IR 05000250/1999001
| ML17355A300 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 04/16/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17355A299 | List: |
| References | |
| 50-250-99-01, 50-250-99-1, 50-251-99-01, 50-251-99-1, NUDOCS 9904280035 | |
| Download: ML17355A300 (64) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-250, 50-251 License Nos:
50-250/99-01, 50-251/99-01 Licensee:
Florida Power and Light Company Facility:
Turkey Point Nuclear Plant, Units 3 & 4 Location:
9760 S. W. 344 Street Florida City, FL 33035 Dates:
February 7 - March 20, 1999 Inspectors:
C. Patterson, Senior Resident Inspector R. Reyes, Resident Inspector W. Sartor, Senior Emergency Specialist (Sections P4.1, P4.2)
J. Kreh, Emergency Specialist (Sections P4.1, P4.2)
G. Salyers, Emergency Specialist (Sections P4.1, P4.2)
F. Wright, Senior Radiation Specialist (Sections R1.1 - R8.1)
B. Holbrook, Project Engineer (Sections 08.1 - 08.5)
P. Steiner, Licensing Examiner (Sections 08.1 -08.5)
D. Desaulniers, NRR (Sections 08.1 -'08.5)
Approved by:
L. Wert, Chief Reactor Projects Branch 3 Division of Reactor Projects 4280035 9'P04i6 R
ADOCK 05000250
PQR Enclosure
EXECUTIVE SUMMARY Turkey Point Nuclear Plant, Units 3 & 4 NRC Inspection Report 50-250/99-01, 50-251/99-01 This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support.
The report covers a 6-week period of resident inspection and includes the results of inspections by a Region II Senior Radiation Specialist and three Region II Emergency Specialists.
Additionally, the report includes the results of an inspection of Operator Workarounds, performed in accordance with Temporary Instruction 2515/138, Evaluation of the Cumulative Effect of Operator Workarounds.
~Oerations Power coastdown operations were properly implemented with thorough training and briefing of Operations personnel (Section 01.1).
The outage risk assessment and preparations for the refueling outage were formal and thorough (Section 02.1).
Senior Management plant status reviews were focused on safety. The plant nuclear safety review committee was critical during reviews and insisted that only quality products be approved (Section 07.1).
The licensee had established adequate procedural guidance for the identification, tracking, and resolution of operator workarounds.
The licensee's recent revision of ODI-CO-016, Control Room Deficiency Log, Annunciator Status, and Operator Workarounds established the same definition of workarounds as used in Temporary Instruction 2515/138.
Similarly, the recent procedure revision established guidance for assessing the cumulative effects of operator workarounds consistent with the criteria provided in the temporary instruction (Section 08.1).
A review of licensee procedures and interviews with operators did not reveal any new operator workarounds that had not been identified or reviewed by the licensee.
The recent workaround self assessment was thorough, detailed, and identified areas for improvement that were either completed or scheduled for completion in the near future.
The timeliness of the corrective actions were appropriate for their significance.
The personnel interviewed demonstrated adequate knowledge of workarounds and the required compensatory actions.
The threshold for identifying potential operator workarounds was low (Section 08.2).
'he licensee had not thoroughly as'sessed the operator workaround compensatory actions that were needed during power changes relating to the feedwater pump seal water collection system on Unit 3. The inspectors identified a vulnerability in the operations shift turnover process in that the procedure did not address how individuals responsible for workaround contingency actions were to be informed or whether or not individuals were knowledgeable of the assigned contingency task. The inspectors concluded that current operator workarounds did not significantly impact plant operational safety.
Operators were knowledgeable of the workarounds and required compensatory actions.
The inspectors did not identify any reduction in system or
e component reliability or availability due to workarounds or compensatory measures (Section 08.3).
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The inspectors concluded that the licensee's current program requires detailed assessment of operator workarounds.
The inspectors did not identify any significant concern with respect to the overall cumulative effect of workarounds using the criteria under the previous program.
The licensee effectively identified workarounds, established reasonable corrective actions, and is currently satisfactorily assessing workarounds for overall cumulative effect on safe operations of the plant (Section 08.4)
The licensee was effectively identifying, assessing, scheduling, and resolving operator workarounds based upon safety significance (Section 08.5).
Maintenance
'esting of the emergency bus load sequencer was satisfactorily performed (Section M1.3).
~En ineerin An Unresolved Item was identified involving controls over software used to implement surveillance testing of the component cooling system.
Administrative deficiencies had resulted in the onsite document control files not containing some documents (Section E3.1).
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A Non-Cited Violation was identified for failure to followcomponent cooling water system surveillance procedures.
Numerous examples were identified in which test criteria were not met and the discrepancies were not addressed as required by the procedure (Section E3.2).
The licensee's submittals of the scope and objectives for the biennial emergency preparedness exercise as well as the scenario package were timely and of sufficient detail (Section P4.1).
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The licensee's overall performance in the emergency preparedness exercise conducted on February 10, 1999, was good. The facilities were staffed and activated in a prompt manner.
Excellent command and control was observed in the technical support center and the emergency operations facility. Event classifications were timely and accurate, and offsite notifications were completed within 15 minutes.
Good technical assessments were observed in the technical support center.
The recovery manager and his emergency operations facilitystaff maintained excellent working relationships and clear lines of communications with the governmental representatives.
Operations support center operations were marginally satisfactory with issues identified addressing the dispatch, tracking, control, and health physics coverage of the repair teams (Section P4.2).
The staff continued to lower annual collective occupational radiation doses in 1998.
Individual occupational radiation doses in 1998 were well within licensee administrative and regulatory limits. The licensee's 1999 collective dose goals were challenging (Section R1.1).
The licensee's radiation surveys accurately measured radiation levels and all areas were
, properly posted.
Alllocked high radiation areas were properly secured (Section R1.2).
The inspectors observed poor frisking techniques by some occupational radiation workers exiting the Unit 4 containment building (Section R1.2).
In general, radiation detection and measurement instrumentation were found in good operating condition (Section R2.1).
The licensee degassed the reactor coolant system (RCS) with the chemical degas process and induced a crud burst for RCS cleanup prior to opening the system for maintenance.
Problems in coordination and control of these evolutions were noted.
The licensee's staff did not anticipate the process results, the RCS cleanup took longer than expected, and the cleanup was not as effective as planned.
The processes resulted in dose rates in some areas of the containment building being higher than planned. (Section R3.1).
The licensee vendor health physics (HP) technicians met minimum qualification requirements (Section R5.1).
Picture identification (security) badges had developed white markings after passing through card readers multiple times. The markings could make it difficultto use the badge picture to confirm the identity of an individual. The licensee initiated appropriate corrective actions (Section S1
~1) ~
Housekeeping and overall conditions in the cable spreading room were excellent.
A small amount of pre-staged transient combustible material in the cable spreading room was determined to be acceptable (Section F1.1).
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Summa of Plant Status Re ort Details Unit 3 operated at full power during this period and has been on-line since October 29, 1998.
Unit 4 operated continuously until the unit was shutdown on March 15, 1999, to start a scheduled refueling outage.
This ended a complete cycle of operation with Unit 4 on-line 516 days.
I. 0 erations
Conduct of Operations 01.1 Power Coastdown 71707 On March 5, 1999, the licensee implemented Temporary Procedure (TP)-99-007, Unit 4 Cycle 17 T-average and Power Coastdown.
As permitted by the procedure, T-average was allowed to decrease no more that five degrees from T-reference.
After the temperature decrease, power was allowed to deciease (coastdown)'until pow'er was reduced on March 12, 1999, to fiftypercent for condenser 0vater box cleaning.
The unit was tripped from fifteen percent power on March 15, 1999, to start the refueling outage.
The licensee conducted thorough training and briefings of these evolutions prior to implementation.
Operations personnel were knowledgeable of the procedure and limitations. The TP was implemented without problems.
Operational Status of Facilities and Equipment Outa e Risk Assessment and Pre arations Ins ection Sco e 71707 The inspectors reviewed the outage risk assessment which was performed prior to the Unit 4 refueling outage and examined key safe shutdown functions during the outage.
Controls of the key functions during the outage were also examined.
b.
Observations and Findin s The licensee completed a formal risk assessment using procedure O-ADM-051, Outage Risk Assessment and Control. Phase I addressed the first 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> after shutdown with a high decay heat load. Phase II covered the period with a lower decay heat load.
The availability of equipment required to meet the key functions at times during the outage was analyzed.
The key functions were decay heat removal, inventory control, power availability, reactivity control, containment integrity control, instrumentation, and fire protection.
No mid-loop activities were planned.
When any change from the minimum required equipment list occurred during the outage, a Temporary Change Notification (TCN) was'evaluated by the assessment team.
The inspectors reviewed the TCNs required during the outage.
The assessment conducted by the licensee was formal and thorough.
In addition, the key safety functions were routinely reviewed during the outage shift director's meeting.
Plant
management also emphasized the importance of monitoring outage preparations such as scaffold erection.
Signs were placed in the plant at entrances to Unit 3 to caution personnel they were entering the operating unit.
c.
Conclusion The outage risk assessment and preparations for the refueling outage were formal and thorough.
Quality Assurance in Operations 07.1 Self-Assessment 40500 On February 23, 1999, the inspectors attended a licensee management plant status meeting.
Each department head presented an overview of plant activities. Senior management provided a good safety focus throughout the meeting, challenging the plant staff. Activities for the upcoming refueling outage for Unit 4 were discussed.
Current industry and regulatory issues and changes were discussed with active plans to keep ahead of issues.
On March 11, 1999, the inspectors attended a Plant Nuclear Safety Committee Meeting.
The inspectors verified that Technical Specification requirements for members were met. The members were critical in reviews and insisted that only quality products be approved.
Miscellaneous Operations Issues An inspection was conducted to evaluate the cumulative effect of operator workarounds (OWAs) on the ability of operators to safely operate the plant and effectively respond to abnormal and emergency plant conditions.
Information gathered during this inspection willbe used to support an evaluation of the need for additional NRC industry guidance concerning OWAs. The inspection was conducted in accordance with Temporary Instruction (Tl) 2515/138, "Evaluation of the Cumulative Effect of Operator Workarounds."
08.1 0 eratorWorkaround OWA Proceduresand Criteria a.
Ins ection Sco e Tl 2515/138
'The inspectors reviewed procedures and criteria that the licensee used for identifying, tracking, and resolving OWAs and evaluating their cumulative effects. The procedures reviewed included the following:
Operations Department Instruction (ODI) ODI-CO-016, "Control Room Deficiency Log, Annunciator Status, and Operator Workarounds," dated February 1, 1999 O-ADM-200, Conduct of Operations, Revised Februa'ry 25, 1999
Observations and Findin s The inspectors found that the licensee's current procedure for identifying, tracking, and resolving OWAs provided a detailed description of personnel responsibilities and the processes for management of OWAs. The licensee noted that much of the detail in the procedure was introduced in the most recent revision of the procedure in response to a self assessment.
Consequently, whereas licensee personnel had several years experience in the identification, tracking, and resolution of OWAs, personnel had limited experience using the current procedural guidance.
The inspectors found that ODI-CO-016 provided the same definition for OWAs as used by the NRC in Tl 2515/138.
Specifically, the procedure defines an OWA as "a degraded or non-conforming condition that complicates the normal operation of plant equipment and is compensated for by operator action." O-ADM-200, Conduct of Operations provides further clarification of this definition in that it states that the definition shall apply to safety-related, quality-related, and non-nuclear safety systems, structures, and components.
The licensee noted that their current definition of OWAs is broader than their previous definition which was "a problem that impedes an operator in performing duties within approved procedures or in accordance with the intended design." The previous definition would have excluded workarounds that had been proceduralized.
In accordance with ODI-CO-016, on-shift operations personnel are responsible for screening all identified control room deficiencies.
If the operator determines that a condition constitutes an OWA then the Operations Supervisor is informed, the item is entered in an OWA Log, and the Shift Technical Advisor completes an OWA Screening Checklist.
Using the checklist, the Shift Technical Advisor (STA) makes several determinations, including whether the OWA creates a significant operator burden, significantly increases the potential for operator error, significantly affects operator response to transients or casualties, significantly impacts system reliabilityor availability, significantly impacts the probability of an abnormal or emergency plant condition, and whether the workaround, combined with other workarounds poses an undue hazard to safe and reliable operation of the plant.
If the STA identifies any of the above conditions are created by the workaround, a 3-day Condition Report is written to request an engineering evaluation of the condition.
ODI-CO-016 requires the Nuclear Plant Supervisor (NPS) to review the STA's screening of the workaround, assess the adequacy of the compensatory measures, and direct additional compensatory measures if necessary.
Adequacy of the compensatory measures for OWAs are also to be assessed weekly by the Operations Supervisor or a designee.
The licensee has used an OWA Team for the last several potential OWAs to coordinate licensee resources for resolving OWAs. The composition and responsibilities of the OWA Team are described in ODI-CO-016. The team is chaired by the Operations Supervisor and consists of representatives from the Operations, Maintenance, Engineering, and Planning and Licensing Departments.
The team is responsible for conducting quarterly meetings to evaluate (1) all known workarounds, (2) the adequacy of compensatory actions, and (3) the cumulative effect of the workarounds.
The inspectors found that ODI-CO-016 defined the criteria to use for assessing the
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cumulative effects of OWAs and that the criteria were consistent with those provided in TI 2515/1 38.
Conclusions The licensee had established adequate procedural guidance for the identification, tracking, and resolution of OWAs. The licensee's recent revision of ODI-CO-016 established the same definition of OWAs as used in Tl 2515/138.
Similarly, the recent procedure revision established guidance for assessing the cumulative effects of OWAs consistent with the criteria provided in Tl 2515/138.
08.2 Identification of OWAs Ins ection Sco e Tl 2515/138 The inspectors reviewed ODI-CO-016, the current list of OWAs, selected Surveillance Procedures, Emergency Operating Procedures, Off Normal Operating Procedures, and Alarm Response procedures to identify any OWAs that had not been previously identified by the licensee.
Additionally, condition reports, overdue condition reports, and condition reports on equipment identified by the Individu'al Plant Examination as important were reviewed to identify OWAs. Licensed and non-licensed operators were interviewed to assess their knowledge of OWAs and compensatory actions.
Observations and Findin s The recent ODI changes addressed weaknesses identified in the self assessment and added assessment criteria described in NRC Tl 2515/138.
Additionally, a Pass To History OWA list was developed.
The licensee's definition of Pass To History is as follows:
"Judged to meet the definition of an operator workaround, but no further action possible, required or desired (as determined by the Operator Workaround Audit Team). These items will be used when determining the "Cumulative effect" of new operator workarounds."
The inspectors did not identify any concerns with respect to the licensee's actions for OWAs that were "Passed to History." The OWAs were being assessed for the overall cumulative affect of OWAs on plant operation.
The self-assessment was thorough, detailed, and identified areas for improvement that were either completed or scheduled
'for completion in the near future. The timeliness of the corrective actions were appropriate for their significance.
The inspectors interviewed licensed and non-licensed Operators, STAs, and control room shift supervisors to assess their knowledge of the OWA list and the process as described in the ODI. As a result of the recent self-assessment the number of OWAs had increased to 28, which included 8 on the pass to history OWA list. The list was therefore relatively new to operators.
In general, the operators described and understood the definition of an OWA and were aware of where to obtain the most recent OWA list. An updated OWA list was maintained in the control room and the licensee
had added an ICON on the computer system for easy access to the most current list.
When questioned on details of the specific work around, Operators were aware of the equipment deficiencies that caused the item to be added to the OWA list and generally understood the required compensatory actions.
However, in some cases the specific details of the deficiencies were not clearly understood.
The inspectors noted that the operators demonstrated a low threshold for identifying potential OWAs.
Conclusions A review of licensee procedures and interviews with operators did not reveal any new OWAs that had not been identified or reviewed by the licensee.
The inspectors did not identify any concerns with respect to the licensee's actions for OWAs that were "Passed to History." The recent OWA self assessment was thorough, detailed, and identified areas for improvement that were either completed or scheduled for completion in the near future. The timeliness of the corrective actions were appropriate for their significance.
The personnel interviewed demonstrated adequate knowledge of OWAs and the required compensatory actions.
The threshold for identifying potential OWAs was low.
Assessment of Individual OWAs Ins ection Sco e Tl 2515/138 The inspectors reviewed OWAs to assess their impact on plant operational safety.
Observations and Findin s The inspectors reviewed all of the licensee identified OWAs and did not identify any significant cumulative impact on plant operational safety. The licensee identified OWAs in accordance with plant procedures which included caution tags, deficiency tags, or procedure revisions.
Operators interviewed did not voice any concerns with regard to operational difficulties or increased potential for error.
The inspectors reviewed an event relating to an operator workaround on the Unit 3 Feedwater pump seal water collection system that caused a near-miss turbine trip on February 2, 1999.
Reactor power was decreased to 40 percent to perform turbine stop valve testing.
Due to previous repeated equipment failures, the feedwater pump seal water collection system had been taken out of automatic control and was put on manual control and entered on the OWA list. Seal water from both feedwater pumps enters the collection tank and then is drawn into the condenser.
To correct for the decrease in seal water entering the tank during the power reduction and when one pump was secured, outlet valve (CV 2210) was manually adjusted to reduce seal water return to the condenser.
During the reactor power decrease and when the B feedwater pump was secured, a significant decrease in condenser vacuum occurred.
The adjustments made to CV 2210 were not sufficient to correct for the changes in seal water flow rate and caused air to be drawn into the condenser.
Condenser vacuum decreased to 25 inches of mercury. At 24.5 inches of mercury, operators are required to manually trip the turbine. Operators recognized the problem and locally closed valve CV 2210. The licensee later determined that the operator assigned to perform the compensatory
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actions by locally adjusting the valve was in the control room attending the shift turnover brief.
The inspectors concluded that condition report (CR)99-110, and the root cause was thorough and detailed.
The licensee identified that personnel failed to appropriately assess the required compensatory actions of the OWA during a transient.
The licensee determined that previous maintenance and corrective actions were not thorough for CV 2210. There had been numerous plant work orders and one condition report written to address this issue. The licensee informed the inspectors that work prioritization was not appropriate because there was previous opportunity to repair the seal water system prior to the downpower, however, it was not recognized as a priority. The corrective actions included a modification to improve the reliabilityof the seal water system and add a fail-safe feature to ensure CV 2210 would close in the event of a low level in the collection tank.
Additionally, all identified OWAs would be screened from the standpoint of the possibility to cause a transient or complicate actions during a plant transient.
The inspectors interviewed licensed and non-licensed operators that were on shift during the morning of the power decrease, reviewed the plant work orders describing the corrective maintenance work and condition reports on the CV 2210 issue, discussed the details of the issue with Operations and Engineering, and verified the Unit 3 and Unit 4 CV 2210 valves were operating in automatic.
The inspectors identified a vulnerability in that the process to ensure all operators were informed and knowledgeable of an existing OWA contingency action prior to standing watch was not clear. The operations shift turnover procedure identified that the Nuclear Plant Supervisor was responsible to ensure on-shift personnel were aware of and correctly implemented the procedure.
However, the procedure did not address how individuals responsible for contingency actions were to be informed or whether or not individuals were knowledgeable of the assigned OWA contingency task.
The inspectors reviewed licensee documentation which indicated the control room simulator model had, on occasion, been altered to provide realistic training due to OWAs. The inspectors did not identify any reduction in system or component reliability or availability due to OWAs or compensatory measures.
Conclusions The licensee had not thoroughly assessed the required operator workaround (OWA)
compensatory actions that were needed during power changes relating to the feedwater
'pump seal water'collection system on Unit 3. The inspectors identified a vulnerability in the operations shift turnover process in that the procedure did not address how individuals responsible for OWA contingency actions were to be informed or whether or not individuals were knowledgeable of the assigned OWA contingency task. The inspectors concluded that current OWAs did not significantly impact plant operational safety.
Operators were knowledgeable of the OWAs and required compensatory actions.
The inspectors did not identify any reduction in system or component reliability or availability due to OWAs or compensatory measure.4 Cumulative Effect of OWAs Ins ection Sco e Tl 2515/138 The inspectors reviewed OWAs to assess the cumulative effect on plant operations.
Observations and Findin s All personnel were responsible to identify and report discrepant and non-conforming conditions and the Shift Technical Advisor conducted an initial screening of the condition using Attachment 6 of procedure ODI-CO-016. The inspectors observed that the attachment for the recently revised procedure included the majority of the assessment elements identified in Tl 2515/138.
The cumulative effect of all identified conditions was a specific assessment element of the procedure attachment.
The inspectors noted that the procedure required a screening assessment for each item identified as a potential OWA. If the screening identified a potential OWA problem, engineering personnel was assigned to conduct a detailed review of the problem using Tl 2515/138 criteria.
The inspectors concluded that the current procedure was thorough, detailed and provided sufficient guidance to effectively assess potential OWAs. However, the inspectors noted that the previous revision of the procedure did not require a detailed assessment.
For example, the previous procedure did not require an assessment of the individual effect of each material deficiency including compensatory actions with respect to the operator burden, the potential for operator error, impact on system reliability and availability, impact on probability of abnormal or emergency plant conditions, and the impact on the crew's response to abnormal or emergency plant conditions. The cumulative effect of OWAs was not assessed.
An Operator Workaround Team performed a detailed review quarterly to assess implementation of all OWA program elements.
The inspectors reviewed selected meeting minutes back to 1993 and determined the quarterly assessments were thorough, detailed, and identified areas for improvement.
However, the quarterly assessment meetings completed under the previous program did not include assessment elements as discussed above.
Senior site management reviewed the results of the meetings, and were aware of ongoing problems, compensatory measures, and scheduled corrective actions.
Procedure ODI-CO-016 provided guidance on what constituted an adverse cumulative effect of conditions that posed an uridue hazard to the safe and reliable operation of the station. The procedure cautioned that a single OWA may pose an undue hazard when considered in conjunction with all existing discrepant or non-conforming conditions.
The inspectors reviewed the licensee's list of 20 open OWAs and eight selected previously closed OWAs and did not identify any significant cumulative effect on operators ability to respond to normal plant operations, transients, or accident conditions. The inspectors did not identify any concerns with respect to the licensee's identification and assessment of the OWAs for the overall cumulative effec The inspectors concluded that the licensee's current program requires detailed assessment of operator workarounds (OWAs). The inspectors did not identify any significant concern with respect to the overall cumulative effect of OWAs using the criteria under the previous program. The licensee effectively identified OWAs, established reasonable corrective actions, and is currently satisfactorily assessing OWAs for overall cumulative effect on safe operations of the plant.
08.5 Licensee Performance in Assessment and Resolution of OWAs The inspectors reviewed procedure O-ADM-701, Control of Plant Work Activities, dated July 28, 1998, the licensee's list of 20 open OWAs, and 12 selected previously closed OWAs to assess the prioritization and resolution of the problems.
The inspectors noted that the OWAs were prioritized in accordance with procedures as B-3 emergent work. This priority specified that the work to correct the problem be scheduled from the next available shift up to 2 weeks if possible.
Except for one licensee identified prioritization problem dealing with valve CV 2210, the inspectors did not identify any instance where problem prioritization or completed work was unreasonable.
Of the 20 outstanding OWAs seven were identified within the last month.
The oldest OWA, associated with turbine valve testing, was 41 months old and was scheduled to be corrected during the April 1999 Unit 4 refueling outage with a plant design change.
The inspectors observed that the number of licensee identified OWAs was relatively stable for the past several years with an average of about 10. The licensee recently increased emphasis on OWAs and completed a 13 person self-assessment during the week of January 25, 1999. As a result, nine new OWAs were identified using the criteria and OWA definition contained in TI 2515/138.
The inspectors concluded that licensee was effectively identifying, assessing, scheduling, and resolving OWAs based upon safety significance.
II~ Maintenance M1 Conduct of Maintenance M1.1 General Comments 61726 62707 The inspectors observed all or portions of the following work activities:
3-OSP-019.1 3-OSP-050.2 O-OSP-075.11 3-OSP-075.1 Work Order 98008771 Intake Cooling Water Inservice Test Residual Heat Removal System Inservice Test AuxiliaryFeedwater Inservice Test AuxiliaryFeedwater Traini Operability Verification 4C Component Cooling Water (CCW) Pump Seal Replacement
Routine testing activities were properly conducted in accordance with procedures.
Measuring and test equipment was verified as properly calibrated.
No problems were identified. Foreign material exclusion protection was noted as adequate during the CCW pump seal work.
M1.2 Emer enc Load Se uence Test a.
Ins ection Sco e 61726 On March 3, 1999, the inspectors observed testing of the Unit 3 emergency bus load sequencer3A.
b.
Observation and Findin s The licensee performed this test per procedure 3-OSP-024.2, Emergency Bus Load Sequence Manual Test. The inspectors observed the entire performance of this test.
The test was performed in accordance with procedural requirements and without difficulty.
The inspectors noticed that the cable tray above the sequencer panel was missing several seismic clips. A similar condition was noted above the 4A sequencer panel.
Engineering inspected the cable trays and concluded there was no operability concern.
CR 99-0273 was initiated for the missing hold down clamps.
Testing of the emergency bus load sequencer was satisfactorily performed.
E3 Engineering Procedures and Documentation E3.1 Com onent Coolin Water CCW Software a.
Ins ection Sco e 37551 The inspectors reviewed the licensee's controls on the computer program that is used to assess CCW heat exchanger thermal performance.
This program is used to complete surveillance testing required by technical specifications.
b.
Observations and Findin s Engineering used a computer program called HX3 and HX4, for Unit 3 and Unit 4, respectively, to calculate the thermal performance capability of the CCW System heat exchangers, i.e., tube fouling resistance and maximum allowable intake cooling water (ICW) inlet temperature to verify compliance with TS surveillance 4.7.2.a and 4.7.2. During the licensee's thermal up-rate project, several changes were made in the licensee's accident analysis that resulted in revisions to HX3 and HX4. The software was subsequently modified to Version II, Revision 1.
Quality Instruction Ql 2-PTN-15, Control of Computer Software, describes the controls imposed on this software.
The inspectors reviewed the quality instruction and noted that some documentation was not included in the document control records.
Subsequently, the licensee initiated Condition Report 99-132 and located some of the documentation.
Some of the documents were located in another office facility. The inspectors determined that other issues associated with controls over the software had been previously identified by Quality Assurance.
One of these issues was that the 50.59 screening for the software was not located in the file. Each of the specific issues had been addressed by Condition Reports and corrected.
However, the licensee had not determined if all the requirements of Ql 2-PTN-15 were met when the software was changed.
The issue is an unresolved item pending additional information. It is identified as URI 99-01-02: Controls Over Software Changes.
Planned corrective actions for Condition Report 99-132 include ensuring that the HX3/4 software met all of the quality instruction requirements and ensuring that other applicable engineering software and, plant software complied with the quality instruction. The licensee verified that Engineering was using the correct version of the HX3/4 software.
Conclusion An URI was identified involving controls over software used to implement surveillance testing of the component cooling system.
Administrative deficiencies had resulted in the onsite document control files not containing some documents.
Com onent Coolin Water CCW Surveillance Test Ins ection Sco e 37551 The inspectors reviewed the procedures used to perform Technical Specification required surveillance testing of the CCW system.
CCW is the most risk significant system on the licensee's list of risk significance systems.
Observations and Findin s The inspectors reviewed surveillance procedures; 3/4-OSP-030.4, Component Cooling Water Heat Exchanger Performance Test; and 3/4 OSP-019.4, Component Cooling Water Heat Exchanger Performance Monitoring. Technical Specifications (TS) 4.7.2.b.2 requires the testing to be completed at least once every 31 days.
Procedure 3/4-OSP-030.4 is used to determine the heat exchanger's maximum allowable intake cooling water temperature, ICW,. Obtaining ICW,requires the use of a program called HX3/4 to perform that calculation. The procedure also described that as an alternate to the HX3/4 software, a hand calculation could be performed and referred to equations on Enclosure 1 of the procedure.
The inspectors determined that there were not enough equations and information in the procedure to obtain ICW,by hand calculation.
Engineering verified the finding and informed the inspectors that the
3/4-OSP-30.4 procedure would be corrected to enable obtaining ICW,by hand calculation.
Records reviewed by the inspectors indicated that the software program had been used to meet the surveillance requirements.
Procedure 3/4-OSP-030.4, described two criteria for validity of the test results.
The first criteria required that the new ICW,temperature could not be 2.5'F greater than the previous ICW,temperature.
This criteria screened out data that indicated the heat exchanger thermal performance had improved without actually cleaning the heat exchanger.
The second criteria used an assumption of a 1'F /day maximum thermal performance degradation on the heat exchanger.
The new ICW,was compared with the degraded ICW,. The new ICW,could not be less than the degraded ICW,.
This criteria verified that the heat exchanger thermal performance was not degrading
'aster than expected.
The procedure requires that if the test criteria are not met, a retest shall be considered to verify the results.
Further, the procedure requires that "The Nuclear Plant Supervisor shall be notified immediately if any test criteria are not met or any malfunction or abnormal conditions occur. This information shall also be recorded in the Remarks Section of the applicable attachment."
The inspectors reviewed selected surveillance data for the past 12 months of Unit 4 CCW heat exchangers.
Eighteen examples of heat exchanger surveillance data were identified in which the test criteria were not met and the condition was not addressed in the documentation.
The inspectors communicated this issue to licensee management.
The licensee initiated Condition report (CR) 99-0222 to address this issue.
The licensee later informed the inspectors that after review of the data, no operability issues were identified.
The inspectors noted that in all the examples identified, the test data were outside the test criteria by only a few degrees.
This small amount supported the licensee's assessment that no operability issues were identified.
TS 6.8.1,requires that written procedures shall be established, implemented, and maintained covering the activities referenced in Appendix A of Regulatory Guide 1.33, Revision 2, dated February 1978.
Section 8.3 of Appendix A of Regulatory Guide 1.33 specifies procedures for surveillance tests.
Surveillance operating procedure 3/4-OSP-030.4, Component Cooling Water Heat Exchanger Performance Test, implements the surveillance requirement for TS 4.7.2.b.2.
The licensee did not properly implement the surveillance procedure, 3/4-OSP-030.4, as evidenced by 18 examples where the CCW heat exchanger test criteria was not met and actions required by the procedure were not completed.
However, Technical Specification requirements for system operability were met.
This Severity Level IVviolation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy. This is identified as NCV 50-250, 251/99-01-01, Failure to Follow Procedure for Testing Criteria Discrepancies.
This violation is in the licensee's corrective action program as Condition Report 99-0222.
Conclusion A Non-Cited Violation was identified for failure to followcomponent cooling water system surveillance procedures.
Numerous examples were identified in which test criteria were not met and the discrepancies were not addressed as required by the procedur II
IV. Plant Su ort P4 Staff Knowledge and Performance in Emergency Preparedness (EP)
P4.1 Review of Exercise Ob'ectives and Scenarios for Power Reactors 82302 The inspectors reviewed the exercise scenario to determine if it was of sufficient detail and challenge to demonstrate exercise objectives and meet regulatory requirements.
b.
Observations and Findin s The scope and objectives for this exercise were submitted by the licensee with a letter dated November 25, 1998. The complete scenario package was submitted with a letter dated December 18, 1998. The review of the scenario package determined that it provided sufficient emergency information to demonstrate objectives and exercise the onsite and offsite emergency organizations of the licensee.
c.
Conclusion The licensee's submittals of the scope and objectives as well as the scenario package were timely and of sufficient detail for this biennial emergency preparedness exercise.
P4.2 Evaluation of Exercises for Power Reactors 82301 During the period February 8-11, 1999, the inspectors observed and evaluated the licensee's biennial, full-participation, emergency preparedness exercise in the control room simulator (CRS), technical support center (TSC), operations support center (OSC),
and emergency operations center (EOF). The inspectors addressed licensee recognition of abnormal plant conditions, classification of emergency conditions, notification of off-site agencies, development of protective action recommendations (PARs), command and control, communications, and the overall implementation of the emergency plan.
In addition, the inspectors monitored selected post-exercise activities to evaluate the licensee's self-assessment of the exercise.
b.
Emer enc Res onse Facilit ERF Observations and Findin s b.1 Control Room Simulator CRS The Nuclear Plant Supervisor (IMPS) performed well as the Emergency Coordinator (EC). The NPS recognized the fire input as an emergency action level for an Alert declaration as of 8:48 a.m. The NPS functioned effectively as he directed EC responsibilities, including the staffing of the onsite ERFs, notification of the State of Florida and risk counties, and notification of the NRC. At 9:20 a.m. the EC
responsibilities were turned over to the Plant General Manager, who became the EC in the TSC.
b.2 Technical Su ort Center TSC The TSC was staffed and activated in a timely manner.
The inspectors noted that command and control in the TSC was a strength.
The EC was effective in obtaining status briefs from the support groups and then summarized the plant priorities based on the coordinated information. Good technical assessment was observed in support of the EC. For example, the EC technical assistant provided timely assessments of the changing conditions for escalation of the emergency classifications, which were made promptly and correctly. The inspectors noted that communications among the TSC support groups was good. The EC was provided with continuous updates describing dose assessments and projections.
Effective Health Physics support was observed and use of emergency procedures was emphasized.
b.3 0 erations Su ort Center OSC Personnel began arriving in the OSC immediately following the PA system announcement of the Alert. The responders promptly converted a lunchroom into an OSC control center which was declared operational at 9:22 a.m.
OSC operations were marginally satisfactory for providing effective and timely processing of teams.
The inspectors noted that during the first hour of activation the OSC Supervisor was mostly involved with trying to correct the repair team status board and determine the status of the control of the non-licensed operators.
This resulted in limited dialog with his staff and infrequent status briefs for the OSC personnel.
The difficulties noted by the inspectors with the status boards, which included individuals being identified on more than one team, would have made personnel accountability challenging.
Other concerns noted by the inspectors focused on repair teams being given new missions and designations while in the field. As a result, most team debriefs did not occur, or at least were not documented as expected.
The inspectors also noted that Health Physics (HP) coverage appeared to be lacking. Teams 4 and 5 were not assigned a HP technician, and when the Post-Accident Sampling Team required HP coverage it was provided by a chemistry technician given a radiological survey instrument.
The inspectors observed that the technician was not familiar with the instrument and needed instructions on its use.
'
The inspectors concluded that the above problem areas did not prevent required repair missions from being accomplished nor were known overexposures of team members observed as a result of the observed scarcity of HP coverage.
However, the above observations reflect that OSC operations need improvement.
The licensee acknowledged this need in a separate debrief to the NRC inspection team following the exercise as well as in a brief summary prior to the exit interview. The licensee representative indicated that significant changes in the operation of the OSC would focus on relocating the maintenance manager from the TSC to the OSC. The licensee's additional plans for improvement were summarized in its preliminary critique report
received by the NRC on February 23, 1999: "The OSC process and setup needs to be completely redone and updated - the organization and layout of the facilityshould be conducive to effective and timely processing of teams..."
b.4 Emer enc 0 erations Facilit In response to the Alert declaration at 8:48 a.m., the EC directed activation of the Emergency Operations Facility (EOF). Required minimum staffing was achieved at 9:53 a.m., followed at 10:03 a.m. by the Recovery Manager's initial briefing of the staff..
At 10:08 a.m., having completed turnover from the EC, the Recovery Manager (RM)
announced that the EOF was operational.
The primary responsibilities of the EOF were communications with offsite authorities and the development of protective action recommendations (PARs) for the public.
Command and control of EOF operations by the RM was commendable.
The RM was particularly effective in maintaining communications with the State of Florida and county (Dade and Monroe) representatives at the EOF. This process was enhanced through the conduct of formal hourly meetings with these representatives in a separate conference room. Excellent working relationships in general were also observed between licensee staff and the State and county representatives.
The EOF staff functioned efficiently and professionally.
State of Florida notification messages 4 through 11 were all prepared, approved, and transmitted in a timely manner, with accurate information and concise event descriptions.
The appropriate minimum PAR was issued promptly upon declaration of the General Emergency at 11:25 a.m.
Based on dose assessment and data from field monitoring teams, the initial PAR was upgraded about 15 minutes later to include evacuation of the 2-mile radius around the plant and sheltering of downwind areas to 10 miles.
b.5 Licensee Exercise Criti ue Immediately following the exercise, the licensee began its critique process.
Players and controllers assembled in their assigned facilities and players critiqued their performance.
Controllers continued their critique process the next morning and a management representative reviewed the issues with the NRC team later that day.
Prior to the NRC exit interview, the lead inspector requested that a licensee representative provide management with a summary of critique findings. The cursory summary identified a successful exe'reise with a need to improve OSC operations.
Following the inspection termination, the lead inspector requested and'received from the licensee a copy of the preliminary critique report from the exercise.
A review of the report indicated that the licensee had identified most of the negative issues noted by the NRC concerning OSC operations.
C.
Overall Exercise Conclusions The licensee's overall performance was good. The facilities were staffed and activated in a prompt manner.
Excellent command and control was observed in the TSC and EOF. Event classifications were timely and accurate, and offsite notifications were
completed within 15 minutes.
Good technical assessments were observed in the TSC.
The RM and his EOF staff maintained excellent working relationships and clear lines of communication with the governmental representatives at the EOF. OSC operations were marginally satisfactory, with issues identified addressing the dispatch, tracking, control, and HP coverage of the repair teams.
R1 Radiological Protection and Chemistry Controls R1.1 Occu ational Radiation Worker Ex osure e.
Ins ection Sco e 83750 The status of individual occupational radiation worker doses and the licensee's progress in maintaining occupational radiation exposures As Low As Reasonably Achievable (ALARA)were reviewed and evaluated.
Observations and Findin s Site collective occupational radiation exposures continued to decline in 1998. The 156 person-rem expended in 1998 met the established dose goal of 185 person-rem.
The Unit 3 Re-Fueling Outage (RFO) expenditure of 134 person-rem was within the established goal of 146.7 person-rem.
Collective Doses Three Year Rolling Averages Person-Rem/Unit YEAR 1994 1995 1996 1997 1998 1999 DOSE 179 160 145 135 126 99 Goal The 1999 annual collective dose goal of 99 person-rem has been established with a goal of 80 person rem for the twenty-five day Unit 4 RFO.
The planned outage length was reduced by eliminating steam generator inspections.
As noted from the maximum reported doses listed below, all 1998 occupational radiation worker doses were well within allowable limits Highest Individual Radiation Dose (Rem)
YEAR TEDE CEDE Skin Extremity Lens-Eye 1998 1.36 0.08 1.39 1.95 1.36 LIMITS 5.0 5.0 50.0,
50.0 15.0,
Conclusions The staff continued to lower annual collective occupational radiation doses in 1998.
Individual occupational radiation doses in 1998 were well within licensee administrative and regulatory limits. The licensee's 1999 collective dose goals were challenging.
R1.2 Radiolo ical Controls Ins ection Sco e 83750 The inspectors toured the Radioactive Materials Storage Warehouse, AuxiliaryBuilding, and Unit 4 Containment to review implementation of radiological controls against regulatory requirements.
In addition, the inspectors reviewed licensee radiation survey results and made independent radiation surveys in selected areas.
Radiological control postings were evaluated against the radiation surveys results and controls for locked high radiation areas were reviewed.
Observations and Findin s Personnel exiting the Unit 4 containment building conducted hand and foot frisking at the Step Off Pad (SOP) prior to proceeding to the employee dress out area where whole body frisks were required prior to donning street clothing. Whole body friskers were located at the dress out facility. A HP technician was stationed at the SOP to monitor workers exiting the area and to coach workers on proper frisking techniques.
The inspectors observed occupational radiation workers performing whole body frisks at the containment SOP.
Overall, the employees performed adequate contamination monitoring at the SOP, although several individuals frisked at a rate greater than 2 inches per second.
The poor frisking performance was also noted and corrected by licensee personnel performing monitoring surveillance.
Demineralizer filtervalve (4-227B) leaked reactor coolant in the licensee's auxiliary building during the reactor coolant system (RCS) cleanup process.
This demineralizer filterwas valved into service on March 14, 1999.
The area contamination was identified at approximately 4:00 am on March 16, 1999, when personnel contamination surveys detected low level contamination.
The licensee initiated Condition Report (CR) 99-0322 to review the event and determine appropriate corrective actions. The licensee found a loose bolt on the valve. The leak resulted in the contamination of the 18 foot elevation of the building with 10,000 to 500,000 dpm/1 00 cm'nd 30 to 40 personnel contaminations.
Most contaminations were minor and did not require documentation as
.personnel contamination events.
Approximately 11 personnel contamination events were documented because of the leak. The licensee also performed whole body counts, on the contaminated workers with eleven having measurable intakes of cobalt-58. The intake measurements ranged from approximately 14 to 152 nanocuries with a maximum
- committed effective dose equivalent value of 1.7 millirem. All exposures were less than regulatory and administrative limits. Airsamples taken in the area, were approximately 0.24 times the derived air concentrations.
The licensee response to the event was appropriat e.
Conclusions The licensee's radiation surveys accurately measured radiation levels and associated postings were proper.
All locked high radiation areas were properly secured.
Poor personnel frisking techniques by some occupational radiation workers exiting the Unit 4 containment building were observed.
R2 Status of Radiological Protection and Chemistry Facilities and Equipment R2.1 Radiation Surve and Monitorin E ui ment 83750 I
The inspectors observed and examined portable radiation monitoring equipment operating in the licensee's Radiation Control Areas (RCAs) to verify the equipment was operating properly, periodically response-checked, and calibrated at procedural frequencies.
AII radiation monitoring instruments including radiation detectors, contamination friskers and air samplers examined by the inspectors had valid calibration dates and were response checked as required.
Radiation detection and measurement instrumentation were found in good operating condition.
R3 Radiological Protection and Chemistry Procedures and Documentation R3.1 Prima Chemist Control Durin Shutdown
~ 'ns ection Sco e 84750 The licensee's shutdown chemistry control activities were reviewed to verify procedure compliance and monitor the effectiveness of the process in reducing Reactor Coolant System (RCS) dose rates.
Observations and Findin s Licensee procedure O-NCOP-001.1, Primary Chemistry Control During Shutdown, revision dated March 8, 1999, provided instructions to minimize corrosion of plant systems and to control RCS contamination and dose rates during reactor shutdown.
The procedure also provided instructions for performing chemical degas of the RCS.
The licensee planned to perform the chemical degas procedure by injecting hydrogen peroxide (H,O,) into the Chemical and Volume Control System (CVCS). The licensee planned to initiate a RCS crud burst after the degas was complete.
Injection of the hydrogen peroxide (H,O,) into the CVCS resulted in an unexpected sharp increase in the Unit 4 containment building dose rates.
The licensee restricted work in the affected areas until cleanup could reduce RCS radiation levels to expected levels.
Hydrogen peroxide was also injected several hours later for magnetite flush.
The processes were repeated and a significant quantity of radioactive material was removed from the RCS.
Ineffective coordination of ongoing plant evolutions and poor communications between Operations and Chemistry resulted in unexpected radiation level increases.
The licensee responded to the radiation level increases appropriately and delayed some maintenance activities.
The procedure indicated that an objective was to reduce the
RCS total activity to less than 0.1 microcurie per cubic centimeter (IjCI/cc) prior to flooding the reactor cavity. However, the licensee was only able to reduce the RCS activity to 0.18 pCI/cc prior to cavity flood up. Condition Report 99-0323 was initiated to address the problems.
Conclusion The licensee degassed the RCS with the chemical degas process and irIduced a crud burst for RCS cleanup prior to opening the system for maintenance.
Problems in coordination and control of these evolutions were noted.
The licensee's staff did not anticipate the process results, the RCS cleanup took longer than expected, and the cleanup was not as effective as planned.
The processes resulted in dose rates in some areas of the containment building being higher than planned.
R5 Staff Training and Qualification in Radiological Protection and Chemistry R5.1 Review of Vendor Health Ph sics Technician Qualifications 83750 Ins ection Sco e 83750 The inspectors reviewed the resumes of vendor Health Physics (HP) technicians against minimum experience requirements for senior HP technicians.
Licensee Technical Specifications required HP technicians to meet the requirements of ANSI 3.1, American National Standard for Selection and Training of Nuclear Power Plant Personnel
~ Section 4.5.2 of the standard requires technicians have three years of working experience in their speciality of which one year should be related technical training.
Observations and Findin s The inspectors found that most of the technicians did not have formal education in HP but all had at least three years or more of related HP experience.
Three had less than four years experience.
The licensee had requested approximately 40 technicians for the outage and had approximately 37 HP coordinators, supervisors and technicians.
Half of the technicians had less than seven years experience.
Conclusions The licensee vendor HP technicians met minimum qualification requirements.
R8 Miscellaneous Radiological Protection Issues R8.1 Closed Ins ection Followu Item 50-250 251/97-03-04: Failure to conspicuously identify tools used in the RCA.
This Inspection Followup Item (IFI) was identified to review licensee's controls for contaminated tools used in the RCA. The inspector had noted that procedures indicated that some tools were to be painted purple but in fact, the tools were not marked purple.
Management had indicated that the requirement would be removed from the procedur The inspectors determined that the purple paint identification requirement for tools used in the RCA had not yet been corrected in licensee procedures.
Management indicated that the procedure would be revised. The inspector noted that the tool painting requirement had not played a role in any problems with control of contaminated tools.
The licensee has significantly improved controls over byproduct material in the last two years and does not rely on the painting to control tools. The failure to revise procedures to remove the painting requirement constitutes a violation of minor safety significance and is not subject to formal enforcement action. The IFI is closed.
Conduct of Security and Safeguards Activities Personal Securit Bad es Ins ection Sco e 71750 The inspectors observed personal security badges to verify proper identification displayed.
Observation and Findin s On March 1, 1999, during some plant testing activities in a vital area, the inspectors noticed a white mark on the front of an employee's security badge.
The white mark or strip was centered over the picture of the employee.
The mark made it difficultto recognize the individual from the security badge picture; The inspectors observed several other badges and noticed that those also contained white markings.
On those badges, the marks were not wide enough to make identification difficult. The strips are apparently formed by swiping the badges in the card readers over a period of time.
This issue was discussed with Security and CR 99-0238 was issued.
The licensee also issued Information Bulletin 99-09, to remind all individuals granted unescorted access to report damage of their security badge and to have it replaced if it becomes unrecognizable.
Conclusion Picture identification (security) badges had developed white markings after passing through card readers multiple times. The markings could make it difficultto use the badge picture to confirm the identity of an individual. The licensee initiated appropriate corrective actions.
Control of Fire Protection Activities Cable S readin Rooms Ins ection Sco e 71750 The inspectors inspected conditions in the cable spreading room with an emphasis on transient combustible material controls. Additionally, the inspectors reviewed the
licensee's frequency of conducting fire drills in fire risk significant areas, including the cable spreading room.
b.
Observation and Findin s On March 2, 1999, the inspectors toured the cable spreading room. Overall housekeeping and other conditions in the room were excellent.
The inspectors observed four new 50 foot extension cords and one older 75 foot extension cord in the room. The presence of these items were discussed with the Nuclear Plant Supervisor.
The licensee reviewed this issue and concluded that the extension cords were pre-staged as part of procedure O-ONOP-025.3, DC Equipment and Inverter Rooms Supplemental cooling. Condition Report 99-253 was issued because there was slightly more extension cord in the room than was specifically listed in the procedure.
The amount of material was subsequently determined to be acceptable as far as transient combustible loading.
The inspectors obtained a listing of fire drills conducted.
It was noted that fire drills had not been conducted in the cable spreading room since 1994.
From discussions with the licensee, it was determined that the licensee's response capability had been demonstrated in the last year or two by actual fire incidents involving the motor-generators sets located in this area.
The licensee planned to review the frequency of drills conducted in the cable spreading area and other risk important fire areas.
c.
Conclusion Housekeeping and overall conditions in the cable spreading room were excellent.
A small amount of pre-staged transient combustible material in the cable spreading room was determined to be acceptable.
V. Mana ement Meetin s and Other Areas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on March 25, 1999.
Interim exit meetings were held on February 11, March 4, and March 19, 1999 to discuss the findings of Region based inspections.
The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.
No proprietary information was identifie Licensee
PARTIALLIST OF PERSONS CONTACTED R. Earl, Acting Quality Assurance Manager C. Mowrey, Acting Licensing Manager R. Hovey, Site Vice-President D. Jernigan, Plant General Manager T. Jones, Operations Manager J. Kirkpatrick, Protection Services Manager R. Kundalkar, Vice President, Engineering and Licensing M. Lacal, Training Manager M. Pearce, Work Control Manager R. Rose, Maintenance Manager E. Thompson, License Renewal Project Manager D. Tomaszewski, Acting Site Engineering Manager J. Trejo, Health Physics/Chemistry Supervisor S. Wisla, Health Physics Supervisor A.Zielonka, Thermolag Project Manager Other licensee employees contacted included office, operations, engineering, maintenance, chemistry/radiation, and corporate personnel.
NRC C. Patterson, Senior Resident Inspector R. Reyes, Resident Inspector INSPECTION PROCEDURES USED IP 37551:
IP 40500:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 82301:
IP '82302:
IP 83750 IP 84750 IP 92904:
TI 2515/1 38:
Onsite Engineering
'ffectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems Surveillance Observations Maintenance Observations Plant Operations Plant Support Activities Evaluation of Exercises for Power Reactors Review of Exercise Objectives and Scenarios for Power Reactors Occupational Radiation Exposure Radioactive Waste Treatment, and Effluent and Environmental Monitoring Followup - Plant Support Evaluation of the Cumulative Effect of Operator Workarounds
ITEMS OPENED CLOSED AND DISCUSSED
~oened 50-250,251/99-01-01 50-250, 251/99-01-02 Closed NCV URI Failure to Follow Procedure for Testing Criteria Discrepancies (Section E3.2).
Controls Over Software Changes (Sectin E3.1)
50-250,251/99-01-01 50-250, 251/97-03-04 NCV IFI Failure to Follow Procedure for Testing Criteria Discrepancies (Section E3.2).
Failure to Conspicuously Identify Tools used in the RCA (Section R8.1)
Attachment: Turkey Point 1999 Emergency Preparedness Evaluated Exercise
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FLORIDAPOWER 8c LIGHTCOMPANY TURKEYPOINT NUCLEARPLANT 1999 EMERGENCY PREPAREDNESS EVALUATEDEXERCISE FEBRUARY 10, 1999 2.1 SCOPE To assure that the health and safety of the general public is protected in the event of an accident at Turkey Point Nuclear Plant, Horida Power ALight Company (FPL) conducts emergency preparedness exercises. This exercise involves mobilization, or simulated mobilization ofFPL, Nuclear Regulatory Commission, State of Horida, Miami-Dade County and Monroe County personnel and resources to respond to a simulated accident scenario.
A Controller organization will control, observe, evaluate and critique the exercise to assess the emergency response capabilities ofthe utilityand government agencies.
An FPL Controller Organization will control, observe, evaluate, and critique the PTN portion of the exercise.
The FPL Emergency Response Organization (ERO) and Controller Organization will be evaluated by the Nuclear Regulatory Commission.
The State of Horida, Miami-Dade County, and Monroe County emergency response organizations will be evaluated by their own organizations and FEMA, as applicable.
Due to the compressed timeline ofthe exercise, some portions ofthe FPL ERO may be pre-positioned.
All onsite Emergency Response Facilities will be activated in accordance with simulated conditions and appropriate emergency response procedures for the exercise.
Exercise participants ("players") will not have any prior knowledge ofthe simulated accident events, operational sequence, radiological eEuents, or weather t
conditions.,
The exercise incorporates the followingsub-drills:
Radiological Monitoring Drill-both onsite and offsite teams will be dispatched during the exercise to obtain required air samples and measurements associated with a simulated offsite release of radioactivity, and communicate these results to the appropriate Emergency Response Facility. (Field monitoring team protective clothing and respiratory protection willbe simulated.)
Health Physics Drill-involves the response to, and analysis of, simulated elevated airborne activity or liquid samples; radiation exposure control; emergency dosimetry, and the use ofprotective equipment
'nsite.
Communications Drill - actual use of emergency response communications links and equipment to demonstrate their integrity.
Medical Drill-involves a simulated contaminated individual.
Fire Drill.involves the response to a simulated fire.
The preceding sub-drills are incorporated into the exercise scenario and will be demonstrated concurrently in the course ofthe exercise.
The overall intent ofthe exercise is to demonstrat'e that the FPL ERO is adequately trained to perform in accordance with the Emergency Plan and its implementing procedures.
Additionally, the scenario assists the Nuclear Regulatory Commission, State and local government agencies in demonstrating t
that they are adequately trained to perform in accordance with their emergency plans and procedures.
2.1-1 99.scc2i/l~J I8/98 ATTACHMENT
r
FLORIDAPOWER ck LIGHTCOMPANY TURKEYPOINT NUCLEARPLANT 1999 EMERGENCY PREPAREDNESS EVALVATEDEXERCISE FEBRVARY 10, 1999 2.2 OBJECTIVES The Turkey Point Nuclear Plant (PTN) emergency preparedness exercise objectives are based upon Nuclear Regulatory Commission requirements provided in 10 CFR 50:
a) 50.47, Emergency Plans; b) Appendix E, Emergency Planning and Preparedness for Production and U1ili "ation Facilities; and NRC Inspection Manual, Inspection Procedure 82302, Review of Exercise Objectives and Scenarios for Power Reactors.
Additional guidance provided in NUIKG-0654, FEMA-REp 1, Revision 1, CriteriaforPreparation and Evaluation ofRadiological Emergency Response Plans and Preparedness in Support ofNuclear Power Plants, was utilized in developing the objectives.
The exercise willbe conducted and evaluated using a realistic basis for activities.
The following objectives are consistent with the referenced planning documents:
A.
Exercise Planning Conduct an exercise ofthe PTN Emergency Plan.
2.
Provide an opportunity for the State of Florida and Miami-Dade and Monroe Counties to participate in an exercise.
3.
Prepare an exercise information package to include:
a.
The objectives ofthe exercise and appropriate evaluation criteria.
b.
The date, time period, place, and a list ofparticipating organizations.
The simulated sequence ofevents.
d.
The narrative summary.
4.
Conduct a critique ofthe exercise and prepare an evaluation report.
5.
Demonstrate that corrective actions are tracked:until completion.
2.2-1
2.2 OMECTIVES (Continued)
B.
Emergency Organizations, Support, and Resource 1.
Demonstrate the prompt activation, adequacy of the staffing and set up, as appropriate, ofemergency response facilities, as follows:
Control Room Technical Support Center (TSC)
Operations Support Center (OSC)
Emergency Operations Facility (EOF)
Emergency News Center (ENC)
2.
Demonstrate the capability of the FPL Emergency Response Organization to implement their Emergency Plan Implementing Procedures.
Demonstrate the ability of the Emergency Response Facility Managers and Supervisors to provide overall direction, including "command and control" by initiating, coordinating, and implementing timely and effective decisions during a radiological emergency.
4.
Demonstrate the ability to effectively transfer command and control of emergency response functions from the Control Room to the TSC/EOF.
t 5.
Demonstrate the provisions for continuous staffing ofthe emergency facilities.
6.
Demonstrate the interface capability between the FPL Emergency Response Organization and the State of Florida and Miami-Dade and Monroe Counties for effective response coordination to a radiological emergency and adequate protection ofthe health and safety ofthe public.
7.
Demonstrate the ability to control access to emergency facilities.
8.. Demonstrate the ability to provide a liaison at each participating offsite governmental emergency operations center (EOC).
9.
Demonstrate adequacy of designated facilities and equipment to support emergency operations.
10.
Demonstrate the availability of outside support agencies and organizations that may be requested to provide assistance in an emergency.
11.
Demonstrate, as appropriate, the ability to identify the need for, notify, and request assistance from Federal Agencies.
12.
Demonstrate the availability of outside support agencies and organization that may be requested to provide assistance in an emergency.
2.2-2
&sec2' !1/I85$
j I >
wt
2.2 OBJECTIVES (Continued)
C.
Accident Assessment and Classification 1.
Demonstrate the availability of methods, equipment, and expertise to make rapid assessments of the consequences of any radiological hazards, including the dispatch and coordination ofField Monitoring Teams.
2.
Demonstrate the ability to recognize emergency action levels (EALs) and properly classify emergencies in accordance with the Turkey Point Emergency Plan Implementing Procedures.
D.
Notification and Communication 1.
Demonstrate the ability to notify the State Warning Point within approximately
'ifteen minutes ofeach emergency classification.
2.
Demonstrate the ability to notify the NRC of any emergency classification within approximately one-hour ofthe declaration.
3.
Demonstrate the ability to notifyFPL Emergency Response Organization personnel.
4.
Demonstrate the ability to develop and send timely information to State and local authorities, as required by the Emergency Plan.
5.
Demonstrate the ability to communicate among the Control Room, TSC, OSC, EOF, and ENC, as appropriate.
6.
Demonstrate that adequate communication capabilities exist between FPL, and the State and local Emergency Operations Centers (EOCs).
7.
Demonstrate the adequacy of communications capabilities between the Emergency Response facilities and the offsite radiation monitoring teams.
8.
Demonstrate the ability to communicate among the Control Room, TSC, EOF, and
~ NRC Operations Center.
E. Radiological Consequence Assessment 1.
Demonstrate methods and techniques for determining the source term of releases or potential releases ofradioactive material.
'- Demo'nstrate'the adequacy of methods and techniques for determining the magnitude ofthe releases ofradioactive materials based on plant system parameters and efHuent monitors.
Demonstrate the ability to estimate integrated dose from projected or actual dose rates and to formulate Protective Action Recommendations (PARs).
4.
Demonstrate the ability to monitor and control emergency worker radiation exposure and implement exposure guidelines, as appropriate.
2.2-3
p
C
~
I
2.2 OBJECTIVES (Continued)
5.. Demonstrate the availability of respiratory protection, and protective clothing for onsite emergency response personnel.
Demonstrate the availability of a procedural mechanism to expeditiously evaluate risks and authorize emergency workers to receive doses in excess of 10 CFR 20 limits, as appropriate.
Demonstrate the capability for onsite contamination control.
8.
Demonstrate the ability to decontaminate onsite personnel, as appropriate.
9.
Demonstrate the capability to prepare a contaminated injured person for offsite transport.
10.
Demonstrate the capability for onsite and oFsite radiological monitoring, to include collection, and analysis of sample media (e.g.,
air)
and provisions for communications and record keeping.
11.
Demonstrate the capability to collect and prepare for shipment simulated elevated airborne or liquid samples, as required.
12.
Demonstrate (walk-through/simulate)
the capability to use the Post Accident Sampling System (PASS).
13.
Demonstrate the capability to analyze simulated fluid samples and provide the isotopic and chemical results ofthe analysis within three hours ofthe time the sample was first requested.
E Protective Action 1.
Demonstrate the ability to recommend protective actions to appropriate oFsite authorities.
2.
Demonstrate the ability to advise individuals, onsite or in owner controlled areas, of emergency conditions.
Demonstrate the ability to conduct search and rescue procedures for persons identified as missing during accountability procedures.
G. Public Information I,
'V Demonstrate the operations ofthe ENC and the availability ofspace for the media.
2.2-4
2.2 OBJEC't LV~> (Connnued)
Exemptions Areas of the PTN Emergency Plan that will NOT be demonstrated during this exercise include:
1.
Site evacuation and relocation ofnon-essential personnel willnot be demonstrated.
2.
Real time activation of the EOF by Juno Beach responders, or State and County participants willnot be demonstrated.
3.
Actual drawing ofa sample utilizing the Post-Accident Sampling System (PASS) willnot be demonstrated.
4.
Onsite personnel accountability will not be demonstrated.
Security will demonstrate accountability through the use ofsimulated personnel rosters.
2.2-5
FLORIDAPOPOVER &LIGHTCOMPANY TURKEYPOINT NUCLEARPLANT 1999 EMERGENCY PREPAREDNESS EVALUATEDEXERCISE FEBRUARY 10, 1999 3.1 NARRATIVESUMMARY Initial Conditions:
Unit 3 is operating at 100% power for the last 180 days.
The core is at the middle of Ijfe with boron concentration of916 ppm.
Unit 4 is in Mode 5, Cold Shutdown.
Items are ofinterest:
Six month surveillance testing is scheduled for the Containment Purge Exhaust Valves, POV-3-2602 and POV-3-2603.
3-OSP-23.1, Section 7.1, 3A EDG Normal Start Test is scheduled to begin. The pre-start checkouts have been completed Unit 3 CCW Deluge system is out ofservice for clapper valve replacement.
4B HHSI Pump is out ofservice for maintenance (repair of a casing leak).
MOV-536 (PORV Block Valve) has been closed due to PORV-455C leaking.
PRMS Channel R-15 is out ofservice due to a failed detector.
Midnight shift Chemistry reported high Spent Fuel Pit activity. Chemistry is resampling.
System Operations:
Demand on the System is moderate with anticipated peak of 16,500 Mwe.
Service area conditions are normal.
Meteorological Conditions:
Current temperature is 92'F, partly cloudy skies, winds are five to ten miles per hour from the east.
Forecast high temperature is in the mid to upper 90's and 20% chance ofrain.
3.1-1 CONFIDEHTlALUNTI02/1 I/99 99 EVALUhTKWLcvOXC/02/99
FLORIDAPOWER 8'IGHT COMPANY TURKEYPOINT NUCLEARPLANT 1999 EMERGENCY PREPAREDNESS EVALUATEDEXERCISE FEBRUARY 10, 1999
'xercise Summary The scenario begins with two plant tests in progress.
One test is the 3A Emergency Diesel Generator (EDG) Normal Start Test which was carried over from the midnight shift and the second test is the Local Leak Rate Test on the Unit 3 Containment Purge Exhaust valves (POV-3-2602 and POV-3-2603).
The first event ofthe day begins when a Chemistry Technician drawing a sample on the Unit 3 Spent Fuel Pit (SFP) trips and falls, causing a compound fracture of his arm. During the fall he spills the SFP sample on himself becoming a contaminated injured person. First Aid personnel respond to the scene. The injured person willrequire transport to an offsite hospital (simulated).
~
During the test ofthe Unit 3 A EDG, a fuel leak develops at the duplex fuel strainer, spraying diesel fuel on the engine. The Control Room willshut down the 3AEDG for repairs.
A short time later, the Control Room will receive a fire alarm in the Unit 3 Component Cooling Water (CCW) room. They willsubsequently receive a call confirming a fire adjacent to the 3B CCW pump. The Fire Brigade willrespond, but will be unable to gain control ofthe fire and willrequest off-site assistance.
An ALERT declaration should be made based on an uncontrolled fire potentially affecting safety systems and offsite support necessary.
Activation ofthe Emergency Response Facilities should be initiated at this time.
Not long after the fire, a flange leak develops on. the CCW line to the Containment Spray Pump (CSP) Seal Water Heat Exchangers. The water is spraying on the control switch boxes for both CSP motors. An operator will be dispatched in response to a Control Room annunciator for low flow to the CSP cooler. The operator willfind the leak and isolate it.
Minutes later, a previously unidentified crack in a pipe-to-elbow weld on the 3A Cold Leg begins to leak reactor coolant (RCS)
to the containment at approximately
g.p.m.
Within minutes containment atmosphere radiation monitor alarms and containment sump level increase. A controlled reactor shutdown willbegin within an hour, in accordance with plant Technical Specifications.
Within approximatelp one hour, the Fire Brigade reports the fire in the CCW room extinguished.
There is damage reported to the 3B CCW pump on the electrical cabling.
The RCS leakrate begins to increase. Additional Charging Pumps are started to maintain Pressurizer level. Containment coolers are limiting the increase in containment temperature and pressure.
The controlled shutdown coniinues but at an increased rate.
The RCS leakage increases to approximately 1600 g.p.m.,
exceeding Charging Pump capacity.
Operators attempt to trip the Unit 3 reactor but it fails to trip (Anticipated Transient Without Scram-ATWS).
3.1-2 CO'AFIDENTIALlJNTI 02/11/99 90 KVALUATEfVRcv0002/02/99
FLORIDAPOWER 8'IGHT COMPANY TURKEYPOINT NUCLEARPLANT 1999 EMERGENCY PREPAREDNESS EVALUATEDEXERCISE FEBRUARY 10, 1999 Conditions are in place for the Declaration ofa SITE AREAEMERGENCY, based on RCS leakage greater than 50 g.p.m. and greater than available Charging Pump capacity.
When the operators respond to the ATWS and locally trip the reactor, or when the ATWS Mitigation System Actuation Circuitry (AMSAC) trips the reactor, three Rod Control Cluster Assemblys
{RCCA's) stick out. The damaged fuel region ofthe core is releasing gas gap activity. Containment High Range Radiation Monitors increase, as do Containment temperature, pressure and hydrogen concentration.
The containment purge valves start to leak through due to increasing containment pressure.
Conditions are in place for the declaration of a GENERAL EMERGENCY, based on the following conditions: RCS'eakage greater than 50 g.p.m. AND RCS leakage greater than available charging pump capacity AND loss ofcontainment integrity which provides a flowpath to the environment.
PARS should be generated based on plant conditions. Field teams are dispatched to measure and track the plume. Emergency response teams continue to stabilize the reactor, verify safe shutdown and evaluate containment integrity.
Emergency Containment Coolers, Emergency Containment Filters, and Containment Spray (if returned to service) will have scrubbed and cooled the containment, reducing containment pressure and eliminating the leakage through the purge valves.
r The Exercise will be terminated when recovery actions are planned and Exercise objectives have been met.
3.1-3 CONFIDENTIALUh'11 02/I I/99
% EVALVATEDIRevOOCJOhpt
FLORIDAPOWER AND'LIGHTCOMPANY TURKEYPOINT NUCLEARPLANT 1999 EMERGENCY PREPAREDNESS NRC EVALUATEDEXERCISE FEBRUARY 10, 1999 3.2 SCENARIO TIMELINE TIME 0730 EVENTS EVENT P
Initial conditions establish Unit 3 operating at 100% power, in the middle ofcore life.
Unit 3 power history has been fullpower operation forthe last 180 days. Unit 4 is in Mode 5, Cold Shutdown.
Six-month Surveillance Testing is scheduled to be conducted on the containment isolation purge exhaust valves POV-3-2602 and POVr3-2603 and all administrative requirements are in place.
3-0SP-23.1, Section 7.1, 3A EDG Normal Start Test, is ready to begin. The pre-start alignment has been completed.
4B Hi Head Safety Injection (HHSI) Pump is out ofservice for maintenance.
U3 CCW Deluge System is OOS for clapper valve replacement.
MOV-536 (PORV Block Valve) has been closed due to PORV-455C leaking.
PRMS Channel R-15 is out ofservice, due to a failed detector.
Midnight shift Chemistry reported high Spent Fuel Pit activity. Chemistry is resampling Demand on the system is high, with an anticipated peak of 16,500 Mwe.
Service area conditions are normal.
Weather has been sunny and hot.
Forecast is for partly cloudy skies, temperatures in the upper 90's and occasional showers for the next four days.
Current temperature is 92', with winds from the east at 5 10 miles per hour.
0745 A Chemistry Technician pulling a SFP sample from SFP Hx Room, trips and fractures his arm, spilling the sample over him.
0800-During the performance of3-0SP-23.1, the 3A EDG fails,due to a mechanical failure (can be repaired in two to three hours).
0830
A fire alarm in the Unit 3 CCW Pump area, Alarm Point 28, comes into the Control Room. The Unit 3 Control Room activates the fire team to combat the fire. The fire impacts the 3B CCW Pump motor wiring conduit and motor filters, and takes out the 3B CCW Pump (minor damage to the wiring which can be repaired).
3.2-1 COYFIDENTIALIUNni.enid)
99.AFJREVO I/02/OW99
3.2 SCENARIO TIMELINE TIME EVENTS EVENT 0845 The fire team has arrived on the scene at the Unit 3 CCW Pump Area and finds a fire underway.
The fire team leader advises the Control Room that offsite fire support should be requested (simulated).
Conditions are in place for the declaration of an ALERT EMERGENCY based on an uncontrolled fire potentially affecting safety systems and offsite fire support is necessary.
Activation ofthe Emergency Response Facilities has been initiated.
0915 A flange leak develops on the CCW line to the Containment Spray Pump (CSP) Seal Water Heat Exchangers.
The water is spraying on the control switches for both CSP's. An operator willbe dispatched in response to a Control Room annunciator for low CCW fiowto the CSP cooler.
0920 A previously unidentified crack in a pipe-to-elbow weld on the 3A Cold Leg begins to leak reactor coolant to the containment at approximately 3 gpm. Within minutes, containment atmosphere radiation monitor alaims and containment sump level increases.
0930 The onsite emergency response facilities (TSC and OSC) should have been declared operational.
The technician performing the LLRT on POV-3-2602 and POV-3-2603 calls and reports that during the test the pressure regulator failed and overpressurized the annulus.
A loud "pop" >ms heard and the annulus depressurized.
POV-3-2602 appears to be offits closed seat.
0935 Operators and the STA have conducted RCS leakrate calculations using charging/letdown mismatch and containment sump levels increase.
RCS leakage is determined to be greater than the Technical Specification limitof 1 gpm unidentified leakage.
0940 A controlled reactor shutdown willbe initiated within the hour, per Tech Specs.
0950 The fire is out, but still smoldering.
1005 The cold leg RCS leakage increases to approximately 100 GPM (leak ramps up over
- 5 minutes).
Additional charging pumps are maintaining Pressurizer (PRZ) level.
Efforts to quantify the increase are initiated.
Containment coolers are limiting the increase in containment temperature and pressure.
Controlled shutdown continues (if already started) but is increased to 5% per minute.
1015 Increasing. leakage from the failed weld, to approximately 1600 GPM, exceeds charging pump capacity.
Operators will attempt to trip the reactor but it fails to trip (Anticipated Transient Without Scram-ATWS).
The EOF should have been declared operational.
3.2-2 CONFIDEh"rIAL(mmt. ci/nest)
99 AKIREVOI/02/02/99
3.2 SCENARIO TIMELINE TIME EVENTS EVENT 1020 Conditions are in place for declaration of a SITE'AREA EMERGENCY, based on RCS leakage greater the 50 gpm and greater than charging pump capacity.
When the operators respond to the ATWS and the reactor is tripped, three RCCA's stick out.
(SIMULATORNOTE -.05fuel damage ramped in over 5 - IO minures)
t Both buses transfer to the Unit 3 Startup Transformer and start all required ECCS Equipment.
1035
.The Post Accident Hydrogen Monitor is placed into service (needs to be - 30 minutes after SI).
1105 The damaged fuel region ofthe core is releasing gas gap activity. Containment High Range radiation Monitors (CHIUMs) increase sharply.
1120 Containment temperature and pressure increase (less than 20 psig).
Containment hydrogen concentration continues to increase.
CHIUMs indications are rising. The containment isolation purge exhaust valves POV-3-2602 (outside containment) and POV 3-2603 (inside containment) start to leak (leak through due to containment pressure).
Efforts begin to confirm containment status with the onset ofthe leakage.
Conditions are in place for the declaration of a GENERAL EMERGENCY, based on the following conditions: RCS leakage greater than 50 gpm AND RCS leakage greater than available charging pump capacity AND Loss of containment integrity which provides a flowpath to the environment.
Protective Action Recommendations (PARs)
should be generated on plant conditions.
1125 Readings on R-14 and the plant vent SPING increase as the release initiates.
Field teams should be dispatched to find the plume and PARs. should be upgraded based (if not already)
on significant core damage and the loss of containment integrity.
3.2-3 CONFiDENTlALrUNrii.mundi 99-AKIRKV01/02/02/99
.32 SCENARIO TIMELINE 1205
Emergency Containment Filters, Emergency Containment Coolers, and Containment Spray (ifrequired) have scrubbed and cooled the containment and the reduction in containment pressure is eliminating the release through the containment isolation purge exhaust valves POV-2602 and POV-2603.
Plant Vent radiation readings begin to decline.
Field monitoring activities continue.
The emergency response teams continue to stabilize the reactor, verify safe shutdown~
and evaluate containment integrity.
Discussions of recovery and reentry should begin as the release rate continues to decline.
1320 Recovery actions should be considered at this time with the identification of personnel for back shifts, possible de-escalation of the General Emergency, and logistical needs for continued operation ofthe facility.
1420 With the completion ofall State, local and utilityobjectives, terminate Exercise Play.
3.2-4 CONFIDEM1ALNmimime)
99.AEIREVOI/0RQ/99