in Table 6.2 to properly reflect the new organization.

The licensee had captured these additions in the TSC organization chart, shown as

~.

Figure 6.3 in the emergency plan.

This figure did not, however, include minimum staffing levels as is prescribed in Table 6.2.

In addition to the above findings, the inspector noted some additional minor discrepancies in Revision 26 to the emergency plan.

For example, there was a conflict in the plan regarding which individual could relieve the Emergency Director in the TSC. Also, there were several changes made to the plan that lacked vertical bars in the margin to identify the lines of text that were changed.

The Emergency Planning Supervisor recognized that the staffing levels in Table 6.2 had not been given the appropriate review and orally stated her intention to revisit the recent reduction of staffing levels and ensure that actual levels were reflected in the plan.

The inspector, in his tour of the emergency response facilities, found all the copies of the emergency plan and the implementing procedures which he checked to be the current revision.

The effectiveness evaluation he reviewed was complete and properly documented.

C.-

Conclusions Discrepancies in the recent revision of the emergency plan indicate that the licensee did not perform a sufficient level of review of emergency plan changes and had not given an adequate amount of attention to the annual reviews of the plan.

The reduction of the radiological assessment staff in the Emergency Operations Facility, from three to two, after that staffing level had been increased to three during a recent revision of the plan, was a reduction of the effectiveness of that plan.

Although this change was not in compliance with the requirements of 10 CFR 50.54(q), the actual level of preparedness was not reduced and the non-compliance is one of minor significance.

This violation, therefore, will not be subject to formal enforcement action.

P5 Staff Training and Qualification in Emergency Preparedness a.

Ins ection Sco e 82701 The inspector reviewed documents governing the conduct of emergency preparedness training including the Emergency Plan, the Emergency Plan Training Curriculum matrix, and several emergency plan training lesson plans.

The inspector also reviewed the training records for twenty-eight emergency responders to verify that they had received the required training.

Finally, he interviewed emergency planning staff, nuclear training center staff, and on-shift emergency responders to determine how the requirements of the above documents were being met.

As part of this inspection, the inspector observed portions of a severe accident management drill the licensee conducted as part of an industry-wide commitment.

b.

Observations and Findin s The twenty-eight emergency responders whose training completion records were reviewed had received all of their required annual retraining.

This retraining

consisted of performance in a "mini-drill"and attendance at a presentation of topical items of interest by the functional leads for the attendee's position in the emergency response organization.

The mini-drills consisted of training scenarios in which the attendees demonstrated the ability to perform various tasks.

The attendees were evaluated by instructors during these mini-drills, but the documentation of performance was limited to a notation of satisfactory or unsatisfactory beside the attendee's name on the attendance sheet.

Licensee training staff stated this practice was enacted due to a conscious decision to reduce documentation paperwork generation and storage.

Attendees were not evaluated for their performance at functional lead presentation training. Although responders performing as Emergency Directors and other decision makers reviewed the emergency action levels during this training, they were not re-examined in a classroom setting on their ability to classify events.

These responders were instead given a single developing scenario to classify during the mini-drills. They were not evaluated on a variety of initiating conditions in order to identify deficient areas of their knowledge.

One group of responders which was evaluated during their classroom retraining was the on-shift, TSC and EOF radiological assessment staff.

The lesson plan for these responders'raining included several dose calculation scenarios performed by the attendees.

The attendees were evaluated on one of these scenarios for their grade.

The evaluated scenario was the same for all the attendees and had not been revised in the last six years.

'The emergency responders interviewed included on-shift and TSC decision makers.

Allthe interviewed responders were familiar with their duties and commented favorably on the content of the training.

The observed severe accident management mini-drillwas attended by both on-shift and onsite (TSC) responders.

The training and evaluation staff effectively controlled the scenario.

M/hen problems arose, the scenario was halted and the problems discussed.

The attendees responded enthusiastically to the scenario and participated as realistically as the drill situation allowed.

There was a significant amount of cross-disciplinary training conducted as part of the mini-drill.

Conclusions The licensee maintained a good Emergency Preparedness training program and ensured completion of all required training.

Evaluation techniques for some elements of this program were unreliable, including the lack of annual re-examination of the entire spectrum of emergency action levels for decision makers and the use of the same evaluation scenario for radiological assessment personnel for the last six years.

The licensee was effectively using mini-drills to train on severe accident, management concept p6 Emergency Preparedness Organization and Administration a ~

Ins ection Sco e 82701 The inspector interviewed the Nuclear Emergency Planning Supervisor, her staff and the General Manager-Plant Operations to determine the effect of organizational changes on the level of emergency preparedness.

b.

Observations and Findin s The Senior Nuclear Emergency Planning Coordinator, a very experienced emergency planning staff member, left the licensee organization in December, 1997. The position remained vacant until May, 1998, although the licensee relied on contractor personnel to assist in various emergency preparedness functions.

The individual named to the position in May, although new to the tasks of day-to-day maintenance of emergency planning, was experienced in the operation of the plant and possessed the technical background necessary for development of drill and exercise scenarios.

The Nuclear Emergency Planning group reported directly to the Senior Vice President-Nuclear and was thus officiallyoutside the station organization.

The Nuclear Emergency Planning Supervisor, however, maintained a close working relationship with station management, regularly attending meetings of the station organization and involving station management in the interaction with the various offsite organizations with which the licensee shares responsibility for emergency preparedness.

C.

Conclusions The licensee maintained the Nuclear Emergency Planning staff at, consistent levels with only brief periods of under staffing.'he recently, appointed Senior Nuclear Emergency Planning Coordinator was well qualified to perform his assigned duties.

Nuclear Emergency Planning kept well informed of station issues and conducted appropriate interface with station management.

P7 Quality Assurance in Emergency Preparedness Activities a I Ins ection Sco e 82701 The inspector reviewed the audit plan, checklist and report for the calendar year 1997 review of the emergency preparedness program which was conducted by personnel in the licensee's Nuclear Assessment Services (NAS) organization (Audit 97-072)

~ The inspector also attended the exit interview for the calendar year 1998 review of the program (Audit 98-025), reviewed the audit plan and checklist for this audit and interviewed the lead auditor.

The inspector also reviewed two NAS surveillances (97-003 and 97-120) that evaluated the adequacy of the licensee's interface with the offsite response agencie ~ 23 b.

Observations and Findin s The 1997 and 1998 NAS audits, were planned with input from other organizations such as the Susquehanna Review Committee, which provided recommendations for specific areas to address.

Both the 97-072 audit report and the 98-025 audit exit interview were thorough in evaluating the performance of the Nuclear Emergency Plan'ning staff in its adherence to various licensee quality assurance procedures and standards.

The audits also evaluated the staff's ability to identify and correct adverse trends in the maintenance of the emergency preparedness program.

The audit teams had several members common to both reviews.

The 98-025 audit was at least partially performance-based since the audit team observed activities associated with the licensee's June 23, 1998 health physics drill.

Both audits evaluated the adequacy of offsite interface as required by NRC regulations; however, rather than explicitly investigating this topic during the period of the audit, the teams relied on past surveillance reports by NAS conducted during the licensee's training sessions with the offsite agencies.

The NAS personnel performing the surveillances informally solicited opinions from the offsite agency representatives as to the adequacy of this interface.

The last surveillance, conducted in December, 1997, failed to identify the adequacy of the licensee's interface with one of the risk counties because no representatives from the county in question had attended the training session.

Conclusions The licensee's review of the emergency preparedness program was well structured and addressed all NRC requirements for conducting an independent review of the emergency preparedness pro'gram.

Auditors evaluated the program against all of the attributes specified in 10 CFR 50.54(t). The assessment of the adequacy of licensee interface with the offsite organization was not complete since it failed to evaluate interface with representatives of one of the risk counties.

S8 Miscellaneous Security Issues and Safeguards Procedures S8.1 Followu of 0 en items (92904)

CLOSED EA 94-21250-387 388 Inaccurate Security Organization Examination Records The violations cover program areas that have been found to be acceptable in inspections following the violations.

No specific additional inspection is warranted to review the licensee's corrective actions.

These violations are close CLOSED EA 95-250 50-387 388 Discrimination due to Security Organization Examination Records The violations cover program areas that have been found to be acceptable in inspections following the violations.

No specific additional inspection is warranted to review the licensee's corrective actions.

These violations are closed.

V. Mana ement Meetin s X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection report period on July 24,1998.

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 ATTACHMENT1 INSPECTION PROCEDURES USED IP 40500 IP 37551 IP 61726 IP 62707 IP 71707 IP 82701 IP 92700 IP 92901 IP 92902 IP 92903 IP 92904 Effectiveness of Licensee Controls in Identifying, Resolving, Problems Onsite Engineering Observations Surveillance Observations Maintenance Observations Plant Operations Operational Status of the Emergency Preparedness Program On Site Followup of Reports Followup Plant Operations Followup Maintenance Followup Engineering Followup Plant Support and preventing

I

Attachment

~oened 50-388/98-06-01 ITEMS OPENED, CLOSED, AND DISCUSSED URI Unexpected Scrams During Reactor Startup (Section 01.3)

50-388/98-06-02 URI Safety Relief Valve Acoustic Monitor (Position Indicator)

Failures 50-388/98-06-03 URI

"A" Emergency Generator Inoperable Due to Heavy Rains (Section E2.3)

~Ud et ed None Closed 50-387,388/97-09-01 IFI Unexpected Half Scram During Reactor Pressure Switch Surveillance (Section M8.1)

50-387,388/97-001-00 50-387, 388/97-001-02 II 50-387, 388 94-21 2 50-387, 388 95-250 50-387, 388/97-006-1 2 LER Loss of Both Trains of Emergency Switchgear Room Cooling (Section 08.1)

VIO Adequacy of BIS Alarm Circuits for RHR System (Section E8.1)

EA Inaccurate Security Organization Examination Records (Section P8.1)

EA Discrimination due to Security Organization Examination Records (Section P8.1)

VIO Failure to Perform 50.59 Evaluation for Communications Test (Section E8.1)

50-387,388/97-03-02 50-387,388/97-06-08 50-387, 388/97-07-1 0 50-387/98-01 4-00 VIO Core Spray System Surveillance (Section 08.2)

VIO Emergency Diesel Generator Surveillance (Section 08.2)

VIO

'Essential Service'Water (ESW) System and Ultimate Heat Sink (UHS). (Section 08.2)

LER Technical Specification Required Shutdown (Section M2.2)

50-388/98-008-00 LER Failed Acoustic Monitor (Section M2.2)

Attachment

3 LIST OF ACRONYMS USED CFR CR CS DCP EDG EEI EOF EP ESGC ESW FSAR gpm IS,C IFI IR ISEG kv LCO LER NAS NDAP NOED NPO NRC OD OSC PCO PORC RHR SRV SS SSES TS TSC TSI UHF URI US VIO WA Code of Federal Regulations Condition Report Control Structure Design Change Package Emergency Diesel Generator Apparent Violation Emergency Operations Facility Emergency Preparedness Emergency Switch Gear Room Coolers Essential Service Water Final Safety Analysis Report gallons per minute Instrument and Control Inspection Follow-Up Item

[NRC] Inspection Report Independent Safety Engineering Group Kilovolts Limiting Condition for Operation Licensee Event Report Nuclear Assessment Services Nuclear Department Administrative Procedure Notice of Enforcement Discretion Nuclear Plant Operator Nuclear Regulatory Commission Operability Determination Operations Support Center Plant Control Operator Plant Operations Review Committee Residual Heat Removal Safety Relief Valve Shift Supervisor Susquehanna Steam Electric Station Technical Specification Technical Support Center Technical Specification Interpretation Ultra-High Frequency

[NRC] Unresolved Item Unit Supervisor Violation Work Authorization