IR 05000277/1987024
| ML20147C760 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 01/08/1988 |
| From: | Linville J, Williams J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20147C734 | List: |
| References | |
| 50-277-87-24, 50-278-84-24, NUDOCS 8801190336 | |
| Download: ML20147C760 (41) | |
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en U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket / Report No. 50-277/87-24 License No. DPR-44 50-278/87-24 DPR-56 Licensee: Philadelphia Electric Company 2301 Market Street Philadelphia, Pennsylvania 19101 Facility Name: Peach Bottom Atomic Power Station Units 2 and 3 Inspection At: Delta, Pennsylvania Dates: October 17 - November 27, 1987 Inspectors: T. P. Johnson, Senior Resident Inspector R. J. Urban, Resident Inspector L. E. Myers, Resident Inspector J. H. Williams, Project Engineer
Reviewed By: .
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J H. Williamst Project Engineer ' / date Approved By:
JgEiM11e, Chief
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/ date edtorProjectsSec n 2A, Ivision of Reactor rojects
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Summary Areas Inspected: Routine, on-site regula= and backshift resident inspection
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(242 hours0.0028 days <br />0.0672 hours <br />4.001323e-4 weeks <br />9.2081e-5 months <br /> Unit 2; 244 hours0.00282 days <br />0.0678 hours <br />4.034392e-4 weeks <br />9.2842e-5 months <br /> Unit 3) of accessible portions of Unit 2 and 3,
operational safety, rartiation protection, physical security, control room i
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activities, licensee events, surveillance testing, refueling and outage i activities, maintenance, and outstanding item Results: Open issues remain associated with a 1986 Unit 2 heatup (section l 3.4). Good involvement in assuring quality by shift and plant management were '
demonstrated (section 4.1.2 and 4.1.12). An ESF actuation on Unit 3 was caused !
by poor worker performance (section 4.2.1). Unit 3 core offload activities I (see section 4.4.4) and plant conditiens (see section 4.4.2) were adequately controlled. Weaknesses were noted in the area of instrument valve terminology
and procedural references to valves (see section 4.5). Maintenance Request I Form (MRF) backlog is being addressed (see section 8.2). A weakness in the j security protected area was identified (see section 10.6). An apparent i violation of radiation survey and posting requirements was identified (see section 9.3). An apparent violation of the QA Plan and document control i was identified (see section 4.8).
8801190336 880111 PDR ADOCK 050 g 7 i
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h TABLE OF CONTENTS Eag 1.0 Persons Contacted........................................... 1 2.0 Facility and Unit Status.................................... 1 3.0 Previous Inspection Item Update............................. 1 4.0 Operations Review........................................... 4 StationTours..........................................4 4.2 Followup on Events..................................... 8 4.3 Logs and Records...................................... 10
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4.4 Ref ueling Outage Activi ties. . . . . . . . . . . . . . . . . . . . . . . . . . . 11 4.5 Control of Instrument Valves.......................... 16 4.6 N R B M e e t i n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 4.7 Operations Management and Shift Rotation Change....... 18 4.8 Emergency Cooling Water System Damage................. 18 l
l E . 0 Em e rg e n cy P l a n n i n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
I 6.0 Review of Licensee Event Reports. . . . . . . . . . . . . . . . . . . . . . . . . . . 22 1 7.0 Surveillance Testing....................................... 24 Maintenance................................................ 24
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9.0 Radiological Controls...................................... 26 I 10. 0 P hy s i c a l S e c u r i ty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 4
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11. 0 A s s u ra n c e o f Qua l i ty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 i
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- 12.0 In-Of fice Review of Special Reports. . . . . . . . . . . . . . . . . . . . . . . . 36 '
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13.0 Management Meetings........................................ 37 i
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DETAILS 1.0 Persons Contacted
- J. B. Cotton, Superintendent, Operations
"A. B. Donell, QA Site Supervisor
- M. J. McCormick, Perspective Plant Manager F. W. Polaski, Assistant Superintendent, Operations
- G. R. Rainey, Superintendent, Services
- D. M. Smith, Manager, Peach Bottom Atomic Power Station J. E. Winzenried, Staff Engineer Other licensee and contractor employees were also contacte *Present at exit interview on site and for summation of preliminary finding .0 Facility and Unit Status 2.1 Unit 2 The unit remained in cold shutdown during the inspection perio Refueling outage recovery efforts and reactor vessel hydrostatic testing preparations continued during the perio .2 Unit 3 The unit remained in a cold condition during the per'. The pipe replacement outage which begin on October 1, 1987 continued. By the end of the inspection perihd, the core offload was complete and pipe decontamination activities were underwa .0 Previous Inspection Item Update 3.1 (Closed) Unresolved Item (277/86-13-02; 278/86-14-02). Review the station lubrication program. This item was discussed in Inspection Report 277/87-07 and 278/87-07. It remained open because the lubrication program conducted by operations was not being fully implemented. Lubrication round sheets were at times not issued, completed, or adequately reviewed to correct problems that were found. The inspector discussed the lubrication program with the licensee representative responsible for overseeing the program. The licensee representative was knowledgeable of the program and appeared to be adequately involved in reviewing and assessing completed round sheets. The inspector reviewed data on lube program implementation. It.was apparant that during 1987, the program improved such that a high percentage of the round sheets were completed and reviewe Licensee management appears to be committed to having an effective lubrication program as part
' of their overall preventive maintenance program. The inspector had no further questions at this time. This item is resolved and closed, t . .
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3.2 (Closed)UnresolvedItem(277/87-15-01). ECW pump and piping support damage from water hamme During review of the unresolved item an apparent violation was found (see section 4.8). This unresolved item is administrative 1y closed but will be followed as part of the violatio .3 (0 pen) Unresolved Item (277/87-22-01; 278/87-22-01). Temporary clearance of blocking permits. See section 6.2.1 of this repor .4 (0 pen) Inspector Follow Item (277/86-16-01). Inadvertent reactor coolant temperature rise to 245 degrees F while Unit 2 was in cold )
shutdown on August 17, 1986. The inspector reviewed the corrective actions associated with this event. The root cause of the event as determined by the licensee was inadequate planning, l lack of job oversight and supervision, and inad.quate procedures !
and trainin , j As part of the corrective actions, extensive revisions to GP-12, l
"Core Cooling Procedure' were mad However, the revision does !
not adequately address stratification while operating in the i natural circulatjon mode. Raising the reactor vessel water level l to a point above;the bottom of the predryers on the steam l separator provides a natural circulation path between the inside !
and outside of the shroud. The separator predryers are located
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slightly higher tha.n the lowest fluid connection between the inside and outsiderof the shroud. The Unit 2 event of August 17, 1986, demonstrated that the minimum reactor coolant level required for natural circulation (+50 inches) was not adequate to prevent stratification and possible boiling. A new procedure, GP-12.1,
"Procedure to Remove Shutdown Cooling from Service," was written for reactor cooling with RHR shutdown cooling removed from service when it is required to remove decay heat. Cooling systems available for decay heat removal before taking RHR shutdown cooling out-of-service are included in the new procedure. Methods of monitoring reactor coolant temperature and pressure are listed, but not in order of priority. Also, GP-12 allows RHR shutdown cooling to be removed from service. It is not clear which procedure would be used in some situations or when one would go from GP-12 to GP-12.1. The requirement to cool down to 120 degrees F before removing shutdown cooling is in GP-12.1 but not in GP-1 When the shutdown cooling valves (MO-17 and 18) were blocked on August 17, 1986, the coolant temperature was 165 degrec F. This higher temperature allows less margin for heating up above 212 degrees F. ST-9.12 has been revised to include recording pressure and temperature while in the natural circulation mode. ST-9.12 previously required logging temperature and pressure when forced circulation was present. Logging this data was ceased when forced circulation stopped. Had temperature and pressure been routinely monitored and logged, the operator may
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The inspector could find no indication that corrective actions were taken to solve the problems of poor planning, inadequate job oversight and lack of communications between the maintenance i workers and operators. Unusual operations must be carefully evaluated and planned. Problems and delays encountered while
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working on M0-17 were not communicated to the control room. These l were important contributors to the heat up event that were 1 identified in the ISEG Event Report. Events in the past have indicated these problems (LER 2-86-21 and LER 2-81-31). In addition NSAC-88, INPO SOER dated April 28, 1982 and NRC Information Circular 81-11 discuss the importance of proper planning and execution of jobs related to shutdown coolin l l
Corrective actions associated with training were incomplete. The l event was discussed in licensed operator requalification training l (LOR 86-06D). However, recommendations associated with heat l transfer princi'ples using vessel metal surface temperature to monitor coolant temperature, natural circulation, and energy balance considerations, were not addresse An operator concern that maintenance workers could not get shutdown i cooling blocked by the operating shift and returned the next shift l for blocking the system appears unfounde The inspector discussed the event with operators and engineers to determine if operators had l
refused to take RHR. shutdown cooling out-of-service. While there I appears to have been some reluctance, the engineers convinced the operators that GP-12 covered the situatio l
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Because of issues associated with job planning, job management, l Gp-12, and training, this item remains ope .5 (Closed) Unresolved Item (277/86-12-19 and 278/86-13-19).
Administrative Centrol of Routine Tests (RTs). No administrative (A) procedure existed for the writing, review, and approval of RTs. The licensee responded to this concern in a letter dated October 20, 1986. The licensee committed to incorporating safety related RTs into surveillance test procedures (STs). The inspector reviewed the current listing of RTs and noted that safety related RTs have been deleted and incorporated into ST In addition, as a CTE action plan task, the licensee is rewriting the A procedure for procedures (A-1) to incorporate the requirements for RTs. This procedures upg'rade project will be reviewed in a future inspection. The unresolved item is resolved and closed.
! 3,6 (Closed) Unresolved Hem (2///87-09-03, 278/87-09-03). Control room upgrade modification (MOD) #1729. MOD #1729 was changing a vital area barrie There was no documented security sign off on i
the modification checklist and site security was unaware of the changes. The licensee stopped work on this modification that
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affects plant securit The licensee's review of this deficiency determined that poor communications between corporate and site security was the root cause. Discussions with the site modification coordinator were held. The licensee representative stated that the safety evaluations for any security related modifications will have a security signoff on the PORC sheet (per procedure A-4). The inspector discussed this with the licensee and had no further questions. This item is resolved and close .7 (0 pen) Unresolved Item (277/87-07-02, 278/87-07-02). Followup of Health Physics Deficiency Reports. This item remains open (see section 9.3).
3.8 (0 pen) Inspector Follow Item (277/86-12-16; 278/86-13-16).
Procedures for ALARA Goals. This item remains open (see section 9.3).
4.0 Operations Review 4.1 Station Tours The inspector observed plant activities during daily facility tours. Most acces:;ible areas of the station were inspecte . Control Room and facility shift staffiy was frequently checked for compliance with 10 CFR 50.54 and Technical Specifications. The presence of a senior licensed operator and a Nuclear Operations Monitoring Team men;ber in the control room was /erified frequently. Operator
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attentiveness to plant operations was determined to be 1 adequat .1,2 The inspector frequently observed that selected control room instrumentation and recorder traces confirmed that !
instruments were operable and indicated values were within Technical Specification requirements and normal operating limit Engineered safety features system switch positioning and valve lineups were verified daily based on control room indicators and plant observation j The inspector was in the control room the morning of November 25, 1987, for a routine tour. At approximately :
8:45 a.m., the inspector noted that the shift was '
pursuing a problem with Unit 3 indicated reactor water level. Level instrument LI-86 and level recorder LR-96 I indicated a decrease from +210" to +170". (The core was l offloaded.) An operator was sent to the fuel floor and I
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level was verified to be at the vessel flange (approximately l
) +210"). A call was made to the fuel floor maintenance i
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foreman asking if any work was being done. A contractor
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crew was removing interferences and cleaning up the reactor cavity after the decontamination evolution. This crew apparently removed the level instrument reference leg (head chamber) and caused a false indicated water leve Miscommunications between the fuel floor foreman and the contractors contributed to this event. The licensee performed an investigatio The inspector noted that the cont'rol room operators were '
quick to note the level decrease, especially since no
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accompanying alarms were receive In addition, both
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shift and plant management were cognizant of the '
problem, and the investigation and followup were goo Licensee corrective actions included: replacement of the reference leg, recalibration of the instrument, stationing an operator on the fuel floor to monitor actual level, and re-instruction of the fuel floor
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worker The inspector questioned personnel involved :
and reviewed the licensee's investigation. The {
inspector discussed the event with plant management and i had no.further questions at this time, j y
i No violations were identified !
l 4. Selectedncontrol room off-normal alarms (annunciators) !
were discussed with control room operators and shift !
supervision to assure they were knowledgeable of alarm status, plant conditions, and that corrective action, if ;
required, was being taken. In addition, the applicable alarm cards were checked for accuracy. The operators were knowledgeable of alarm status and plant condition .1.4 The inspector checked for fluid leaks by observing sump status, alarms, and pump-out rates; and discussed i reactor coolant system leakage with licensee personne ;
4.1.5 Shift relief and turnover activities were monitored l
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daily, including periodic backshift observations, to ensure compliance with administrative procedures and
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regulatory guidance. No inadequacies were identifie .1.6 The inspector observed the main stack and both reactor building ventilation stack radiation monitors and >
recorders, and periodically reviewed traces from backshift periods to verify that radioactive gas release rates were within limits and that unplanned releases had
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not occurred. No inadequacies were identifie l 4.1.7 The inspector observed control room indications of fire '
detection instrumentation and fire suppression systems, monitored use of fire watches and ignition source
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controls, checked a sampling of fire barriers for integrity, and observed fire-fighting equipment stations. No inadequacies were identifie . The inspector observed overall facility housekeeping conditions, including control of combustibles, loose trash and debris. Cleanup was checked during and after maintenanc Plant housekeeping was generally acceptable, !
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4. The inspector observed the nuclear instrumentation subsystems (source range, intermediate range and power ,
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range monitors) and the reactor protection system to
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4.1.10 The inspector frequently verified that the required ;
off site electrical power startup sources and emergency '
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on site diesel generators were operabl l J
' 4.1.11 The inspector monitored the frequency of in plant and '
contro] room tours by plant and corporate managemen The toqrs were generally adequat i 4.1.12 The inspector verified on a weekly basis, the .
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operabiltty of selected safety related equipment and '
systems by in plant checks of valve positioning, control ;
of locked valves, power supply availability, operating 3 procedures, plant drawings, instrumentatio,n and breaker 4 positioning. Selected major components were visually inspected for leakage, proper lubrication, cooling water supply, operating air supply, and general condition No significant piping vibration was detected. The '
inspector reviewed selected blocking permits (tagouts) L for conformance with licensee procedure l During a routine tour on November 4,1987, the inspector noted that the Unit 2 B fuel pool cooling heat exchanger tube side relief valve line was leaking into the 165 foot level reactor building floor drain. A floor operator nearby stated that the control room had been informe In addition, the HP control point on this level had also noted the condition and had taken a j
survey of the leak area. No contamination outside of
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The licensee isolated the heat exchanger to stop the leak. The A heat exchanger was out of service due to a !
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known tube leak and relief valys leak. The C heat l
2 exchanger was also out of service due to suspected tube leaks. The Unit 2 spent fuel pool was without any l
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normal method of forced cooling. The licensee monitored fuel pool heatup rate and determined it to be about 10 degrees F in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> perio The inspector attended the 8:30 a.m. morning meeting in I the control room on November 5, 1987. At this meeting i the status of Unit 2 fuel pool cooling system was '
discusse Plant management was present at the meeting }
monitoring and directing activities in this are Plant !
management's direction was to assure a course of action '
that prioritized the repair activities for the three l heat exchangers, gave contingencies if the repair was !
delayed, ensured that procedures were available for alternatives, and verified that hourly temperature readings were taken. The inspector determined that this i oversight was effectiv l l
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The inspector independently verified that procedures were available by reviewing S.3.7.1.B, "Loss of Fuel Pool Cooling," Revision 2 and S.3.2.C.7, "Shutdown Cocling Mode - Fuel Pool Cooling Swapover," Revision The inspector also examined the fuel pool for possible bubbling and none was found. The operator performing ,
the hourly temperature reading was also questione l Control room operators were cognizant of the fuel pool l status, and of the RHR to fuel pool cooling backu l The inspector reviewed the Technical Specifications (TS)
and UFSAR. TS do not address the fuel pool cooling system. UFSAR section 10.5 states that the maximum fuel pool temperature is 150 degrees F. Adherence to this limit is assured by the licensee's procedure The B fuel pool heat exchanger relief valve was repaired and returned to service at 9:25 p.m. November 5, 198 The C heat exchanger was also made available for backu The A heat exchanger remained out of service for repairs. The fuel pool reached a maximum temperature of 102 degrees The inspector reviewed the auxiliary plant operator's (APO) shift turnover checklists for the period November 3 - 6, 1987. The status of fuel pool cooling equipment was not thoroughly documented on these checklists, nor is there any required control room supervisory revie The inspector questioned plant management on this issu The licensee stated that this is a recurring problem that has been recently noted during the last INPO evaluation. The licensee is in the process of stationing a non-licensed shift supervisor "Floor
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This issue and the effectiveness of the Floor Foreman !
will be reviewed during a future inspection, l No violations were note I i
4.1.13 The inspectnrs performed backshift and weekend tours of l l the facility on the following days- 1 i
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Thursday, October 22, 1987; 5:30 a.m. - 6:00 a.m.
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Friday, October 23, 1987; 3:55 a.m. - 6:00 Friday, October 30, 1987; 12:00 a.m. - 6:00 l
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Saturday, October 31, 1987; 8:00 a.m. - 1:00 j
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Sunday, November 22, 1987; 6:00 a.m. - 12:30 l 4.1.14 The in}pectors verified that the licensee's use of overtinte was consistent with regulatory requirements and 3 administrative procedure A-40, "Working Hour 1 Restrictions." .
4.1.15 The Unit d drywell was inspected October 22, 198 No :
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abnormalities were note !
4.2 Followup On Events.0ccurring During the Inspection ;
4. Unit 3 Spurious Triple Low Reactor Water Level Signal At 10:42 a.m, on October 26, 1987, Unit 3 received a spurious triple low reactor water level signa l Operations personnel (shift blockers) wrote blocking l permit 32BM878032 to enable replacement of Yarway level l
indicating switch LIS-588. After applying the block, maintenance personnel noticed that the instrument was still indicating water level. A craft worker attempted to drain LIS-58B by opening the low side instrument drain valve (IDV). However, by operating a valve beyond the boundary of the block, the entire rack's variable l 1eg header was inadvertently drained. As a result, the following occurred at Unit 3: Group I isolation; 3D HPSW pump trip, ADS nine minute bypass timer start; and initiation signals for HPCI; RCIC; CS; LPCI; and DG Due to current conditions at Unit 3, the only resulting i action was the 3D HPSW pump trip; other equipment was .
isolated. Control room operators manually tripped the l RHR pump providing shutdown cooling (SDC) to Unit 3, {
This is a precautionary practice in case there is a leak l
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in the RHR heat exchanger, which would create a leakage path to the environment. The only action that occurred at Unit 2 was a trip of the 2B RHR pump. An interlock exists between the units such that if one unit receives a LOCA signal (triple low reactor water level signal),
the other unit's running RHR pumps trip. Therefore, Unit 2 also experienced a loss of SD The icensee restored SDC to both units at 10:45 a.m., ,
made an ENS phone call at 11:40 a.m., and made a i followup ENS phone call at 2:36 p.m. once the cause of the event was determined. A suspected licensee event report (SLER) was prepared by the shift technical ;
advisor. The preliminary conclusion of the SLER was ,
that the safety significance was minimal due to the current condition of Unit 3. Licensee corrective actions consisted of closing the IDV, stopping work untti the investigation was complete, and refilling the variable leg to restore normal water level indicatio Presently, the licensee is preparing an LER for this occurrenc The inspector spoke with operations personnel, and reviewed the SLER, electrical schematics, P& ids, and the
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blocking permit. The inspector determined that the root cause of the event was the craft worker opening the IDV.
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which is stU,dard practice. The IDV could then have -
been opened without incident. Apparently, some ;
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confusion oxists among plant personnel concerning the r.omenclature of various instrument valves. See section
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4.5 of this report for specific details, >
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No violations were noted and the LER will be reviewed in a future inspection repor !
4.2.2 Losses of Ernergency Assessment Capability
The licensea made a'n ENS call on November 6, 1987, at 1:35 p.m. to report a loss of emergency assessment !
4 capability. At 10:56 a.m. during weekly testing of the l Unit 1 diesel generator (DG), the off site power supply (3305 line) to the Technical Support Center (TSC) and >
Emergency Operations Facility (EOF) tripped. Power was returned to the line at 11:32 a.m.; however, the supply l breaker was not reclosed due to troubleshooting activities. The operating shift manually restarted the
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i Unit 1 DG to supply power to the TSC and EOF, However, ,
problems with the DG output breaker prevented the DG i
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re-energized to the TSC/ EOF loads at 1:25 p.m. The licensee investigated these problems with the Unit 1 DG syste It was determined that the "C" phase of the DG output breaker had shorted. Repairs were performed on the DG breake ,.
The inspector reviewed the related test and operating procedures: ST/EP-118, "Unit 1 Diesel Generator Full Load Test," Revision 5 and S.19.2, "Manual Start and Shutdown of the Unit 2/3 TSC Diesel Generator," Revision 2. In addition, the inspector discussed this event with licensee engineers and operator The licensee made an additional ENS call on November 23, 1987, at 9:03 a.m. to report a second loss of emergency asses'sment capability. At 7:27 a.m. the off site power ,
supply-(3305 line) to the TSC and EOF tripped. Power '
was returned to the line at 8:01 a.m. The operating ;
shift was unable to start the Unit I diesel generator (DG) to supply power to the TSC and EOF because the DG
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l was out of service due to modification activities associated with the construction of the plant simulator facility in the Unit I administrative buildin ,
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The inspector reviewed the control room logs and discussed this second event with licensee operators and ;
engineers. The inspector questioned the licensee with '
respect to operability requirements for the TSC and EOF DG. The licensee stated that the DG is tested weekly ,
(ST/EP-118), but was unaware of any operability I requirement The inspector reviewed NUREG 0654, l
"Criteria for Preparation and Evaluation of Radiological l Emergency Response Plans and Preparedness in Support of Nuclear Power Plants," and NUREG-0696, "Functional Criteria for Emergency Response Facilities." The TSC and EOF are required to be available at least 99% of the time while above the cold shutdown conditio No violations were identified I 4.3 Logs and Records !
I The inspector reviewed logs and records for accuracy, completeness, abnormal conditions, significant operating changes and trends, required entries, correct equipment and lock-out !
status, jumper log validity, conformance with Limiting Conditions for Operations, and proper reporting. The following logs and l records were reviewed: Shift Supervision Log, Unit 2 Reactor Operator's Log, Unit 3 Reactor Operator's Log, Control Operator log Book, Nuclear Operations Monitoring Team Log, STA Log Book,
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Night Orders, Radiation Work Permits, Locked Valve Log, Maintenance Request Forms, Temporary Circuit Modification Log, and Ignition Source Control Checklists. Control Room logs were ccapared with Administrative Procedure A-7, Shift Operation Frequent initialing of entries by licensed operators, shift supervision, and licensee on-site management constituted evidence of licensee review. No unacceptable conditions were identifie .4 Refueling Outage Activities 4. Unit 3 Refueling and Pipe Replacement Outage Preparations On October 1, 1987, Unit 3 began a scheduled ten month refueling outage. Major work items include replacement of reactnr recirculation and associated piping, refueling,10 CFR 50 Appendix R modifications,10 CFR 50 Appendix J testing, turbine maintenance, plant modifications, and other maintenance and testin The lisensee has organized the management of the Unit 3 refueling and pipe replacement outage similar to the 1 Unit 2 pipe replacement outage (1984-85) with some enhancements. The management of pipe replacement is the responsib.ility of an Engineering and Research Project Engineerr Groups reporting to the Project Engineer include a construction division project engineer I (including the contractor for pipe removal and installation), a power plant design project engineer, a service project engineer (decontamination services), an electrical project engineer and a nuclear operations (plant) interface engineer. The remainder of the outage I is divided into work areas each headed by a responsible l supervisor, l The critical path for the outage is the fuel floor and pipe replacement activitie These jobs are to be man-loaded on a six day per week, and two ten hour shifts per day basis. The pipe replacement activities are delineated in a PECo Project Procedures Manual (PPM) l and a contract handboo Periodic meetings to discuss outage progress are as follows:
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at contractor shift turnover meetings (5:30 l and 4: 30 p.m.)
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at plant shif t turnover meetings (7:15 a.m., 3:15 and 11:15 p.m.) l
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daily conducted by plant management (8:30 a.m.)
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daily conducted by outage management (10:00 a.m.)
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twice a week among outage management, construction, maintenance, and plant management
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weekly conducted by the Project Review Group
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a monthly executive review meeting The inspector reviewed the PPM, the organizational structure, the modification list, and discussed it sith licensee outage personnel. The inspector also attended selected meetings and toured the on site pipe replace-ment facilities. The inspector will continue to follow the eYfectiveness of this organization including the changes made during the refueling outage period. NRC Inspection 277/87-33 and 278/87-33 also addresses Unit 3 pipe repiscement outage activitie ~
4.4.2 Controt of Unit 3 Plant Conditions The licensee has written and approved a number of .
special procedures (SP) to control and implement the necessary plant conditions for the Unit 3 pipe replacement activitie These procedures include the following:
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SP-1060 and 1060A, "Overall Coordination Procedure for Recirculation Pipe Replacement," Rev. SP-360, "Defeat of Portions of RPS and PCIS with Unit 3 Reactor Fuel Off Loaded," Rev. SP-361, "Defeat of Rod Block and Refueling Interlocks with the Unit 3 Core Off-Loaded," Re .
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SP-707. "Installation of Vessel Drain Flange Conneu.ons," Rev. SP-1050, ",WCU Decon Equipment Installation and Checkout," Rev. SP-1051, "RWCU LOMI Decon Operating Procedure,"
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The inspector reviewed these procedures and selected !
temporary changes, independently verified the l implementation of selected steps of each procedure, and i discussed them with licensee engineers and operator In addition, the inspector reviewed the contractor procedures and drawings for the implementation of reactor vessel level temporary instrumentation. This level instrumentation is required during vessel drain down for pipe cutting and decontamination-activitie The inspector verified that the operators had drawings in the control room that depicted this arrangement for temporary level indication and drain device l No violations were note !
4. Containment Spray System Sparger Inspection
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In combined inspection report 50-277/87-17; !
50-278/87-17, section 4.4.5 discussed the licensee's ;
visual inspection of the Unit 2 containment spray system spargers and nozzles. The inspection was conducted in i
response ti the discovery of a large amount of rust flakes in another BWR's spray spargers and nozzles. The i i
spargers and nozzles in Unit 2 were found to be fairly '
! clean with only minimal rust seen. However, this area l was left open pending licensee inspection of the Unit 3 !
containment spray system spargers and nozzles.
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On September 21, 1987, the licensee performed a visual v inspection of the Unit 3 drywell and torus containment ,
spray spargers and nozzles. The inspection was carried i out under two maintenance request forms (MRFs 8705756, >
8705758). The licensee's findings were- '
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For the A drywell spray loop, four nozzles were removed (A2, 45, 250, & 300). All of the nozzles ;
and piping near the nozzles had indications of I minimum rus For the B drywell spray loop, two nozzles were !
removed (A20 & 180). Both nozzles and piping near l the nozzles had indications of minimum rus i t
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For the torus spray loop, four nozzles were removed I (Bay 2, 6, 10 & 12). Nozzles 2, 6 and 12 and the l piping near the nozzles had indications of minimum i rust. Nozzle 10 had a small build-up of loose rust I that would not interfere with the nozzle flow path; piping near the nozzle head had a minimum amount of surface rus ,
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The inspector reviewoo the licensee's inspection findings, Mechanical Engineering Report (RES 15-11) and spoke with the test engineer who was part of the inspection team. Based on the above information and information described in combined inspection report 50-277/87-17; 50-278/87-17, Peach Bottom does not appear !
to have rusting problems in their containment spray spargers similar to that found at the other BWR
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l facilit The inspector had no further questions or concerns at this tim '
4. Unit 3 Core Offload t
Unit 3 core offload activities occurred during the l period October 15-28, 1987. The inspector reviewed ;
licensee ,arerequisites for. core offload. A review of t the related refueling documentation was performe i
The inspectors monitored the following items associated i with core offload through direct observation of fuel (
handling activities on the fuel floor and in the i control room, f i
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The operability of refueling interlocks, !
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The operability of source range monitoring (SRM) !
instrumentation, '
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Availability of direct communication between the control room and refueling bridge,
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The presence of a senior licensed operator supervising fuel handling activities, ;
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The operability of the standby gas treatment system and secondary containment, ,
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The radiological precautions for fuel handling i including adherence to the RWP, j
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The presence of an HP technician in the fuel floor !
area,
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The operation of refueling bridge and associated ;
fuel handling equipment, ;
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Reactor vessel and fuel pool water level and h clarity requirements, t i
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Fuel and component accountability in the spent fuel pool and in the reactor cor Reactor mode switch locked in "refueling" positio The operability and required full insertion of all control rods, and
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Unit 3 reactor operator cognizance of refueling activities and direct monitoring of SRM levels and changes (count rates and period changes).
With respect to the above routine observations, no violations were note !
On October 18, 1987, during core offloading, the bridge operator experienced a hoist jam while attempting to remove-fuel bundle LJW823 from core coordinate 21-01. A '
visual camera inspection was performed and the licensee i determined that a 9/16 inch combination wrench was '
laying.over the channel of LJW823 and under the bail handle of the adjacent fuel bundle, LYA333 (core
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coordinate 21-04). The licensee suspended core offloading pending "resolution of this proble , ,
Procedure Sp-1059, Inspection and Retrieval of Object
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at Core Location 21-02," was written and implemented on ;
October 19, 198 !
The licensee performed a safety evaluation (with support from GE). The safety evaluation concluded the following: Only minimal and superficial damage was caused by the wrench. Some damage to one of the lock tab washers was noted on fuel bundle LYA333, but the l lock tab washer appeared to be intact. It is acceptable to remove both bundles from the core. Prior to reinsertion of fuel bundle LY,*.333 into the core, i visual inspection of the top of the bundle should be performed with an underwater periscope. It is also i recommended that the damaged lock tab washer should be l replaced. In addition to the GE recommendations, PORC
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(meeting #87-224) approved the Safety Evaluation and recommended the following:
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Both fuel bundles LYA333 and LJW823 should be removed from the cor Both fuel bundles should be inspected and repaired as require ,
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d it inspectii
- Fuel core priorbundle to PORC LYA333 approvalwill of itsn repair i nor The licensee removed both fuel b
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. ' procedure , the s The inspector reviewed procedure h wrer.ch, a evaluation, the videotape showing described tt e confirmed the wrench The orientation licensee
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license ideotape frort the wrench the post core entered the86).
load verification reacto The licer thevwrench pi previous refueling (February 19 have <
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that this videotape did not show d prior to
, The licensee stated that the wrenc
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reactor after core verification a separator installatio f tt The on site ISEG is performing November 5, a
writing an event repor d note this occurrence at a meeting onitud /
inspector attended this NRB meeti i members displayed EG and a be que the r
f reactor was noted both by future inspectio .
4,5 Control of Instrument Valvn that occurred ,
As a result of containment isolationsthe The d i l
1987, proJram for (see section the control o 4.2.1)f instru valves include:
flow root valvecheck valve (RRV); called the the instrument ractroot call the valves nearest the instrumen i ingInoraddition
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, equali:,
isolation /stop valve (IIV/ISV)./ ,
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controlle f the ir=f tions. /
The isolation valves beyo "Unit 2(3) Inst'<
13.38-2(3), desguidancefol surveillance test, STCheck-Off This ST implements cb Li .
related instrument valves.The COL identifie (COL),S.22.1-2(3). f ty Instrumet j
- surveillance test, ST 2. I
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Check-Off List," Revision 0(1). In addition, the individual instrument calibration / functional test STs provide control of these instrument valve The inspector reviewed the above documentation and discussed l instrument valve control implementation with operators, engineers, I&C technicians, and station management. The current approved copy of COL S.22.2-3 had the RRVs mislabelled as RIVs. The inspector brought this to the attention of the licensee. The
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licensee stated that a revised ST with the correct terminology was
! written and scheduled to be approved. These COLs use the Critical Equipment Monitoring System (CEMS). The inspector questioned the CEMS engineer regarding instrument valve identification and tagging. The engineer showed the inspector an approved procedure C.2.1, "CEMS Guideline for Instrument Valve Labeling," Revision C.2.1 provides for the designation and identification of all instrument valves. I&C procedures ST 2.0.2(3) do not use the CEMS terminology for the valves on each instrument reck. In addition, the inspector reviewed selected I&C calibration / functional test STs. These STs also do not use this CEMS terminology. The inspector stated that for consistency and in order to minimize confusion; the approved CEMS terminology for instrument valves should be used in all procedures. The licansee agreed and stated that the affected procedures would be revised during the in progress I&C ST rewrite project, t
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The inspector questioned selected operators, I&C technicians, and engineers with regard to instrument valve controls, terminology and identificattun. Familiarity with the CEMS terminology was :
lacking in most cases. Interviewed personnel did not know the I
dif ferences among root valves, rack root valves, rack isolation valves, and instrument stop (isolation) valves. The CEMS engineer stated that training on instrument valve terminology had been planned, but not yet schedule The inspector summarized concerns . hat the CEMS instrument valve :
terminology is not currently in sone station procedures and that personnel have not been training ir this area. Licensee management agreed with this conclurion. The inspector will follow the procedure revisions to implemeit CEMS terminology and review !
the trair.ing of personnel. These items will be addressed during a i future inspectio ;
l 4.6 Nuclear Review Board (NRB) Meeting
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i The inspector attended the November 5, 1987 NRB Meeting number !
210. The inspector verified that meeting composition, meeting {
frequency, review and audit activities were in accordance with ,
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Technical Specifications 6.5.2 and approved NRB implementing !
' procedures. The inspector reviewed the meeting agenda, meeting j minutes and open item listing. The inspector noted that the NRB
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members demonstrated a questioning attitude and nuclear safety perspective. In addition, two members of the NRB (including the NRB chairman) toured the Peach Bottom facility on November 4, 1987. Their observations were communicated in writing to the NRB at the November 5 meeting. Their conclusion was thai ~ rail station housekeeping was improving and that personne' .anges appeared to be improving operations. They also identi. led two concerns: (1) equipment layup during extended outages, and (2)
indicators of personnel attitude improvemen No unacceptable conditions were identifie .7 Operations Management and Shift Rotation Changes The operating shift at Peach Bottom changed the shift rotation schedule effective October 19, 1987. The new schedule continues with a six shift eight hour rotatio However, the schedule rotates from midnight shift (11:00 p.m. - 7:00 a.m.) to dayshif t (7:00 a.m. - 3:00 p.m.) and then to af ternoon shift (3:00 p.m. -
11:00 p.m.). This new rotation differs from the previous
backwards" rotation schedule. Two utility (day shift) shifts are i6cluded two weeks afur midnight shif t. The schedule repeats every six calendar weeks and the maximum hours per week is 4 (A calendar week begins Monday and ends Sunday.) Attachment 1 .
delineates the new rotation schedul #.
In addition, the licensee implemented the following shift operations organizational changes: (1) J. B. Cotton assumed the duties of the Superintendent, Operations effective October 23, 1987; and (2) the Shift Managers assumed the duties previously held by the Shift Superintendent effective 11:00 p.m., October 25, 198 The inspector reviewed these changes, monitored their implementation at the station, and discussed them with licensee management and operations personnel. Based on selective interviews, operators appear to be satisfied with the new shift rotation schedul The inspector attended selected shift turnover meetings and daily plant status meetings (8:30 a.m.) in the control room. These
, meetings are conducted by the Shift Managers. The inspector noted I
that these meetings were professionally conducted and informative, i No unacceptable conditions were note l l
4.8 Emergency Cooling Water System Damage In combined inspection report 50-277/87-15; 50-278/87-15, the inspector reviewed water hammer damage to the ECW pump and piping support The inspector left unresolved item 87-15-01 open
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pending: (1) visual observation of a full flow test of the ECW system; (2) review of PECo's Engineering Evaluation of the ECW damage; and (3) repair of the ECW system damag On June 3, 1987, the inspector observed a full flow test of the ECW syste Prior to the test, performance engineers walked down the ECW system and determined that.the pump discharge line was not full of water as evidenced by a vacuum indication at a vent connec-tion downstream of closed discharge valve H0-841. Upon pump start and opening of M0-841, no dynamic transients were observed. However, during pump shutdown, the check valve (0-506) between the pump and valve M0-841 slammed shut, caustrig minor pipe movement. Based upon this testing, it could not be determined if one large water hammer, numerous small water hammers or numerous check valve slams caused the damag Draining of the ECW pump discharge.line was likely caused by leakage through one or both ESW pump discharge check valves (0-515 A/B) or through one or more diesel generator ESW block valves (AO-241 A/B/C/D). Because of the need to maintain the diesel generators operable, no additional investigation was done to determine the leakage source. During unrelated ESW testing, leakage problems were noted with both ESW discharge check valve Two maintenance request forms (MRFs) were written to examine the check valves; 0-5158 was subsequently found satisfactory, but 0-515A was stuck open. The ECW pump discharge line leakage may have been through check valve 0-515A, if it had been stuck open for some time. However, when 0-515A was closed, tite seal was goo Transient analysis to determine the hydro-dynamic loads on the ECW system will be performed by engineering to determine if system modifications are necessary. Some initial modifications under consideration by the licensee are the installation of an ECW keep full system and weighting check valve 0-506. The insnector will continue to follow the resolution to ECW drain down end subsequent system modifications, if necessary, in a future repor The inspector reviewed the engineering evaluation of the ECW damage (L. B. Pyrih to D. M. Smith dated September 14,1987). The evaluation described: specific damage; past and continued system operability; magnetic particle examinations; and repairs, routine 1 inspections, and transient analysis for system modifications, if j necessar The inspector found the evaluation to be thorough and l detailed. The inspector concluded that recommendations in the i evaluation should be sufficient to repair existing damage and '
preclude or inhibit future damage. The inspector had no further questions in this are I i
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On Octouer 5,1987, the inspector conducted a tour of the ECW tower structure. Work had just begun to repair the damaged pipe ,
supports. The work was being carried out using a new Construction !
Oivision Procedure, CD 2.3, "Procedure for Performing Maintenance and Repair Work on Q-Listed Systems at Peach Bottom," Rev. O, dated 9/11/87. This new procedure receives the same review process as a formal MOD raquest, but reduces the paper work and .
time,
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As part of the review, the inspector examined Station Repair l Request R-087. Support 48HB-H58 was the first support to be !
repaired. The engineering evaluation, which was endorsed by a l PORC approved SER (9/30/87), stated that a temporary support will '
be used approximately two feet west of 48HB-H58. The Construction l Job Metrorandum also called for the support to be located in the same place. The inspector noted that the as-found position of the temporary support was two feet east of '3HB-H5 Upon further review of R-087, the inspector found Engineering Review Request Form (ERRF) P-3832 stating that the temporary support will be located two feet east of 48HB-H5 ERRF P-3832 was written to request PEco Engineering to provide more specific details concerning the tecporary support for 48HB-H58 and proper adjustment of two other damaged ECW hangers. Field crews are to j perform work in accordance with design drawings and any ERRFs written against these drawings; this was done. However, the inspector was concerned with the discrepancy between the actual ;
temporary support location and PECo Engineering's recommendatio The inspector spoke with the Mechanical Construction Engineer l (MCE) who had written ERRF P-3832. Apparently, he had written i east instead of west for the temporary support location. The MCE 1 contacted PEco Engineering concerning the placement of the temporary support. PEco Engineering stated that the present support location was acceptable. The inspector had no further questions concerning the temporary suppor The inspector reviewed the PORC approved engineering evaluation and Nonconformance Report (NCR) CD-P-903 which were in R-087. The NCR stated that repair will be as specified in the engineering evaluation. Part of the repair procedure for 48HB-H58, as stated
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in the engineering evaluation, was to completely remove the base plate and anchor bolts. The inspector noted that the support had not been removed as required. Also, no documentation (ERRF) was found in R-087 authorizing the change. The inspector spoke with the MCE regarding this issue. He stated that craft personnel informed him that they could remove the cracked grout and anchor bolts, and regrout the area without removing the support. The MCE also stated that he spoke with the responsible engineer who wrote the engineering evaluation that required support removal. The
' basis for the requirement was strictly for ease of repair. A verbal agreement to leave the support in place was made between
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the MCE and the responsible engineer, but paperwork was not initiate Engineering and Research Department Procedure ERDP 3.8, "Procedure for Processing Engineering Review Requests," Re , Section 6.2.1, states that an ERRF must be processed even though verbal approval was received. A copy of all verbally approved ERRFs must also be sent to the Construction Division QC group. 10 CFR 50, Appendix B, Criterion VI states that measures shall be established to control the issuance of documents, such as instructions, procedures, and drawings, including changes thereto, which prescribe all activities affecting qt.ality. "Design changes to modifications, including field originated changes, shall be subject to design control measures commensurate with those applied to the original design of the modification and shall be approved by the organization approving the original modification design unless PEco documents or procedures specify otherwise. The independent design review of design changes shall include the changed icformation and an evaluation of the effects of the ;
changes on the overall design. "Failure to document a field initiated change to PORC approved repair procedures is an apparent violation of 10 CFR 50 Appendix B Criterion VI, Document Control l
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2 ab During discussions with the Construction Supervising Engineer concerning the above apparent violation, it was discovered that l i
the licensee had also changed the disposttion to approved NCR i CD-P-903 wittout initiating a new NCR. Failure to initiate a new l NCR is in disagreement with Section 6.10 of ERDP 15.1, "Proca i re !
for Handling Nonconformances," Rev.12. The inspector considered l this item to be licensee identified. Also, QA issued a Finding Report, and Construction initiated a new NCR (CD-P-937) to address the changes made to NCR CD-P-903. The inspector had no further questions at this tim In conclusion, unresolved item 277/87-15-01 has been closed, an apparent violation of Appendix B has been identified, and the ;
inspector will continue to follow the disposition of the transient analysis for the ECW system and further repair of the ECW system 1 damag .0 Emergency Planning In preparation for the annual emergency exercise, the licensee conducted emergency drills on October 27, November 10 and 24, 198 l The new management and shift organization participated in the drill The inspector participated in the October 27, 1987 drill in the control room. Overall 'icensee response was adequate. The inspector also observed portions of the November 10 and 24, 1987 drills, l.icensee response was noted as also being adequat .
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No unacceptable conditions were identifie The inspector also observed the annual emergency exercis .0 Review of Licensee Event Reports (LERs)
6.1 LER Review The inspector reviewed LERs submitted to the NRC to verify that the details were clearly reported, including the accuracy of the '
description and corrective action adequacy. The inspector determined whether further information was required, whether generic implications were indicated, and whether the event warranted on-site followup. The following LERs were reviewed:
LER N .
LER Date :
Event Date Subject l
- 2-87-17 Unit 2 Group III Isolation Due to a Temporary .
October 16, 1987 Clearance of a Block !
September 16, 1987 2-87-20 HPCI System Inoperability Due to Electrical I October 5, 1987 Failure September 4, 1987 ,
2-87-22 HPCI System Inoperability Due to a Battery October 30, 1987 Charger Failure ;
September 29, 1987 '
- 3-87-08 Unit 3 Shutdown Cooling and Group II Isolation November 4, 1987 During Troubleshooting Activities October 5, 1987
- 3-87-09 Unit 3 Snutdown Cooling Isolation During November 12, 1987 Testing October 12, 1987 6.2 LER Followup For LERs selected for followup and 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. Report accuracy, compliance with current reporting requirements, and applicability to other I site systems and components were also reviewe !
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6. LER 2-87-17 concerns a partial containment isolation that occurred on Unit 2 at 6:00 a.m. on September 16, 1987. The isolation was a group III outboard reactor building ventilation trip and standby gas treatment system (SGTS) fan start. The isolation occurred when a fuse was being replaced during the temporary clearing of a blocking permit for modification work. This resulted in a re-energization of control power; with the isolation logic in a tripped state, an isolation occurred. The licensee reset the isolation, opened the valves which closed, restarted reactor building ventilation fans, and stopped the SGTS fan. A four hour ENS call was made at 8:15 The licensee concluded that the root cause of the event was inadequate review of a blocking permit, and how blocking permit appli, cation or removal affects ESF logic system The inspector reviewed the LER, and the licensee's upset report, and discussed the event with operators and engineers. NRC open item UNR 277/87-22-01 and 278/87-22-01 also address the issue of clearing blocking permit Licensee proposed corrective actions include the development of a system which requires operations approval of blocking permit for ESFs. The inspector i will reyt.ew this item after licensee implementation of corrective actions. No inadequacies were noted relative to this LE i 6. LER 3-87-08 concerns a shutdown cooling and Group II I containment isolation on Unit 3 on October 5,198 The i event was reviewed in NRC Inspection 277/87-25 and l 278/87-25. No inadequacies were noted relative to this i LE . LER 3-87-09 concerns a shutdown cooling isolation on Unit 3 on October 12, 1987. The event was reviewed in NRC Inspection 277/87-25 and 278/87-25. No inadequacies i were noted relative to this LE j
6. LER 2-87-16 concerns a partial loss of off site power on l August 20, 1987, resulting in Unit 2 and 3 containment isolations. This event was reviewed in NRC Inspection 277/87-22 and 278/87-22 and the LER was initially reviewed in NRC Inspection 277/87-25 and 278/87-25. The l cause of this event was an 80-ton mobile crane drawing an arc through the boom to the ground while attempting to move a cargo unit located under the No. 2 off site power source 220 KV line Corrective actions have been completed to prevent recurrence which included training of maintenance foremen and riggers in electrical safety
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and placement of warning bars from high voltage lines where appropriate. No inadequacies were noted relative to this LE .0 Surveillance Testing The inspector 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 was performed by qualified personnel, and test acceptance criteria
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L were met. Parts of the following tests were observed:
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ST 9.32-2(3), "Reactor Cold Shutdown Date Log - U/2 (U/3)," Re , performed on both units during the inspection perio ST 6.10-2, "HPSW Pump & Valve Operability & Flow Rate Test - U/2 Only," Rev. 7, performed on Unit 2 on November 22, 198 ,
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ST 9.33, "Plant Status Reporting," Rev. 2, performed on both units during the week of November 16, 198 ST 13.9, "Secondary Containment Capability Test," Rev. 5, e performed on Unit 3 on November 3, 198 No inadequacies were identifie .0 Maintenance 8.1 Routine Observations i
For the following maintenance activities the inspector checked administrative controls, reviewed documentation, and observed ;
portions of the actual maintenance:
Maintenance <l Procedure /
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Document Equipment Date(s) Observed ;:
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M00-2132 Control Room Panels Various during ;,
period .l HRF #87-7780 -:
Enhancements A0-3506 and 3507 October 27, 1987 '. l
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FH-GE-1 LPRM removal (Unit 3) November 6, 1987
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Administrative controls checked included maintenance request forms (MRFs), blocking permits, fire watches and ignition source controls, item handling reports, QA/QC involvement, plant conditions, TS LCOs, equipment alignment and turnover information, post maintenance testing, and reportabilit Documents reviewed included maintenance- procedures, material certifications, RWPs, MRFs, and receipt inspection No inadequacies were note .2 Maintenance Request Form (MRF) Backlog The licensee is working to clear the MRF backlog for Unit 2 and -
common open work items. This MRF backlog includes outage and non-outage MRFs, which are sub classified as either Q (safety related) or non-Q (non safety related), and as either corrective or preventiv The licensee issues a weekly MRF summary report that itemizes the open MRFs by section '(i.e., status of completion), responsible vor'. group, and trend informatio The November 19, 1987 report shows the following status:
Category MRFs Open preventive - 0 265 preventive - Non Q 436 Corrective - Q 291 Corrective - Non Q 1150 i Total 2142 l
In addition, a total of 2371 MRFs have been classified as work complete; however, the "Operations Verification Form (OVF)" has not been done. That is, section 7 (OVF) of the MRF remains ope Additional licensee action in this area includes a program to reduce the MRF backlo ;
The inspector reviewed: selected MRF summary reports; a listing of the open MRFs; selected safety related MRFs; the MRF backlog j reduction program. The inspector also discussed the MRF backlog i with licensee engineers and plant management. The inspector ;
stated that reducing the backlog was important prior to the !
commencement of major milestones (i.e. , vessel hydro, ILRT and the j restart of Unit 2). The licensee agreed and further stated that i this item is being constantly monitored and reviewed periodically '
by management. The inspector will continue to monitor the licensee's progress in reducing this MRF backlo I No violations were note .
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9.0 Radiological Controls 9.1 PECo Special Team Assessment of Pipe Replacement Project Group Organization and Program Implementation In response to concerns expressed by a regional based radiation specialist during an inspection October 17-21, 1987, the licensee committed to conducting a comprehensive team assessment of the Project Radiation Protection Group (PRPG) which is the group responsible for providing radiological control of Unit The assessment was conducted November 2-13, 1987. The pipe replacement assessment report was completed on November 20, 198 The inspector was briefed by the Superintendent of Services and the Applied Health Physicist of the findings of the assessment and proposed immediate corrective actions. The report and corrective actions will be reviewed in detail in a later specialist inspection repo~r .2 Training for Unit 3 Control Rod Drive Removal The At. ARA groups,of the plant and Pipe Replacement Project Group (PRPG) cooperated to develop a mock up training program for control rod drive (CRD) removal during the outage. Early in the outage, removal of two CRDs was required for installation of. level and draining contro.l. The training package was developed and training facilitier were constructed which included a realistic mock up of the CRD to support that activity. The inspector reviewed the training on November 7, 1987. The mock up training was realistic and effective. The training was performed with all appropriate tools and equipment, appropriate radiation protective equipment, and full participation by all groups involved with the work activit In addition, QA personnel were involved to audit the training and suggest lessons learned to incorporate in subsequent trainin The training was initially in work clothes to familiarize the already experienced workers with the operation; it was repeated after discussions to determine if time saving motions could be utilized. After several repetitions incorporating lessons learned, the required radiation protective clothing was use Work activities were again repeated, including a repeat of the lesson learned discussion for time saving motions in full protective clothing. As a result of the mock up training and lessons learned in the time study, the job duration was cut in hal The man-rem for a CRD removal in the past (Unit 2,1985) had been approximately 3.9 man-rem per CR The two CRDs were removed resulting in a dose of 1.1 man-rem. The mock up training resulted in substantial man-rem savings and reduction of the time required to remove a CR __ . _ - . _ - - _ _ - - -
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No unacceptable conditions were identifie .3 Significant Radiological Events The inspector reviewed four radiological events that occurred during the reporting period to determine the licensee's response to these events, the immediate corrective actions, and the long term corrective actions to prevent recurrence. As a result of this review the inspector identified an apparent violation of plant procedures, and survey and posting regulations. Throughout the inspection period, the inspector noted weaknesses in several areas, which are summarized below, that were contributing factors to the apparent violatio The Applied Health Physics department has not effectively utilized procedure HP0/C0 600, "Health Physics Deficiency Reports" (HPDR) as an internal quality control method for self correction of problems identified within the departmen The HPDR open item (see section 3.7) remains ope In the field, there is some indication HP technicians lack adequate knowledge of HP procedures, and in many cases, HP techni-cians do not know where to find them. Due to the number and quality of revisions to these procedures recently, there is confusion amongst some HP technicians, as to which procedure is correct, old or ne There is a lack ofeknowledge of procedures by other groups that impact upon the responsibilities of the HP techs. An example is the rad waste procedures that define radchecker responsibilities and their methods for picking up radioactive waste. The inspector will review the licensee's efforts to correct this deficiency in future inspection The ALARA program implementation has been weak. For example, procedure HP-302, "ALARA Suggestion Program" was issued and implemented on August 10, 1987. There have been three suggestions since that implementation. The procedure requires further revision to be more workable and to increase worker participatio The ALARA suggestion method is a very effective introspective technique for improvement of the Applied Health Physics organizatio The HPDR procedure as written, suggests that deficiencies are the fault of the radiation worker. The inspector observed that some HP Technicians do not feel that they are responsible for ensuring that the following radiation protection policies are enforced:
questioning of work groups in radiation control areas that do not seem to be doing work; and checking that workers are on a radiation work permit, have their Dose Card, and if necessary, are wearing their self reading dosimeter. The inspector will review the licensee's a efforts to correct this deficiency in a future inspec-tio The ALARA open item (see section 3.8) remains ope _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ ._
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In the events that follow other examples of this poor practice of ALARA are give . Hot Particle Found Outside of A Locked High Radiation Area During a routine weekly Unit 2 Reactor Building survey of radiation levels and contamination on October 7, 1987, a health physics technician found an area outside the door to the regenerative heat exchanger room (RHXR) ,
that exhibited higher radiation levels than expecte '
The technician surveyed the area to determine the extent and reason for the change. A source was located in a radioactive waste drum outside of the door to the RHXR, inside an area posted as "contaminated area." The radiation levels were 300 mR/hr at 18 inches from the drum.' On the step off pad at the door to the RHXR the levels-were 140 mR/hr. The source in the drum was immediately removed, shielded and transported to a locked high radiation area for storage. A Health Physic} Deficiency Report (HPDR) was initiated to investigate the cause of the event and to determine corrective actions to prevent recurrence. The initial investigation determined that there were two work events the preytous day that occurred in the RHXR (a locked high radiation area which had potential for generating the source in the trash). These events were the clean up of the area and the cutting out of a valv The inspector, upon discovery of the event in the HPOR log, reviewed appropriate procedures and logs, interviewed personnel involved with the event and the corrective actions. Based upon the review the inspector determined that:
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The HP technician (tech) providing continuous coverage in the RHXR for both work events did not do the prejob briefing as require The HP tech providing continuous coverage in the RHXR for both work events did not keep the ;
worker (s) under continuous surveillance as !
require The HP tech providing continuous coverage in the RHXR for both work events did not survey the RHXR j area upon exit, nor did he survey the area outside i of the RHXR upon exit to determine if any change in conditions occurre This is apparently a common work practic !
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Since there was not continuous surveillance and the HP tech did not do the prejob briefing, neither the i HP tech nor the worker understood the precautions required. Neither the HP tech nor the worker ;
understood their responsibility to communicate what l the other was doing or required to d !
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The investigation of the HPDR did not begin until October 14, 1987, 7 days after the event. There were no immediate corrective actions initiated by i the applied health physics group to prevent !
recurrence of failure to survey and to post the !
locked high radiation area t.ntil October 19, 198 j l
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The HPDR was not completed until November 17,' 1987, ,
after several attempts to propose adequate '
corrective actions. Follow up investigations were too late to determine with certainty the origin of the source and the duration it may have been in the drum outside of RHX l
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The applied health physics group supervisors were not aware of the procedures practiced by the rad waste group for pick up and survey of the rad waste by the crafts ("radcheckers"). As a consequence, the applied health physics group did not know that the radcheckers first removed the bags from radwaste, rebagged the waste, then finally surveyed the trash. They did not know what triggered the radcheckers to pick up the waste nor when. As a consequence, there was a potential for the radcheckers to receive an unplanned exposure from the source in the wast The HPOR did not address the origin nor the disposition of the source, and where it was '
ultimately store The final HPDR inve:tigator's report of November l 16, 1987 was an adequate investigation of this '
event with findings ard recommendations of corrective action CFR 20.201 ("Survey") requires that radiation hazards i be evaluated by the licensee. 10 CFR 20.203 requires '
that areas greater than 100 mr/hr be posted as high radiation areas. The Unit 2 RHXR was not surveyed and an area of 300 mr/hr was not posted as a high radiation ,
area. The failure to adequately survey and post the i high radiation area is an apparent violation of the I
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criteria in 10CFR20.201, "Survey," and 10CFR20.203.(c)(2), high radiation area posting (see i section 9.3.5). !
l 9. Unplanned Internal Intake By Worker Work activity in the Unit 2 RHR "A" Pump Room was to paint and to replace insulation. On October 12, 1987, the work activity began after a survey of the areas involved. The work proceeded daily until October 19, l 1987, when a worker who exited the area was contaminated i externally and internally (positive nasal blow). The individual was decontaminated and a whole body count (WBC) was performe The estimated intake, based upon a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> count, was 42 MPC-h (maximum permissible concentration-hour). The other workers in the area were l also contaminated but not internally. The workers had i been in the room cleaning up debris and insulation on radiation work permit (RWP) 3876172. The maintenance j request form (MRF) 8705320 was for painting and ;
insulation in the room. .Workers are expected to clean I up after work activity and the workers understood, by l practice, that'the RWP was sufficient for that activit The licensee initiated an HPOR and informed the inspector of the incident and the estimated intak The inspector reviewed procedures, the HPDR, the RWP and MRF, and interviewed involved personnel. Based on that review the inspector determined the following:
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The immediate corrective actions proposed in the HPOR were adequate, but were not instituted in a timely or reasonable manne The HPDR did not address the root cause of the intake as a lack of communication between the l workers and the responsible HP tec !
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The area had not been surveyed or evaluated for radioactive hazards for seven days prior to the )
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event. The RWP required a survey every seven day No measurements were made of the increased contamination levels for seven days, hence the evaluation of the radioactive hazards could not be made by the HP tech providing coverage, the control point, nor the group superviso The RWP was inadequate in that there were no requirements for consideration of the contamination level changes that insulation work would caus l
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The initial HPDR corrective actions of October 28, ,
1987, did not recognize the inadequacy of the RW l The HP tech failed to recognize changing conditions. The event occurred due to the high contamination levels (4 to 176 mrad /hr) on the floor. With this kind of contamination levels, motions, even walking, could have caused the. event to be an airborne even l
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The group supervisor should have recognized by discussions with his techs the potential for changing conditions. HP control point logs are !
difficult to read because they are not written in a '
clear, concise, and professional manne CFR 20.201 requires that radiation hazards be l evalu'ated by the licensee prior to work activit The 2A RHR-room was inadequately surveyed. The failure to survey is also an apparent violation of the criteria in ;
10 CFR 20,201, "Survey" (see section 9.3.5). !
9. Contam'inated Equipment In An Unrestricted Area On October 26, 1987, an HP Tech assigned to cover .
radiography in the north substation, noticed that a !
rediation drum manipulator had been stored in the scrap ,
yard located near the north substatio It had been '
stored there since the start of the construction of the i new radwaste building. He surveyed the equipment because he was familiar with it and knew it had been i contaminated in the past. The survey revealed that the 1 manipulator was contaminated up to 12,000 CPM fixed and l 1,800 DPM/100 square centimeters smearable. The i manipulator had been released to an unrestricted area i after it had apparently met the criteria for release on !
August 10, 198 The manipulator was stored in an unrestricted area for 77 days, until October 26, 198 An HPDR was immediately initiated. The inspector reviewed the HPOR and procedures, and interviewed personnel. Based upon that review the inspector determined that:
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The HPDR required 23 days to complete the corrective actions; this was neither tir.ely nor reasonable. The final disposition of the HPDR was inadequate because it did not address whether or not the drum manipulator was decontaminated or where it was stored. In addition, the resurvey report and the HPOR did not indicate that storage of decontaminated equipment in a restricted area is l
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a violation of regulatory requirements of "posting, survey, storage and control of licensed materials in unrestricted areas".
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The manipulator was stored in an area accessible via the gate to the main stack. This gate is locked when no work is being done in the are Otherwise it is unlocked until the workers leave the area. When the gate is unlocked, there is no guard. The radioactive material was in an unlocked, unsecured, and unguarded unrestricted area which is a violation of 10 CFR 20.207,
"storage and control of licensed materials in an unrestricted area."
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The HPDR did not address training nor qualifications of the HP tech who inadequately surveyed the equip-men It id not address review of the procedures for inadequacies or responsibilities of the supervisor for oversigh CFR 20.201 requires that the licensee evaluate radiation hazards prior to releasing equipment to an uncontrolled area. There was a failure to exercise proper control over radioactive material in unrestricted areas; however, the raot cause of the event was the failure to survey. This is also an apparent violation of the criteria in 10 CFR 20.201, "Survey" and 10 CFR 20.203, posting of radioactive materials (see section 9.3.5).
9.3.4 Radioactive Materials Found In a Clean Area of the Station On November 4, 1987, the inspector noted an area roped off in the protected area near the decontamination i trailer, posted as a "contaminated area". The asphalt l delineating the contamination area: was painted. The !
inspector investigated the posting and the cause of the l posting by interviewing licensee personnel and reviewing procedures and documents. Based upon this review the inspector determined the following:
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An HPDR hr not been written to investigate this even The HPDR procedure states that contamination found in a previously clean area is a level III deficiency, therefore an HPOR should have been writte l l
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1985, from a contamination event that was ,
insufficiently cleaned up and surveyed. The area -
was apparently surveyed inadequately because, "of
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No evaluation was made of the event to determine 'if i an off site release had occurre l
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Investigation revealed that_there was a spill in 1985
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of approximately five gallons of contaminated. water from a 55 gallon drum onto the asphalt. The water was contaminated to levels of 50 mrad /hr.as measured by an R0-2A instrumen The contaminated area was found by an effective investigative effort by the applied health physics supervisor. A hot particle was found by.the clean trash and maintenance HP techs, who were assisted by their supervisor in tracking the particle in the ,
.tr. ash to a piece of asphalt from the construction !
work activities in conjunction with the decontamination trailer mov .
10 CFR 20.201 requires that licensees evaluate radiation hazards and 10 CFR 20.201 requires that radioactive materials be conspicuously posted. The failure.to i adequately survey this area is also an apparent {
violation of 10 CFR 20.201 and the failure to post this I contaminated area is an apparent violation of 10 CFR 20.203 (see section 9.3.5).
9. Conclusion These events (section 9.3.1 to 9.3.4) were licensee {
identified, however, it does not meet all the criteria i listed in 10CFR2, Appendix C for not issuing a Notice of l Violation. The corrective actions were not reasonable nor timely to prevent recurrence. It was also a
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violation that could have been prevented by the licensee's corrective actions for recent previous violation. (See NRC Inspection 277/87-07-04.)
Therefore these four events are an apparent violation of 10CFR20.201 and 20.203 (277/87-24-02; 278/87-24-02),
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10.0 Physical Security
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10.1 Ro_utine Observations 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 physical protected and vital area barriers, checks on control of vital area access, escort procedures, checks of detection and assessment aids, and compensatory measures. One concern was noted involving vehicle contro See NRC Combined Inspection Report 50-277/87-37; 50-278/87-3 .2 Drug Search Using Druc Detection Dogs
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PECo corporate security brought five teams of trained drug detection dogs, handlers, Pennsylvania State Police and PECo security representatives on site October 30, 1987. From 3:00 to 6:00 a.m., thp search encompassed areas inside the protected area. Areas sear.ched included the access facility, reactor building, maintenance shops, locker room, administration building and vendor trailers and buildings. All three resident inspectors ;
were on site and accompanied three of the five search team From 9:00 a.m. to 10:00 a.m. on October 31, 1987, the drug teams again searched the Peach Bottom site. Areas searched the previous !
day were searched agai In addition, the parking lot, NRC t office, control room and licensee management offices were searched. One NRC resident inspector accompanied a search tea No contraband was foun However, the dogs "hit" at 37 different locations, none of which were in the control room, management offices nor the NRC office. A "hit" is confirmed when another dog
"hits" the identical spot. A forensic expert was present to take swipes of the areas "hit" by the dogs. After analysis, all 37 swipes were determined to be negative, indicating no drug residu The licensee explained that the dogs were probably "hitting" on arom For example, if an article of clothing that was worn recently had come into contact with marijuana smoke, it would retain an aroma. If it was then placed on a desk or in a locker, the locker or desk could also retain an arom i l
The licensee's investigation into alleged drug activities at Peach '
Bottom will continue. The resident inspectors will keep abreast of further activitie l l
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I 10.3 Suspected Drug Paraphernalia Found During Routine Access Sear:.:h l On November 9, 1987, during a scan of a lunch box by the x-ray system, the guard observed what he suspected to be a metal paraphernalia pipe. The guard requested and was granted !
permission to perform a hand search of the lunch box by the owne l The guard found a small closed suede bag. The individual refused i to allow the guard to open the bag, retrieved the bag and lunch j box, and exited the guard house. The individual was a contractor i employee who had access to the protected and vital areas. The I individual's access was subsequently cancelled after refusing a ,
searc l On November 12, 1987, the individual attempted to gain access to the protected area following the above incident. His access was denied. He was then interviewed by security officers and stated that he had inadvertently left firecrackers in the suede bag in his lunch box from the previous day's activities at the beac Explosives are prohibited items. The individual has been denied any access to the plan .4 Bomb Threats on November it and 20, 1987 The control room, the station telephone operator, and a guard received seven anonymous telephone bomb threats on November 18 and 20, 1987. The calls were received from a male caller who in a raspy voice whispered: "there's a bomb". No specific mention of Peach Bottom .9er time / location was included in these bomb threat The licensee implemented the security procedure for a bomb threat in each instance. This included additional searches of personnel entering the protected area and a search of plant buildings by security and operations personnel. Nothing abnormal was noted during the searches. The licensee evaluated the threats as having no supporting evidence and not to be explicit threats. The licensee notified the senior resident inspector and made ENS call The ir,spector reviewed the licensee's bomb threat procedures and interviewed the individuals who received the calls. The inspector independently searched the control room and selected plant vital areas. Nothing abnormal was located. In addition, a review of the licensee's investigation was performed. No violations were note .5 Drug Investigation Results In Arrests by the FBI On November 18, 1987, the FBI arrested six individuals who are accused of drug distribution at the Peach Bottom Atomic Power Station and in the surrounding York County area. The indictment
'by a Federal Grand Jury sitting in Harrisburg charges all of the defendants with conspiracy to distribute and possess with the i
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intent to distribute methamphetamine. Four licensee and two contractor employees were involved. Two arrests occurred on sit The NRC was informed of this action by the licensee and the U. Attorney's office has issued a press releas The inspector monitored plant activities during these arrest .6 Weakness in Protected Area Access Control System-On November 20, 1987, the inspector identified a potential vulnerability in the protected area access control system. The licensee immediately instituted corrective actions. The licensee committed to a security procedure change as long term corrective action. The details of the potential vulnerability in the system, as well as combined immediate and long term corrective actions are identified in Attachment 2 The inspector will follow the licehsee's respo(SGI)
nse to to this this repor issue in a future repor .0 Assurance of Quality 11.1 Management Involyement in Plant Operations
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Licensee shift and plant management were noted as being directly involved in pursuing plant problems including problem .
identification, inv.estigation and corrective action implementation. Two specific examples include the Unit 2 fuel pool cooling system problems on November 4-5,1987 (see section 4.1.12) and the Unit 3 indicated reactor level decrease on November 25, 1987 (see section 4.1.2). In each case, shift and '
plant management were noted as being involved in assuring qualit Also, the inspector noted that the Shif t Managers conduct of the daily 8:30 a.m. meeting and the shift turnover meetings was goo .2 Worker performance Several instances of poor supervisory control of and craft worker ;
performance were noted during the inspection period. An ESF actua-tion on Unit 3 on October 26, 1987, caused a loss of shutdown cooling on both units (see section 4.2.1). This ave..t ::.- be attributed to a maintenance worker positioning instrument valves that he has no authority to operate. A loss of Unit 3 indicated reactor water level j on November 25,1987, (see section 4.1.2) can be attributed to poor l control of contractor worker '
12.0 In-Office Review of public and Special Reports The inspector reviewed the September and October 1987 Monthly Operating !
Reports. No deficiencies were note '
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13.0 Management Meetings 13.1 Preliminary Inspection Findings A verbal summary of preliminary findings was provided to the Manager, Peach Bottom Station at the conclusion of the inspectio During the inspection, licensee management was periodically notified verbally of the preliminary findings by the resident inspectors. No written inspection material was provided to the licensee during the inspection. No proprietary information is included in this repor .2 Attendance at Management Meetings Conducted by Region Based Inspectors Inspection Reporting Date Subject Report N Inspector Oct 10-23 Health Physics 87-26/26 Dragoun Nov 6 Rgactor Cavity 87-31/31 Rebelowski Seals Nov 6 Inservice Testing 87-32/32 Gregg .
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Nov 13 Eledtrical Open 87-34/34 Woodard Items Nov 13 Operator Team 87-35/35 Lange Evaluations Nov 19 Security 87-37/37 Bailey Nov 20 Pipe Replacement 87-33/33 Gray 13.3 NRC/PECo Management Meeting on November 20, 1987 On November 20, 1987, a management meeting was held at Peach Bottom Station. At this meeting, PECo discussed the status of actions in response to the NRC Order dated March 31, 198 The licensee presented their intentions for their Restart Plan submittals and the status of the Commitment to Excellence Action Pla The proposed corporate and plant reorganizations were also discussed. The inspector attendec '.nis meeting. The licensee submitted the slides utilized in che presantation in a letter dated November 23, 1987. These slides depict the proposed PECo corporate and plant reorgani:ation. This area will be reviewed in a future inspectio . - -
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ATTACHMENT 1
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l Peach Bottom Shift Rotation l I
Week Sun Mon Tue Wed Thu Fri Sat
'l 1 Off U 0 V U U Off 2 Off T T T T T Off 3 Off Off Off D 0 D D 4 0 0 Off Off A A A 5 A A A A Off Off N 6 N N N N N N Off EeX U= Utility T= Training D= Days (7:00 a.m. - 3:00 p.m.) i A= Afternoon (3:00 p.m. - 11:00 p.m.) l N= Nights (11:00 p.m. - 7:00 a.m.)
l 6 shifts, 6 week rotating schedule
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ATTACHMEtiT 2 a
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THIS PAGE CONTAINS SAFEGUARDS IllFORMATION AtlD Is fl0T FOR PUBLIC DISCLOSUR IT IS It4TENTIO!4 ALLY LEFT BLAtl i l
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