IR 05000277/1982019
| ML20027C333 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 09/20/1982 |
| From: | Blough A, Mccane E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20027C329 | List: |
| References | |
| 50-277-82-19, 50-278-82-18, IEB-79-15, IEB-81-01, IEB-81-1, NUDOCS 8210150302 | |
| Download: ML20027C333 (19) | |
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ENCLOSURE 1 50-277/820724 50-277/820725 50-277/820806 50-277/820820 U.S. NUCLEAR REGULATORY COMMISSION 50-277/820910 50-278/820806 50-278/820807 Region I 50-278/820818 50-277/82-19 Report No.
8i0-27R/R2-1R 50-277 Docket No. 50-278 DPR-44 c
License No. DPR-56 Priority Category e
Licensee:
Philadeluhia Electric Company 2301 Market Street Philadelphia. Pennsylvania Facility Name: Peach Bottom Atomic Power Station, Units 2 and 3 Inspection at: Delta, Pennsylvania Inspection conducted: August 7 - September 15, 1982 Inspectors: k
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7/Ohd A. R. Blopgh, Senior Resident Inspector date signed
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date signed date sign Approved by:
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d McA E. C. McEbbe, Jr., Chief, Reactor
'pste vigned Projects Section No. 2B, DPRP Inspection Summary:
August 7 - September 15,1982 (Combined Inspection Report 50-277/82-19 and 50-278/82-18
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Routine, on-site and backshift resident inspection (63 hours7.291667e-4 days <br />0.0175 hours <br />1.041667e-4 weeks <br />2.39715e-5 months <br /> Unit 2; 55.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> Unit 3) of: accessible portions of Unit 2 and Unit 3, operational safety, radia-tion protection, physical security, control room activities, licensee events, IE Bulletin followup, surveillance testing, potentially generic issues, containment purging commitments, periodic reports, and outstanding items.
Results: Violations: One (failure to meet Technical Specification Limiting Conditions for Operation regarding primary containment integrity, Detail 5),
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DETAILS j
1.
Persons Contacted S. L. Daltroff, Vice President, Electric Production J. K. Davenport, Maintenance Engineer G. F. Dawson, I&C Engineer
- R. S. Fleischmann, Assistant Station Superintendent N. Gazda, Engineer, Health Physics
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D. Helker, Test Engineer A. Hilsmeier, Senior Health Physicist G. John, Test Engineer J. Mitman, Results Engineer F. W. Polaski, Reactor Engineer S. R. Roberts, Operations Engineer S. A. Spitko, Site QA Engineer S. Q. Tharpe, Security Supervisor
- W. T. Ullrich, Station Superintendent J. E. Winzenried, Technical Engineer Other licensee employees were also contacted.
- Present at exit interviews on site for summation of preliminary inspection findings.
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2.
Status of Previous Inspection Items (Closed) Inspector Follow Item (81-07-04 and 81-09-03), conduct activities which could result in radioactive releases only in accordance with approved procedures; apply contamination control procedures to potentially contaminated systems; mark the piping and components of potentially contaminated systems (ImmediateActionLettercommitments). The inspector interviewed operations personnel to verify their awareness of the required procedural controls. Also, the inspector reviewed the following procedures:
-- S12.7.1.L, Revision 0, April 21, 1981, Placing the Drywell Chilled Water System in Bleed and Feed Purge Mode;
-- S9.6.H, Revision 0, February 1, 1982, Placing Turbine Building Closed Cooling Water in Bleed and Feed Purge;
-- S9.5.G, Revision 1, May 23, 1982, Placing the RBCCW in Feed and Bleed Purge Mode; and
-- HP0/CO-llA, Revision 0, August 3,1981, Breach of Potentially Contaminated l
Systems.
i Each feed-and-bleed procedure has precautions against unplanned releases and
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provides bleed points routed to the liquid radwaste system. The inspector i
also verified the " Potential Contamination" markings on piping and components j
of the Reactor Building Closed Cooling Water, Turbine Building Closed Cooling
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Water, and Drywell Chilled Water Systems. The inspector had no further ques-i tions regarding this item.
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(Closed) Inspector Follow Item (277/81-07-03), review of normally non-radioactive systems that had become contaminated to insure that permissible activities will not result in unplanned releases (Immediate Action Letter commitment). The inspector verified, through review of system drawings and discussions with licensee engineers, that the review had been completed.
Corrective actions included tagging selected valves, blocking certain drain lines, and posting of potentially contaminated areas. The review also pro-vided input to a more comprehensive (i.e. plant wide) study of liquid leakage poten'!al (see items 277/81-07-05 and 278/81-09-04, below).
(Closed) Violation (277/81-07-02), feed and bleed of contaminated systems without an approved procedure. The licensee's corrective action was discussed in items 277/81-07-03 and 04 above. The inspector had no further questiens.
(0 pen) Inspector Follow Item (81-07-05 and 81-09-04), review licensee progress on modifications to reduce potential for liquid radioactive releases. The licensee committed to about 40 modifications with due dates of July 1,1982, January 1, 1983, and July 1, 1983. The inspector reviewed the status of the July 1,1982 modifications, which involved a portion of the Turbine Building 116-foot elevation. A dike was installed at the personnel and vehicle access point. Selected floor drains were capped or plugged, as connitted. At three locations, temporary plugs were used prior to July 1 and later replaced with permanent materials.
One modification, sealing of the backwater valve access pit had not been done. The licensee indicated that sealing of the pit would be needed only if floor drains had been re-routed to radwaste; when the licen-see chose instead to cap or plug selected drains, he overlooked deletion of the access pit modification. The licensee is reviewing this matter further and is considering amending his commitment.
The licensee had indicated that, among the January 1,1983 modifications, installation of dikes at the Reactor Building 135-foot elevation railroad access doors would be expedited. The railroad doors had been of particular concern because of past releases of contaminated water under the doors. On August 30, the inspector noted that the dikes were completed.
This item remains open, pending review of the future modifications and is now unresolved, pending licensee clarification of the backwater valve access pit status.
(Closed) Unresolved Item (80-02-03 and 80-02-03), Fire Protection Safety Evaluation Report (SER) commitment 3.1.14, various procedure revisions needed.
The inspector reviewed the following procedures:
-- S 13.1, Revision 0, May 18, 1981, Smoke Removal Equipment Operation;
-- ST 16.15, Revision 1, January 6,1981, Fire Hydrant Lubrication;
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-- ST 16.16, Revision 3, October 15, 1981, Fire Door Inspection; and
-- A-30, Revision 4, June 10, 1981, Plant Housekeeping Controls The inspector also reviewed a sampling of Pre-Fire Strategy Plan Procedures, F-1 through F-146, issued during June-September 1981. The RBCCW Room and Recirculation MG Set Room strategies were revised in February 1982 to in-corporate the new automatic sprinkler systems. The inspector checked smoke removal equipment storage lockers. Smoke removal equipment met licensee commitments; however, the number of extension cords was less than is listed on the licensee's inventory sheets. When informed, the licensee promptly re-inventoried and re-stocked the lockers.
Inventory is routinely checked quarterly. The inspector also reviewed the completed documentation for ST 16.16, completed June 25, 1982. No violations were identified; the in-spector had no further questions on this item.
(Closed) Inspector Follow Item (277/82-14-03), restoration of full-operability of the seismic monitor. One of four sensors was out of service due to lack of replacement parts.
The inspector verified through in-plant observations that the repairs had been completed.
This item is closed.
(Closed) Violations (277/79-23-03, 277/79-29-02, 277-79-30-08, 277/80-08-02, 277/81-24-06,278/80-05-01,278/81-07-01), failure to follow various RWP requirements or to wear required dosimetry. The inspector spot-checked individual item corrective actions, which included counselling individuals, upgrading General Employee Training, relocating RWP's from a Field Opera-tions Office to local access points, issuance of " Nuclear Plant Rules," and meetings with operators and with HP supervicion.
No inconsistencies were identified and the same individuals were not involved in recurrent violations.
However, recent inspections have identified additional problems with worker adherence to Health Physics requirements, indicating a generic problem. This was discussed at an enforcement conference on July 22, 1982 (reference meet-ing report 277/82-17,278/82-15). The licensee's recently developed " Health Physics and Radwaste Action Program" lists measures to correct this problem, including stronger enforcement, policy studies, and procedure revisions. The inspector reviewed a memorandum from the Station Superintendent implementing stronger enforcement for plant rules.
During this inspection the licensee twice restricted site access of workers who violated Health Physics proced-ures--a total of five individuals were involved. The inspector discussed these events with the Station Superintendent and the Radiation Protection Manager.
These items are closed; NRC review of recent findings is on-going.
(Closed) Unresolved Item (277/82-11-08), inconsistencies in survey information and dose estimates regarding fuel channel clips handling incident. The in-spector attended a licensee meeting held to clarify details of the event and
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also interviewed individually three persons involved in the event. The licen-see identified the following errors in his initial investigation:
(1) The worker handled about three pieces of rusty shim stock, not fuel channel clips; and
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(2) The worker found the shims lodged in a section of the refueling grapple mast that he was cleaning and inspecting, not from the " fuel elevator."
The worker's inspection included putting his hands inside the mast to check air hoses for tightness.
The worker said he remembers wearing finger dosimetry. The Health Physics (HP) technician did not see or ask whether the worker was wearing finger dosimetry. The licensee stated that the worker had been issued one set of finger badges for October 1981, and the readings were 99 and 82 millirems for the month. The HP technician's survey of the pieces of shim stock in-dicated 30-40 Roentgen per hour (R/Hr) at one to three inches and 0.8 to 3.2
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R/Hr at 10 to 24 inches. Also, the HP technician remembers that two area radiation monitors (ARMS) alarmed; he described the shims' location at the time of the alarms. The inspector checked the monitor setpoints (15 milli-roentgen per hour), observed monitor arrangement on the Unit 2 fuel floor, and estimated the distances from the monitors to the described shim loca-tion. Using survey and ARM information, the inspector performed several calculations of dose to the worker's hands in this event.
Each calculation indicated a higher dose than was read on the worker's October 1981 finger dosimetry. The licensee re-enacted the event and re-calculated the worker's extremity dose, using survey and ARM information.
The licensee concluded that 2900 millirem was a reasonable, conservative dose estimate and revised the individual's exposure record to reflect that dosage. This item is resolved.
The inspector also received additional information regarding surveys in this event. Just prior to the event, the HP technician had surveyed a " prep machine" as it was removed from the pool. Wl.en the worker contacted him about making an inspection, the HP technician believed the " prep machine,"
rather than the refueling mast, was to be inspected. Also, the HP tech-mast (which had been surveyed on its exterior) putting his hands inside the nician was not aware that the worker would be or removing loose pieces, activities that would necessitate special surveys.
Later, when the worker raised a bucket from the fuel pool to place the shims in it, no survey was made. The worker believes there were some small pirces of metal in the bucket when he raised it. The issue of removal of the bucket without a survey is considered unresolved (277/82-19-01).
Failure to perform sur-veys of the mast was identified in a previous report (reference combined report 277/82-11and278/82-11).
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(Closed) Inspector Follow Item (277/79-SB-04, 278/79-SB-04), review poten-tial effects of degraded 4 KV bus voltage. This generic item has been transferred to NRR for review. To verify that requested information had been submitted to NRR, the inspector reviewed licensee letters dated February 4,1982, April 15,1982, and July 22, 1982.
(0 pen) Inspector Follow Item (277/81-24-02), ECCS logic power supply failures.
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The licensee continues to pursue seismic and environmental qualification of a more reliable supply (see Detail 3.3).
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3.
Plant Operations Review 3.1 Logs and Records The inspector spot-checked logs and records for accuracy, completeness, abnormal conditions, significant operating changes and trends, required entries, operating and night order propriety, correct equipment and lock-out status, jumper log validity, conformance to Limiting Conditions for Operations, and proper reporting. The following logs and records were reviewed.
(a) Shift Supervision Log, August 7 - September 14, 1982 (b) Reactor Engineering Log, Unit 2 - August 7 - September 14, 1982 (c) Reactor Engineering Log, Unit 3 - August 7 - September 14, 1982 (d) Reactor Operator's Log, Unit 2 - August 7 - September 14, 1982 (e) Reactor Operators Log, Unit 3 - August 7 - September 14, 1982 (f) C0 Log Book - August 7 - September 14, 1982 (g) STA Log Book - (Sampling) August 7 - September 14, 1982 (h) Night Orders - Current Entries (i) Radiation Work Permits (RWP's) - Various in both Units 2 and 3, August - September 1982 (j) Maintenance Request Forms (MRF's) - Units 2 and 3, (Sampling)
August - September 1982 (k)
Ignition Source Control Checklists (Sampling) - August - September 1982 (1) Operation Work & Information Data - August - September 1982 Control Room logs were compared against Administrative Procedure A-7,
" Shift Operations." Frequent initialing of entries by licensed operators, shift supervision, and licensee on-site management con-stituted evidence of licensee review.
No unacceptable conditions were identified.
3.2 Facility Tours Daily tours and observations included the following:
-- Control Room - (daily).
-- Turbine Building - (all levels).
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t Diesel Generator Building.
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Yard area perimeter and exterior to the power block, including
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Emergency Cooling Tower and torus dewatering tank.
Security Building, including Aux SAS, and control point monitoring.
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Vehicular Control.
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The SAS and power block control points.
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Security Fencing.
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Portal Monitoring.
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Personnel and Badging.
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-- Control of Radiation and High Radiation areas, including locked door checks.
-- TV monitoring capabilities.
-- Shift turnover.
Off-Shift inspections during this inspection period and the areas examined were as follows:
DATE AREAS EXAMINED August 13 Control Room, Cable Spreading Room August 24 Control Room, Circulating Water Pump Structure August 25 Control Room, Unit 3 Reactor Building August 26 Control Rocm Start-up Switchgear Buildings i
August 30 Control Room, Emergency Cooling Tower
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3.2.1 Control Room Manning. Staffing frequently was checked against 10 CFR 50.54(k), the technical specifications, and comitments to the NRR letter of July 31, 1980.
Presence of a senior li-censed operator in the control room complex was verified fre-quently. No unacceptable conditions were identified.
3.2.2 Fluid Leaks. The inspector observed sump status, alarms, and pump-out rates, and discussed leakage with licensee personnel.
On August 9, the inspector noticed an actuating air leak on Unit 2 containment ventilation valve A0-25218. When informed, shift supervision initiated a Mair.tenance Request and the leak was repaired.
No violations were identified.
3.2.3 Piping Vibration.
No significant or unusual piping vibration was identified.
3.2.4 Monitoring Instrumentation. The inspector frequently confirmed that selected instruments were operating and indicated values were within Technical Specification requirements. Daily, when the inspector was on site, ECCS switch positioning and valve lineups, based on control room indicators and plant observations were verified. Observations included flow setpoints, breaker positioning, PCIS status, radiation monitoring instruments, and process computer printouts.
About 2:25 p.m., August 16, the inspector noted that a Unit 3 process computer printout indicated that core power at noon had been 3300 megawatts thermal (MWT). The operating license limits steady state power level to 3293 MWT. When informed, the operator obtained a current computer heat balance calcula-tion of core power (it was 3295 MWT), then reduced recircula-tion flow slightly to bring core power to 3277 MWT. The inspector reviewed heat balance data, which indicated that power had been varying between 3284 and 3300 MWT during the shift. The licensee calculated average power during the shift as 3292.6 MWT. The inspector reviewed NRC:IE enforcement guidance dated August 23, 1980 and determined that this event did not constitute steady state operation above the licensed power level. The NRC:IE enforcement guidance was discussed with the licensee, who had i
previously been supplied a copy. The licensee indicated that
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additional guidance to operations personnel on this subject is being considered; the item will be re-inspected (278/82-18-01).
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3.2.5 Environmental Controls. The inspector observed visible portions of main stack and ventilation stack radiation recorders and peri-odically reviewed traces from backshift periods to verify that radioactive gas release rates were within limits and that unplanned releases had not occurred. The inspector reviewed licensee samples and administrative controls for the following planned liquid re-leases to verify that regulatory requirements were met:
Radwaste No.
Source Release Date 1200-82 Floor Drain Sample Tank (FDST) August 9,1982 1370-82 FDST September 4, 1982 The inspector also reviewed liquid release final suninaries for July and August; these indicated a total of about 3.8 curies (excluding tritium and noble gases)
relea:;ed during the quarter.
The inspector verified that the licensee was aware of both the 20 curie per quarter limit and the 5 curie per quarter reporting requirement of Technical Specifications. The licensee believes he will be able to maintain total releases less than 5 curies for the quarter.
3.2.6 Fire Protection. On frequent occasions the inspector verified the licensee's measures for fire protection. The inspector observed control room indications of fire detection and fire suppression systems, spot-checked for proper use of fire watches and ignition source controls, checked a sampling of fire barriers for integrity, and observed fire-fighting equipment stations.
Also, the inspector checked carbon dioxide tank levels and se-lected fire suppression system valve positions.
No violations were identified.
3.2.7 Housekeeping. The inspector observed in-plant housekeeping
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conditions. Some improvement was noted. The inspector noted that housekeeping inspections by operations personnel are con-tinuing at a frequency of twice per week.
The inspector reviewed a sampling of the completed reports.
No violations were identified.
i 3.2.8 Equipment Conditions.
The inspector verified operability of -
selected safety equipment by in-plant checks of valve positioning, control of locked valves, power supply availability and breaker positioning. Selected major components were visually inspected for leakage, proper lubrication, cooling water supply, operating (
air supply, and general conditions.
Systems checked included I
Unit 3 Standby Liquid Control, Core Spray 'A'
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'C', and Unit 2
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Selected Emergency Service Water System valves and safety instrument root valves were also checked.
Engineer safety feature actuation sensor readouts were periodically checked to verify con-sistency with plant conditions.
3.3. Follow-up of Events Occurring During Inspection--ECCS Power Supply Failure--Unit 3 About 9:30 p.m., August 30, voltage oscillations in one of the two ECCS logic systems resulted in a RCIC initiation signal. The operator veri-fied that the injection was unnecessary and tripped RCIC before it in-jected. The licensee informed the NRC Operations Center and the resident inspector and began a shutdown during troubleshooting.
Both 24-VDC power supplies to the affected logic were found degraded and were replaced.
Then the reactor was restored to full power. These supplies had been tested monthly since a similar occurrence in June 1982.
The inspector reviewed logs and recorder traces and discussed this event with licensee operators and engineers. The licensee increased the test frequency to weekly and plans to review test data weekly at PORC meetings.
The licensee's corporate engineering staff continues to pursue environ-mental and seismic qualific.ations of a more releable supply (see Detail 2).
4.
I.E. Bulletin Followup 4.1 I.E.Bulletin 79-15, Deep Draft Pump Deficiencies Deep Draft Pumps at some facilities had shown extensive design and workmanship deficiencies.
Pumps from three manufacturers were involved.
The bulletin required licensees to report the following on each safety-related deep draft pump: manufacturer, model, capacity, application, dimensions, testing and routine maintenance history, operating history, and corrective maintenance history.
Backup information was to be avail-able for inspection.
Corrective action programs were required where pumps failed to meet design requirements.
The inspector reviewed the licensee's response, interviewed the cogni-zant enginecr, and spot-checked supporting documentation. All required information was supplied in the licensee's response. The licensee uses a total of thirteen safety-related pumps in the High Pressure Service Water (HPSW), Emergency Service Water (ESW), Emergency Cooling Water (ECW) and Fire Suppression Systems.
None of the pumps are from vendors referenced in the bulletin.
No significant problems have been noted with the ESW, ECW, or Fire Pumps.
In 1976 and 1977, the High Pressure Service Water Pumps experienced the following problems:
-- One pump broke its shaft coupling. After evaluation, the coupling hardness was reduced to prevent recurrence.
-- Coupling bolts and nuts on all eight pumps were not to specification and were replaced.
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-- Column flange bolts on all pumps had to be replaced for seismic upgrading.
No significant design or workmanship problems have been discovered since.
HPSW pump design discharge pressure at rated flow is significantly above Technical Specification limits.
Pump capacity will drop over time due to wear, but the licensee's surveillance program requires quarterly testing and repair of a pump before the Technical Speci-fication limit is reached. Several pumps were rebuilt (or had their impeller clearances adjusted) to improve capacity in 1977 and 1978.
The inspector reviewed recent pump capacity tests:
-- ST 6.10-2, Revision 1, December 22, 1981, HPSW Pump and Valve Operability and Flow Rate Test - Unit 3 performed August 26, 1982; and
-- ST 6.10-3, Revision 2, December 22, 1981 HPSW Pump and Valve Operability and Flow Rate Test--Unit 3, performed August 27, 1982.
At rated flow, the pumps provided discharge pressure from 260 to 290 psig (minimum acceptable = 233 psig).
Because pump wear accelerates if mud or silt accumulates in the suction bays, a routine test, performed about once per month, checks for accu-mulation. The inspector reviewed the most recent test:
-- RT 1.5.1, Revision 2, November 20, 1981, HPS0 Pump Bay Mod Accumula-tion Measurement, performed August 23, 1982.
No violations were identified. The inspector had no further questions.
4.2 I. E.Bulletin 81-01, Surveillance of Mechanical Snubbers Because of numerous snubber failures at other facilities, the bulletin required certain inspections and tests of mechanical snubbers..
All actions, except for manual tests of Unit 2 snubbers, were verified complete during combined inspection 277/81-24 and 278/81-26. The li-censee's final bulletin response, dated April 22, 1982, indicated that the tests were completed during the Spring 1982 refueling outage. The inspector reviewed snubber data sheets, the test procedureMechanical Snubber Surv M65.10, Revision 0, July 31, 1981, see maintenance records. These indicated that all mechanical snubbers had been tested with no failures. Regarding the licensee's response letter, the inspector noted the omission of certain required informa-tion, i.e., number of snubber tested, grouped by manufacturer, model number and size. The licensee indicated that the response would be amended; the inspector will review the submittal (277/82-19-02).
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5.
Licensee Event Reports 5.1 In-Office Review The inspector reviewed LER's submitted to NRC:RI to verify that the details were clearly reported, including the accuracy of the descrip-tion of corrective action adequacy. The inspector determined whether further information was required, whether generic implications were indicated and whether the event warranted onsite followup. The fol-lowing LER's were reviewed:
LER No./
LER Date/
Event Date Subject
- 2-82-18/3L Fire damper failed to trip during testing.
August 23, 1982 July 24, 1982 2-82-19/3L Two steam line radiation monitor setpoints August 23, 1982 drifted above allowable and were re-July 25, 1982 adjusted; redundant channels were oper-able.
2-82-20/3L Two drywell pressure recorders failed due September 3, 1982 to blown fuses. A circuit ground was August 6, 1982 eliminated and the fuses replaced; re-dundant instruments were operable.
2-82-22/3L One Control Room intake air radiation September 10, 1982 monitor failed downscale.
The channel August 20, 1982 was tripped until the detector was re-placed and calibrated.
- 2-82-27/IP Reactor was operated without primary September 13, 1982 containment integrity.
September 10, 1982 3-82-14/3L Drywell temperature indicator failed due September 10, 1982 to defective power supply; redundant August 18, 1982 temperature recorder was operable.
Indicator was repaired.
3-82-12/3L Reactor Building exhaust radiation monitor September 3, 1982 detector failed and was replaced. Re-August 6, 1982 dundant monitors were operable.
3-82-13/3L Torus level indicator failed due to September 3, 1982 broken linkage. Redundant indicator August 7, 1982 was operable during repairs.
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5.2 Onsite Followup For LER's selected for onsite review (denoted by asterisks above), the inspector verified that appropriate corrective action was taken or responsibility assigned and that continued operation of the facility was conducted in accordance with Technical Specifications and did not constitute an unreviewed safety question as defined in 10 CFR 50.59.
l Report accuracy, compliance with current reporting requirements and applicability to other site systems and components were also reviewed.
1 5.2.1 LER 2-82-18/3L. One Cable Spreading Room fire damper failed to
trip during smoke detector testing. The release mechanism l
appeared to be improperly reset; however, it tripped when touched and the failure could not be repeated. The mechanism
i was reset, tested several times, and declared operable.
i Although not addressed in the LER, the procedure for re-setting fire dampers was revised to prevent recurrence.
The inspector had no further questions, i
5.2.2 LER 2-82-27/IP. About 5:25 p.m., September 10, the licensee i
determined that the 100 psi Service Air System outboard con-tainment isolation valve was open.
For primary containment f
integrity, the valve must be shut; procedure requires it to
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be locked shut. This condition was found during investiga-
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tion of higher than normal drywell oxygen concentration. The
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licensee shut and locked the valve and, believing the inboard
valve must also be open providing air leakage into the dryviell,
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declared an Unusual Event, notified the NRC Operations Center
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and began a plant shutdown. After shutdown the licensee entered the drywell, found the inboard isolation valve fully open, and
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shut and locked it. The unit returned to power operation on i
i September 11. The inspector verified that the licensee had i
properly classified this event and had followed emergency plan procedures.
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The licensee identified several circumstances and causal factors
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in this event. The valves had been checked following a refuel-
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ing outage that ended June 25.
Darir.g a maintenance outage from August 6 through 12, the valves were opened for use of pneumatic
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tools in the drywell during recirculation pump seal replacement.
Re-positioning of the valves was not entered into the " Locked
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Valve Log," as required by Administrative Procedure A-8.
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failure to log valve positions defeated one administrative con-i trol, a shift supervision review of the log prior to startup
to verify that valve positions are consistent with startup re-i quirements. Because the inboard isolation valve had a lock i
that is more coninonly used on electrical switches and fire pro-tection equipment than on administratively-controlled valves, the operator who opened it believed (wrongly) that logging was i
unnecessary. The outboard valve had a standard " Unit 2 Locked
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Valve" lock; licensee investigation had not yet determined how it was opened. Reactor startup procedures call for performance of GP-1, Pre-Startup Check-off List, if prescribed by the Oper-ations Engineer.
For the August 11-12 startup, an abbreviated GP-1 was prescribed due to the limited scope and duration of the outage. The abbreviated GP-1 did not include GP-1 C.0.L.,
Drywell Check-off List, which involves, in part, checking ser-vice air drywell isolation valve positions. The inspector interviewed licensee personnel and reviewed logs and procedures to verify accuracy of licensee-provided information.
Had a loss of coolant accident (LOCA) occurred, the drywell could have pressurized to about 49 psig (the design basis). With service air pressure 100 psig, leakage would still be into con-tainment.
Either of two additional events could cause service air piping depressurizetion and consequent out-leakage:
-- Loss of nor.-emergency electrical power. Closed valves at individual service air connections in the drywell(in the non-seismic portion of the system) would restrict outflow in this event.
-- Failure of service air piping. Only the portion of piping containing the isolation valves is seismically qualified.
This section of piping also contains a check valve which would probably restrict flow.
However, this check valve is not subject to leakage specifications or test require-ments.
The Technical Specification definition of primary containment integrity includes, in part, that all non-automatic contain-ment isolation valves on lines connected to the reactor coolant system or containment which are not required to be open during accident conditions are closed. Those valves may be opened to perform necessary operational activities. Thus, with the ser-vice air drywell isolation valves open (not necessary for oper-ational activities) primary containment integrity was not established. Technical Specification Limiting Conditions for Operation, Section 3.7.A, Primary Containment, requires primary containment integrity when the reactor is critical.
Failure to have primary containment integrity with the reactor critical from August 12 to September 10, 1982 is a Violation (277/82-19-03).
Besides shutting down and closing and locking the service air drywell isolation valves, licensee short-term corrective actions included checking all Unit 2 locked valves per Administrative Procedure Appendix A-8A; no additional discrepancies were found.
The licensee indicated that investigation and review was contin-uing and long-tenn corrective action would be developed. The
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inspector expressed concern regarding control of valving in general, in view of the facility's recent history of significant t
valving errors:
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-- In May 1982, the licensee identified a primary containment violation due to a manometer valved to the torus air space.
-- In July 1982, the licensee identified two instances of l
violation of safety instrument operability requirements
due to open equalizing valves on main steam line flow trans-
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mitters.
-- In July 1982, the NRC identified that a back-up ADS air supply, installed per the TMI Action Plan in May 1982, had been left isolated from the ADS valves, j
The licensee acknowledged and agreed with this concern.
6.
Surveillance Testing
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6.1 Observations
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The inspector observed surveillance to verify that testing had been j
properly approved by shift supervision, control room operators were knowledgeable regarding testing in progress, approved procedures
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were being used, redundant systems or components were available for service as required, test instrumentation was calibrated, work was i
performed by qualified personnel, and test acceptance criteria were
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met.
Parts of the following tests were observed:
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-- ST 6.7.1, Revision 3, October, 1981, Daily Core Spray 'B' System
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and Cooler Operability, Unit 3, performed August 25; l
-- ST 3.5.1-2, Revision 2, October 21, 1980, RBM Function and Calibra-tion Test, started August 26 (completed August 27);
i 6.2 Document Reviews The inspector reviewed documentation t,i the following completed
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surveillance tests:
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-- ST 9.16 (see Detail 8);
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-- ST 16.2.1, Revision 5, October 10, 1980, Fire System Weekly Check,
performed August 17, 1982.
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For ST 16.2.1 there was no documentation of shift supervision permission to begin the test. Shift supervision had, however, accepted the com-
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i pleted test. The supervisor believed that permission had been obtained, but not documented.
Based on the large number of surveillances reviewed in recent inspections, this oversight is considered an isolated case.
This was reviewed with the Operations Engineer and shift supervisor.
Based upon the above findings, the inspector had no further questions on this item.
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7.
Follow-up of Potentially Generic Issues The Residual Heat Removal System (RHR) logic, by design, thould prevent remote manual closing of outboard isolation valves for 5 minutes after initiation of Low Pressure Coolant Injection (LPCI). At an operating BWR, this feature was found to be by-passed, because vendor-supplied drawings showed the logic circuitry connected to the wrong contacts of a time delay pick-up relay.
To evaluate the applicability of this issue to the Peach Bottom units, the inspector reviewed RHR logic diagrams, interviewed the cognizant licensee engineer, and spot-checked in-plant wiring.
Findings were as follows:
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-- The licensee's RHR logic was designed differently from the vendor's generic logic to incorporate the sharing of diesels between units.
-- The licensee's drawings show proper connections to the time delay pickup relay contacts.
-- The inspector checked a representative Unit 2 time delay relay; its connections agreed with the licensee's drawings.
The inspector had no further questions on this issue.
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8.
Containment Purging Commitments The inspector verified the licensee's continued adherence to commitments on large diameter containment purge valves (previously reviewed in com-bined report 277/81-16 and 278/81-17.
Qualification of large diameter containment purge valves is the subject of an on-going NRC review. The licensee has made interim commitments to disable these butterfly-type valves from opening more than 37 degrees when the reactor is not in cold shutdown. Also, with the reactor critical and above 105 psig, venting and purging through the valves is to be limited to 90 hours0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br /> per year per unit.
On a sampling of the valves at each unit, the inspector verified that spring-clips were installed on the valve actuating stems to limit valve
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opening.
During control room tours, the inspector verified that either all large diameter purge valves were closed or time was being accounted against the 90 hour0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br /> limit. The following surveillances indicated that the licensee was meeting the 90-hour per year commitments:
-- ST 9.16, Revision 10, February 26, 1980, Containment Gross Leak Rate Detection, completed December 28,1981 (total time for 1981: 78.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, Unit 2;45.1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, Unit 3);and
-- ST 9.16 Revision 12, June 25, 1982, Containment Gross Leak Rate Detection, completed August 22,1982 (total time thus far in 1982:
65.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, Unit 2; 18.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, Unit 3).
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The primary reason for purging with the reactor critical was to provide a habitable atmosphere for coolant leakage inspections in the drywell during plant startups and shutdowns.
No violations were identified.
9.
Radiation Protection During this report period, the inspector examined work in progress in both units, including the following:
a.
Health Physics (HP) controls b.
Badging c.
Protective clothing use d.
Adherence to RWP requirements e.
Surveys f.
Handling of potentially contaminated equipment and materials More than 25 people observed frisking requirements of Health Physics pro-cedures. A sampling of high radiation doors was verified to be locked as required. The inspector checked radiation levels at several locations using licensee instruments to verify accuracy of posted dose rate informa-tion.
No violations were identified.
10.
Radwaste Transportation On August 12, the inspector observed surveys of a loaded radwaste shipping vehicle. Two technicians were independently surveying the vehicle as re-quired by procedures; measured values were well within limits. The inspec-tor also checked that the procedures were being followed and the check-offs were current for the shipment's status:
-- HP0/C0-17, Revision 10, June 21, 1982, Shipment of Radioactive Material; and
-- HP0/C0-71C, Appendix A, Revision 5, June 17, 1982, Loading and Closing HN-100 Series 2 Radioactive Waste Shipping Cask.
No violations were identified, i
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11. Physical Security
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The inspector spot-checked compliance with the accepted Security Plan and implementing procedures, including: operations of the CAS and SAS, over 20 spot-checks of vehicles onsite to verify proper control, observation of protected area access control and badging procedures on each shift, in-spection of physical barriers, checks on control of vital area access and escort procedures.
NG violations were identified.
12.
In-Office Review of Monthly Operating Ricorts The inspector reviewed Peach Bottom Atomic Power Station Monthly Operating Report for July 1982, dated August 13, 1982, to verify that operation statistics had been accurately reported and that narrative summeries of the month's operating experience were contained therein.
No unacceptable conditions were identified.
l 13. Unresolved Items Unresolved items are items about which more infonnation is required to ascertain whether they are acceptable, violations, or deviations. An unresolved item is discussed in Detail 2.
14. Management Meetings 14.1 Preliminary Inspection Findings A summary of preliminary findings was provided to the Station Superintendent at the conclusion of the inspection.
During inspection, licensee management was pericdically notified of the preliminary findings by the resident inspector.
The dates in-volved, the senior licensee representative contacted, and subjects discussed were as follows:
seniorLicensee Date Subject Representative Present August 13 Routine Discussion Station Superintendent August 18 Routine Discussion Station Superintendent September 1 Routine Discussion Station Superintendent September 13 Primary Containment Station Superintendent Requirements (Detail 5.2.2)
September 17 Summary of Preliminary Station Superintendent Findings
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14.2 Attendance at Management Meetings Conducted by Region-Based Inspectors The resident inspector attended entrance and exit interviews by region-based inspectors as follows:
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Inspection Reporting i
Date Subject Report No.
Inspector August 16 Local Leak Rate 277/82-20 and S. V. Pullani
(Entrance)
Test Program 278/82-19 i
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