IR 05000324/1982005
| ML20054H087 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 03/25/1982 |
| From: | Burger C, Burke D, Garner L, Paulk G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20054H031 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-1.A.2.1, TASK-2.B.3, TASK-2.D.3, TASK-2.E.4.2, TASK-2.F.1, TASK-3.A.1.2, TASK-3.D.1.1, TASK-3.D.3.3, TASK-TM 50-324-82-05, 50-324-82-5, 50-325-82-05, 50-325-82-5, NUDOCS 8206220558 | |
| Download: ML20054H087 (17) | |
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pn urog'o, UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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E REGION li o,
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101 MARIETTA ST N.W SUITE 3100 o
ATLANTA, GEORGIA 30303 s
Report Nos. 50-324/82-05 and 50-325/82-05
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Licensee: Carolina Power and LigM. Company 411 Fayetteville Streef.
Raleigh, NC 27602 Facility Name: Brunswick Docket Nos. 50-324 and 50-325 License Nos. DPR-62 and DPR-71 Inspection at Brunswick site near Wilmington, NC Inspectors:
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M L. W. Garner, Resid'ent InspecJor Date Signed
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G. Paulk, Resident spectorg Browns Ferry Date Sigried YU SXb S
un D. Burks,' Senior Regident Ipspector, Surry fate St'gned Approved by:
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C. 'Burgdr, Se'ction fAfief, D[iyision of Wate Sighed f
Project and Resident Prog ams SUMMARY Inspection on January 15 - February 15, 1982 Areas Inspected The inspection involved 237 inspector hours on site in the areas of review of Licensee Event Reports, follow-up on Tl11 Task Action Plan Items, review and audit of onsite safety committee meetings, review of periodic reports, training, followup of plant trips and safety system challenges, independent inspection operational safety verification, review and audit of surveillance activities, and review and audits of maintenance activities.
Resul ts Of the 10 areas inspected, three violations were identified.
(Failure to adequately establish procedures see paragraphs 6.c & 6.e.; 10.g,12.f and 11.b; Failure to retain surveillance, maintenance records, see paragraph 13.; and Failure to initiate SBLC LCO, see paragraph 12.a.
One deviation was identified.
(Failure to perform quarterly calibration of equipment installed per Till action plan comaitment see paragraph 6.e).
82062205J8 820609 PDR ADOCK 05000324 O
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DETAILS 1.
Persons Contacted Licensee Employees A. Bishop, Engineering Supervisor J. Boone, Project Engineer
- C. Dietz, General !!anager, Brunswick J. Dimmette, tiechanical liaintenance Supervisor E. Enzor, I & C/ Electrical thintenance Supervisor it. Hill, Itaintenance Ibnager R. Knobel, Assistant fianager of Operations R.11 organ, Plant Operations Ibnager D. Novotny, Regulatory Specialist
- R. Poulk, Regulatory Specialist L. Tripp, RC Supervisor W. Tucker, Technical and Administrative Ibnager Other licensee employees contacted included technicians, operators and engineering staff personnel.
- Attended exit interview 2.
Exit Interview The inspection scope and findings were summarized on February 11, 1982 with those persons indicated in paragraph 1 above. lieetings were also held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings.
3.
Licensee Action on Previous Inspection Findings Not inspected.
4.
Unresolved Items Unresolved items are matters about which more information is required to determine whether they are acceptable or may involve noncompliance or devia tions. New unresolved items identified during this inspection are discussed in paragraphs 10d and 12a.
5.
Review of Licensee Event Reports The below listed Licensee Event Report (LER's) were reviewed to determine if the information provided met NRC reporting requirements.
The determination included adequacy of event description and corrective action taken or planned, existence of potential generic problems and the relative safety significance of each event.
Additional in-plant reviews and discussions
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with plant personnel, as appropriate, were conducted for those reports indicated by an asterisk.
Unit 1 1-81-76 (3L) Check of control Rod 26-19 Hydraulic Control Unit (HCU),
revealed low accumulator pressure and accumulator declared inoperable.
1-81-84 Suppression Chamber Water Level Indicator,1-CAC-LI-2601-3, exhibited gradual upward trend in level indication.
Unit 2
- 2-81-125 (3L)
4" level discrepancy for Torus Level Indications on RTGB between wide range and narrow range instruments.
2-81-135 (3L)
Incorrect input signals from RTGB Instrument 2-CAC-LR-2602 and 2-CAC-LI-2601-3, of RTGB Suppression Chamber Water Level.
- 2-81-137 (3L) RCIC System Turbine tripped and RCIC Trip / Throttle Valve, 2-E51-f10V-V8, would not reset.
- 2-81-144 (3L) Comparison of Suppression Chamber Level Indications on the RTGB, revealed discrepancy between narrow and wide range instrument indications.
- 2-81-145 (3L) No. 4 Diesel Generator tripped on low lube oil pressure.
2-82-1 (3L)
Isolation Valve 2-E51-F043D, would not close when manually actuated from RTGB.
6.
Inspection of Licensee Actions on NUREG-0737, Ti1I Action Plan Requirements a.
I. A.2.1.4.B - Tra ining The inspector verified that the licensee had modified the reactor operator (and SRO) training programs to include training in heat transfer, thermodynanics, accident mitigation and the use of plant systems if core damage occurs, and has increased the emphasis on transients.
Certain individual operator training records were reviewed to verify completion of the above training; no discrepancies were identified.
This item and item II.B.4, Training for flitigating Core Damage, are closed.
b.
II.B.3 - Post-accident Sampling Capability The post-accident sampling systems have not been installed at Brunswick 1 and 2.
Installation of the reactor coolant and containment dunosphere sampling systems is currently planned to occur during the 1982 refueling outages.
The licensee submitted his revised schedule
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for installing the sample systems to the NRC on 6/30/81, and will rely on the interim equipment and measures established in 1979 for post-accident sampling. The inspector reviewed licensee sampling procedures
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RC&T 1500 and 1501 and inspected the sampling station equipment to assure their adequacy.
The inspector determined that the sample technique and equipment is inadequate.
Licensee shielding analysis indicates that post-accident reactor building dose rate would far exceed permissable limits for personnel, excluding entry into the reactor building to take the samples.
In addition, the reactor coolant postaccident sampling equipment consists of a 3/8 inch clear rubber hose on a short run of stainless steel tubing which penetrates a rubber stopper on a 5 gallon plastic bottle.
For post-accident sampling, the rubber tubing is pushed onto the SS tubing discharge from sample valve RXS-1, which is then opened to purge water into the plastic bottle.
The tubing lines are unshielded. A 10 mi syringe, with needle, is used to penetrate the rubber tubing and extract the reactor coolant sample, for analysis.
During observation of the sample technique, the rubber tubing fell off RXS-1 discharge when the valve was opened (hose clamps or fittings are not used).
Thus, the interim equipment, installed in 1979, also appears inadequate.
The NRC is discussing the above items with licensee management to assure expeditious installation of the new (long-term) sampling systems.
Since the licensee has only recently requested manufacturers bids on certain sampling system components (e.g.-reactor building penetration assembly), the inspector recommended that upgrading of the installed (interim) sampling system be considered if further delays occur in the schedule for installation of the long-term system.
In addition, the inspector questioned the relation of the sampling system installation to the refueling outages, since secondary containment (reactor building) is required during refueling.
Ideally, the secondary containment penetration would be installed during mode 4 (cold shutdown) when the primary containment boundary is intact.
(See TS 3.6.5.1).
Item II.B.3 remains open.
c.
II.D.3 - Direct Indication of Safety / Relief Valve Position An acoustic monitoring system has been installed to provide direct indication of safety valve position on each unit. A valve open alarm and seal in open position indication was installed in each control room.
However, the inspector noted that, while the Unit 2 annunciator alarm 1-10 on panel 2A3 was modified to state, " Safety / Relief Valve Open", the alarm procedure for 1-10 on panel 2A3 still referred to the recirc low level loop selection logic, which was removed. This is another example of previous Violation (324/81-29-01) for failing to have appropriate procedures for safety-related annunciators (TS 6.8.1.a), and applies to Unit 2 (324/82-05-01).
The Unit 1 procedure for annunciator alarm 1-1 on panel 2A3 was proper.
The licensee is currently conducting environmental and seismic qualification testing on the valve monitoring system.
Item II.D.3 is closed in that the position indication is functional.
The results of environmental qualification testing will be an inspector followup item (324, 325/82-05-04).
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d.
II.E.4.2 - Containment Isolation Dependability The inspector verified the following:
(1) There is adequate diversity in the parameters sensed for the initiation of containment isolation; this item is closed.
(2) Essential and nonessential systems have been identified and reviewed, and reported to the flRC; this item is closed.
(3) flonessential systems are automatically isolated by the containment isolation signal; this item is closed.
(4) Review and modifications have been performed to prevent automatic reopening of containment isolation valves; reopening requires deliberate operator action.
This item is closed.
(5)
The containment pressure setpoint for isolation of nonessential penetrations is compatible with normal operating conditions (See Insp. Rpt. 324/81-12). This item is closed.
(6) The containment purge valve qualification issue is still under review by the licensee and flRC; this item remains open.
(7) The high radiation closure signal to the purge and vent valves remains open.
e.
II.F.1 - Additional Accident Monitoring Instrumentation (1) The licensee has installed three shielded noble gas effluent radiological monitors (R!l); one on the plant stack and one on each turbine building roof vent.
These interim monitors will be replaced with increased range Rft's in 1982, following equipment del ivery. The inspector observed that 2 of the 3 R!l's installed did not appear operable when their channel displays were monitored (behind U-2 control room).
In addition, a Trouble Ticket was found written on 4-4-81 documenting the existing problem on the U-2 TB roof vent Rf1 (flo test / source response).
The inspector then checked the Ril calibration records and determined that the Rf1 quarterly calibration (111-15T) had not been performed since April, 1981.
Since the licensee stated in his December 31, 1979 letter to the NRC, that these instruments would be calibrated quarterly, according to the manufacturer's recommendations, this is a deviation to that committment (324, 325/82-05-02).
The interim installation is complete and is closed. The long-term item remains open pending installation of the increased range monitors.
(2) Sampling of plant effluents - This item remains open, equipment is being procured.
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4 (3) Containment high range monitors - This item remains open, equipment delivery problems have occurred and have been docu-mented.
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(4) Containment pressure monitor - Wide range (-5 to +245 psig)
containment pressure instruments have caen installed on each unit; this item is closed. While inspecting calibration.and check records, however, the inspector noted that new wide range pressure instrument (CAC-PI-4176) channel check was not documented on 01-3, since the pressure instrument removed (CAC-PI-2599), was still on
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the DSR sheets in procedure 01-3.
This failure to properly revise procedure 0I-3 following modifications, is another example of the previously stated Violation (324/81-05-01) and applies to both units. TS Table 4.3.5.3-1, item 3, requires a monthly channel check on CAC-PI-4176 and 01-3 documents this TS check. The inadequate procedure constitutes a Violation of TS 6.8.1.c (324/82-05-01) and 325/82-05-01).
(5)
Containment water level monitor - This item remains open pending installation of instrument taps on Unit 1 during the !! ark I torus modification outage, and pending completion of the installation on Unit 2.
(6) Containment hydrogen concentration monitor - this item remains open; current schedules for monitor replacement are the 1982 refueling outages.
f.
III.A.1.2 - Upgrade Emergency Support Facilities The licensee has established interim E0F, TSC, and OSC facilities. The interim requirement have been met and are closed.
The licensee is currently reviewing TSC habitability considerations. The inspector verified that the ENS telephone to the NRC was operable in the TSC.
Item 50-324 and 50-325/81-6-4 is closed. Telephone and radiation monitoring equipment in the TSC was appropriate. The inspector noted that the blue emergency phone had been inadvertantly removed from the OSC and was not readily available. The licensee is reinstalling this phone in the OSC.
g.
III.D.3.3 - Improved Inplant Iodine Instrumentation Under Accident Condi tions.
The licensee has provided equipment, training, and procedures for determining the airborne iodine concentration in areas within the facility where plant personnel may be present during an accident.
Additional constant air monitors (CA!!) have been installed in various plant and emergency facility locations, and silver zeolite cartridges
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are utilized to selectively collect iodine.
This iten is closed.
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III.D.1.1 - Integrity of Systems Outside Containment The inspector verified that the licensee had implemented a systematic
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leak rate reduction program on systems outside contappment' which may contain radioactive materials.
Visual inspections and walkdowns were incorporated into the quarterly Periodic Tests (PT's).
Detected
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i leakare is documented and corrected when found.
The inspector stated s
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that acceptance criteria for the leakage rates should be incorporated into the, system PT's.
In addition, initial and periodic test documentation for leak rate determination could not be found for the gaseous system, although the licensee recalled performing helium leak detection tests cn the standby gas treatment and containment air monitoring.(ARM's:aad hydrogen / oxygen monitors) systems outside primary
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contai nment.~ This. };em remains open pending verification of leak rate t,esting of'these gaseous systems.
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In summary, one Violeton (two examples) and one Deviation were identified by the inspector during inspection.of the licensee actions to implement the conmitments to NUREG 0737.
Several Task Action Plan items require licensee followup and action for cor ' -+49n, and thus remain open.
7.
Onsite Review Committees The inspector attended Plant Nuclear Safety Committee (PNSC) 16etings conducted during the period of January 15 through February 15, 1981.
The inspector verified the following items:
a.
Meetings were conducted in accordance with Technical Specification requirements regarding quorum membership, review process, frequency and personnel qualifications;
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Meeting ninutes were reviewed to confirm that decisions / recommendations were reflected and follow-up of corrective actions were completed.
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No violations were identified.
r 8.
Review of Periodic Reports The inspector reviewed the following Licensee Reports.
a.
Brunswick Steam Electric Plant, Units Nos.1 and 2, Monthly Operation
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Report for November,1981.
b.
Brunswick Steam Electric Plant, Units Nos.1 and 2, Monthly Operation Report for December,1981.
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The inspector verified that the information reported by the licensee is
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technically adequate and satisfies applicable reporting requirements established in 10 CFR 50.
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7 The licensee identified that these reports were not issued within ten days, as required by Technical Specification 6.9.1.6.
Corrective action has been implemented and future reports are expected to be issued in a more timely'
manner.
The inspector has no further questions in this area.
9.
Training References:
a.
Technical Specification, Section 6 b.
Regulatory Guide 8.13, Prenatal Radiation Exposure c.
TI 300, General Employee Training, Revision 6/8/81.
d.
10 CFR 20 The inspector observed the General Employee Training (badging) Program given on January 26, 1982, to detennine if the program meets the requirements of applicable regulatory and licensee requirements specified in references (a)
- (d). The inspector observed the badging class to be conducted efficiently and adequately met the regulatory requirements set forth in the above references.
No violations or deviations were identified during this review.
10.
Followup of Plant Transients and Safety System Challenges During the period of this report, a followup on plant transients and safety system challenges was conducted to determine the cause; ensure that safety systems and components functioned as required; corrective actions were adequate; and the plant was maintained in a safe condition.
a.
On January 13,1982, at 1236 hours0.0143 days <br />0.343 hours <br />0.00204 weeks <br />4.70298e-4 months <br />, Unit 2 reactor experienced a high flux scram from 72% of full power. The high flux was caused by void collapse which resulted from a sudden increase in core flow when recirculation pump 2A rapidly increased in speed. No reason for the pump speed increase was found.
Immediately following the reactor scram a group 1 isolation closed the main steamline isolation valves,11SIV's.
The itSIV's remained closed for the next I hour and 15 minutes until the group 1 isolation signal could be reset.
During this time, reactor pressure and water level was controlled by operation of the high pressure coolant injection, HPIC, system, the reactor core isolation coolant, RCIC, system, and manual operation of relief valves B21-F013J and B21-F013D at 1245 hours0.0144 days <br />0.346 hours <br />0.00206 weeks <br />4.737225e-4 months <br /> and 1249 hours0.0145 days <br />0.347 hours <br />0.00207 weeks <br />4.752445e-4 months <br /> respectively.
Each relief valve was opened for approxi-mately one to two minutes.
Normal cooldown was initiated after the group 1 was reset.
The group 1 isolation was attributed to failure of one or more of the main steamline differential pressure switches B21-dPIS-N006A, N0078, N008C and N009D to properly reset when steam flow decreased below 40%
of rated.
Thus when the mode switch was taken out of Run, a group 1
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isolation occurred.
Similar isolations occurred following reactor scrams on December 18,1981 (see Inspection Report No. 325/82-01) and on January 20, 1982 (see paragraph 8c below).
Performance of these switches in this application is less than desirable. The licensee has committed to replace these switches during the next refueling outage.
This has been designated as an inspector followup item in inspection report 82-02.
b.
On January 16,1982, at 1638 hours0.019 days <br />0.455 hours <br />0.00271 weeks <br />6.23259e-4 months <br />, Unit 2 reactor experienced a turbine stop valve TSV, clostre scram from 31% of full power.
Reactor water level was controlled by use of RCIC. The lowest level reached was 156 inches. No Engineered Safeguard Features, ESF, were required.
Events preceding the scram began at 1625 hours0.0188 days <br />0.451 hours <br />0.00269 weeks <br />6.183125e-4 months <br /> when the steam jet air ejector, SJAE, was isolated. An I&C technician was replacing a SJAE low pressure switch 2-MS-PSL-890 when one of the leads shorted to the'
panel causing the SJAE logic power fuse to blow and closing the SJAE isolation valves.
An attempt was made to lower reactor power by reducing recirculation flow and driving in control rods.
However, decreasing condenser vacuum tripped the turbine generator before reactor power could be reduced to below 30% as measured by turbine first stage pressure.
While attempting to put the residual heat removal, RHR, system into the suppression pool cooling mode at 1640 hours0.019 days <br />0.456 hours <br />0.00271 weeks <br />6.2402e-4 months <br />, all 4 RHR service water booster pumps failed to start.
The B and D pumps were started at 2058 hours0.0238 days <br />0.572 hours <br />0.0034 weeks <br />7.83069e-4 months <br /> and A and C pumps were returned to service at 2354 hours0.0272 days <br />0.654 hours <br />0.00389 weeks <br />8.95697e-4 months <br />. The suppression pool temperature did not exceed 95 F during this event. A special investigation into the failure of the pumps to start was conducted by NRC Region II personnel.
The results are documented in Inspection Report 50-324,325/82-02.
The inspector has no further questions about this event at this time.
c.
On January 20,1982, at 0852 hours0.00986 days <br />0.237 hours <br />0.00141 weeks <br />3.24186e-4 months <br />, Unit 2 reactor experienced a scram discharge volume high level trip. A group 1 isolation, closure of the f1SIV's, was received when the mode switch was transferred to shutdown.
See paragraph 8a for explanation.
HPIC, RCIC and relief valves B21-F013F and B21-F013D were manually operated to control reactor pressure and water level until the group 1 could be reset at 0927 hours0.0107 days <br />0.258 hours <br />0.00153 weeks <br />3.527235e-4 months <br /> and normal cooldown initiated.
Apparently, construction work in progress around the scram discharge instrument volume jarred the level switches, thereby initiating spurious trip signals.
The inspector has no further questions about this event at this time.
d.
On January 26,1982, at 0442 hours0.00512 days <br />0.123 hours <br />7.308201e-4 weeks <br />1.68181e-4 months <br />, Unit 2 was manually scrammed from 5% of full power.
Prior to the scram, reactor startup had been halted with system pressure at 200 psig to allow post maintenance testing of L
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safety relief valve, SRV, 2-B21-F013K per procedure 0WP 1-1 following its replacement.
Valve F013K was manually opened but failed to close.
Emergency Instruction EI-40 was implemented which requires a manual scram to be inserted. At 0440 hours0.00509 days <br />0.122 hours <br />7.275132e-4 weeks <br />1.6742e-4 months <br />, in accordance with the emergency plan, an unusual event was declared and required notifications made.
At 0552 hours0.00639 days <br />0.153 hours <br />9.126984e-4 weeks <br />2.10036e-4 months <br />, control board indication showed F013K had started to cycle open and close.
By 0554 hours0.00641 days <br />0.154 hours <br />9.160053e-4 weeks <br />2.10797e-4 months <br />, control board indication indicated the valve was closed with a system pressure of 25 psig. At 0625 hours0.00723 days <br />0.174 hours <br />0.00103 weeks <br />2.378125e-4 months <br />, the tail pipe temperature chart recorder also indicated that the valve was closed with a system pressure of 15 psig.
At 0630 hours0.00729 days <br />0.175 hours <br />0.00104 weeks <br />2.39715e-4 months <br />, the unusual event was declared to be over.
The SRV was replaced.
During the post maintenance checkout, it was discovered that the exhaust port to the associated air operated solenoid valve contained a metal plug.
The other SRV solenoid valves were verified to be open. The licensee is conducting an investigation into why this was not discovered during the initial installation.
This is an unresolved item (324/82-05-05) pending completion of the investigation.
e.
On January 27,1982, at 0625 hours0.00723 days <br />0.174 hours <br />0.00103 weeks <br />2.378125e-4 months <br />, Unit 2 reactor experienced a high IRf1 flux scram during startup after criticality was attained.
Review of IRf1 traces indicate that three reactivity increases had occurred in relatively rapid succession.
The increases were caused by movement of rod 30-47 from 4 to 6 and then 6 to 8 followed by selection and move-ment of rod 38-39 from 4 to 6.
Investigation revealed the operator had failed to observe the flux increase on two of the IM1 channels until it was too late to react.
Compounding the personnel error was an apparent lack of emphasis during operator training of the amount of reactivity held in the top notches of control rods late in core life.
On the subsequent startup, movement of rod 38-39 from 4 to 6 was observed to increase reactor power fron approximately 1.3% to 3%.
The licensee has reviewed this event with each operator.
In addition, all subsequent startups will be observed by the on duty nuclear engineer until the RUN mode is reached.
The licensee is evaluating procedure changes and changes in rod pull patterns to prevent recur-rence.
This study should be complete by April 15, 1982. This is an Inspector Followup Item (324/82-05-06, 325/82-05-06).
flo engineered safeguard features were required during the event. The event was reviewed by the Plant Nuclear Safety Committee prior to the subsequent startup on January 28.
The scram was witnessed by the inspector.
f.
On February 3,1982, at 1516 hours0.0175 days <br />0.421 hours <br />0.00251 weeks <br />5.76838e-4 months <br />, Unit 2 reactor experienced a main steam line, t1SL, high radiation trip from 74% of full power.
A group 1 isolation closed the f1SIV's.
HPCI was operated in the condensate storage tank recirculation mode to control pressure while RCIC was used to control vessel water level.
The 11SIV's remained closed until a reactor coolant sanple was collected and
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analyzed. No abnormal activity was detected in the sample. The liSIV's were opened at 1912 hours0.0221 days <br />0.531 hours <br />0.00316 weeks <br />7.27516e-4 months <br /> and nomal cooldown commenced.
Subsequent coolant samples also showed no abnormal activity.
Investigation revealed that several non-radiation monitors had a series of spurious signals about the same time llSL radiation monitors tripped.
No cause of the spurious signals was identified.
The inspector has no further questions about this event at this time.
g.
On January 18,1982, at 1134 hours0.0131 days <br />0.315 hours <br />0.00187 weeks <br />4.31487e-4 months <br />, Unit I reactor experienced a rapid power reduction from 99% of full power to 45%, when reactor recir-culation pump 1B tripped. The pump was restarted at 1209 hours0.014 days <br />0.336 hours <br />0.002 weeks <br />4.600245e-4 months <br />.
Prior to the restart, recirculation pump 1A's speed was reduced to 48%, in accordance with procedure EI-10. The control room strip chart recorder indicates that loop A flow was thus reduced to between 25,000 and 26,000 gpm.
System description, SD-2, Reactor Recirculation System, Rev. 4, indicates that rated pump flow is 45,100 gpm at 1032 psig.
Technical Specification 3.4.1.3 specifies that startup of an idle recirculation pump is to be suspended if the flow in the operating loop is greater than 50% of rated flow.
Starting of the IB pump on January 18, uith the flow in the operating loop exceeding 50% of rated flow, was caused by inadequate proceduras.
Compliance with procedure El-10, step 3.2.1, i.e., reduce pump speed to less than 50% and with procedure OP-2, step F.2.5, i.e., operating pump speed is 50% (and no lower), does not assure compliance with the technical specification.
Thus, El-10, Rev. 9 and OP-2, Rev 32, were not adequately established on January 18.
This inspector identified item is a violation of Technical Specification 6.8.1.a. in that the procedures for items D.1 and F.18 in Appendix A of NRC Regulatory Guide 1.33, November 1972, were not ade uately established as required.
(324/82-05-01and 325/82-05-01 Investigation into the cause of the pump trip revealed that I&C technicians, while working a trouble ticket, had attempted to measure the output signal of the B21-LIll-N025B-2 transmitter without bypassing the trip function.
Because this analog instrumentation had been recently installed, no written instruction was available on how to perfom this task.
The contractor personnel who installed the equip-ment had indicated that the transmitter output could be measured without removing the instrument from service but failed to supply sufficent infomation on how it could be accomplished.
Thus, failure to provide adequate training to I&C personnel prior to their working on new and unfamiliar equipment was the root cause of this event. This is an Inspector Followup Item.
(324/82-05-12and325/82-05-12)
h.
On February 5,1982, at 2115 hours0.0245 days <br />0.588 hours <br />0.0035 weeks <br />8.047575e-4 months <br />, Unit I reactor experienced a high pressure scram from 15% of full power.
Prior to the scram, the unit was being shut down for a scheduled outage. When the turbine generator was removed from service, the turbine bypass valves failed to open.
Reactor pressure increased to a maximum of 1054 psig. After the scram
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reactor pressure and water level was controlled by use of a feedwater pump and the main condenser via the steamline drains. No ESF systems were required.
The failure of the bypass valves to open was attributed to a malfunc-tioning relay in the bypass valves control circuitry.
This component locked the bypass valves closed as if a low condenser vacuum existed.
The relay has been repaired.
The inspector has no further questions about this event at this time.
One example of the previously cited violation and one unresolved item were identified in this area.
11.
Independent Inspection a.
On January 26, 1982, the inspector review of calibration records indicated that the instrumentation used to comply with the surveillance requirement of Unit 2 Technical Specification 4.4.2, were not part of a periodic calibration program. Technical Specification 4.4.2, requires the safety-relief valves shall be demonstrated operable by verifying that the bellows on the safety-relief valves have integrity, by instrumentation indication, at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Plant procedure 01-3, Attachment No. 2, Auxiliary Operators Daily Surveil-lance Requirements (DSR), Technical Specification Items page 2-2, implements the requirement.
The instruments which are checked daily along with their last calibration date are listed below.
Instrument (Prefix: 2-B21-PI- )
Last Calibration 780 12-15-77 781 12-11-75 783 12-15-77 784 12-11-75 785 Folder Not Found 1250 12-15-77 1253 12-11-75 1254 12-11-75 1256 12-11-75 2891 12-11-75 i
3263 12-30-74 The Licensee promptly calibrated the indicators. One was found to be reading approximately 5 psi low.
No further action is deemed
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necessary, since these instruments will be removed fran service when i
the two stage Target Rock relief valves are installed during the next refueling outage, scheduled early Spring,1982.
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Electrical lineup check sheet contrary to Technical Specification Requirement On January 12, 1982 inspector review of operating procedure OP-17, Residual Heat Removal (RHR) System, revealed that the crosstie valve between Divison I and II of RHR is verified by two operators to have its breaker 1XB-DK6 in the on position.
Technical Specification 3.5.3.2.a.3 requires while in condition 1, 2 or 3 that the power to the LPCI system crosstie valve be removed from the valve operator or be in at least hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This is another example of failure to adequately establish a procedure.
Startup procedure GP-1 does require the valve operator breaker to be open and the breaker apparently has been open during past operation.
Another example of the violation identified above was found in this area.
(324,325/82-05-01)
12. Operational Safety Verification The inspector verified conformance with regulatory requirements throughout the reporting period by direct observations of activities, tours of facilities, discussions with personnel, reviewing of records and independent verification of safety system status. The following detenninations were made:
a.
Technical Specifications: Through log review and direct observation during tours, the inspector verified compliance with selected Technical Specifications Limiting Conditions for Operation.
(1)
Standby Liquid Control Heat Tracing Inoperable The inspector reviewed the circumstances of the licensee's failure to declare the Unit 1 standby liquid control system inoperable between January 8,1982 and January 18, 1982, when the heat tracing was found to be inoperable.
Standby Liquid Control (SBLC) operability is demonstrated on a daily basis through meeting surveillance requirement 4.1.5, which requires the heat tracing circuit to be operable. On January 8, 1982, trouble ticket 1-E-82-068, was written stating the Unit 1 SBLC heat tracing circuits were inoperable.
No limiting condition for operation requirements were noted on the trouble ticket review block 21 by the Shif t Foreman during his review.
The licensee did not note until January 18, 1982, when the heat trace circuit was repaired, that the technical specification surveillance require-ments were not satisfied.
Daily technical specification surveil-lance requirements are checked in accordance with Operating Instruction 3 (01 3).
Operating Instruction 3 was reviewed by the inspector for the week of January 9,1982 to January 15, 1982.
In the daily review blocks, the heat trace circuit was noted to be inoperable for every day during the week.
The SBLC system heat
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tracing was restored to operability on January 18, 1982. After investigation, the licensee determined that the inoperable heat tracing was not in the SBLC flow path, thus SBLC was not inoper-able during the period in question.
Procedure 01-4, LC0 Evaluation and Followup, Revision 8 dated July 10,1981, step 4.1 requires that when any system with a Technical Specification LC0 is found inoperable, the Shift Foreman shall complete appropriate portions of a Event Evaluation Check Sheet and note the malfunction in the Shift Foreman's log.
Failure to perfonn these actions on January 8,1982 when the SBLC heat tracing was found to be inoperable is a violation.
(50-325/82-05-03).
(2) Failure to take Coolant Sample for Dose Equivalent I-131 Determi-nation On January 20, 1982, inspector review of Dose Equivalent I-131 determinations revealed that no reactor coolant samples had been taken on January 18 from Unit 1 after a greater than 30% thermal power change in one hour. Technical Specification 4.4.5, requires a sample to be taken after a change greater than 15%.
No samples were taken because Unit 1 operating personnel failed to infonn the Reactor Chemistry and Testing, RC&T, group that a power change had occurred.
Inspection Report number 324/82-01, issued a violation, 324/82-01-01, for failure to take required reactor coolant samples on December 18, 1981.
That event was attributed to failure of RC&T personnel to complete in a timely manner the Dose Equivalent I-131 calculation.
The licensee has committed to address corrective action to prevent recurrence of the January 18 event in the response to Violation 324/82-01-01.
This is an Inspector Followup Item (325/82-05-05).
(3) Failure to Establish Fire Surveillance per Technical Specifi-cations From 1530 hours0.0177 days <br />0.425 hours <br />0.00253 weeks <br />5.82165e-4 months <br /> on January 11 to 1100 hours0.0127 days <br />0.306 hours <br />0.00182 weeks <br />4.1855e-4 months <br /> on January 12, 1982, surveillance requirements of Technical Specifications 3.7.7.2a and 3.7.7.4.a. were not met in that the service water building standpipe system and south-side sprinkler system were not operational and continuous fire watches were not established as required.
The licensee identified this after the systems had been returned to service. The surveillances were not established as required because personnel used a drawing to determine normal valve positions. The drawing had not been updated to reflect current valve lineups as required by fire protection procedure FP-10, Rev. 2, and operating procedure OP-41, Rev.10.
Thus, when
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portions of the fire main system were isolated to allow repair of a broken pipe in the auxiliary boiler area, personnel were mislead into believing that a flow path existed to the service water building through valves PIV 39 and 40.
However, PIV 40 was actually closed.
Surveillances for other buildings were properly established and the licensee has taken corrective action to 3"
prevent recurrence of this event.
(4) On January 19, 1982, inspector review of limiting condition of operation, LCO, event evaluation check sheets revealed an incon-sistency in the use of the forms for the 2-CAC-AQH-1263 instru-ment.
Because the instrument is in two different Technical Specifications, 3.3.5.3 and 3.6.6.4, sometimes the LC0 is listed under one but not the other.
For example, LC0 No. 2-82-61, listed 3.6.6.4 as the applicable Technical Specification. No mention was
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made of 3.3.5.3 and no separate LC0 was issued for 3.3.5.3 during the time LC0 2-82-61 was in effect.
The subject form is part of the Licensee's administrative controls to maintain operation within technical specification action statement.
There are several other instances of the same component being required under one or more technical specifications which may or may not have similar action statements. The licensee has committed to study this problea and initiate administrative procedure changes by April 15, 1982, as necessary. This is an Inspector Followup Item (324, 325/82-05-09).
(5)
Potential Design Error in Control Building Emergency Ventilation System On February 4,1982, the licensee identified that the Control Building Emergency Ventilation System would not automatically isolate to prevent the admission of chlorine into the control room, if the local control switch is in the ON position.
The system was operated with the local control switch in the ON position from January 25, 1982 to February 4,1982.
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Technical Specification 3.3.5.5, requires that a chlorine
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detection system shall be operable and an inoperable detection
system is to be restored to operable status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or be in Hot Shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Bases for the specifi-cation states in part; upon detection of a high concentration of chlorine, the control roan emergency ventilation system will
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automatically isolate the control roan.
The apparent discrepancy
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between systen design and the intent described in the specifi-cation bases is being investigated.
This is an unresolved item (324,325/82-05-10), pending completion of the investigation.
b.
Control Roen iianning:
By observation during the inspection period, the inspector verified the control roan manning requirements of 10 CFR cg.ca(k) and the Technical Specifications were being met.
In addition, r
a w
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the inspector observed shift turnovers to verify that continuity of system status was maintained.
The inspector periodically questioned shift personnel relative to their awareness of plant conditions.
c.
Control room annunciators: Selected lit annunciators were discussed with control room operators to verify that the reasons for them were understood and corrective action, if required, was being taken.
d.
flonitoring instrumentation: The inspector verified that selected instruments were functional and demonstrated parameters within Technical Specification limits.
e.
Safeguards system maintenance and surveillance: The inspector verified by direct observation and review of records that selected maintenance and surveillance activities on Safeguards systems were conducted by qualified personnel with approved procedures, acceptance criteria were met and redundant components were available for service as required by Technical Specifications.
f.
itajor components:
The inspector verified through visual inspection of selected major components that no general conditon exists which might prevent fulfillment of their functional requirments. One problem condition was identified.
On January 17, 1982, the inspector noted that the Unit 1 Reactor Core Isolation Cooling, RCIC, flow controller was set in " Auto" with a flow demand of 150 gpm instead of the normal value of 400 gpm.
On January 16, at 1930 hours0.0223 days <br />0.536 hours <br />0.00319 weeks <br />7.34365e-4 months <br /> PT 10.1.1 had been completed on this system and the flow demand was apparently not returned to normal. The PT 10.1.1 checklist for returning the RCIC system to standby configuration does not include verification that the flow controller is set in " Auto" with a flow demand of 400 gpm.
This is another example of violation of Technical Specification 6.8.1.a in that PT 10.1.1 is not adequately established in that the above mentioned verification is not included.
(324/82-05-01 and 325/82-05-01).
g.
Valve and breaker positions:
The inspector verified that selected valves and breakers were in the position or condition required by Technical Specifications for the applicable plant mode.
This verifi-cation included control board indication and field observation (Sa feguard Systems).
h.
Fluid leaks:
fio fluid leaks were observed which had not been identi-fied by station personnel and for which corrective action had not been
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initiated, as necessary.
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Plant housekeeping conditions: Observations relative to plant house-keeping identified no unsatisfactory conditions.
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Radioactive releases: The inspector verified that selected liquid and gaseous releases were made in conformance with 10 CFR 20 Appendix B and Technical Specification requirements.
k.
Radiation Controls: The inspector verified by observation that control point procedures and posting requirements were being followed.
The inspector identified no failure to properly post radiation and high radiation areas.
1.
Security. During the course of these inspections, observations relative to protected and vital area security were made, including access control, boundary integrity, search, escort, and badging.
Two violations, examples of a previous violation and one unresolved item were identified in this area.
13.
Review and Audit of Surveillance / Maintenance Activity On January 11, 1981 review of completed surveillance procedures PT 20.3, local leak rate testing of containment isolation, in record storage revealed that data sheets of leak tests conducted on thin Steam Isolation Valve (f1SIVs) 1-B21-F022D, 280, 228 and 28B between August 29 and 31,1981 had not been retained.
During the August and September repair of MSIVs, the inspector had obtained copies of test data.
Comparison of these with the official record indicated that four data sheets had not been retained.
Copies from the inspector's records have been made and incorporated into the record copy.
Failure to retain records of sureveillance activities is contrary to Technical Specification 6.10.1.d.
Leak test data indicates that HSIV valves 1-B21-F022D and 28D had a combined leakage of 14.7 SCFH on September 9,1981.
Another test on September 10, 1981 reported a leakage of 9.4 SCFH.
Review of maintenance records failed to identify what maintenance activity was involved.
Failure to retain records and logs of principle maintenance activities and repair of principle items of equipment related to nuclear safety is a failure to meet Technical
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Specification 6.10.1.b.
These are two examples of a violation of Technical Specification 6.10.1.
(325/82-05-7)
Two examples of one violation vere identified in these two areas.
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