IR 05000280/1981022
| ML18139B587 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 09/01/1981 |
| From: | Burke D, Dance H, Marlone Davis NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18139B583 | List: |
| References | |
| 50-280-81-22, 50-281-81-22, NUDOCS 8111050385 | |
| Download: ML18139B587 (10) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA ST., N.W., SUITE 3100 ATLANTA, GEORGIA 30303 Report Nos. 50-280/81-22 and 50-281/81-22 Licensee:
Virginia Electric and Power Company Richmond, Virginia 23261 Facility Name:
Surry Units 1 and 2 Docket Nos. 50-280 and 50-281 License Nos. DPR-32 and DPR-37 Inspection at~/~ site near Surry, Virginia Inspectors: hfC..: ~a-~ J/::v DXu1~
M. J. DJ}5 Approved by:
&fC ~
H. C. Dance, Section Chief, Division of Resident and Reactor Projects Inspection SUMMARY Inspection on June 1-through July 31, 1981 Areas Inspected 06te'Si gned 9/fff1 tfate 'Signed D~
This inspection involved 280 inspector-hours onsite in the areas of plant operations and operating records, plant maintenance, calibration and testing, followup on NUREG 0737 items, waste shipments, licensee events, and plant securit Results Of the seven areas inspected, no violations or deviations were identified in four areas; six violations were identified in three area Violations were identified during followup of licensee events (improper controls for inoperable spent fuel pit high level alarm-paragraph 5.b; failure to comply with LCO following loss of required equipment-paragraph 5.k); two violations were also identified in the calibration and testing area (calibration procedure for chemical addition tank level instrumentation not properly revised-paragraph 5.i; CLS periodic Tests 8.4 and 8.5 not performed as required-paragraph 5.m); two violations were identified in the plant operations area (no operable boric acid flow path to fueled core-paragraph 5.e, inadequate documentation of increased RCS
leakage-paragraph 6.c)
8111050385 811016 PDR ADOCK 05000280
' G PDR
- . Persons Contacted Licensee Employees
- J. L. Wilson, Station Manager DETAILS
- R. R. Saunders, Assistant Station Manager G. E. Kane, Operations Superintendent
- D. A. Christian, Superintendent of Technical Services L.A. Johnson, Maintenance Superintendent S. P. Sarver, Health Physics Supervisor F. L. Rentz, Resident QC Engineer Other licensee employees contacted during this inspection included control room operators, shift supervisor, QC, HP, plant maintenance, security, engineering, chemistry, administraive, records and contractor personne *Attended exit interview Management Interviews The inspection scope and findings were summarized on a biweekly basis with those persons indicated irr paragraph 1 abov The violations were discussed with licensee management when identified. A management meeting will be held with VEPCO in the Region II office on August 25, 1981, to discuss these and other inspection finding Licensee Action on Previous Findings (Closed) Violation 280 and 281/81-17-01, Nonfunctional fire barrier doors with no fire watc Security Procedure 21, Accessing Security Alarms, was revised on July 27, 1981, to assure that a fire watch is present when the fire doors are in access or blocked ope.
Unresolved Items Unresolved items were not identified during this inspectio.
Unit 1 Operations Unit 1 Steam Generator Replacement Project (SGRP) is complet Unit 1 restart occurred on July 6, 1981, and is currently operating at full powe During the inspection period the inspector routinely toured the control room and other plant areas to verify that the plant operation testing and maintenance were being conducted in accordance with the facility technical specification and procedures. Within the areas inspected, five violations
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were identified. Specific areas of inspection and review included the foll owing: Review of annunciated alarms in the control room and inspection of safety-related valve and alignments on the consoles and in the plan Unit 1 ECCS valves in the safeguards building valve pit were inspected to verify correct valve positions prior to startu Followup on the spent fuel pit overflow which led to an unauthorized, unplanned radioactive liquid release from the station on June 3, 198 At 0530 during a routine security check of the spent fuel (SF)
building, the SF pit was observed overflowing and control room personnel were notifie Inspections of systems were in progress due to the decreasing level of the primary grade (PG) water tank level previously observed by the operator PG valve alignments were checked and verified proper, so systematic isolation of PG from the spent fuel pit was implemente However, at approximately 0800 water was observed flowing from the fuel building truck door to the outside yard storm drai SF pit overflow was stopped at 085 Samples verified that water was from the SF pit(.002 uci/ml Cobalt 60).
Based on the maximum-times and flow rate, up to 100 gallons of contaiminated water may have been released into the storm drain which discharges to the station discharge canca The release, when diluted by the circulating water flow, was well within the Technical Specification (TS) 3.11 and 10 CFR, Part 20 limits. ALER was submitted on the even Subsequently, the licensee found and repaired a hole in the diaphram of valve PG-146 in the PG heade The slight dilution of the spent fuel pit borated water was not significant; the SF pit was filled with greater than 2,000 ppm borated water at all time in accordance with TS 5. The inspector reviewed the control room annunciator alarms and setpoints for the spent fuel pit high level alarm to determine when the alarm occurred and what operator actions were implemented following alarm occurrenc The annunciator alarm card IC-46, which contains electronics for the SF pit high level alarm (CF6), was found pulled and
. inoperable, preventing actuation of the high level visible and audible alarm to the operator in the control roo No logs, procedures, or forms documented or approved pulling of the alarm card IC-46; this is a Violation of Criterion XIV of Appendix B to 10 CFR 50 and Section 14 of the VEPCO NPS QA manual (280/81-22-01). While replacing the reactor pressure vessel (RPV) head onto the vessel, using two of the three guidepins, a thermocouple instrument column in the southeast quadrant was damaged (bent) due to misalignment with the RPV head penetration for the instrument tub The instrument tube or column was removed along with some 12 in-core thermocouple lead Sufficient in-core thermocouples remain for the instrumentation systems and core cooling monitor Subsequently, the guide pin insert in RPV stud hole 37 could not be removed and was cut out; the threads in the
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hole were reworked as require The inspector observed portions of the RPV stud or bolt installation. The studs were properly coated and tightened, but the procedure for threading the studs w~s not observed at the work site in the reactor cavity. A working copy of the procedure OP 4.1 was provided at the job site; the official procedure was maintained in. the control roo The inspectors observed portions of the Type A Integrated Leak Rate Test of the containment on June 25 through June 27, 1981; within the areas inspected, no violations were identifie On June 12, 1981, the inspector observed that the Unit 1 low head and high head safety injection (SI) systems were isolated and inoperable due to Type C leak rate testing prior to the Type A Tes Normally, one of the SI subsystems would remain operable while the redundant systems undergo maintenance and testin However, to expedite the valve maintenance and type C testing, all SI systems were removed from service; the licensee was utilizing the flow path from the refueling water storage tank (RWST) to the reactor core through motor-operated valve (MOV)-RH-100 to satisfy TS 3.2.A, which requires at least one boric acid flow path to the core when fuel is in the reacto MOV-RH-100 is the Residual Heat Removal (RHR) system discharge valve to the RWST:
to assure fl ow from the RWST to the RHR and primary. systems, the RHR pumps would have to be secure This could violate TS 3.1.A.1.d or 3.10.A.6, which requires at least one operable RHR pum In addition, the inspector noted from a jumper log entry that the limitorque operator from MOV-RH-100 had recently been replaced, and that the Unit 1 RWST hi-hi (greater than 100%) level alarm was annunciate This alarm automatically closes MOV-RH-100, to terminate RHR makeup to the RWS Therefore, the inspector requested that the MOV-RH-100 be stroke tested (cycled).
Th~ licensee attempted to stroke test MOV-RH-100 but the closed valve would not ope Personnel were dispatched to the valve, but could not open MOV-RH-100 with the handwheel; a helper bar was located and used to open the valv The torque switches on the valve operator required adjustment to prevent the valve from thermally overloading its main electrical breake Adjustment of limiting switches during maintenance will be reviewed by the inspector (280/81-22-06).
The lack of an operable flow path to the core for boric acid injection is a Violation of Technical Specification 3.2.A (280/81-22-02).
The licensee stated that a flow path for borated water was available as required, with manual operation of MOV-RH-10 The licensee stated that a procedure would be developed outlining this specific equipment arrangement The licensee detected excessive chlorides in the Unit 1 primary system on June 16~ 198 The normal TS 3.1.F.4 limit of 0.15 ppm chloride was exceeded, however, the transient limit of 1.5 ppm was no The maximum
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concentration of chlorides was 0.6 ppm. The reactor was in the cold shutdown condition during the occurrenc Action to correct the condition was delayed due to the valve maintenance and testing mentioned in paragraph e abov The chlorides were reduced below 0.15 on June 21, 1981, after the charging pumps and CVCS were placed into operatio ALER was submitted on the even The inspector observed the performance of portions of Period Test (PT)
18.11, RCS Pressure Isolation Valves and LHSI Check Valve Leakage Determination, prior to Unit 1 startup. The PT was performed in accordance with TS 3.1.C.7, and no check valve leakage was identifie During Unit 1 startup, while placing the charging flow control valve FCV-1122 in service on July 2, 1981, the power operated relief valves (PORV) operated to mitigate an RCS overpressurization transien The RCS was solid and at 190° F, 350 psig when FCV-1122 opened too far due to valve controller problem The RCS pressure increased to some 425 psig, at which time the PORV's operated as required to relieve the pressure; the pressurizatipn limits of TS 3.1.B for heatup were not exceede A special report in the form of an LER (81-18) was submitted in accordance with TS 3.1.6.3. Corrective actions were taken to isolate the FCV and reduce RCS pressure; the FCV and controller were recalibrated, retested, and returned to servic The report stated that no further action was required to prevent recurrence; however, the inspector determined that Periodic Test (PT) 2.13, which calibrates FCV-1122, could be revised to specifically address the calibration error which led to the high flow through FCV-1122 and the pressuri-zation even The licensee stated that PT 2.13 would be reviewed for inclusion of the valve stroke measurement (2 inches) in sections. and 5.8, and correction of the low limit flow of 250 gpm in steps of the data shee (280/81-22-03). During Unit 1 heatup on July 4, 1981, the licensee determined that the calibration procedure CAL-CS-005 for the chemical addition tank (CAT)
level instrumentation was not properly revised to reflect the density differences between pure water and the 17.5% (by weight) solution of sodium hydroxide in the CA (Water is used to calibrate the CAT level instrumentation pressure transmitter).
When the density correction and recalibration was performed on July 4, 1981, the CAT level was at 82%,
well below the minimum TS 3.4.A.4 level of 96.5%, and several hours were required to increase the CAT level to within specificatio The CAT and spray systems are required to be operable prior to exceeding 350° F and 450 psig in the RC The lack of an appropriate detailed written procedure for calibration of the CAT level instrumentation is a Violation of Technical Specification 6. (280/81-22-04).
The correction for densities was identified during Unit 2 startup on August 5, 1980, however, the Unit 1 and 2 calibration procedures CAL-CS-005 and 010 were not properly revised following identification of the discrepanc In addition, PT-2.19A, R~JST Level Calibration, and
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PT 2.15, Boric Acid Tank Level Calibration, have not been properly revised to reflect the density differences between pure and borated wate Since the corrected levels appear to be within the TS limits this is an open item (280/81-22-05).
The RWST contains a 1.25% solution of boric acid, so the 100%
calibration level in the tank should be increased some three inches to 554 inches to correct for the density of the BA solution in the RWS The boric acid tank (BAT) contain a 12.5% (by weight) boric acid solution, however, preliminary studies by the licensee indicate that the decrease in the solution density due to BAT temperature (180° F) compensates for the increase in density due to the boric aci ' The inspector observed the Unit 1 return to criticality at 1720 on July 6, 198 Criticality was achieved within the limits of Operating Procedure IC and the rod insertion limits of TS 3.1 No dis-crepancies were identifie During Unit 1 zero power testing on July 7, 1981, an electrical fuse failure caused a rod urgent failure alarm and two inoperable groups of control rods (8 rods).
The fuse was in the main power cabinet for the CRD lift coil The rod urgent failure alarm occurred at 0040 and was resolved some 2~ hours later by fuse replacemen Technical Specif-ication 3.12.C.3 requires the reactor to be shutdown after two hours if more than one control rod in a given bank is inoperable due to a single failure external to the individual rod drive mechanis Regional interpretation invokes TS 3.0.1 which allows six hours to obtain hot shutdow This item was discussed with plant managemen Subsequently, on July 9, 1981, with Unit 1 at 40% of full power, the delta T (temperature) loop B protection channel was inoperable and not tripped for approximately 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> The instrumentation was inoperable due to incorrect wiring terminations~ from the hot and cold leg RTD 1s, following completion of a design ch~ng Since the temperature protection channel was not tripped, the degree of redundancy required by TS table 3.7-1 for the overpower and overtemperature delta T protection systems was not met, and the reactor was not shutdown as required by TS 3.7.B. This is a violation (280/81-22-07). Followup ori the Unit 1 shutdown due to an auxiliary feedwater leak which occurred at 2030 on July 9, 198 With the unit operating at 47%
power a leak developed at a mechanical joint fitted with a viton sleeve gasket on the 1A 1 steam generator auxiliary feedwater line flow limiting venturi inside containmen The venturi viton gaskets were installed during the recent Unit 1 outag Indications included increasing containment sump level, and increasing containment tem-peratur Increased feed flow on 1A 1 main feed line was observe Power was ramped down to approximately 20% and a manual reactor trip was initiate During the cooldown a safety injection was received at 2127 from steam header to line delta pressure due to the cool down with the reactor pressure greater than 2000 psi Safety systems responded as designe Some 8,000 gallons of feedwater leaked to the containment floo The resident inspector arrived on site shortly after the event
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__ e for an independent revie The plant was placed in cold shutdown at 0607 on July 1 The vi ton gaskets were replaced with flexitall ic gaskets and the unit returned to operation During the Unit 1 startup testing period the inspector reviewed Periodic Test's (PT's) to verify that the required systems were operable for unit startu Portions of the following PT's were reviewed:
PT 2.2 and 2.2A, Reactor Coolant Flow PT 2.3 and 2.3A, Pressurizer Level PT 2.4 and 2.4A, Pressurizer Pressure PT 2.6, Steam Line Pressure PT 2.7, Steam Header Pressure PT 2.11 and 2.11 A, Containment Pressure PT 2.12, Containment Pressure (Vacuum System)
PT 8.38, Safety Injection Logic PT 8.4, Consequence Limiting Safeguards (Hi-Train)
PT 8.5, Consequence Limiting Safeguards (Hi-Hi Train)
PT 17.1, Containment Spray System PT 17.2, Inside Recirculation Spray Pumps PT 17.3, Outside Recirculation Spray Pumps PT 17.4, Containment Spray & Recirculation Spray Check Valves PT 18.1, Low Head SI Test & Flushing of StainlessSteel Piping PT 18.4, Boron Injection Tank PT 18.5 Flushing of Sensitized Stainless Piping PT-18.6, Monthly Testing of Safety Related MOV's PT 18.6A, Quarterly Testing of SI MOV's and HCV's PT 18.68, Quarterly Testing of Miscellaneous Containment Trip Valves PT 18.6C, CSC Testing of Charging & SI MOV's and Check Valves PT 18.6D, Refueling test of MOV 1373 and MOV 1381 PT 18. 7, CHG PUMP OPERABILITY & PERFORMANCE PT 18.8, CHG PUMP CC & SW Pump Test PT 18.9, Boric Acid Pump Operability & Performance PT 19,1, RWST Chemical Addition Tank Performance Within the ares inspected two discrepancies were note PT 8.4 (CLS Hi Train logic) and PT 8.5 (CLS Hi-Hi train) were not performed during the Unit 1 Steam generator Replacement outage nor prior to exceeding 350° F and 450 psig during Unit 1 heatu This is contrary to Technical Specification 4.1.A which requires monthly testing of consequence limiting safeguards syste (280/81-22-08) Unit 2 Operations Unit 2 operated at power during the inspection period except for the reactor trip discussed belo During this time, the inspector routinely toured the Unit 2 control room and other plant areas to verify that the plant operations, testing and maintenance were being conducted in accordance with t~e facility technical specifications and procedure Within these areas inspected, one violation was identified concerning the documentation of
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excessive primary system leakag Specific areas of inspection and review included the following: Review of annunicated alarms in the control room and inspection of safety-related valve and pump alignments on the consoles and in the plan Followup of the Unit 2 RWST chloride contamination which occurred due to chemical addition tank (CAT) sodium hydroxide leakage through normally closed valves (MOV-CS-202A and 2028), into RWST pipin Portable demineralizers were placed in service on the RWST to reduce the chloride concentration. Periodic samples and analyses verified that the boron concentration in the RWST was at least 2000 ppm, but less than 2200 ppm in accordance with TS 3.3.1 during demineralizatio On July 30, 1981, the inspector noted that the reactor coolant system (RCS) leak rate determination, which is normally performed at 0200 or 0300 was not documented in the control room logs or on PT-1 The licensee performed the daily leak_ rate determination at 0940 on July 30, 1981, at which time excessive unidentified RCS leakage was foun The total and unidentified leakage which normally averages 1.2 and gpm increased to some 2.5 and 1.7 gpm respectivel TS 3.1. requires reactor shutdown if the unidentified leakage exceeds 1.0 gpm and the source of the leakage is not identified within 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> The source of the leakage was identified (approximately 0.7 gpm on valve HCV-2310) within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from 094 Efforts to correct the valve leakage are in progres Based on discussions with the licensee's staff and review of inspections and work performed on the July 30 midnight to 0800 shif The inspector determined that increased RCS leakage was identified (RCS valve 2-CH-31) before the 0800 shift change, but not properly documente The action taken to correct the leakage were also not documented, and a deviation report was not initiated. This is a Violation of Criterion XVI of Appendix B to 10CFR50, Section 16 of the VEPCO NPS QA Manaual, and Administrative Procedure ADM-29 (281/81-22-
-01).
A slight increase in containment particulate and gaseous activity was observed on the strip chart recorder for radiation monitors RM-259 and 26 The trend recorder displaying the volume control tank (VCT) level also gave some indication of increased RCS 1 eakag At 1122 on July 17, 1981, Unit 2 experienced a reactor trip and safety
_injection from a high main steam line to header differential pressur The inspector verified that the safety systems performed as require The inadvertent SI was determined to be caused by workers removing scaffolding in the area of two of the main steam header pressure instruments; the instruments, if bumped, momentarily spike up and downscale enough to cause a tri The licensee is considering protective enclosures for the transmitter *
e 8 Genera 1 I terns NUREG 0737, POST-TMI REQUIREMENTS Item II.E.4.1 concerned installation of dedicated containment pene-tration systems for plants using external recombiners or purge systems for postaccident combustible gas control. This item is not applicable to Surry Units 1 and Surry is equipped with two hydrogen recombiners located inside the containment of each unit and therefore does not require dedicated penetrations for its operation, although penetrations could be utilized if external systems were necessar The technical specifications do not require periodic testing of the recombiners to assure operability, however, the licensee has imple-mented a program to periodically test the recombiners and has submitted a change request to technical specifications. This item is considered close Item II.G.1.(1) concerned emergency power for pressurizer relief and block valves and pressurizer level indicator The PORV solenoids are powered from redundant safety grade 125 V de emergency buse The PORV block valves are powered from separate 480 V ac emergency buse Pressurizer level indication channels are powered from vital buses that are powered from redundant safety grade emergency buse This item is considered close Item III.D.3.3, Improved Inplant Iodine Instrumentation under Accident Condition The licensee has obtained silver zeolite cartridges for use in portable air samplers for iodine monitoring under accident condition Use of the cartridges is covered in Emergency Plan Implementing Procedures (EPIP-16 Appendix IV, entitled 110nsite and Offsite Radioiodine Air Sampling Under Conditions of High Noble Gas Concentration
- The requirements of this item have been satisfied for Surry Unit 1 and This item is close Item I.A.2.1 - Reactor Operator and SRO training was previously modified to improve the program in accordance with NUREG 0737; this item is close Item II.E.4.2.(7) - The containment purge valves automatically close on a high radiation signal during refueling or shutdown operation. the valves are closed during power operation. This item is close NRR has reviewed the diversity in the parameters sensed for initiation of containment isolation discribed, however IE review of this item is not complet This item is ope Item II.a.1 - The power supplies for the pressurizer relief valves block valves, and level instruments are fed from the emergency or vital buses in accordance with NUREG 073 This item is close * *
Item II.K.3.9 - In addition, the pressurizer power operated relief valve (PORV's) controllers have been modified to preclude derivative action from opening the PORV's; the proportional integral derivative controllers have had their derivative action or time constants set to zero. This Item is close Waste shipment on June 19, 198 The inspector observed the inspec-tions, monitoring, and loading of LSA boxes onto a trailer truck for shipmen LSA metal boxes with pinholes or cracks were rejected and returned to the storage area for repair The radiation levels around the boxes and the truck were within procedural and regulatory requirements. Although the survey sheets were documented at the loading site, Health Physics procedure HP 3.2.9 used for the inspec-tions and surveys was not at the work site; a copy of HP3.2.9 was brought to the work site and use Plant Physical Protection The inspector verified the following by observation during the report period:
Gates and doors in protected and vital area barriers were closed and locked when not attende Isolation zones described in the physical security plans were not compromised or obstructe Personnel were properly identified, searched, authorized, badged and excorted as necessary for plant access control.
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