IR 05000335/1993020
| ML17228A362 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 10/25/1993 |
| From: | Elrod S, Landis K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17228A361 | List: |
| References | |
| 50-335-93-20, 50-389-93-20, NUDOCS 9311160082 | |
| Download: ML17228A362 (22) | |
Text
~S Rfg~
e~
C
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREIjj, N.W., SUITE 2900 ATLANTA,GEORGIA 30x94199 Report Nos.:
50-335/93-20 and 50-389/93-20 Licensee:
Florida Power L Light Co 9250 Mest Flagler Street Miami, FL 33102 Docket Nos.:
50-335 and 50-389 License Nos.:
DPR-67 and NPF-16 Facility Name:
St. Lucie 1 and
Inspection Conducted:
August
Se tember 25, 1993.
Inspectors:
~
~. A.
ro
,
Rior esi ent nspector Approved by:
an is, ie Reactor Projects Section 2B Division of Reactor Projects a
e igne
/0 g5 a
e igne SUMMARY Scope:
This routine resident ins ection Results:
p was conducted onsite in the areas of plant operations review, surveillance observations, maintenance observations, fire protection review, and followup of previous inspection findings.
Backshift inspection was performed on September 4, 6, 7, ll, 12, 18, 19, and 21, 1993.
Plant Operations area (paragraphs 3 and 8):
Operations reacted well to jellyfish incursions during the month.
A number of power changes, three Unit 1 trips, and a shutdown were required.
The Unit 1 startups from trips were routine.
Maintenance (paragraph 5)
and Surveillance (paragraph 4) area:
A number of important surveillances were performed in a professional manner.
In one instance, the licensee discovered and corrected a
flaw in vendor-supplied information during a moderator temperature coefficient test.
Management control and pretest briefings were excellent.
The licensee strongly pursued a capacitor failure in an inverter, modifying all four Unit 2 instrument inverters and initiating generic review by vendors.
In the areas inspected, violations or deviations were not identified.
9311160082 93i025 PDR ADOCK 05000335-Q PDR~
I
REPORT DETAILS Persons Contacted Licensee Employees D.
C.
J.
H.
J.
R.
R.
W.
J.
R.
H.
R.
J.
J.
L.
G.
A.
C.
L.
C.
J.
D.
J.
W.
D.
E.
Sager, St.
Lucie Plant Vice President Burton, St. Lucie Plant General Manager Barrow, Fire/Safety Coordinator Buchanan, Health Physics"Supervisor Scarola, Operations Manager Church, Independent Safety Engineering Group Chairman Dawson, Haintenance Manager Dean, Electrical Maintenance Department Head Dyer, Plant guality Control Manager Englmeier, Site guality Manager Fagley, Construction Services Manager Frechette, Chemistry Supervisor Holt, Plant Licensing Engineer Hosmer, Site Engineering Manager HcLaughlin, Licensing Manager Madden, Plant Licensing Engineer Henocal, Mechanical Maintenance Department Head Pell, Site Services Manager Rogers, Instrument and Control Maintenance Department Kead Scott, Outage Manager Spodick, Operations Training Supervisor West, Technical Manager West, Operations Supervisor White, Security Supervisor Wolf, Site Engineering Supervisor Wunderlich, Reactor Engineering Supervisor Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personnel.
NRC Personnel 2.
I. Selin, NRC Chairman S. Ebneter, Region II Administrator
- S. Elrod, Senior Resident Inspector
- H. Hiller, Resident Inspector
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
Plant Status and Activities a.
Unit I Unit I began the inspection period at power.
The licensee reduced power to 60 percent from August 30 to September 2 while the lA2 main
circulating water pump bearing cooling water low flow indication was investigated.
The unit was returned to full power following evaluation by the vendor and the addition of a bleed-off indicator to show that the bearing housing was actually full of water.
Operators reduced power to 75 percent at about 5 a.m.
on September 18 and throttled the 1B1 circulating water pump because a large influx of jellyfish had caused the 1B1 traveling screen shear pin to shear.
Operators manually tripped Unit 1 at 5:25 a.m.
on September 18 because, by then, the jellyfish influx had also caused the 1B2 circulating water pump motor overloads to function.
Loss of two adjacent circulators requires tripping the turbine to prevent turbine blade damage.
Unit 1 was restarted on September 19.
On September 20, while at 63 percent power, the 1A1 traveling screen and circulator pump were stopped due to differential pressure from jellyfish, then at 12:05 p.m., the 1A2 traveling screen shear pin sheared from overload.
Operators tripped Unit 1 reactor and turbine because of impending loss of all circulator pumps.
Unit 1 was restarted on September 21.
On September 22, jellyfish incursions caused operators to downpower Unit 1.
Operators reduced power to about 11 percent, not quite to the turbine trip permissive level, before impending loss of circulators prompted a manual reactor trip then a turbine trip.
The licensee maintained Unit 1 in hot standby until September 24, during the worst of the jellyfish intrusion, then started up September 24, reaching about 33 percent power.
The Unit 1 generator was then taken,off line on September 25 to repair the no.
2 governor valve.
The turbine was restarted that evening, ending the inspection period in day 1 of power operation.
b.
Unit 2 C.
Unit 2 began the inspection period at full power and has run at power since.
Several power reductions occurred to provide for condenser cleaning.
Beginning September 22, power was reduced to varying levels as low as 55 percent to prepare for jellyfish incursions.
Unit 2 ended the period in day 45 of power operation since startup on August 11.
Site Visits NRC Chairman Hr. Ivan Selin, Deputy Secretary of Energy Hr. William White, and the Region II Regional Administrator Hr. Stewart Ebneter visited on August 31, 1993, in conjunction with a visit by Prime Hinister of the Russian Federation Chernomyrdi.
Review of Plant Operations (71707)
a
~
Plant Tours The inspectors periodically conducted plant tours to verify that monitoring equipment was recording as required, equipment was properly tagged, operations personnel were aware 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 positions, 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 to be adequate.
The inspectors routinely conducted partial 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:
AC Distribution, 2A, 2B, 2C AFW, and Unit
ICW b.
Plant Operations Review 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, operating orders, standing 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.
During this inspection period, the inspectors reviewed the following tagouts (clearances):
1-93-09-030 1B AFW Pump Motor Bearing Replacement
2-93-08-114 2A instrument Inverter Capacitor Change out On September 6, the inspector observed from the control room as operators reduced Unit 2 power from 89 percent to 58 percent at
NW per minute per OP 2-0030125, Rev 18, Turbine Shutdown-Full Load to Zero Load, to accommodate removing a condenser waterbox from'ervice for cleaning.
The condenser specification is 4.5 inches mercury average if all waterboxes are in service or 4.0 inches mercury maximum if less than
waterboxes are in service.
Increasing condenser fouling had forced a number of small power reductions since August 31.
Power was at 89 percent just prior to this reduction for cleaning.
On September 7 at 9:50 a.m., Unit 2 condenser backpressure exceeded 4.0 inches of mercury and the operators further reduced power from 58 per cent to 52 percent per OP 2-0030125, Rev 18.
(2)
(3)
Operators reduced power to 75 percent at about 5 a.m.
on September 18 and throttled the 1B1 circulating water pump because a large influx of jellyfish had caused the 1B1 traveling screen shear pin to shear.
Operators manually tripped Unit 1 at 5:25 a.m.
on September 18 because, by then, the jellyfish influx had also caused the 1B2 circulating water pump motor overloads to function.
Loss of two adjacent circulators requires tripping the turbine to prevent turbine blade damage.
The unit was stabilized and taken to mode 3.
The inspector responded to the trip and verified that plant conditions were stable and as expected.
The licensee restarted Unit 1 on September 19 following repair of the 181 and 1B2 traveling screens, and completion of a PCH to use a "reactor regulating" power range neutron detector in place of a grounded
",reactor safety channel" detector.
Since the unit had remained hot in mode 3, procedurally described prestart activities associated with heatup from cold to mode
were not performed.
Prior to the operator commencing the startup by pulling regulating group CEAs, the inspector evaluated the licensee's decisions recorded on OP 1-0030120, Rev 52, Prestart Checkoff List.
The inspector judged these decisions to be prudent and within regulatory requirements.
The inspector verified shift manning, the use of a "reactivity manager" and a separate management-on-shift representative, and reactor engineering present and monitoring RPS power channels B
and D for the inverse count rate ratio.
Procedures in use were:
OP 0030126, Rev 13, Estimated Critical Conditions and Inverse Count Rate Ratio.
OP 1-0030120, Rev 52, Prestart Checkoff Lis 'I fJ
OP 1-0030122, Rev 50, Reactor Startup.
(4)
On September 20, while at 63 percent power, the 1A1 traveling screen and circulator pump were stopped due to differential pressure from jellyfish, then -at 12:05 p.m., the IA2 traveling screen shear pin sheared from overload.
Operators tripped Unit 1 reactor and turbine because of impending loss of all circulator pumps.
Unit 1 was restarted on September 21.
(5)
On September 22, jellyfish incursions caused operators to downpower Unit 1.
Operators, reduced power to about ll percent, not quite to the turbine trip permissive level, before impending loss of circulators prompted a reactor trip then a
The licensee maintained Unit 1 in hot standby until September 24, during the worst of the jellyfish intrusion, then started up September 24, reaching about
percent power.
(6)
At 7:40 a.m.
on September 25, the licensee commenced a Unit
load reduction from 33X reactor power because the No.
governor valve would not open due to a sheared anti-rotation pin.
Unit 1 was taken off line at 9:00 a.m.
and entered Node
at 9:15 a.m.
Following the replacement of the No.
2 governor valve anti-rotation pin, the unit entered Mode 1 at ll:25 a.m.
and was placed back on line at 12:56 p.m.
Reactor power was stabilized at 20X at 1:30 p.m.
Power ascension was commenced at 3: 11 p.m.,
and reactor power was stabilized at 50X at 3:48 p.m.
Power ascension was re-commenced at 5:07 p.m.,
and reactor power was stabilized at 60X at 5:28 p.m.
Power ascension was re-commenced at 6:24 p.m.,
and reactor power was stabilized at 98X at 10:10 p.m.
Power ascension was re-commenced at 10:32 p.m.,
and 100X reactor power was reached at ll:15 p.m.
Unit 1 ended the inspection period in day 1 of power operation.
c.
Technical Specification Compliance 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.
d.
Physical Protection The inspectors verified by observation during routine activities that security program plans were being implemented as evidenced by:
proper display of picture badges; searching of packages and personnel at the plant entrance; and vital area portals being locked and alarmed.
By telephone call and letter to the licensee of August 27, 1993, the NRC exercised enforcement discretion on August 31, 1993, in matters affecting the visit of foreign dignitaries accompanied by their security staff, U. S. government officials, and U. S. Secret Service Agents.
Enforcement discretion concerned:
searches per sections 3.2 and 3.3 of the site physical security plan, other access controls, and reporting requirements.
. The enforcement discretion was ended immediately after the visit was concluded on August 31.
This enforcement discretion is closed.
Plant operators continued to successfully meet a number of challenges this period.
Unit 1 reactor startups were well planned and coordinated.
Unit 2 operations were carefully coordinated to support Unit 1 concerns.
4.
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 tests were observed:
a
~
Unit 2 Auxiliary Feedwater Actuation System Honthly Functional Test on September 7 per NPWO 64/1848 and 18C Procedure 2-0700051, Rev 16, TC 2-93-124, same title.
Activities specifically observed included use of a reader and a performer to accomplish the test, procedure usage, communications with the RCOs, and effect of the TC.
This procedure was a mature procedure well designed for use in a four-channel surveillance test.
The procedure had signoff spaces under each step for each channel.
The overall effect on the page was four vertical columns of signoffs with steps interspersed so the same section could be repeated four times, yet the technicians could easily retain their place.
Data was collected in attached tables, again in a four-column mode.
The TC caused a test meter for one of the channels to be connected directly, vice using the test
connection and switch, because the switch was not functioning due to a dirty contact.
During the test, the inspector observed the technician use a medical clamping device (hemostat)
several times to hold test pushbuttons depressed for three to five minutes at a time.
Pushbutton test switches are used to prevent permanently disabling signal paths by leaving a [toggle] switch in the wrong position.
Licensee management decided to specify use of the hemostat to reduce wear on the technicians who would be holding the buttons down for hours, and had so changed the procedure.
The inspector considered the hemostat to be a mechanical jumper controlled by a specific procedure and evaluated the effectiveness of the procedural control.
Three factors favored hemostat removal after the surveillance.
It stuck out so as to be obvious, It prevented closing the panel cover, and It would have to be removed to obtain final system indications prior to proceeding.
The inspector considered the use and control of this jumper acceptable.
On September 11, 'the inspector witnessed the Unit 1 operators testing the various turbine trips per OP 1-0030150, Rev 63, Secondary Plant Operating Checks and Tests.
These tests included the overspeed trip, thrust bearing trip, low bearing oil pressure tlip, low vacuum trip, and solenoid valve trips 20/ET, 20-1/OPC, and 20-2/OPC.
Coordination, management control, and test performance were excellent.
NPWOs were submitted for test discrepancies.
The 20/ET, 20-1/OPC, and 20-2/OPC tests were possible only because the licensee invented and perfected a test block for the hydraulic system following a turbine failure to trip during Spring, 1992.
The procedure was lacking in good human factors elements.
Examples include use of generic valve name vice valve number in some cases, and a repetitive section for three separate solenoids with a poor listing of the individual valve numbers.
This is of concern because a mis-step can trip the turbine, then the reactor, then challenge safety systems.
The licensee is evaluating the procedure.
The inspector does not plan a special followup because this sensitive test is often observed.
On September 13, the inspector witnessed the Unit 1 MSIV periodic test per OP 1-0810050, Rev 12, Main Steam Isolation Valves Periodic Test.
The tailboard meeting was well conducted.
The test was properly performed and was successful.
On September 16, the inspector observed the operators and reactor engineering staff determine Unit 2 moderator temperature coefficient I
per AP 3200051, Rev 11, At Power Determination of Moderator Temperature Coefficient.
This surveillance determines MTC and confirms that it is within TS requirements.
Since it was an
"infrequently Performed evolution" per AP 0010020, plant management conducted a detailed pre-evolution briefing.
The inspector focused on operator action, preparation, interface between reactor engineering and operations persons, management involvement, proper suspension and reinstatement of TS 3. 1.3.6, Regulating CEA Insertion Limits, and conduct of the surveillance.
The inspector also reviewed the procedure and completed data.
The pre-evolution briefing was extremely thorough, coordination between operators at the reactor control and turbine control stations was excellent, and surveillance performance was very smooth.
Suspending TS 3. 1.3.6 per special test exception 3. 10.5 required the determination of reactor power at least once per hour and continuous monitoring of linear heat rate.
These requirements were specifically built into the test procedure.
The six data runs were uneventful, and resulted in finding that MTC was -20.6977 pcm/degree F,
wel'1 within the TS limit of +3 to -30 pcm/degree F.
Though MTC met the NRC requirements, it did not meet the vendor acceptance criteria of being within 3 PCM/degree F of predicted.
The vendor promptly evaluated the data, found that the original rod worth curve data contained an administrative error and was also based on a "new" methodology.
They provided the licensee with a corrected rod worth curve with the error corrected and based on the customary methodology.
The MTC then met vendor acceptance requirements.
The licensee has asked the vendor to address quality aspects of the error.
The inspector observed that the completed surveillance document did not contain the unsatisfactory result but did contain the vendor correspondence forwarding the corrected data.
The inspector judged this omission to be a weakness in Reactor Engineering recording data (calculation results in this case),
but not severe enough to constitute a violation of the ANSI N18.7-1976 requirement that surveillance records show what conditions were found, what was done, and how it was left.
The licensee is adding the original failure to the record and evaluating whether or not other specific actions are needed.
The inspector planned no specific followup since Reactor Engineering documentation is often reviewed during routine inspections.
Surveillances were performed well this perio.
Haintenance Observation (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 observed:
a.
NPWO 6877/66 HFA Relay Adjustment per Procedure 0960066 This maintenance activity was based on previously finding the latch on latching HFA relays to be set too tight and not latching properly.
While the reasons are not obvious, relay component clearances had been found to change while in service.
The two-sided latches are often crooked such that one side makes contact while the other has clearance.
This one for the 2C Intake Cooling Water pump had been found needing adjustment during an August inspection and had been adjusted.
The inspector accompanied the supervisor to inspect the latch position prior to NPWO closeout.
The supervisor was knowledgeable.
The latch was straight and had adequate clearance.
b.
NPWO 6873/66 Check Capacitors for Proper Operation and Change per PCM 171-293M (2A Instrument Inverter)
Failure of Unit 2 Instrument Inverter In ut Ca acitors.
On August 10, 1993, at St. Lucie Unit 2, the 2B instrument power supply inverter failed suddenly while in operation.
This loss of power tripped the B channel of the Reactor Protection System (RPS),
Engineered Safety Feature Actuation System (ESFAS),
and Auxiliary Feedwater Actuation System (AFAS).
Four of eight Reactor Trip Circuit Breakers (TCBs) tripped.
The licensee found one of seven 5400 microfarad electrolytic capacitors had failed at the inverter Direct Current (DC) power input.
Another capacitor failed during troubleshooting.
All seven were replaced.
On August 21, the 2C instrument power supply inverter also failed suddenly while in operation, with similar results.
In this case, one DC input capacitor and the commutating, capacitor had failed.
This was the second such event in two week's involving input capacitors that were less than two years old, having been both manufactured and placed in service in the Spring of 1992 to preclude age-related inverter failures.
The licensee then replaced all seven capacitor's on the 2C
inverter and initiated a substantial investigation for root cause and generic issues.
After the second failure, the licensee had found that the 5400 microfarad capacitors had reduced capacitance ranging from failed to very low.
Two days later, the capacitors had returned to nominal 5400 microfarad values.
Other low-reading capacitors returned to the inverter vendor also tested
"good".
The capacitor manufacturer -
originally MEPCO prior to purchase by the present PHILIPS COMPONENTS -
found that the explanation of capacitors testing "failed" then testing
"good" also explained why the
"new" capacitors failed in service.
Capacitor technology has improved significantly in recent years.
The housing for the 5400 microfarad capacitor was about three inches in diameter and six inches long, and the original ones were almost full of foil wrap.
Mounting position of the originals proved unimportant by virtue of horizontally-mounted capacitors operating for years.
The recently manufactured replacements were the same housing dimension, however the foil wrap diameter inside was only about one and three eighths inches.
The bottom half was submerged in tar.
When mounted on its side for a long period, as these were in service, the dielectric oozed out of the foil wrap, resulting in capacitance loss.
When the capacitor was repositioned to upright, the dielectric wicked back up into the foil wrap, and capacitance was restored.
The component labeling said nothing about vertical mounting only.
The inverter manufacturer, Solidstate Controls, had changed from using 5400 microfarad capacitors to 7700 microfarad ones in 1980 but did not update the specification for previously-manufactured nuclear-use inverters.
Following the inverter failures in August, 1993, and at the licensee's request, the inverter manufacturer declared the 7700 microfarad capacitors to be functionally identical, and physically interchangeable with the 5400 micr ofarad ones and
'uthorized them as replacements for St. Lucie.
They are believed not to have the loss-of-dielectric problem.
The licensee is reviewing other capacitor applications in safety-significant equipment for similar problems.
In addition to following the root cause effort in detail, the inspector observed maintenance activities replacing the DC input capacitors per the above NPWO.
Attributes included preparation, management involvement, work practices, instrument calibration, and retesting.
The work was well controlled.
The journeymen were well aware of and followed procedural requirements.
The inspector concluded that maintenance activities were effective in restoring plant reliabilit.
Fire Protection Review (64704)
During the course of their normal tours, the inspectors routinely examined facets of the Fire Protection Program.
The inspectors reviewed transient fire loads, flammable materials storage, housekeeping, control of hazardous chemicals, ignition source/fire risk reduction efforts, and fire barriers.
Fire protection activities were well performed.
7.
Onsite Followup of Events (Units
and 2)(93702)
Nonroutine plant events were reviewed to determine the need for further or continued NRC response, to determine whether corrective actions appeared appropriate, and to determine that TS were being met and that the public health and safety received primary consideration.
Potential generic impact and trend detection were also considered.
Manual reactor trips of Unit 1 on September 18, 20, and 22 were the result of jellyfish incursions causing or threatening failure of some of the traveling screens.
These are further discussed in paragraph 3.b.(2),
(4),
and (5).
8.
Followup of Regional Requests (Units 1 and 2)
(92701)
The inspector followed up on Region II concerns about potential degradation of Boraflex inserts in spent fuel pool racks, as follows:
a.
Does the plant use Boraflex in spent fuel pool racks?
St.
Lucie Unit 1 uses Boraflex, Unit 2 does not.
b.
Is the licensee aware of the potential problem with Boraflex?
Is the licensee's operating staff cognizant of a potential problem if the spent fuel pool is diluted?
Yes, Yes.
Ap 1-0010123, Rev 93, Administrative Control of 'Locked Valves and Switches, specifies that the demineralized water hose valve in the spent fuel pool area be locked shut to prevent unauthorized use.
OP 1- 0350020, Rev 18, Fuel Pool Cooling and Purification System - Normal Operations, controls filling the pool, purification, filtering, draining the canal, and silica reduction.
ONOP 1-0350030, Rev 7, Fuel Pool Cooling Off-Normal Procedure, addresses high and low levels in the pool.
The inspector observed in the control room a request from Chemistry to use the demineralized water connection to make up to the pool because the boric acid concentration was getting high.
This was still under effective administrative control of the operators because of the lock.
The utility was asked to consider whether additional text was needed in the cooling
system OP.
The utility did revise it to address when to use the demineralized water source for adding water.
c.
Are there procedural controls to prevent spent fuel pool dilution?
Yes, see the answer to question b.
d.
At what boron concentration is the spent fuel pool maintained?
St. Lucie Unit 1 and Unit 2 technical specifications 5.6. l.a.3 require spent fuel pool water boron concentration be maintained greater than or equal to 1720 ppm.
Unit
FSAR section 9. 1.2.3.5 requires that the Unit 1 spent fuel pool always contain boric acid at 1720 ppm when irradiated fuel in the pool.
Unit 2 FSAR section 9. 1.2.3 requires that the Unit 2 spent fuel pool contain boric acid at 1720 ppm, however no credit is taken for it in analysis.
Chemistry procedure C-61, Rev 7, Maintaining Spent Fuel Pool Chemistry, has operating ranges of 1800-2400 ppm boric acid for Unit 1 and 1800-1950 ppm for Unit 2.
e.
Does the licensee have a chemistry sampling program?
If so, what are the results of the last three samples?
(date and ppm)
Yes, the licensee has a chemistry sampling program.
The tests are scheduled per Chemistry Procedure C-Ol, Rev 35, Schedule of Periodic Tests.
Spent fuel pool parameters are specified in Chemistry procedure C-61, Rev 7, Maintaining Spent Fuel Pool Chemistry.
Dates and corresponding Unit
SFP samples were:
8/19/1993 2467 ppm.
8/26/1993 2445 ppm.
9/02/1993 2480 ppm.
These samples were outside the administrative limit, which was based on being well below a limit reducing visibility of the numbers on fuel assemblies.
There was no actual high "safety limit".
The design limit for visibility was 2620 ppm, but even that may not actually impair visibility.
The concentration of boric acid was satisfactory.
f.
How does the licensee assure the integrity of the Boraflex?
The integrity of the Boraflex is assured by scheduled periodic removal of Boraflex test coupons for analysis to determine viability.
Both region 1 and region 2 contain test coupon lj l~
The applicable procedure is OP 1-0010144, Rev 2, Unit
Surveillance Test Program For Boraflex Neutron Absorbing Haterial Contained in the Spent Fuel Racks.
LOI-1-RE-04, Rev 0, Unit 1 Boraflex Blackness Testing, also applies.
HOLTEC International Report HI-931042, of July 1993, Examination of St.
Lucie Unit 1 Accelerated Boraflex Surveillance Coupons Numbers 5.and 6, reports a recent test.
Initial review of the data gathered shows that this site is sensitive to the condition of Boraflex neutron absorbers in the spent fuel pool racks.
Exit Interview The inspection scope and findings were summarized on October 4, 1993, with those persons indicated in paragraph 1 above.
The inspector described the areas inspected and discussed in detail the inspection results.
Proprietary material is not contained in this report.
Dissenting comments were not received from the licensee.
Abbreviations, Acronyms, and Initialisms AFAS AFW ANSI CEA DC ECCS ESF ESFAS F
FSAR HFA IKC ICW LCO LOI HSIV HTC HW NPWO NRC ONOP OP PCH pcm RCO Rev RPS RWP TC TCB Auxiliary Feedwater Actuation System Auxiliary Feedwater (system)
American National Standards Institute Control Element Assembly Direct Current Emergency Core Cooling System Engineered Safety Feature Engineered Safety Feature Actuation System Fahrenheit Final Safety Analysis Report A GE relay designation Instrumentation and Control Intake Cooling Water TS Limiting Condition for Operation Letter of Instruction Hain Steam Isolation Valve Hoderator Temperature Coefficient Hegawatt(s)
Nuclear Plant Work Order Nuclear Regulatory Commission Off Normal Operating Procedure Operating Procedure Plant Change/Hodification PerCent Hilli (0.00001)
Reactor Control Operator Revision Reactor Protection System Radiation Work Permit Temporary Change Trip Circuit Breaker