IR 05000387/1996001
| ML17158B571 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 04/09/1996 |
| From: | Pasciak W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17158B569 | List: |
| References | |
| 50-387-96-01, 50-387-96-1, 50-388-96-01, 50-388-96-1, NUDOCS 9604160025 | |
| Download: ML17158B571 (22) | |
Text
UNITED STATES NUCLEAR REGULA'TORY COMMISSION
REGION I
Inspection Report Nos.
License Nos.
Licensee:
Facility Name:
Inspection At:
Inspection Conducted:
Inspectors:
50-387/96-01; 50-388/96-01 NPF-14; NPF-22 Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Susquehanna Steam Electric Station Salem Township, Pennsylvania February 6, 1996 March 18, 1996 M. Banerjee, Senior Resident Inspector, SSES B. McDermott, Resident Inspector, SSES T. Walker, Senior Operations Engineer, DRS Approved By:
ascia
,
ie Projects Branch No.
9604160025 960409 PDR ADQCK 05000387 G
EXECUTIVE SUNNARY Operations Susquehanna Inspection Reports 50-387/96-01; 50-388/96-01 February 6,
1996 - Harch 18, 1996 A performanced based inspection of the licensed operator requalification training program indicated that the program was of high quality and effectively evaluated operator ability to safely operate the plant.
The facility evaluators conducted thorough evaluations of crew and individual performance, and operators were held to high standards of performance on both the simulator and walk-through portions of the operating test.
Operator performance was strong on all parts of the examination with the exception of one of the two crews that demonstrated weak team work.
An observed radwaste release operation was performed by knowledgeable operators with good procedure compliance and effective supervision.
The licensee's practice of assigning Nuclear Plant Operators (NPOs) to operate the radwaste (RW) control room was acceptable based on their having met the basic training requirements for the required systems.
Oversight of RW releases by the Assistant Unit Supervisor, a licensed Senior Reactor Operator, provided an additional assurance of safety.
The inspector considered the licensee's failure to evaluate the need for implementing refresher training, prior to reassignment of NPOs to this task, an oversight.
A violation is issued involving the licensee's failure to appropriately identify repeated damper strokes that indicated a secondary containment isolation damper was not fully closing during a technical specification surveillance.
Maintenance/Surveillance A standby gas system logic modification installation was well executed and performed in accordance with the work plan.
Good oversight by guality Control (gC) personnel was noted during the work.
The scope of the post modification testing was appropriate and no problems with either the installation or modification design were identified.
Engineering/Technical Support The licensee identified that during a design basis accident condition, the water seals for the feedwater lines as described in the Final Safety Analysis Report (FSAR) was not achievable.
As the past as-found leakage results exceeded the criteria for maintaining off-site doses within the regulatory limit, the licensee reported the condition to the NRC.
Because of various modifications made to the valves that improved leakage, and acceptable test data from the last outages, the condition was considered acceptable for continued plant operation.
The licensee is reviewing various options to address the long term corrective action for this issu On February 29, 1996, during control rod drive rebuild activities the rebuild room's negative pressure was lost.
Dirty exhaust louvers and an almost closed exhaust damper was determined to be the root cause.
Initiation of a condition report to identify corrective actions to prevent recurrence and address generic implications was delayed.
Plant Support Health Physics support of the control rod drive rebuild activities was effective in identifying spread of contamination outside the room when its negative pressure was lost.
The contamination spread was limited to the second step-off-pad.
Safety Assessment/guality Verification The licensee's Inprocess Corrected Errors (ICE) program trending was a good initiative by gC, and the trends are consistent with the findings from the other corrective action processes (e.g., condition reports).
The trend reports have major potential benefit to the licensee because they capture the performance weaknesses at a much lower threshold of safety significance, thus allowing an opportunity to resolve issues before they impact plant performanc SUMMARY OF FACILITY ACTIVITIES Susquehanna Unit 1 Summary At the start of this report period Unit 1 was operating at lOOX power.
On March 9, power was reduced to 75X for main turbine valve testing, main steam isolation valve testing, control rod sequence exchange and control rod scram time testing.
The unit was maintained at 100M power throughout the remainder of the report period.
Susquehanna Unit 2 Summary Unit 2 began the report period at 100X power.
On the weekend of February 9,
power was reduced to 40X prima ily to replace reactor recirculation pump motor generator set brushes.
quarterly turbine valve testing, main steam isolation valve testing, and scram time testing were also completed.
The unit was returned to lOOX power on February
and was maintained at this power level for the remainder of the report period.
2.
PLANT OPERATIONS (71707, 92901, 93702)'.
Plant Operations Review Using inspection procedure 71707, the inspectors routinely observed the conduct of plant operations.
The licensee operated the plant safely, and according to station procedures and regulatory requirements.
The inspector observed plant housekeeping controls including control and storage of flammable material and other potential safety hazards.
In general, acceptable housekeeping practices were noted.
However, certain areas in the Radwaste building contained open chemical bags in carts, chemical bags on the floor, open chemical cans and material on the floor, and transient material without control tags.
The inspector concluded that housekeeping in certain areas of the Radwaste building needed improvement.
Additionally, posting and control of radiation, high radiation, and contamination areas when verified, were found to be appropriate.
2.2 Operator Requalification Program During the week of February 20, 1996, the NRC conducted a performance-based inspection of the Susquehanna Steam Electric Station (SSES)
licensed operator requalification training (LORT) program, using NRC Inspection Procedure 71001,
"Licensed Operator Requalification Program Evaluation."
The objective of the inspection was to verify that the LORT program ensures safe plant operation by evaluating how well individuals and crews have mastered the training objectives.
The inspection procedure from NRC Manual Chapter 2515 that the inspector used as guidance is parenthetically listed for each report sectio namic Simulator Examinations The inspector determined that the dynamic simulator scenarios were high quality evaluation tools of appropriate complexity to effectively evaluate crew and individual performance, However, the scenarios generally contained a
limited number of success paths and little variation in event severity.
For example, the success path in 22 of the 27 non-anticipated transient without scram (ATWS) scenarios was to rapidly depressurize the reactor vessel.
Only four of these scenarios contained momentary electrical failures that prevented the reactor from scramming automatically and/or manually.
None of these scenarios contained
"."-failure in which all the control rods did not insert which would vary the required operator actions.
These limitations could result in predictability, and decrease their effectiveness.
The facility evaluators performed thorough evaluations of both crew and individual performance.
They were critical of operator actions or inactions, and held the operators to consistently high performance standards.
Even though no critical tasks were missed by either of the crews, the evaluators determined that one of the crews demonstrated significant weaknesses in teamwork that would require additional training.
They also evaluated one of the SROs on the crew as unsatisfactory in directing shift operations.
The other crew performed well without any notable weaknesses, The inspector agreed with the facility evaluators'valuations.
The facility evaluators focused their evaluations of the crews and individuals on clearly defined critical tasks (CTs).
However, the written performance standards for the CTs were not always well defined.
Hany CTs relied on the judgement of the evaluators to determine satisfactory or unsatisfactory performance.
The evaluators indicated that any questionable performance related to CTs would be thoroughly discussed by the evaluation team and the results of the evaluation would be reviewed by training and operations management.
The inspector did not observe any inconsistencies in the facility evaluators'ssessments of CT performance.
Walk-Throu h Examinations The inspector determined that the job performance measures (JPHs)
were acceptable for evaluation of operator performance and that operators were held to high standards of performance on the walk-through examination.
The inspector noted minor problems with the identification of critical steps in the JPHs.
Some steps that were critical for performance of the task were not designated as critical, and the performance standards for some critical steps contained actions that were not critical to performance of the task.
Written Examinations The written examinations were judged to be effective evaluation tools with operationally oriented questions written at high cognitive levels.
However, the inspector noted that more attention was needed in the exam development and review process to ensure that individual questions and examinations effectively d',scriminate between safe and less than safe operators.
Some questions had distractors that were not plausible or problems that could allow
the operator to determine the correct answer by logic rather than knowledge or ability.
Additionally, the static simulator examinations contained some double jeopardy questions and some questions that provided the answers to other questions.
Sam le Plan Examination Develo ment The method used for examination sample plan development ensured that the examinations adequately sampled the items specified in 10 CFR 55.41, 55.43, and 55.45.
Emphasis was placed on evaluation of the tasks covered during the previous year such that a comprehensive evaluation would be administered over the two year requalification program.
The sample plans included all portions of the exam'ination; however, the dynamic simulator scenarios did not appear to be effectively incorporated into the plans.
The scenarios had been analyzed by the facility to determine the average number of emergency, procedural (off-normal, normal, alarm response, etc.)
and administrative tasks that the crew would be exposed to in a scenario.
These average values were used in developing sample plans to indicate the amount of coverage on the examination to ensure that appropriate emphasis was placed on the general categories of emergency, procedural, and administrative tasks for the overall examination.
However, the specific scenarios were not selected during development of the sample plans and no evaluation was performed to ensure that the selected scenarios did not result in duplication of specific tasks or overemphasis of a system or procedural topic.
No duplication or overemphasis was identified on the examination sample plan that was reviewed by the inspector.
The methodology used to categorize test items and training tasks on the sample plan did not appear to adequately reflect areas covered during requalification training and test item distribution on the examinations.
Hany tasks covered in training and numerous test items were assigned to procedural categories (emergency, operations, or administrative) rather than to systems categories.
This resulted in more emphasis on procedures and less emphasis on systems knowledge than was actually covered in training or tested on the examinations.
Additionally, the methodology for linking test items to tasks was inconsistently applied such that the sample plan did not accurately reflect the objective that each test item evaluated.
For example, there were two questions on one of the written examinations that tested interpretation and application of the power to flow map.
One of the questions was identified a"."
related to off-normal procedures.
The other question was identified as related to recirculation system controls.
Neither designation accurately reflected the relationship to the power to flow map, an administrative document.
These problems with the sample plan development methodology could lead to overemphasis or underemphasis of a category or specific task.
JPHs were not always selected on clear test objectives or for their benefit as evaluation tools.
For example, both of the in-plant JPHs administered to the SROs during the inspection only required the operator to install jumpers.
Even though the jumpers had different functions, the JPHs evaluated the same
ability to identify the correct location and installation of the jumper.
This provided a very limited evaluation of the SROs'bility to perform in-plant activities.
Hang ement Oversi ht The inspector concluded that training, operations, and plant management provided positive oversight of involvement in the requalification examination process.
All of the examination materials and examination results were reviewed by training management and several nuclear training supervisors were actively involved in the evaluations.
Operations management did not actively evaluate the operators, but provided an oversight role in monitoring the training department evaluations and providing guidance on expected performance standards when necessary.
The plant manager also provided oversight by observing simulator scenarios.
Conclusion The inspector concluded that the requalification examinations were of high quality and that they effectively evaluated operator ability to safely operate the plant.
The dynamic simulator scenarios were valid evaluation tools of appropriate complexity to effectively evaluate crew and individual performance.
The facility evaluators performed thorough evaluations of both crew and individual performance.
Operators were held to high standards of performance on both the simulator and walk-through portions of the operating test.
The written examinations were effective evaluation tools with operationally oriented questions written at high cognitive levels.
Operator performance was strong on all parts of the examination with the exception of one individual and one crew on the dynamic simulator examination.
The method used for examination sample plan development ensured that the examinations adequately sampled the items specified in 10 CFR 55; however, the dynamic simulator scenarios did not appear to be effectively incorporated into the plans.
2.2. 1 Review Of UFSAR Commitments A recent discovery of a licensee operating their facility in a manner contrary to the Updated Final Safety Analysis (UFSAR) description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters to the UFSAR de~criptions.
While performing the inspections discussed in this report, the inspectors reviewed the portions of the UFSAR that related to licensed operator training.
The inspectors verified that the UFSAR wording was consistent with the observed plant practices and procedures.
2.3 Liquid Radwaste Release On March 14, 1996 the inspector observed the radwaste (RW) control room operators release the contents of the evaporator distillate sample tank to the Susquehanna river through the cooling tower blowdown path, as allowed by the license.
The release was made following procedure OP-069-050, Rev 17, Release of Liquid Radwaste.
Two Auxiliary System Operators (ASOs) performed the
operation from the RW control room and locally at the RW building, with the Assistant Unit Supervisor (AUS) providing oversight and supervision.
The inspector observed good oversight by the AUS who independently verified some of the calculations in the release permit, good procedure compliance by knowledgeable and experienced operators, and good coordination and communication with the main control room.
The inspector noted that a source check was performed for the liquid radwaste (LRW) radiation monitor, expected radiation monitor response was established, and the actual response closely followed the expected response.
The LRW release evolution was quite detailed with many procedure steps requiring coordination with the main control room and the local operator.
Also, the inspector noted that the release permit required certain verification steps to be completed by shift supervision, and in this case the AUS provided very good involvement and oversight oF the release evolution.
The inspector concluded the radwaste release operation was per Formed by knowledgeable. operators with good procedure compliance and efFective supervision.
2.4 Nuclear Plant Operator (NPO) Training On February 5,
1996, the licensee began assigning NPOs to the RW control room with the responsibility of monitoring RW effluent releases.
On Harch 7, 1996, a question was raised within the licensee's organization regarding the qualification of NPOs for these tasks since, in most cases, they have not had this responsibility for a number of years.
The RW control room and areas such as the circulating water pump house had previously been assigned to the junior non-licensed operators known as ASOs.
As an interim measure Operations Hanagement discontinued assignment of NPOs to ASO tasks pending a review of their qualifications.
The inspector independently reviewed the licensee's operations instruction OI-AD-044, "Return to On-shift Duty/Promotion (Operator gualification)" and training records associated with nuclear training procedure NTP-(A-32, I,
"ASO/NPO Operator Training And gualification Program" to determine if the training requirements had been met.
A prerequisite for the initial NPO qualification described in NTP-(A-32. 1, Revision 5, is a verification that all initial ASO qualification requirements have been met.
Training records show that,NPOs have either completed this training or were qualified prior to development of the ASO position.
The non-licensed operator refresher training program covers both NPOs and ASOs, providing the same review of systems and procedures over a three year period.
The required in-plant JPHs are different for the two groups of operators, however, in general the NPOs also complete ASO JPHs.
The inspector's review of RW release permits and training records found that the NPOs who participated in releases between February 5,
1996, and Harch 7, 1996, had received the classroom training, quizzes and in-plant training for RW releases, with one exception.
One of the four NPOs did not complete all portions of the ASO in-plant training related to RW release The requirements for return to shift duties contained in OI-AD-044, Revision 13, address situations where an operator has not been assigned responsibility for any area for a minimum of one 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shift per 6 week training cycle.
However, this procedure does not require familiarization when operators are assigned to a new area.
The Operations Manager indicated that the NPOs are considered qualified to perform the RW control room duties but acknowledged that refamiliarization training for the NPOs would improve the operator's ability to execute their responsibilities.
A January 23, 1996, Non-Licensed Operator Continuing Training Subcommittee report (PLIS 44560)
recommended that
"Because many NPOs may be performing AS'asks, the Subcommittee recommends that NPOs on-shift complete portions of the ASO gualification Card on-shift utilizing the AUS or incumbents as trainers/evaluators."
Although not required by the licensee's training program or procedures, the need for refamiliarization training had been recognized by the licensee but was not acted upon prior to assigning NPOs to ASO tasks.
The licensee stated that the need for refamiliarization training was not evaluated when the decision was made to reassign the NPOs.
The inspector concluded that the licensee's practice of assigning the NPOs to operate the RW control room was acceptable based on their having met the basic training requirements for those systems as described in NTP-(A-32. 1.
Further, the oversight of RW releases by the Assistant Unit Supervisor provides an additional assurance of safety.
The inspector considered the licensee's failure to evaluate the need for implementing refresher training, prior to reassignment of NPOs, was an oversight.
2.5 Secondary Containment Isolation Damper Surveillance On February 15, 1996, during surveillance S0-034-001, secondary containment Zone III supply isolation damper HD-27564A showed dual indication when operators attempted to confirm the damper's ability to close within the
seconds required by Technical Specifications.
Dual indication (i.e.,
amber and red lights both illuminated) is representative of a mid-stroke position for the damper.
Operators initially reported that during subsequent strokes, the full closed indication was observed and that the damper stroke time was within the surveillance acceptance criteria.
Operators also initiated a work authorization for investigation of what they perceived to be an intermittent indication problem.
On February 16, during a maintenance investigation of the damper indication problem, workers found that the damper was not fully closing.
The damper was declared inoperable and operators entered the action statement for Technical Specification (TS) 3.6.5.2.
In discussions with the Shift Supervisor, Shift Technical Advisor, and System Engineer, the inspector questioned the basis for completion of the surveillance as satisfactory on February 15.
The licensee's position that there had been an intermittent position indication problem was based on the damper showing closed indication during subsequent strokes, the stroke time being within acceptance criteria, the operators past experience with limit switches, and the variation of building differential pressure accompanying the strok Further investigation by the Shift Supervisor revealed that the damper had been stroked twice with dual indication and that on the third attempt, a non-licensed operator had pushed on it. It was after the "hands-on" actions of the non-licensed operator that the damper showed full closed.
Subsequent strokes provided good control room indication.
This new information was documented in a Condition Report (CR)
on February 16, 1996.
During investigation of the CR, PP&L identified that dual indication had been observed for damper HD-27564A after an inadvertent Zone III isolation on October 10, 1995.
An indication problem was suspected and a work authorization was initiated to check the position indication for proper operation.
However, when the switches checked out satisfactorily, the licensee failed to question whether this meant the damper had failed to stroke full closed.
Damper HD-27564A was stroked three times between October 10, 1995 and Harch 15, 1996 with no problems identified.
The inspector noted that at the time of this event, neither the surveillance procedure nor administrative procedures provide explicit guidance on the expected operator response for a device that fails to meet acceptance criteria on the first attempt.
The inspector concluded that on February 15, 1996, the licensee failed to appropriately identify repeated damper strokes that indicated secondary containment isolation damper HD-27564A was not functioning properly.
The failure to promptly identify this condition resulted in the degraded damper being returned to service, after which it failed to stroke closed on a manual signal.
The inspector considered the October 1995 work authorization a prior opportunity to identify the damper problem.
The failure to identify
"conditions that could affect the ability of the station to operate with'in the conditions of the operating license" is a violation of PP&L's administrative procedure NDAP-gA-0702, "Condition Reports,"
Revision 1,
and is also a
violation of 10 CFR 50, Appendix 8, Criterion XVI, for corrective action.
(VIO 50-388/96-01-01)
2.6 Open Item Followup (92901)
(Closed)
URI 50-387/94-25-02 Feedwater Transient On November 30, 1994 a feedwater transient occurred, while Unit 1 was operating at 100X power, when the control room operators placed the 125V DC battery on equalize.
This was in response to a battery monitor alarm, and followed recommendations from the maintenance organization on previous similar Unit 2 alarms.
Higher equalize voltage caused a zener diode to short out, and a consequential loss of a feed flow channel input to the feedwater level control system started a feedwater transient.
This item was left open pending the licensee's review of the operation and maintenance interface to address the informality of the process used to respond to the battery monitor alarm.
The licensee corrected the design error in Unit 1 by replacing the zener diodes with conventional ones.
The licensee also evaluated the other circuits powered by 125V DC, and the General Electric (GE) de"igned system circuits powered by AC sources for any misapplication of zener diodes.
The licensee
did not identify any other misapplication.
The feedwater level control system was reviewed for setpoints and trip margin adequacy.
A review of the battery monitor setpoint resulted in a setpoint change to avoid unnecessary alarms.
The revised alarm response procedures now require operations to contact electrical maintenance to investigate the alarm.
The plant simulator model was reviewed and no change was deemed necessary.
The inspector reviewed the licensee's corrective actions, and noted that the battery monitor alarm response procedure now formalized the operations and maintenance interface.
Also, with the new setpoints, the frequency of battery monitor alarm conditions are greatly reduced.
The inspector concluded that the licensee's corrective actions were adequate.
This item is closed.
(Closed)
URI 50-387,388/93-06-01 - ATWS Strategy Differences This item was related to the SSES Emergency Procedure Guidelines (EPGs)
ATWS strategy which differed from the Boiling Water Reactor Owners Group (BWROG)
EPGs.
The SSES EPGs contained four significant deviations from the ATWS strategy defined in the BWROG EPGs.
The most significant of these deviations, the level control strategy, has been addressed generically by the BWROG and the NRC staff.
The BWROG submitted a revision to the BWROG EPGs, Rev. 4, which implemented the SSES EPG strategy for level control during an ATWS.
The NRC staff review of the revision conclude~ that the revised strategy would reduce the uncertainties related to achieving reactor shutdown without depressurization and would reduce overall core damage risk.
The NRC staff informed PP&L that they approved the SSES deviation from the BWROG EPGs at a
meeting on June 13, 1995.
Regional inspector review of the safety evaluations for the remaining three deviations did not identify any concerns with PP&L's analysis methods.
In discussions with the NRC Office of Nuclear Reactor Regulation (NRR), the project manager indicated that the NRR staff had determined that the remaining three deviations did not have generic implications, and the NRC staff plans no further plant-specific review on these issues.
This item is closed based on NRC staff approval of the PP&L ATWS level control strategy and apparently sound analysis methods related to ATWS strategy..
(Closed)
Unresolved Item 50-387,388/94-22-01 Use Of Operators In EP Exercise This item was related to the use of control room operators as referees during emergency response exercises.
The inspectors were concerned that this practice did not meet
CFR 50, Appendix E requirements for training and exercising of personnel responsible for accident assessment, including control room shift personnel.
During this inspection, the nuclear training supervisor indicated that control room operators are no longer used as referees during emergency response exercises.
Discussions with the training supervisor indicated that in addition to participation in emergency response exercises, periodic "mini-drills" are run on each shift of licensed operators during requalification training.
During the "mini-drills," the Technical Support Center (TSC) is manned and operators practice their skills in responding to the accident and communicating with the TSC.
Based on these discussions, the
inspector concluded that the emergency response training provided to the operators meets the intent of 10 CFR 50, Appendix E.
This item is closed.
(Closed)
VIO 50-388/93-01-01 Reactor Water Surveillance LCO Tracking During an 18 month calibration of the reactor water level low-low-low trip channels, operators did not make a log entry into the applicable TS limiting condition for operation (LCO).
The surveillance procedure (SI-280-303)
suggested, but did not require, the work group to monitor and control out-of-service times for the individual trip channels.
During review of a completed surveillance, the inspector found no record of the out-of-service times ror the reactor water level trip channels during the 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> the surveillance paperwork was open.
A violation was issued citing 10 CFR 50, Appendix B,.
Criterion V, based on the inspector's conclusion that the procedure was inadequate.
As corrective action the licensee revised the administrative procedure for tracking LCOs to allow documentation of the out-of-service time on the surveillance procedure cover sheet.
The surveillance cover sheet,
"Part V.
Remarks,"
was revised to include verification of whether the TS surveillance allowed performance time applies and a record of the start and stop time for the individual trip channels.
The inspector reviewed the procedure changes and a sample of completed surveillances.
No problems were identified with tracking of allowed outage times and the inspector concluded that the licensee's corrective actions adequately addressed the violation.
Based on the corrective actions taken this violation is closed.
3.
MAINTENANCE AND SURVEILLANCE (62703, 61726, 92902)
3. 1 Maintenance Observations The inspectors observed portions of the following work activities:
WA P52865 Annual Swing Bus MG Set PM, on February 23, 1996 WA C60149 SBGT Logic Modification Installation, February 28, 1996.
The inspector noted that the limiting conditions for operation were met while components or systems were removed from service, work was conducted following the approved work package, required administrative approvals were obtained prior to initiating the work, safety permits were appropriately hung, technicians were experienced and knowledgeable, radiological controls were implemented, and system engineers were monitoring the job when required.
Based on this observation, the inspectors concluded that the jobs were completed appropriately, with due concern for plant safety and procedures.
3.1.1 Installation of SHGT System Logic Modification On February 28, 1996 the licensee installed a logic modification for the
'A'rain of the standby gas treatment system.
The inspector observed portions of the field installation, wiring checks, and post modification testing.
The
design of the logic modification is discussed in NRC Inspection Report 50-387,388/96-03.
The installation was well executed and performed in accordance with the work plan.
Cold verification of the wiring changes and multiple checks of the logic timer after installation provided an additional level of assurance that the installation was as designed.
Good oversight by Quality Control personnel was noted during the work.
The scope of the post modification testing was appropriate and no problems with either the installation or modification design were identified.
The inspector concluded that the modification installation was well executed and appropriately verified.
3.2 Surveillance Observations The inspector observed and/or reviewed the following surveillance tests to determine whether the following criteria, if applicable to the specific test, were met:
the test conformed to TS requirements; administrative approvals and tagouts were obtained before initiating the surveillance; testing was accomplished by qualified personnel in accordance with an approved procedure; test instrumentation was calibrated; Limiting Conditions for Operations were met; test data were accurate and complete; removal and restoration of the affected components were properly accomplished; test results were appropriately communicated with regard to TS and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.
Surveillance observations and/or reviews included:
S0-250-002 Unit 2 RCIC Quarterly Flow Verification, February 29, 1996.
SO-249-002 Unit 2 'B'HR Quarterly Flow Verification, February 16, 1996.
SO-235-005 Unit 2 RHR Fuel Pool Cooling Valve Test, March 12, 1996.
Based on observation of selected portions of the above surveillances, the inspector concluded that they were completed with appropriate consideration for safe plant operation and administrative control.
4.
ENGINEERING (71707, 37551, 92903)
4. 1 Feedwater Loop Seal On January 15, 1996, the licensee initiated a
CR after they identified that the water seal for the feedwater lines as described in the FSAR was not achievable, thus creating a potential bypass leakage path.
Further licensee review indicated that past feedwater penetration high LLRT leakage results, obtained during outages, might have put the plant in a degraded condition outside the design basis.
Hence, the licensee reported the finding to the NRC on March 6, 1996 as a
4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> non-emergency repor FSAR section 6.2.3.2.3, 1 stated that a water seal was expected to remain for a considerable length of time following an accident until the operator remotely isolated the feedwater motor operated valve.
The bypass leakage through the feedwater lines would then be eliminated because of the water seal that would exist in the piping between the inboard check valve and the remote manual motor operated valve.
Also, an additional water seal would be maintained by the feedwater system outside the containment.
The high pressure coolant injection (HPCI)
and reactor core isolation cooling (RCIC)
pump discharges are water sealed at the feedwater lines.
The FSAR also indicates that a valve maintenance and testing program will assure that bypass leakage through the feedwater line is restricted such that the offsite dose and the control room dose are maintained within regulatory limits.
In a letter dated December 18, 1984 to the NRC, PPKL stated that a
conservative water volume calculation resulted in a minimum 200 day water seal, based on the piping geometry back to the feedwater pump discharge check valves.
Hence, it was PP&L's position that zero leakage should be attributed to the feedwater system pathway.
f During a design basis Loss of Coolant Accident (LOCA) with loss of offsite power, the water in the feedwater lines will be flashing to steam resulting in water loss.
Also the condensate and condensate transfer system will be unavailable to maintain water in the feedwater lines, or the HPCI and RCIC keepfill lines until offsite power is restored and the systems are returned to service.
During a review of the HPCI injection valve pressure locking concerns, the licensee discovered that the FSAR was inconsistent with the design basis calculation that only justified a water seal at the feedwater pump discharge check valves rather than within the containment boundary.
A further review concluded that the feedpump bypass line was not properly evaluated.
As a
result of this, the water seal at the feedpump discharge check valves and feedpump bypass line will be exhausted in less than eight hours.
In addition to the HPCI and RCIC keepfill lines, the water seal at the reactor water cleanup line connection to the feedwater containment penetration would also be lost.
The licensee's assessment of the keepfill line indicated that the piping would remain intact and the suction head of water from the condensate storage tank will keep the line full in the turbine building thus effectively preventing -,.>
bypass leakage through this line.
The total bypass leakage for each unit must be less than 5 scfh (2360 sccm)
assumed in the offsite dose analysis for a large break LOCA.
The plant TS limit the leakage through each of the main steam line drain isolation valves to 1.2 scfh.
However, the TS does not address the contributions from the feedwater lines.
The licensee justified that with the LLRT leak rates measured for each penetration during the last outages, the total as-found and as-left bypass leakage values for both units were well below 5 scf The licensee further contended that although a specific procedure to replenish the water seal in the feedwater penetration does not exist, such a procedure could easily be developed by the engineering personnel to replenish water within a few days of the accident.
After offsite power is restored, expected within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the condensate system will be available to fill the feedwater lines.
The emergency plan procedure for technical support coordinator was revised to require such a procedure be developed and implemented.
The licensee is reviewing possible engineering modifications to ensure a water seal, and is also completing a sensitivity study of feedwater penetration bypass leakage to offsite dose values.
The inspector reviewed the past LLRT results for the Units I and 2 feedwater penetrations.
Although the last as-found leakages for the feedwater penetration isolation valves were within the acceptance criteria, the previous history does not indicate consistent performance.
The inspector noted leakage values improved after soft seat replacement of the feedwater check valves, rework of the HPCI injection valve, and installation of a second valve on some connected te'st line.
The inspector concluded that the licensee's operability evaluation, short term corrective action, and plan for long term assessment or a modification were adequate.
This item will remain open until the completion of licensee's long term corrective actions.
(IFI 50-387; 388/96-01-02)
4.2 GRDCE Rebuild Room Pressurization The control rod drive module (CRDH) rebuild room is a potentially contaminated area in the reactor building that is maintained at a negative pressure compared to the adjacent areas to ensure air flow is into the room and not out of the room.
On February 29, 1996, during CRDH rebuild activities, the licensee identified contamination outside the room.
The licensee determined that air flow was in the opposite direction through the bottom of the door.
The licensee's survey confirmed that contamination was contained inside the tent covered area between the two step-off-pads (SOPs).
The adjacent clean area in the reactor building was not contaminated.
All work inside the room was stopped.
The nuclear system engineer (NSE)
was contacted to evaluate the situation.
After taking measurements with hand held instruments, the NSE determined that the exhaust air f<ow from the room was lower than required.
One of the two exhaust grills into the room was dirty and had its louver blade damper substantially closed.
The grills were removed, cleaned, and the damper opened.
The exhaust flow returned to normal.
The NSE believes that vi'ation induced by a crane monorail that shared the same support as the grill could have made the damper change position.
The inspector interviewed the Health Physics (HP) technicians supporting CRDH rebuild activities about the spread of contamination outside the rebuild room.
The spread was limited to the SOP area and was of low level.
The inspector noted that the SSES FSAR, Section 9.4.2. 1. 1 states that the reactor building ventilation system was designed to maintain air flow from areas of lesser contamination to areas of greater potential contamination.
In this case this design basis requirement was not met when air flow was found to be from the CRDH room (higher potential contamination)
into the adjacent areas
of the reactor building (lower contamination level).
FSAR Section 9.4.2. 1.3 states that operational degradation of ventilation system components can be detected by direct equipment status indication or can be concluded based on abnormal temperature, differential pressure, alarms and indication, and corrective actions can then be taken.
FSAR Section 9.4.2. 1.5 indicates that there is local and control room alarm capability on high or low pressure in the reactor building zones or one of the potentially contaminated areas.
The inspector noted that no,such indication or alarm capability existed for the CRDN rebuild room such that corrective actions could have been taken before contamination was spread outside the room.
The actual safety impact of the event was minimal as spread of contamination was limited.
Potential safety significance of the event is small as the reactor building zones were maintained at a negative pressure.
During a
design basis accident the standby gas treatment system would be available to maintain the reactor building at a negative pressure and provide for a filtered ventilation path to limit offsite doses.
The inspector also noted that the licensee did not have any preventive maintenance on the exhaust damper, indication of damper position, or any established method of monitoring negative pressure in the room.
The inspector discussed these concerns with the Nuclear System Engineer and questioned if other similar situations might exist in any other rooms of higher potential contamination in the reactor building.
The licensee initiated a condition report (96-259)
on March 12, 1996, to evaluate and document the root cause, needed corrective actions to prevent recurrence, and generic implications.
The inspector concluded that the licensee's HP controls were effective, immediate'orrective actions were appropriate, but initiation of a review for generic impact and longer term corrective action to ensure system design function was maintained was delayed.
5.
PLANT SUPPORT (71750, 71707, 92904)
5.1 Radiological and Chemistry Controls During routine tours of both units, the inspectors observed the implementation of selected portions of PP&L's radiological controls program during the conduct of maintenance and.surveillance activities.
During these general observations, the inspectors checked utilization and compliance with radiological work permits (RWPs), descriptions of radiological conditions, and personnel adherence to RWP requirements.
No deficiencies were identified during these general observations.
During the report period several condition reports were written by the licensee that identified high radiation area posting deficiencies, contaminated material (mostly small hand held tools)
found outside the radiologically controlled area, and a potentially contaminated tanker truck that was returned to the vendor without appropriate survey.
At the end of the inspection period, the licensee's investigation and implementation of corrective actions, and NRC inspection of these issues were ongoing.
The
results of the NRC inspection will be presented in a separate inspection report.
5.2 Security PP&L's implementation of the physical security program was verified on a
periodic basis, including the adequacy of staffing, entry control, alarm stations, and physical boundaries.
These inspection activities were conducted in accordance with NRC inspection procedure 71707.
There were no problems identified during periodic observation of access and egress controls this report period.
6.
SAFETY ASSESSMENT/QUALITY VERIFICATION (90700, 90712)
6. 1 Self Assessment Inprocess Corrected Errors (ICE) Program The licensee's procedure NQAP-QA-300, QC Inspection Program, allows for and requires documentation of the ICE.
ICE reports document QC inspector identified low level deficiencies that are corrected on the spot after identification, and are below the threshold of the condition report process.
The QC group in Nuclear Assessment Services maintains an ICE database.
Rollup reports identifying the problem areas and opportunities for improvement are provided to the functional units based on periodic review of ICEs generated against that unit.
QC reviews the database for developing trends, and the trends are often identified in rollup reports or periodic ICE review reports.
Review reports are distributed to the functional unit's first and second line supervisors and to the functional unit managers (FUMs) based on the significance and extent of the report.
For example, the ICE review report for July and August was distributed to the maintenance and planning foreman level, whereas the ICE review report for the Unit 2 7th refueling outage was additionally distributed to the FUMs.
The inspector reviewed several ICE rollup and review reports.
The inspector noted that consistent with a recently completed Independent Safety Evaluation System (ISES) surveillance report (8-95), the ICE review report for the Unit 2 7th refueling outage identified a negative trend in industrial safety performance.
This ICE report also identified the same overall number of procedure related ICEs generated during the last Unit 1 and Unit 2 outages in 1995.
An ICE report for a two year period through June 26, 1995, included 162 procedure related problems out of a total of 947 problems.
The inspector also noted that condition reports were being generated on ICE trends to address the root causes and corrective actions.
The inspector concluded the ICE trending was a good initiative by QC, and the trends are consistent with the findings from the other corrective action processes (e.g.,
condition reports).
The trend reports have major potential benefit to the licensee because they capture the same performance weaknesses at a much lower threshold of safety significance, thus allowing an opportunity to resolve issues before they impact plant performanc.
MANAGEMENT AND EXIT MEETINGS (71707)
7.1 Resident Exit and Periodic Neetings The inspector discussed the findings of this inspection with PP&L station management throughout the inspection period to ensure timely communication of emerging concerns.
At the conclusion of the reporting period, the resident inspection staff conducted an exit meeting summarizing the preliminary findings of this inspection.
Based on NRC Region I review of this report and discussions held with licensee representatives, it was determined that this report does not contain '.nformation subject to
CFR 2.790 restrictions.
7.2 Exit Neeting A separate exit meeting was conducted on February 23, 1996, to discuss the licensed operator requalification program inspection scope and findings.
A partial list of PP&L attendees at the exit meeting is attached.
7.3 Other NRC Activities A radiation protection inspection was started on Harch 18, 1996.
The results of this inspection will be reported in a separate inspection repor ATTACHMENT I PARTIAL LIST OF PP&L ATTENDEES AT THE NRC EXIT MEETINGS H.
G. Stanley, VP - Nuclear Operations G. Kuczynski, Plant Manager K. Chambliss, Manager - Operations A. Fitch, Nuclear Training Supervisor M. Simpson, Manager - Nuclear Modifications G. Miller, Manager Nuclear Plant Services D. Roth, System Engineering R. Prego, Supervisor, Surveillance Services M. Friedlander, Maintenance J. Fritzen, Supervisor - Health Physics T. Dalpiaz, Manager - Outages