IR 05000335/1988014
| ML17222A405 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 07/28/1988 |
| From: | Bibb H, Crlenjak R, Paulk G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17222A404 | List: |
| References | |
| 50-335-88-14, 50-389-88-14, NUDOCS 8808160448 | |
| Download: ML17222A405 (21) | |
Text
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.IN.
ATLANTA,GEORGIA 30323 Report Nos.;
50-335/88-14 and 50-389/88-14 Licensee:
Florida Power and Light Company 9250 West Flagler Street Miami, FL 33102 Docket Nos.:
50-335 and 50-389 Facility Name:
St. Lucie 1 and
Inspection Conducted:
Nay 8 - July 2, 1988 License Nos.:
G.
Pau
, Senior Resid ector fY/. 5, H.
E. Bibb, Resident Inspector a
e Soigne Da Signed 7 88
$ 9 ate Si ned Other Inspectors:
J. Caldwell, North Anna Senior Resident Inspector H. Christensen, RII Project Inspector L. McElhinney, Turkey Point Resident Inspector L. Nicholson, Surry Resident Inspector G. Schnebli, Turkey Point Resident Inspector N. Scott, RII Project Inspector Approved by:
R.
V. Crlenjak, Section Chief Division of Reactor Projects SUMMARY Scope:
This inspection involved on-site activities in the areas of plant tours, plant operations, technical specification compliance, main-tenance observation, licensee event report review, physical protec-tion, surveillance observation, reactor trip review,
CFR 50.59 reviews, special nuclear material, design changes and modifications, instrument air system review, and refueling operations.
Results:
Inspector Followup Item (389/88-14-01):
CFR 50.59 review inconsistencies by licensee procedures and personnel.
8808ih0448 880803 PDR ADOCK 05000335 PNU
REPORT DETAILS Persons Contacted Licensee Employees J. Barrow, Fire Prevention Coordinator J. Barrow, Operations Superintendent
- G. Boissy, Plant Manager H. Buchanan, Operations Supervisor
- C. Burton, Operations Supervisor R. Dawson, Assistant, Plant Superintendent
- Electrical T. Dillard, Maintenance Superintendent R. Frechette, Chemistry Supervisor J. Harper, gA Supervisor K. Harris, St. Lucie Site Vice President
- C. Leppla, ISC Supervisor
- C. Pell, Technical Staff Supervisor
- N. Ross, guality Control Supervisor B. Sculthrope, Reliability and Support Supervisor R. Sipos, Service Manager W. White, Security Supervisor
- C. Wilson, Assistant, Plant Superintendent
- Mechanical
- E. Wunderlich, Reactor Engineering Supervisor Other licensee employees contacted during this inspection included technicians, operators, mechanics, security force members and office personnel.
- Attended exit interview Licensee Action on Previous Enforcement Matters (92702)
(Closed)
Violation 335/87-31-01; Procedure 1-0970020, Operation of the 120Y Instrument AC System (Class IE),
was not properly implemented, thereby causing loss of 120V instrument AC and a subsequent reactor trip.
The licensee concurred with the violation in response letter dated March 7, 1988.
The corrective actions stated in the response have been completed, including a revision to Administrative Procedure (AP) 0010120, revision 39, Duties and Responsibility of Operators on Shift, to increase operator awareness of operation of sensitive systems.
This item is closed.
Plant Tours (Units 1 and 2)
(71707 and 71710)
The inspectors conducted plant tours periodically during the inspection interval 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 estab-lished, 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 inspectors routinely conducted partial walkdowns of the Emergency Core Cooling Systems (ECCS).
Valve, breaker/switch lineups and equipment conditions were randomly verified both locally and in the control room.
During the inspection period, the inspectors conducted a complete walkdown in the accessible areas of the Units 1 and 2 Auxiliary Feedwater, AC and DC electrical distribution, and emergency diesel generators systems to verify that the lineups were in accordance with licensee requirements for operability and equipment material conditions were satisfactory.
Additionally, flowpath verifications were performed on the following systems:
Units
and
Chemical and Volume Control, Emergency Diesel Generator (EDG) Air Start, High and Low Pressure Safety Injection, and Unit 2 Intake Cooling Water.
The inspectors reviewed the information in Section 6.2.2.5 of the Unit 2 Final Safety Analysis Report (FSAR)
which addresses containment pump cleanliness.
The pump areas provide drainage and collection for some ECCS equipment.
Section 3/4.5.2.e of the Unit 2 Technical Specifications (TS)
discusses inspection of the pump areas.
The inspectors reviewed pump inspection implementing procedures which are contained in Operating Procedure (OP) 2-1600023, revision 13; Administrative Procedure 2-0010125, revision 23; and Quality Instruction 13-2, revision
(Refueling Sequencing Guidelines; Schedule of Periodic Tests, Check, and Calibra-tions; and Cleanliness Methods Controls, respectively).
The inspectors discussed the pump inspection method with Quality Control (QC) personnel.
The inspectors examined quality control inspection report 21749 (dated 871014),
21658 (dated 871014)
and 21620 (dated 871118),
which included pump inspections, and found no deficiencies.
During the walkdown of the Unit 2 EDG rooms, the inspectors noted a white tag on the crank case drain on the 2B1EDG.
The tag indicated that the coupling on the drain line was leaking oil.
The tag was dated April 19, 1986.
There was less than a cup full of oil present on the EDG room floor beneath valve 2V-59-306.
The EDG rooms are randomly cleaned by site personnel, which is not strictly monitored by operations.
The line itself was sheathed in metal insulation.
The site knew the leakage was minimal but did not know who attached the tag.
After being informed about the tag by the inspector, the licensee issued a plant work order (PWO)
to investigate the leak.
The investigation revealed that a coupling was loos No violations or deviation were identified in this area..
4.
, Plant Operations Review (Units 1 and 2) (71707)
The inspectors, periodically during the inspection interval, 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, operator performance and response actions were observed and evaluated.
The inspectors conducted random off-hours inspections during the reporting interval to assure that operations and security staffing remained at an acceptable level.
Shift turnovers were observed to verify that they were conducted in accordance with approved licensee procedures.
The inspectors reviewed operating procedures 1-2200020, revision 14 and 2-2200020, revision 11, both entitled Emergency Diesel Generator Standby Lineup.
The following observations were noted during the inspection and were brought to the attention of the licensee.
a
~
During the inspection, the load limit control knob for both 2B EDG engines were not in the maximum load setting.
The knob is normally in the full clockwise position with the engines in the standby mode.
This control setting allows the governor to control the fuel rack position from full closed to full open.
The 2B EDG had been surveil-lance tested earlier in the day and loaded to approximately 3800 kw.
This is above the continuous rating of 3685 kw.
However, the Updated Final Safety Analysis Report (USFAR), Section 8.3, specifies a
minute rating of 3985 kw.
The licensee could not verify that the EDG could obtain this load with the as-found load limit control setting.
Therefore, a
temporary change was written to procedure 2-2200050, Emergency Diesel Generator Periodic Test, to allow loading the EDG to approximately 4000 kw with the load limit control knob in the as-found condition.
This would verify that the operability of the 2B EDG was not affected by the setting of the load limit knob.
The test was subsequently run and the EDG was able to load to the design limit of 3985 kw.
In order to prevent the recurrence of this problem, the licensee plans to add a step in procedure 2-2200020 to have the operator verify that the load limit knob is in the maximum load position.
b.
Section 8.8 of Unit 1 procedure 1-2200020, directs the operator to place the EDG control for the speed droop set to "0" position.
The inspector noted that the speed droop settings for the 1A and 1B EDG's were not set at "0".
The 2A and 2B EDG had the speed droop settings at the
"2" position.
However, the Unit 2 procedure did not direct the operator to set the speed droop.
The system engineer indicated that the speed droops are adjusted by the vendor technical representative and that the operators should not reposition the
settings under any circumstance.
A procedure change request (PCR)
was submitted to delete this step from the Unit 1 procedure.
c.
The inspectors noted that the housekeeping of the EDG rooms could be improved.
The 1B EDG 16 cylinder engine had a puddle of oil on the engine pedestal under the governor end.
The Unit 2 diesel rooms had oil on the floor, especially around the buckets used to contain the oil drained out of the inlet air box.
The licensee indicated that these concerns will be resolved promptly.
No violations or deviations were identified in this area.
The inspectors performed an in-depth review of the following safety-related tagouts (clearances):
Clearance No.
Descri tion Unit
1-6-75 1-6-90 1-6-91 Unit 2, 1B Component Cooling Water Pump - Remove Motor HVE-16A, Fuel Pool Exhaust Fan - Planned Main-tenance (PM)
S-2903, Strainer for Boric Acid Makeup (BAM) Pump Discharge - Leak Repair 2-4-59 2-6-30 2-6-33 2-6-34 2-6-40 Fuel Handling Building Cask Crane - Repair Level Control Valve 2110P - Repair 2B Fuel Pool Cooling Pump -
PM 2A Charging Pump - Repair 2B Instrument Air Compressor
- Repair Sight Glass Leak During a walkdown of Unit 2 EDG, the inspector cross checked some random PWO tags hung in the EDG rooms against actual plant status for the PWO's.
PWO's are to be worked in accordance with AP 0010432,'evision 33, Nuclear Plant Work Orders.
The PWO tag numbers were as follows:
Number
~OT I
d Notes a.
881410532 b.
870330144 None 2/2/87
c.
870602005 Number
~Cont d.)
d.
880414141827 e.
22170 (Tag No)
871261442 3/1/87 Date Ta Issued 4/14/88 2/2/87 5/5/88
Notes
Notes:
(1)
Tag hung, but work complete (2)
Planning to work 3)
Awaiting parts (4)
See be)ow PWOs represented by (b), (c),
and (e)
above are to be worked at the next refueling outage.
PWOs represented by (a)
and (f) had been worked but the tags have not been removed.
This violated the requirements of the above procedure, but due to the minor significance of the event (severity level V violation)
and the current NRC enforcement policy, no Notice of Yiolation will be issued.
The licensee is aware of the problem and had formed a guality Improvement Program (gIP)
team to study/resolve PWO tagging problems prior to the inspector finding these specific examples.
The PWO represented by (d)
above presented a variation in the type of problem the licensee had been experiencing with PWO tags.
A duplicate number, 026650, for the PWO tag had been entered into the computer for another component; this component was repaired and the PWO was closed.
The second tag with number 026650 was on a pressure switch, PS-59-036A, with problems identified on the tag as "switch would not shut off the 2A2 EDG air accumulator compressor".
This switch had never been worked.
When notified of the potential problem by the inspector, operations cycled the switch and it performed its function.
The licensee assured the inspector that changes, which were made to the computer program since the issuance of this PWO, would make PWO number duplication nearly impossible.
The licensee could not determine where the tag on the pressure switch came from or the reason for it.
Technical Specification Compliance (Units 1 and 2 (71707))
During this reporting interval, the inspectors verified compliance with limiting conditions for operations (LCO's)
and results of selected sur-veillance tests.
These verifications were accomplished by direct observation of monitoring instrumentation, valve positions, switch positions, and review of completed logs and records.
The licensee's compliance with LCO action statements were reviewed on selected occurrences as they happene No violations or deviations were identified in this area.
Maintenance Observation (62703)
Station maintenance activities of 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; limiting conditions.for operations 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.
The inspectors observed portions of the following maintenance activities:
PWO No.
Unit
Descri tion 4287 4290 6853 7196 3233 3238 Unit 2 lA Primary Water Pump Motor - Annual PM HVS-6, Fuel Pool Supply Fan - Annual PM Letdown Boronometer - Troubleshoot/Repair Auxiliary Feedwater Pump Flow - Channel Check 1B2 Emergency Diesel Generator Radiator Repair 1B2 Emergency Diesel Generator Radiator Replacement 4701 6023 6089 2030 2HVS-6, Fuel Pool Supply Fan - Annual PM Lead/Lag Device for Pressurizer Level Control-Check Setting Reactor Regulating System No.
1 - Cal Check Component Cooling Water Heat Exchanger 2A-Clean and Inspect On Saturday, June ll, 1988, the Nuclear Reactor Regulation (NRR) Project Manager (PM), was contacted by the licensee to seek possible discretionary enforcement.
The 1B Emergency Diesel Generator had been declared inoperable on Friday, June 10 due to a leaking radiator, thereby forcing the plant into a
72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement which would elapse about 6 on Monday, June 13.
Discretionary enforcement was sought because the licensee felt that repairs might require a few hours longer than the
hours.
The licensee subsequently re-contacted the PM on Sunday morning, June 12, to inform him that the radiator replacement was completed, testing was underway and discretionary enforcement was not necessary.
No violations or deviations were identified in this area.
7.
Review of Nonroutine Events Reported by the Licensee (Units
and 2)
(90712)
The following Licensee Event Reports (LERs)
were reviewed for potential generic impact, to detect trends, and'o 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 were of upmost consideration.
The following LERs are considered closed:
LER No.
Descri tion 335-88-01 335-88-02 335-88-03 389-88-01 Inadvertent Start of 1C High Pressure Safety Injection Pump Due to Electrical Transient Bypass Leakage on Containment Radiation Monitor Isolation Valve Exceeded Technical Specification Limit Reactor Trip on Low Steam Generator Level Due to Main Feedwater Regulating Valve Failure 2A2 and 2B2 Safety Injection Tanks Out of Service Simultaneously Due to Unrelated Valve Reseating Problems 389-88-02 389-88-03 389-88-04 Reactor Containment Building Polar Crane Power Supply Breaker Found Open, but Unlocked Safeguards Signals to a Containment Isolation Valve Bypassed Due to a Personnel Error Missed Surveillance on Sampling of Dose Equivalent I-131 Due to Personnel Error 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 were of upmost consideration.
No violation or deviations were identified in this are e Physical Protection (Units 1 and 2) (71881)
The inspectors verified by observation and interviews during the reporting interval that measures taken to assure the physical protection of the facility met current requirements.
Areas inspected included the organi-zation of the security force, the establishment and maintenance of gates, the conditions of doors and isolation zones, access control and badging, and compliance to procedures.
The inspectors followed construction activities which were initiated in response to violation 389/88-02-03, Failure to Provide Alarmed Barrier at Protected Area Barrier.
At the close of the inspection period, the physical metal grating barrier had been completed on both, units, but security guard compensatory measures were still maintained until formal final acceptance of the work.
Violation 389/88-03-03 will remain open until the next visit by Region II security inspectors.
No violation or deviations were identified in this area.
9.
Surveillance Observations (61726)
During the inspection period, the inspectors verified that plant operations were in compliance with selected TS requirements.
Typical of these was confirmation of compliance with the TS for reactor coolant chemistry, refueling water tank, 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, limiting conditions for operations were met, removal and restoration of the affected components were accomplished, test results met requirements and were reviewed by personnel other than the individual directing the test, and that deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
The inspectors observed the following surveillance(s):
Document Ho.
Descri tion Unit 1 AP 1-0010125A Data Sh
AP 1-0010123 Unit 2 1A Boric Acid Pump - Monthly Code Run Administrative Control of Valves, Locks and Switches-Valve Deviation Log AP 2-0010125A Data Sh 20 2C Component Cooling Water Pump - Monthly Code Run OP 1200022 Periodic Surveillance of Incore Detection System
Unit 2
~Cont'd.)
OP 2-1400057 Reactor Regulating System Functional Test OP 2-2200050 2B Emergency Diesel Generator Periodic Test No violations or deviations were identified in this area.
10.
Design Changes and Modifications (37700)
The inspectors reviewed the design change and modification program to confirm compliance with TS and
CFR 50.59.
This particular inspection focused on the control and implementation of changes which were not submitted to the NRC for approval, but reported on -an annual basis pursuant to the requirements of
CFR 50.59.
The following plant changes/modifications (PCM)
were selected from the station records for review:
PCM 003-184, Electrical Penetration E-4 Nozzle.
This modification installed a weld neck flange and blind flange to convert the spare electrical penetration E-4 nozzle into an outage service penetration.
PCN 167-184, Main Steam Isolation Valve (NSIV) Bypass Valve Cable Repair.
This modification repaired damaged power and control cables to the main steam isolation bypass valve NV-08-1B.
PCM 233-184, Auxiliary Feedwater (AFW) System Actuation Modification.
This modification alters the control circuits of the AFW discharge valves to allow manual control for throttling purposes.
PCN 045-185, High Pressure Safety Injection (HPSI)
Pump Oil Drain.
This change added a drain assembly to each bearing drain on the HPSI pumps to aid in maintenance.
PCM 144-283, Personnel Air Lock Leak Test Monitor.
This change provided a permanently installed personnel air lock leak rate test monitor to assist in compliance with TS surveillance requirements.
PCM 028-284, Reactor Coolant Pump (RCP)
Seal Injection System.
This PCN added a backup cooling water system for the RCP seals to prevent damage to the seals in the event of a total loss of component cooling water (CCW) to the RCP seal heat exchangers.
PCM 145-284, Charging Pump Seal Water Makeup Valve Replacement.
This modification removed the existing solenoid operated char ging pump seal water makeup valves and replaced them with manual globe valves.
The inspectors reviewed the licensees engineering review and safety analysis for each change to assure that the changes had been reviewed and approved in accordance with
CFR 50.59 and that the reviews were
adequate.
The review also include a determination that:
the design changes were processed and controlled by established station procedures; completed post-modification testing, which demonstrated the operability of the modified system/component, was accomplished; and operating procedures and training were updated to reflect the design change or modification.
No violations or deviations were identified in this area.
Instrument Air System Review Subsequent to a presentation on instrument air system problems given at the June Resident Inspector's meeting in Atlanta by Nr. Harold Ornstein, Office of Analysis and Evaluation of Operational Data (AEOD), the resident inspector returned to the plant site to conduct an inspection of the Units
and 2 instrument air systems.
The inspection commenced with a review and cross-comparison of the following documents:
2998-G-085, Sheets 1 and 2 - Unit 2 Service and Instrument Air System Flow Diagram OP 2-1010020, Rev.
11, Instrument Air System Operation C
OP 2-1010022, Rev. 5, Instrument Air System Initial Valve Alignment The inspector found, through cross-comparison, that four valves which are shown on the flow diagram are not shown on either of the operations procedures.
The valves (181218, 19, 20 and 21) are root isolation valves for two pressure switches and two pressure indicator/controllers which sense low pressure in one unit's instrument air system and automatically open isolation valves to cross-tie to the other unit's instrument air system.
This was immediately brought to the attention of the Nuclear Plant Super visor, who immediately verified the proper (open)
valve position and initiated a temporary procedure change to add the four valves to the alignment procedures.
The licensee also initiated a review to determine if other discrepancies exist.
The review found several other minor differences and these were also submitted for procedure revision.
No violations or deviations were identified in 'this area.
Reactor Trips/Runbacks (93702)
On the evening of June 16, Unit 2 reduced power to 50% to repair lightning damage in the switchyard, and returned to full power on June 17.
On June 29, at 5:48 a.m., Unit 1 reactor tripped from 100Ã power on high pressurizer pressure initiated by loss of a condensate pump.
The root cause appeared to be a over-sensitive phase differential current relay.
The resident inspector was notified at home and responded within one hour to observe plant stabilization activities.
All systems functioned normally, standard post trip actions were performed, and the shift technical advisor conducted a post-trip review.
The trip was an
uncomplicated trip, but the reactor trip recovery procedure was not immediately implemented due to the current end-of-life boron concentration (57 ppm)
and extended (93 day)
run at 100Ã power.
These conditions placed the xenon -over-ride capability in the 36 to 40 hour4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> time frame.
A short notice outage work (SNOM) meeting was held to schedule and prioritize necessary shutdown work items.
Unit 1 had about 10 days until a scheduled refueling outage, so work items that might jeopardize a timely restart and were not impacting plant safety were delayed until the refueling outage.
Conversely, items which could help get a head start on the refueling outage and were not critical path for restart (such as the containment paint condition inspection)
were scheduled.
The unit was taken critical at 0032 on Friday, July 1, but efforts to return to power were hampered by a large feedwater leak.
The leak was caused by seat leakage past the feedwater header isolation valves which connect to a
feedwater recirculation filter to the feedwater system.
This feedwater recirculation filter is not normally used, but the isolation valves are used periodically to dump to the storm drains when the hot well level is too high.
During the brief outage, the valves were used for this purpose, and one did not reseat properly upon closing.
The unit had reached 50%
power when the problem s(as noted by excessive steam coming through the storm drain covers.
Power was reduced to zero, one feedwater pump was secured and the header isolation valve was successfully closed.
The unit was returned to full power by 12 p.m.
on Friday, July 1.
No violations or deviations were identified in this area.
Special Nuclear Material (SNM) (85102)
The inspector reviewed the program established by the licensee for the accountability and control of non-fuel SNM as required by the facility license and
CFR 70.
The review included verification of activities required by AP 0010433, Special Nuclear Material Control, Records, and Reports.
Reactor Engineering, Health Physics and Quality Assurance personnel were interviewed to discuss program implementation.
The following documents were reviewed:
a.
Special Nuclear Material Quality Assurance Audit; QSL-OPS-87-568 of December 15, 1987.
b.
Administrative Procedure 0010433, Historical Records for 1986, 1987, and 1988.
c.
Recent NRC Form-741s for inventory changes.
d.
SNM Status and Control forms for all non-fuel SNM in Unit 1 and 2.
e.
Health Physics Procedure 40, Shipment of Special Nuclear Materia A record verification and comparison of the master index of SNN verses SNM inventory records indicated no significant deficiencies.
It was noted that two SNN inventories were completed on March 26, 1987, with different reviewing officials.
One record was in gC records storage and one inventory was not in gC storage.
The licensee is evaluating the discrepancy.
All other records in regards to SNN non-fuel inventories, were satisfactory.
No other, major programmatic deficiencies were noted.
1988 Unit 2 10 CFR 50.59 Review A review of Unit 2 changes conducted pursuant to
CFR 50.59 was undertaken by the St. Lucie Project Manager (PN) at the site on Nay 30, June
and June 3, 1988.
The PN also reviewed the change process used by the licensee.
The licensee provided an update of the Unit
FSAR by letter dated April 4, 1988.
In that submittal, the licensee provided a list of PCMs that were completed during the time period of October 1986 through October 1987.
Forty-one changes were included on the list; approximately half were safety-related changes.
A brief description of the changes and a
summary of the safety evaluation for each change were submitted by letter dated April 6, 1988.
The licensee utilizes the Annual Operating Report (AOR) for reporting changes in procedures as described in the FSAR, and the conduct of tests and experiments not described in the FSAR.
The AOR for 1987 was submitted by letter dated February 29, 1988.
Five items were reported.
The PN selected three PCNs to review in detail:
PCN 028-284, RCP Seal Injection (Supplement 2);
PCN 038-284, Heat Tracing Setpoint; and PCN 071-284, Thermocouple Cable Changeout (Supplement 1).
The RCP Seal Injection System is an emergency back-up to the normal cooling system.
The normal cooling system uses component cooling water to the RCP seal heat exchanger.
The backup system injects cooling water directly into the RCP seals via the lower seal cavity vent pipe.
The water source in this case is the Chemical and Volume Control System (CVCS).
The backup system is intended to be used in the event of a total loss of CCH to the RCP seals heat exchanger or when one or more RCPs are idle during alternate pump combination runs.
The PCN stated that this same modification was made to the Unit
RCPs.
The PM reviewed the safety analysis justifying the change pursuant to
CFR 50.59.
An analysis of each factor involved in determining if an unreviewed safety question exists was made by the licensee, as supplemented by Combustion Engineering.
Because of the complexity of the change and the time available to the PN for this review, it was not possible to make an independent determination as to whether an unreviewed safety question was involved.
However, the PM determined that the licensee meets the requirements for 10 CFR 50.59.
It should be noted that this change was also reported by the licensee to the NRC in the previous PCM listing update to the FSAR (April 1987).
The licensee believes that the previous update was the reporting of an earlier supplement to this PC The heat tracing setpoint modification involved resetting temperature setpoints (control setpoints of the heater cables, high/low temperature
'larm setpoints)
for those heater circuits which deviate from the boric acid heat tracing setpoints.
The setpoint modifications were made in order to maintain the correct process temperatures and to eliminate nuisance heat trace alarms in the control room and at the heat trace control panels.
Four categories of systems/equipment had setpoint changes made:
boric acid and radwaste concentrators; charging bypass lines/radi-ation monitoring system; and post accident sampling system.
The PN reviewed the details of the charging bypass lines.
The primary and backup heaters'igh temperature alarms are set at 185'F, while the primary and back-up heaters'ow temperature alarms are set at 162'F and 148'F, respectively.
The primary and backup heaters'aintenance temperatures are set at 170'F and 155'F, respectively.
According to the licensee's system description in Section 11.8 of the PCN, there is a large variation in temperature and in percentage of boric acid content (up to 12 weight percent)
in the process fluid in the charging bypass lines.
As a resolution to the nuisance alarms, the low temperature alarm was effectively disabled (reset to 50'F).
As figures of merit, 3.5 weight percent boric acid will precipitate at 50'F, 8 weight percent boric acid will precipitate at 104'F, and 12 weight percent boric acid will precipitate at 134'F.
The system description specified that the heat tracing will still function normally; however, there will be no low temperature alarm.
The PM reviewed the licensee's drawings to determine the nature and extent of the bypass lines.
According to drawing number 2998-G-078, sheets 121 and 122, the bypass lines are two-inch heat traced lines branching off the charging lines just downstream of charging pumps and terminate at the volume control tank.
According to the FSAR, the charging pump bypass loop (line) is used to minimize thermal transients to the charging piping when a charging pump is started or stopped.
The licensee's safety analysis specified that the solidification of the boric acid in these lines will not inhibit any safety functions of equipment.
In addition, the operators could detect blockage in these lines by the altered flow path which would result.
Lastly, the operators make daily temperature checks on these lines to reconfirm process temperature and proper operation of the heat tracing.
On the basis of the above, it does not appear that an unreviewed safety question,was involved in resetting the low temperature alarms to 50'F.
It should be noted that this change was also reported by the licensee in the previous PCN testing update to the FSAR (April 1987).
The licensee stated that the PCN was completed in October 1986.
Since October is the stop and start month for counting PCMs, the PCM was counted twice in the listings.
The FSAR was updated only once per the licensee.
A new procedure is in effect which uses an actual day in October so that a
PCM will not be reported twice.
The thermocouple cable changeout was necessary because of environmental qualification concerns with the originally installed cable.
The installed thermocouple extension cable for eight thermocouples associated with the
Shield Building Ventilation System (HVE-6A and 6B)
was "qualified for interim operation" until the first refueling.
The change entailed replacing the existing cable with Class 1E qualified cable.
The safety analysis was reviewed by the PN.
The licensee's evaluation met
CFR 50.59 requirements.
The PM also checked PRO 403011 and noted that the work was performed in October 1984.
Thus, the licensee did make the change during the first refueling outage.
It should be noted that this change was also reported by the licensee in the previous PCN listing update to the FSAR (April 1987).
The licensee gave the same reason as the heat trace setpoint PCN for multiple reporting.
The PM was aware that the last reload for Unit 2 was accomplished pursuant to
CFR 50.59.
.However, the PN noted that the brief description of the change and summary of the safety evaluation was not included in the most recent submittal of PCM listings.
This was discussed.with licensee personnel.
The licensee provided the PM a copy of the
CFR 50.59 evalu-ation for the last reload (internal memorandum dated 9/28/87, FRNT-87-292).
The evaluation was supplemented by a
reload Safety Evaluation Report prepared by Combustion Engineering.
The PM noted that the licensee performed independent calcul'ations to check the vendor's work.
This is a noteworthy practice and demonstrated that the licensee does not accept vendor-related work at face-value.
The licensee and vendor's work meets
CFR 50.59 requirements.
The licensee agreed that the change should have been reported.
The PN discussed the change procedure used by the licensee for making changes pursuant to
CFR 50.59.
The licensee does not utilize one change procedure to be used by all licensee personnel.
In addition, there is no
CFR 50.59 procedure.
The required evaluation to support a
determination pursuant to
CFR 50.59 is a part of the various other change procedures.
The change procedure used for a physical related change to the plant would be performed by Juno Plant Engineering (Juno Branch Office), using guality Instruction 3.1-3, Engineering Package for Nuclear Plants.
The package instructions require a Safety Evaluation, and each factor involved in the determination of no unreviewed safety question must be addressed.
The TS change question must also be answered.
The package is sent to the Facility Review Group (FRG) for final determination pursuant to
CFR 50.59.
The change procedure used for core reloads would be performed by Fuel Resources (Miami Office) with assistance from vendors using guality Instruction FR-7, Evaluation and Review of Contractor Core Designs, Safety Analysis, and Safety Related Documents.
A Safety Evaluation would be prepared, and the determination of no unreviewed safety question must be made.
The TS change question must also be answered.
The package is sent to the FRG who makes the final determination pursuant to 10 CFR 50.59.
The change procedure used for changes to procedures as described in the FSAR, and the conduct of tests and experiments not described in the FSAR, would be performed by plant personnel.
They would use guality Instruction 5-PR/PSL-l, Preparation, Revision, Review/Approval of Procedures.
It
requires that a Safety Evaluation be written pursuant to
CFR 50.59 if (a)
a proposed test or experiment is determined to be a special test (pg
of 37), or (b)
a proposed procedure change constitutes changes in the system operating procedures requirements described in the FSAR (pg 23 of 37).
The package is sent to the FRG who makes the final determination.
As can be seen from the above, various personnel use different procedures for meeting
CFR 50.59.
The PM suggested the standardization of the procedure to be used by all personnel within the company.
The licensee agreed.
This item will be left open to review licensee actions.
(Inspector Followup Item 389/88-14-01)
No violations or deviations were identified in this area.
Bulletin 85-03 Status (92703)
As requested by action item e. of Bulletin 85-03, Motor-Operated Valve Common Mode Failures During Plant Transients Due to Improper Switch Settings, the licensee identified the selected safety-related valves, the valves'aximum differential pressures and the licensee's program to assure valve operability in their letters dated May 15, October 13, and October 31, 1986.
Review of these responses indicated the need for additional information which was contained in Region II letter dated July 21, 1987.
Review of the licensee's August 21, 1987 response to this request for additional information indicates that the licensee's selection of the applicable safety-related valves to be addressed and the valves'aximum differential pressure meets the requirements of the bulletin and that the program to assure valve operability requested by action item e. of the bulletin is now acceptable.
The results of the inspections to verify proper implementation of this program and the review of the final response required by action item f. of the bulletin will be addressed in additional inspection reports.
Preparations for Refueling (60705)
This inspection module's objectives are to:
a.
Ascertain the adequacy of the licensee's procedures for the conduct of refueling operations.
b.
Ascertain the adequacy of the licensee's administrative requirements for control of refueling operations and plant conditions during refueling.
c.
Ascertain the adequacy of the licensee's implementation of controls for (a)
and (b) abov The following procedures were reviewed:
OP 1-1600023, Rev.
OP 1-1610020, Rev.
OP 1-1630028, Rev.
AP 0005732, Rev.
AP 0005746, Rev.
AP 0010119, Rev.
HP 7, Rev.
HP23, Rev.
Refueling Sequencing Guidelines Receipt and Handling of New Fuel New Fuel Handling Crane Operation Outage Management Training Program Outage Management Overtime Limitations for Plant Personnel Health Physics Requirements for all Steam Generator Activities Health Physics Activities in the Reactor Containment Building During Shutdown The spent fuel pool and new fuel storage areas were toured to observe housekeeping and were found adequate.
Continued refueling operations will be observed and reported in subsequent inspection reports.
No violations or deviations were identified in this area.
17.
Exit Interview The inspection scope and results were summarized on July 1, 1988, with those persons indicated in paragr'aph 1.
The inspectors described the areas inspected and discussed in detai
the inspection results listed above.
The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee.
Item Number Descri tion and Reference 335/88-14-01 IFI -
Review licensee's action to standardize procedure for 10 CFR 50.59 review, paragraph 14.