IR 05000335/1989018
| ML17223A272 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 07/31/1989 |
| From: | Butcher R, Crlenjak R, Elrod S, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17223A271 | List: |
| References | |
| 50-335-89-18, 50-389-89-18, IEB-89-001, IEB-89-1, NUDOCS 8908170568 | |
| Download: ML17223A272 (17) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTAST., N.W.
ATLANTA,GEORGIA 30323 Report Nos:
50-335/89-18 AND 50-389/89-18 Licensee:
Florida Power 5 Light Co 9250 West Flagler Street Miami, FL 33102 Docket Nos.:
50-335 and 50-389 Facility Name:
St. Lucie 1 and
Inspection Condu
- June 2 - J ly~,
1989 License Nos.:
S.
R. Butch
~
. enlor side Turkey oint Inspector r d, enior esid t Srepector Date Signed 7~ p( vg Date Signed i. A.
S
,
ess nt In ector Approved By:
r R.
V.
rlenjak, S
on Chi Division of Reactor Proje s
Date S>gne te gned SUMMARY Scope:
This inspection involved on site activities in the areas of Technical Specification compliance, operator performance, overall plant operations, quality assurance practices, station and corporate management practices, corrective and preventive maintenance activities, site security procedures, radiation control activities, and surveillance activities.
Results:
Of the areas inspected, no violations or deviations were identified.
Two URIs** were identified during this inspection.
These URIs were concerned with the mispositioning of the 1B Diesel Fuel Oil Transfer Pump Discharge Valve, paragraph
(URI 335,389/89-18-01),
and the control of safety-related heat exchanger tube plugging, paragraph
(URI 335,389/89-18-02).
89081705b8 8~0731 PDR ADCICK 05000335 G
PNU
This inspection identified two positive licensee initiatives, one in the area of plant operations and the other associated with outage related
.activities.
These initiatives demonstrated operational strengths in the area of steam generator and reactor coolant system water chemistry (paragraph 4)
and in outage related operations associated with the resolution of steam generator plug removal problems (paragraph 10).
- Unresolved items are matters about which more information is required to determine whether they are acceptable or may involve violations or deviation REPORT DETAILS Persons Contacted Licensee Employees
- D. Sager, St. Lucie Site Vice President
- G. Boissy, Plant Manager
- J. Adams, Acting Chairman, Independent Safety Engi
- J. Barrow, Operations Superintendent
- J. Barrow, Fire Prevention Coordinator
- H. Buchanan, Health Physics Supervisor C. Burton, Operations Supervisor C. Crider, Outage Supervisor D. Culpepper, Site Juno Engineering Manager
- R. Dawson, Maintenance Superintendent R. Diehl, Nuclear Watch Engineer R. Frechette, Chemistry Supervisor J. Harper, guality Assurance Superintendent
- J. Hoffman, Project Engineer, Juno Engineering
- C. Leppla, 18C Supervisor L. McLaughlin, Plant licensing Supervisor V. Mendoza, System Engineer
- B. Parks, guality Assurance Supervisor
- R. Parks, Backfit Project Manager
"J. Riley, Procedures Group Superintendent L. Rogers, Electrical Maintenance Supervisor
- N. Roos, guality Control Supervisor B. Sculthorpe, Reliabil-ity and Support Supervisor
- R. Sipos, Services Manager
- C. Swiatek, Technical Staff Engineer
- 0, West, Technical Staff Supervisor
- J. West, Acting Operations Supervisor W. White, Security Supervisor
- C. Wilson, Mechanical Maintenance Supervisor
- G. Wood, Maintenance Reliability Supervisor
- E. Wunderlich, Reactor Engineering Supervisor neering Group Other licensee employees contacted included technicians, operators, mechanics, security force members and office personnel.
- Attended exit interview Note:
An Alphabetical Tabulation of acronyms used in this report is listed in paragraph 14.
Plant Status Unit 1 began the inspection period at power.
On June 28, day 280 of power operation since its return from outage, the unit was shut down as planned to replace'ertain'G hot leg tube plugs.
Other accumulated outage-dependent work was also planned.
The unit ended the inspection period in day 12 of the outag Unit 2 began the inspection period at power; The unit was taken off line and power reduced to the startup range on June 26 to investigate indications of 'decreasing oil level in the 2B1 RCP upper bearing sump.
That investigation required entry 'inside the containment biological shield.
During power escalation on June 27, the turbine and feedwater pumps tripped from high SG water level.
The turbine trip initiated a
Unit 2 was restarted without incident the next morning, June 28.
At the end of the inspection, the unit was in day 12 of power operation since restart.
3.
Plant Tours (Units 1 and 2) (71707).
Plant tours were periodically conducted 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 FCCS systems.
Valve, breaker/switch lineups and equipment conditions were randomly verified both locally and in the control room.
The inspectors walked down the accessible Unit
ECCS areas, with the exception of the SDCHX rooms, to verify that system lineups met operability requirements and equipment conditions were satisfactory.
The spaces and associated equipment were in satisfactory condition.
The pumps were operating providing SDC to the RCS.
The LPSI pump valve lineups in those spaces were correct per drawing 8770-G-078, sheets 130-131 and procedure OP 1-0030127, Rev. 43, Reactor Plant Cooldown, Hot Standby to Cold Shutdown.
The control room indications of the LPSI system valve lineup in this mode were also correct.
The radiological condition in the spaces was acceptable.
Some minor leakage was noted on the 1B LPSI pump, which did not cause a concern at this point.
The licensee is aware of this condition and is taking the appropriate corrective actions.
During plant tours, a nitrogen gas cylinder was found in the 2A electrical penetration room.
The cylinder was standing free of the wall with a loop of magenta and yellow Health Physics barrier line loosely wrapped around it.
The line was not secured to,the wall.
Two other barriers were not properly maintained in other areas.
Maintenance of these barriers was discussed with plant management and the barriers were corrected promptl The gas cylinder was promptly removed from the safety-related area.
Since gas cylinder storage and control was the subject of recent Violation 335,389/89-16-01, this instance was not pursued separately.
Plant Operations Review (Units 1 and 2) (71707)
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.
During routine operations, control room staffing, control room access and operator performance and response actions were observed and evaluated.
The inspectors conducted random off-hours inspections to assure that operations and security remained at an acceptable level.
In addition, the inspectors verified the status of control room annunciators with the licensee's operations staff and observed shift turnovers to verify that they were conducted in accordance with approved licensee procedures.
Following the investigation of the RCP 281 and 2A2 motor upper sump level indications and replacement of one sump level indicator cable, the operations staff closed out the Unit 2 containment building on June 27th.
The operator toured the containment to ensure no perso'nnel remained and that work items had been completed.
During the Unit 2 power escalation attempt on June 27th, the inspectors observed much of the operations staff activity in the control room and on the turbine deck.
Several minor problems occurred:
the feedwater controls
. were not operating smoothly in automatic; CEA movement was needed to track feedwater variations
- creating some CEA-to-group deviations; and one turbine control valve and one throttle valve would not open when tested.
After the turbine valves were repaired, Unit 2 continued to power escalation from approximately two percent power.
Late on June 27, while at about 21% power, the turbine and main feed pumps tripped on high steam generator level.
The turbine trip initiated a reactor trip.
Safety systems performed as designed.
The post-trip review indicated that personnel error was the primary cause.
Unit 2 was restarted the next morning and returned to power without incident.
After Unit 2 returned to power, Unit 1 was shut down for steam generator tube plug replacement.
The inspectors observed the:-shutdown to approximately 30 percent power.
Overall control in tHe control room was excellent.
The operators appeared to be extremely focused on the job at hand.
The few small problems that did arise, such as the failure of the 4A heater level control, were handled in a routine manner.
During this shutdown, the licensee invoked their chemistry hold policy.
After the unit has been brought to a non-critical condition, it is held at normal operating pressure and 350'F for 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> prior to completing the shutdown to outage conditions.
SG blowdown and CVCS purification of the
RCS are maintained during the hold.
The benefits are thought to outweigh the negative aspect of the extended downtime.
The benefits of,the hold are as follows:
Maintaining SG blowndown assists in removing SG contaminants such as chlorides, fluorides, sulfates, etc.
prior to shutdown.
These corrosion causing agents normally hide out in SG sludge after shutdown.
With the RCPs running, the purification filters of the CVCS are used to remove corrosion products and iodines which are still in suspension in the RCS during the hold.
The site has seen increases'f between 300 to 600 Rem/hr in the purification filters/ion exchangers during this process.
This process reduces dose rates and airborne activity in containment during the outage.
Those reductions are accompanied by lower manrem exposure totals and a reduction in the potential for skin contamination.
When coupled with the damage resistant fuel discussed in previous inspection reports, the chemistry hold provides substantial benefits for both-equipment and personnel.
The inspectors performed an in-depth review of the following tagouts (clearances):
1-6-116 1B CCWHX (PWO 2859/61)
1-6-130/19,20 1A and
.18 HPSI Pumps 1-6-155 183 Pressurizer Heater Control Center 1-6-152 1B Main Feed Pump Discharge Valve 1-6-158 1B LPSI Pump 1-6-161 1A MSIV Bypass Valve, MV 08-18 1-8-404 Unit 1 Administratively-Controlled Equipment (partial)
2-6-72 2B AFW Pump (PWO 2658/62)
No violations or deviations were identified.
5.
Technical Specification Compliance (Units 1 and 2) (71707)
Licensee compliance with selected TS LCOs and surveillance requirements was verified.
These verifications were accomplished by the inspector performing direct observation of monitoring instrumentation, valve positions, switch positions, and by review of completed logs and records.
The licensee's compliance with LCO action statements was reviewed on selected occurrences as they happened.
The inspectors verified that plant
procedures involved were adequate, complete, and the correct revision..
Instrumentation and recorder traces were observed for abnormalities.
No violations or deviations were identified.
.6.
Maintenance 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 assure that priority was assigned to safety-related equipment.
Portions of the following maintenance activities were observed:
PWO 5887/61, HFA Relay Inspection.
This PWO involved inspection of the relays per GE SALs 188.1 and 192. 1 armature binding and finger binding, respectively.
PWO 5964/61, Add Rebound Springs to I-T-E K600 Circuit Breakers.
PWO 5084/61, Inspect Load Center Current Transformers.
This PWO involved inspection and replacement of current transformers whose insulation was softening and running down into the electrical conductor.
This appeared to be a service life phenomenon.
The licensee was addressing part suitability with the vendor.
PWO 5143/61, Pressurizer Heater Load Center 1A3.
PWO 5927/61, Pressurizer Heater Load Center 183.
These PWOs replaced the circuit breaker stabs with longer ones that make more positive contact with the bus bar.
The new stabs had a
small contact area due to the manufacturing process putting a nipple on them.
The licensee was dressing and resilvering the parts and addressing the part quality with the vendor.
PWO 2658/62, Install motor coupling on 2B AFW Pump.
PWO 2859/61, Replace Rubber Tube Plugs in 1B CCWHX with Brass Plugs.
This PWO is discussed in paragraph 12.
On May 27, during the last inspection period, operators identified minor leakage from the lA LPSI pump casing.
A PWO was written to remove, clean, apply sealant, and re-install the stud from around which the leakage was reported.
The gasket between the mating halves of the casing was
reportedly replaced in late 1988.
Operations had not run the pump to quantify leakage at the.time.
On May 29, during initial evaluation of the work scope, at least four casing studs were found to have a significant buildup of boric acid crystals on the nut heads; the accumulation was approximately 1 and 1/2 times the diameter of the nuts.
Crystals had also accumulated on the pump mechanical seal.
Subsequent pump operation identified a leak rate of about one drop.per three minutes from an area involving four studs and approximately 90 degrees of arc.
The crystals were removed from the pump that day.
Casing sealing joint evaluation for corrosion damage and leakage concluded that the pump was operable.
The licensee deferred sealing the casing seal points until this inspection period after parts arrived.
It was stated that no gasket seating surface problems were noted during the tear down inspection.
As discussed in the operations section of this report, the cable to the 2A2 RCP upper motor oil level reservoir required replacement.
The replacement cable was drawn from site stores; the cable had been precut to fit the intended application.
The cable was found to be about 10 feet short upon installation.
A temporary cable had been previously strung to the level sensor to test the sensor and electronics during the determina-tion of cable failure.
This temporary cable was used for the return to power.
Juno site engineering performed a containment building walk down of the cable run to ensure that it was acceptable for such use.
The NRC inspectors discussed the walkdown criteria with the engineers involved following the walkdown and found the criteria to be satisfactory.
No violations or deviations were identified.
7.
Review of Nonroutine Events Reported by the Licensee (Units 1 and 2)
Non-routine plant events were reviewed for potential generic impact, to detect trends, and to determine whether corrective actions appeared appropriate.
Events which were reported immediately were also reviewed as they occurred to determine that TS were being met and that the public health and safety received primary consideration.
On June 14, the operations staff, performing a weekly diesel fuel oil system valve lineup, discovered that the 1B fuel oil transfer pump discharge valve was mispositioned shut.
The normally-locked-open valve, V17215, was found to be locked shut, which made the lB EDG inoperable.
The valve position had been independently audited on June 13th by the gC organization and verified that the valve position was proper at that time.
The valve is a
one and one half inch, rising stem valve and located in a small concrete structure within. the radiation controlled area adjacent to the 1B transfer pump.
By reviewing the logs for the event time period, the inspectors determined that no other vital electrical equipment had been declared out of service during the potential time that the valve could have been locked.
As required by TS, the licensee did not attempt to start the adjacent train EDG while the subject valve was closed.
The licensee is currently investigating this event and drafting a formal LER.
Therefore, the inspectors determination with respect to the operability of the 1B EDG is pending on the result of the licensee's
ongoing investigation and review of the mispositioned valve.
This item is identified as URI 335,389/89-18-01 and will be reviewed further during a subsequent NRC inspection.
8.
Physical Protection (Units 1 and 2) (71707)
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.
No violations or deviations were identified.
9.
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 during the power ascension on June 28, 1989:
OP 2-3200020, Rev 7, Primary System Manual Calometric OP 2-1200051, Rev 7, Nuclear and Delta T Power Calibration The plant was stablized at approximately 35 percent power while the readings for the calculations and subsequent calibration occurred.
The surveillances were performed in accordance with procedures.
No violations or deviations were identified.
10.
Outage (71707)
The inspector observed the following overhaul activity during the ongoing Unit 1 outage:
Large Electrical Motor Repair The ICW pump 1C motor was removed and sent to Tampa for electrical work and testing.
The inspectors observed the electrical recon-nection and the no-load (uncoupled)
test run of the motor per PWO 5093 and found the reconnection and test to be satisfactory.
RCP Pump Balancing
The inspector accompanied the licensee on an inspection of the Unit
RCPs to obtain balance information.
The 1A1 pump, in particular, had been operating before this mini-outage with 10 to 12 mils of displacement as sensed by two local pump sensing units'.
This was a
higher value than desired by FPL but well below vendor-recommended action values.
The technicians surveyed 3 of the 4 pumps for balance weight locations and other vital information.
This information was to be placed into computer programs for followup balancing, which will occur outside of this inspection period.
The actions taken by the licensee appeared prudent and within pump and valve code requirements.
SG Tube Plug Removal NRC Bulletin 89-01, Failure of Westinghouse Steam Generator Tube Mechanical Plugs, dated May 15, 1989, indicated SG tube problems.
FPL response letter L-89-223, dated June 19, 1989, indicated that the Unit
SGs contained the subject mechanical plugs and the unit would be shut down in the summer of 1989 for defective plug replacement.
The present outage, which began on June 28th, was a result of the above commitment.
The inspectors observed the CE presentation and plug removal technique demonstration.
CE, the SG manufacturer, had contracted to replace a total of 63 plugs in SGs 1A and 1B.
The presentation, using an existing site SG mockup, was impressive and well explained.
CE did not have Westinghouse plugs to use in the presentation nor did they have them for technique development, this caused some minor operational problems during,the actual plug removal process.
The inspectors observed tube plug removal from the 1A SG.
The observation point was a
remote station, outside of the containment building, that contained control instruments and both video and audio equipment which allowed control of machines actually in the SG and communication with a person at the SG.
CE removed five proof plugs from each SG in a controlled manner to test the technique on the actual configuration.
Because plug cutting rates were slightly different than anticipated (no Westinghouse plugs being available for technique development)
several minor equipment changes were required.
After the minor changes were in effect, the proof plugs were successfully removed.
1B MSIV Downstream Check Valve Check valve V08148, downstream of the 1B MSIV, was repaired per PWO 1611/61 due to a
steam cut between the body and cap.
Initially, the cap was the only piece to be weld repaired.
Due to some misunder-standing between shifts, the valve body was also welded.
This required that the valve body studs be removed for machining of the body in the cap-to-body seating area.
The appropriate machine was available and brought in from the Turkey Point facility, where it had
last been used.
The local machinist reworked the unit prior to the machining.
The inspector observed the machinist setup, the refurbishing machine, examined some of the job documents, and observed portions of the machining operation.
11.
Tube Plugging of Safety-Related Heat Exchangers (62703)
The operations staff had identified, by excessive automatic make up to the CCW surge tank of over 2000 gallons per day, that a tube leak existed in the 1B CCWHX.
The MX was removed from service for tube repair.
On June 21, the inspectors observed the replacement of rubber expansion tube plugs with brass plugs.
Jobsite activities were uneventful.
The PWO was at hand and referred to.
The jobsite was well organized.
Several concerns regarding rubber expansion plugs were subsequently identified during a review of the base reason for changing the type of plug:
The applicable Yuba technical manual, 8770-3599, did not recognize rubber expansion plugs as being an acceptable plug.
No instructions could be found discussing how to install or limits on use of rubber expansion-plugs.
Obvious examples were:
Shelf life or service life, resultant inspection or replacement requirements.
Limits on tightening of the expansion screw.
Differential pressure limits for use.
Temperature limits for use.
Use of double plugs as reported by the licensee to be an occasional practice.
No evidence of Engineering Department involvement or evaluation could be found.
These prompted a more detailed review of this activity.
Several rubber expansion plugs had been found dislodged,;from plugged tubes in 1B CCWHX.
The cause of the expansion plugs falling out of or having been forced out of the tubes has not been identified.
The licensee has indicated that other plug ejections had occurred.
This had prompted the planners, who had initiated rubber expansion plug repair, to reinstitute brass plug repair.
Shop stores records indicated that rubber expansion plugs had been on site since late 1985 and that they had been issued from stores.
This agrees with the historical PWOs.
Further, those same records indicated that the
rubber plugs were not safety related, had not been receipt inspected, and that two separate vendors had provided them.
The use of two separate vendors agrees with stated problems with the second vendor's plugs in that those plugs were the type that dislodged from the
CCWHX tubes in June.
Maintenance had replaced all the rubber plugs that had been installed in the Unit
CCWHXs, completing the task in June.
As of June 1989, an unknown quantity of rubber expansion plugs were still installed in the Unit 2 CCWHXs.
The exact number of rubber expansion plugs installed in either units'CWHXs was never known; only the locations and total number of tubes plugged, which had been identified on a plugging map.
The gC group had been involved in the work effort from the standpoint of verifying that the tubes specified for plugging were plugged, not what type plug was used.
The licensee contacted Yuba and obtained on June 30, a brief letter indicating that Yuba could recommend using rubber plugs based on the nominal 60 psi pressure differential between the shell and tube sides, The letter did not address plugging methods, types of plugs to be used, parametric considerations for plug use, or possible reasons for the plug ejection phenomena.
Review of the work order, installing the brass plugs and interviews show that the brass plugs carried by stores were not what they were stat'ed to be, that they were machined in some not-clearly-defined informal manner such that the taper is in question, and that the engineering and quality organizations were not involved.
Local procedure gI'-PR/PSL-1, Rev 34, Preparation, Revision, Review/Approval of Procedures (section 5.15),
indicates that the technical manual shall be treated as plant procedures for the purpose of procedure adherence.
From discussions with the licensee, it is understood that technical manual requirements may be superseded by approved engineering procedures.
To date, the site has been unable to demonstrate that site or corporate engineering was involved with the plug installation.
No documentation is available indicating that the modification to the CCWHXs were evaluated for impact on the system.
10CFR 50.59 required that an engineering evaluation be written prior to implementation of a modification of safety-related equipment and that the evaluation be retained as a record.
This requirement is implemented in part in ANSI standard N18.7 and in section 5.1.3 of site procedure gI 3-PR/PSL-1, Rev 19, Design Control (after fuel loading).
Regulatory Guide 1.33 and the licensee's guality Assurance Manual require that procedures exist to perform certain activities.
gl 5-PR/PSL-1 states in part (section 3.2.4)
that maintenance procedures include those activities performed to maintain, modify, or repair safety-related equipment.
The PWO is a typical document that is used to indicate procedures to be used on a job.
The more recent PWOs.that installed the brass plugs in the Unit 1 Heat fxchangers invoked the technical manual for plug installation.
The earlier PWOs that were examined by the inspectors did not invoke an instruction for the rubber plug installation; the
licensee indicated that no instruction existed for the the plug installa-tion and the job was within the skill of the craft.
This area appears to involve an improper design change by the. maintenance department dating from about 1985 and several cases of failure to follow procedures.
Since the inspection in this area is not complete, this is URI 335,,389/89-18-02 pending completion of the licensee's and NRC review.
Review of Procedures and Drawings at The EOF and Juno Engineering Office (71707)
The inspector reviewed the procedures maintained at the EOF.
Portions of.
the EOPs, ONOPs, EPIPs, and HP procedures were reviewed for completeness and for being current.
The procedures were well labeled, organized, and in good condition with an index for most areas.
The Unit 1 and Unit 2 TS and FSARs were also available.
The inspector found several procedures that were superseded per.the latest procedure index from document control, but were within the 30 day period allowed for updating per procedure g1-6.
Drawings were not maintained at the EOF.
If an event were to occur that would require manning the EOF, the Juno Beach engineering office is responsible for deploying certain equipment and material to either the St.
Lucie or Turkey Point EOFs.
Administrative procedure JPE-AP 1.11, FPL Nuclear Plants Emergency Operations Facilities - Materials and Deployment, assigns responsibilities to Power Plant Engineering disciplines/
groups for the maintenance and deployment of these materials and equipment.
Paragraph 3.0(5) of JPE-AP 1. 11 states that the administrative supervisor is responsible for the latest revisions of drawings and for inventory of supplies.
A sample of drawings from the St.
Lucie EOF box were checked and found to be available and current.
No violations or deviations were identified.
Exit Interview (30703)
The inspection scope and findings were summarized on July 7, 1989 with those persons indicated in paragraph 1 above.
The inspector described the areas inspected and discussed in detail the inspection findings listed below.
The licensee did not identify as proprietary any of the material provided to or reviewed by the inspector during this inspection.
Dissenting comments were not received from the licensee.
I tern Number Status Descri tion and Reference 335,389/89-18-01 open 335,389/89-18-02 open URI - Mispositioned 1B Diesel Fuel Transfer Pump Discharge Valve and Affects on EDG Operability, paragraph 7.
URI - Control of Component Cooling Water Heat Exchanger Tube Plugging, paragraph 1.
Acronyms and Abbreviations AC AFW
'LARA ATWS CCWHX CEA CFR CIS DC DDPS ECCS EDG FPL FSAR GDC GL HP HPSI IFI IN ISC INPO IR ISI LTOP LCO LER LPSI MFIV MSIV NPS NRC ONOP PORV ppm PT PWO QA QC RCB RCP RCPB RCS Rev RO RWT SDC SDCS Alternating Current Auxiliary Feed Water (system)
As Low as Reasonably Achievable (radiation exposure)
Anticipated Transient Without Scram Component Cooling Water Heat Exchanger Control Element Assembly Code of Federal Regulations Containment Isolation System Direct Current Digital Data Processing System Emergency Core Cooling System Emergency Diesel Generator The Florida Power
& Light Company Final Safety Analysis Report General Design Criteria (from 10CFR 50, Appendix A)
NRC Generic Letter Health Physics High Pressure Safety Injection (system)
NRC Inspector Follow-up Item NRC Information Notice Instrumentation and Control Institute for Nuclear Power Operations Inspection Report (NRC)
Inservice Inspection (program)
Low Temperature Overpressure Protection (system)
TS Limiting Condition for Operation Licensee Event Report Low Pressure Safety Injection (system)
Main Feed Isolation Valve Main Steam Isolation Valve Nuclear Plant Supervisor Nuclear Regulatory Commission Off Normal Operating Procedure Power Operated Relief Valve Part(s)
per Million Pressure Transmitter Plant Work Order Quality Assurance Quality Control Reactor Containment Building Reactor Coolant Pump Reactor Coolant Pressure Boundary Reactor Coolant System Revision Reactor [licensed] Operator Refueling Water Tank Shut Down Cooling Shut Down Cooling System
SG SIT SNPO SRO TS URI VIO Steam Generator Safety Injection Tank Senior Nuclear Plant [unlicensed] Operator Senior Reactor [licensed] Operator Technical Specification(s)
NRC Unresolved Item Violation (of NRC requirements)