IR 05000335/1995022
| ML17228B389 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 02/05/1996 |
| From: | Landis K, Mark Miller NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17228B388 | List: |
| References | |
| 50-335-95-22, 50-389-95-22, NUDOCS 9602120034 | |
| Download: ML17228B389 (77) | |
Text
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900 ATLANTA,GEORGIA 303234199 Report Nos.:
50-335/95-22 and 50-389/95-22 Licensee:
Florida Power 8 Light Co 9250 West Flagler Street Miami, FL 33102 Docket Nos.:
50-335 and 50-389 License Nos.:
. Facility Name; St.
Lucie 1 and
Inspection Conducted:
,Decem Lead Inspector:
er Senior Resident Inspector 3,
1995 through January 6,
1995 5t igne Approved by:
R. Aeillo, License Examiner, and 2.8 '
R. Prevatte, Senior Resident S.
Sandin Senior Operations C.
i Re ctor Inspector,
>s, C
1e Reactor Projects Branch
Division of Reactor Projects Region II, paragraphs 2.2. 1 Inspector, Retired Officer,. AEOD Region II, paragraph 4. 1 e
igne Scope:
Results:
SUMMARY I
This routine resident inspection was conducted onsite in the areas of plant operations review, maintenance observations, surveillance observations, engineering support, plant support, review of nonroutine events, followup of previous inspection findings, and other areas.
Inspections were performed during normal and backshift hours and on weekends and holidays.
Plant operations area:
Walkdowns of the Unit 1 and 2 Auxiliary Feedwater Systems were satisfactory.
One example of poor logkeeping, involving the Unit 2 Key log was identified.
The restart of Unit 2 following a refueling outage exhibited good Reactor Engineering support, however, deficiencies were identified with the startup physics testing procedure.
The manual trip of Unit 2, due to high main generator gas temperature, showed alert operator action in an off-normal condition.
The inspector was impressed by the open'atmosphere which was established in the post-trip critique 9602i20034 960205 PDR ADOCK 05000335
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and the active participation of the operators.
The Operations Supervisor was effective in soliciting and facilitating the crew's critique of their own performance.
The inspector found the process to be highly effective in identifying areas for improvement.
One monitored FRG meeting suffered from lack of attendance by organizations with issues before the committee.
guality Assurance audits and assessments reviewed during the period were considered sound and well-focused.
Several examples of poor procedure temporary change control were identified and resulted in a non-cited violation.
Outage activities covered during the period,.including entry into reduced inventory conditions, the resolution of a leaking reactor vessel head 0-ring, and corrective actions for a failed reactor coolant pump seal stage were satisfactorily performed.
Overall, the increase in outage work scope provided a significant challenge on plant resources and scheduling.
'owever, the added work activities clearly indicated that plant management-was striving to address existing deficiencies and improve plant performance.
Haintenance area:
The inspectors noted good troubleshooting for a Steam Bypass and Control System valve which exhibited questionable subcomponent dimensions.
Issues relating to incore instrumentation flanges were satisfactorily resol'ved and preparations for the retermination of instrumentation leads indicated good worker knowledge and a cautious approach to the evolution.
The repair of limit switch fingers for a Limitorque motor operator was
.
satisfactory; however,a poor worker practice, involving sitting on safety-related ductwork, was identified.
Engineering area:
Review of the licensee's
CFR 50.59 Safety Evaluation Program revealed
'that adequate procedural guidance had been established for implementing the program requirements, A 10 CFR 50.59 training program was also being implemented for indoctrination and training in the requirements of 10 CFR 50.59 Safety Evaluations.
Work products reviewed were determined to have been prepared in accordance with the program requirements.
Additionally, the conclusions documented in most of the
CFR 50.59 safety evaluations were conservative and consistent with the inputs used in the analysis.
One deficiency involving the preparation of engineering evaluations concerning operability issues was identified.
Engineering Evaluations JPN-PSL-SENP-95-101, Revision 0, and JPN-PSL-SENP-95-103, Revision 0, failed to provide a documented level of detail sufficient to demonstrate validity of the conclusions reached concerning radiological consequences.
A potential violation involving failure of the Facilities Review Group to review a safety evaluation JPN-PSL-SENP-95-103 was identified but was subsequently resolved based on additional information provided by the licensee on December 18, 1995.
The inspector concluded that the licensee's engineering organization had provided timely support to the plant in resolving the SG level indication
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time lag problem.
Less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> elapsed between the unit trip and the resolution of the identified conditions.
Further, the conclusions reached regarding root cause were arrived at in a methodical and scientific manner and were validated in the field prior to acceptance.
Plant Support area:
Observations of Physical Security, Fire Protection, and Radiological Protection were satisfactory.
II Within the areas inspected, the following non-cited violation was identified associated with events reported by the licensee:
NCV 335,389/95-22-02,
"Failure to Properly Implement Temporary Change Controls," paragraph 2. REPORT DETAILS Acronyms used in this report are defined in paragraph 9.
1.0 Persons Contacted 2.0 2.1 2.1.1 Licensee Employees Ball, R., Mechanical Maintenance Supervisor
- Bladow, W., Site guality Manager
- Bossinger, L., Electrical Maintenance Supervisor
- Buchanan, H., Health Physics Supervisor
- Burton, C., Site Services Manager
- Dawson, R., Licensing Manager
- Denver, D ~, Site Engineering Manager Dyer, J.,
Maintenance guality Control Supervisor
- Fagley, H., Construction Services Manager Fincher, P., Training Manager Frechette, R., Chemistry Supervisor
- Fulford, P., Operations Support and Testing Supervisor Heffelfinger, K., Protection Services Supervisor
- Harchese, J.,
Haintenance Manager
- Olson, R.,
Instrument and Control Maintenance Supervisor Parks, W., Reactor Engineering Supervisor
- Pell, C.,
Outage Hanager
- Rogers, L., System and Component Engineering Manager
- Sager, D., St.
Lucie Plant Vice President
- Scarola, J., St.
Lucie Plant General Manager
- West, J.,
Operations Manager
- Wood, C., Operations Supervisor White, W., Security Supervisor Other licensee employees contacted, included office, operations, engineering, maintenance, chemistry/radiation, and corporate personnel.
Plant Operations Plant Status and Activities Unit
2.1.2 Unit 1 entered the inspection period at full power and remained at essentially full power throughout the inspection period.
Unit 2 Unit 2 entered the inspection period in Mode 5 as a part of an ongoing refueling outage.
Due to leaks associated with the inner 0-ring of the reactor vessel head, the unit was returned to Mode 6 on December 17.
Following maintenance on the 0-ring groove, replacement of the 0-ring and other maintenance activities, the unit
was brought to criticality on January 1,
1996, and was placed on-line on January 5.
On January 5, the unit was manually tripped due to high generator hydrogen gas temperature.
At the close of the inspection period, the unit was in Node 3.
2.2 2.2.1 Plant Tours (71707)
The inspectors periodically conducted plant tours to verify that monitoring equipment was recording as required, equipment was properly tagged, operations personnel wereiaware of plant conditions, and plant housekeeping efforts were adequate.
The inspectors also determined that appropriate radiation controls were properly established, critical clean areas were being controlled in accordance with procedures, excess equipment or material was stored properly, and combustible materials and debris were disposed of expeditiously.
During tours, the inspectors looked for the existence of unusual fluid leaks, piping vibrations, pipe hanger and seismic restraint settings, various valve and breaker positions, equipment caution and danger tags, component positibns, adequacy of fire fighting equipment, and instrument calibration dates.
Some tours were conducted on backshifts.
The frequency of plant tours and control room visits by site management was noted.
The inspectors routinely conducted main flow path walkdowns of ESF, ECCS, and support systems.
Valve, breaker, and switch lineups as well as equipment conditions were randomly verified both locally and in the control room.
The following accessible-area ESF system and area walkdowns were made to verify that system lineups were in accordance with licensee requirements for operability and equipment material conditions were satisfactory:
System Lineups/Area Walkdowns On December 5,
1995, the inspector performed a walkdown of the Unit
AFW system in.the CST area, AFW pump rooms, steam trestle area, and the Unit 1 control room and switchgear.
The walkdown was conducted in accordance with OP 1-0700022, Rev 34, "Auxiliary Feedwater - Normal Operation."
All valves and breakers inspected were found in the normal operating lineup as configured in the above procedures and the AFW P&IDs.
General and specific comments are itemized below.
The inspector noted that instrument isolation valves (both units)
are neither labeled nor required to be verified per 1(2)-0700022.
Furthermore, these instrument valves were neither checked nor required to be checked prior to performing OP 1-0700050, Rev 53,
"Auxiliary Feedwater Periodic Test,"'on December 5,, 1995.
The inspector reviewed AP 0010143, Rev 11, "Labeling/Tagging of Plant Equipment."
The procedure stated in paragraph 8.2.2.B. that instrument valves may be tagged at the discretion of the IKC
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Supervisor.
The inspector discussed the bases of the discretion exercised by the licensee in this case with the licensee, who stated that no policy describing why the valves were not identified was established and that the practice was under review.
P On December 7,
1995, the inspector performed a walkdown of the Unit
AFW system in the CST area, AFW pump rooms, and steam trestle area.
The walkdown was conducted in accordance with OP 2-0700022, Rev 36, "Auxiliary Feedwater Normal Operation."
Many valves were found out,of their normal operating lineup as configured in the above procedures due to the outage.
The inspector found that there were several valves, listed in the specific comments itemized below, that were not properly configured in accordance with drawing 2998-G-080, Sheet 2B, Condensate System.
Specific Comments:
Valves V09149, V09150, V09542, V09543, V09313, V09314, V09540, V09541, V09133, V09134, V09544, V09545, V09155, V09156, V09546, and V09547, were identified as LOCKED CLOSED valves in OP 2-0700022, Rev 36, "Auxiliary Feedwater - Normal Operation,"
and actually locked and closed in the plant.
However, P&ID 2998-G-080, Sheet 2B, Condensate System, did not reflect actual plant and procedure configuration.
V12829 (2C AFW Pump Suction PDIS-12-52C Upstream Isolation)
and V12830 (2C AFW PDIS-12-52C Downstream Isolation) were closed and capped on the P&ID but not in the valve lineup procedure (2-0700022)
or the plant.
fl V09513 (V09303 2C AFW Pump Recirc Downstream Vent)
was closed and capped in the plant but not on the P&ID or the valve lineup procedure (2-0700022).
.V09153 (PX-09-4B2 Isolation)
and V09154 (PX-09-3B2 Isolation) were CLOSED with no valve label or position tag attached.
They appeared to be replacement valves.
V08177, 2C AFW Pump Drain, was open as required by OP 2-0700022, however the P&ID list the valve as being normally closed.
The, inspector reported these conditions'o the licensee.
STAR 960004 and STAR 960003 weres generated to evalu'ate the above conditions.
The inspector had submitted the following deficiencies to the licensee as a result of a walkdown of the Unit 2 AFW system in July 1995 ( IR 95-14).
During this walkdown, the inspector checked the status of these previously identified items:
Nameplate identification was inconsistent with the description in the operating procedure.
This deficiency has been correcte OP 2-700022, Rev 35, "Auxiliary Feedwater Normal Operation" listed valves SE-08-1 and V08660 as located in the 2C AFW-pump room on the alignment of steam supply system when, in fact, they were in the 2A/2B AFW pump room.
This deficiency had not been corrected.
STAR 952146 was initiated to address this concern.
OP 2-700022, Rev 35, also listed valves V09149, V09150, V09542, V09543, V09313, V09314, V09540, V09541, V09133, V09134, V09544, V09545, V09155, V09156, V09546, and V09547, as being CLOSED only.
The actual configuration was LOCKED and CLOSED.
This deficiency has been corrected.
V09540 and V09541 were LOCKED CLOSED with no valve,label or position tag attached.
They appeared to be replacement valves.
This deficiency has been corrected.
2.2.4 ESFAS Cabinet Door Found 0 en P
On December 5, at approximately 1:00 pm, during a control room walkdown the inspector questioned an operator as to why Annunciator R-7,
"ENG SFGD CAB DOORS OPEN," was in alarm when all of the Safeguards Cabinet Doors appeared closed.
The operator explained that this particular alarm had been in since December 4 and was due a faulty limit switch on one of the Safeguards Cabinet Doors (SA, MA, MB, MC, MD or SB).
The operator jiggled each cabinet door handle and pushed the door to see if the alarm would clear.
In doing so, the operator discovered that the SA and the MC cabinet doors were unlocked.
A review of Appendix 8 Rack Key Log showed that key ¹114,
"Safeguard Cabinet,"
had been signed out and returned by an I&C technician performing instrument calibrations earlier in the day.
The operator informed the ANPS, signed out key ¹114 and locked the two open Safeguards Cabinet doors.
The operator identified. that one of the limit switches was stuck and initiated Work Request
¹95020468 for repair.
The inspector discussed the unlocked ESFAS cabinet doors with the Operations Supervisor who stated that he would investigate further and talk to the personnel involved.
STAR ¹952182 was issued on December 5 addressing this problem.
On January 4, the inspector retrieved from the Vault the completed and reviewed Appendix B Rack Key Log for December 5 and compared it with an in-process copy made on December 5.
The in-process copy showed various keys signed out and/or in with no reason provided in the last column of the table.
The copy retrieved from the Vault listed reasons in all cases.
The incomplete entries made on the in-process Appendix 8 Rack Key Log is identified as a logkeeping weakness, in that there was insufficient information indicating why the key was logged out until after the key was returne gl
- I PI
.2.3 2.3.1 The in'spector discussed this issue with the Maintenance Manager and I&C Supervisor.
The inspector agreed that this was an isolated incident involving personnel performance.
The licensee intends to implement corrective.actions involving training and shop briefings on good work practices.
The inspector noted that the safety significance of the loss of access control to the ESFAS cabinets was minimal due to plant conditions (Mode 5) at the time.
Plant Operations Review (71707, 93702)
The inspectors periodically reviewed shift logs and operations records, including data sheets, instrument traces, and records of equipment malfunctions.
This review included control room logs and auxiliary logs, night orders, jumper logs, and equipment tagout records.
The inspectors routinely observed operator alertness and, demeanor during plant tours.
They observed and evaluated control room staffing, control room access, and operator performance during routine operations.
The inspectors conducted random off-hours inspections to ensure that operations and security performance remained at acceptable levels.
Shift turnovers were observed to verify that they were conducted in accordance with approved licensee procedures.
Control room annunciator status was verified.
Except as noted below, no deficiencies were observed.
Unit 2 Reactor, Trip On January 5, at 4:36 pm, Unit 2 operators manually tripped the reactor and turbine when main generator cold gas temperature exceeded 52 'C (the limit allowed by plant procedure).
The cause for the temperature increase was the erratic operation of TCV-13-15, a temperature control valve which regulated TCW flow to the Unit 2 hydrogen cooling system.
The valve had been bypassed during startup and was placed in service (the bypass valve was manually shut)
immediately prior to the event.
The inspector responded to the site and found the unit stable in Mode 3.
While touring the control room at approximately 6:30 pm, the inspector noted the following tripped conditions with regard to the RPS:
"A" Channel Local Power Density Trip
"B" Channel SG Low Level Trip Loss of Load Trip Local Power Density Trip
"C" Channel SG Low Level Trip Loss of Load Trip Local Power Density Trip
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"0" Channel Steam Generator Low Level Pre-Trip (no trip)
Loss of Load Trip The inspector also noted that a control room SG Level Recorder indicated that SG "A" Level appeared to drop rapidly at the approximate point of the reactor/turbine trips and recovered quickly into a normal range.
The inspector questioned the RCO as to the reason for the reduction in indicated level.
The RCO had no explanation and appeared to have not noticed the indication.
The inspector questioned the NPS as to the RPS conditions noted above, with particular emphasis on the SG level trips and the lack of an "A" channel Loss of Load trip (the Loss of Load trip would have been expected, as the manual turbine trip would have resulted in a loss of DEH fluid pressure
- the parameter sensed by the Loss of Load trip pressure switches).
The NPS indicated that he had not-noticed the RPS conditions cited and reviewed available strip charts to verify that "A" SG water level had not varied as radically as was indicated (it had not).
2.3. 1. 1 Post-Trip Critique The inspector then attended a post-trip critique of the operating crew.
The meeting was focused on crew members critiquing their own performance and was facilitated by the Operations Supervisor.
Input from the crew resulted in a number of observations, including:
The evolution of placing TCV-13-15 in service should have been performed with greater diligence, as valves similar to this have been responsible for operational difficulties
,in the past.
More discussions should have occurred prior to the evolution and constant communications should have been employed.
The operator placing the valve in service noted that the valve was hunting when he left the scene (prior to the trip).
The crew felt that he should have reported the hunting to the control room and either remained until oscillations dampened or removed the valve from service.
~ 'perators who were dispatched from the control room to the valve when temperature conditions were identified tried to adjust the valve's setpoint in an effort to regain valve function.
They should have opened the bypass valve, effectively removing the valve from service, and adjusted cooling flow to restore acceptable gas temperature prior to addressing the errant valve.
In all, the inspector was impressed by the open atmosphere which was established in the post-trip critique and the active participation of the operators.
The Operations Supervisor was effective in
soliciting and facilitating the crew's critique of their own performance.
The inspector found the process to be highly effective in identifying areas for.improvement.
Root Cause Effort A
The observations made with regard to SG level indication were documented in STAR 960039.
The licensee's engineering organizations performed an analysis of the noted SG level indications.
Their efforts included a review of plant computer data (which provided a
more refined timeline) for level channels.
From this review, the following SG level transmitters were found to exhibit the phenomenon of a rapid reduction in indicated level, followed by a return to normal level indication:
LT-9013A SG 2A channel A level LT-9011 SG 2A level indication and recorder LT-9013C SG 2A channel C level LT-9023B -
SG 2B channel B level LT-9023C SG 2B channel C level (partial reduction)
LT-90230 SG 2B channel 0 level (partial reduction)
The licensee's troubleshooting considered electrical power fluctuations, Rosemount transmitter failure modes, SG tap location and sensing line geometries before concluding that the observed behavior was most probably caused by blockage"'in the sensing lines for the subject transmitters (blockage could have been in the form of foreign material or isolation valves which were not fully open).
The licensee theorized that sensing line blockage could create a
pressure response time lag between the SGs and the transmitters.
As the transmitters in question employed wet reference legs, any blockage of the sensing lines which did not similarly affect the reference legs would, in the case of rapid pressurization (e.g.
post-turbine trip) result in an unequal pressurization rate across the'ransmitters.
In such a case, the more rapid increase in pressure of the reference legs would result in an erroneously high differential pressure across the transmitters, interpreted electrically as low SG level.
Such a condition would then be indicated until the increased SG press'ure was transmitted through the sensing line blockage, at which time the pressurization would cancel out across the transmitters, leaving the SG level water column as the only remaining differential pressure across the transmitters and returning the transmitters to their original accuracy.
The licensee validated their theory by first verifying that sensing line isolation valves were fully open.
They then cracked open sensing line vent valves for selected transmitters and observed a
rapid reduction in indicated SG level.
The indicated level reduction implied that water released at the transmitter was,.not rapidly replaced (due to blockage),
thus increasing differential
pressure across the transmitter and resulting in an indication of low level.
The sensing lines were then blown down fully and a large amount of sludge was recovered (filtered) from the blowdown effluent.
Following the blowdown evolutions, cracking open the vent valves did not result in the previously observed reduction in indicated level, implying that the lines were free of time-delay-inducing blockage.
The licensee then conducted blowdowns of all SG level transmitter sensing lines.
The licensee's disposition of the STAR also considered issues of past SG level channel operability, analyzed potential sources of the blockage and considered the potential impact of the noted conditions on Unit 1.
Because the event occurred at the close of the inspection period, the inspector will review the balance of the licensee's conclusions in IR 96-01.
The issue will be tracked as IFI 95-22-01,
"SG Level Channel Inaccuracies Due to Sensing Line Blockage."
The inspector concluded that the licensee's engineering organization had provided timely support to the plant in resolving the SG level indication time lag problem.
Less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> elapsed between the unit trip and the resolution of the identified conditions.
Further, the conclusions reached regarding root cause were arrived at in a methodical and scientific manner and were validated in the field prior to acceptance.
Post-Trip Review The inspector reviewed the licensee's post-trip review package, prepared in accordance with OP 0030119, revision 19, "Post Trip Review."
The inspector had the following observations with regard to the package:
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The inspector found that data sheets had been completed per the procedure and that the SG level trips discussed above were noted.
However, the inspector found that the balance of the RPS trips received following the insertion of the manual trip (i.e.*Loss of Load, Local Power Density) were neither described nor dispositioned as expected RPS responses.
Several copies of strip chart recorder output were not labeled indicating which recorder (or which instrument channels)
was represented.
With regard to the inspector's observation that the "A" Loss of Load trip bistable was not illuminated, the licensee verified that the Sequence of Events Recorder showed that the trip had been received at the RPS.
Discussions with plant personnel resulted in an IEC Supervisor stating that he had reset the subject bistable some time after the trip.
He stated that he had come to the control room to observe the performance of the new NI system (for which he had
IL
2.5 maintenance responsibility and which share cabinets with the RPS)
and noted that the bistables had not been cleared.
He stated that he saw no reason why the bistables should not be reset, and began to do so before being told to stop.
The inspector pointed out that OP 0030119 stated that RPS trip unit indicating lights must not be reset until their status was noted.
While IEC personnel routinely perform switch manipulations at the RPS and other cabinets in the course of performing surveillance testing and calibrations, the inspector found the practice of personnel other that operators manipulating RPS switches to be, at the least, questionable.
The inspector conveyed this finding to the Operations Manager, who concurred with the inspector's concern and stated that he would speak with the individual involved.
In conclusion, the inspector found that operators were alert in manually tripping Unit 2.
The self-critique of the operating crew following the trip was found to be effective in identifying areas for improvement.
The root cause effort with regard to SG level trips received by the RPS was performed in a methodical and scientific manner and conclusions were validated in the field prior to acceptance.
The observed practice of a non-operator clearing a
reactor trip bistable at the RPS was considered a poor practice.
The post-trip review package failed to address RPS Loss of Load and Local Power Density trips received during the event.
Plant Housekeeping (71707)
Storage of material and components, and cleanliness conditions of various areas throughout the facility were observed to determine whether safety and/or fire hazards existed.
Clearances (71707)
During this inspection period, the inspectors reviewed the following
'agouts (clearances):
2-95-12-214 on charging pump 2C - This clearance consisted of five tags.
All tags were in place and all breakers and valves were in the correct position.
2-95-12-207 on CEDM fans HVE 21A/21B This clearance consisted of removal of the control power fuses and tagging open the breakers for both fans.
All tags were in place.
The fuses were removed and the breakers were in the correct position.
During a review.of the Unit "1 Equipment Clearance Log, the inspector noted that Clearance 1-95-12-046 for the HVE-8A Centrifugal Fan for Containment Purge System issued December 18, identified in the Safety Review section that an IV was not required.
The clearance involved verification'f the position of both HVE-8A and HVE-8B
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2.6 control switches as OFF and two tags on 480 VAC MCC breakers as OFF, all of which were IV'd, contrary to the safety review.
Although no violation of NRC requirements
. occurred, this inadequate safety review emphasizes the need for attention to detail on the part of operators and supervisors.
/
Technical Specification Compliance (71707)
Licensee compliance with selected TS LCOs was verified. This included the review of selected surveillance test results.
These verifications were accomplished by direct observation of monitoring instrumentation, valve positions, and switch positions, and by review of completed logs and records.
Instrumentation and recorder traces were observed for abnormalities.
The licensee's compliance with LCO action statements was reviewed on selected occurrences as they happened.
The inspectors verified that related plant procedures in use were adequate, complete, and included the most recent revisions.
2.7 2.7.1
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272 Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems (40500)
Facility Review Group Meetings The inspector attended the December
FRG meeting.
The agenda consisted of a review of procedure changes, jumper and lifted leads, and open Unit 2 STARS.
The STARS were reviewed to determine if they impacted the restart of Unit 2.
The meeting was chaired by the Manager of Plant Services and the membership consisted of the Supervisor of Reactor Engineering, who represented Operations, the 18C Supervisor, who represented Maintenance, the Manager of Licensing, and a guality Assurance representative.
The inspector noted that the majority of the issues were related to Operations and Engineering and felt that the meeting would have been much more beneficial if an Operations Supervisor and an engineering representative had been present during the discussions on the agenda issues.
Several questions were unanswered and had to be rescheduled for a later meeting.
f As described below, the licensee's gA organization had performed an assessment of FRG activities.
One observation/recommendation involved the lack of FRG attendance by organizations having issues before the FRG and the suggestion that those members attend such meetings.
In the case of the December 27 meeting, failure to heed the subject recomme'ndations resulted in the deferral of recommendations'he inspector concluded that the licensee was slow in implementing the noted recommendations.
Licensee Self Assessment
FRG Assessment The inspector=reviewed an assessment performed by the licensee's gA organization,and transmitted to the plant on December 18.
The-report reviewed FRG activities and benchmarked these activities against similar functions performed at Arkansas Nuclear One, Surry, and Turkey Point.
The assessment found that the FRG was fulfillingits responsibilities under TS to review issues and advise the Plant Hanager.
One weakness, involving the volume of material being reviewed by the FRG, was identified.- The number of documents requiring, FRG review per TS was noted as being larger than that at the three sites with which PSL was compared.
The assessment recommended that TS be amended to narrow the scope of FRG reviews to those activities directly affecting nuclear safety.
Other recommendations included:
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Revise the procedure development and review process to strengthen technical reviews and to combine TCs and PCRs.
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Establish a'procedure review committee, under the cognizance of FRG, to conduct procedure reviews.
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Reduce the backlog of FRG meeting minutes.
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Consider reducing FRG membership to add consistency to the review process.
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'istribute copies of all materials being reviewed to all FRG members to create parallel, rather than series, reviews during FRG meetings.
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Consider the desirability of conducting meetings with only a quorum present.
The assessment stated that the composition of the FRG at a given meeting should be reflective of the material being considered and that Operations, as
"owners of the plant,"'hould always be present.
Overall,.the inspector found the assessment to be insightful and appropriately self-critical.
The inclusion of a team member from Arkansas Nuclear One, and the visit to Surry, were considered good initiatives, Correc'tive Actions Assessment The inspector reviewed an assessment of Corrective Actions at PSL, conducted by the licensee's gA organi'zation and transmitted to the site on December 20.
The assessment was conducted in accordance with NRC Inspection Manual Chapter 4050 The The document identified a number of strengths and weaknesses.
weaknesses included:
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Trending which was insufficient to detect repetitive
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failures.
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STAR corrective actions which were generally narrow in scope.
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A high number of overdue STARs.
Generally ineffective training on the STAR program.
Strengths included:
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An aggressive approach to reduce the number of TCs.
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Aggressive followup on gA-initiated STARs V
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Thorough operability assessments for STARs
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Management involvement in problem-solving.
For each identified weakness, a series of options were recommended and a.final recommendation was made from among those offered.
The inspector found the assessment to be thorough in scope and effective at identifying and supporting weaknesses.
The licensee's gA organization continues to provide the plant with sound independent views on issues of concern.
gA Audit Review The inspector reviewed the corporate gA audit of the Nuclear Assurance guality Control Program dated December 6,
1995 of the Juno Beach, Turkey Point, and St.
Lucie plants.
the following comments are applicable to the St.
Lucie plant only.
Five audit findings applicable to St.
Lucie guality Control were identified in the report.
These items-included:
Discrepant conditions identified by gC inspections are not being documented as unsatisfactory and requiring documented corrective action.
Construction and Haintenance gC not performing all scheduled surveillance activities.
Inspection personnel using non-controlled documents to verify safety related replacement parts use.
NDE reports not receiving independent certified review f,
2.7.4
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guality procedures and instruction not maintained current
, with procedures and practice.
The report noted that the first two of the above items had resulted in a management perception of better performance than what really existed.
The inspector noted that specific corrective actions were required for each identified deficiency and that a 90 day deadline for that action was specified.
Overall, this audit appeared to be detailed and thorough and clearly documented to provide a good working document for improvement.
Temporary Procedure Changes 2.7.4. 1 Background The licensee, after experiencing several problems involving personnel errors and procedural compliance in August and September, implemented a station wide policy requiring verbatim procedural compliance.
As personnel attempted to follow procedures step-by-step to accomplish each task, numerous procedural deficiencies were identified.
This resulted in a large number of temporary changes to procedures to permit the completion of tasks until the procedures could be revised or rewritten as needed.
The inspector expressed a concern with the number of changes that were occurring and the licensee quality assurance organization conducted an audit of this program.
The audit found that the several hundred TCs generated on each unit was placing a serious administrative burden on operators to control and administer this process.
As a result of this audit, the following immediate and long term corrective actions were implemented to the TC process on December 1,
1995:
Immediate Corrective Actions:
~
All departments review TCs for conversion to PCRs or CANCEL.
(Due prior to Mode 2)
~
Any subsequent TCs approved shall include a
PCR unless the TC is a "One-time only" change.
(Due prior to Mode 2)
~
The FRG shall expedite PCR review.
~
The TC index will be consolidated concurrently by the team with the above efforts with the goal being a MINIMUMof TCs (reduce by 75 percent by Mode 2).
~
Non-unit specific procedures will have their own "common" TC log, kept in Unit 1.
(Due prior to Mode 2)
~
Hake the CANCELED TC distribution identical to the APPROVED TC distribution.
(Due prior to Mode 2)
t
~
Nake necessary changes"to gI 5-1 to incorporate above actions.
(Due prior to Node 2)
Hake Information Services accountable for TC ind'ex control.
(Due prior to Mode 2)
Long Term corrective actions:
~
'Provide CLEARLY PROCEDURAL DEFINED CRITERIA when a
procedure change is to be processed as a TC.
Any other procedure changes shall be considered as PCRs.
(Due January 31, 1996)
~
Consolidate the TC and the PCR process into one process.
Combine forms to allow for expeditious 'processing of PCRs along with TCs.
(Due January 31, 1996)
~
Eliminate Licensing from the distribution process.
(Due January 31, 1996)
Procedurally limit maximum number of TCs to three (3) per procedure or one (1) per page.
(Due January 31, 1996)
Establish the interface between TCs and gI 6-1.
(Due January 31, 1996)
~
Revise gI 5-1 to better define the overall process and accountability associated with procedure changes.
(Due January 31, 1996)
~
Benchmark against other utilities.
(Due January 31, 1996)
Based on the above, it appeared that the licensee had implemented changes in an attempt to address the large number of procedure changes that have been required to implement verbatim procedural compliance.
The majority of these changes have been helpful, but additional management and supervisory attention is still needed to effectively resolve this issue.
2.7.4.2 Failure to Incorporate TCs in Working Procedure Following maintenance performed on December 20, the inspector.
reviewed the work package containing the Maintenance and Post Maintenance Test Procedures.
HP-09400775 (describing the subject maintenance work) had 2 TCs in the work folder which were not incorporated into the working procedure:
Both TCs were identified as procedural improvements.
TC 81-95-538 allowed for performance of steps out of sequence and TC tl-95-565 required verification of field wiring deficiencies be documented in the PWO.
The worker who signed off the procedural steps was aware of these TCs and acknowledged that both needed to be incorporated.
The inspector reviewed gI-5-1 Rev 67, "Preparation, Revision, Review/Approval of
-I fi
Procedures",
and discussed this item with the worker the following day.
This worker said that, as a member of the Electrical Planning Department, working procedures are issued with the TCs incorporated and that, in this particular instance this was not done due to an oversight.
Further.,
he had missed incorporating the applicable TC prior to performing the maintenance.
gI 5-PR-PSL-I, Rev 67, "Preparation, Revision, Review/Approval of Procedures,"
Section 5.9.28, stated that "Personnel using procedures affected by temporary changes shall use the TC number(s)
to locate and review the actual temporary change, filed in the TC log book.
If the change pertains to the portion of the procedure being used, the change shall be made by lining through the affected portion and adding the temporary change.
The temporary change shall be noted by writing the TC n'umber in the margin next to the affected area."
The failure of the maintenance worker to properly incorporate the subject TCs was a violation of the requirements of gI 5-PR-PSL-1 and is further discussed in paragraph 2.7.5 below.
2.7.4.3 Failure to Remove Expired TCs From TC Logs The inspector audited the TC logs in Unit
and Unit 2 control rooms on December 26, 1995.
The Unit 2 TC logs were satisfactory.
The Unit 1 log index contained a number of TCs that had exceeded the
day expiration date, as follows:
TC 1-95-310 1-95-334 1-95-338 1-95-342 1-95-350 1-95-364 1-95-365 Date Initiated 9-19-95 9-22-95 9-22-95 9-22-95 9-26-95 9-26-95 9-26-95 The inspector informed the ANPS of these deficiencies and the ANPS stated that he would cancel the TCs that had expired.
The inspector reviewed these logs again on the morning of December 27 and found that TC 2-95-205 (which had been initiated on 9-19-95)
had not been canceled.
The inspector informed the ANPS of this and observed him cancel the TCN.
gI 5-PR-PSL-1, Rev 67, "Preparation, Revision, Review/Approval of Procedures,"
Section 5.9.25, stated that TCs expired 90 days after authorization and required that the ANPS/NPS initiate a cancellation upon expiration.
The failure to cancel the above TCs is a violation of the subject procedure and is further discussed in paragraph 2.7.5 belo ft l1 l,
The inspector questioned whether or not PCRs had been prepared to incorporate the subject TCs into procedure revisions.
The results were as follows:
~
TC 1-95-310 had no PCR prepared.
A PCR was subsequently generated.
~
TCs 1-95-334, 1-95-338, and 1-95-342 had PCRs prepared and were incorpora'ted into procedure revisions on December 21.
The inspector noted that revision 67 of gI 5-PR-PSL-1 became effective on December 8, 1995.'his revision required PCRs to be submitted to the FRG at the same t'ime as the subject TC.
Prior to this requirement, no time frame was established by which PCRs should have been submitted following a TC.
As a result, the inspector concluded that the failure to prepare PCRs for the subject TCs, and to have them in force prior to the'xpiration of the TCs, was not in expl'icit contradiction of the subject gI; however, the inspector found the practice weak and counter to the intent of ensuring that adequate procedures were available and up-to-date.
Failure to Remove Expired TCs From HSPs On December 29, the inspector reviewed the, procedures maintained in the Hot Shutdown Panel rooms for both units.
This review consisted of a verification of the current revision and incorporation of effective TCs.
The following discrepancies were noted:
~
OP 1-0030127, Rev 72, "Reactor Plant Cooldown - Hot Standby to Cold Shutdown" had 5 TCs written on previous Rev 70.
These included:
TC 1-95-403 TC 1-95-392 TC 1-95-401 TC 1-95-402 TC 1-95-421 issued September
issued September
issued September
issued September
issued October
A review of the TC Log index maintained in the Unit 1 control room did not contain any reference to the above TCs which implied that they had been canceled.
It was currently the practice to transcribe the active index entries to a new index sheet following numerous cancellations to minimize paperwork.
An employee in the Information Services Department responsible for making controlled distribution of this procedure showed the inspector a memo dated'ecember 7,
'canceling three of the five above TCs.
He also acknowledged that he had overlooked removing canceled TCs from the Hot Shutdown Panel rooms.
The remaining two TCs were verified canceled using a list of active TCs provided by the Licensing Department.
~
OP 2-0030127, Rev 61, "Reactor Plant Cooldown Hot Standby to Cold Shutdown,"
had 2 TCs; one written on the
previous Rev 58 and the other on the current Rev 61.
These were:
TC 2-95-228 issued October
TC 2-95-643 issued December
2.7.5 A review of the TC Log index maintained in the Unit 2 control room showed that both of these TCs were active, however, TC 2-95-228 had been incorporated in the procedure.
The ANPS canceled this TC.
gI 5-PR-PSL-1, Rev 67, "Preparation, Revision, Review/Approval of Procedures,"
Section 5.9.26, stated that TCs were to be removed from documents upon notice of cancellation or after 90 days, whichever comes first.
The failure to remove the canceled TCs, detailed above, was a violation of'th'e subject procedure and is further discussed in paragraph 2.7.5 below.
Conslusion 2.8
.2.8.1 On January 2, the Information Services Manager met with the inspectors to describe the licensee's efforts to address the lack of effective TC control.
He intended to propose that all TCs be incorporated as PCRs within 14 days of the date of issue.
He further identified the failure to remove the canceled TCs from the-HSP as a personnel performance issue.
The inspector noted that the deficiencies identified above were addressed gen'erically in the licensee's corrective actions for the identified problem of TC control.
Additionally, the inspector noted that, at the time the deficiencies were identified, the Mode
closure point of the licensee's short term corrective actions had not been reached.
The inspector concluded that the identified deficiencies represented only minor safety concerns.
Consequently, the instances of failing to follow gI 5-PR-PSL-1 are considered examples of a violation of minor 'significance and is being treated as a Non-Cited Violation, consistent with Section IV of the NRC Enforcement Policy (NCV 335,389/95-22-02,
"Failure to Properly Implement Temporary Change Controls" ).
The noted conditions highlight the need for increased management attention to procedure issuance and change control.
Outage Activities (71707,71750,62703)
Outage Work Scope The inspector reviewed the overall outage work scope to determine if the planned critical work had been completed; if any needed work activities had been canceled; and to determine the status of emergent items.
The following was identified:
Planned outage activities 3317
l
~
Completed work activities 7118
~
Activities added after (outage freeze date and emergent)- -
3801
~
PCMs planned
~
PCMs completed
95
~
.
PWOs added (emergent and backlog reduction)
1486
~
STARS completed 282 The above shows that outage activities experienced a
115 percent increase.
This was primarily due to the increase in outage scope and work to address the problems identified by plant management after the Unit 1 unplanned outage.
This action was taken to reduce
~ existing operator workarounds, long term equipment problems, and other plant deficiencies. 'his work should result in improved plant performance.
The inspector also found that 54 planned work activities had been canceled.
A review of each of these items with the outage manager and the assigned department found that these cancellations were adequately justified based on:
incomplete design, lack o'
parts/material, or inadequate resources.
In each case, the work had been rescheduled for either on-line maintenance or the next scheduled outage.
The inspector determined that this delay in completion was justified'verall, the increase in outage work scope provided a significant-challenge on plant resources and scheduling.
However, the added work activities clearly indicated that plant management was striving to address existing deficiencies and improve plant performance.
Containment Closeout (71707)
The inspector conducted a walkdown of Unit 2 containment with gC on December 7,
1995.
The inspector visually inspected containment housekeeping, component and instrument conditions, storage of equipment and material, pipe hanger and seismic restraints, breaker and instrument covers, and the reactor cavity torpedo tubes.
The inspector" was only able to perform a visual inspection of the top grading of the containment sump area due to inaccessibility.
The following discrepancies were gC and NRC identified:
~
A pair of dikes was found on top of 2A SG undergrading.
~
There was a barrier a~ound the Hydrogen Recombine ~
The insulation was damaged on the V1239 line located on top of the pressurizer'all.
~
A power. receptacle on the 43',
330 degree azimuth was missing a cover.
~
A keyway channel
"D" liner box was missing on the 18'evel.
The biowall radio. wire was still installed.
removal and cover reinstallation.
Many of the HP postings were still hung.
I-95 scaffolding was still on the RV head.
It required Head sets, lights and cables were still on the RV head.
~
Cannon plugs were still on the refueling machine.
~
The torpedo tube bolts were not secured.
~
The Woodhead cover was missing on the polar crane catwalk (east side).
~
There were 2 conduit clamps that did nothing (located on PC walkway far end).
~
JPN strain computer cables for pressurizer SRV were still attached.
While deficiencies existed, the inspect'or noted, that the number of deficiencies was decreased over previous containment closeout walkdowns,'indicating an increase in the effectiveness of the licensee's cleanup effort.
Unit 2 Reduced Inventory Operations (71707)
On December 16, Unit 2 entered a reduced RCS inventory condition to support 2A2 RCP seal work and several other miscellaneous valve repairs.
The following items were verified prior to this evolution:
Containment Closure Capability - Instructions were issued to accomplish; men and tools were on station.
The only containment openings were valve 3259 on SIT 2A2 fill line that could be open during maintenance on LPSI A header, the equipment and personnel hatch.
The inspector verified that personnel were assigned with specific duties to close these penetrations for containment integrity.
RCS Temperature Indication - The inspector verified that two CETs were available for indicatio RCS Level Indication - The inspector verified that independent RCS wide and narrow range level instruments, which indicate in the control room, were operable.
An additional Tygon tube loop level indicator in the containment was to be manned during level changes and was displayed via closed circuit television in the control room.-
The inspector verified that the tygon tube was free of obvious kinks and properly supported.
~
RCS Level Perturbations When RCS level was altered, additional operational controls were invoked.
Procedural restrictions required operators to terminate maintenance activities that could affect RCS level, shutdown cooling, or related ins'trumentation and controls.
~
RCS Inventory Volume Addition Capability - The inspector verified that one (of three)
charging pumps and a HPSI pump were available for RCS addition.
~
Vital Electrical Bus Availability - Operations'ould not release busses or alternate power sources for work during reduced inventory conditions.'he 1A and 1B EDG were operable.
Governing procedures prohibited switchyard work during reduced inventory conditions and signs were posted to that affect at the switchyard.
~
Pressurizer Vent Path The manway atop the pressurizer was removed to provide a vent path, and a vented FHE device was attached.
The inspector reviewed AP 0010145, Rev 7,
"Shutdown Cooling Controls,"
and OP 2-160023, Rev 38, "Refueling Sequencing Guidelines,"
and found that initial conditions either were satisfied at the time of the review or could be satisfied by the time inventory reduction commenced.
The inspector completed the above verifications on the morning of December 16 and notified the Regional Duty Officer of these conditions.
He also attended the control room pre-evolution briefing and was in the control room during the drain down to reduced inventory.
The briefing was detailed and thorough and attended by operators and by outage personnel.
Overall preparations for this evolution were considered excellent.
The inspector conducted routine inspection while the unit was in reduced inventory to ensure that all the above conditions were maintained.
No deficiencies were identified.
The 2A2 seal was replaced, the other valve repairs were completed, and the unit exited reduced inventory at 10:00 pm on December 1 It
2 1 2.8.4 Reactor Head 0-Ring and RCP Seal Leaks Delay Restart The Unit 2 RFO was originally scheduled to end in late November.
Due to added outage work, the majority of the outage work was not completed until second week of December.
When the RCS was pressurized, the unit experienced a small amount of leakage past the reactor vessel head inner 0-ring.
Since this was a self energizing O-ring, a decision was made to monitor this condition and raise the RCS to NOP/NOT.
After starting RCPs, the licensee-also found that the lower seal on RCP 2A2 was experiencing excessive leakage.
A management decision was made to monitor the leakage of both the above and continue RCS heatup and pressurization to NOP/NOT to check for leakage of any other components and then 'cooldown, depressurize, and repair all existing leaks.
This testing revealed leaks in se'veral other valves that required repair.
The unit was cooled down and entered Mode 5 on December 16, and Mode 6 on Decemb'er 17.
The unit entered reduced inventory on December
and replaced the 2A2 RCP seal.
The reactor vessel head was removed and inspection revealed pitting in the 0-ring seating surfaces.
The pitted areas were inspected by the licensee, CE, B&W, and a
representative of the 0-ring manufacturer.
The maximum pitting depth was approximately
.005 inches,'so a decision was made to hone these areas by hand to reduce the imperfections to permit an acceptable sealing surface.
Engineering and maintenance developed a
plan to do this work with the assistance of a vendor who had personnel available on site.
The work was planned to start on December 20.
The inspector attended several'of the meetings where this work was discussed in detail.
The inspector also attended the. prejob briefing held on December 20.
At this meeting it became very apparent that HP and maintenance had not completed adequate planning to allow the start of this task.
Some of the planning deficiencies identified included:
II
~
No specific manager assigned to this critical path job.
No specific guidance on how the honing was to be done.
No criteria for radical or circumfrential dimension and-depth of the honed and blend-in areas.
Dress out requirements and exposure limits had not been
, determined.
No specific inspection criteria or inspection personnel assigned.
Engineering involvement and availabilit ~,
fI
~
Radiation shielding requirement not predetermined.
~
Lighting'requirements.
~
Specific work procedure not developed.
~
Had not decided if one location would be weld repaired or honed.
After listening to the discussion for approximately one hour, the inspector reported his concerns to the maintenance manager, who stopped the prejob briefing and assigned a manager to this job.
The job was replanned and worked the following day.
The licensee was able to hand hone all indications in the 0-ring seating surface to an acceptable level of less than 0.002 inches.
This appears to be adequate to prevent leakage'ast the seal.
The reactor head was then set on December 22 and the unit entered Node 5 on December 23.
The licensee's root cause analysis of the reactor vessel head and flange pitting determined that it was a result of crevice corrosion, most probably due to the introduction of contaminants to the groove during refueling outages.
2.8.5 RCP 2A2. Seal First Stage Failure During Unit 2 RCS pressurization on December 9, the licensee discovered that RCP 2A2 first stage seal had failed.
The seal was replaced on December 16 and 17.
The seal had been previously replaced during the current refueling outage.
The licensee was concerned about this failure, and a root cause team was established to investigate and evaluate this item.
This team found that the root cause of the seal first stage failure was a rapid depressurization of the RCP middle seal cavity pressure.
The team came to this conclusion after a detailed examination of ERDADs data and the RCO chronological log.
The following scenario is the licensee's explanation of the first stage seal failure:
Hechanical Maintenance installed the new 2A2 RCP seal sometime on the morning or early afternoon of November 29, 1995.
RCS integrity was established which allowed Operations to raise the RCS level in accordance with OP 2-0120020, "Filling and Venting the RCS."
This portion of the fill and vent procedure aligned seal injection to the RCP seals to.alleviate the possibility of damaging the seals with "dirty" water.
Operations started and stopped the 2A charging pump three times during the evening of November 29, 1995, between
9:00 pm and 10:38 pm', with seal injection aligned to all four RCPs.
'uring the first two starts of the 2A charging pump the 2A2 RCP pump was still uncoupled'orm the motor.
The ERDADS data suggested that the 2A2 RCP was coupled between the second and third starts of the 2A charging pump (i.e.
between 9:51 pm and 10:30 pm)
as the pump was started three times and only two pressure spikes appeared on the ERDADS graphs.
ERDADS data for the other three RCPs was reviewed with no indications of any pressure changes while the 2A charging pump was running.
The RCP recirc impeller
, located at the bottom of the seal cartridge housing is a
metal to metal fit designed to hold 20 psig from the RCS to the seal cartridge housing.
In some cases the recirc impeller may leak slightly due to lodged particles at the fit.
With the recirc impeller seated, the seal injection water pressurized the middle, upper, and bleedoff cavities of the 2A2 RCP seal and assisted in seating the recirc impeller in the bottom of the seal cartridge housing.
ERDADS data showed that the middle cavity pressure increased to at least 150 psig on two occasions.
At this point one of two'hings occurred:
When the 2A charging pump was secured the recirc impeller leaked slightly and the static head pressure and the pressure increase by the 2A charging pump caused a reverse pressure condition on the 2A2 RCP seal.
OR When the pump was coupled (and the recirc impeller lifted off its seat)
the static head pressure and the pressure increase by the 2A charging pump caused a
reverse pressure condition on the 2A2 RCP seal.
~
A reverse pressure condition on an RCP seal caused the backup ring seat 0-ring or the U-cup to become dislodged and,explained the cause of the first stage failure.
The RCP vendor (Byron Jackson)
has stated that as little as
to 20 psi reverse pressure can cause this condition to take place.
The fact that the 2A2 RCP,seal re-staged itself after the pump was secured on December 13, 1995 lends more credibility to a U-cup being, temporarily dislodged as it is more plausible than an 0-ring being temporarily dislodge The licensee's corrective action for this failure included:
- ~
Replacement of this failed seal.
Revising'P 2-0120020, "Filling and Venting the RCS," to include the use of ERDADS display as the primary data source and the local temporary gauges installed in the containment building as the secondary source.for recording RCP seal cavity pressures during RCP sweeps and other low pressure operating conditions.
The use of control room installed instrumentation for recording RCP seal pressures during these conditions should be discontinued as they cannot be read accurately at these low pressures.
~
Revising OP 2-0120020, "Filling and Venting the RCS," to ensure that the Operations Department does not raise the RCS water level until after Hechanical Haintenance has completely coupled the RCP for the final time.
~
Revising GHP H-0009,
"Reactor Coolant Pump Seal Installation," to alert Hechanical Haintenance to ensure that Operations does not raise RCS waster level until the RCP is coupled.
~
Disassembly and inspection of the failed seal to identify any additional deficiencies.
The inspector reviewed the licensee's root cause and corrective actions taken for the RCP seal first stage failure and found it to be detailed and thorough.
The corrective action appeared to be adequate to prevent a future failure of this type.
Unit Restart On December 30, the inspector attended a briefing to operators covering unit startup activities.
The briefing was conducted by the Operations Supervisor, and included management expectations for control of the evolution, defined the chain of command and control, discussed the overall order for the activities to be performed, reviewed criteria for determining criticality, and delineated criteria for tripping the reactor.
A discussion of a reactivity event during startup at another facility was also included to underscore the importance of cautious operations.
A portion of the briefing was presented by the Reactor Engineering Supervisor, who described the expected dynamic behavior for the new core load and compared and contrasted the new NI system (installed during the current outage) with the old.
Overall, the inspector found the briefing to be comprehensive and well-focused.
On January 1, the inspector observed the, licensee perform the Unit 2 approach to criticality using Preoperational Test Procedure No. 2-3200088, Rev 10, "Unit 2 Initial Criticality Following Refueling."
The inspector reviewed the Inverse Count Rate Ratio Data Sheet and the RCS Dilution I/O Plots used to evaluate the boron dilution rate.
The Reactor Engineer effectively analyzed the data and provided timely feedback to operations.
Criticality was verified at approximately 2:26 am by a sustained positive startup rate and steadily increasing flux level.
On January 4, the inspector reviewed the completed FRG approved Unit 2 Preoperational Test Procedure No. 3200091, Rev 7,
"Reload Startup Physics Testing,"
and noted the following discrepancies:
TC ¹ 0-96-001 deleted
"the signal summing box" in step 5.2.2 since this item is no longer used.
However, references to this item still appear in steps 5.3. 1 and 8.1.
The acceptance criteria listed in step 10.6 Appendix E, Rod Worth Measurements (Rod Swap)
are given as i values, whereas in the Appendix E itself, these criteria are identified as
< values with no lower bounding value.
For Appendix A step 2, the Appendix G step 3 delta ppm average is incorrectly calculated as 2.3.
It should read 1.0.
This reduces the calculated quantity from 0. 14 to 0.06 which is still within the acceptance criteria of k2 percent.
For Appendix E step 11, the Appendix G step 3 delta ppm average is incorrectly calculated as 1.67.
It should read-0.33.
This reduces the calculated quantity from 0. 12 to-0.03 which is still within the acceptance criteria of i2 percent.
Appendix A step E percent difference is incorrectly calculated as
.03 percent.
It should read -.03 percent.
Appendix C step 1 identifies
"Measured Critical Boron Concentration" from Appendix A step 2.
This is an averaged value.
Appendix D Average ITC is incorrectly calculated as -0.96.
It should read -0.97.
The MTC measured of 0.56 is correct using -0.97.
However, it was incorrectly calculated if you use the incorrect Average ITC of -0.96.
The ZPPT Test Record completed per Appendix E step
incorrectly lists Boron Concentration of the "Last RCS Sample" as 154 ppm taken at 0915.
This should read 1549 ppm from Appendix G Special CBC Instructions - Boron Concentration Lo.9 2.9.1 2,10
~
Appendix E Rod Worth Measurements by Rod Swap step 6.J utilizes a calculated absolute percent Deviation of 2.3 percent with an acceptance criteria of g 10 percent for the Reference Group.
Step 11 recalculates, this same percent Deviation as -2.3 percent with the same acceptance criteria of < 10 percent.
~
Appendix F step 2.A contains the instruction "If the Measured CEA Worth is <90 percent of the Design CEA worth, then reduce the Total design CEA Worth below by the same percentage".
No detailed calculational step or formula is provided to do this.
~
Appendix G Special CBC Instructions - Boron Concentration Log incorrectly identifies several Appendices and steps where particular boron sample results are used in the procedure.
These deficiencies were reported to the licensee, and were subsequently documented on STAR 0-960030.
Followup of Operations LER's (92700)
(Closed)
"Missed Emergency Diesel Generator Surveillance Due to Procedural Deficiency."
This event was the result of deficient procedural guidance that did not require independent verification of a TS interpretation.
The action to perform weekly testing until five or less test failures in the last 100 tests was not accomplished.
As a result of the above, the licensee modified the test procedure to accomplish this action.
They also verified that the correct testing frequency was and had been accomplished with the required frequency.
The licensee has submitted and received approval to delete this TS requirement under the guidance provided by NRC Generic Letter 94-01.
The inspector verified that this TS change had been implemented and the other stated corrective actions had been completed.
Followup on Previous Operations Inspection Findings (92901)
2. 10. 1 (Closed)
VIO 335/95-01-01,
"Failure to Perform TS Required Sampling of 1A1 SIT."
This event occurred when the chemistry technician sampled the wrong SIT.
The licensee has revised their procedures for filling SITs to include a data sheet that is generated when filling starts and requires sampling prior to data sheet closure.
The chemistry department also enhanced their computer program for logging samples to include a time dependent notification system to track sample requests.
In addition, each department has implemented -procedural steps to require independent verification of surveillances.
This
e C
V'
and added training of all effected personnel should prevent a
recurrence of this event.
(Closed)
VIO 335/95-15-01,
"Failure to Follow Procedure and Block NSIS Actuation."
This event occurred during a plant cooldown, when the licensee noted that all actuation equipment was already correctly positioned and failed to block this actuation signal.
The licensee's corrective action included;
~
Blocking signal.
~
Counseling and disciplining operator.
~
NPSs held meeting and reiterated procedural requirements and goals to operators.
~
Event incorporated into licensed operator requalification training.
~
Plant adopted verbatim procedural compliance policy.
The inspector verified that the above corrective actions as stated in the licensee response to this violation dated November 15, 1995 had been accomplished.
(Closed)
VIO 335/95-15-02,
"Failure to Follow Procedure During RCP Seal Restaging."
The licensee responded to this violation in a letter dated November 15, 1995.
The licensee's corrective actions included:
Counseling and disciplining responsible operators.
Deleting the procedure appendix that permitted seal restaging.
Completed a management assessment of the decision making process that allowed this event to occur and revised plant policy 105 "Plant Operation Beyond the Envelope of Approved Operating Procedures,"
to require a technical review prior to first time use of procedures.
Held meetings and discussed this event and management expectations with operators.
Adopted verbatim procedural compliance.
The inspector verified that the above actions had been completed.
It appears that this action should reduce or prevent occurrence of this on similar issues.
(Closed)
VIO 335/95-15-04,
"Failure to Follow Procedures During Alignment of Shutdown Cooling System."
The licensee responded to this violation in a letter dated November 15, 1995.
The licensee's corrective actions included:
~
Correctly aligning system when discovere lt
~
Satisfactory testing of affected LPSI pump
.
~
Counseling and disciplining operators.
~
Implemented new requirement for dedicated procedure reader for critical tasks.
~
Meeting with operators to emphasize mistake and stress needed corrective actions.
3.0 3.1
~
Adoption of verbatim procedural compliance.
~
Incorporated event into requalification training for operators.
The inspector verified that the above action had been completed.
This should prevent recurrence.
Maintenance and Surveillance Maintenance Observations (62703)
Station maintenance activities involving selected safety-related systems and components were observed/reviewed to ascertain that they were conducted in accordance with requirements.
The following items were considered during this review:
LCOs were met; activities were accomplished using approved procedures; functional tests and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; and radiological controls were implemented as required.
Work requests were reviewed to determine the status of outstanding jobs and to ensure that priority was assigned to safety-related equipment.
Portions of the following maintenance activities were observ'ed:
3. 1. 1 Steam Bypass and Control Valve On December 27, the inspector attended two meetings to discuss the acceptability of the post-outage configuration of Unit 2 PCV-8801, the 8" Steam Bypass to Hain Condenser (5 percent capacity)
identified in STAR ¹952223.
This valve which had a trim upgrade installed this outage.
During Flowscan testing, the licensee discovered that the inner plug travel was 0.32 inches instead of the recommended 0.48 inches
+0. 12/-0.06 inches as specified on the vendor supplied drawing.
Since the upgraded trim was assembled by the vendor and installed as a unit, the licensee arranged for a vendor representative to provide onsite assistance in evaluating the performance of this valv On December 28, the vendor representative worked with members of the licensee's 18C, HH, SCE and Engineering Departments to analyze the availabl.e data and develop options.
Three options were considered:
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Leave As Is
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Put in the old trim that was removed during the outage Remove, repair, and reinstall new trim The vendor representative recommended option 1 based on the followi'ng:
No significant change in the balancing cylinder pressure with the reduced inner plug travel (assuming a normal piston ring leakage rate).
The specified inner plug tr'avel of 0.50 inches was for use with a 10 inch trim size.
The reduced travel provides sufficient flow capacity in an 8 inch trim.
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The presence of balancing ports not found in the old trim which reduces the risk of erratic positioning.
The licensee accepted the vendor recommendation subject to a thorough engineering evaluation and functional testing.
On January 2, while in mode 2, operators encountered difficulties in maintaining stable secondary plant conditions using the Low Power Feedwater Control and the Steam Bypass Control Systems.
Operators placed the SBCS in manual due to apparent control system instability.
PWO 64/8342 was revised to allow hookup of test equipment to troubleshoot the SBCS.
Output of the SBCS master controller, SG pressure and demanded steam dump valve position for PCV-8801 and PCV-8802 suggested that a controller reset adjust was required.
This was performed and a second set of data showed stable steam dump valve operation.
On January 3, the licensee continued efforts to troubleshoot the Low Power Feedwater Control System per PWO 64/6084.
A vendor representative arrived onsite to assist the licensee in evaluating system response.
At the close of the inspection period, the licensee was continuing to'monitor the performance of the SBCS.
The inspector concluded that the licensee performed good troubleshooting in the identification and treatment of this issue.
ICI Flange Issues The inspectors reviewed selected aspects of the reassembly of the ICI flanges following reactor vessel head tensionin The inspectors noted that PWO 64/8703, which had been issued to clean and lubricate ICI flange hardware had resulted in the generation of a STAR by gC.
STAR 951770 documented the inspections conducted in accordance with gC holdpoints in IKC procedure 1400023.
The gC inspector had identified galling on the conical side of all greylock nuts, the outside surfaces of greylock clamps, and, on the
, inside of some greylock clamp bolt holes.
The inspector reviewed the disposition to the STAR, which included vendor evaluations of =
the subject conditions.
The licensee, with the concurrence of'the vendor, found the conditions to pose no operational concern.
Additionally, the licensee initiated WOs to replace.the components with a new ICI flange clamp design during the next Unit 2 outage.
The inspector found the licensee's disposition of the issue satisfactory.
The inspector observed portions of the preparations for reterminating ICI leads at the ICI flanges.
At the end of the 1993 Unit 2 refueling outage, this activity resulted in the cross-connection of several leads, resulting indeterminate spatial data,
'eing received in the control room.
This'as documented in IR 95-05 and IR 95-18 (NCV 95-18-05).
The activity was conducted in accordance with IKC procedure 1400023, which had been recently revised to include more thorough checks of electrical terminations..
The inspector observed the staging of figures and wiring diagrams at individual ICI flanges at the reactor vessel head and verified that maintenance personnel had properly identified individual ICI locations'rocedures were verified to be the most recent revisions.
The inspector discussed the upcoming activity with I&C personnel's they prepared the ICI flanges for assembly.
The inspector found that personnel were quite knowledgeable about the upcoming activity and the sequence of flange assembly.
On December 20, the inspector observed electrical maintenance troubleshoot and repair FCV-25-14 Control Room Outside Air North Intake per PWO 65/1587.
This valve showed dual indication after repositioning closed during Unit 2 Safeguards Testing (a CIAS on either unit shifts both units CR HVAC envelopes to the recirc mode).
The inspector verified that this valve was properly logged out-of-service at 2:03 am on December 20 and isolated per the applicable Equipment Clearance Order.
The work was performed by a Journeyman Electrician assisted by a valve specialist, A shop supervisor was present to observe the work.
The cause of the dual indication was identified as a misaligned L-shaped finger which did not allow the open indicating lamp to extinguish when the valve was in the full closed position.
Each l-imit switch is repositioned by these L-shaped fingers which ride on the surface of the Limitorque rotors in the valve actuator.
According to the valve specialist, a small change in the bend angle of the L-shaped finger affects limit switch actuation which is what occurred in this case.
An adjustment to the
3.2 3.2.1 applicable L-shaped finger was made and the valve actuator cover reinstalled for post-maintenance testing.
The inspector observed workers position themselves on the overhead safety-related ducting while performing work due to the restricted access for this valve.
This included both the North Air Intake Duct and the exhaust duct of HVE-13B.
The day after maintenance was completed, the inspector discussed this with the cognizant SKCE Engineer and several inspectors in the gC Maintenance department.
Both the SECE Engineer and gC inspectors were aware that ducting should not be used to support.workers.
The inspector reviewed numerous maintenance and administrative procedures with a Maintenance gC inspector and was not able to identify any instruction regarding this practice.
The SCE Engineer was requested to evaluate whether these ducts were designed to withstand loading applied by workers in this fashion.
Post-maintenance testing verified that the valve position limit switches functioned properly, MOV motor amps were less than or equal to 130 percent nameplate rating, and that both the open and close stroke times were within specification.
Surveillance Observations (61726)
Various plant operations were verified to comply with selected TS requirements.
Typical of these were confirmation of TS compliance for reactor coolant chemistry, RWT conditions, containment pressure, control room ventilation, and AC and DC electrical sources.
The inspectors verified that testing was performed in accordance with adequate procedures, test instrumentation was, calibrated, LCOs were met, removal and restoration of the affected components were accomplished properly, test results met requirements and were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
The following surveillance test was observed:
OP 2-0400050, Rev 16, "Periodic Test of the Engineered Safety Features."
On December 5, the licensee resumed the Integrated Safeguards Test Sections 8.4 through 8.7 and Sections 8. 11 and 8. 12.. This procedure had an additional TC incorporated to recognize the current plant configuration, The sections of the test performed completed the Unit 2 surveillance requirements (see IRs 95-18 and 95-21 for additional information).
These sections were:
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Section 8.4 Loss of Offsite Power with Integrated Safeguards (SIAS, CIAS and CSAS) Actuation Test using A
and B Pumps with the 2AB Buses Aligned to the A Electrical Sid ~
Section 8.5 Verification of 453 KW Load. Rejection and LOOP with Concurrent SIAS Swing Bus Test.
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Section 8.6 Manual SIAS/CIAS/CSAS Actuation Verification.
Section 8.7 Loss of Offsite Power without ESFAS Signal and Swing Pump LOOP Testing.
Section 8. 11 Plant Restoration.
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Section 8. 12 Independent Verification of Test Instrumentation, Jumper/Lifted Lead Restoration and Plant Restoration Configuration.
The inspector attended the pretest briefing,conducted by the operations manager and found it to be thorough and detailed.
All test personnel were verified in attendance, Items covered included:
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Precautions and Limitations
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Past experiences and lessons learned.
This included the problems encountered on October 12 when testing was secured due to the reverse power trip of the 2A EDG.
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. Procedural control
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Use=of effective communications Contingencies and test termination criteria The inspector was in the control room during performance of Section 8.4 and had the following observations:
The Test Coordinator and ANPS exercised excellent procedural control.
The Test Coordinator advised the ANPS when to continue in the procedure after-ensuring that all that the required verifications had been performed.
The ANPS minimized the time that SDC was secured.
On at least two occasions the ANPS announced to control room staff the time remaining to restore SDC before exceeding the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> allowed in the procedure.
The Test Coordinator ensured during performance of Appendix G Verification"of Diesel Generator Trips that control room operators acknowledged each alarm.
This verified that all DG trips generated not only a local but a control room alarm as well.
An abnormally low running amperage reading was seen on the 2B CS Pump.
An operator visually'nspected the pump and neither saw nor heard any abnormal indications prior to it
being secured.
The pump was vented then restarted at which time operators verified all pump paramet'ers were in the normal operating range.
Two STARs were written to identify the cause of the air binding or inadequate venting and for Engineering to assess, any potential equipment degradation or damage.
Several area and process radiation monitoring instruments displayed possible malfunctions or failures.
RC-26-, 14 Plant Vent and RC-26-66 Control Room Outside Air Int showed
"HELP" and the RC-26-70 ECCS Wide Range Gas Monitor lamp marked "error" flashed intermittently.
Other instruments were reporting numerical data, however, their
, green "operating" lamps was not illuminated.
These included:
RC-26-13 Plant Vent, RC-26-61 Control Room Outside Air Int, RC-26-70 ECCS Wide Range Gas Monitor, RC-26-90 Plant Vent Stack Rad Monitor and the RC-26-69 'ECCS Wide Range Gas Monitor. The inspector questioned, both the
, NPS and Operations Ma'nager as to whether these instrument indications were consistent with the current plant configuration, i.e. all plant electrical loads being carried by the EDGs.
During restoration of Unit 2, operators discovered that a "reboot" of the affected radiation monitor software was required to shift control room ventilation from the emergency or recirculation mode.
to normal mode.
STAR 8951390A was written to investigate and document deficiencies.
On December 6, the inspector attended a meeting which addressed the above issues.
IKC explained the following:
Radiation monitoring instruments communicate with an RM-80 computer during normal operation.
If RM-80 communications is interrupted, the instrument will attempt to reestablish the link.
After 3 unsuccessful attempts, the
"HELP" message locks in alerting operators of the problem.
A backup battery supply is provided.to maintain memory for short periods of time if power was lost.
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The green operating lamp indicates that the instrument is operating properly.
A similar problem involving one of the radiation moni.toring instrum'ents had occurred during Safeguards Testing in October.
At that time STAR 4951390 identified the cause as an inverter failure.
However, in this instance, no-inverter'failure was observed.
On December 15, an Interim Engineering Disposition was issued by 18C to investigate and resolve these deficiencies.
The potential causes of RM-26-14 and 66 flashing
"HELP" were identified as a discharged battery pack, bad CPU RAM chip, or bad Metal Oxide Varistor across the RM-80 ac input line.'he loss of the green operating status LED
r>
J
'I
lights on RH-23 units RH-26-2, 13, 61, 66, 69, 70 and 90 indicated either a check source test failure, loss of count input, loss of flow, filter not moving, tom filter, or a loss of power.
The vendor'nformed the licensee that due to the configuration of some of the firmware the database is reloaded but, an automatic restart of the pumps does not occur.
The licensee's Interim Engineering Disposition will:
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t I
Perform battery load test for RH-26-14
& 66 Perform power down test for affected Rad monitors.
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Record existing firmware versions and revision levels for all radiation monitors in the RC-11 loop.
The licensee has completed the battery load test detailed above.
Both battery packs were found below the allowed 3.0 VDC specified in I&C Procedure No. 2-1220057, Rev 3, "Functional Testing of the RH-80 Power Supply Assemblies."
-This survei'llance test is currently performed every 18 months and had been satisfactorily completed this year for both failed Rad monitors.
The I&C Supervisor intends to recommend that all backup batteries be replaced and is considering increasing the frequency of this surveillance test.
The licensee completed Safeguards Testing on December 6 with no safeguards equipment failures noted.,
A list of equipment deficiencies identified during Safeguards Testing is provided below:
Com onent V2516 V2515 2B LPSI Pump HVA/ACC-3B V3414 RCP 2A2 Lift Oil Pum B
Problem Indicated dual position when closed Indicated dual position when closed Ammeter pegged high upon pump start and remained there after pump was secured This control room air conditioner shut down due to high discharge ressure durin test Valve leakin by Pump shut off for no a
arent reason WR Number 95020540 95020542 95020544 95020545 95020546 95020547
'dditionally the following items were addressed:
'RH-23's A number of Rad monitors did not have indicating lights or were flashing a help message after the LOOP.
This problem was also encountered during the initial safeguards test.
STAR 8951390A was generated to address this problem and is currently being worked on by the IKC system supervisor.
.A list of rad monitors that were affected was also given to 18C.
These were:
RC-26-66, RC-26-14, RC-26-2, RC-26-61, RC-26-13 and RC-26-70 (see above).
2B CS Pump
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This pump was found to be air bound following the start for the test.
A STAR was generated to address this problem.
Train B
ECCS The B train ECCS ventilation flow indicated 25,500 CFH during the test.
This is less than the required minimum flow of 27,000 CFH.
This Technical Specification requirement was verified during the initial safeguards test performed'n October 12, 1995.
Section 8.4 was reperformed only to get the plant in a lineup to allow the remaining portions of the tests to be completed.
The System Engineer was-notified.
The plant was in mode 5 at the time of the test, ECCS ventilation is not required until mode 4.
Surveillance testing will verify this at a later time.
3.3 3.3.1 The inspector found that the licensee's overall performance of this complex, infrequently performed surveillance test was good with one reservation, i.e., the operations personnel that the inspector queried about the RH-23s were unable to explain system behavior following a LOOP.
The Operations Manager said that a
STAR had been written to address this in operator training, Followup of Maintenance LERs (92700)
(Closed)
"Hissed Technical Specification Scheduled Surveillance Due to Procedural Deficiency."
This surveillance was missed because the surveillance conducted by the technical support area did not require any independent verification of the projected due date.
The inspector verified that the licensee had completed all corrective actions listed on the LER which also included verification that this and other plant departments had implemented procedural changes to ensure independent reviews of projected schedules.
These actions appear satisfactory to prevent event repetitio I li
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3.3.2 (Closed)
"IA3 4160 Volt Bus Load Shed During Replacement of Failed 2X-5 Relay Oue to Procedural Deficiency."
The inspector verified that the corrective action to add a checklist to enhance the plant policy for work on sensitive systems that could cause a plant trip had been accomplished.
This was the only action open when the LER was submitted.
This action appears adequate to prevent recurrence of this event.
3.4 Followup on Previous Maintenance Findings (92902)
3.4. 1 (Closed)
VIO 335/95-15-06,
"Failure to Follow Maintenance Procedure Steps as Work Was Completed."
The. licensee responded to this violation in a letter dated November 15, 1995.
Their corrective actions included:
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Signing of procedure steps.
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Testing of electrical circuitry.
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Meeting with electrical maintenance personnel to review the event and emphasize management expectations.
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Meetings with all maintenance employees to stress strict procedural adherence.
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Adopted a policy of verbatim procedural compliance.
4.0 4.1 The inspector verified that the above stated actions had been satisfactorily completed.
This appears adequate to prevent repetition.
Engineering Support (37001)
CFR 50.59 Safety Evaluation Program This inspection was conducted to ascertain whether the licensee was implementing a safety evaluation program that conforms to Title 10 of the Code of Federal Regulations, Section 50.59, 10 CFR, Changes, Tests, and Experiments.
Engineering assessments of operability on non-conforming or degraded conditions performed by the engineering staff was also reviewed by the inspector.
Criteria determining compliance with the
CFR 50.59 Safety Evaluation and operability assessment program controls were identified by reviewing the following documents.
FP8L Guidance for Performing
CFR 50.59 Safety Evaluations, Revision
Administrative Procedure No. 5769,
CFR 50.59 Safety Evaluation Guidelines, Revision
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gI 5-PR/PSL-I, Preparation, Revision, Review/Approval of
- Procedures, Revision
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Administrative Procedure No.
10124, Control and Use of Jumpers and Disconnected Leads, Revision
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OI 3-PR/PSL-I, Design Control, Revision
ENG gI 1.0, Design Control, Revision
0 ENG gI 1. 1, Engineering Package, (EP), Revision
ENG 01 1.2, Minor Engineering Package,,(MEP),
Revision
ENG 01 2.0, Engineering Evaluations, Revision
ENG gI 2, 1,
CFR Screening/Evaluation, Revision
ENG gI 2.3, Operability Determinat'ions, Revision
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FP&L Nuclear Engineering Training Manual,
CFR 50.59,
.
Parts
and
The inspector reviewed the above documents and verified that procedural guidance had been established for implementing the requirements of 10 CFR 50.59.
Based on this review the inspector concluded that the licensee's formal procedural guidance for implementing its safety evaluation program conforms to
CFR 50.59 requirements.
The licensee's training and qualification requirements for indoctrination of personnel in the use of 10 CFR 50.59 were also reviewed.
The inspector determined that FPL implements practices which provided for the indoctrination and training of personnel in the use of 10 CFR 50.59.
However, the licensee has not established written requirements for personnel who have completed this training to demonstrate attainment of-the skills and abilities required for proficiency in this functional area.
The inspector was informed that a certification program for gualified Safety Reviewers would be developed and implemented by December 31, 1996.
This program would establish the above requirement.
This item was identified as inspector followup item, IFI 50-335,389/95-22-03,
"Completion of Certification Program for gualified Safety Reviewers."
Implementation of the
CFR 50.59 program requirements was evaluated by review on the following work products.
Steam Generator Equivalency Report (SgER) Safety Evaluation, JPN-PSL-SENP-94-026, Revision 0 was reviewed and determined to be a very good work product.
This safety evaluation clearly identified and addressed the licensing basis for the replacement steam generators (RSGS).
Additionally, the conclusions clearly demonstrated that there were no technical specification changes and no unreviewed safety question associated with steam generator replacement of St.
Lucie 1.
Two
jumper and lifted leads (JLL) Engineering Evaluations 'and four Plant Change Modifications (PC/Hs)
and their associated
CFR 50.59 Safety Evaluations were reviewed.
No deficiencies were identified with these work products.
Non-conformance Reports, NRC No.
2603 and 2-616 were reviewed and were also determined to have been adequately dispositioned.
Operability evaluations are a particular type of engineering evaluation that support continued operation of the plant.
These type of engineering evaluations would also require a
CFR 50.59 Safety Evaluation if temporary designs, compensatory actions or procedure changes were involved.
The inspector reviewed the following Engineering Evaluations to assess their technical adequacy and compliance with program controls:
JPN-PSL SEFJ-95-003, T-Hot Temperature Oscillations, Revision
JPN-PSL - SENP-94-079, Assessment of ECCS Suction X-Tie (NaOH),
Revision
JPN-PSL SENP-95-025, Operation at 2225 psia, Revision
JPN-PSL SENP-95-101, Assessment of Lifting LPSI Discharge Relief, Revision
JPN-PSL - SENP-95-103, Relief 'Valve Performance, Revision
JPN-PSL SENP-95-108, Assessment of Aux High Pressure Header Piping for In-House Event Summary 95-058, Revision
Engineering evaluations for the most part were determined to have been adequately prepared with the following exception.
Engineering evaluations JPN-PSL-SENP-95-101, and JPN-PSL-SENP-95-103 did not
'rovide a documented level of detail sufficient to demonstrate validity of the conclusions reached concerning radiological consequences for the equipment malfunctions identified.
FPL provided the inspector with revision 2 of JPN-PSL-SENP-95-,101 along with calculation PSL-IFJN-95-001, Estimate of the Offsite Dose Consequences from Leakage of LPSI Header Relief Valve V3439, which addressed this concern.
The inspector selected four safety/engineering evaluations to verify that they had been reviewed by the Facility Review Group in accordance with Technical Specification, Section 6.5. 1.
FP&L management presented objective evidence which demonstrated that three had been reviewed by the FRG.
Engineering evaluation JPN-PSL-SENP-95-103 was identified as not having been reviewed by the FRG.
This item was identified as a potential violation to which FP&L management dissented.
FP&L management subsequently provided a
facsimile of FRG Heeting Minutes95-194, dated August 22, 1995, on
+
'j r,
Ei
5.0 F 1 5.2 December 18, 1995.
Based on review of the additional information provided by the license this issue was resolved.
Within this area no violations or deviations were identified.
Plant Support (71750)
Fire Protection During the course of their normal tours, the inspectors routinely examined facets of the Fire Protection Program.
The inspectors
'eviewed transient fire loads, flammable materials storage, housekeeping, control hazardous chemicals, ignition source/fire risk reduction efforts, fire protection training, fire protection system surveillance program, fire barriers, fire brigade qualifications, and gA reviews of the program.
No deficiencies were identified.
Physical Protection During this inspection, the inspector toured the protected area and noted that the perimeter fence was intact and not compromised by erosion or disrepair.
The fence fabric was secured and barbed wire was angled as required by the licensee's Physical Security Plan (PSP).
Isolation zones were maintained on both sides of the barrier and were free of, objects which could shield or conceal an individual.
The inspector observed personnel and packages entering the protected area were searched either by special purpose detectors or by a physical patdown for firearms, explosives and contraband.
The processing and escorting of visitors was observed.
Vehicles wer e searched, escorted,'nd secured as described in the PSP.
Lighting of the perimeter and of the protected area met the 0.2 foot-candle criteria.
5.3 In conclusion, selected functions and equipment of the security program were inspected and found to comply with the PSP requirements.
Radiological Protection Program Radiation protection control activities were observed to verify that these activities were in conformance with the facility policies and procedures, and,in compliance with regulatory requirements.
These observations included:
Entry to and exit from contaminated areas, including step-off pad conditions and disposal of contaminated clothing; Area postings and controls;
ie
6.0
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Work activity within radiation, high radiation, and contaminated areas;
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Radiation Control Area (RCA) exiting practices; and,
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Proper wearing-of personnel monitoring equipment, protective clothing, and respiratory equipment.
Other NRC Personnel of Site
,7.0 8.0 R. Aiello, License Examiner, NRC Region II, was on-site from December 4 through 8..
His activities included augmenting the resident inspection effort and the results of his inspection are contained in this report.
On December 8, Hr. Aiello held an exit meeting with the licensee to discuss his findings.
C. Smith, Reactor Inspector, NRC Region II, was on-site from December 11 through 15.
His activities included an inspection of the licensee's engineering activities and his results are included in this report.'n December 15, Hr. Smith held an exit meeting with the licensee to discuss his findings.
L. Moore and R. Gibbs, Reactor Inspectors, NRC Region II, were on-site from December 11 through December 15.
Their activities included an inspection of the licensee's procurement engineering activiti'es and their results are documented in IR 335,389/95-17.
D. Matthews, Director, Project Directorate II-l, and J. Norris, Senior Project Manager, NRC Office of Nuclear Reactor Regulation, conducted a visit of the licensee's facilities in Juno Beach and the St.
Lucie Power Plant December
and 12, respectively.
Their
.activities included meetings with the licensee's engineering managers in preparation for the upcoming SALP board meeting.
J. 'Jaudon, Deputy Director, Division of Reactor Safety, NRC Region II, was on-site December 12.
His activities included a site tour and meetings with the licensee's maintenance and plant support management in preparation for the upcoming SALP board meeting.
Other Areas (40500)
The inspector reviewed the INPO evaluation report of St. Lucie which was recently received in completed form by the licensee.
The evaluation was performed in June 1995.
In general, the inspector found no areas of significant disagreement between the findings generated by INPO and those developed by NRC.
Exit Interview The inspection scope and findings were summarized on January 5,
1996, by the SRI with those persons indicated in paragraph 1.
Interim exits were conducted on December 8 and 15.
At the
r
V
December 15 meeting, the licensee was informed of a potential violation involving. failure of the Facil,ities Review Group (FRG),to review Engineering Evaluation JNP-PSL-SENP-95-103, Evaluation of Relief Valve Performance, Revision 0.
Licensee management dissented and requested additional time to review this issue.
On December 18, 1995, the licensee provided the NRC a facsimile of the Facility Review Group Minutes95-194, dated August 22, 1995.
The meeting minutes documented, the FRG review of LER 335-95-006, Revision 0, where the corrective action delineated in Engineering Evaluations JNP-PSL-SENP-95-103 and JNR-PSL-SENP-95-105'ere addressed.
Based on the additional information provided -by FPL in this facsimile this issue has been.resolved.
Proprietary information is not contained in-this report.
Dissenting comments were not received from the licensee.
~T e
Item Number Status Descri tion and Reference IFI 50-335,389/95-22-01 NCV 50-335,389/95-22-02 IFI "
50-389/95-22-03 r
VIO 50-335/95-01-01 Open Closed Open Closed
"SG Level Channel Inaccuracies Due to Sensing Line Blockage,"
paragraph 2.3.1.2
"Failure to Properly Implement Temporary Change Controls,"
paragraph 2.7.4.
"Completion of Certification Program for gualified Safety
, Reviewers,"
paragraph 4. I
"Failure to Perform TS Required Sampling of lAI SIT," paragraph 2.10.1.
VIO 50-335/95-15-01 Closed
"Failure to Follow Procedure and Block HSIS Actuation," paragraph 2.10.2 VIO 50-335/95-15-02 VIO 50-335/95-15-04 Cl osed Closed
"Failure to Follow Procedure During RCP Seal Restaging,"
paragraph 2. 10.3.
"Failure to Follow Procedures
'uring Alignment of Shutdown Cooling System,"
paragraph 2.10.4.
VIO 50-335/95-15-06 Closed
"Failure to Follow Maintenance Procedure Steps as Work Was Completed,"
paragraph 3.4. 'f l}a f
J
I
LER 50-335/95-001 LER 50-335/95-002 LER 50-389/95-003 Closed Closed Closed
"1A3 4160 Volt Bus Load Shed During Replacement of Failed 2X-5 Relay Due to Procedural Deficiency," paragraph 3.3.2.
"Hissed Emergency Diesel Generator Surveillance Due to Procedural Deficiency," paragraph 2.9.1.
"Hissed Technical Specification Scheduled Surveillance Due to Procedural Deficiency," paragraph 3.3.1.
9.0 Abbreviations, Acronyms, and Initialisms AEOD AFW ANPS AP ATTN BKW CBC CC CE CEA CEDH CET CFH CFR CIAS CR CSAS CST DEH DG DPR ECCS EDG ERDADS ESF ESFAS FCV FNE FPL FR FRG GNP HPSI HSP HV Analysis and Evaluation of Operational Data, Office for (NRC)
A'uxiliary Feedwater (system)
Assistant Nuclear Plant Supervisor Administrative Procedure Attention Babcock and Wilcox Co.
Critical Boron Concentration Cubic Centimeter Combustion Engineering Inc.
Control Element Assembly Control Element Drive Nechanism Core Exit Thermocouple Cubic Feet per Minute Code of Federal Regulations Containment Isolation Actuation Signal Control Room Containment Spray Actuation System Condensate Storage Tank Digital Electrohydraulic Control Diesel Generator Demonstration Power Reactor (A type of operating license)
Emergency Core Cooling System Emergency Diesel Generator Emergency Response Data Acquisition Display System Engineered Safety Feature Engineered Safety Feature Actuation System Flow Control Valve Foreign Haterial Exclusion The Florida Power L Light Company Federal Regulation Facility. Review Group General Maintenance Procedure High Pressure Safety Injection (system)
Hot Shutdown Panel Heating Ventilation
HVAC HVE IKC ICI IFI INPO IR ITC IV JPN KW LCO LED LER LOOP LPSI MCC MM MOV MSIS MTC NCV NDE NI NOP NOT NPF NPS NRC NRR OP OWA PCM PCR PCV P&ID ppm Pslg PSL PSP PWO QA QC QI RCO RCP RCS Rev RFO RI I RM RPS
Heating Ventilation and Air Conditioning Heating and Ventilating Exhaust (fan, system, etc.)
Instrumentation and Control Incore Instrumentation Inspector Followup Item Institute for Nuclear Power Operations
[NRC] Inspection Report Isothermal Temperature Coefficient Independent Verification Juno Beach Nuclear Engineering KiloWatt(s)
TS Limiting Condition for Operation Light-emitting Diode Licensee Event Report Loss of Offsite Power Low Pressure Safety Injection (system)
Motor Control Center (elec'trical distribution)
Mechanical Maintenance Motor Operated Valve Main Steam Isolation Signal Moderator Temperature Coefficient NonCited Violation (of NRC requirements)
Non Destructive Examination Nuclear Instrument Normal Operating Pressure Normal Operating Temperature Nuclear Production Facility (a type of operating license)
Nuclear Plant Supervisor Nuclear Regulatory Commission NRC Office of Nuclear Reactor Regulation Operating Procedure Operator Work Around Plant Change/Modification Procedure Change Request Pressure Control Valve Piping 8 Instrumentation Diagram Part(s)
per Million Pounds per square inch (gage)
Plant St. Lucie Physical Security Plan Plant Work Order Quality Assurance Quality Control Quality Instruction Reactor Controls Operator Reactor Coolant Pump Reactor Coolant System Revision Refueling Outage Region II - Atlanta, Georgia (NRC)
Radiation Monitor Reactor Protection System
RWT Refueling Water Tank SALP Systematic Assessment of Licensee Performance SBCS Steam Bypass Control System SCE System and Component Engineering SDC Shut Down Cooling SG Steam Generator SIAS Safety Injection Actuation System SIT Safety Injection Tank SRI Senior Resident Inspector SRV Safety Relief Valve St.
Saint STAR St, Lucie Action Request TC Temporary Change TCN Temporary Change Notice TCW Turbine Cooling Water TS Technical Specification(s)
VAC Volts Alternating Current VDC Volts Direct Current VIO Violation (of NRC requirements)
WO Work Order WR Work Request ZPPT Zero Power Physics Testing
4e e~
.P C
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