IR 05000387/1997010

Insp Repts 50-387/97-10 & 50-388/97-10 on 971209-980119.No Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML17159A137
Person / Time
Site:	Susquehanna
Issue date:	02/04/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17159A136	List: IR 05000387/1997010 ML17159A135
References
50-387-97-10, 50-388-97-10, NUDOCS 9802120113
Download: ML17159A137 (46)

Text

U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket Nos:

License Nos:

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

50-387/97-10, 50-388/97-10 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:

December 9, 1997 through January 19, 1998 Inspectors:

K. Jenison, Senior Resident Inspector B. McDermott, Resident Inspector J. Richmond, Resident Inspector G. Smith, Senior Security Specialist Approved by:

Clifford Anderson, Chief Projects Branch 4 Division of Reactor Projects 9802i20ii3 980204 PDR

,ADQCK 05000387

PDR

EXECUTIVE SUMMARY Susquehanna Steam Electric Station (SSES), Units 1 & 2 NRC Inspection Report 50-387/97-10,50-388/97-10

'P 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 an un-announced inspection by a regional physical security inspector.

~Oerations While operating at power, the licensee entered Technical Specification (TS) 3.0.3, when the limiting condition for operation (LCO) requirements of TS'3.1.4.3 could not be met.

The licensee successfully completed the required testing to prove the operability o'f the "A"rod block monitor. Managements decision to intentionally not reduce power and the operator admission that insufficient time remained to permit an orderly shutdown of the unit demonstrates a weakness in implementation the TS. Managements decision to enter TS 3.0.3 and these actions to not meet the intent of the TS will be followed as an unresolved item.

(Section 02.1)

Operator performance was reviewed by direct observations, interviews, and evaluations of PP&L self assessments.

The inspectors verified the weaknesses, identified by the PP&L self assessments, that were described as environmental factors.

Despite the weaknesses, the inspectors verified current operator performance was very good.

PP&L management is establishing general approaches to resolve these weaknesses.

The identified weaknesses currently have no apparent impact on the safe operation of SSES.

(Section 04.1)

The PP&L program, to qualify Senior Reactor Operator (SRO) license candidates, was reviewed.

From August 1988 to August 1997, the licensee was not in compliance with SSES TSs for SRO license candidates.

After discussions with the inspectors, PP&L implemented adequate corrective actions.

The inspectors considered the violations of TS requirements to be of low safety significance because the SSES training program is industry accredited, SSES SROs have a long history of good performance, TS change submittals based on similar occurrences have been routinely approved by the NRC, and SSES corrective actions ensure future SRO license candidates willmeet verbatim TS compliance.

Therefore, a failure to implement adequate corrective actions, in response to a licensee identified failure to comply with TSs, is considered a violation of minor significance and is being treated as a non-cited violation. (Section 05.1)

SSES experienced a temporary loss of the Emergency Notification System (ENS).

Backup communications to the NRC Operations Center were verified. While the reportability requirements of 50.72(b)(1)(v) were satisfied by performance of the test call to verify backup communications, the SSES procedure did not require immediate NRC notification. A procedure change is currently in process to correct this condition.

The failure to provide adequate procedural guidance, for reportability

requirements, is considered a violation of minor significance and is being treated as a non-cited violation. (Section 08.1)

Maintenance Corrective actions, for a previous NRC violation, identified the Unit 1 'standby liquid control (SLC) system was potentially inoperable and may not have been capable of fulfillinga safety function needed to shut down the reactor in the event of an accident.

A maintenance work practice and a non-specific procedure appear to have resulted in both Unit 1 SLC pump accumulators being inoperable at the same time. This condition existed for an indeterminate period of time between September 9, 1997, and November 25, 1997.

PPRL is continuing to reanalyze the SLC system design, to determine if depressurized accumulators would have prevented the SLC system from performing its safety function.

Pending additional licensee information, this issue is being followed as an unresolved item.

(Section M2.1)

~En ineerin

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The "E" Emergency Diesel Generator (EDG) tripped on high jacket water temperature, as designed, during a surveillance test.

Prior to the surveillance, the Emergency Service Water (ESW) supply valve failed to stroke open under dynamic conditions and was not noticed by the operators.

Post maintenance testing for a previous maintenance activity failed to verify the valve would function under the expected operational conditions.

Although the inadequate post maintenance test of the valve had the potential to impact safety related equipment, the "E" EDG was not aligned to a safety-related bus at the time of the event, there w'as no effect on the operating units, and no damage to the EDG occurred.

In this case, the failure to provide adequate post maintenance testing for safety related equipment is considered a violation of minor significance and is being treated as a non-cited violation. (Section E4.1)

Plant Su ort

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Implementation of the licensee's site access authorization (AA) and Fitness-for-Duty (FFD) programs were reviewed.

A failure to allow an individual to review the psychological information contained in his file is considered a violation of NRC regulations of minor significance and is being treated as a non-cited violation.

(Section S8.1)

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TABLEOF CONTENTS I. Operations

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Conduct of Operations....................

01.1 Safety Related Tagouts 01.2 Condition Report Operability Determinations 01.3 Notices to Workers 01.4 Seismic Monitors...................

01.5 Breaker Interior Inspection 01.6 Nuclear Assessment Service Surveillances

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01.7 Operator's Response to Alarmed Conditions

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02.1 Technical Specification 3.0.3 Entry to Support Surveillance Activities

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3, Operator Knowledge and Performance...

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05.1 Senior Reactor Operator License Candidate Qualification......

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08.1 Loss of Emergency Notification System Communications Capability 08.2 Licensee Event Report Review..............

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M1.1 Preplanned Maintenance ActivityReview..... ~.......

M1.2 Surveillance Test ActivitySample Reviews

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Maintenance and Material Condition of Facilities and Equipment

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M2.1 Standby Liquid Control Accumulators Found Depressurized Miscellaneous Maintenance Issues..........

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M8.1 Followup of Open Items........... ~....... ~.....

II. Maintenance

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E4 Engineering Staff Knowledge and Performance

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"E" Emergency Diesel Generator Trip on Over Temperature E8 Miscellaneous Engineering Issues

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IV. Plant Support...

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S8 Miscellaneous Security and Safeguard Issues S8.1 Access Authorization and Fitness-for-Duty Program Review

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X1 Exit Meeting Summary...........................

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Re ort Details Summar of Plant Status Susquehanna Steam Electric Station (SSES) Unit 1 was at 100% power at the beginning of the inspection period.

On December 13, 1997, a one day planned power reduction was

'ade to support a control rod sequence exchange.

A power reduction was also made on December 26, 1997, to support a minimum generation request.

The unit was returned to 100% power on December 26, 1997, and remained at 100% power until the end of the inspection period.

Unit 2 was at 100% power at the beginning of the inspection period.

On December 20, 1997, a one day planned power reduction was made to support preventive maintenance on the 'D'ondenser water box and to perform main steam isolation valve testing.

The unit was returned to 100% power on December 20, 1997, and remained at 100% power until the end of the inspection period.

I. 0 erations

Conduct of Operations

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~ 1 Safet Related Ta outs A selection of safety-related tagouts was evaluated/reviewed and some of the tags were observed independently to ensure that they were properly pre'pared and implemented.

The inspectors verified the tags were properly prepared and hung, and did not identify any problems.

01.2 Condition Re ort 0 erabilit Determinations One of the functions performed by SSES Condition Reports (CRs) is that of

"problem-identification." A sample of CRs were reviewed to determine if the deficiencies were properly identified and received a reasonable initial operability determination.

For those CRs reviewed in this sample, the CRs were properly processed and contained an adequate initial operability determination.

01.3 Notices to Workers The inspectors verified the Notice to Employees (NRC Form-3) forms were posted at SSES in at least the north gate house (i.e.,

1 of 2 site main entrances),

the Unit 1 controlled zone access point, and the control structure access tunnel (i.e., normal plant entrance to main control room). The postings were determined to be in accordance with 10 CFR 19.11.

'Topical headings such as 01, M8, etc., are used in accordance with the NRC standardized reactor inspection report outline.

Individual reports are not expected to address ail outline topic.4 Seismic Monitors A review of operator log entries associated with station seismic monitors was conducted to determine if off normal conditions were routinely occurring.

No routinely occurring conditions were identified.

01.5 Breaker Interior Ins ection While inspecting modifications associated with the signal isolators for current transformers in the ESS 4kv switchgear (see section M1.1 of this report), the interior of a breaker and the surrounding electrical cabinet were inspected for debris, loose material, and evidence of rodents.

No problems were identified.

01.6 Nuclear Assessment Service Surveillances Pennsylvania Power and Light (PPSL) Company Nuclear Assessment Services (NAS)

surveillances perform in part the function of quality assurance surveillances.

A sample of NAS operations department surveillances were reviewed for a six month period ending in December 1997. The results of the NAS audits were determined to be good and are discussed in more detail in section 04.1 of this report.

01.7 0 erator's Res onse to Alarmed Conditions a.

Ins ection Sco e 71707 During control room observations, the inspectors observed/reviewed plant control operator (PCO) and unit supervisor (US) response to alarmed conditions in order to determine compliance with TS and SSES operating procedures.

b.

Observations and Findin s Operator responses to the following alarmed conditions were observed to be aggressive and in accordance with TSs and SSES operating procedures.

AR-103-D04 Rod Block Monitor AR-107-A01 CRD Charging Water AR-106-001 Main Turbine Generator AR-203-001 Reactor Protection System c.

Conclusions Operator responses to control room alarms were observed to be aggressive and in accordance with SSES operating procedure Operational Status of Facilities and Equipment 02.1 Technical S ecification 3.0.3 Entr to.Su ort Surveillance Activities a.

Ins ection Sco e 71707 During a routine inspection of control room activities, the inspectors observed a

portion of a TS required surveillance on the "A" RBM. The licensee made decisions concerning TS 3.0.3 entry during this surveillance which the inspectors questioned.

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Observations and Findin s On October 16, 1997, the Unit 2 "A" RBM was taken out of service and declared not operable to support the performance of a surveillance test SI-278-325A, Semi-Annual Calibration of RBM2A. During the performance of this surveillance a count circuit output was observed to be below an expected voltage.

The licensee stopped the performance of the surveillance, initiated work authorizations (WAs) V73181 and V73182, to investigate and repair the low circuit output and initiated CR 97-3431 to account for an operability determination.

The following sequence of events is provided to support a discussion of the event in this report.

Date Time Se uence of Events

~Activit 10/16/97 0820 TS 3.1.4.3 limiting condition for operation (LCO) was entered when the "A" RBM was declared inoperable to support surveillance testing.

To support the surveillance test, the RBM was not placed in the tripped condition.

The inspector noted that no documentation, by means of a operator log entry, diagnostic activity, or surveillance test to show that TS 3.1.4.3.a requirements to "verifythat the reactor is not operating on a limiting control rod pattern" were completed.

Control room operators indicated that this TS requirement is interpreted as ensuring that no existing process computer alarms were present for the three thermal limits.

10/16/97 1020 Eleven local power range monitor (LPRM) inputs to the

"A" RBM were determined to be inoperable, preventing completion of the "A" RBM surveillance tes IRC technicians perform investigation and corrective maintenance that require the "A" RBM to not be in the tripped condition.

10/17/97 0820 TS 3.1.4.3 Action (a), 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period expires and the 1-hour period to trip RBM "A" begins.

10/1 7/97 0849 Corrective maintenance on LPRM inputs completed and

"A" RBM surveillance testing is resumed.

"A" RBM surveillance can not be performed with the RBM tripped.

10/17/97 0920 TS 3.1A.3 Action (a),

1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period expires, and the

"A" RBM is not tripped in accordance with the action statement.

The PCO log states "entered 3.0.3 due to non-compliance w/ [sic. with] RBM A inoperability action statement."

CR 97-3431 states that "the "A" RBM was not placed in the tripped condition to facilitate testing."

CR 97-3431 operability determination further states that TS 3.0.3 was entered because

"the action to place the 2A RBM in the tripped condition cannot be completed due to operability testing in progress."

10/17/97 1020 TS 3.0.3, 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period to initiate action to place the unit in an operational condition in which the specification does not apply expires.

The licensee completed its informal "preparations" for plant shutdown.

The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> period to place the unit in shutdown begins.

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"A" RBM surveillance SI-278-325 was completed satisfactorily.

10/17/97 1410 TS 3.0.3 action statement is cleared approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> into the LCO requirement to place the unit in at least Startup within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

The inspectors were not able to verify that the licensee took any physical actions to shutdown the plant to comply with the TS 3,0.3 LCO requirements during this 4hour period.

No power reduction was made.

The licensee stated that the decision was made to not take actions or reduce power based on a reasonable expectation that TS 3.0.3 would be exited prior to the end of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> perio The inspectors verified through conversations with Unit Superviso'r (US) and Shift Supervisor (SS) personnel that the remaining 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> from the original 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> LCO would not be sufficient to perform a normal shutdown in accordance with SSES procedure NDAP-QA-338, thus requiring a reactor trip from some elevated reactor power.

The inspectors determined that:

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the licensee entered TS 3.0.3 because the requirements of TS 3.1.4.3 to trip the "A" RBM after the allotted time prohibited the performance of the surveillance test to prove channel operability.

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the licensee successfully completed the surveillance test during the first 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> TS 3.0.3 LCO action statement and returned the "A" RBM to an operable condition.

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the licensee conducted no specific organized activities to prepare for an orderly shutdown nor took any action to reduce reactor power.

The actions that were conducted were informal because PPSL management expected to be able to exit TS 3.0.3 prior to its expiration.

the control room management stated that the remaining 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> from the original 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> LCO would not be sufficient time to perform a normal shutdown in accordance with SSES procedure NDAP-QA-338, thus requiring a reactor trip from some elevated reactor power.

The inspectors questioned the appropriateness of managements decision to enter TS 3.0.3.

Further, the failure to implement formal actions to facilitate a controlled shutdown did not meet the intent of TS 3.0.3., as stated in the bases of the Technical Specifications and Generic Letter 87-09, Sections 3.0 and 4.0 of Standard TS on LCOs and Surveillance Requirements.

TS 3.0.3 establishes the shutdown requirements that must be implemented when a TS LCO is not met and the condition is not specifically addressed by the associated LCO action requirements.

It requires that within one hour action shall be initiated to place the unit in a safe shutdown condition within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

The time limits specified to reach lower conditions of operation permit the shutdown to proceed in a controlled and orderly manner.

The TS is not intended to be used as an operational convenience or a defacto extension when a TS LCO is not met.

Managements decision to intentionally not reduce power and the operator admission that insufficient time remained to permit an orderly shutdown of the unit demonstrates a

weakness in implementation of the T PP5L management is re-evaluating the issue to enter TS 3.0.3.

Managements decision to enter TS 3.0.3 and the actions to not meet the intent of the TS will be followed as an unresolved item. (URI 50-388/97-10-01)

C.

Conclusions While operating at power, the licensee entered Technical Specification (TS) 3.0.3, when the limiting condition for operation (LCO) requirements of TS 3,1.4.3 could not be met. The licensee successfully completed the required testing to prove the operability of the "A"rod,block monitor.'anagements decision to intentionally not reduce power and the operator admission that insufficient time remained to permit an orderly shutdown of the unit demonstrates a weakness in implementation the TS. Managements decision to enter TS 3.0.3 and the actions to not meet the intent of the TS will be followed as an unresolved item.

Operator Knowledge and Performance 04.1 Environmental Factors and 0 erator Performance a 0 Ins ection Sco e 71707 Various PPtkL internal reports have indicated that environmental factors have created a stressful working relationship between Operations personnel and management.

The inspectors reviewed these documents and conducted interviews to evaluate PCO and Nuclear Plant Operator (NPO) performance.

The inspector reviewed an Independent Safety Engineering Group (ISEG) report, dated December 19, 1997, a sample of Nuclear Assessment Services (NAS) surveillances, and a letter from the Operations Manager to a distribution list, dated December 31, 1997.

The inspector discussed these issues with SSES Management, the ISEG Supervisor,

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the NAS surveillance group supervisor and selected auditors, and various representative from the Operations Department.

Further, the inspector observed a

sample of operator activities.

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Observations and Findin s Observations The ISEG report indicated that the quality of in-plant watch standing was improved and that in-plant evolutions were well done.

However, the relationship between Operations Department Management and the rank and file of the Operations Section needed to be improved.

The NAS surveillances noted effective communications and operator work performance.

Yet some weaknesses in the scheduling of plant activities cause a conflict and impact on PCO ability to complete some activities.

The inspector determined that operator activities were in general being well performed, but that there were organizational environmental factors which posed challenges to SSES managemen During the observation of NPOs and PCOs, the inspectors found the assigned activities to be currently performed in'a professional, aggressive and effective manner.

Operators were able to describe the activity they were performing, the impact on other plant equipment, and appropriate PPSL controls and procedures applicable to the performed activity. However, the inspector discerned a concern on the part of the NPOs and PCOs that managements expectations were not always clear and often affected the performance of operator's activities.

The inspectors observed US, AUS, and STA activities, which included a plant inspection, interfacing with control room staff, and providing direct supervision of the NPO and ASO shift staff. Adequate technical direction was observed to be provided to the NPOs and ASOs by the supervisors.

Communications between the supervisors and the SS, STA, and the NPOs and ASOs were clear and concise.

Conduct of the supervisors appeared professional and appropriate.

The inspectors discussed separately management expectations for operator performance and the lines of communications between the operators and plant management with the supervisors.

The supervisors were confident the NPOs and ASOs clearly understood their expectations and stated the work performance of the NPOs and ASOs satisfied their expectations.

The supervisors felt they clearly understood the expectations of their direct supervisor, the SS, and believed they met those expectations.

However, the supervisor's felt the organizational environment and the lines of communications between the shift operators and management needed improvement.

The inspector discussed his observations with the Site Vice President, General Manager SSES, and Manager of Operations.

During one conversation, the job performance functions issues and the ISEG report were discussed specifically.

PPSL is working to resolve issues involving the PCO, NPO and ASO job performance associated functions through a bargaining unit negotiation process.

The ISEG report is being addressed through normal management actions much the same way that a cultural survey was resolved in 1997.

Operations management was observed to be sensitive to the need for a quick resolution of operator related issues and continues to communicate a safety oriented approach to the operation of the units.

PP5L management stated that they are expending considerable resources trying to resolve these issues but do not find that the issues are affecting the safety of the units.

~Findin n

In general, the inspectors found the operations department personnel to be well aware of plant activities, their individual performance, and the overall condition of their assigned units. The US were very able to describe their actions, direct the actions of the PCO, research the resolution of technical issues using the tools available to them in the control room, and control the release of work authorization The inspectors were able to verify the conclusions made by the ISEG and the NAS concerning present operator performa'nce.

Through conversations with SSES workers the inspectors were also able to verify some individuals felt the need to improve specific organizational environmental factors, including communications between management and workers.

SSES Management is establishing general approaches to the resolution of identified organizational environmental factors including bargaining unit negotiation, PP&L leadership training, increased communications between management and workers, PP&L human resources programs, PP&L employee concerns program initiatives in supervision, Operator Department Focus Group activities', and responses to the findings from the 1997 cultural survey and ISEG report.

The inspectors concluded that organizational environmental factors were determined to have no current visible impact on the safe operation of the plant.

C.

Conclusions Operator performance was reviewed by direct observations, interviews, and evaluations of PP&L self assessments.

The inspectors verified the weaknesses, identified by the PP&L self assessments, that were described as environmental factors.

Despite the weaknesses, the inspectors verified current operator performance was very good.

PP&L management is establishing general approaches to resolve these weaknesses.

The identified weaknesses currently have no apparent impact on the safe operation of SSES.

Operator Training and Qualification 05.1 Senior Reactor 0 erator License Candidate Qualification a.

Ins ection Sco e 71707 PP&L corrective actions to resolve questions concerning initial qualifications of some SRO license candidates were reviewed by the inspectors to determine safety impact on current unit operations and the adequacy of long term corrective actions.

b.

Observations and Findin s TS 6.3 states that "Each member of the unit staff shall meet or exceed the minimum qualifications of ANSI N18.1-1971 for comparable positions and the supplemental requirements specified in sections A and C of enclosure 1 of the March 28, 1980 NRC letter to all licensees..."

Enclosure 1 to the above stated letter identifies two requirements for an SRO applicant.

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Applicants for Senior Reactor Operator license shall have four years of responsible power plant experience.

Responsible power plant experience should be obtained as a Control Room Operator (fossil or nuclear) or as a Power Plant staff engineer involved in the day-to-day activities of the facility, commencing with the final year of construction.

A maximum of two years shall be academic or related technical training, on a one-for-one time basi ~

Applicants for Senior Reactor Operator license shall have held an operator's license for one year.

From the time of the initial operating license until August 1997, the licensee did not strictly comply with TS 6.3 during the licensing of some SRO candidates.

Rather than meet the specific TS requirements, the licensee has employed various interpretations for those SRO license candidates that it submitted to the NRC for approval.

Included in the interpretations employed by PPS.L was the incorporation of wording from NUREG 0776, SSES Safety Evaluation Report and NUREG 1021, Operator Licensing Examiner Standards for Power Reactors.

NUREG 0776 did not affect the existing wording in the TS but, interpreted the 1980 NRC letter in the following manner:

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Applicants for Senior Reactor Operator license shall have four years of responsible power plant experience, of which at least two years shall be nuclear power plant experience (including six months at the specific plant),

and not more than two years shall be academic or related technical training, After fuel loading, applicants shall have one year experience as a licensed operator, or equivalent.

Note: the term "equivalent" was described to be a combination of a college degree and experience.

The NRC identified to the licensee that there was a difference between the interpretations used by the licensee to license some SRO candidates and the standards dictated in the TS.

In response, the licensee issued CR 97-2503. The inspectors reviewed the CR and the licensee's Improved Technical Specifications (ITS) submittal (note: the ITS submittal is currently under review by the NRC). The inspectors determined that the ITS submittal, when approved by the NRC, will incorporate the interpreted wording of the 1980 NRC letter proposed in NUREG 0776. The inspectors determined that the subject wording is routinely accepted by the NRC for utilities with industry accredited training programs such as the SSES training program.

Based on an inspector review of CR 97-2503, several corrective action weaknesses were identified. The resolution of these weaknesses was discussed with representatives of the licensee's training and licensing organizations.

The weaknesses included:

The CR refers to the requirements of the NRC letter incorporated into TS 6.3 by reference, as a "commitment" and does not state clearly that the TS requirements were not met for an extended period of time.

The CR did not identify that two individuals failed to meet both the TS and the NUREG 0776 interpretations when PPSL proposed them for their initial SRO license examination.

In addition, the CR did not clearly state that these currently licensed individuals met the TS requirement or justify why it was

acceptable for the two individuals to continue to maintain and use their SRO licenses.

The CR simply stated "NTG [SSES Nuclear Training Department]

has reviewed each licensed Unit Staff member's qualification and determined that each currently meets the intent of the requirement."

Neither of the individuals possessed a four year degree, neither held a valid reactor operator license and one of the individuals did not have extensive in plant experience at the time they became SRO license applicants.

These conditions were clearly stated on the SRO application packages.

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The CR identified six individuals that did not comply with the TS but 'did meet the NUREG 0776 interpretation when SSES proposed them for their initial SRO license examination.

However, the CR did not state that the currently licensed individuals met the TS requirement or justify why it was acceptable for the individuals to continue to maintain and use their SRO licenses.

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The CR identified the root cause of these problems as "human error" further stating that "The documents related to unit staff qualification were not revised as necessary.

When the changes to eligibilityrequirements were implemented the related documents were not updated."

It was not recognized (stated in the CR) that the NUREG documents were not eligibility requirements and that the only legal requirements were those stated in the TS.

In the safety assessment portion of the CR, it states that "There is no safety impact based on 1) All individuals who perform license (sic) duties meet the intent of the eligibilityrequirement, as clarified in the SER, NUREG 0776."

This CR statement implies that licensee management determined that NUREG documents were capable of amending or changing requirements stated in the TS.

Following discussions of the above weaknesses with the inspectors, the licensee undertook adequate corrective actions.

The licensee's corrective actions included a verification that all licensed operators held valid, current and appropriate operating licenses.

Secondly, the licensee established remediation training for one operator as a very conservative measure.

Finally, the licensee submitted a Technical Specification change to account for the licensing process that is currently used by PPSL and the industry as a whole.

Neither the licensee nor the inspector identified a condition or situation that brought the current appropriateness of any operating license into question.

The inspectors considered the deviations from the strict TS SRO eligibility requirements to be of low safety significance with respect to the performance of the SROs in a licensed capacity.

The safety significance was considered to be low because the SSES training program is industry accredited, all of the SROs have a long history of good licensed and/or operating performance, the program implemented by the licensee is routinely accepted by the NRC when TS changes are

properly submitted, and the licensee has put actions in place to ensure that future SRO license applications will be made in accordance with the applicable TS.

Therefore, the failure to identify specific corrective actions, in response to a failure to comply with TS 6.3 for the licensing of SRO candidates, was considered a

violation of minor significance and is being treated as a non-cited violation, consistent with Section IV of the NRC Enforcement Policy.

(NCV 50-387,388/97-10-02)

c.

Conclusions The PPSL program, to qualify Senior Reactor Operator (SRO) license candidates, was reviewed.

From August 1988 to August 1997, the licensee was not in compliance with SSES TSs for SRO license candidates.

After discussions with.the inspectors, PPSL implemented adequate corrective actions.

The inspectors considered the violations of TS requirements to be of low safety significance because the SSES training program is industry accredited, SSES SROs have a long history of good performance, TS change submittals based on similar occurrences have been routinely approved by the NRC, and SSES corrective actions ensure future SRO license candidates willmeet verbatim TS compliance.

Therefore, a failure to implement adequate corrective actions, in response to a licensee identified failure to comply with TSs, is considered a violation of minor significance and is being treated as a non-cited violation.

Miscellaneous Operations Issues 08.1 Loss of Emer enc Notification S stem Communications Ca abilit a.

Ins ection Sco e 71707 The inspectors observed the licensee's actions during an approximately 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> period when the Emergency Notification System (ENS) at SSES was inoperative.

b.

Observations and Findin s On January 14, 1998, at approximately 9:30 a.m., an AT&Trepresentative informed the NRC that the FTS-2000telephone system, which carries the emergency notification service (ENS) communications circuits, was out of service.

The Shift Staff verified that the ENS phones in the main control room, SS office, and the Technical Support Center (TSC), were inoperative.

The SS verified alternative reliable communications were available between the control room and the NRC Operations Center within 15 minutes.

The SS informed the NRC Duty Officer and the SSES emergency planning group of the problem with the ENS syste At 5:20 p.m. the ENS phone system was returned to service.

The problem was a local telephone company pole mounted line repeater, between SSES and the local phone company's switching station, had failed.

P Although the SS did report to the NRC Operations Center within one hour, the loss of the ENS communications capability, SSES did not process the call as a "NRC one hour notification" as required by 10 CFR 50.72.

SSES procedure NDA'P-QA-0720, Station Report Matrix and Reportability Evaluation Guidance, directs SSES personnel to establish communications with the NRC, using a variety of methods listed in preferential order.

However, the procedure states the loss of the ENS is not NRC reportable "provided at least one alternative reliable communications method can be established with the NRC within one hour." The reportability actions directed by the SSES procedure are contrary to the requirements of 10 CFR 50.72(b)(1)(v).

NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73, states that testing the backup means of communications to the NRC Operations Center, satisfies the requirements of 50.72(b)(1)(v). Therefore, the reportability requirements were met.

However, the SSES procedure provides reportability guidance to the contrary.

The inspectors concluded procedure NDAP-QA-0720 was not adequate in that it directed station personnel not to make an NRC notification for the loss of the ENS.

As a result, SSES made a test phone call, to verify backup communications reliability, but did not make a CFR 50.72 notification, as required.

SSES is currently in the process of revising the procedure to correct this condition.

The failure to provide adequate procedures for the control of plant communications systems was considered a'violation of minor significance and is being treated as a non-cited violation, consistent with Section IV of the NRC Enforcement Policy.

(NCV 60-387,388/97-10-03)

c.

Conclusions SSES experienced a temporary loss of the Emergency Notification System (ENS).

Backup communications to the NRC Operations Center were verified. While the reportability requirements of 50.72(b)(1)(v) were satisfied by performance of the

test call to verify backup communications, the SSES procedure did not require immediate NRC notification. A procedure change is currently in process to correct this condition.

The failure to provide adequate procedural guidance, for reportability requirements, is considered a violation of minor significance and is being treated as a non-cited violation.

08.2 Licensee Event Re ort Review a.

Ins ection Sco e 92700 The inspectors reviewed Licensee Event Reports (LERs) submitted to the NRC to verify that details of the event were clearly reported, including the accuracy of the event description, cause, and corrective action.

The inspectors determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite followup.

b.

Observations and Findin s Closed LER 50-387 97-025-00:Loss of Both Trains of Standby Liquid Control On November 25, 1997, PPSL discovered that both trains of Unit 1 standby liquid control had pump discharge accumulators which had depressurized below the minimum required value.

This event is reviewed in detail in this inspection report, section M2.1, and is being followed as unresolved item URI 50-387,388/97-,10-05.

This LER is closed.

Closed LER 50-388 97-006-00:Recirculation Discharge Valve Bonnet Vent Line Crack On September 17, 1997, a cracked weld on the 3/4 inch bonnet vent line for reactor recirculation system valve HV-2F031B resulted in a primary coolant system leak and subsequent unplanned shutdown of Unit 2.

This event was reviewed in detail in NRC Inspection Report 50-387,388/97-09, section M3.1, and resulted in VIO 50-388/97-09-02.

This LER is closed.

Closed LER 50-388 97-007-00:Entry into Technical Specification 3.0.3-Rod Block Monitor Operability Testing On October 17, 1997, the RBM failed to pass a TS required surveillance test and was declared inoperable.

During the subsequent repair and post maintenance surveillance testing of the RBM, the TS 3.0.3 LCO action statement was initiated.

This event is reviewed in detail in this inspection report, section 02.1, and is being followed as unresolved item URI 50-387,388/97-10-01.

This LER is close e

'4 c.

Conclusions The licensee event reports reviewed during this period were appropriately reported, and provided an accurate description of the causes and corrective actions.

II. Maintenance M1 Conduct of Maintenance M1 ~ 1 Pre lanned Maintenance Activit Review a.

Ins ection Sco e 62707 The inspectors observed/reviewed selected portions of preplanned 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 the following WAs were observed/reviewed during this inspection.

In addition, selected equipment, permits (tagouts),

procedures, drawings, and/or vendor technical manuals associated with the maintenance activities were also reviewed.

P72487 C60658 P70764 S74706 S72239 S73107 S73108 S75383 Security X-ray device 1A 20401 Isolator Modification Assembly Installation High Pressure Coolant Injection (HPCI) Overspeed Performance HPCI Tappet Replacement Steam Jet Air Ejector Containment Radiation Monitor Containment Radiation Monitor Suppression Pool Temperature Monitoring System Interviews with maintenance personnel showed the individuals involved in the maintenance activities to be knowledgeable and capable of explaining their function, C.

Conclusions The planned maintenance activities, reviewed during this period, were found to be appropriately conducted and controlled.

Interviews with maintenance personnel showed the individuals involved in the maintenance activities to be knowledgeable and capable of explaining their activities.

No violations of NRC requirements were identifie 'I M1.2 Surveillance Test Activit Sam le Reviews a.

Ins ection Sco e 61726 The inspectors observed/reviewed selected portions of preplanned surveillance activities, to determine whether the surveillance tests conformed to TS requirements and SSES administrative requirements.

b.

Observations and Findin s Portions of the following preplanned surveillance activities were observed/reviewed:

SI-280-31

SO-1 00-006 SE-224-B02 SO-024-001 SI-21 3-238 SO-1 56-001 SI-214-202 Quarterly Calibration of Reactor Vessel Water Level Channels LIS-B21-2N024 BRD, December 23, 1997 Shift Surveillance Operating Log, December 23, 1997 18 Month Diesel Generator B (or E) Auto Start and ESS Bus 2B Energization on Simulated Loss of Offsite Power, April 18, 1997 Monthly Diesel Generator Operability Test, December 15, 1997 Semi-Annual Functional Test of Preaction System Fire Protection Ionization and Photoelectric Detectors, January 5, 1998 Weekly Control Rod Exercising, January 5, 1998 Quarterly Functional Test of Drywell Pressure Channels PSH-25120 CSD, January 12, 1998 The subject surveillance activities were determined to conform to the requirements of TS and met PPSL administrative requirements (approvals, 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.

c.

Conclusions The surveillance activities observed were adequately performed and appropriately controlled.

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

No violations of NRC requirements were identified.

M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Standb Li uid Control Accumulators Found De ressurized a.

Ins ection Sco e 62707 92700 On November 25, 1997, PPSL discovered the discharge accumulators, for the Unit 1 "A" and "B" standby liquid control (SLC) pumps, had depressurized below the minimum required pressure.

The inspectors reviewed PPRL's engineering investigation, root cause evaluation, and Licensee Event Report for this issu Observations and Findin s Unit 1 TS 3.1.5 requires the SLC system to be operable during Operational Conditions 1 and 2. With one inoperable SLC pump, the TS requires the licensee to restore the pump to an operable condition within 7 days.

With both SLC pumps inoperable, the TS requires the SLC system be restored to an operable condition within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

Otherwise, the reactor must be placed in the Hot Shutdown condition within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

Pressure pulsations created by the SLC positive displacement pumps are dampened by nitrogen accumulators located downstream of each pump.

PP&L mainte'nance procedure MT-053-003, Revision 5, requires the nitrogen pre-charge on each accumulator to be between 1020 and 1085 psig.

Historically, this pressure was verified, and restored if necessary, prior to the SLC quarterly flow surveillance test.

In September 1997, the NRC questioned the effect of depressurizing a SLC accumulator on the system operability.

PP&L subsequently determined SLC pump operability required the accumulators to be pressurized.

Without sufficient accumulator pressure, the pulsations may cause the relief valve, downstream of the SLC pump, to liftand divert a portion of the sodium pentaborate back to the pump suction.

An NRC violation (VIO 50-387/97-07-06) was issued because the maintenance procedure used to verify and restore the accumulator pressure allowed the system to be placed in an unanalyzed configuration that rendered a SLC pump inoperable.

In October 1997, PP&L responded to concerns regarding the ability of the accumulators to maintain the required pressure between surveillance tests (i.e.,

accumulator leakage), by implementing a monthly accumulator pressure check, until additional data could be collected.

On November 25, 1997, a check of the Unit 1 "A" SLC accumulator found the pressure at 220 psig.

The control room was notified, the "A" SLC pump declared inoperable, maintenance personnel re-pressurized the accumulator, and the "A" pump was then declared operable.

Several hours later, a check of the Unit 1 "B" SLC accumulator found that it was pressurized to 75 psig.

Again, the control room was notified, the "B" SLC pump declared inoperable, maintenance personnel re-pressurized the accumulator, and the "B" pump was then declared operable.

CR 97-3888 documented the as-found condition of both pump accumulators and made a reportability determination that the event was not reportable to the NRC because the problems were discovered sequentially.

On November 26, 1997, PP&L identified a maintenance practice as the potential cause for the accumulators loosing pressure.

A schrader valve (i.e., similar to a bicycle tire valve), on the accumulator, is the nitrogen fillvalve. This valve has a cap, which must be removed, to check accumulator pressure or add nitrogen to the accumulator.

The vendor manual for the accumulator specifies tightening requirements for the valve cap.

However, the maintenance procedure did not incorporate these requirements, or contain any cautions regarding the tightening of

the cap.

As a consequence of the lack of guidance, in the maintenance procedure, PP&L concluded the valve caps may have been, in the past, over-tightened by maintenance personnel.

PP&L further concluded over tightening the valve cap can distort the o-ring seal inside the cap to the point that it depressed the valve stem core, inside the schrader valve, allowing the valve to leak slightly.

On December 1, 1997, the inspectors questioned the CR 97-3888 reportability determination because a poor maintenance practice, used on both SLC accumulators (i.e., a potential common mode failure mechanism), resulted in both SLC pumps being inoperable at the'same time.

On December 2, 1997, PP&L concluded the as-found condition of the accumulators indicated the SLC system was inoperable as the result of a common cause.

NUREG 1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73, states that any time a system could not have performed its safety function, because of a common-mode failure, it is reportable under these criteria.

PP&L initiated a 4-hour report to the NRC on December 2, 1997; an LER (50-387/97-25-00),describing the problem, was issued on January 2, 1998. This event was reported under the requirements of 10 CFR 50.73(a)(2)(v) as a condition that alone could have prevented the fulfillmentof a safety function of a system needed to shut down the reactor. The LER transmittal letter states, in part, that:

...both trains of Standby Liquid Control System (SLCS) were determined to be inoperable at the same time due to low accumulator pressure which could prevent the SLCS from achieving its maximum design flowto the reactor vessel...the in-operability of both trains of Standby Liquid Control System is considered to be a loss of a safety system needed to mitigate the consequences of an accident.

As discussed in the LER, PP&L concluded the cause of the depressurization was most likely the result of over tightening the schrader valve cap, thus distorting the o-ring seal to the point that it depressed the valve core enough to allow it to leak slightly. Over time the accumulator pressure bled down below the allowable value.

The inspectors noted that PP&L was unable to determine when the SLC accumulators had decreased below the required pressure, and therefore a direct comparison to the SLC TS action statement time limits was not possible.

The inspectors discussed the PP&L investigation with cognizant licensing and NSE representatives, reviewed the associated CR and engineering documentation, and observed maintenance practices associated with verifying the accumulator pressure.

It was concluded that the licensee's postulated cause of the depressurization was plausible and that the event was appropriately reported.

The five day delay in reporting the event was considered a weakness in PP&L's reportability evaluation process.

The inspectors determined that the lack of adequate procedural guidance for installation of the schrader valve cap may be a root cause for this even PP5L calculation EC-053-1001, approved on January 14, 1998, determined that the minimum accumulator pressure required for operability is 875 psig.

Corrective actions, discussed in LER 50-387/97-25-00,were verified by the inspectors.

These actions included revision of the accumulator maintenance procedure and installation of new schrader valve caps on all four accumulators.

The inspectors determined the scheduled actions described in the LER were in progress and that the modification to install permanent pressure indication for the accumulators was scheduled for the first quarter of 1998.

The adequacy of the procedure used to control maintenance on the accumulators is still under NRC review. Specifically, additional information is needed to determine whether the over tightening of the schrader valve caps should have been recognized by PPSL as a potential problem prior to this event.

In addition, PPSL is reanalyzing the SLC system design, to determine if the depressurized accumulators would have prevented the SLC system from performing its safety related function.

Pending additional information from PPSL, this issue willremain unresolved.

(URI 50-387/97-10-04)

Conclusions Corrective actions, for a previous NRC violation, identified the Unit 1 standby liquid control (SLC) system was potentially inoperable and may not have been capable of fulfillinga safety function needed to shut down the reactor in the event of an accident.

A maintenance work practice and a non-specific procedure appear to have resulted in both Unit 1 SLC pump accumulators being inoperable at the same time. This condition existed for an indeterminate period of time between September 9, 1997, and November 25, 1997.

PPSL is continuing to reanalyze the SLC system design, to determine if depressurized accumulators would have prevented the SLC system from performing its safety function.

Pending additional licensee information, this issue is being followed as an unresolved item.

Miscellaneous Maintenance Issues Followu of 0 en Items (92902)

Closed URI 50-387 93-19-01: Unexpected Control Rod Movement On October 5, 1993, during an SSES Unit 1 refueling outage, control rod 14-35 drifted out to position 04, with no operator action.

Several control room alarms were received, including a rod drift alarm.

No control rod manipulations were being performed at the time. The cause of the rod drift event was subsequently determined to be a failure of the control rod drive mechanism (CRDM) to settle back to position 00 from the over-travel position, following a scram, coincident with a failure of a hydraulic control unit (HCU) transponder card.

During the investigation of this event, more than 16 other unexpected rod movement events at SSES were also identified and reviewed as part of this URI ~

When a CRDM is in any "even" position, such as position 00, the collet fingers are latched in a notch on the index tube.

Due to the ratchet notch design of the index tube, a control rod cannot move in the withdraw direction without first unlatching the collet fingers from the index tube.

The withdraw pressure, applied to a CRDM from the HCU, is insufficient to unlatch the collet fingers from the index tube while the weight of the CRDM is on the collet fingers.

Normal rod withdrawal requires correctly sequenced (i.e., timed) insert and withdraw command signals.

A short insert signal is first applied, followed by a withdraw signal.

The purpose of the short insert signal is hydraulically to liftthe weight of the CRDM off the collet fingers.

Once the weight is remov'ed from the collet fingers, withdraw pressure is applied, and the collet fingers are then maintained open and unlatched.

This is a system design feature (i.e., physical design of CRDM and electronic design of reactor manual control system (RMCS)) to prevent inadvertent rod withdrawal due to a malfunction of the HCU or RMCS. However, it should be noted that this design feature will not prevent an inadvertent rod insert event.

An unexpected rod withdrawal event, therefore, requires two separate events sequentially to take place.

First, the collet fingers must be unlatched from the index tube, and second, hydraulic withdraw pressure must be applied to the CRDM. In 1979 and 1980, based on BWR industry experience, General Electric (GE) Service Information Letters (SILs) identified several system malfunctions that can result in unexpected rod withdrawal (i.e., SIL 292, SIL 292 Supplement 1, and SIL 310).

NRC Information Notice 86-89 reviewed this issue and the GE recommended actions contained in SILs 292, 292 Supplement 1, and 310. The identified'failure mechanisms all relied upon the collet fingers unlatching during normal rod movement, coincident with a failure that applied withdraw pressure to the CRDM.

The failure mechanisms include a failure to close an HCU directional control valve (DCV) or a DCV inadvertently energized by an HCU transponder card failure, coincident with an insert or withdraw command (i.e., rod continues to withdraw, or drifts in the withdraw direction, after the operator terminates a withdraw or insert command).

Collet sticking or binding in the open (i.e., unlatched) position, following an operator initiated withdraw command, was also identified as a malfunction leading to a rod drift in the withdraw direction.

An unexpected rod withdrawal event at SSES, in October 1993, was caused by a failure mechanism sequence that had not previously been identified.

During a scram, CRDMs normally insert beyond position 00, then settle back down to position 00. The position above position 00, is called the "over-travel" position.

During cold reactor. conditions (i.e., refueling operations),

a common phenomena following a scram, seen at some BWR plants, is for a few CRDMs to stick in the over-travel position and not settle back to position 00. When a CRDM is in the over-travel position, the collet fingers are not latched in a notch on the index tube.

If a control rod is left in the over-travel position (i.e., unlatched), it is then susceptible to a single failure of the HCU transponder card that could result in an inadvertent rod withdrawal even After the SSES event, GE issued SIL 292 Supplement 2, describing the "over-travel" failure mechanism leading to an unexpected rod withdrawal. Although GE performed extensive investigations into these over-travel sticking events, no explicit cause has been identified.

GE identified the most probable cause as a crud buildup on the CRDM outer piston bushings.

GE recommended procedural controls to ensure all rods are at position 00, as soon as possible, after resetting any scram.

By repositioning a control'rod, that had failed to settle, to position 00, and verifying all control rods are at position 00,'he probability of an inadvertent rod withdrawal event is significantly reduced.

Before this October 1993 SSES rod drift event, it was not recognized that leaving a CRDM in the over-travel position (i.e., unlatched)

was in fact "removing a design barrier" meant to prevent inadvertent rod withdrawal.

At the time of the event, more than 40 CRDMs at SSES Unit 1 were stuck in the over-travel position, and the SSES HCU transponder card failure rate was significantly above the industry average.

Before the event, SSES made no distinction between control rods in the over-travel position, and rods at position 00.

As a consequence, SSES may have operated during refueling, startup, and power operations, without all control rods latched, and was therefore susceptible to a higher probability of an inadvertent rod withdrawal event.

SSES subsequently revised its operating procedures to confirm all control rods are latched at position 00, as part of the scram reset procedure.

In addition, once per each shift, all fully inserted control rods are verified to be latched.

Any control rod that cannot be settled to position 00, is hydraulically disarmed.

These actions exceed the GE recommendations, and appear to be both reasonable and effective.

In addition to procedural controls to ensure all rods are latched, SSES has greatly reduced the number of cold scrams generated during a refueling outage, further reducing the possibility of unexpected rod movement.

Improvements have been made to the preventative maintenance program for trending and rebuilding CRDMs.

Detailed instrument and control (ISC) procedures have been developed to repair HCU transponder cards.

During the last operating cycle, SSES transponder card failure rates and CRDM over-travel sticking events have been significantly reduced from the 1993 levels, and are in line with BWR industry averages.

/

As part of the initial corrective actions, the licensee reanalyzed Final Safety Analysis Report (FSAR) section 15,4, Reactivity and Power Distribution Anomalies, and determined that an unexpected rod withdrawal event, from full-into full-out, was bounded by the continuous rod withdrawal accident analysis.

In performing the analysis, the licensee classified the event as an "infrequent incident" (i.e., occurs once in 20 to once in 100 years).

However, based on the occurrence and frequency of actual unexpected rod movement events at SSES, the inspectors questioned the methodology used by the licensee.

In particular, general design criteria (GDC) 25 requires that protection systems be designed to prevent exceeding

"fuel design limits" in the event of a single malfunction of the reactivity control

system.

However, the fuel design limits, used in the accident analysis, are dependent upon the event frequency (i.e., a more restrictive value of minimum critical power ratio (MCPR) is used to analyze moderate frequency events than is used to analyze infrequent events).

Based on an NRC concern, the licensee classification of unexpected rod movement events as infrequent, the licensee reanalyzed these events as a moderate frequency incident (i.e., occurs once a year to once in 20 years).

No change'to the MCPR limitwas required; the generator load reject incident remained more restrictive.

PP&L subsequently revised the NRC approved methodology used in their cycle reload analyses.to include a rod drift event from fully inserted to fully withdrawn, classified the event as moderate frequency, and did not take credit for the RBM.

Revisions to SSES FSAR sections 15.4.1, Rod Withdrawal Error - Low Power, and 15A.2, Rod Withdrawal Error - At Power, have been prepared by PP&L engineering and submitted to PP&L licensing to reflect the current analysis basis and results for the p'ostulated events which involve rod drift events.

This item is closed.

III. En lneerin E4 Engineering Staff Knowledge and Performance E4.1

"E" Emer enc Diesel Generator Tri on Over Tem erature a.

Ins ection Sco e 37551 71707 On November 25, 1997, the "E" Emergency Diesel Generator (EDG) was started for a 24-hour TS surveillance test run. Twenty nine minutes into the surveillance test, the EDG tripped on high jacket water temperature.

The inspectors reviewed the licensee's root cause investigation for the'rip and the implementation of corrective actions.

b.

Observations and Findin s At the time of this event, the "E" EDG was aligned to its non-safety-related test bus for a 24-hour surveillance and the "A"through "D" EDGs were aligned to the Engineered Safeguard System (ESS) buses to meet TS requirements.

At 10:20 a.m. the "E" EDG was started in accordance with SE-024-E05 to perform the 24-hour endurance surveillance required by TS 4.8.1'.1.2.d(7). At 10:49 a.m.,

the EDG was running and was loaded to 2750 kW when the "AirHeader System Trouble" annunciator alarmed.

Operators in the EDG room were in the process of referencing the alarm response and operating procedures when the EDG tripped.

The operators'nvestigation, following the trip, found the jacket water temperature in excess of the trip setpoint and the inlet valve for the "B" loop of ESW, HV-01110E had dual indication.

Initial attempts to remotely open the valve were unsuccessful.

However, after the valve's control switch was taken to the closed position, the valve would again move in the open directio '2 Although the "E" EDG was not aligned for service, the license performed an operability determination to evaluate the effects of the high jacket water temperature trip. After discussions with the EDG vendor and a review of the EDG response to the high temperature condition, PPSL concluded no engine or auxiliary component damage had occurred.

The EDG vendor also informed PPSL that there was no need to conduct any component inspections.

Nuclear System Engineering (NSE) performed an investigation of the motor operated valves'ontrol circuit configuration and inspected the limit and torque switches.

Plant records indicate that this was the first time the "B" ESW supply valves to the

"E" EDG have been stroked under dynamic conditions since their torque switches were adjusted in February 1997.

NSE confirmed that the valves do not have a safety function to stroke under dynamic conditions.

The inspector verified that the safety related function of the ESW valves, described in the licensee's investigation, was consistent with their Motor Operated Valve (MOV) program assumptions.

The inspector determined that the as-found condition on November 25, 1997, was indicative of a valve having tripped its torque switch after stroking approximately 5% open.

This scenario is consistent with the valve's opening logic which places the torque switch into the circuit after approximately 5% of the open stroke.

The inspectors concluded that the NPO who opened the valves in accordance with OP-054-001, Emergency Service Water System, step 3.4.4, did not adequately verify that valve HV-01110E completed its stroke to the full open position.

The inspectors considered this a human performance weakness and a missed opportunity to identify the problem.

Although this human performance error occurred, the inspectors considered the root cause of this event to be the inadequacy of the process used to modify the valves as discussed below.

PPSL's review of plant maintenance records found that in response to a spring pack deficiency identified on February 2, 1997, the torque switch setting for HV-01110E was changed under WA P61402.

Similarly, the torque switch settings for HV-01120E were changed on February 9, 1997, under WA P61403, The inspector noted that these changes were implemented as "Immediate Corrective Actions" under CRs 97-0212 and 97-0236, respectively.

The torque switch settings were not changed under the Setpoint Change Package process normally used by PP&L for this type of design change.

The inspectors considered this a weakness that contributed to the failure to establish an adequate PMT. However, regardless of the change process implementing the change, the post maintenance test (PMT) of the valves did not verify the valves would operate under the expected flow conditions.

The inspector considered the maintenance procedures for this change to be inadequate because they did not ensure the valve would operate as expected.

This event could have resulted in damage to the "E" EDG during the surveillance test.

The licensee implemented short term corrective actions to ensure the ESW valves to the "E" EDG are stroked under only static conditions.

The NPO was coached and counseled by Operations management regarding expected self checking practices.

In addition, the torque switch setpoint changes have been formally processed.

Considering the unique design basis for the "E" EDG ESW supply valves and the

motor operated valve (MOV) program requirements, that apply to other safety related MOVs, the inspector identified no generic problems with the PMT practices used for safety related valves. The inspector considered the licensee's corrective action for this event to be adequate and there was no impact on plant safety as the result of this event.

TS 6.8.1 requires written procedures be established, implemented, and maintained covering the procedures recommended in Appendix A of RG 1.33, Revision 2, February 1978.

Item 9.a. of Appendix A to RG 1.33, requires procedures for maintenance that can affect the performance of safety related equipment.

In February 1997, maintenance procedures that altered the design of ESW valves, and affected the "E" EDG, were not adequate to ensure the valves would function under expected operational conditions.

This non-repetitive, licensee-identified, and corrected violation is being treated as a non-cited violation, consistent with Section VII.B.1 of the NRC Enforcement Policy.

(NCV 50-387,388/97-10-05)

C.

Conclusions The "E" Emergency Diesel Generator (EDG) tripped on high jacket water temperature, as designed, during a surveillance test.

Prior to the surveillance, the Emergency Service Water (ESW) supply valve failed to stroke open under dynamic conditions and was not noticed by the operators.

Post maintenance testing for a previous maintenance activity failed to verify the valve would function under the expected operational conditions.

Although the inadequate post maintenance test of the valve had the potential to impact safety related equipment, the "E" EDG was not aligned to a safety-related bus at the time of the event, there was no effect on the operating'nits, and no damage to the EDG occurred.

In this case, the failure to provide adequate post maintenance testing for safety related equipment is considered a violation of minor significance and is being treated as a non-cited violation.

E8 Miscellaneous Engineering Issues E8.1 Followu of 0 en Items a.

Ins ection Sco e 92903 The inspectors reviewed the licensee response and corrective actions for open inspection items from prior NRC inspections.

b.

Observations and Findin s The following open items were reviewed during this inspection period:

Closed EA 50-387 388 96-087-01014:Failure to Correct Conditions Adverse to Quality This violation documented two instances where plant systems and components were not operated according to design specifications and licensing requirements.

Specifically, the licensee failed to ensure the Reactor Water Cleanup (RWCU)

ventilation area leak detection and isolation system could detect a 25 gallon per minute (gpm) leak in the RWCU system as outlined in an October 1992, NRC Safety Evaluation Report (SER)

~ Additionally, the licensee failed to restore seismic monitors to the locations described in the plant TS and FSAR.

Licensee corrective actions included repositioning the RWCU ventilation louvers to ensure the design leak rate could be detected and relocating the seismic monitors to the areas described in plant TS. To control future movements of ventilation dampers, procedure NDAP-QA-0408, "Station Requirements for Controlling HVAC Air Distribution/Control Equipment" was prepared to control and track changes to air conditioning and heating equipment.

The inspectors verified portions of the corrective actions and determined the response was adequate.

This violation is closed.

Closed EA 50-387 388 96-087-01024:Seismic Monitors Incorrectly Located This violation identified the licensee's failure to submit a special report to the NRC as required by the ACTION statement of plant TS 3.3.7.2.1, when plant staff identified seismic monitors were not installed in the locations required by TS.

Licensee corrective action included relocating the seismic monitors to the areas specified in the TS and submitting the required special report.

The inspectors verified portions of the corrective actions and determined the licensee's response was adequate.

This violation is closed.

Closed EA 50-387 388 96-087-03014:Failure to Update the Final Safety Analysis Report This violation was written to document the FSAR did not reflect the current plant configuration.

Specifically, Chapter 5 of the FSAR indicated the RWCU system ventilation differential temperature isolation system could detect and isolate a five gpm RWCU system pipe leak.

However, in April 1993, the licensee implemented a TS change that decreased the sensitivity of RWCU leak detection system from 5 to 25 gpm but did not update the FSAR to reflect the change.

Licensee corrective action included revising the FSAR to reflect the current sensitivity of the leak detection instruments.

To identify other potential deficiencies, a program to compare the FSAR with the as-built plant configuration was commenced.

The inspectors verified portions of the corrective actions and determined the licensee's immediate corrective actions were adequate.

This item is close '5 C.

Conclusions PP&L's corrective actions for several open items were reviewed.

The licensee's responses to the issues were considered adequate, and the long term corrective actions being implemented were viewed as reasonable.

IV. Plant Su ort S8 Miscellaneous Security and Safeguard Issues S8.1 Access Authorization and Fitness-for-Dut Pro ram Review ao Ins ection Sco e 81700 On December 16-17, 1997, a regional security specialist reviewed portions of the licensee's AA and FFD programs to verify implementation was in accordance with applicable regulatory requirements and security plan commitments.

The review included an evaluation of the AA and FFD procedures as implemented, and an examination of selected records.

b.

Observations and Findin s The inspector reviewed the AA records of an individual who was denied access based on information provided by the individual and a psychological'evaluation of the individual. The individual appealed the denial and in his appeal, asserted he was not provided the specific details upon which his denial was based.

The inspector's review determined the individual was permitted to review his file on September 12, 1997. At that time, the psychologist's handwritten notes of the psychological interview were not in the file. The psychologist's report of the interview was not completed and put into the file until September 16, 1996, and therefore, was not in the file at the time of the individual's review. Interviews with AA personnel disclosed that it had been the practice at the time the individual reviewed his file to remove psychological information prior to individuals being allowed to review their files.

Based on the concerns identified by the individual in his appeal and a licensee review of the program, the practice of removing psychological information prior to an individual reviewing his or her files has since been discontinued.

The licensee notified the individual that he would be permitted to review his complete file and would be reimbursed for costs incurred to return to the site for the review. At the time of the inspection, the individual had not yet returned to review his complete file.

The Code of Federal Regulation, 10 CFR 73.56 requires "...that employees be informed of the grounds for denial or revocation and allow the employee an opportunity to provide additional relevant information." The inspector determined that the removal of the psychological information, prior to the individual reviewing his file, did not allow the employee an opportunity to address the specific basis for the denial or the opportunity to provide additional relevant information. The licensee has discontinued the practice of removing psychological information prior

to an individual reviewing his or her files; no further action is deemed necessary on this issue., This failure constitutes a violation of minor significance and is being treated as a non-cited violation, consistent with Section IV of the NRC Enforcement Policy. (NCV 50-387,388/97-10-06)

The inspector also reviewed the AA records and the FFD records for an individual that had been terminated for a positive FFD test.

The inspector's review determined that the individual was selected for a random FFD test'in accordance with applicable procedures, employee notification was performed properly, the chain-of-custody process for the FFD sample was properly implemented and appropriate confidentially of the results was maintained.

The inspector did

'etermine that the Medical Review Officer (MRO) review of the FFD test results was not completed within 10 days of the initial presumptive positive screening test as required by 10 CFR 26.24(e).

However, the inspector noted that the MRO could not take any action or complete his review of the test results until he met with the individual and that the individual reported off sick and canceled a scheduled meeting with the MRO that would have allowed the MRO to meet the 10-day window.

The failure to meet the 10-day requirement specified in 10 CFR 26.24 was beyond the control of the licensee as a result of the prohibition of the MRO taking any action until meeting with the individual.

No further action is deemed necessary on this issue.

c.

Conclusion Implementation of the licensee'.s site AA and FFD programs were reviewed.

A failure to allo'w an individual to review the psychological information contained in his file is considered a violation of NRC regulations of minor significance and is being treated as a non-cited violation.

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 on January 21, 1998. The licensee acknowledged the findings presented.

The licensee also acknowledged that a re-evaluation of the standby liquid control accumulator problem identified on November 25, 1997, is in progress.

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

No proprietary information was identifie ITEMS OPENED, CLOSED, AND DISCUSSED

~Oened 50-388/97-10-01 URI Technical Specification 3.0.3 Entry to Support Surveillance Activities 50-387/97-1 0-64 Closed URI Standby Liquid Control Accumulators Found Depressurized e

50-387,388/97-1 0-02 NCV Senior Reactor Operator License Candidate Qualification 50-387,388/97-10-03 50-387,388/97-1 0-05 50-387,388/97-1 0-06 50-387/97-025-00 50-388/97-006-00 NCV Loss of Emergency Notification System Communications Capability NCV Alignment of Emergency Service Water to the

"E" Emergency Diesel Generator NCV Access Authorization and Fitness-for-Duty Program Review LER Loss of Both Trains of Standby Liquid Control LER Recirculation Discharge Valve Bonnet Vent Line Crack 50-388/97-007-00 50-387/93-1 9-01 50-387,388/96-087-01 014 50-387,388/96-087-01 024 50-387,388/96-087-0301 4 LER Entry into Technical Specification 3.0.3-Rod Block Monitor Operability Testing URI Unexpected Control Rod Movement EA Failure to Correct Conditions Adverse to Quality EA Seismic Monitors Incorrectly Located EA Failure to Update the Final Safety Analysis Report

LIST OF ACRONYMS USED AA ASO CFR CR CRDM DCV EDG ENS ESS ESW FFD FSAR GDC GE gpm HCU HPCI IFI ISEG kv kw LPRM LCO LER MCPR MOV MRO NAS NCV NOV NPO NRC NRR NSE NTG PCO pslg RBM RG RMCS RWCU SER SIL SLCS SRO SS Access Authorization AuxiliarySystems Operator Code of Federal Regulations Condition Report Control Rod Drive Mechanism Directional Control Valve Emergency Diesel Generator Emergency Notification Service Engineered Safeguard System Emergency Service Water Fitness-for-Duty Final Safety Analysis Report General Design Criteria General Electric gallons per minute Hydraulic Control Unit High Pressure Coolant Injection Inspection Follow-Up Item Independent Safety Engineering Group Kilovolts Kilowatts Local Power Range Monitor Limiting Condition for Operation Licensee Event Report Minimum Critical Power Ratio Motor Operated Valve Medical Review Officer Nuclear Assessment Services Non-Cited Violation Notice of Violation Nuclear Plant Operator Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Nuclear System Engineering Nuclear Training Department Plant Control Operator Pounds per Square Inch Gauge Rod Block Monitor Regulatory Guide Reactor Manual Control System Reactor Water Cleanup Safety Evaluation Report

[GE] Service Information Letter Standby Liquid Control System Senior Reactor Operator Shift Supervisor

SSES STA TSC TS US WA

Susquehanna Steam Electric Station Shift Technical Advisor Technical Support Center Technical Specification Unit Supervisor Work Authorization