IR 05000387/1989081
| ML17156B490 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 11/14/1989 |
| From: | Kelly G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17156B489 | List: |
| References | |
| 50-387-89-81, 50-388-89-81, GL-89-20, NUDOCS 8911290115 | |
| Download: ML17156B490 (33) | |
Text
Report Nos
~
Docket Nos.
License Nos.
Licensee; U.S.
NUCLEAR REGULATORY COMMISSION
REGION I
50-387/89"81; 50-388/89-81 50-387/ 50-388 NPF-14; NPF-22
'ennsylvania Power and Light Company 2 North Ninth Street Al 1 entown, Penn syl vania 18101 Facility Name:
Susquehanna Steam Electric Station Inspection At:
Salem Township, Pennsylvania Inspection Conducted:
October 16-20, 1989 Team Leader:
Inspectors:
J.
Lyash, Senior Resident Inspector, Peach Bottom L. Scholl, Resident Inspector, Limerick E. Conner, Project Engineer P.
Kauffman, Project Engineer Approved by::
G.
K lly, Chief, Te hnical Support Division of Reacto Projects ate
~AI I
Results:
A limited scope team inspection was'onducted to evaluate the degree to which probabilistic risk assessment has been utilized by the licensee to improve plant hardware, procedures and work practices.
The team assessed the licensee's plant reliability analysis initiatives, and their resolution of the attached previous NRC concerns (Section 6').
Both corporate and site management appear committed to development of a quality risk management program.
Resources and priority have been appropriately assigned, and tangible benefits have resulted.
A reliability centered maintenance program initiative is well underway and is intended to contribute to a decrease in the number of plant transients (Section 4.0) Also notable are unique risk strategies for ATWS, SDC operational guidance, and the adoption of the TEAM Manual by operating staff (Section 3').
89ii2901i5 89iiib
~APDR,..ADOC}C 05000387
The licensee's program for evaluation and control of temporary modifications (bypasses)
appeared weak.
Procedural provisions for periodic review were not consistently implemented, and formal programmatic controls were not in place to ensure updating of affected drawings and procedures (Section 5. 1, Unresolved Item 89-81-01).
Also controls for transient maintenance equipment in the plant, and for control of temporary scaffolding require additional attention.
(Section 5.2, Unresolved Item 89-81-02).
Finally, the team concluded that the slow responsiveness of the modification process contributed to a large number of outstanding temporary modifications, and to delays in implementing risk reducing modifications such as for the ESW system return valves and low pressure ECCS permissives (Section 3.5).
SUMMARY
~
~
~
4.0 PLANT RELIABILITYANALYSIS INITIATIVES...................
5.0 GENERAL PLANT OBSERVATIONS 5.1 BYPASS CONTROL PROGRAM REVIEW.............................
5.2 SCAFFOLDING AND TRANSIENT EQUIPMENT CONTROL PROGRAM REVIEW
~
~
~
~
~
~
~
~
5.3 STANDBY LIQUID CONTROL SYSTEM INSPECTION..................
5.4 NONCONFORMANCE REPORT REVIEW
6.0 REVIEW OF OPEN NRC FINDINGS...................................
DETAILS 1. 0 SUMMARY AND CONCLUSIONS The licensee has established the foundation of an effective risk management program.
Significant analytical work has been completed and beneficial changes to plant design and operation have been identified.
Several of these changes have been implemented while many remain yet to be done.
The licensee's reliability based maintenance program has the potential to reduce plant transients.
Care should be taken, however, to ensure that appropriate standby safety system maintenance priorities are maintained.
Inspections in other areas indicated that the licensee has effective programs in place.
In some instances, however, inconsistent implementation or the need for program enhancements were noted.
The licensee's scaffolding/equipment control and bypass control programs are examples.
A final exit interview was conducted an October 20 with the Station Superintendent.
2.0 INTRODUCTION AND SCOPE During the week of October 16, 1989 Region I conducted a limited scope team inspect>on at Pennsylvania Power 5 Light (PP5L)
corporate engineering offices and at the Susquehanna site.
The team consisted of four inspectors and was intended to address the three areas of interest listed below.
2.1 RISK ASSESSMENT APPLICATIONS REVIEW Individual licensees and industry groups have been increasingly involved in risk assessment activities.
NRC interest in ensuring that thorough assessments are performed and that results are understood and 'factored into the licensee decision making process is substantial, as evidenced by the issuance of Generic Letter (GL) 89-20.
PP5L has completed significant risk analyses for the Susque-hanna station.
NRC technical review of the methodology employed by the licensee will be conducted as part of the GL 89-20 follow-up program.
The purpose of this inspection effort was to review the effectiveness of licensee efforts utilizing the analysis results, understand the nature of risk significant contributors and initiate measures to mitigate these risks.
The inspectors attempted to measure the degree to which the licensee has integrated risk assessment-derived insights into plant design and operation.
This was accom-plished through review of risk assessment results, implemented modifications, conceptual designs, operating and test procedures, work control procedures and practices, and through discussion with
2.2 licensee staff.
The team did not evaluate the technical adequacy of the licensee's risk analysis.
Implementation of risk management programs and efforts to identify and address factors contributing to beyond design basis accidents are not presently required by the NRC.
However, review of licensee initiatives in this area provides infor-mation regarding the committment and safety perspective of licensee management.
RELIABILITYCENTERED MAINTENANCE PROGRAM INITIATIVES 2.3 The licensee initiated a plant reliability study designed to identify components whose failure could result in forced power reductions or plant trips.
While this effort primarily focuses on balance-of-plant equipment, some safety-related equipment is included.
The goal. of the program is to increase overall plant availability by enhancing the maintenance and test program applied to critical equipment.
While plant availability is not directly related to plant safety, any reduction in the number and severity of plant transients represents a reduction in risk.
As discussed in Section 2. 1 above, this program is viewed as a licensee initiative, not a regulatory requirement.
GENERAL PLANT OBSERVATION AND NRC OPEN ITEM REVIEW The team also toured the facility to evaluate general plant'ondition and to observe conduct of routine activities.
Substantial effort was dedicated to review of licensee corrective actions in response to previous NRC concerns.
These inspections, when integrated, provide the team with a general sense of the
.licensee's control of field activities, and of the thoroughness of technical evaluations.
3.0 RISK ASSESSMENT APPLICATIONS REVIEW 3.1 HISTORY OF RISK ASSESSMENT ACTIVITIES AT SUS UEHANNA PAL began involvement with probabilistic risk assessment (PRA)
in 1980 in cooperation with NUS Corporation.
This effort concluded during 1985 with issuance of Revision 0 of the Susquehanna PRA.
Work in support of Revision 1 of the PRA continued during 1985.
Also in early 1985 PPCL became a pilot plant for application of the Individual Plant Evaluation (IPE) methodology.
The Susquehanna IPE was conducted with in-house personnel, resulting in development of significant retained expertise.
The present status of the risk assessment program at PPLL reflects the resources dedicated to these two efforts.
The licensee is presently working to refine the IPE to include additional internal events such as flood and fire, in preparation for a planned early submittal to the NR.2 CORPORATE SUPPORT FOR CONTINUING RISK ASSESSMENT ACTIVITIES Licensee senior management commitment to the development, maintenance and application of the risk assessment program is evident.
The licensee established a Systems Engineering Group within the corporate engineering organization responsible for the ongoing IPE effort.
The Systems Engineering Group consists of 3 subgroups.
The Safety and Licensing Analysis subgroup bears primary responsibility for coor-dination of PRA-related activities.
The remaining 2 subgroups supply additional technical expertise in support of the PRA program.
Current Systems Engineering Group staffing includes,16 personnel with an additional 2 positions allocated but not filled.
While the Group performs a variety of analytical duties not directly associated with PRA, these duties tend to complement the knowledge base needed for PRA-related efforts.
3.3 As part of the licensee's Managing For Excellence Program, the Nuclear Department develops and
- mplements a five year plan designa-ting the major projects that must be completed to support continued performance improvement.
Content of the plan is approved by the Plant Superintendent, the Nuclear Services Manager and the Nuclear Plant Engineering Manager.
Five year plan goals include: I) reducing core and containment damage probability; 2) achieving safety system availability higher then levels assumed in the IPE; and 3) limiting challenges to safety systems.
guantitative goals for safety system challenges have been established at less than or equal to I unplanned scram per unit per 2 years, 6 engineered safety feature actuations per unit per year and zero unplanned safety system actuations.
Inclusion of overall goals and specific actions in the five year plan are intended to reduce the transient arrival rate, increase safety system availability and reduce plant damage probabilities, and these goals reflect evidence of management commitment.
MAINTENANCE OF INDIVIDUALPLANT EVALUATION VALIDITY The licensee has established an availability monitoring program for 14 safety significant systems.
The program is implemented by the corporate Systems Engineering Group and is described in a work instruction presently in dr aft.
Availability data on systems from initial criticality through the present is maintained and compared against industry goals and values assumed in the IPE.
A breakdown of unavailable hours due to preventive maintenance, corrective maintenance, modifications and surveillance testing is also included.
The onsite technical staff reviews the data to determine if corrective action is needed.
-quarterly management performance indicator reports include comparison of actual and IPE assumed availabi lities.
Actual avai 1-abilities are generally higher than those used in the IPE.
Systems displaying lower average availability (albeit for limited time periods)
were not significantly less than the IPE assumptions, and discussions with the onsite technical staff indicated that the causes were under-stood and being addresse The licensee has not yet developed formal programmatic controls to ensure that the IPE is updated to accurately reflect plant hardware and procedure modifications.
The need for these controls, however, has been recognized.
An informal process for IPE update has been established and appears to be functioning adequately.
The team did note that several strategies identified as effective in coping with severe accidents had been incorporated into the IPE, but had not been translated into Emergency Operating Procedure revisions.
In these instances, the capabilities assumed in the IPE were not actually in place.
For example, procedures establishing the use of the reactor water cleanup (RWCU) system as an alternate method for depressurizing the reactor are not presently in effect, and operator training has not been conducted.
The draft procedure for use of RWCU in this mode incorporated the instructions into the system operating procedure.
Location of this abnormal system alignment in the normal operating procedure does not seem appropriate.
The licensee clearly recognized the inconsistency between the plant as portrayed in the IPE versus its actual configuration, and was actively pursuing development of appropriate procedures and training.
Revision of the IPE is planned in support of the licensee's'esponse to Generic Letter 89-20.
3.4
~LICENSEE APPROACH TO APPLICATION OF IPE-RELATED INSIGHTS As a primary goal of the risk management program, the licensee has pursued the reduction of risk from accident sequences having high cal.culated frequencies.
Because complete confidence in the accuracy of the assumptions made in the IPE and in its quantitative results can practically never be achieved, the licensee has developed a
"defense-in depth" approach to application of the IPE results.
This approach requires that all accident sequences, even those having low calculated frequencies, must have defense-in-depth in the form of both equipment and procedures.
With respect to equipment the licensee requires that:
core or containment damage shall not occur without multiple failures of redundant or diverse equipment, vessel failure shall not occur following core damage unless additional independent equipment failures occur, containment failure shall not occur following core damage unless additional independent equipment fai lures occur, containment failure shall not occur following vessel failure unless additional independent equipment failures occur.
These criteria, if successfully applied to the station design, would prevent any group of equipment failures from causing the failure of more than one of the barriers to fission product release.
This results in truncating the progression of each accident sequence
at several points by creation of three levels of equipment protection.
A similar set of defense-in-depth criteria have been established for evaluation of procedures and instrumentation.
3.5 The licensee has completed an Integrated Risk Reduction Study intended to identify risk significant improvements suggested by the IPE results.
During the study each potential accident sequence, including low probability sequences, was reviewed and evaluated against the defense-in-depth criteria previously discussed.
Equipment designs, instrumentation and procedural guidance not meeting the criteria were identified, and recommended actions for resolution were developed.
The study report is presently in draft with final issuance expected in the near future.
While the final report has not been issued, the licensee has already used the insights gained to address several of the more risk significant sequences.
SPECIFIC IPE"DRIVEN ENHANCEMENTS The results of risk assessment can be effectively used to improve plant design, event response procedures, routine operating practices, and maintenance practices.
The inspectors reviewed licensee efforts in each of these. general areas to determine if IPE results had been appropriately considered and if recommendations were being implemented.
Modifications, station operating procedures, and administrative control procedures were reviewed.
PLANT DESIGN IMPROVEMENTS As discussed in Section 3.4 above, the licensee has completed a
detailed study of the IPE results and identified vulnerabilities in plant design.
In several cases the licensee has taken action to initiate plant modifications intended to reduce these vulner-abilities.
for example, station blackout (SBO) events represent the accident class with the greatest contribution to core melt frequency (CMF).
The licensee's coping analysis for SBO demonstrated that the plant design adequately met the applicable 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> coping criteria.
However, it was noted that the CMF for SBO events could be significantly reduced if 125 VDC power availability could be extended.
Based on this, the licensee procured a
100 KW mobile diesel generator which can be tied-in to energize the 125 VDC battery chargers during a
SBO event.
The machine and support equipment needed for its use are presently in place, and controlling procedures have been developed and are in the review process.
Also, as a result of the IPE effort, the licensee identified design deficiencies in the emergency service water (ESW) system.
The four emergency diesel generators (EDG) are all cooled during an accident by ESW.
The ESW system consists of two redundant,
independent loops.
Each ESW loop discharges cooling water flow to the spray pond through a single, normally-closed motor-operated return valve.-
The valve must be maintained closed'with the system in stand-by to ensure system keep-fill pressure.
Failure of the EOG supplying motive power to the return valve in a given loop would result in the valve remaining closed, preventing ESW flow and causing failure of the second EDG cooled by that ESW loop.
Because of this design, failure of a single EDG would result directly in failure of a second EDG.
In addition, if the two EDGs which provide power for the ESW return valves fail to start during a loss of offsite power, no cooling water flow would be available, resulting in a SBO.
The licensee had previously identified a precurser event at the site in which the two key EDGs were both inoperable with the unit at power.
Following identification of this weakness, the licensee modified the ESW system to allow all
EDGs to "swing" between the redundant ESW loops, receiving cooling water flow from the pressurized loop.
This removes the possibility that a single EDG failure would cause failure of a second machine.
A second modification to alter the ESW keep-fill system and allow the ESW return valves to be normally open is planned and will eliminate the remaining EOG interdependency.
The final modification is included in the licensee's five year plan for implementation in early 1991.
The ESW design weakness was discovered by the licensee in late 1985.
The inspector questioned the timeliness of the licensee's response, given that 5 years would transpire between initial identification and final resolution.
Clearly the system meets the original design basis and improvements by the licensee only provide enhanced safety.
However, the extended time period required for resolution raises questions regarding the efficiency of the modification process.
The inspector also noted that assessment of risk impact was not included as a factor in evaluating and prior itizing potential modifications.
These observations were discussed with the licensee.
In their IPE, the licensee identified the failure of the low pressure permissive instrumentation as the major contributor to low pressure emergency core cooling systems (ECCS) unavailability during an accident.
A common set of sensors feed the logic for both the core spray and low pressure coolant injection systems.
The licensee plans to install a permissive bypass switch in the control room to address this problem.
Switches for the Unit 2 core spray system have already been installe It is evident that the licensee has utilized the IPE to identify potentially beneficial modifications.
Corfduct of their Integrated Risk Reduction Study (IRRS) demonstrates that these efforts are likely to continue.
EVENT RESPONSE PROCEDURES The licensee has identified several beneficial strategies for use in coping with severe accidents as a result of the IPE efforts.
A unique approach to anticipated transient without scram (ATWS)
response is being developed in which water level is not lowered to the top of active fuel.
Instead, level is maintained at a
higher, more easily controllable point, The licensee is also developing a procedure to utilize the reactor water cleanup system as a means to depressurize during sequences in which the reactor is isolated, and the high pressure coolant injection system and the automatic.depressurization systems are rendered inoperable.
A third example is the use of increased suppression pool water mass in some accident scenarios to delay containment failure.
These provisions are not currently contained in the emergency operating procedures (EOP) or operator training.
However, the licensee plans to incorporate the enhancements in the planned upgrade of the EOPs 'to Revision 4 of the Owners Group emergency procedure.,
guidelines.
ROUTINE OPERATING PRACTICES During previous operating cycles the plant had experienced routine suppression pool heatup due to leaking safety relief valves.
Because of the heat addition to the suppression pool, the operating staff maintained at least one and occasionally both loops of sup-pression pool cooling (SPC) in service for extended periods of time.
The engineering staff identified that, if a loss of offsite power and a loss of coolant accident were to occur with SPC 'in service, the head created by the residual heat removal pumps would be momentarily lost.
Pump discharge piping would drain to the suppression pool due to elevation differences.
Subsequent low pressure coolant injection (LPCI) initiation would result in water hammer and potential loss of the system.
If both SPC loops were in operation at the time, all LPCI injection could be lost.
The engineering=organization concluded this operating practice resulted in excessive time in a vulnerable condition and an unacceptable increase in risk.
Guidance maximizing the efficiency of time spent in SPC and thereby reducing the total system operating time, and precluding operation of both loops of SPC simultaneously, was developed and provided to operation WORK PLANNING PRACTICES The inspectors discussed the IPE and its impact on maintenance and testing practices with site planning/scheduling personnel and Maintenance Department management.
The licensee has developed a
manual establishing station policy for work management.
The Tactics for Excellence Through Accountable management (TEAM)
manual is intended to formalize the rules, practices and recommendations associated with planning and scheduling system outages for the purposes of corrective maintenance, preventive maintenance and testing.
The licensee planning and scheduling group coordinates the performance of all work activities, including conduct of surveillance testing.
The TEAM manual includes a listing of 27
"Safety Impacting Rules" used for preparing all schedules.
Many of these rules have been provided to the site from corporate engineering based on IPE insights.
For example, systems have been categorized based on safety impact as requiring around-the-clock, extended 'hours, and normal hours schedules.
The inspector attended a daily work planning meeting and noted that the priority list specifically identified work falling into these three categories, effectively translating the TEAM manual into practice.
Other rules limit the duration and combinations of equipment which may be removed from service based on potential risk.
These scheduling rules provide additional limitations on safety system availability beyond technical specification requirements.
The safety impacting rules help to establish a scheduling process which integrates discrete engineering advice to reduce overall vulnerability, and to reduce reliance on the operations staff for identifying scheduling conflicts.
TRAINING The inspector attended a licensed operator training session conducted by the corporate Systems Engineering Group addressing station blackout (SBO) response.
The session included discussion of the IPE and its results relative to SBO.
Completed efforts such as the SBO diesel and SBO response procedures were covered.
In addition, the corporate engineering department's plans for additional plant modifications intended to reduce SBO risk were outlined.
The inspector considers this interaction between engineering and operations a positive step.
Discussions with the site technical staff indicated that there was little appreciation for the status of results of the IPE.
Increased understanding of the IPE by the site technical staff through training could generate additional valuable insights for day-to-day operational us.6 SUMMARY Licensee management commitment to continued refinement of the IPE, and util'ization of the results in improving station design, procedures and training is evident.
Risk related goals have been incorporated into control documents and specific risk reducing practices have been included in implementing procedures.
The foundation created by the licensee in this area appears sound, and continued efforts are encouraged.
4.0 RELIABILITYCENTERED MAINTENANCE RCM PROGRAM INITIATIVES In 1986, the corporate Systems Engineering Group began an effort to develop a reliability engineering capability.
The goal was to identify plant design, operation, and maintenance areas which could be improved such that the number of scrams could be reduced and the time that the units operated at full capacity could be maximized.
Although these goals were primarily based on economic factors, plant safety would also be enhanced in that the number of plant transients would be reduced, in turn minimizing challenges to plant safety systems.
The reliability analysis program focuses on the balance-of-plant (BOP)
systems.
The starting point for the analysis was to model the BOP systems using logic diagrams to evaluate the functional relationships of the systems and components.
The logic diagram information is computer processed using a success oriented technique.
The
"GO" software ultimately generates the plant reliability estimates.
The system modeling is utilized to determine what component single failure would result in a scram or a forced shutdown.
The licensee has also evaluated single train safety systems such as HPCI to identify single component failures which would result in a loss of function.
These components are identified as "Priority One" components and will be reviewed for potential design or maintenance improvements and which could significantly improve reliability.
Single failures which would result in a partial loss of generating capability are also identified and are classified with one of several lower priority ratings.
Components are included if their failure results in a two megawatt or greater loss in electrical output.
To simplify the analysis, BOP systems were grouped into 8 modules:
Power Conversion Drywell Cooling Condenser Air Removal Reactivity Control Condensate and Feedwater Extraction Steam and Feedwater Heaters Reactor Recirculation Main Steam
To date, modeling has been completed on seven of the eight modules.
The inspector discussed the results with the supervising'ngineer and reviewed the. reports for the condenser air removal and extraction steam/feedwater heating modules.
The inspector also attended a, meeting at which the results of the condenser air removal analysis were presented to station management.
A total of 266 single failures were identified in the condenser air removal analysis of which 32 would result in a reactor scram or plant shutdown.
The extraction steam/feedwater heating analysis identified no single failures which would cause a plant scram or shutdown.
Similar findings resulted from the other module analyses resulting in the generation of a list of approximately 350 priority one components.
These components have been identified to the maintenance department who wi 11 review the adequacy of the current maintenance and testing activities relative to the component.
The Systems Engineering Group has also proposed BOP system modifications which would reduce the plant vulnerability to single failures as a result of the reliability studies.
'Work is ongoing to compare the actual plant reliability statistics to those obtained from the models.
Comparisons to date iiave shown a good correlation between the model data and actual plant data.
Also, once the modeling is complete and additional operating experience is gained, the reliability calculations will be fine tuned using actual component failure rates in lieu of the generic industry data which had been applied in the initial efforts.
't The team discussed the station maintenance program and the impact of the plant reliability study with the Site Supervisor of Maintenance.
The licensee is in the process of developing a reliability centered maintenance (RCM) plan that will utilize predictive maintenance techniques.
A comprehensive checklist has been developed to aid in performing a review of the maintenance presently in place for a particular component, as well as what's required or recommended by the vendor or other sources.
The results of these reviews will be used to determine maintenance to be added or deleted to assure that activities are focused to achieve optimum safety and reliability benefits.
The bases for the level and type of maintenance to be performed will be the component's significance to safety or reliability, as determined by the IPE, and the reliability engineering analysis discussed above.
The team noted that, after some initial work was contracted to a vendor, the licensee decided to develop the RCM in-house using the IPE and the reliability analysis program.
This approach should foster a "pride in ownership" attitude in the program and, as familiarity is gained during the development of the program, help ensure a useful progra The team questioned the impact of the increased maintenance scope and priority of BOP components on the licensee's ability to maintain safety systems.
If plant reliability is a key factor in prioritization decisions, standby safety system priority could potentially suffer.
. However, the licensee assured the team that safety system priority would
- remain at the highest level.
In summary, the reliability analysis and RCM efforts are providing valuable insights to allow identification of vulnerabi lities in plant design, and thus permit better focused maintenance and modification efforts.
5.0 GENERAL PLANT OBSERVATIONS 5.1 BYPASS CONTROL PROGRAM REVIEW As follow-up to Unresolved Item 387/87-11-01, Control of Temporary Modifications (Bypasses),
the
.'nspector conducted a review of open bypasses.
Licensee procedure AO-QA-484, Electrical and Mechanical Bypass Control, defines the program for initiation, control and removal of bypasses.
A bypass is defined as a temporary interruption or disturbance of mechanical or electrical circuits by the use of spool pieces, blank flanges, bypass piping/valving, jumper wires, lifted leads, blocked relays, fuse removal or link opening.
Review of this procedure, detailed review of four safety-related bypasses, and discussion with licensee staff identified several weaknesses described below.
Licensee procedures require a quarterly review of all open bypasses addressing the status of the final closure mechanism (design change, maintenance item, etc.), reconfirming the need for the bypass installation and justifying its continued placement.
A review of the open bypass listing dated October 19, 1989, identified that 32 open bypasses had not received the quarterly update of the closure document status or justification.
When this concern was raised to the licensee by the inspector the licensee's compliance staff indicated that they were aware of the problem and were already working to resolve it.
The inspector was provided with a memorandum dated September 8,
1989 to all department heads requesting more complete updates.
Review of licensee procedure AO-QA-484 also identified that no provisions are included to ensure that bypasses are permanently resolved and closed in a timely manner, or to ensure that affected drawings and procedures are annotated to reflect these temporary design changes.
The licensee's program for implementation of
5 '
permanent modifications requires document updates to be performed within a few days of modification completion.
Document update for bypasses only after one year has elapsed does not seem appropriate.
All four of the bypasses reviewed in detail by the inspector were over one year old, however, in two of the four cases associated drawings had not been annotated (Bypass Nos.
1-87-098 and 2-85-017),
indicating that the documented update guidance promulgated by the licensee is not being consistently implemented.
Currently, there are in excess of 130 open bypasses installed at Susquehanna.
Mhile some of these bypasses are recently installed or are associated with ongoing Unit 2 outage activity, a significant number are long-standing temporary modifications.
System design problems important enough to warrant near-term installation of a bypass, should be followed in a timely manner with a permanent modification.
The inspector expressed concern that the licensee's bypass process, if improperly controlled, could be used as a method to circumvent the permanent modification process.
The inspector reviewed a listing of Minor Modification Candidates (MMC) provided by the licensee, and noted that the present backlog of MMCs is over 500.
Only about 120 of these MMCs are implemented each year.
The level of difficulty in a minor modification progressing through the licensee's design change process may contribute to the number and age of bypasses.
The licensee indicated that a review of the bypass control procedure and its implementation would be conducted.
The fact that this was a
nonrecurrent issue originally identified by the licensee with no apparent safety impact (to date) is sufficient to warrant no NRC action at this point.
This issue will remain unresolved pending further review of the licensee's actions to ensure compliance with the controlling procedure, and to strengthen provisions related to document updates for bypasses (UNR 89-81-01).
SCAFFOLDING AND TRANSIENT E UIPMENT CONTROL PROGRAM REVIEM During tours of the Unit 1 and common areas the inspectors noted significant amount of scaffolding and transient equipment.
In some cases the scaffolding was installed in very close proximity to or over safety related equipment.
The licensee's scaffolding erection procedure includes detailed instructions regarding the structural configuration.
The instr'uctions are intended to ensure the erection of "seismic" scaffolding in the vicinity of safety-related equipment.
A post-erection checklist is required to confirm proper assembly.
Inspection of scaffolding in place on the 749 foot elevation of the reactor building identified several concern scaffolding erected over and around a safety related inverter did not display the scaffolding inspection checklist required by the licensee's procedure.
The scaffolding was braced against the inverter, contrary to the established guidance.
scaffolding in place over the main reactor vessel level instrument rack also had not been inspected.
The scaffolding was constructed using a safety related junction box support as a member.
In this instance and in the instance noted above, the inspections had not been completed promptly, thus leaving the potential for improperly installed scaffolding to be in place for a significant amount of time.
scaffolding over the standby liquid control system appeared to be properly erected and inspected, but had been in place for approximately 2 years.
Generally the placement of scaffolding makes equipment access more difficult.
Problems requi ring its erection should be resolved permanently via some appropriate means.
It did not appear that steps were being taken to eliminate the need for this scaffolding.
The licensee's procedure for control of scaffolding appeared to be comprehensive.
Implementation of the procedure, however; was not effective in the cases noted above.
While the engineering controls associated with scaffold design are judged to be good, the above weaknesses or inconsistencies with. regard to implementation and management of those controls require additional attention.
The inspector also noted that transient equipment such as tool boxes and equipment handling carts were located in various buildings and in close proximity to safety equipment.
This rolling equipment generally was not secured and therefore could impact safety equipment and prevent it from functioning properly, particularly during a
seismic event.
Equipment on wheels should receive added attention.
There does not appear to be a program to control transient equipment.
This item remains unresolved pending further review of the adequacy of implementation of procedure AD-gA-903 scaffolding controls and of licensee efforts to control transient equipment.
(UNR 89-81-02)
5.3 STANDBY LI UID CONTROL SYSTEM INSPECTION The standby liquid control (SBLC) system operability is of importance in that anticipated transient without scram (ATWS) events are one of the dominant sequences which contribute to core damage per the IPE.
The inspectors walked down portions of the Unit 1 system and also reviewed the provisions for boron injection using the reactor core isolation cooling system (RCIC).
The SBLC system components appeared to be in good condition with both injection pumps operable.
A review of system availability data since commercial operation for both units showed that the actual system availabi,lity was consistent with that assumed during the preparatioh of the PRA.
The emergency operating procedure which would direct the use of SBLC was also reviewed,
"EO-102 RPV Control".
This procedure included a
step to perform boron injection by the use of the RCIC system in the event the normal SBLC pumps were unavailable.
Emergency procedure ES-150-002,
"Boron Injection Using RCIC System!'as also reviewed.
The procedure gives specific details to the operator on how to install a temporary hose to connect from the SBLC tank drain piping to the suction of the RCIC pump.
The affected system tie-in points have been painted green as an aid to the operators in identifying the appropriate connection points.
The temporary equipment was verified to be stored in the vicinity of the SBLC tank, as identified in the procedure.
The inspector also reviewed outstanding maintenance items and nonconformance reports for the system, and identified no concerns.
In summary, the SBLC system and procedures were found to be maintained in good condition commensurate with their importance as discussed in the IPE.
5,4 NONCONFORMANCE REPORT REVIEW Nonconformance Reports (NCRs) are issued and handled in accordance with adminstrative procedure AD-QA-120,"Nonconformance Report Control and Processing".
NCRs which were either identified in the field during plant observations or selected from the licensee's computer tracking printout of outstanding NCRs, the Plant Maintenance Information System (PMIS), were reviewed by the inspectors to verify the licensee's timeliness and acceptability of corrective actions.
The October 2, 1989 (PMIS) computer printout revealed that there are a total of 412 outstanding NCRs.
Approximately 20 percent of these NCRs are Appendix "R"/Outage related or Unit 2 mechanical snubber functional testing deficiencies.
Unit 2 is currently in a refueling outage and the snubber problems and NCRs are at this time appropriately being addressed.
During a tour of the reactor building the inspector noted several local pressure indicators aligned to the containment instrument gas (CIG) system with attached NCR tags.
Followup of NCR 88-0438 issued in June, 1988 indicated that seven local pressure indicators and two pressure switches within the CIG system boundary had been identified as non-Q and non-seismic.
In response to the NCR, the
licensee initiated qualification testing of the pressure switches, and a design change to upgrade the associated tubing and supports to seismically qualified configurations.
Pressure switch qualification testing was successfully completed in mid-1989.
Implementation of the referenced design change is ongoing and final closure of the NCR is imminent.
During the period from initial identification through completion of qualification testing and modification implementation, the licensee maintained the system with the instruments aligned.
The justification for system operability stated that following a seismic event the nonqualified tubing would fail, depressurizing the system to the low pressure alarm point.
Upon receipt of the alarm an operator would be dispatched, isolate the leaks and recharge the system.
The CIG system supplies motive power for the automatic depressurization system (ADS).
The analysis indicated that the short-term function of ADS would not be affected.
The long-term function of ADS, however, as described in the FSAR could not be met without the operator action.
The justification did not address the fai lure mode of the nonqualified pressur e switches and associated circuits which had been relied upon to initiate the alarm.
The inspector also questioned the need for continued alignment of the nonqualified local indicators and tubing.
Isolation of these indicators when not in use would eliminate their potential impact.
Reliance upon operator action to compensate for equipment designs which do not conform to the original specifications is not a conservative practice.
Following a seismic event, plant operators would be compelled to deal with a large number of problems.
Addition of minor compensatory measures such as this without assessment of their cumulative impact could result in unrecognized problems.
These concerns were acknowledged by the licensee.
Twelve additional NCRs reviewed by the inspector had a clear delina-tion of responsibility for closure.
The resolution to correct the identified deficiencies appeared reasonable.
The PMIS for NCRs is adequate.
However, the remaining number of outstanding NCRs, which are not Appendix "R"/Outage related or Unit 2 mechanical snubber related, represent a significant backlog of unresolved deficiencies.
Additional licensee attention to their timely resolution may be warranted.
The adequacy of the justification of system operability for other open NCR's is therefore unresolved (UNR 89-81-03)
pending further review of their status and significanc.0 REVIEW OF UNRESOLVED NRC FINDINGS 6 ~ 1 Closed UNR 387/85-11-04 Failure to Establi sh Ade uate Procedures For Maintenance of Class 1E Batteries During a previous inspection, a number of maintenance inconsistencies were noted in the licensee's procedure for maintaining the Class 1E batteries in accordance with IEEE 450-1975 and the vendor's manual.
The procedure was found to be inadequate in that the average of individual battery cell voltages were not required to be calculated, intercell connector resistance measurements were not compared to previous measurements, and no guidance for monitoring battery parameters during an equalizing charge or when to terminate the charge were included.
The IEEE 450-75 Standard only served as a recommended practice for maintenance of Class 1E batteries since it lacked baseline criteria.
The Susquehanna Technical Specification (TS) bases requires battery.surveillances in accordance with Regulatory Guide 1. 129,
"Maintenance Testing and Replacement of Large Lead Storage Batteries for Nuclear Power Plants" and IEEE 450-1980,
"IEEE Recommended Practice for Maintenance, Testing, and Replacement of Large Lead Storage Batteries for Generating Stations and Substations."
The licensee's battery surveillance
.procedures SM-102-001,
"125 OC Station Batteries Weekly Electrical Parameter Check - Unit 1 and Diesel Generator E," SM-102-002,
"125 Volt Station Batteries:
Quarterly (92 day) Electrical Parameter Check,"
and SM-102-A03, "18 Month Channel
"A" ID610-125 V DC Battery Electrical Parameter Test and Inspections, Battery Service Discharge and Battery Charger Capability Test," were revised to provide the required guidance for maintaining station batteries in accordance with TS requirements and IEEE 450-80 recommendations.
The inspector determined that current battery surveillance procedures adequately address the methods utilized to maintain the station batteries in accordance with IEEE 450-1980 standard and Technical Specifications.
6.2 Closed IFI 387/85-12-03 Reins ection of 125V OC Panels
~Bent Lu s During inspection 387/85-12, broken terminal lugs in 125V OC panels caused an automatic start of the "C" diesel generator.
During inspection 387/87-22 the inspector found an adequate inspection and repair program had been implemented.
However, the item remained open until the licensee completed actions to prevent recurrence, including inspection of areas surrounding the work for damage.
The inspector reviewed training material provided to craft personnel entitled ME049 Unit of Instruction - Cable Termination.
Section III.K, Work Area Evaluation, contains training that satisfactorily addresses the issues.
In addition, MT-GE-010, "Control, Instrumen-
6.3 tation Cable, and Lower Range Power Circuit Wire Terminations,"
Revision 1, was reviewed.
This procedure contains acceptance criteria that require verification of final cable/wire routing and barrier condition.
Inspection and training completed by the licensee, adequately resolve this issue.
Closed NC4 388/86-14-01 Ino erable Traversin Incore Probe Containment Isolation Valve In July 1986, the licensee identified that Unit 2 operated in a condition prohibited by Technical Specifications (TS).
While in Operational Condition
a Limiting Condition For Operation (LCO) was not entered when a primary containment isolation valve on the traversing incore probe (TIP) system was inoperable.
The TIP drive mechanism was deenergized with the TIP inserted in containment, and the primary containment penetration integrity was not restored within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and the reactor was not placed in Hot Shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Thus, the plant failed to comply with the TS LCO 3.6.3 and a notice of violation (NOV) was issued.
The inspector reviewed the licensee's response to the NCV dated November 11, 1986, and verified that the corrective actions stated were completed.
Caution labels have been installed on the TIP control panels in the control room stating that "Loss of PWR/
.Deenergizing TIP Drive Disables Ball Valve Isolation Capability-Isolate or Comply with T.S. 3.6.3". Operating Procedures OP-178 (278)-001,
"Traversing Incore Probe System" have been revised adding precautions when power is removed or lost.
The reactor engineering controlling procedure for TIPs, RE-OTP-011 has been revised to include a form which is completed by operations wherever TIPs have been returned to their shield positions.
The practice of leaving the TIP inserted in containment afte~ use was established to ensure a decay period, preventing high dose rates in the TIP room.
The licensee subsequently conducted an evaluation to determine if the TIP detectors can be immediately withdrawn into the shield rather than leaving them inside the containment for the 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> decay time.
Test results indicate that TIP room general area dose rates would be 500 R/hr, which is significantly greater than estimated in the system description manual 3R/hr:
The licensee has initiated modifications to install additional shielding in the TIP rooms to reduce the radiation levels and allow the TIP detectors to be immediately placed in the shields after use.
The modifications are not currently implemented.
However, they are scheduled to be completed by the fourth quarter of 1989.
The inspector found the licensee's interim corrective actions and long-term resolution satisfactor.4 Closed Other 388/86-19-01 RHR Service Water Flan e
Erosion Evaluation Significant erosion on the inlet pipe flange to the Unit 2 residual heat removal service water (RHRSW) heat exchanger was visually detected by the licensee on September 3,
1986.
The erosion damage
'was on the flange to which the inlet throttle butterfly valve is bolted.
The damage was significant enough require replacement of the Unit 2 flanges.
Review of the licensee's long-term corrective actions and root cause evaluation were required to resolve this issue.
The licensee conducted an ultrasonic inspection of the Unit
RHRSW heat exchanger inlet valve flanges and found similar but less extensive erosion.
Nonconformance report (NCR) 87-0518 was initiated to document the deficiency.
The unit
RHRSW heat exchanger inlet valve flanges were repaired by building up the eroded areas of the existing flanges with Balzona ceramic-metal followed by coating the flange and pipe inside diameter surfaces with Arcor S-16 material.
The repaired Unit 1 flanges were again ultrasonically tested (UT)
after 700 hours0.0081 days <br />0.194 hours <br />0.00116 weeks <br />2.6635e-4 months <br /> of operation.
The UT res 'its were forwarded to Nuclear Plant Engineering (NPE) for further evaluation to determine flange acceptability.
NPE analysis confirmed that the flange in its present condition is acceptable.
Specification No. C-1088, "Inspections, Evaluations, and Repair/Replacement of RHRSW Inlet-to-Heat Exchanger Flanges" was issued to establish an inspection/evaluation program for the RHRSW flanges.
NPE also conducted an RHRSW Flange Damage Study to deter-mine the root cause of the flange erosion.
The study concluded the degradation of the flanges was caused by cavitation-induced erosion.
Cavitation occurred because of excessive throttling of the inlet valves to the RHR heat exchangers.
To prevent further cavitation damage to the flanges the licensee revised operating procedure OP-116-001,
"RHR Service Water," to specify flow rate limits when the inlet valves to the RHR heat exchangers are throttled below 6000 gpm.
6.5 The inspector found the root cause evaluation and corrective actions acceptable.
Closed UNR 387/87-11-01 Tem orar Modifications B
asses Inspection 87-11 reviewed the licensee's program for temporary modi-fications and bypasses (jumpers, lifted leads, etc.)
and found the administrative controls for bypasses had improved since the previous review.
However, five specific discrepancies were identified.
The inspector reviewed a licensee Action Required Memo'randum, issued October 28, 1987 and closed December 22, 1988, that addresses these five issues including corrective actions.
The inspector's review concluded that these specific issues wer e resolved.
.Additional review of the licensee,'s program is discussed in Section 4. 1 of this repor.6 Closed UNR 387/87-11-02 Im ro er Power Su
to Containment Isolation Valve Position Indication Units 1 & 2 In March 1987, the reactor recirculation sample line containment isolation valves (CIVs) F019 and F020 position indication circuits were found to be powered from non-Class 1E station standby power sources.
In addition, the valve limit switches were found to be unqualified models.
This issue remained unresolved pending review of the licensee's corrective actions.
The licensee provided a review package consisting of NCRs 87-0084 and 87-0085, project funding request (PFR) MMC¹87-188, the engineering studies, analyses, and evaluations,.the FSAR change request, and a revised PFR MMC¹87-188 to include replacement of the related limit switches with qualified models.
The inspector reviewed the above stated documents and found that the licensee modifications effectively resolved the problem.
This work is completed for Unit 2 and scheduled for Unit 1's next refueling outage.
The licensee also evaluated all other CIV position indica-tion circuits.
No additional problems were found.
The issue is closed for both units.
6.7 Closed UNR 387/87-11-03 Emer enc Diesel Generator Unit Exhaust Manifold Crackin and Turbochar er Failure In June 1987 during overhaul of-the "A" Emergency Diesel Generator (EDG),
a crack of one of the rigid exhaust ports was discovered, Later, after the unit was repaired and operated several times, inspection of the newly rebuilt turbocharger identified a damaged blower and radial bearing.
These two issues remained unresolved at the close of Inspection 387/87-11.
The licensee completed the failure analysis in July 1987.
They concluded that the turbocharger radial bearing overheated to the point where the oil decomposed, the tin surface of the sleeve bearing melted, and the journal insert cracked under thermal stress.
An extensive root cause evaluation was performed by the licensee, however, the cause could not be determined.
The turbocharger inspection, repair, and new part installation performed by the licensee were comprehensive.
Subsequent turbocharger inspections have not identified any additional problems, and no repeat of the failure has occurred.
This issue is closed.
6.8 Closed UNR 387/87-12-01 Technical S ecification Amendment Im lementation Process In August 1987, the licensee found that Unit 2 Technical Specifica-tion (TS) Amendment No.
35 had not been implemented for about 3~~
months after issuance.
This amendment increased the main steam line (MSL) high radiation trip setpoint from three times normal background to seven times normal background.
Although the new TS requirements
were less restrictive, the unit operated with an unnecessarily conservative setpoints resulting in unnecessary alarms.
The licensee's corrective action was to implement new procedure AD-gA-427, Station Technical Specification Implementation Program.
AD-gA-427 delegates TS compliance to the Superintendent of Plant, review of approved amendment implementation to the plant operations review committee interim adherence to approved amendments upon receipt to the Supervisor of Operations, and notification of Section Heads of approved license amendments which may affect their section's opera-tions to the Senior Compliance Engineer.
The inspector verified that the last two amendments, Nos.
92 and 56 for Units 1 and 2 [Appendix R
modifications to Emergency Service Mater Valves),
and No.
57 for Unit 2 (Surveillance Intervals) were implemented properly and in a timely manner.
This issue is closed.
6.9 Closed Violation 387/87-16-02 Secondar Containment Ventilation Zone Cross-tie In September 1987, with Unit 1 at 90 percent power, the licensee discovered that Reactor Building Ventilation Zones I and III had been cr-ss-tied, through open isolation dampers XD-17513 and XD-17514, for four (4) days.
By letter dated December 18, 1987, the licensee responded to the violation stating that this event occurred-as a result of inadequate communication.
Corrective actions included revision of the Reactor Building HVAC operating procedure to require step-by-step confirmation administrative tagging of the Railroad Access Bay isolation dampers during any Railroad Access Bay evolution and training concerning the procedure revisions and the importance of good communications.
Operating procedures contain detailed instructions for control of the Railroad Bay Door 101.
In addition, similar evolutions related to secondary containment are covered.
This issue is closed.
6.10 Closed UNR 387/87-16-03 Main Steam Line Plu Ejection During the performance of main steam isolation valve (MSIV) local leak rate testing (LLRT), a plug in the "C" main steam line ejected at an air pressure of about 38 psig.
The plug became suspended by two hoses and a 1/2 inch nylon rope against the side of the reactor vessel several feet below the main steam line nozzle.
The issue remaining unresolved from Inspection 387/87-16 was the licensee investigation into the cause of the event and development of corrective actions to prevent its recurrence.
The licensee provided the safety evaluation approved by PORC at the March 16, 1989 meeting.
The inspector reviewed the safety. evaluation that addressed the problem the original GE designed MSL plug.
The GE plug was not capable of holding any pressure in the MSL. It was used until 1984 and then replaced with a Preferred Engineering (PE)
MSL plug designed to hold a MSL pressure of 22 psig.
This is the plug that
6.11 ejected.
The plug currently in use is a modified/upgraded PE plug with an improved locking mechanism which can be used at pressures up to 45 psig.
It is designed to remain in place during a seismic event, not leak in excess of the make-up capability available without inflated seals, and not fall onto the core.
The inspector review indicated adequate licensee casual review and acceptable engineering improvements to prevent plug ejection.
Closed UNR 387/87-22-01 Vendor S ecified Maintenance for Critical Parts in Warehouse Stora e
During a 1987 inspection'f the warehouse the inspector identified that vendor storage requirements for recirculation water pump motors were not being met.
The issue remained unresolved pending procedure revision to include correct vendor required storage maintenance provisions.
The inspector reviewed the maintenance performed on safety-related equipment in the warehouse under MC-I0-020, Revision 1, Materials.
This procedure specifies the routine maintenance to be performed by warehouse personnel and more specialized work to be performed by maintenance personnel.
AC and DC motor rotation, heating, and lubrication requirements are now specified.
The inspector toured the warehouse and noted that the physical condition of spare safety-related equipment was acceptable.
Records of work performed by warehouse and maintenance personnel were reviewed and no questions were identified.
This issue is resolved.
6.12 Closed UNR 388/88-04-02 Missed Source Ran e Surveillance Due to Earl Technical S ecification Im lementation Following an October 1984 submittal of a proposed TS amendment to change Unit 1 source range monitor (SRM) testing, the licensee's IKC department changed the testing.interval from quarterly to a semi-annual.
This change was made in mid-1985, prior to approval of the proposed change by the NRC.
According to LER 88-003-01, this unapproved adjustment resulted in four periods of time when required SRM surveillance had not been performed at the TS required frequency.
However, a review of the surveillance records showed the setpoints were within TS limits, and the SRM control rod block instrumentation was fully operational.
After discovery in December 1987, the Unit
SRM surveillance interval was returned to quarterly.
The inspector reviewed SOOR 1-88-014, Mis-scheduling of Surveillance Procedure Results in Operations Prohibited by TS, LER 50-387/88-003-01, and QD-QA-427, Revision 0, Station TS Implementation Program.
The SOOR and LER indicate that this personnel error should be corrected by implementa-tion of AD-QA-427 and revision of the Surveillance Procedure Review Checkli.st.
In the revised checklist, if changes were incorporated which are less conservative than the previous requirements, the
preparer of the checklist is required to include the number of the approved amendment in which the NRC authorized the change.
For changes that are more restrictive, the licensee normally implements the change at the time an amendment to the TS is submitted to the NRC.
The corrective actions taken adequately resolve this issue.
Closed NC5 388/88-06-03 Personnel Door In Unit 2 Turbine Buildin Found Im ro erl Posted In An 0 en Condition During a previous inspection, a personnel door leading to a
radiological controlled area (RCA) was found propped open in the Unit 2 Turbine Building without proper provisions to control access/egress, The licensee took immediate corrective action, posting a sign across the doorway barring access or egress.
Subsequently, the hose that was running through the open door was removed and the door was closed.
Other similar doors were inspected and the postings were repositioned accordingly.
The incident was discussed in a "Station News" letter, which was addressed to all station personnel.
The licensee also conducted a review of all turbine building access/egress points.
As a result, modificatiohs were initiated to install alarms and improved locks on ground level emergenc'y exit doors.
To date, three of the five modifications associated with the improved access control to the.RCA are complete.
The two remaining modifications packages have been developed and scheduled for implementation.
The inspector determined the licensee's corrective actions to be both prompt and effective.
This item is closed.
6.14 Closed NC4 388/88-23-01 Reactor Core Isolation Coolin S stem Injection I
In December 1988, the reactor core isolation cooling (RCIC) System initiated and injected water into the reactor for about 30 minutes, with no valid initiation signal.
Investigation indicated that an ILC technician erred in pressure transmitter isolation valve operation, causing the RCIC initiation.. The technician failed to notify the control room and the injection proceeded unnoticed for 30 minutes.
An area radiation monitor alarmed due to the initiation.
However, the control room staff did not promptly follow-up.
PP&L's March 8, 1989 response to Notice of Violation (NOV) states that the I&C pro-cedure involved (SI-280-206)
was reviewed and found accurate; the failure to close the isolation valve is attributed to the I&C technician's attention being diverted by a packing leak on the valve.
I&C training has been performed to emphasize the importance of communicating abnormalities to the control room.
The high.radiation reactor building area alarm response procedure was revised to require operator review of system operating statu ~
~
~ /p 4ij
The inspector reviewed the NOV response, I8C training records and the revised AR-101/201-001 alarm response procedure.
Step 2.2, Check applicable system operating status, has been implemented at both units.
The control room staff was aware of this change.
This issue is closed.
6. 15 Closed UNR 387/89-01-01 Tem orar Loss of Shutdown Coolin On January 7,
1989, Unit 1 RHR shutdown cooling (SDC) was lost twice within a short time period by unanticipated closure of isolation valve HV-151-F008.
Licensee review determined that these SDC isolations were due to actuation of the RHR SDC isolation instrumen-tation when pressure perturbations occurred.
NRC inspection 89-01 found that the Emergency Notification System (ENS) call and the LER were appropriate, but left the review of licensee's corrective actions unresolved.
The licensee initiated a three phase program to resolve this issue.
Phase 1 was to install a time delay relay in the isolation logic under a temporary bypass controlled by site admini-strative procedures.
Phase 2 was the assessment of the need for a permanent modification.
Phase 3 was to ensure the acceptability of the time delay during Condition 3 (hot shutdown) operations.
The inspector reviewed Unit 1 Bypass No. 1-89-021, (including the
bypass locations, drawings, work authorization S-90473, and related Safety Assessment, installed on March 30, 1989, and Change Packages Nos.
89-9059 (Unit 2) and 89-9060 (Unit 1), dated August 24, 1989.
The temporary bypass and permanent modification was to install Agastat time delay relays, set for 2 second delay, into each division of the SDC isolation circuits.
The permanent modifications for both units have been completed.
This issue is closed.