IR 05000277/1991003
| ML20029C251 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 03/11/1991 |
| From: | Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20029C247 | List: |
| References | |
| 50-277-91-03, 50-277-91-3, 50-278-91-03, 50-278-91-3, NUDOCS 9103270059 | |
| Download: ML20029C251 (19) | |
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION 1 Docket / Report No.
50-277/91 03 License Nos.DPR-44 50-278/91-03 DPR-56 Licensee:
Philadelphia Electric Company Peach Bottom Atomic Powc; Station P. O. Box 195 Wayne, PA 19087-0195 Facility Name:
Peach Bottom Atomic Power Station, Units 2 and 3 Dates:
January 8 February 11, 1991 Insputors:
J. J. Lyash, Senior Resident inspector L. E. Myers, Resident inspector R. J. Urban, Resident Inspector F. P. Bonnett, Operations Engineer
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Approved By:
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L. T. Doer 0ein, Chief Dafe
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Reactor Projects Section 2B Division of Reactor Projects (
Areas inspected:
The inspection included routine, on-site regular, backshift and deep backshift review of accessi-
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ble portions of Units 2 and 3. The inspectors reviewed operational safety, radiation protection, physical security, control room activities, licensee events, sarveillance testing, refueling activi-ties, engineering and technical support activities, and maintenance.
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TABLE OF CONTENTS Page EX EC UTIVE S U M M A R Y....................................... il 1.0 PLANT OPERATIONS REVIEW (60705,60710,71707)
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1.1 Operational Overview.......................
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1.2 Routine Plant Tours.................................
I 1.3 Alanual Operation of the Reactor Recirculation Pump Scoop Tube Posi-tioner..........................................
1.4 Unit 2 Core Off Load Activities.......,..............,...
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2.0 FOLLOW-UP OP PLANT EVENTS (93702, 71707, 62703, 61726)........
2.1 Unit 3 Shutdown Due to Main Transformer Cooling Loss..........
2.2 Unit 2 Shutdown Cooling Isolation During Blocking Activities.......
2.3 Unit 2 Secondary Containment Isoladon and Standby Gas Treatment System Initiation During Recirculation Pump Start..............
2.4
. Declaration of Unusual Events Due to Personnel Injuries...........
2.5 Inadvertent Actuation of the "B" Emergency Service Watec Pump.....
3.0 ENGINEERING AND TECHNICAL SUPPORT ACTIVITIES (37701)......
4.0 SURVEILLANCE TESTING OBSERVATIONS (61726,71707)
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5.0 MAINTENANCE ACTIVITY _ OBSERVATIONS (62703,92720)..........
5.1 Routinc Observation................................. 10 5.2 Licensee Self Assessment of the Instrument and Controls Program.....
I1 6.0 RADIOLOGICAL CONTROLS (71707)......................... 12
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6.1 Radiography incident
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i 6.2 Achievement of Exposure Goal for 1990
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7.0'
. PHYSICAL SECURITY (71707)
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l 8.0 PREVIOUS INSPECTION ITEM UPDATE (92702)
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9.0 M ANAGEMENT MEETINGS (71707)....................
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EXECUTIVE SUhthiARY Peach Bottom Atomic Power Station Inspection Report 9103 Plant Operations _
The inspector observed an Unit 2 licensed operator giving instructions by radio to a non-licensed plant operator to move the scoop fube positioner of the "A" reactor recirculatien pump :notor-generator set, contrary to NRC requirements. This had been long standing practiec. The licensee implemented immediate corrective actions, including procedure revisions and operator briefings, addressing this issue. A review of additional procedures and clarification of the Operations hianagement hianual were initiated by the licensee. Because immediate corrective actions were implemented and reviewed by the inspector, and additional reviews were initiated, i
no written response to this violation is requested (NV4 91-03-01, Section 1.3),
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The licensee completed core offload during the period. The sample of fuel movement and support activities observed by the inspectors were generally well performed (Section 1.4).
Unit 2 declared Unusual Events due to the transportation of a potentially contaminated injured person off site on two occasions during the period. One individual was determined not to be contaminated and the other individual had one small area of contamination, about 40 counts per minute. Licensee personnel responded well to the events and the appropriate notifications were maae (Section 2.4).
M.aintenance and SurYrillanc.c Nuclear hiaintenance Division (NhiD) personnel were observed rebuilding scram pilot solenoids, The inspector observed _the craftsman performing procedure steps out of sequence. The licensee instituted immediate action to correct the practice and readdressed with all NhiD personnel the policy regarding adherence to procedures. Because this incident was of minor safety signifi-
cance, and meets the criteria contained in the Enforcement Policy,Section V. A., no Notice of
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Violation will be issued (NON 91-03-03, Section 5.1).
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- In response to recent events and inspection finamga, licensee maintenance management has initiated a comprehensive instrument and controls program review and self assessment. This
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cffort appears to be well focused and is being well received at the working level (Section 5.2).
L Radiological Controls
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A strong station commitment to ALARA and involvement from all working groups resulted in achieving the station exposure goal for 1990 (Section 6.2).
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Assurance of Ouality in response to an identified environmental qualineation denciency in the HPCI system, a modiG-cation correcting the denciency was developed and implemented. Quality Assurance (QA)
Department involvement in reviewing the deficiency and performance of the modification was effective, and resulted in issuance of sevual Corrective Action Requests. The QA finJings indicate that while the technical content of the modification was sound, licensee personnel
involved with its implementation did not adhere to the modi 0 cation procedures and program controls (UNR 91-03-02, Section 3.0).
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DETAILS 1.0 PLANT OPERATIONS REVIEW (60705,60710,71707)
The inspector completed NRC Inspection Procedurc 71707, " Operational Safety Veri 6 cation,"
by directly observing activities and equipment, touring the facility, interviewing and discussing items with licensee personnel, independently verifying safety system status and limiting cond-itions for operation, reviewing corrective actions, and examining facility records and logs. The inspectors performed 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of deep backshift and weekend tours of the facility.
The inspector completed NRC Inspection Procedure 60705, " Preparation for Refueling." Tlis was completed by verifying on a sampling basis: 1) the technical adequacy of approved procec.-
ures,2) the adequ; cy of administrative requirements for centrol of refueling operations, and 3)
the adequacy of rdministrative requirements for establishing and monitoring control of plant conditions during refueling.
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The inspector complcted NRC !=pection Procedure 60710, " Refueling Activities " This was completed by verifying that the licensee had implemented controls for the conduct of refueling operations and for establishing and maintaining plant conditions in accordance with Technical
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Specifications (TS) and approved procedures, by directly observing Tefueling activities and equipment, and interviewing licensee personnel.
1.1 Operational Overview Unit 2 began the inspection period at full power. On January 11 the unit was shut down to enter a scheduled 68 day refueling outage. Major modifications scheduled during the outage are condenser tube replacement; emergency service water (ESW) system piping replacement; replacement of injection check valves on the high pressure coolant injection (HPCI) system, reactor core isolation cooling (RCIC) system, and core spray (CS) system; and installation of a safety grade air supply to certain containment isolation valves. Other major activities include torus coating inspection and repair, and 2B low pressure turt ine rotor replacement.
Unit 3 began the period at full power. On January 16 the unit scrammed due to a main generator lock-out and turbine trip. The " A" phase main transformer lost cooling which resulted in an actuation of the sudden pressure relay causing the generator lock-out (see Section 2,1).
The unit returned to 60% power on January 23. It remained at 60% power until January 29 due to high reactor coolant system con'luctivity caused by condenser tube leaks. After the condenser tube leaks were repaired the unit returned to full power and continued at full power for the remainder of the period.
1.2 Routine Plant Tours During the report period the inspectors toured accessible areas of the facility. Items evaluated during these tours included general housekeeping, security system performance, equipment
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condition, radiation worker practices and posting, and supervisory and management presence.
Unit 2 entered a refueling outage during the inspection period. The inspectors expanded the conduct of plant tours to include areas normally inaccessible during operation. Several drywell, torus, torus compartment, outboard main steam isolation valve room and main condenser area tours were performed. Generally, the physical condition of equipment and the radiological controls applied to activities within the areas were good. Minor weaknesses identified by the inspectors were promptly resolved by the licensee.
1.3 Manual Operation of the Reactor Recirculation Pump Scoop Tube Positioner Prior to the refueling outage shutdown on Unit 2 the inspector observed, in the control room, the Unit 2 reactor operator (RO) giving instructions by radio to a plant operator (PO) to move the scoop tube positioner of the "A" reactor recirculation pump (RCP) motor-generator (MG)
set. A change in the position of the scoop tube results in a change of RCP speed, which directly affects reactivity. The remote Bailey scoop tube positioner was inoperable at the time, requiring
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the local manual operation.
The inspector expressed concern that an unlicensed PO was manipulating controls which would directly affect teactivity. The procedure implementing the manual positioning of the scoop tube, SO.2D.7. A 2, " Recirculation MG Scoop Tube Manual Operation," Revision 0, did not specify that a licensed operator must manually adjust the scoop tube while in direct communication with
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the control room, h has been a long standing practice at Peach Bottom to use a PO for this adjustment. This practice is in violation of 10 CFR 50.54(i) and 10 CFR 55.13 which require that the licensee not permit manipulation of the controls of the facility by anyone who is not a licensed operator or licensed operator trainee. Part 55 defhes controls as the apparatus and mechanistas whose manipulation directly affects the reactivity or power level of the reactor. The inspector informed the licensee that the above constituted r.n apparent violation of 10 CFR 50.
The licensee immediately communicated to all licensea operators, through the Shift Managers, that only licensed operators would manipulate the scoop tube positioner. The licensee also initiated actions to change SO 2D.7.A 2 from a standard operating procedure to an abnormal operating (AO) procedure, AO 2D.2-3, with the same title. The new AO was approved and issued, and specified that only a licensed operator, at the positioner and in direct communication with the unit RO, may vary the position of the scoop tube. The licensee initiated a review of
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, procedures used for operation and testing of other systems directly affecting reactivity and committed to implementation of any appropriate revisions. The licensee also_ committed to revise the Operations Management Manual (OMM) to clarify existing non licensed operator responsibility guidance relative to this issue. These tasks will be complete by March 15, 1991.
Corrective actions implemented by the licensee were effective. Because adequate _ corrective actions were complete and reviewed, no written response to this violation is required. The inspector will review the changes to the OMM and the results of the licensee's additional procedure reviews during a future inspection (NV4 91-003-001).
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1.4 Urit 2 Core Off-Load Activities The Unit 2 refuel outage began on January 11, 1991; core off-load was completed on February 2; acd Local Power Range hionitor (LPRht) replacement was completed on Februhry 4. Tbc inspector observed fuel movement from the reactor pressure vessel (RPV) to the spent fuel pool (SFPj, LPRM replacement, SRhi and refuel platform surveillances, and the inspection of used fue'. No deficiencies were noted.
The inspectot revkwed procedure FH-6C, " Fuel hiovement and Core Alteration Procedure
During a Fuel Handling Outage." This procedure provides precautions, limitations and adminis-trative controls for movement of any core component during the refueling outage, it provides
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proceduralinstruction for fuel movement. The movement of all other core components (control rod blades, LPRMs, etc.) are described in their respective individual procedures.
The licensee implemented a signincant organizational change and modified the fuel movement procedures immediately prior to thir outage. Fuel movement and oversight is now provided by the Nuclear Maintenance Division (NMD), a corporate division within the Nuclear Engineering and Services Department. Traditionally, the senior reactor operator (SRO) on the refuel floor
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was a member of the Operations Department and directly responsible to the Shift Manager (SM). However, during this outage refueling limited senior operators (LSO) oversee refueling activities. The Refueling LSOs are members of NMD and have been licensed by the NRC to perform the SRO functions on the refueling floor, as outlined in the licensee's TS and
' 10 CFR 50.54(m)(2)(iv). Procedure FH 6C defines the roles and responsibilities of the Refuel LSO, however, it was noted by the inspector that FH-6C did not clearly define to whom the Refueling LSO was directly responsible. The inspector also reviewed administrative procedures dealing with refueling operations and the OMM and determined that this concern was not addressed. The licensee informed the _ inspector that administratively, the Refueling LSO is responsible to his NMD Supervisor.. While core alterations are in progress, he is functionally responsible to the SM through the Shift Supervisor (SSV). The licensee stated that they would verbally clarify this in discussion with the Refueling LSOs and formally in procedure FH 6C and the OMM.
.The licensee revised fuel handling procedures prior to the current outage to eliminate require-ments for use'of the fuel assembly tag _ board and the nuclear material accounting technician.
The licensee indicated that their evaluation, and experience during a recent Limerick refueling outage, indicated that the tag board and technician did not provide any significant benefit. The inspector observed a sample of fuel movement activities from the refueling platform and related activities in the control room and did not identify any concern or performance weaknesses.
Related surveillance testing was also observed and was found to be well coordinated and conducted. The inspector had no further questions at this time.
The inspector discussed with Reactor Engineering the results of the fuel inspections performed by General Electric (GE). It was discovered that oxide spalling was developing on the fuel loaded during the last outage (reload seven). Since this fuel has been in the core for % one
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operating cycle, the spalling was unexpected. Due to this development the scope of the fuel inspection was changed to concentrate on reload seven fuel. A total of eight fuel bundles were inspected. These included six reload seven bundles, one reload five and one reload six bundle.
GE evaluated the inspection resulta and recommended that the fuel be reused. The oxide spalling, though unexpected, would not inhibit or degrade fuel performance during the upcoming fuel cycle. GE further recommended that reinspection of the bundles during the next refueling outage be performed. The licensee plans to perform several additional inspections prior to core reload. The licensee was continuing to evaluate the results of the inspection at the close of the period.
2.0 FOLLOW-UP OF PLANT EVENTS (93702,71707,62703,61726)
During the report period the inspectors evaluated licensee staff and management response to plant events to verify that root causes were identined, appropriate corrective actions implement-ed, and required notincations made. Events occurring during the period are discussed individu.
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2.1 Unit 3 Shutdown Due to Main Transformer Cooling Loss
l At about 12:40 p.m. on January 16, 1991, the Peach Bottom Unit 3 reactor scrammed due to
problems with the main transformer. A fault developed in the normal power supply to the "A" phase main transformer oil pumps and cooling fans, tripping the associated feeder breaker. The system design included automatic transfer to a back-up power supply, but the transfer relay failed to actuate. Loss of transformer cooling resulted in lifting of the oil system relief valve.
As a precautionary measure personnel were evacuated from the adjacent Administration Build-ing. The transformer sudden pressure relay actuated causing a main generator lock out, turbine trip and reactor scram. The unit had been operating at 100% reactor power prior to the event, but power was reduced to about 6% before initiation of the automatic scram.
All safety systems functioned as designed, and no significant complications were experienced.
Three problems were encountered. Following reset of the initial scram a second scram signal was generated when the control room operator mistakenly returned the scram discharge volume
- (SDV) high level auto scram bypass switches to the normal position 3efore the SDV level had decreased below the trip setpoint. The error was immediately recognized and the scram was reset by the operator. Following the scram, the main turbine steam seal pressure regulator failed to maintain adequate steam pressure, allowing increased condenser air in leakage. The resulting increase in offgas flow rate caused a spike in the main stack radiation release rate.
Licensee analysis verined that the stack release rate peaked at a small fraction of the TS allowable vake. The licensee found that the Emergency Notification System (ENS) was not functioning when they attempted to report the event. The initial reactor scram, the subsequent SDV high level scram, loss of the ENS phone, and the main stack radiation release spike were reported to the NRC via commercial telephon _. _ _. - _ _ _. _ _ _ _ _ _ _ _. _ _ _ _ _ _ _ -
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The licensee's investigation identified that the transformer cooling system normal power supply
breaker tripped due to a fault in one of the fan motors. An intermediate breaker between the faulted fan motor and the power supply breaker did not trip as expected. The motor and the intermediate breaker were replaced. The power supply transfer relay did not actuate because of dirt build-up on the device, it was cleaned and tested satisfactorily. Similar transfer relays
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were inspected on the other transformers and found to be acceptable. The licensee is evaluating the failure of the intermediate breaker to trip, and is considering a system design change.
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The inspector was present in the control room during the scram recovery activities and observed operating shift performance. Communication and direction were generally good. Operators were knowledgeable and effective in performance of required actions.
Shift management implemented a controlled and conservative approach to the recovery. As discussed above a roain stack high radiation alarm was received following the scram, due to the increased offgas flow
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rate. The inspector noted that the shift acknowledged the alarm, and recognized it as an entry i
condition to an offnormal (ON) procedure. However, the ON for plant vent stack high radiation
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was mistakenly entered and executed rather than the correct ON addressing main stack high
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radiation. The inspector pointed this error out to the Shift Technical Advisor, who informed L
shift supervision. The operators entered the correct ON. Use of the wrong ON did not have any adverse impact on the plant recovery. This issue, and others, were identified by the licensee staff during the post-event critique for additional review and follow up. The inspector'
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2.2 Unit 2 Shutdown Cooling Isolation During Blocking Activities On January 20 at about 8:22 a.m., a shutdown cooling isolation occurreJ when power was removed from the B" residual heat removal (RHR) system logic. Power was restored to the RHR logic within minutes, the shutdown cooling valve lineup returned to normal, and cooling resumed at 8:45 a.m. During the isolation reactor coolant system (RCS) temperature increased from 91.5 to 93.5 degrees Fahrenheit.
The loss of power to the "B" RHR logic was due to use of an incorrect blocking sequence used while blockbg the power supply to the automatic depressurization system (ADS) for mainte-nance. Permit 2 90-0539 directed the plant operator to open circuit breaker switch 20D24
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-/CKTil to remove power from the "B" logic of ADS, However, this breaker also supplied power to the "B" RHR logic. The reactor operator instructed the plant operator to restore power to the RHR logic by closing the breaket, Subsequent review of the permit indicated that the
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technical review was inadequate. It was also found that the controlled drawing, E-26, " Single Line Diagram 125/250 VDC System Unit 2," used by the reviewer was unreadable in those
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sections listing the systems receiving power from the breaker.-
l The incident was discussed by the_ licensee with the personnel involved. The licensee's planned
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- long-term corrective actions include h review of drawings for legibility; a study of electrical line drawings te determine if additional expanded drawings are needed; and a review to determine if a tabulation of circuit breakers and corresponding loads could be developed to support permit
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preparation. The licensee in'tiated an Event Investigation to track the evaluation and corrective action, and will issue an LER. The inspector had no further questions.
2.3 Unit 2 Secondary Containment Isolation and Standby Gas Treatment System Initiation During Recirculation Pump Start On January 21, 1991, at about 1:20 a.m., the Unit 2 "B" channel of the reactor protection syt. tem (RPS) tripped on bus undervoltage. This caused the trip of reactor building ventilation and actuation of the "B" standby gas treatment system. All equipment responded as expected.
The RPS channel was powered from its alternate feed at the time of the trip. The breaker was reset ar.d the ventilation returned to normal. The cause of the trip was a transient undervoltage condition on the RPS channel while aligned to the alternate source, E 224 bus, which ultimately
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is fed from startup source No.2. The Unit 3 "B" recirculation pump (RCP) was loaded onto startup source No. 2, creating the momentary undervoltage condition. The RPS system is not operated in this condition frequently. The licensee is evaluating the need to add cautions to system operating procedures addressing this condition. An LER will be issued. The inspector had no further questions.
2.4 Declaration of Unusual Events Due to Personnel Injuries On January 28,1991, at about 3:00 p.m., the licensee declared an Unusual Event due to the transportation of a potentially contaminated injured person off site. The individual sustained hand injuries while operating the milling machine used for turning down the Main Turbine No.
8 shaft seal diaphragm. Due to the extent of his injury, he was transported o an off site medical facility by ambulance for treatment. A health physics technician (HPT) accompanied the injured man who was removed from the radiological controlled area without being surveyed.
The Unusual Event was terminated at 4:20 p.m. following completion of the radiological survey verifying that the individual was not contaminated. The inspector verified that appropriate notifications had been made, and had no further questions.
On February 10,1991, at about 4:37 p.m., the licensee declared an Unusual Event due to 'he transportation of a potentially contaminated injured person off site. The individmd was a contractor working in the 2C condenser who fell from a scaffolding, injuring bh eck. The individual:was wearing protective clothes and a respirator at the time of the accident. He'was transported off site to a medical facility by a medical evacuation helicopter and accompanied by
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a HPT. Due to the extent of his injuries it could not be determined prior to evacuation if the individual was contaminated. The UE was terminated following transfer of the individual to the medical facility staff. The medical facility, the helicopter, and the worker were surveyed, and tit was determined that the individual had one small area of contamination, about 40 counts per minute, which was decontaminated. No other contamination was found. The inspector had no further questions.
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2.5 Inadvertent Actuation of the "B" Emergency Service Water Pump On February 2,1991, at about 4:45 p.m., the "B" emergency service water (ESW) system pump received an auto start signal during performarve of ST-1054 752 2, "E-22 tKV Bus Undervoltage Relays Functional Test." The test was stopped and the "B" ESW pump was restored to the standby lineup. The test procedure was corrected and the test was completed satisfactorily.
All breakers on 4KV Bus E-22, which includes the "A" ESW pump breaker, had been placed in the TEST position in preparation for the fast transfer portion of the undervoltage test. The procedure instructed the operator a the E-22 switchgear to place the breakers in TEST position and to close them. The system engineer overseeing the test requested the control room operator to close the breakers which were in the TEST position from the con'aol room. When the "A" ESW pump breaker was closed, the pump logic circuit activated, did not sense pump discharge pressure within the design 15 second time delay after breaker closure, and auto started the "B" ESW pump. Closure of the "A" ESW pump breaker locally, at the switchgear, would not have caused the actuation.
The cause of this eveut was due to an inadequate test procedure. The procedure did not clearly specify that closure of the breaker was to be done locally, at the switchgear. This ST had recently been written and had not been performed previously. Corrective actions included revising this procedure and similar procedures for undervoltage testing of other buses, and discussion of the event with technical test personnel. The inspector had no further questions.
3.0 ENGINEERING AND TECHNICAL SUPPORT ACTIVITIES (37701)
In January 1991, the licensee's Procurement Engineering Group (PEG) identified as a result of their ongoing materials review program, that a shipment of General Electric (GE) Type CR120]
relays procured in 1982 and designated as "Q" had been supplied by GE as non-safety-related.
It was unclear if adequate steps to dedicate the material had been taken. Additional research indicated that the relays had been installed in only one safety-related application. The high pressure coolant injection system (HPCI) auxiliary oil pump control circuit utilizes the relay to provide control r x>m indication. No safety function was provided by the relay. The licensee subscquently concluded that the dedication of the relay was appropriate.
As part of their evaluation of the issue discussed above, the licensee performed in-field walk-downs of the relays. These walkdowns idenified that the CR120J relays were not located in the panel shown on the schematic diagram. It appears that during initial construction a panel, located in the HPCI pump room, was edded to accept the CR120J relay and a 250 VDC undervoltage (UV) relay. This new panel was not depicted on the schematic. In early 1990 new information caused the licensee to upgrade the environmental qualification of equipment located in the HPCI room. The upgrade evaluation was apparently based on a panel by panel approach, with the source of the affected panels being the schematic. Since the panel containing the CR120J and UV relay was not on the schematic, inspection and qualification of the panel i
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and components was not performed. Neither relay was environmentally qualified. The licensee concluded that the existing electrical fuse protection was inadequate, so that failure of the relays due to a harsh environment could result in the inability to start the auxiliary oil pump, making
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HPCI inoperable. This potential failure mode was reported to the NRC.
Unit 2 had just entered a refueling outage and Unit 3 was shut down due to main transformer maintenance problems at the time these problems were discovered. The Lasee implemented a modification which included replacement of the relays with qualified components, and
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modi 0 cation of the panel to support environmental qualineation.
This modification was completed before Unit 3 start-up and will be implemented on Unit 2 prior to start-up from the refueling outage.
The inspector reviewed the as-found configuration, the modification package, and the results of the licensee's investigation. The following issues were identified and addressed by the licensee:
The panel containing the CR120J and UV relay was not shown on the schematic.
- The licensee believes that the condition was created during initial construction. Ilowev-cr, the licensee indicated that schematic diagrams are intended to portray system fune-tion, not physical layout, and may not be a reliable source of layout information. The inspector questioned the accuracy of other related drawings. In response the licensee committed to review other applicable drawings such as bk)ck diagrams, and cable and raceway schedules to determine if the panel is incie ed, and to tevise them appropriate-ly.
- The licensee's EQ upgrade program for the HPCI system appears to have been based on review of the schematic to identify panels and equipment. If this approach was utilized in other EQ reviews, potentially inaccurate schematics could result in additional omis-sions from the EQ program.
This question was also raised by the licensee's QA organization and is being tracked as a QA Recommendation. The site technical staffinitiated an Engineering Work Request addressing this question.
- During implementation of the modi 6 cation, workers found one electrical lead not termi-nated on the point specified on the drawing. They moved the lead to the point shown on the drawing and proceeded with the modi 6 cation. No nonconformance report (NCR)
was issued.
If a condition not in conformance with the design documents is identified, an NCR is required to ensure evaluation of the discrepancy, and determination if the as-built condition or the drawing is correct. The licensee's QA organization also identiDed this concern and issued a corrective action request (CAR) to the Installations organization.
l The inspector also questioned if the connection diagram for the circuit was consistent
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9 with the schematic for this termination. The licensee's technical staff will evaluate this question.
The licensee's QA organization closely monitored processing and installation of this modifica-tion. In addition to the CAR and QA Recommendation described above, their review resulted in issuance of four additional CARS. These CARS indicate that while the technical content of the modification was sound, the licensee did not adhere to the modification program controls contained in their procedures during its processing. The QA Hndings appear to be compre-hensive, and should appropriately track licensee corrective actions. The licensee will submit t Licensee Event Report (LER) addressing the environmental qualineation design issue. The inspector will review the LER, the outstanding questions discussed above, and the licensee's corrective actions in response to the related CARS during a future inspection (UNR 91-03-02).
4.0 SURVEILLANCE TESTING OBSERVATIONS (61726,71707)
The inspectors observed surveillance tests to verify that testing had been properly scheduled, approved by shift supervision, control room operators were knowledgeable regarding testing in progress, approved procedures were being used, redundant systems or components were available for service as required, test instrumentation was calibrated, work wr.s performed by qualified personnel, and test acceptance criteria were met.
Daily surveillances including instrument channel checks, jet pump operability, and control rod operability were verified to be adequately performed. The following tests were observed during the inspection period with no
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S12 A-2-RPS-B1FM
" Functional Test of RPS "B" Card File," observed January 11; ST/LLRT 20.10.11-
" Main Steam Isolation Valve Local Leak Rate Test," observed January lit ST/LLRT 20.01 A 05
"As Found LLRT - Main Steam Line Drain," observed January
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12; ST/LLRT 20.0.'.14
"Drywell Air / Nitrogen Purge Valves,0 Ring Seals of AO 2 070-2505, AO 2-07B-2519, and AO 2-07B-2520," observed January 16; ST/LLRT 20.11.01
"LLRT Standby Liquid Control," observed January 16;-
S12F-7G ll8-CICO
" Calibration Check of Main Steam Line High Flow Instruments DPT /DP15 2-2-118C," coserved January 17; S13T-70 5931-CICO
" Calibration Check of Main Steam Line Tunnel Exhaust Duct High Temperature Instrument, TE ITS 5931C," observed January 23; I
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ST/LLRT 20. 3.04
'LLRT RCIC Turbine Exhaust 10" Line," observed January 29; ST 6.5 F-3
"HPCI Pump, Valve, Flow, Cooler " observed January 29; ST 3.1.2
"SRM Core Monitoring Test," observed January 31; and FH-6C.C.O.L.
" Refueling Platform Check Off List," observed January 31.
5.0 M AINTENANCE ACTIVITY OBSERVATIONS (62703,92720)
5.1 Routine Observation The inspectors reviewed administrative controls and associated documentation, and observed portions of ongoing work. Administrative controls checked included blocking permits, fire watches and ignition source controls, QA/QC involvement, rad!ological controls, plant condi-tions, TS LCOs, equipment alignment and turnover information, post-maintenance testing and reportability. Documents reviewed included maintenance procedures, maintenance request forms (MRF), item handling reports, radiation work permits (RWP), material certifications, and receipt inspection reports.
The following maintenance activities were observed:
MRP 9003752 Safety Related Gas Supply Installation (Torus /RB Vacuum Breaker
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Portion), observed January 18; MRF 891il72 Unit 2A 125 VDC Battery Cc:1 Replacement, observed January 18; MRF 9061964 Inspection and Repair of Components of HCU 18-15, observed January 23;-
MRF 9005408 Rosemount Replacements on MOD 1419C, observed January 23;
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MRF 9060610 MSIV Inboard Air Solenoid Test, observed January 25; MRF 9100570 Swap of the East and West Fuel Prep Machines, observed January
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MRP 9061975 CRD Scram Pilot Soleneid Valve Rebuild, obse.ed January 31; MRF 9061973 CRD Scram Pilot Solenoid Valve Rek.. id, observed January 31; MRF 9005931 Core Spray "B" Check Valve Replacement, observed January 31;
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MRF 9001498 ESW Piping Replacement, HPCI, observed January 31; and MRF 9001499 ESW Piping Replacement, RCIC, observed January 31.
No concerns, empt as noted below, were identined by the inspector.
The Nuclear 1 ~ Jnance Division (NMD) was responsible for scram pilot solenoid rebuild activities during this outage. During observation of these activities the inspector noted that the craftsman had performed the steps of procedure M-003-008, " Hydraulic Control Unit Scram Pilot Valve Resi!!cnt Parts Replacement," out of sequence. The procedure calls for an initial solenoid coil resistance test at the hydraulic control unit (HCU), removal of the solenoid assembly, transport to the rebuild area and rebuild, return to the HCU and a final resistance check prior to termination. The normal maintenance practice, unless otherwise stated in the procedure, is to perform the steps in the sequence specified in the procedu*c. Prior to the start of work,' a decision had been made to replace all solenoid coils during the rebuild. The practice in the field was to perform resistance tests on the replacement coils in lots, prior to installation in the valve assembly and transport to the HCU. The procedure step documenting the final i
resistance was signed-off based on the preassembly test described above. Both the craft and the job supervisor at the work location viewed this as an acceptable practice and consistent with the procedural requirements.
The inspector discussed the concern with the NMD cognizant engineer, and a Peach Bottom senior maintenance engineer. They both indicated that the desired sequence was described in the procedure, and that performance of steps out of sequence-in this case was not permitted, immediate action was taken to correct the practice at the wors location. About 25 valves had been rebuilt prior to correcting the practice. The licensee performed a final resistance test on those solenoid coils which had not been termmated. h. preparation for system return to service, thorough post-maintenance test is required for all valves which would identify any problems with the remaining coils. Therefore, the licensee ccncluded that retest of the installed and terminated coi's was not needed. While this incident was not safety significant, the inspector expressed
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concern regarding NMD craft and supervision adherence to procedures. On February 8,1991, the inspector met with the Plant Manager and NMD management to discuss the event. NMD management stated that the policy regarding odherence to procedures had been readdressed with
- all NMD personnel stressing the need for careful review and adherence to the procedures.
Following the meeting NMD management reinforced this position with all supervisors. Subse-
_ quent observation of the rebuild activities by the inspector veri 0ed proper procedure adherence.
This violation is not being cited because the criteria specified : 1 Section V. A, of the Enforce-ment Policy were satisfied (NON 91-03-03). The i.. sto, had no further questions and considered this item closed.
5.2 Licensee Self-Assessment of the Instrument and Controls Program i
During inspection report no. 90-22 the inspectors identified that the licensee had not established adequate procedures defining implementation of the measuring and test equipment (M&TE)
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control program. This issue was the subject of a Notice of Violation (NV4 90 22-03). Addi-i tionally, poor performance of I&C activities resulted in several recent engineered safety feature actuations. In response to these issues licensee management elected to expand the scope of their corrective action to include a systematic assessment of I&C responsibilities and activities. A senior engineer with I&C, operations, and quality assurance experience was assigned to lead the effort.
The assessment methodology includes identification of 1&C responsibilities, and review of the Quality Assurance Plan (QAP) to identify the processes and activities requiring establishment of administrative program procedures and implementing procedures. These responsibilities and QAP requirements are being evaluated against existing procedures, beginning with the top tier Nuclear Group Administrative and Peach llottom Administrative Procedures, and ending with the detailed implementing procedures used to conduct work in the field. Discrepancies between the requirements, the existing procedures, and work practices are being identined for additional action. A data base has been established to capture and track the issues. The licensee plans to
.plete the assessment by the end of February 1991, and to develop an action plan addressing corrective actions, Organization and staffing changes in the Maintenance Engineering Group have been made to ensure that resources are available for implementation of the action plan.
The licensee effort appears well focused and is progressing.
The licensee also briefed I&C technicians and supervision on the reasons for and conduct of the assessment. Significant input is being received from the I&C staff. In discussions with 1&C tecnnicians, the inspector noted that the management effort to assess the program, particularly to solicit and act on technician input, was received ;x>sitively and with enthusiasm by the techni-clans. The inspector will continue to monitor licensee efforts in this area as part of the follow-up to NV4 90 22-03.
6.0 RADIOLOGICAL CONTROLS (71707)
During the report period, the inspector examined work in progress in both units and included health physics procedures and controls, ALARA implementation, dosimetry and badging, protective clothing use, adherence to RWP requirements, radiation surveys, radiation protection instrument use, and handling of potentially contaminated equipment and materials.
The inspector observed individu ds frisking in accordance with HP procedures. A sampling of high radiation area doors was veriGed to be locked as required. Compliance with RWP require-ments was verined during each tour. RWP line entries were reviewed to verify that personnel had provided the required information and people working in RWP areas were observed to be meeting the applicable requirements. No unacceptable conditions were identified.
6.1 Radiography Incident On January 15,199t, at about 6:00 p.m., vendor radiographers inadequately posted and barricaded a radiation area adjacent to the Site Management Office (SMO) building located
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outside of the protected area. The health physics technician (HPT) assigned to oversee the activity surveyed the area while the radiographs were being exposed to verify the adequacy of the posting by the radiographers. The HPT determined that the posting was incorrect, stopped the work, and informed supervision. The exposure rate at the posting was 50 milliroentgen per hour (mR/h). The health physics supervisor required the radiographers to re-post and barricade the area at the 2 mR/h line before the activity could be resumed. Before the first exposure the HPT had conservatively relocated all personnel in ;he SMO as a precaution. During the first exposure no unauthorized individual entered the area where the exposure was greater than 2 mRih The following day all radiography was terminated until the incident could be evaluated.
Radiography at the site is controlled by Administrative Procedure A 115 " Radiography Proce-dure," Revision 0. A-115 requires the posting of radiation areas where the estimated dose rate is greater than or equal to 2 mR/h when the radiography source is u, shielded. The 2 mR/h rate is consistent with the site posting procedure. However, the radiographer's license provides that posting of a radiation area is required where the estimated dose to an individual is greater than or equal to 2 mrem. The radiographer estimates the potential exposure by calculating the source exposure rate multiplied by shielding factors, multiplied by the time the source is unshielded.
The radiographers had placed their posting based upon that estimate rather than the more conservative site posting requirements. Radiography activities resumed following clarification by the licensee. The licensee is evaluating the need to permanently clarify A 115 to prevent recurrence. The inspector had no further questions.
6.2 Achievement of Exposure Goal for 1990 The station exposure goal for 1990 was set originally at 600 man Rem. Early in the year the Station ALARA Committee (SAC) re-evaluated the goal and decided that a more challenging goal could be established. Each work group re-evaluated doses and methods to reduce the dose, and submitted new goals to the SAC. The new station goal was set at 500 man Rem for the i
_ year. The goals were tracked carefully by each group and the radiolog' cal engineering section provided monthly charts of progress towards the goal that were posteo throughout the plant during the year. The actual station exposure (dose) a;hieved was 378.6 man Rem.
7.0.
PHYSICAL SECURITY (71707)
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- The inspector monitored security activities for compliance with the accepted Security Plan and associated implementing procedures, including: security staffing, operations of the CAS and SAS, checks of vehicles to verify proper control, observation _ of protected area access control and badging procedures on each shift, inspection of protected and vital area barriers, checks on control of vital area access, escort procedures, checks of detection and assessment aids, and
- compensatory measures. No inadequacies were identified.
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8.0 PREVIOUS INSPECTION ITEM UPDATE (92702)
(Closed) UNR 89-26-04, M AT Discrepangrs _Concerning Cooling WacLSypply_fntAIC Spray Motor Oil Coolers.
During inspection 89-26 the inspector identified several concerns with the licensee's review and approval of modincation acceptance test (MAT) results for a n odification to the core spray motor oil coolers. The concerns are listed below.
- The Plant Operations Review Committee (PORC) accepted the M AT results even though collected test data did not meet the specined acceptance criteria. This acceptance was based on the results of informal, qualitative testing that demonstrated adequate cooler functioning. Concerns related to adequate functioning of instrumentation installed to pro-vide for ongoing performance monitoring were not resolved.
- The MAT results analysis was not documented in a MAT Report and presented to the PORC as specified in licensee procedures, o
Surveillance test procedures were revised following design of the modi 0 cation, but were not revised to reflect new information obtained during the testing process which impacted their validity. Licensee program procedures did not contain provisions to ensure that this final evaluation would take place.
In response to these concerns the licensee revised procedures A-89, " Modification Acceptance Tests," and A-14 " Plant Modifications," to clarify the process and responsibilities associated with approval of MAT results. The inspector reviewed the procedure changes, a sample of MAT Reports for recently completed modifications, and the PORC meeting minutes document-ing presentation of the MAT Reports. It appears that this weakness hr.s been resolved procedur-ally and in practice. The licensee also revised A-14 to ense "at controlled documents are reviewed following installation and testing to determine if the dormation obtained during the process would require further revision of the documents.
The licensee also performed a review of all Technical Group sponsored modifications imple-
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mented during the past Unit 3 refueling outage to assess the broader impact of the identified weaknesses. While similar documentation weaknesses were found, no significant technical deficiencies or inadequate procedure revisions were identified. The inspector had no further questions.
(Closed) UNR 89 27-001, IRkaf3 Procedure for Steadv State Power Operations or Planned f
I oad Changes (Commont The subject concern was that there was no specific procedural guidance for operating the plant at steady-state power or for performing planned load changes. The applicable sections from GP-2, " Normal Plant Startup," and GP-3, " Normal Plant Shutdown," were used by the operators
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i for load changes. The inspector reviewed procedure GP-5, " Power Operations," which now provides procedural guidance for making power changes at les els above the rod worth minimizer (RWM) Low Power Alarm Setpoint not associated with startup or shutdown. The inspector concluded that this procedure satisned the action requirements necessary to close this item.
(Closed) UNR 89-27-002, Licensed Otrator Training Material Contains Cumbersome _imd Difficult System Oncrations Descriotions (Commont This item identified that the format and structure of the training lesson plans was not adequate.
The lesson plan format provided the main body of " testable" material in a Subject Outline.
Support Information, which was not testable, was listed in the right hand margin. The Support Information column, however, contained much of the information necessary to cover the
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objectives of the written examination. The inspector discussed with the !!censee's training
department representative the action steps implemented to correct this item. The inspector also reviewed the licensee's commitment tracking documents and reviewed a sample of the upgraded i
lesson plans. The upgraded lesson plans were utilized in the preparation of the NRC Initial License Examination that was given in September 1990, and there were no discrepancies noted.
The inspector determined that actions taken by the licensee were adequate.
9.0 M ANAGEMENT MEETINGS (71707)
The Resident inspectors provided a verbal summary of preliminary findings to the Peach Bottom Station Plant Manager at the conclusion of the inspection, During the inspection, the Resident inspectors verbally notined licensee management concerning preliminary Gndings. No written inspection material was provided to the licensee during the inspection. This report does not contain proprietary information. The inspectors also attended the entrance or exit interview for the following inspections during the report period:'
Dates Subitcl ikport No.
Luegim 2/1/91 Fire Protection Program 91-07 Paolino 2/8/91 Radiological Control Program 91-06 Chawaga 2/5/91 Fitness for Duty Program 91-05 Albert
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