IR 05000335/1996014
| ML17229A080 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 10/07/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17229A079 | List: |
| References | |
| 50-335-96-14, 50-389-96-14, NUDOCS 9610220080 | |
| Download: ML17229A080 (36) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50-335, 50-389 License Nos:
50-335/96-14.
50-389/96-14 Licensee:
Florida Power 8 Light Co.
Facility:
St. Lucie Nuclear Plant, Units
8
Location:
9250 West Flagler Street Miami, FL 33102 Dates:
August 4 - September 7,
1996 Inspectors:
M. Miller, Senior Resident Inspector J.
Munday. Resident Inspector D. Lanyi, Resident Inspector D. Starkey, Resident Inspector, Sequoyah, paragraph Rl. 1 C.
Rapp, Senior Reactor Inspector, paragraph El. 1 J. Coley, Reactor Inspector, paragraph M8. 1 Approved by:
K. Landis, Chief. Reactor Projects Branch
Division of Reactor Projects 9b10220080
'Pbi007 PDR ADOCK 05000335
i EXECUTIVE SUMMARY St. Lucie Nuclear Plant, Units
8
NRC Inspection Report 50-335/96-14, 50-389/96-14 This integrated inspection included aspects of licensee operations, engineer -.
ing, maintenance, and plant support.
The report covers a 5-week period of resident inspection.
~Qerati ons
~
The shift turnover process accomplished its purpose and was adequate.
One Non-Cited Violation was identified for fai lure to perform a control board walkdown as required by the Conduct of Operations procedure (paragraph 01.2).
~
Posted information which met the procedural definition of Operator Aids appeared to be adequately controlled.
However, other information postings which were identified as
"permanent information" did not receive periodic reviews and in at least two examples conflicted with instructions in approved procedures (paragraph 01.3).
~
Operators acted promptly and in accordance with procedures in commencing the Unit 1 downpower and, later, in tripping the unit.
Equipment
.
response to the trip was good.
The operator self assessment conducted after the trip was excellent.
An error in performing the post-trip review was identified and cor rected (paragraph 01.4).
~
Startup activities were conducted well and in accordance with approved procedures.
Actions of the Reactivity Manage and the Assistant Nuclear Plant Supervisor were responsible and timely in predicting an inability to achieve criticality in accordance with the applicable procedure (paragraph 01.5).
~
The licensee's actions were conservative and appropriate in declaring a
Notification of Unusual Event based on the inability to quantify charging pump packing leakage (paragraph 01.6).
Maintenance Haintenance associated with the Unit 1 linear power range detector
$9 was conducted correctly; however, more information was needed with regard to the control of measuring and test equipment for the activity reviewed, and an Unresolved Item was identified (paragraph H2. 1).
A review of completed work orders indicated that work scope control was appropriately managed f'r the population reviewed (paragraph M3.1).
A review of response time testing indicated that, while the subject procedure was weak in its 'detail, testing had been accomplished successfully in the past and that Technical Specification requirements were satisfied (paragraph M3.2).,
En ineerin
~
A review of Reactor Engineering activities during Unit 1 power ascension indicated that. while miswired nuclear instrumentation could have been identified sooner by trending of Axial Shape Index, it would not have been reasonable to expect trending of Axial Shape Index during Xenon free startups.
Reactor engineering identification of this problem during data analysis'nd subsequent followup with the responsible engineering group was a strength (par agraph El. 1).
~
The licensee's approach to the resolution of leakage from the 18 containment fan cooler was found to be in accordance with regulatory guidance (paragraph E2.2).
Plant Su ort
~
The practice of placing collection barrels outside of contaminated area boundaries was considered a poor practice which could result in spreading contamination into clean areas of the plant (paragraph Rl. 1).
~
The licensee reacted quickly to determine the cause of and to correct a
low flow condition associated with the Unit 1 containment radiation monitor; however, a more thorough and systematic method could have identified that a valve was left out of position (paragraph ER1.2).
i Summar of Plant Status Re ort Details Unit 1 entered the inspection period at 100 per cent power and remained at full power until August 23, when the unit was taken off line for turbine balancing.
The unit returned to full power operation on August 24 and remained at essentially full power until August 31, when the unit was manually tripped due to indications of'as buildup in the 1B main transformer.
The unit was brought to criticality on September 1 and was placed on line with only one of the two main transformers in service on September 5.
At the close of the inspection period, the unit was operating at 60 per cent power, limited by single transformer operation.
Unit 2 entered the inspection period at 100 per cent power and remained at essentially full power throughout the period.
I. 0 erations Ol Conduct of Operations 01. 1 General Comments 71707 Using Inspection Procedure No. 71707, the inspectors conducted frequent reviews of ongoing plant operations.
In general, the conduct of opera-tions was professional and safety-conscious; specific events and noteworthy observations are detailed in the sections below.
01.2 Review of Crew Relief/Shi ft Turnover 71707 Inspection Scope During this inspection period, a resident inspector from another plant was on site to assist the St. Lucie resident inspectors.
In the area of Operations, the inspector reviewed Administrative Procedure No. 0010120,
"Conduct of'perations,"
Revision 83, as it related to the shift turnover process, and attended several shift turnover meetings.
Observations and Findings On August 6, 1996, immediately after a crew relief/shift turnover meeting.
the inspector, who had attended the turnover meeting, questioned the on-coming Unit 2 operators as to whether they had performed a walkdown of the Reactor Turbine Generator Board (RTGB) as part of the shift turnover process.
One of the two on-coming operators stated that he had not performed a walkdown prior to assuming the shift.
The inspector then asked the Assistant Nuclear Plant Supervisor (ANPS)
whether a walkdown was expected of on-coming crews and was informed that each operator was expected to perform a RTGB walkdown as part of the shift turnover process.
Furthermore, Procedure No. 0010120, Revision 83,
"Conduct of Operations,"
Appendix C, required that on-coming control room watchstanders shall perform a walkdown of the RTGB The licensee initiated prompt action to discipline the operator involved and to reinforce to all licensed operators the expectations regarding shift turnover
.
The failure to perform a walkdown of the RTGB during a
shift turnover as required by Procedure No.
0010120 was a violation of the licensee's procedural requi rements and, as such, a violation of Nuclear Regulatory Commission (NRC) requirements.
However, due to the isolated nature of this violation and the licensee's prompt corrective action, this failure constitutes a violation of minor significance and is being treated as a Non-Cited Violation, consistent with Section IV of the NRC Enforcement Policy (Non-Cited Violation (NCV) 389/96-14-01,
"Failure to Perform an Adequate Pre-Turnover Board Walkdown").
In addition to the above observation, the inspector noted the following regarding the shift turnover process:
~
During one turnover, the control room was noticeably crowded, apparently with several trainees who were attending the turnover meeting.
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The Reactor Control Operator (RCO) with the desk responsibilities appeared to be more involved with administrative duties than with control duties.
~
One Senior Reactor Operator (SRO) trainee was observed resting a
clipboard on the RTGB handrail in close proximity to control switches and was not questioned or stopped by the on shift crew.
~
Crew members who were briefing during the turnover, in general, did not speak loudly enough to ensure that all those in attendance could hear what was being said.
Conclusions In general, the shift turnover process accomplished its purpose and was adequate.
One NCV was identified for fai lure to perform a RTGB walkdown as required by the Conduct of Operations procedure.
01.3 Review of 0 erator Aids 71707 a.
Inspection Scope The inspector reviewed Administrative Procedure No. 0010140, Revision 9,
"Control of Operator Aids," and inspected the posting of operator aids in various locations throughout the plant.
Observations and Findings On August 6, 1996. the inspector noted what appeared to be several uncontrolled operator aids posted in each of the diesel generator rooms.
Specifically, the aids were related to emergency starting the diesel generator s (DGs), starting and stopping the diesel driven air compressors, adding water to the engine radiator, and verifying proper
engine oil level.
The inspector determined that the Control of Operator Aids procedure defined those type postings as
"permanent information" and therefore they were not considered to be operator aids.
The inspector compared the instructions on the "permanent information" postings and determined that in two of the above examples the posted information conflicted with similar instructions in approved procedures.
First, the posted instruction for emergency starting the Unit 2 DGs did not agree with the steps in Procedure No. 2-EOP-99, Revision 13,
"Emergency Operating Procedure.
Appendixes/Figures/Tables,"
Appendix C,
"Diesel Generator Local Start."
Second, the posted instruction for starting and stopping the diesel driven air compressors did not agree with the steps in Procedure No. 1/2-2200050A/B,
"Emergency Diesel Generator Periodic Test and General Operating Instructions."
Prior to the end of the inspection period, the licensee had removed all of the subject informational postings in the diesel generator rooms with the exception of the air compressor starting/stopping information which was to be incorporated into Procedure No. 1/2-2200050A/B and which was labeled on the components as operator aids.
Conclusions Posted information which met the procedural definition of Operator Aids, as defined in Procedure No.
0010140 'ppeared to be adequately controlled.
However, other information postings which were identified as
"permanent information" did not receive periodic reviews and in at least two examples conflicted with instructions in approved procedures.
Unit 1 Manual Tri due to Transformer Gas Inleaka e
93702 71707
~40500 Scope On August 31, Unit 1 was manually tripped by control room operators in response to indications of gases collecting in the top of the 1B main transformer.
At 6:48 p.m., operators had received an annunciator indicating that a main transformer alarm panel (located outside the control room) was alarming.
An operator was dispatched to the scene and reported that a gas detector alarm was lit.
At 7:03 p.m., operators began a downpower per Off Normal Operating Procedure (ONOP)
No. 1-0910032.
Revision 11,
"Main Transformer Off Normal."
At 8: 18 p.m.,
operators tripped the reactor and turbine based upon indications that gas volume in the main transformer was increasing and upon the advice of transformer experts off-site.
The inspector followed the licensee's actions.
Inspection Findings The inspector responded to the site and found operators completing post-trip actions per the appropriate Emergency Operating Procedures (EOPs).
Control room conditions were quiet and professional.
The inspector
verified that major plant equipment had responded as designed and that reactor protection system trips had occurred as expected for the conditions.
Of particular note, the steam bypass and control system, which had been of questionable reliability in the past, appeared to operate very well, with traces for both reactor pressure and steam generator pressure and level indicating very minor transients.
The inspector attended a crew assessment of the event, conducted after shift turnover.
Positive and negative observations were made by the crew of its own performance.
The inspector found that crew participation in the assessment was good, with a free exchange of impressions and observations taking place.
The Plant General Hanager attended the meeting and provided positive feedback to the crew on their performance.
The process of crews critiquing their performance for significant operational events is a relatively new practice at the site, and appears to be an excellent method for obtaining operator feedback.
The inspector reviewed the post trip review package, completed on September 1 in accordance with Operating Procedure (OP)
No. 0030119, Revision 20,
"Post Trip Review."
In general, the process had been completed satisfactorily.
However, the inspector noted that Part 3.A,
was improperly completed.
Specifically.
the procedure included a table to be completed entitled "Other Reactor Protection System (RPS) Trips," which required that individual RPS trips be recorded and explained.
The inspector noted that the section had been filled out to indicate that no other trips had occurred.
In reality, after the manual trip was inserted.
a loss of load trip (expected upon turbine trip) and a Local Power Density trip (due to rapid changes in Axial Shape Index (ASI) as Control Element Assemblies (CEAs) inserted
- also expected)
was received in all channels of the RPS.
The inspector notified the NPS of the error, which was corrected.
Following the trip, the licensee obtained samples of the gas that had collected in the top of the transformer.
The gas was found to be air, indicating possible in-leakage to the transformer.
The lack of combustible gases (e.g.
hydrogen, acetylene),
combined with satisfactory results from oil analysis, indicated that no damage had occurred internal to the transformer
.
The licensee determined that one or more leaks must have existed in low pressure portions of the transformer, allowing air to be drawn in.
At the end of the inspection period, the licensee was attempting to locate and correct sources of leakage.
While touring the Unit 1 transformers and associated areas, the inspector noted that the area surrounding the Unit 1 turbine lubricating oil tank appeared to have a large amount of oil distributed over the ground.
The oil had discolored rocks used as surfacing in the area and was noticeable below the rocks in the sand.
The inspector questioned the licensee as to the source and acceptability of the oil.
The licensee produced Condition Report (CR) 96-1810, which documented the need to install a secondary containment around the turbine lube oil tank by December, 1999.
The need for the secondary containment was identified as Florida Department of Environmental Protection regulation
62-762.520,
"Performance Standards for Existing Field-Erected Storage Tank Systems."
The licensee stated that. at the time of construction, the lube oil tank was allowed to be installed directly over the ground, which allowed minor lube oil leakage from the lube oil demisters to accumulate in the area.
The licensee had dug a
sump in the area, which pumped a combination of rain water and lube oil to a lube oil separator for removal and treatment.
The inspector was satisfied that the licensee was addressing this issue in accordance with the requirements of state regulations.
Conclusions The inspector concluded that operators acted promptly and in accordance with procedures in commencing the Unit 1 downpower and, later, in tripping the unit.
Equipment response to the trip was good.
The operator self assessment conducted after the trip was excellent.
An error in performing the post-trip review was identified and corrected.
Unit 1 Startu 71707 Scope The inspectors observed portions of the Unit 1 reactor startup, conducted on September 2.
Findings Startup activities were conducted in accordance with Normal Operating Procedure (NOP) No. NOP-1-0030122, Revision 2,
"Reactor Startup."
Ouring the startup, the inspector verified proper RPS switch alignment.
proper preparation of estimated critical condition (ECCs),
and that operators were proceeding in accordance with procedures.
Procedurally.
the result of the ECC was an estimated critical boron concentration for an assumed rod height at the point of criticality.
Tolerances (+/-10 ppm) were placed on agreement between the ECC-generated critical boron concentration and actual Reactor Coolant System (RCS) boron concentration.
Step 3.E of Appendix E of the procedure included the restriction that the difference between the ECC and the boron reactivity worth of the RCS not exceed 125 percent millirho (PCM).
Star tup was commenced at 4:38 p.m.
Given the time since reactor trip on August 31, xenon concentrations were decaying at the time of the startup (adding positive reactivity to the core).
At approximately 5:25 p.m.,
the inspector noted that the period of validity for the current ECC was coming to a close and asked the reactivity monitor whether a new ECC was available.
The Reactivity Manager stated that a new ECC was prepared, but that Appendix E, "Reactivity Monitor Guidelines," of the startup procedure, allowed the startup to proceed even after the period of ECC validity had passed (the concern for ECC validity over time stemmed from the fact that, as xenon decayed, positive reactivity was being added to the core which necessarily changed the critical rod height for the approach to criticality).
At approximately 5:45 p.m.. the inspector reviewed the ECCs prepared for 5:00 p.m.
and 6:00 p.m.
and noted that the change in required boron concentration (due to xenon decay)
over the one hour period was approximately 110 pcm.
Concurrently, the Reactivity Manager reached the conclusion that. given the rate of xenon decay and the time required to reach a critical rod height, criticality could not be achieved before the 125 pcm limit was reached for the difference between calculated critical boron concentration and RCS concentration.
At 6:00 p.m., the Reactivity Manager and ANPS concluded that the startup must be terminated and a new ECC must be calculated and that a new RCS boron concentration must be established.
All regulating group CEAs were subsequently driven in to the 3 inch withdrawn position.
A new ECC was subsequently performed assuming a 9:00 p.m. time of criticality and boron was adjusted accordingly.
The second approach to criticality was commenced at 7:35 p.m.
Criticality was achieved without incident at 9:16 p.m.
Conclusions The inspector concluded that startup activities were conducted well and in accordance with approved procedures.
Actions of the Reactivity Manager and the ANPS were responsible and timely in predicting an inability to achieve criticality in accordance with the applicable procedure.
Unusual Event Declaration Due To Excessive Reactor Coolant S stem Leaka e On Unit
9370Z 71707 Scope On August 9, 1996, the Nuclear Plant Supervisor (NPS) declared an Unusual Event on Unit 1 when an RCS inventory balance indicated an unidentified leakage rate of 1.5 gpm.
Earlier in the shift, the Volume Control Tank (VCT) was being purged of fission gases in accordance with Operating Procedure No. 1-02100Z1, Revision 21,
"Volume Control Tank Hydrogen And Nitrogen Concentration Control," to increase the hydrogen concentration in the tank.
To accomplish this task, the VCT level was alternately raised and lowered in accordance with the procedure.
Upon completion of this activity, a routine inventory balance was initiated in accordance with Operating Procedure No.
1-0010125A, Data sheet 1,
Revision 5.
"Reactor Coolant System Water Inventory Balance."
The inventory balance measures the change over a period of time in the boric acid integrator, the primary water integrator, the VCT level, and the pressurizer level. which are the components involved in the addition or removal of RCS volume.
The results of the inventory balance indicated a leakage rate of 0.56 gpm and a second inventory balance was initiated.
The Senior Nuclear Plant Operator (SNPO)
was directed to inspect the Reactor Auxiliary
02.1 Building (RAB) for possible sources of leakage.
The inventory balance indicated that the RCS leakage rate had increased to 1.5 gpm.
Additionally, the SNPO reported that the 1A charging pump center plunger was leaking and the pump was subsequently secured.
Even though the only evidence of leakage was from the lA charging pump, the leakage rate from the pump could not be quantified.
Therefore, the NPS declared an Unusual Event based on unidentified RCS leakage.
exceeding 1 gpm, in accordance with site procedures.
In addition, a one hour emergency notification was made to the NRC in accordance with 10 CFR 50.72(a)(1)(i).
Another inventory balance was conducted over the following two hour period and indicated that with the lA charging pump isolated, the leakage rate had decreased to 0.42 gpm.
Based on this information the Unusual Event was terminated.
Findings The licensee initiated In-House Event Summary 96-067 and Condition Report 96-1952 to document the event and develop corrective actions.
The cause of the packing leak around the center plunger could not be conclusively determined but appeared to be due to wear.
However.
another CR, 96-1956, was initiated to investigate life expectancy of the packing.
The licensee concluded that the source of the leakage appeared to be due to the 1A charging pump packing leak and is investigating the possibilities of quantifying this leakage should it occur again.
Conclusions The inspector was in the Control Room during the event and concluded that the licensee's actions were conservative and appropriate based on the inability to quantify the charging pump packing leakage.
Operational Status of Facilities and Equipment En ineered Safet Feature S stem Walkdowns 71707 The inspectors used Inspection Procedure No.
71707 to walk down accessible portions of the following Engineered Safety Feature (ESF)
systems:
Units 1 and 2 High Pressure Safety Injection System (HPSI) Trains A and
Units 1 and 2 Low Pressure Safety Injection System (LPSI) Trains A and B
Units 1 and 2 Containment Spray Trains A and B
Equipment operability, material condition, and housekeeping were accept-able in all cases.
Several minor discrepancies were brought to the licensee's attention and were corrected.
The inspectors identified no substantive concerns as a result of these walkdown Operations Procedures and Documentation a.
Scope The inspector reviewed the completed version of Procedure No.
OP 1-1600023, Revision 59, "Refueling Sequencing Guidelines," which was employed during the recent Unit 1 outage.
b.
Findings The inspector found that the procedure had. in general, been adequately completed and documented; however, the following observations were made:
~
The procedure had undergone a number of revisions during its use.
The refueling began with Revision 59 to the procedure and ended with Revision 68.
~
In reviewing the procedure, a discrepancy in the logic flow of the procedure was identified.
Steps 8.29 (which installed the reactor vessel head per Appendix H of'he procedure)
and 8.30 (which verified an RCS vent path via the gas vent system (RCGVS))
appeared to have been performed after step 8.32 (which included actions to be taken to shift the RCS vent to the RCGVS from the Incore Instrument (ICI) flanges if the flanges were to be assembled at that stage).
The inspector reviewed Appendix H of the procedure and found that it included a verification that RCS integrity was established prior to exiting the appendix, which would have required that the ICI flanges be made watertight.
Consequently, it appeared that the procedure should have verified an appropriate vent path prior to the completion of the head installation (i.e. within the bounds of the appendix),
as opposed to after completion of the appendix.
As the procedure lacked detail on when to install ICI flanges, it did not appear that a violation of the procedure (working steps out-of-sequence)
occurred; however, the inspector found that the sequencing of verification of RCS vent paths could have been earlier in the procedure.
The inspector informed the licensee of this observation.
Conclusions The inspector concluded that the performance of refueling sequencing guidelines proceeded satisfactorily; however, the number of revisions required to the procedure during the course of the refueling indicated sequencing difficultie II. Maintenance Maintenance and Material Condition of Facilities and Equipment Unit 1 Linear Power Ran e Detector Re lacement 62703 Scope The inspector reviewed documentation associated with the replacement of the Unit 1 linear power range detector
$9.
This documentation consisted of Work Orders 95031787 and 96015967, Instrument and Control (18C)
Procedure No.
1200062.
Revision 5,
"Uncompensated Ion Chamber Acceptance Test," Condition Report (CR) 96-1565, and Quality Instruction (QI) 12.2, Revision 21, "Control And Calibration Of Measuring And Test Equipment (MEcTE)."
Findings During the most recent Unit 1 refueling outage, the licensee replaced this detector in accordance with Work Order 95031787 and applicable site procedures.
Prior to installation.
resistance and capacitance checks were performed on the detector, as well as a physical examination, in accordance with IBC Procedure No.
1200062.
The results were then compared to the manufacturer's acceptance test data with satisfactory results.
After the detector was installed it was similarly tested again, however the results of this test identified that the resistance values were lower than those identified in the pre-installation test and lower than the manufacturer 's test criteria.
The as-found values were 10" ohms with an acceptance criteria of 10" ohms.
CR 96-1565 was written to address this issue.
The CR resolution cited a vendor evaluation which concluded that the detector was acceptable for use.
During review of this documentation, the inspector noted that the megohmeter used during the post-installation test was different than that used during the pre-installation test.
I&C Procedure No.
1200062 required that a Hewlett Packard, model HP4329A.
megohmeter or equivalent be used.
During the pre-installation testing an HP4329A was used, however, during the post-maintenance testing a Biddle BM-10, M8TE item PSL-865, was used.
The inspector asked the licensee if this instrument was equivalent to the HP4329A.
The licensee provided the vendor manuals for the two instruments which indicated that when obtaining resistance readings the HP4329A was accurate,to within 10 percent of the indicated value and had a range up to 2 x 10" ohms.
The BM-10 was accurate to within 2 percent of the indicated value, however, its range only extended to 10" ohms.
The inspector questioned the use of the BM-10 to obtain the resistance measurement because the minimum acceptable value for this detector was beyond the range of the BM-10.
The licensee stated that this measurement had previously been taken with an HP4329A.
However, when
08.1
the values indicated low, in the 10" or less range, the readings were taken again with the BM-10.
The instrument was also preferred because it was battery powered making it more portable.
The licensee indicated that the results from the two instruments were the same.
The inspector requested the licensee provide the documentation identifying this series of events.
Additionally, a review of the usage log by the inspector identified that this particular BM-10 meter, PSL-865, had not been logged out for maintenance associated with Work Order 95031787.
The licensee initiated an investigation into this condition.
At the conclusion of this report period the licensee was collecting information to resolve this issue.
Pending a review of this additional information this item will be tracked as Unresolved Item (URI) 335/96-14-02,
"Control of METE."
Conclusions The inspectors'eview of the documents indicated that the maintenance associated with the Unit 1 linear power range detector ¹9 was conducted correctly, however more information was needed with regard to the control of %TE for the activity reviewed, and a URI was initiated.
Miscellaneous Operations Issues Closed Ins ector Followu Item IFI 50-335/96-11-01
"Ade uac of Root Cause Investi ation for Unit 1 Char in S stem Anomalies" Scope The inspector reviewed the resolution to CR 96-1792, which documented Unit 1 charging system anomalies which were documented in Inspection Report (IR) 96-11.
Two areas of concern were associated with this event; an automatic cessation of charging flow due to erroneous ressurizer level setpoint.
and waterhammer which was experienced when etdown was initiated.
Findings With respect to the cessation of letdown flow. the licensee determined that the cause was as described in IR 96-11 (erroneous backup charging pump selector switch position).
The inspector reviewed Procedure No.
OP 100210020, Revision 40,
"Charging and Letdown - Normal Operation."
and found that switch positions were suggested (connoted by the work
"should" ) in Step 8.5 for various combinations of charging pump operation.
Notwithstanding adequate guidance, the procedure was revised to include a table which described all possible permutations of operable and operating charging pumps with required backup pump selector switch positions for each.
With respect to the waterhammer event, the licensee concluded that a
waterhammer event was possible under the conditions at the time of the event, based upon elevations, temperatures.
and pressures associated
with the regenerative heat exchanger and associated piping and valves.
The licensee performed VT-3 inspection of the subject piping and associated pipe support and found no indications of damaged, per FTD-H-031, Revision 1, "Piping System/Support Walkdown And Evaluation Requirement Following An Unanticipated Transient Event".
Conclusions The inspector concluded that the licensee's investigation adequately identified the causes for both the cessation of charging flow and the reported waterhammer event.
Maintenance Procedures and Documentation Control of Work Sco e
62703 Inspection Scope The inspector reviewed twenty recently closed safety-related Work Orders from all disciplines to verify adherence to Administrative Procedure (ADM) No. 0010432.
"Control of Work Orders," particularly with respect to the control of work scope.
Inspection Findings The work orders reviewed were examined for agreement between the stated scope of work and the work described in the Journeyman's Work Reports attached to the completed work orders.
All were found to comply with the Administrative Procedure and no discrepancies between the work specified and the work performed were identified.
Conclusions The inspector concluded that work scope control was appropriately managed for the population reviewed.
RPS/ESF Res onse Time Testin 62703 Inspection Scope The inspector noted that CR 96-1570 had been generated documenting procedural weaknesses in 18C Procedure No. 1-1400053.
Revision 8.
"Reactor Protective and Engineering Safeguards System Response Time Testing."
Specifically, the preparer cited a lack of detail in that the procedure was prepared to perform response time testing generically, without specifications for actual component designations.
The inspector reviewed the subject procedure and records of previously performed response time tests.
The CR was resolved requiring revision to the procedur Inspection Findings The inspector reviewed the subject procedure and found that the CR accurately identif'ied weaknesses in specificity.
The procedure was prepared to direct the testing for any of four channels of RPS/ESF actuation channels without specifying actual component designations (e.g. for testing of pressurizer high pressure trips, the procedure specified that hydraulic test equipment be connected to the pressure transmitter for the channel under test.
not specifying the channel or the transmitter).
Similar lack of detail was noted in procedural requirements detailing the installation of electrical test equipment.
Technical Specifications (TSs) specify that components in one actuation channel be tested for response time every 18 months and that the channel being tested be alternated each time, such that all four channels are tested over a period of 72 months.
The inspector noted that the procedure did not provide a formal mechanism for determining which channel to test.
Rather.
the procedure required the personnel performing the test to specify which channel was to be tested.
The inspector reviewed records for the most recent four performances of the procedure on both units to ensure that all channels had been tested over a four fuel cycle period, as required by TS.
The inspector found that channel designation had been made appropriately and that the TSs were satisfied.
Conclusion While the inspector concluded that the subject procedure was weak in its detail, the review ot records from previous testing indicated that the test had been accomplished successfully in the past and that TS requi rements were satisfied.
The decision to revise the procedure to rovide greater detail was considered appropriate to the circumstances.
he surfacing and resolution of this issue was considered an example of good use of the corrective action process.
Miscellaneous Maintenance Issues Si nificance and Effect of Weld Volumes within American Societ of Mechanical En ineers Boiler and Pressure Vessel Code ASME Section XI A
endix VIII Su lement 4 and 6 Performance Demonstration Test
~Secimens Although the Authorized Nuclear Inspector (ANI) for Florida Power and Light (FPL) had approved single side weld examination techniques demonstrated by Southwest Research Institute (SwRI) at the Electric Power Research Institute (EPRI)
Non Destructive Examination (NDE)
Center, the inspectors had questions concerning single side weld access test parameters and examiner's per tormance that could only be addressed at the EPRI NDE center (see NRC Inspection Report 335/389/96-06 for further details).
On May 10, 1996, the inspectors and a representative from FPL visited the EPRI NDE Center in Charlotte, North Carolina, to review the performance demonstration examination results for the four Southwest Research Institute data analysts that would be used by FPL to examine the Unit 1 reactor vessel.
This review was necessary because FPL's Relief Request entitled,
"Request for Authorization of Alternative Examination Methods" had two alternative examinations proposed by the licensee that had changed since NRC had originally approved the relief request.
The relief request addressed Unit 1 reactor pressure vessel welds which had limiting conditions that prevented 100 percent examination coverage.
The first change was that the licensee had initially stated that a full vee 45'hear wave examination would be performed to the extent practical to compensate for recorded limitations.
However, SwRI examination procedures did not contain this examination method.
The second change to the April 1995 Relief Request stated that, FPL would employ, as they became available, additional examinations, inspections and/or techniques that would provide a substantial increase in the examination of areas currently missed under the current examination techniques.
To comply with thei r commitment to employ examination techniques that provide a substantial increase in the examination of weld areas currently missed.
FPL had SwRI qualify to the performance demonstration examinations conducted by the EPRI NDE Center for a single side weld access examination.
These examinations are to be conducted in accordance with Appendix VIII of later editions of the ASME Code.
The editions of the Code which include Appendix VIII have not been approved for use by NRC at this time.
The applicable ASME Section XI Code presently requires that a weld be examined from two di rections (both sides of a weld).
Therefore, to supplement the Unit 1 Reactor Vessel examinations with these new alternative techniques, the licensee invoked paragraph IWA-2240 of the applicable ASME Code which states that,
"alternative examination methods, or newly developed techniques may be substituted for the methods specified provided the ANI is satisfied that the results are demonstrated to be equivalent or superior to those of the specified method."
During the inspectors'isit to the EPRI NDE Center the inspectors identified that the qualification examinations given for one sided weld access examinations were conducted on test samples which did not have a
weld joint in them.
The inspectors were concerned that the demonstration test did not accurately depict plant conditions because there are acoustical differences between weld metal and base material which could effect the results of the examinations.
In addition, the differences in the lay of defect indications on far side of the welds had not been addressed by EPRI even in an analytical manner.
The EPRI p ttt tht, th
1 g
1d 1d t
k
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difference in the detection and sizing of indications in the carbon steel reactor vessel.
Although not disagreeing with EPRI. the
inspectors felt that the difference should be defined and factored into the difficultlyof the single side weld access performance demonstration test.
and actual reactor vessel examinations if necessary.
On Hay 13.
1996, the inspectors returned to the St. Lucie plant and the above issue was discussed with FPL licensing and NDE personnel.
As a
result of these discussions the licensee offered the following response to this item:
FPL Response:
"We contend that a weld is not necessary in carbon steel vessel material.
Because this is a completely isotropic medium which has minimal influence on the passage of ultrasonic waves.
We intend to prove this by the following:
As a member of the Performance Demonstration Initiative (PDI),
FPL has initiated action at the EPRI NDE Center to address the issue.
The PDI program was used to conduct the demonstration therefore it is incumbent of them to defend their position.
We expect them to produce empirical data from previous study or a demonstration to show that the presence of a weld in vessel material is insignificant.
OR/
The examination contractor (Southwest Research Institute) will look at producing similar empirical data form their studies.
If necessary.
will measure ultrasonic beam attenuation in similar material with and without a weld."
The licensee also stated they would assign a licensing No. to this item to insure that the issue is properly tracked and that a copy of the result, would be forwarded to the inspector.
On August 15, 1996, FPL provided the inspectors an August 8.
1996, letter from EPRI to FPL which addressed an evaluation conducted by EPRI to determine the significance and effect of weld volumes within ASNE Section XI, Appendix VIII, Supplement 4 and 6 performance demonstration test specimens.
The evaluation was conducted on a practice mockup.
The material for practice specimen was obtained from the nozzle course of the same vessel that was used for the PDI Pressurized Water Reactor (PMR) shell performance demonstration specimens.
To facilitate the evaluation, the original weld seam was identified by acid etch of the plate.
An EDN notch and a side drilled hole were fabricated in the specimen at appropriate positions (Note: specimen ID and reflector dimensions are not used in this report to protect the identity of PDI ractice and/or test mockups).
Ultrasonic measurements were taken from oth reflectors with the sound passing only through the plate material
and then with the sound passing through the plate material and the weld seam.
From the results obtained.
the EPRI NDE Center reached the following conclusions:
Comparison tor the attenuator/amplitude measurements from both the hole and the notch indicate the weld seam does not have any measurable effect on the amplitude of an ultrasonic reflector.
Plotting of the ultrasonic beam indicates the beam continues in a straight line and is not redirected by the weld seam.
The inspector considered actions taken by FPL and EPRI regarding the inspector's concern to be responsible and adequate.
This issue is considered closed.
III. En ineerin Conduct of Engineering Unit 1 Nuclear Instrument NI Wirin Errors 61702 Inspection Scope The inspector reviewed plant startup data to determine if the oppor tunity for earlier identification of Unit 1 miswired Nuclear Instrumentation System (NIS) drawers (discussed in IR 96-11) existed.
Findings and Observations The inspector reviewed the axial shape index (ASI) reading taken hourly during power ascension from each NIS channel.
The ASI data taken above 25 percent rated thermal power (RTP) showed that NIS channels A, C, and D trended more negatively indicating core flux was becoming more top peaked as power was increased.
However, the ASI data for NIS channel
trended more positively indicating core flux was becoming more bottom peaked as power was increased.
The licensee did not trend ASI during refueling power ascension because the core was essentially Xenon (Xe)
free.
Furthermore, the licensee had replaced the excore detector for NIS channel B at the same time the NIS drawers were replaced and was taking data during the power ascension to develop the shaping factor for this new detector.
In order to gather sufficient data, it was considered desirable to allow core flux to shift.
The licensee had installed a new real-time core performance monitoring system that used data from the permanently installed incore detectors to develop a three-dimensional core flux distribution.
Due to difficulties calibrating NIS channel D, the licensee relied on the real-time core performance monitoring system for monitoring ASI and thermal limit compliance as allowed by Technical Specification 4.2. 1.4.
However.
initially inconsistent incore flux maps results were obtained because the licensee had installed several new incore detector strings.
Once the errant detector strings were identified and the removed from input
i E2 E2.1
to the incore flux maps'he licensee used the incore flux maps to verify compliance with thermal limits during power ascension and calibrate the NIS channels.
The reactor engineering staff was not aware of the full capabilities of the real-time core performance monitoring system and the licensed operators had not yet received any training.
The licensee planned to provide operator training on this system.
but had not developed a
training schedule.
The reactor engineering staff was scheduled to receive further training on analysis capabilities.
Conclusions The inspector concluded that the ASI data clear ly indicated a difference in response between NIS channel 8 and NIS channels A. C, and D.
However, the replacement of NIS channel 8 detector, the lack of significant Xe buildup in the core.
and the use of the real-time core performance monitoring system reduced the necessity to trend indicated ASI.
This event could have been identified sooner by trending of ASI during power ascension..however it would not have been reasonable to expect trending of ASI during Xe free startups.
Reactor engineering identification of this problem during data analysis and subsequent.
followup with the responsible engineering group is a strength.
Engineering Support of Facilities and Equipment Embedded Board in Unit 1 Shield Buildin 37551 Scope The inspector noted that CR 96-1885 had been generated to document a
X 6 inch plank found embedded in the Unit 1 shield building.
The inspector reviewed the licensee's resolution of this issue.
Inspection Findings The inspector reviewed the engineering disposition to the subject CR.
The evaluation stated that the board had been removed from the concrete wall and that the depression was noted to be approximately 4 inches.
The board was presumed to have been in place since the construction of the building.
The evaluation further noted that no reinforcing bar was damaged or missing.
The reduced wall thickness resulting from the depression made by the board was evaluated against original missile protection criteria and found to be satisfactory.
The inspector reviewed this portion of the evaluation, and Unit 1 Updated Final Safety Analysis Report (UFSAR) section 3.5.2.2.
and agreed with the licensee's conclusion.
Plant Management Action Item (PHAI) 96-08-211 was generated to track a repair to be made to the depressio Conclusion
The inspector concluded that the licensee had appropriately dispositioned this issue.
Heatin and Venti latin Su
HVS -1B Coolin Water Leaka e
37551 Scope On August 26, the licensee identified a number of'ocalized pinhole leaks in a brazed joint at the component cooling water (CCW) supply to the 1B Containment Fan Cooler.
The leak was quantified at approximately 1.5 gph.
The licensee's engineering organization prepared evaluation JPN-PSL-SEHS-96-066,
"Operability Evaluation of Containment Cooling Unit HVS-1B Cooling Coil Leakage," to justify continued operation.
The inspector reviewed the subject evaluation.
Findings The inspector observed the leak during a containment entry and found the licensee's characterization of the nonconforming condition to be accurate.
The subject evaluation included a review of functions performed by the cooler, an analysis on the effects of the noted leakage on safety, an evaluation of the flaws'mpact on the structural integrity of the cooler, leakage impact on adjacent equipment.
and impacts on containment integrity.
The inspector compared the licensee's treatment of the issue to criteria established in NRC Generic Letter (GL) 91-18 and GL 90-05.
The inspector found that the licensee's operability decision was appropriate and that the requirements of GL 90-05 (for justification of continued operation with existing flaws in a moderate energy Class 3 line) were met.
At the end of'he inspection period, the licensee intended to perform a
non-code repair to the affected line (encapsulation of the affected area)
and to submit a request to the NRC for relief from the code.
In the interim, the licensee was performing augmented inspections (approximately every 3 days) of the leak to ensure that conditions were not degrading.
Conclusions The licensee's approach to the resolution of leakage from the 1B containment fan cooler was found to be in accordance with regulatory guidanc IV. Plant Su ort R1 Radiological Protection and Chemistry Controls (71750)
Rl. 1 Radiolo ical Housekee in 71750 a.
Inspection Scope The inspector walked down the RAB with specific attention paid to radiological postings, establishment of contamination area boundaries, and general radiological housekeeping.
b.
Observations and Findings During the week of August 5-9, 1996, the inspector noted the following examples of poor radiological and housekeeping practices.
~
Three examples were noted where barrels used to collect anti-contamination clothing were placed outside the contamination area boundary (Unit 1 Charging Pump Room 8, Unit 2 Charging Pump Room C.
and Unit 1 Equipment Drain Tank
& Pump Room).
In one example, the barrel was placed outside the contamination area and directly behind the step-off pad.
~
Bags containing contaminated trash were overflowing the contamination area boundary in the Unit 1 waste compactor room.
~
At the entrance to the Unit 1 decon room there were two step-off pads, one directly behind the other, separated by approximately eight feet.
It was not clear which step-off pad actually defined the separation between the clean and contaminated areas of the room.
Additionally the decon room was in poor housekeeping condition.
c.
Conclusions The practice of placing collection barrels outside contamination area boundaries was considered a poor practice which could result in spreading contamination into clean areas of the plant.
R1.2 Unit 1 Containment Radiation Monitor Ino erabilit 71750 71707 Scope On August 12.
1996, a
SNPO identified that the Unit 1 containment radiation monitor sample flow was low and the flow fault light was flickering.
The operator inspected the equipment and noted the pump to be running and the isolation valves to be open.
Operations entered Off-Normal Operating Procedure No. 1-1110035.
Revision 5, "Off-Normal Operation Of The Containment Chemistry Process Monitor," and notified Chemistry personnel to investigate.
Shortly thereafter, the Chemistry supervisor reported to Operations that a switch was mispositioned on the
Post Accident Sample System (PASS) panel which resulted in a low flow to the monitor.
It was subsequently realigned and the system properly placed in service.
Findings The licensee initiated Condition Report (CR) 96-1975 to document the event and determine corrective actions.
The subsequent investigation determined that earlier in the shift an operability check on the PASS system had been performed by two Chemistry technicians in accordance with Chemistry Procedure No. 1-C-112, Revision 16,
"Operation And Calibration Of The Hilton Roy Post Accident Sampling System."
The procedure required that the containment monitor be secured prior to performing PASS operations.
However, step 8. 1.33, requi red in part that when all samples had been taken, all valves were to be shut, PASS system and meters deenergized, and the containment radiation monitor pump restarted.
This step was signed as having been completed by the technician, however, the PASS system was not deenergized as required.
This resulted in isolation of the containment radiation monitor return line which rendered the system inoperable.
On August 13. the inspector and a Chemistry supervisor performed a field verification of'he procedure that was in progress at the time of the event and noted that it contained several steps which directed multiple actions, including the step that was improperly performed.
In addition, the procedure was not formatted consistent with other Chemistry procedures.
This was discussed with the supervisor who stated that all of the Chemistry procedures were in the process of being improved and that this particular procedure had not yet been revised to the new format.
The supervisor energized the PASS system to illustrate the process the technicians used when the mistake was made, however, the inspector noted that the supervisor did not use a procedure when doing so.
When questioned.
the supervisor stated that, while it was a good practice to use a procedure, the particular evolution was considered to be within the "skill of the craft" and was therefore acceptable to not have a
procedure in hand.
The inspector noted that the supervisor performed the steps properly and in the proper sequence.
In addition, he was extremely knowledgeable about the oper ation of the system.
The inspector later discussed this concern with licensee management who agreed that this evolution was within the "skill of the craft."
However, it was their expectation that a procedure would be used.
A statement to that effect was later distributed to all Chemistry department personnel.
After the panel was energized, the inspector noted that the switch controlling the outlet valve from the 1A Reactor Coolant Sample Sink, SE-05-5, was in the OPEN position rather than CLOSED which is the normal osition for this condition.
The supervisor determined that this switch ad also been mispositioned during the ear lier evolution and subsequently repositioned it accordingly.
CR 96-1991 was written to
document this error.
This valve being out of position did not affect the operability of the containment monitor but would have affected the ability to obtain an adequate PASS sample if needed.
At the conclusion of this report period, the inspector was reviewing additional information related to the procedure being used at the time of the event and overall procedure usage by the Chemistry technicians.
Pending a
complete review of this additional information, this item will be tracked as URI 335/96-14-03,
"Failure To Properly Align The Unit 1 Containment Radiation Monitor."
c.
Conclusion The licensee reacted quickly to determine the cause and to correct the low flow condition associated with the containment radiation monitor following the August 12 event.
However, a more thorough and systematic method could have identified the second valve, SE-05-5, also found out of position by the inspector
.
Further conclusions are pending review of additional data.
S1 Conduct of Security and Safeguards Activities S1.1 Tam erin Event 71750 93702 On August 14, the licensee identified three instances of tampering, involving glue which was injected into key lock switches in the hot shutdown panels of both units.
The NRC dispatched a special inspection team to review the event and to assess the licensee's actions in response to the tampering.
The results of the team's inspection are documented in IR 335/96-16 and 389/96-16.
V. Mana ement Meetin s and Other Areas Xl Exit Meeting Summary The inspectors presented the inspection results to members of licensee management on September 13.
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 identified.
PARTIAL LIST OF PERSONS CONTACTED Licensee W. Bladow, Site Quality Manager H. Buchanan, Health Physics Supervisor C. Burton, Site Services Manager R.
Dawson, Business Manager D. Denver, Site Engineering Manager R. Frechette, Chemistry Supervisor P. Fulford. Operations Support and Testing Supervisor
C. Harple, Operations Supervisor K. Heffelfinger, Protecti on Services Super visor J. Holt, Information Ser vices Supervisor H. Johnson, Operations Manager T. Kreinberg, Nuclear Material Management Superintendent J.
Marchese, Maintenance Manager C. O'Farrel, Reactor Engineering Supervisor A. Pawley.
Instrument and Control Maintenance Supervisor C. Pell. Outage Manager J. Scarola, St. Lucie Plant General Manager A. Stall, Site Vice President E.
Weinkam, Licensing Manager C.
Wood. System and Component Engineering Manager W. White, Security Supervisor Other licensee employees contacted included office. operations, engineering, maintenance, chemistry/radiation, and corporate personnel.
INSPECTION PROCEDURES USED IP 37551:
IP 40500:
IP 61702:
IP 62703:
IP 71707:
IP 71750:
IP 92700:
IP 93702:
Onsite Engineering Effectiveness of Licensee Controls in Identifying'esolving.
and Preventing Problems Surveillance of Core Power Distribution Limits Maintenance Observations Plant Operations Plant Support Activities Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED, CLOSED, AND DISCUSSED
~0ened 50-335/96-14-02 50-335/96-14-03 Closed 50-389/96-14-01 50-335/96-11-01 Discussed 50-335/96-11-06 URI URI NCV IFI URI
"Control of HSTE"
"Failure To Properly Align The Unit 1 Containment Radiation Monitor"
"Failure to Perform an Adequate Pre-Turnover Board Walkdown"
"Adequacy of Root Cause Investigation for Unit 1 Charging System Anomalies"
"Unit 1 NI Wiring Errors"
ADM ANI ANPS ASME Code ASI ATTN CCW CEA CFR CR DG DPR ECC EOP EPRI ESF FPL FR GL gph gpm HPSI HVS I8C ICI IFI IR JPN LPD LPSI M8TE NCV NDE NI NIS No.
NOP NOV NPF NRC ohm ONOP OP PASS PCM PDI PDR PMAI LIST OF ACRONYMS USED Administrative Procedure Authorized Nuclear Inspector Assistant Nuclear Plant Supervisor American Society of Mechanical Engineers Boiler and Pressure Vessel Code Axial Shape Index Attention Component Cooling Water Control Element Assembly Code of Federal Regulations Condition Report Diesel Generator Demonstration Power Reactor (A type of operating license)
Estimated Critical Position Emergency Operating Procedure Electric Power Research Institute Engineered Safety Feature The Florida Power 8 Light Company Federal Regulation
[NRC] Generic Letter Gallon(s)
Per Hour (flow rate)
Gallon(s)
Per Minute (flow rate)
High Pressure Safety Injection (system)
Heating and Ventilating Supply (fan, system, etc.)
Instrumentation and Control Incore Instrument
[NRC] Inspector Followup Item
[NRC] Inspection Report (Juno Beach)
Nuclear Engineering Local Power Density Low Pressure Safety Injection (system)
Measuring 8 Test Equipment NonCited Violation (of NRC requirements)
Non Destructive Examination Nuclear Instrument Nuclear Instrumentation System Number Normal Operating Procedure Notice of Violation Nuclear Production Facility (a type of operating license)
Nuclear Regulatory Commission Unit of Electrical Resistance Off Normal Operating Procedure Operating Procedure Post Accident Sampli'ng System Percent Millirho Performance Demonstration Initiative NRC Public Document Room Plant Management Action Item
PSL PWR QI RAB RCGVS RCO RCS RII RPS RTGB RTP SNPO SRO St.
Plant St. Lucie Pressurized Water Reactor Quality Instruction Reactor Auxiliary Building Gas Vent System Reactor Control Operator Reactor Coolant System Region II - Atlanta, Georgia (NRC)
Reactor Protection System Reactor Turbine Generator Board Rated Thermal Power Senior Nuclear Plant [unlicensedj Operator Senior Reactor
[licensed] Operator Saint Southwest Research Institute Technical Specification(s)
Updated Final Safety Analysis Report
[NRCj Unresolved Item Volume Control Tank