IR 05000277/1988034
| ML20205P836 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 10/25/1988 |
| From: | Linville J, Williams J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20205P833 | List: |
| References | |
| 50-277-88-34, 50-278-88-34, NUDOCS 8811080325 | |
| Download: ML20205P836 (34) | |
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a V. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket / Report No. 50-277/88-34 License No. DPR-44 50-278/88-34 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:
September 3 10 October 14, 1988 Inspectors:
T. P. Johnson, Senior Resident Inspector R. J. Urban, Resident Inspector L. E. Myers, Resident Insoector J. H. Wtiliams, Project Engineer
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J. Gadzala, Reactor En ineer Reviewed By:
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A1.' Williams, Pr fect Engineer date
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Approved By:
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C#1.:invillpf' Chief, Mate
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f actor Pr'ivets Section 2A, ivision of Reactor Projects Summary Areas Inspected:
Routine, on site regular and backshift resident inspection (231 hours0.00267 days <br />0.0642 hours <br />3.819444e-4 weeks <br />8.78955e-5 months <br /> Unit 2; 212 hours0.00245 days <br />0.0589 hours <br />3.505291e-4 weeks <br />8.0666e-5 months <br /> Unit 3) of accessible portions of Unit 2 and 3,
operational safety, radiation protection, physical security, control room j
activities, licensee events, surveillance testing, refueling and outage activities, maintenance, and outstanding items.
Rcsults: Two containment isolations occurred due to personnel e ro n associated with unauthorized opening of power supply breakers (section 4.2.1 and 4.2.4).
An inadvertent condensate pump start occurred when a u rker caused a sheet in a valve liwit switch compartment (section 4.2.4).
LER quality e -
imeliness were nnted to be improved (section 6.0 and 11.0).
Two lice
'dentified violations were noted:
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failure to have a firewatch
, 6.2.4); and (2)
failure to have an adequate surveillance
test for 1 th minimizer (section 6.2.7).
Concerns were noted assoc!ated.<itt <.he adequacy of surveillance test procedure implementation of the Technical Specification surveillance requirements (sections 7.1, 7.2 and 11.C).
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e TABLE OF CONTENTS Page 1.0 Persons Lontacted............................................
2. 0 Fa c i l i ty a n d U n i t S t a t u s.....................................
3.0 Previous Inspection Item Update.............................
4.0 Operations Review...................
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4.1 Station Tours..........................................
4.2 Follow-up on Events....................................
4.3 Logs and Records...............
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5.0 Refueling Outage Activities.................................
6.0 Review of Licensee Event Reports............................
7.0 Survet11ance Testing...........
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8.0 Maintenance Activities......................................
9.0 Radiological Controls.......................................
10. 0 P hy s i c a l S e c u r i ty...........................................
11. 0 A s s u ra n c e o f Qu a l i ty........................................
12.0 In-Office Review of Special Reports.........................
13.0 Unresolved Items............................................
' 4. 0 t% n a g eme n t Me e t i n g s
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DETAILS 1.0PersonsContactg J.-B. Cotton, Superintendent, Operations
- T. E. Cribbe, Regulatory Enginee;-
- G. F. Daebeler, Supirintendent, Technical J. W. Devlin, Nuclea-Security Specialist
- J. F. Franz, Plant Manager J. L. Fulton, Superint endent, Fire Protection
- D. P. LeQuia, Superintendent Services
'f. N. Mitchell, Operations Cupport Engineer
- F. W. Polaski, Assistant Superintendent, Operations K. P. Powers, Peach Bottom Project Manager J. M. Pratt, Manager, Peach Bottom QA G. R. Rainey, Superintendent, Maintenance
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D. M. Smith, Vice President, Peach Bottom Atomic Power Station
- J. T. Wilson, Quality Support Superintendent Other licensee and contractor employees were also contacted.
- Present.at exit interview on site and for summation of preliminary findings.
l 2.0 Facility and Unit Status 2.1 Unit 2 The unit remained in cold shutdown during the inspection period.
System maintenance outages continued during the period.
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Preparations for the hydrostatic test were in progress at the end of the period.
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2.2 Unit 3 The unit remained defueled during the inspection period.
Pl ar.t modifications, corrective and preventive maintenance, and system testing were performed.
3.0 Previcus Inspection Item _ Update (92701, 92702)
3.1 (Closed) Inspector Follow Item (277/88-20-01; 278/88-20-01).
Measurement control evaluation of nonradiological chen,istry. On completion of the analyses of water samples (spiked Samples) by the licensee and Brookhaven National Laboratory, a statistical evaluation was to be made.
The analyses were completed and an evaluation was performed.
The analytical comparisons for the items were acceptable. These are presented in Attachment 1 to this report.
The inspector follow itam is closed.
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3.2 (Closed) Unresolved Item (277/88-02-05; 278/88-02-05).
Impact of non-safety related modifications.
ihe licensee completed their review of this item and reported the results in LER 2-87-31, Rev.
2 (section 6.2.2).
The unresolved item is closed.
3.3 (Closed) Unresolved Item (278/85-07-01).
Technical Specifications (TS) regarding containment cooling subsystems.
The licensee submitted a TS amendment request dated August 26, 1988, addressing containment cooling subsystems.
This TS amendment includes the torus ccoling, drywell spray and torus spray modes of RHR.
The licensee has been using interim TSs to address this concern including operability requirements, action statements and surveillance requirements.
NRR is currently reviewing the TS amendment request.
The unresolved item is considered resolved and is closed.
The inspector will review the actual amenument, when approved, in a future inspection.
3.4 (Closed) Inspector Follow Item (277/85-29-04).
Technical Specification (TS) change for core spray sparger itne break instrument.
TS Table 4.2.B and 4.5.A have different calibration check frequeccies.
The licensee is using the more conservative frequency of three runths in lieu of six months. The licensee is initiating a TS change for this minor discrepancy.
The inspector follow item is considered closed.
3.5 (Closed) Inspector Follow Item (277/86-16-02).
Technical Specification (TS) surveillance requirements when a diesel generator (DG) is out of service.
The current TS 4.5.F.1 requirer, daily testing of emergency core cooling system pumps when a DG is out of service.
The licensee submitted a TS change dated August 26, 1988, to eliminate the unnecessary and redundant pump testing.
NRR is currently reviewing this TS request.
The inspector follow item is considered closed.
Implementation of the approved TS amendment will be reviewed in a future inspection.
3.6 (Closed) Violation and Unresolved Item (277/87-17-02 and 03).
Control roon ventilation radiation monitor (CRVRM) inoperability and related surveillance testing.
The licensee responded to the violation at en enforcement conference on August 13, 198}, and in a letter dated October 8,1987.
The licensee's analysis concluded that the system would have activated even though it was imp.operly piped.
The delay of actuation was determined to be 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> with a calculated 20 mrem increase in thyroid dose to control room operators.
Licensee corrective actions included correct pipe realignment of the system, a check of all other radiation monitor systems, and a check of other safety systems which have process sensing lines. No other systems were found piped incorrectly.
The NRC issued a severity level four violation in a letter dated September 8, 1987.
The inspector reviewed the licensee's response
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-5-and their program for verification of safety related systems process sensing lines.
The inspector also reviewed the revised surveillance test (ST) procedures for the calibration, calibration check and functional test for the CRVRM system.
Selected completed STs were also reviewed (see section 7.1).
The inspector reviewed the licensee's calculation number ME-245 for the CRVRM high and high-high trip setpoint determination dated August 12, 1987.
The inspector also verified that these setpoints were implemented in the appropriate STs.
No unacceptable conditions were noted.
Based on the above items, the violation and uniosolved items are closed.
3.7 (Closed) Violation (277/88-10-02; 278/88-10-02).
Failure to submit timely licensee event reparts (LERs).
The licensee responded to the violation in a letter dated.Nne 17, 1988. The licensee concluded that there were three reasons for the late LERs:
(1) Ineffectiva management of the LER preparation process by the Nuclear Services Department Licensing Section; (2) Failure to develop in a timely manne-the technical information needed to prepare the LER or to develop a realistic schedule for submittal; and, (3) Failure of the Nuclear Engineering Department to review the LER draf ts in a timely manner.
The licensee has implemented the following corrective actions to ensure LER submittal in an expaditious manner:
(1) Reportability evaluation and notification to the Licensing Section; (2)
Identification of an LER information contact; (3) Obtain and/or develop all pertinent information; (4) Draft the !ER; (5) Re <ew by ap9ropriate philadelphia Electric Company technical and management personnel; and, (6) Rewrite and re-review as necessary
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to obtain approval. Other licensee corrective action includes improvements in the management of the preparation process, improvements in the interface between Nuclear Engineerina Department and the Station, and improvements in the cE.
acking process by the on site regulatory group.
The inspector reviewed the licensee's submittal, verified corrective actions, and discussed this item with licensee regulatory and management personnel.
The inspector has noted improvements in the timeliness and in the quality of recent LERs (see sections 6.0 and 11.1 of this report).
Based on the licensee's response and improvements in submitted LERs, the violation is closed.
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-6-3.8 (Closed) Violation (277/88-10-01; 278/88-10 s1).
Seismic adequacy of control room panels.
The violation concerned control room panels that were not anchored as depicted in drawing E-1315, Sheet 146.
In response, the licensee committed to examine safety related panels in the cable spreading room and in the balance of the plant.
Modification (MOD) 2376 was initiated to examine all safety related panels at Peach Bottom, and to correct those that were nonconforming.
All 76 control room panels were welded. bolted, and accepted by Quality Control (QC). Of 59 safety related panels
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examined in the cable spreading room, 18 were found acceptable.
The remaining panels were welded, bolted, and accer.ted by QC. Of 99 safety related pancis in the balance af the plant, three panels were bolted and accepted by QC.
For the review, the inspecto" reviewed MOD rackage 2376 and Quality Assurance Audit Repcrts SS-88-05 and 11; and, observed field welding of various panels. Tne inspector also compared some completed panels with design drawings.
Both audit reports revealed r.o discrepancies and the inspector did not observe any nonconforming conditions. This item is closed.
3.9 (Closed) Inspector Follow Item (278/86-05-01). This item questioned the adequacy of the basis for the Condensate Storage Tank (CST) dike design.
FSAR section 9.2.4.1 assumes the maximum spill from the CST is 200,000 gallons due to tank rupture.
This spill is contained by the dike desigr.
The CST spill of February 16, 1986, demonstrated that the maximum radioactive water inventory in the CST can be greater than 200,000 g.llons.
The CST filled to the internal overflow line (200,000 gallons), continued to fill to the tank top (an additional 22,500 gallons) and spilled an undetermined amount (over 36,000 gallons)
from the top vent.
The tank was slightly pressurized during the
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event and showed that an inventory greater than 200,000 gallons could be introduced into the dike structure.
This scenario goes beyond the design for the dike and is not addressed by NRC regulations.
General Design Criteria (GDC) 60 of 10 CFR 50, Appendix A, requires the design to include means to control the release of radioactive liquids during anticipated operational occurrences.
Regulatory Guide 1.143 paragraph 1.?.5 states that outdoor tanks should have dikes to prevent runoff in the event of ov6rf'
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NUREG 0800, Section 15.7.3 provides acceptance criteria fw the results of a tank failure as radionuclide concentrations not in excess of the limits of 10 CFR 20, Appendix B, Table II, Column 2 at the nearest potable water supply in an unrestricted area.
For th's analysis 80*. of the tank volume is used.
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the analysis done in accordance with Section 15.7.3 meets the accep-tance criteria, the NRC staff currently concludes that the design meets GDC 60 for control of radioactive releases resulting from tank failures.
The licensee's original design :alculation for the dike considered only hydrostatic loads and therafore was not designed as c Class I structure, as stated in FSAR Section 9.2.4.1.
For Class I structures the load combinations of FSAR Section C 2.6.1 must be considered.
PECo calculation ME-333, performed June 22, 1988, determined that the dike was capable of containing the contents of the tank in the event of the Design Earthquake.
This analysis was done in accordance with the loading and stress criteria of Appendix C of the FSAR.
The CST dike was determined to have a capacity in excess of the current NRC design criteria for dikes and of the CST capacity of 240,000 gallons.
An FSAR change was initiated to delete the seismo. Class I designation.
The inspector reviewed the licensee's safety evaluation for the proposed FSAR change.
No concerns were identified during this review and this item is closed.
3.10 (Closed) Violation (278/86-05-06).
Failure to perform a safety evaluation for the change in the Condensate Storage Tank (CST)
dike design, and higher radioactivity inventory levels in the CST.
This was a violation of 10 CFR 50.59.
The licensee responded to the violation in a letter dated August 15, 1986.
The corrective actions included writing a procedure, CH-10, Chemistry Goals, to administratively cor, trol the radioactive inventory of the CST, refueling water storage tank (RST) and the torus dewatering storage tank (TST) in order to maintain radioactivity levels below FSAR ":ble 9.2.7 values.
Should plant operation require that these levels be exceeded the procedure calls for a safety evaluation to be performed.
The inspector reviewed procedure CH-10 and discussed it with staff engineers.
The CST moat was repaired and resealed shortly after tha event.
Further, signs were installed which indicate the moats are barriers to the release of iiquid effluents and must not be violated without plant management approval.
The inspector verified the moat was repaired and the signs were installed. However, signs on the Unit 3 CST and TST dike walls have been blocked from view by trailert When brought to licensee's attention, they indicated that actions would be taken to correct this problem.
The radioactivity inventory of the TST was only recently added to the FSAR after a PECo QA finding of the deficiency in December 1987.
The action level for the TST given in CH-10 is larger than the FSAR Table 9.2.7 value.
The licensee indicated the values would be made consistent.
In addition, FSAR Table 9.2.7, Rev. 6 was noted to be missing the proper units on radioactivity.
Changes to the FSAR will be reviewed when they are made.
Other than the inconsistencies described no further concerns were noted.
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-8-3.11 (Closed) Unresolved Item (278/86-05-05). A loss of work control in January and February of 1984 associated with correcting heat trace deficiencies made the CST heat trace sptem inoperable with uninsulated lines and the holes to remain'in the dike for two years.
In December 1984 and November 1985 even though the heat trace alarm was lighted, the dike had two large holes in it and CST piping was not insulated. Discussions with plant operators indicated that the plant' has apparently operated since original startup without adequate procedures for assessing the operability of the non safety related CST heat trace system. These items were unresolved.
As a result of the NRC concerns, the licensee made assessments of the heat trace system in March 1986 to determine the condition of
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these systems. Many problems were discovered during these assessments; such as missing insulation, corrsion, non-operable i
circuits and alarms. This troubleshooting resulted in the licensee initiation of 32 Equipment Trouble Tags (ETTs), two i
Suspected Maintenance Request Forms (SMRFs) and four Maintenance t
Request Forms (MRFs).
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RT 6.1, Heat Trace System Test,ing, was written in 1986 to ensure that the heat trace systems were properly installed and conformed
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to design requirements prior to energization for winter use.
This test was to be performed each October.
Because of inoperable heat trace systems, +.hree partial tests were performed on October 31, 1986; Novemba: 17, 1986 and Decein!;er 1,1986. Nine MRFs were written to correct problems identified during these tests.
RT 6.1 was converted to ST 21.17 in PORC Meeting No. 87-12 dated January 26, 1987. ST 21.17 was performed February 25, 1987, and resulted in 20 EITs and six MRFs.
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As a result of the experience descrioed above, the licensee initiated Modification 86-132 and 86-136 to replace all the Electrowrap Heat t
Tracing with Auto Trace.
Electrowrap heat tracing is no longer
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manufactured.
Repairs to the heat trace system using a different
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type heat trace prior to the modific1 tion resulted in fsise indication and/or no indication on many circuits. MOD 86-136 provides 31 arms
and indications consistent with the self-limiting heat trace tape
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characteristics. Modification Acceptance Test (MAT)86-136 was i
performed J:nuary 26, 1988, to verify proper operation of the heat l
trace system.
The inspector reviewed the MOD packages, including the r
Safety Evaluations, PORC reviews and the MAT. As part of the MOD process, a shift training bulletin as written to inform operations personnel of the new system.
This information was included in Reading Package 88-04C for Non-Licensed Operators and was sent out August 15, 1988.
The inspector noted that essentially all non-licensed operators had completed the required reading package. As a result of on going drawing updates, the MOD is 5*.111 cpen.
No concerns were identified as a result of the inspector. review of the M00s.
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-9-After repairing the heat trace systems and completing ST 21.17, it was determined that the Outside Auxiliary Operator could adequately check the operability of the heat traca systems on his rounds.
Round sheets were updated to reflect the proper indication on the various heat trace panels.
The inspector reviewed several Round Sheets which were completed properly.
This was an improvement in maintaining operability.
As a result of the experience a heat trace system test engineer position was created.
The inspector found the System Engineer knowledgeable of the heat trace system.
The incident with the Unit 3 CST resulted in a comprenensive program on the part of the licensee to upgrade the heat trace system and provide adequate controls and information to assess operability.
The inspector had no further concerns and this unreiolved item
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3.12 (Closed) Unresolved item (277/87-25-01; 278/87-25-01). Diesel Generator Cardox Injection as built versus designed logic discrepancies.
See section 5.2 and 6.2.1 of this report.
3.13 (Closed) Violation (277/87-17-0'j.
Failure to perform ST 12.2 on the A and B loop drywell spray neaders.
The licensee responded to the violation in an August 31, 1987, letter from J. W. Gallagher to W. F. Kane.
Corrective actions consisted of:
completing ST 12.2 on September 25, 1987; reviewing all STs with a frequency greater then a year and verifying that they were scheduled correctly; and reviewing all STs with a frequency greater than a year to ensure
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that there were no outstanding partially completed tests that were not being properly tracked.
To prevent future recurrence, Administrative Procedure A-43,
"Surveillance Test Program " was revised to ensure that partially completed STs are reviewed by a PORC member.
In addition, the STARS program was modified so that partially completed STs can be entered into the system to be tracked until completion.
The inspector reviewed corrective actions and A-43, and discussed this item with the ST coordinator.
The inspector had no concerns and this iten is closed.
3.14 (Closed) Unresolved Item (277/87-32-04; 278/87-32-04).
Emergency Service Water (ESW) pump discharge check valve 33-0-515A and B testing.
The ESW check valves were not being full stroke tested per ASME inservice testing (IST) code requirements The licensee revised surveillance test (ST) 6,3, Revision 16,,.
88, to comply with the code requirements.
The inspector reviewed t.ie IST plan and ST 6.3.
No unacceptable conditions were noted.
The unresolved item is closed.
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o-10-4.0 Operations Review 4.1 Station Tours (71707)
The inspector observed plant operations during daily facility tours.
Most accessible areas of the station were inspected.
4.1.1 Control Room and facility shift staffing were frequently checked for compliance with 10 CFR 50.54 and Technical Specifications.
The presence of a senior licensed operator in the control room was verified frequently.
Operator attentiveness to plant operations was determined to be
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adequate.
4.1.2 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 limits.
Engineered safeguards features system switch positioning and valve lineups were verified daily based on control room indicators and plant observations.
4.1.3 Selected control 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 conditions.
4.1.4 The inspector checked for fluid leaks by observing sump status, alarms, and pump-out rates; and discussed reactor coolant system leakage with licensee personnel.
4.1.5 Shift relief and turnover activities were monitored daily, including periodic backshift observations, to ensure compliance with administrative procedures and regulatory guidance. No inadequacies were identified.
4.1.6 The inspector observed the main stack and both reactor building ventilation stack ridiation monitors and
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recorders, at,d periodically reviewed traces from
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backshift periods to verify that radioactive gas release rates were within limits and that unplanned releases had not occurred. No inadequacies were identified.
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 m
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controls, checked a sampling of fire barriers for integrity, and observed fire-fighting equipment stations. No inadequacies were identified.
4.1.8 The inspector observed overall facility housekaeping -
conditions, including control of combustibles, loose trash and debris. Cleanup was checked during and'after maintenance.
Plant housekeeping was generally acceptable.
(See section 5.3 regarding a tour of the Unit 2 arywell and torus room.)
4.1.9 The inspector observed the shutdown nuclear instrumentation subsystems (source range and intermediate range monitors)
and the reactor protection system to verify that the required channels were operable. On October 3, 1988, the source range monitor (SRM) counts per second for Unit 2 were as follows:
SRM A - 9, SRM B - 4, SRM C - 4, SRM 0 -
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In an engineering letter dated May 4, 1988, the licensee projected the Unit 2 SRM count rate to be the following values effective January 1989:
- 6, SRM D - 4.
Similar count rates were projected for Unit 3.
In addition, the licensee submitted a Technical Specification (TS) change dated September 7, 1988, requesting a SRM count rate of less than three. The inspector will continue to follow this area, including the TS amendment.
4.1.10 The inspector frequently verified that the required off site electrical power startup sources and emergency diesel generators were operable.
4.1.11 The inspector :nonitored the frequency of plant and control room tours by plant and corporate management.
The tours were generally adequate.
4.1.12 The inspector verified on a weekly basis, the operability of selected safety related equipment and systems by in-plant checks of valve positioning, control of locked valves, power supply availability, operating p*ocedures, plant drawings, instrumentation and breaker posit.ioreing.
Selected major components were visur.11y inspected for leakage, proper lubrication, cooling water supply, operating air supply, and general conditions.
No significant piping vibration was detected.
The inspector reviewed selected blocking permits (tagouts) for conformance with licosee procedures.
No inadequacies were identified.
4.1.13 The inspectors performed backshift and weekend tours of the facility on the following days:
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September 9 1988; 3:45 a.m. - 5:00 a.m.
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September 11, 1988; 5:10 a.m. - 10:40 a.m.
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September 27, 1988; 10:00 p.m. - Midnight
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September 28, 1988; Midnight - 5:00 a.m.
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October 2, 1988;.6:00 a.m. - 11:00 a.m.
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4.1.14 Record breaking summer temperatures caused some plants to operate at reduced efficiency due to high temperature of the heat sink (lake br other body of water). Since this plant was shut down by Order, there was no'
temperature effect on the operation of the plant.
However, the Conowingo Pond heat sink did increase'in temperature to a peak of 90.5 degrees F in mid-August 1988. Discussions with the licensee indicate that, with the plant operating, natural circulation of the reservoir is created by in and out flows from the reservoir. This effect would have added heat to the reservoir. The licensee has studied the effects of high temperature of the heat sink on plant efficiency.
For example, if the inlet of the heat sink is 90 degrees F, the plant's operation output is reduced by 2%. There is no Technical Specification (TS) which addresses limitations on the plant thermal power output due to high heat sink temperatures.
Environmental TS address recording of the inlet and discharge canal flow rate.
When the river flow is less than 15,000 CFS, the thermal plume of the discharge canal is logged.
Procedure ST
6.14, revision 16, "River Temperature Monitoring",
provides for the Environmental TS recordings and for state environmental imposed conditions for operation of cooling towers depending on the outlet temperature of the discharge canal and the power levels of the units.
No unacceptable conditions were noted.
4.2 Follow-up On Events OccurHng During the Inspection (93702)
4.2.1 Unit 2 Group II Isolation on September 13, 1988 At 9:48 a.m., on September 13, 1988, the Unit 2 control room received alarms indicating actuation of the group
'I primary containment isolation system (PCIS).
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PCIS valves closed and shutdown cooling isolated.
The group II isolation was reset at 1:15 p.m., and shutdown cooling was restored at 4:48 p.m.
A four hour emergency notification system phone call was made to the tiRC at
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h The cause of the group II isolation was investigated by the-licensee immediately following the event.
The Shift Technical Advisor verified that no fuses were blown and
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no personnel were working in associated panels in the cable spreading room. 'In addition, a check of the associated instrument racks revealed no individuals working in the area. The most credible cause of the event was postulated to be momentary de-energization of.
power from two separate distribution panels (120 volt AC instrument power).
The licensee obtained a security zone trace to determine
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who was in the cable spreading room at the time of the occurrence. After interviewing numerous personnel, the licensee determined that two workers had accidentally turned off power in both distribution panels while performing maintenance on the public address system.
Both individuals were disciplined and were reminded of attention to detail when manipulating switches in the
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cable spreading room.
The inspector reviewed the suspected licensee event report, spoke with operations personnel and attended a
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critique on September 14, 1988.
The critique was effective and focused resources to investigate alternate paths that may have caused the event. The insnector questioned the licensee's corrective actions that would
prevent this type of event from occurring in the future.
The licensee stated that this issue would be addressed in a future LER revision. The inspector also reviewed LER 2-88-21 regarding this event (see section 6.2.13).
1.2.2 sectrical Switchgear Breaker problem
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On September 19, 1988, the licensee made a four hour j
telephone notification to the NRC regarding a mechanical
problem associated with cell switches in safety related
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4KV switchgear breaker compartments.
The E-3 diesel t
generator output breaker (E-33) cell switch actuator arm
was found bent on September 14, 1988. The licensee
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investigation determined that a mechanical interference l
with the breaker And the cell switch caused the problem t
when the breaker was rolled into its compartment. The i
licensee conducted inspections of 15 similar breakers
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and noted two additional bent actuator arms.
Licensee t
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engineering performed a review of this condition and
determined the event to be reportable. The licensee's l
corrective actions include an inspectt:,n of the breaker
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compartment prior to reinstallation, revisions to i
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appropriate procedures an'd a functional test of the
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breaker after it is rolled into the compartment.
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The inspector monitored the ENS call; reviewed the
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licensee's suspected. licensee event report (LER) and-evaluation reports; discussed the item with licensee engineers; and, inspected selected breaker compartments in the field..The LER will be reviewed in a future inspection.
In addition, the licensee's longer term
corrective actions will also be reviewed dur'ng a future inspection.
4.2.3 Inadvertent Start of the Unit 2 Condensate pump
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At 2:02 p.m., on September 22,-1988, the control room received a condensate. pump hi-vibration alarm.
The
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reactor' operator noticed that the 2A condensate pump control switch light indicated on, hetwell level was decreasing, and discharge pressure was increasing. At 2:03 p.m., the reactor operator secured the 2A condensate pump by turning the control switch to stop.
In addition, control power to the pump motor was removed and blocked, and the motor breaker was later racked out and blocked.
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Initial' conditions prior to the pump start were as
'l follows:
control switch in normal and tagged out; 2A condensate pump motor breaker racked in; suction valve full open; and, motor operated valve analysis testing
(MOVAT) performance on the pump suction valve. With these conditions, the condensate mator starting circuit is complete except for turning the control switch
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to start. The licensee concluced that the cause of the i
pump start was either a mechanical malfunction or a breaker closure signal in the pump start logic.
The licensee's investigation revealed no mechanical
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f malfunctions.
The licensee also determined that no one was in the control cabinet located in the cable spreading room.
The remaining feasible possibility to start the pump would be inadvertent shorting in the suction valve limit switch housing. Shorting 125 VDC in i
the start circuit logic downstream of the control switch could start the pump.
Licensee pers:snnel interviewed the MOVAT contractor and found him to be knowledgeable. He believed that he did not cause a short in the limit switch housing.
However, after recreating the contractor's actiuns, the licensee determined that he had been leaning over the open limit
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switch housing hand cranking the valve open. His metal
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pocket dosimeter or a wire ring on his. steno pad could have inadverte.atly shorted terminal #3 to terminal #2.
This action could have started the pump. After exhausting all other possibilities, the. licensee believes that shorting in the limit switch housing the caused the P.A condensate pump start.
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The inspector spoke with operations personnel, reviewed preliminary upset report P-2-88-21, toured the i
condensate pump room and reviewed-control prints. The
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inspector stated that the pump motor breaker should have been racked out as part of ';he blocking permit.
The
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inspector had no further questions and no violations
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were noted.
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4.2.4 Unit 3 Containment Isolation on September 23. 1988
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At 10:00 p.m., on September 23, 1988, a loss of power occurred to the motor c. ',rol center that supplies power
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to the Unit 3 "A" reactor protection system (RPS). This
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loss of power caused a partial group III primary
containment isolation system (PCIS) actuation.
The RPS A power supply was being supplied by its alternate feed.
The licensee concluded that the power loss was caused by a worker bumping the RPS motor control center breaker compartment. Tb H, ection caused the breaker to open.
The inspector reviewed the licensee's preliminary upset report, operator logs and associated electrical schematic drawings.
The inspector a:so discussed this event with licensad operators and enqineers.
The LER
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and associated corrective actions will be reviewed in a j
future inspection report.
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4.2.5 Unit 2 Inadequate Seismic Gap j
l-During performance of modification 2339, "Upgrading of Unidentified Fire Barrier Material," on July 22, 1988,
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it was discovered that a seismic gap between the Unit 2 j
reactor building and the rAdwaste building was filled with t
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I concrete.
Nonconformance deport (NCR) CD-P-1458 was written to address the concern. After engineering
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reviewed the NCR, the condition was determined to be
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reportable because the seismic qualification of both r
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buildings was in quest.icn and possibly placed the plant L
in a condition outside of the design basis, j
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The licensee proposed the cause to have been formwork
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movement during concrete placement during construction.
The licensee performed a repair that basically consisted
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of chipping out concrete to create at least a 1/2" wide
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seismic gap, filling with molded compressible filler, and repairing damaged concrete.
In addition, the licensee inspected the same location between the radwaste building o_
and the Unit 3 reactor building. No discrepancies were found.
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During tne review, the inspector spoke with licensing personnel, reviewed NCR CD-P-1458, construction prints, and the SLER,
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and inspected the repair on the Unit 2 side and the seismic gap on the Unit 3 side.
No deficiencies were noted. The
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LER wil) be reviewed during a future inspection.
4.3 -Logs and Records (71707)
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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 leg validity, conformance with Limiting Conditions for Operations, and proper reporting. The following logs and records were reviewed:
Control Roorr. Shif t Supervisor Log, Unit 2 Reactor Operator Log, Unit
3 Reactor Operator Log, Control Operator Log, STA Log, QC Shift Monitor Log, Radiation Work Permits, Locked Valve Log, Maintenance Request Forms, Temporary Plant Alteration Log, Special Procedure Log, Information Tag Log, Annunicator Mode Log, Plant Status List, and Ignition Source Control Checklists.
Control Room logs were compared i
with Administrative Procedure A-7, Shif t Operations and the Operations Manual.
Frequent initialing of entries by licensed operators, shift
supervision, and licensee site management constituted evidence of licensee review. No unacceptable conditions were identified.
l 5.0 Refueling Outage Activities (60710)
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5.1 Limitorque Motor Leads
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i In combined inspection report 277/278; 87-07/07, the inspector reviewed the use of Nomex-Kapton insulated leads in de Limitorque
motor operators. At that time, there remained three de Limitorque
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motor operated valves in Unit 2 that could have had Nomax-Kapton t
insulation. These valves were-
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i M0-2-13-16, Steam Supply Outboard Isolation Valve
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MO-2-23-19, HPCI Pump Discharge Valve
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MO-2-23-20, HPCI Pump Discharge Valve
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The inspector reviewed three maintenance request forms (MRFs)
authorizing inspection of the wiring inside the three suspect motor operators.
These MRFs were:
2-13-M-8704226 (RCIC 16)
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2-23-M-8704227(HPCI19{
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2-23-M-8704228 (HPCI 20, t
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None of the three motor operated valves contained Nomex 'Capton insulation. All motor leads were found to be acceptable..
The inspector had no further questions or concerns. No violations were noted.
5.2 Diesel Generator (DG) Cardox Modification (37700)
In October 1987, an inadvertent Cardox system actuation without iniection occurred in the E-4 DG roon.
The licensee's investigation determined that the actuation of the Cardox injection system was found to be a "1 out of 4" logic rather then the designed "2 out of 4" coincident logic (see NRC Inspection 277/87-25, section 4.5.3).
Since a Cardox injection signal trips the DG (except during a loss of coolant accident signal start), a single heat sensor failure or actuttion could disable the respective DG, During the investigation, the licensee determined that the DG Cardox System was not seismically qualifted. The safety-related components and the power supply were common to all four DGs as detailed in LER 2-87-28 (section 6.2.1).
During a loss of off site power event concurrent with a seismic event, the DG could be tripped by the Cardox system relay.
Thus, a common cause event could affect the ability to safely shut down the plant during a seismic event.
The relays were pneumatic-electric relays with mercury tube switches that actuate the Cardox system upun initiation by the heat detectors.
The relays were not seismically qualified and could actuate in seismic events.
The licensee modified the Cardox system by performing Modification (MOD) 2390.
This MOD replaces the Cardox system controls with seismically qualified, safety related components and provides a separate power circuit to the system panel of each DG.
In addition, the heat detectors provide a 2 out of 2 logic for each of eight locations in each DG room (16 detectors per room).
The heat detectors are seismically qualified, rate compensated detectors. The detectors trip on 190 d?grees F limit or on fast temperature rise.
The old heat detectors were fixed 15 degrees F rate of rise and 190 degree F limit with a one time response on temperature limit.
The inspector reviewed MOD package 2390, discussed the work with cognizant engineers and observed work on the system in the field.
The MOD work is nearing completion.
The licensee has adequately responded to the as-built versus as-designed logic and identificd a common cause failure in the system. The completed MUD work will be reviewed in a later inspection report.
The inspector had no further questions. No unacceptable conditions were noted.
The unresolved item is closed 'isee section 3.12).
5.3 Unit 2 Drywell and Torus Room Tour o,n September 29, 1988 The inspector conducted an inspection and detailed tour nf the Unit 2 drywell and torus room to check on general equipment
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-18-conditions, status of work in progress, housekeeping, and radiation protection controls. OveraII, the general conditions in these areas were determined to be adequate.
Temporary equipment was arranged with no excessive amounts of loose material.
New labeling and flow indicators permitted quick and accurate system identification in the torus room.
The inspector gave special attention to pipe snubbers in the drywell.
No deficiencies were noted.
The inspector noted the safety consciousness of a plant employee enforcing requirements for wearing hard hats in the torus room.
The inspector noted obscene graffiti in the drywell. Although much of it appears to date from initial construction, removing it should be justified on an ALARA basis for expenditure of man-rem.
The inspector discussed this graffiti concern with licensee management.
A questionable practice was observed regarding the station's ALARA program. A visiting inspector was required to be accompanied by a.
health physicist technician during the inspector's tour of the drywell to ensure his administrative exposure limit of 100 mrem was not exceeded. Although the accompanying health physicist technician was knowledgeable, this practice effectively doubles the man-rem expended.
This item was discussed with licensee personnel. The licensee indicated that they were addressing this concern.
The inspector will review this in a future inspection.
5.4 Diesel Generator (DG) Fuel Oil System The licensee initiated an upgrade to the diesel generator fuel oil surveillance program to the guidance specified in NRC Regulatory Guide 1.137, Revision 3 (October 1979) "Fuel Oil Systems for Standby Diesel Generator".
This upgrade resulted in proposed changes in the Technical Specifications (TS) concerning surveillances for water in the DG storage and day tanks; sampling the fuel for particulates; and, sampling in accordance with ASTM 04057-81. The oil is analyzed for specific gravity, kinematic viscosity, flash point, color, clarity, and other tests for properties specified in ASTM 0975-01.
The tanks are checked for cathodic protection, and are drained and cleaned every ten years.
To support the TS, new sampling techniques were tested.
The licensee noted that previous sampling methods of the storage tanks did not sample from the bottom of the tank but six or eight inches from the bottom.
The previous procedure did not sample the bottom of the tank for water.
Bottom samples of each tank revealed substantial amounts of water in the fuel and some sludge.
Analysis of the sludge and water in the samples demonstrated that
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-19-there was substantial anaerobic acid producing bacteria and sulfate-reducing bacteria in the samples. The sulfate-reducing bacteria and acid producing bacteria cause microorganism induced corrosion (MIC) and create the sludge.
The licensee pumped out each storage tank from the bottom to remove the water and sludge.
The E-1 DG fuel oil storage tank was completely emptied of fuel so that visual and ultrasonic tests could be done to determine if any and to what extent corrosion of the carbon steel tank was caused by the microorganisms.
The tests indicated there was no corrosion in the carbon steel metal or the welds in the tank where MIC effects are expected. The E-3 DG tank was being examined in the same manner at the close of the inspection period.
The PORC approved sampling and analysis procedures storage for the DG tanks, which require composite fuel samples, bottom sampling for water, and removal of water if found. To determine the particulate (microorganisms) quantity the licensee will use ASTM 2276-78, method A, with the exception that they will use filters of nominal pore size up to three microns in size.
Licensee studies in the use of one micron filters indicated an inordinate time is required to do the analysis, and it is subject to large variance, hence the change to three micron filter size which results in rapid and reliable analysis.
The day tank will be sampled for water. Other surveillances address the cathodic system, flushing the fuel system if water is found in the system, changes in the full load test frequency, and various analyses of the fuel oil.
The inspector reviewed the licensee's related procedures and discussed this item with cognizant licensee engineers and chemists.
The inspector also attended licensee meetings to resolve problems.
The TS amendment will be implemented November 30, 1988.
The inspector had no further questions.
6.0 Review of Licensee Event Reports (LERs)
6.1 LER Review (90712)
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 follow-up.
The following LERs were reviewed:
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ai-20-V LER No..
LER Date Event Date Subject 88-508 Inattentive guard on a compensatory post 09/01/88 08/03/88 88-509 Inadequate compensatory post for a degraded 09/02/88 vital area barrier 08/06/88 88-S10 Degraded vital area barrier 09/26/88 08/27/88 88-511 Inattentive guard at Unit 2 drywell 09/23/88 08/24/88
- 2-87-28, Rev. 2 Diesel generator trips during loss of off site 08/01/88 power 12/17/87
- 2-87-31, Rev. 2 Extraction steam modification resulting in 08/01/88 being outside design basis 12/31/87
- 02-88-01, Rev. 1 Blown fuses caused the A core spray logic 08/18/88 failure with plant shutdown 04/28/88
- 2-88-15 Failure to post a es +inuous fire watch
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07/26/88 06/28/88
- 2-88-16 Electrical distribution system outside design 08/01/88 basis 07/01/88
- 2-88-17 Shutdown cooling isolation caused by personnel 08/05/88 error 07/05/88
- 2-88-17, Rev. 1 Shutdown cooling isolation caused by personnel 09/26/88 error 07/05/88
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- 2-88-18 Inadequate rod worth minimizer surveillance 09/19/88 test 08/19/88
- 2-88-19 Shutdown cooling isolation due to deficient 09/15/88 blocking permit 07/29/88
- 2-88-20 North substation fire and ESF actuation 08/26/88 07/29/88
- 2-88-21 Primary isolation due to personnel error 10/06/88 09/13/88 3-88-01, Rev. 1 Primary containment isolation during DG and 09/26/88 bus switching 04/08/88 3-88-02, Rev. 1 RWCU isolation due to breaker trip 09/19/88 05/07/88 3-88-03, Rev. 1 ESF actuations due to RPS alternate power 09/27/88 supply trip 05/20, 22/88 3-88-05, Rev. 1 RWCU isolations due to equipment failure 08/30/88 06/13/88
- 3-88-06 Containment isolation due to fuse failure 07/25/88 caused by personnel error 06/24/88
- 3-88-07 Containment isolation due to fuse failure 08/11/88 caused by personnel error 07/12/88
- 3-88-08 Containment isolations due to RPS trip 09/26/88 08/29/88
- 3-88-09 DG start due to feeder breaker trip 09/26/88 08/31/88
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-22-6.2 LER Follow-up (92700)
For LERs selected for follow-up and review (denoted by asterisks above), the inspector verified that appropriate corrective action was taken or responsibility was 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 site systems and components were also reviewed.
6.2.1 LER 2-87-28, Rev. 2 concerns a licensee identified design problem with the seismic adequacy of the diesel generator carbon dioxide (Cardox) system.
The licensee is implementing a modification (MOD) to upgrade the Cardox system with seismically qualified components.
The LER was previously reviewed in NRC inspections 277/88-10, 13; 278/88-10, 13.
The inspector reviewed portions of MOD 2390 including field installation (see section 5.2).
In addition, open item 277/87-25-01 (see section 3.12) was reviewed and is closed. No unacceptable conditions were noted.
6.2.2 LER 2-87-31, Rev. 2 concerns a licensee identified inadequate safety evaluation for a modification (MOD) to the feedwater heater extraction steam valves.
The event was reviewed in NRC Inspections 277/88-02, 10; 278/88-02, 10. As corrective actions, the licensee reviewed 39 non-safety related M00s to check their potential impact on safety.
Based on that review, the licensee concluded that the extraction steam modification was an isolated case.
The inspector reviewed the LER, the licensee's program for reviewing non-:afety related modifications, and discussed this item with licensee engineers and management.
No unacceptable conditions were noted.
6.2.3 LER 2-88-01, Rev. 1 concerns an event where blown fuses caused the Unit 2 A core spray logic to be out of service.
The unit was shut down at the time of the event.
The LER and the event were initially reviewed in NRC Inspection 277/88-18; 278/88-18.
The licensee determined that the cause of this event was operator error during blocking permit application.
The operator inadvertently grounded a wire; however, he did not recognize this condition.
The licensee discussed the event with the operator.
In addition, the new Operations Manual addresses the importance of ensuring care when applying blocks in safety related cabinets.
Tha inspector
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-23-reviewed the LER and the relative portions of the Opera +. ions Manual.
No violations were noted.
Operatcr performance during blocking and permit program implementation will continue to be reviewed during future inspections.
6.2.4 LER 2-88-15 concerns an event that occurred on June 28, 1988, regarding a fire watch in the cable spreading room.
Technical Specification (TS) 3.14.B.4.a requires a continuous fire watch in the cable spreading room when the Cardox system is out of service.
The fire watch was posted in the room; however, he left m thout proper relief, for approximately 20 minutes to perform another fire watch roving tour.
This is a licensee identified TS violation (277/88-34-01). However, it rets the criteria for not issuing a Notice of Violation.
The inspector reviewed the event end the LER, including corrective actions. The inspector discussed this with Itcensee management and had no further questions at this time.
6.2.5 LER 2-88-16 concerns a licensee identified co?dition of the degraded grid protection system for elect ical distribution.
The apparent cause wis a design error.
The licensee is performing modifications to change the time delays and voltage setpoints for equipment protection.
Techn' cal Specification amendment requests have been submitted. This subject was also discussed at PECo/NRC meetings on July 1 and September 7,1988.
The inspector had no further questions or concerns with this LER.
NRC Inspection 277/88-18, 278/88-18 also discusses this problem, 6.2.6 LERs 2-88-17, Rev. O and Rev. I concern a shutdown cooling isolation that occurred on Unit 2 on July 0, 1988.
The cause of the isolation was a lack of training and supervision of engineering department personnel who were performing field walkdowns in the cable spreading room.
The event was reviewed in NRC Inspection 277/88-18 and 278/88-18.
No inadequacies were noted relative to this LER.
6.2.7 LER 2-88-18 concerns a licensee identified inadequate surveillance test (ST) procedure for the rod worth minimizer (RhN) system. During a procedure review for a modification, a licensee system engineer noted that ST 10.5, "RhH Operability Test" did not implement Technical Specification (TS) surveillance requirement 4.3.B.3.b.1.c.
This TS requires a verification of the RhM rod block function during startup by withdrawing an out-of-sequence control rod.
$1 10.5 does adequately verify TS
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-24-4.3.B.3.b.1.a and b, which performs a RhH diagnostic test and the out-of-sequence rod select error function.
This is a licensee identified violation (277/88-34-02).
The licensee determined that this RhH rod block functional check was deleted from ST 10.5 when it was revised on July 12, 1976. The licensee concluded that there were no actual or potential safety consequences resulting from this event.
The licensee based this conclusion on the following:
adequate checks of RhH diagnostic test and the RhH select error alarm and function; operability of the redundant rod sequence control system (RSCS); and, operator pulling -ods per the sequence in the plant startup procedure G1
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The inspector reviewed the LER, ST 10.5, applicable TS sections, and discussed this item with licensee engineers and operators.
The inspector also reviewed a revised ST 10.5 which adequately implements the RhH surveillance requirements.
The inspector concluded that this licensee identified TS violation was of minor safety significance.
However, additional concerns were raised with respect to the licensee's surveillance program and the adequacy of ST procedures (see section 7.2 of this report).
6.2.8 LER 2-88-19 concerns a Unit 2 shutdown cooling (SOC)
isolation on July 29, 1988, caused by an inadequate blocking permit.
The event wa* reviewed during NRC Inspection 277/88-24, 278/88-24.
The licensee is developing a peach Bottom Permits and Blocking Manual.
This manual will be included in permit preparer training.
The licensee also reviewed their root cause analysis (June 9, 1988) for the numerous SOC isolations which occurred during 1987/1988.
Additional corrective actions were identified.
No inadequacies were noted relative to the LER.
6.2.9 LER 2-88-20 concerns a north substation fire ar.d engineered safeguards features actuation on July 29, 1988.
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The event was reviewed in NRC Inspection 277/88-24, 278/88-24.
The inspector concluded that the LER was well written, contained excellent detail, and contained the required elements.
6.2.10 LERs 3-88-06 and 07 concern Unit 3 containment isolations on June 24, 1988 and July 12, 1988, caused by blown ' m s due to personnel errors.
These events were reviewed in NRC Inspection 277/88-18, 278/88-18.
No inadequacies were noted relative to these LERs.
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-25-6.2.11 LER 3-88-08 concerns a Unit 3 containment isolation on August 29, 1988, caused when the RPS feed breaker tripped on a large motor start. The event was reviewed in NRC Inspection 277/88-24, 278/88-24. No inadequacies were noted relative to this LER.
6.2.12
!.ER 3-88-09 concerns the E-2 EG auto start due to an inadvertent feeder breaker trip on August 31, 1988.
The event was reviewed in NRC Inspection 277/88-24, 278/88-24.
No inadequacies were noted relative to this LER.
6.2.13 LER 2-88-21 concerns a Unit 2 group II primary containment isolation system (PCIS) actuation on September 13, 1988.
This event was reviewed in section 4.2.1 of this report.
The LER was well written and addressed the inspectors concern regarding corrective action to prevent recurrence.
This LER stated that a revision would address corrective actions resulting from a Human Performance Evaluation System review.
The LER revision will be reviewed in a future inspection report. No inadequacies were noted relative to the LER.
7.0 Surveillance Testing 7.1 Routine Observations (61726)
The inspector o'oserved surveillance tests to verify that testing had been properly scheduled and 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 were met.
Parts of *.he following tests were observed:
ST 2.4.11 A/C/F, Functional Test of LS-2-3-231
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A/C/F, performed on Unit 2 on September 13, 1988.
ST 8.2-2A, Station Battery Weekly. Inspection -
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125/250 VDC, performed on Unit 2 on October 4, 1988.
RT 6.12 Reactor Feed Pump Turbine (RFPT) Overspeed
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test, on Unit 2A RFPT on October 12, 1988.
ST 6.17, Olesel Driven Fire Pump Operability Test,
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Rev. 13, performed on October 14, 1988.
On October 14, 1988, the inspector witnessed performance of ST 6.1/, "Diesel Driven Fire Pump Operability Test," Rev. 13, 10/10/88.
Before performance of toe test, the inspector determired that the auxiliary operator had an outdated versicn (Rev. 11, 4/88) of ST 6.17.
The auxiliary op returned to the control room to obtain the current versio,erator n.
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o-26-The inspector discussed the out-of-date revision of ST 6.17 with the Shif t Technical Advisor (STA).
He could not recall where he had gotten the out-of-date ST, even though there is only one set of STs in the control room and it did contain the correct revision.
The licensee is currently investigating how revision 11 of ST 6.17 was issued to the auxiliary operator.
During performance of ST 6.17 the inspector noted four problems.
First, the diesel fire pump did not start at the acceptable header pressure of 130 psig or higher. The pump started at 124 psig.
Maintenance request form (MRF) 2-88-10496 was in:tiated to recalibrate the diesel fire pump starting pressure switch.
Second, step 12 of the ST contained two different actions.
Step 12 should be separated into two steps to be consistent with the licensee philosophy on procedures.
Third, system procedure S.13.2.1.0, "Shutdown of Fire Pumps," was not listed in the reference section of ST 6.17 even though it is used in step 12 to shut down the diesel fire pump.
The system engineer stated that the ST procedure is being rewritten and both concerns would be corrected.
Fourth, the faspector noted that diesel engine parameters were not monitored during the performance of ST 6.17 even though system procedure S.13.2.1.F, "Routine Inspection of Fire Protection Water System," listed numerous items to be monitored during pump testing.
The system engineer was investigating this concern at the close of this inspection.
During discussion with the System Engineer, the inspector learned that a temporary procedure change (TPC) was made to ST 6.17.
The change was to recirculate fire water to the intake pond rather than to run the pump at shutoff head.
The ST was performed in the recirculation manner on October 11, 1988, but not on October 14, 1988.
The inspector later learned that the Superintendent of Operations had cancelled the TPC due to a concern.
However, while investigating this the inspector determined that TPCs to Sis were not controlled in a positive nanner such as those procedures listed in step 7.S.3.5 of procedure A-3 "Temporary f W et to l'rocedures", Rev. 10, 9/26/83.
It is possible fe a
4 be performed without knowing that a TPC applies to
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censee
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is investigating the adequacy of A-3 with regards tc
'e Based on witnessing performance of ST 6.17; on the review of administrative procedures; and on discussior with the Syst a Engineer. ST Coordinator and operations personnel, this surveillance
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observation w il remain unresolved (277/88-34-03) pending resolution of the following issues:
cause for outdated revision of ST 6.17;
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acceptability of ST 6.17 with regard to
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S.13.2.1.F; and acceptability of A-3 with regard to STs.
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ST 4.7.3, Control Room Rad Monitor Orawer
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Calibration; Rev. O, performed on 12/13/37 and
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5/27/88.
i ST 9.8, Control Room Emergency Ventilation and
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Radiation Monitor Functional Test, Rev. 13, performed on 5/23/88 and 7/11/88.
ST 7.6.12, Calibration of the Control Room
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Vent Radiation Monitor with a Known Radioactive Source, Rev. O, performed on 2/17/88 and 5/27/88.
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No inadequac es were identified during this review.
7.2 Surveillance Testing ($T) program Review (61725)
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The inspector reviewed selected portions of the GT program.
This wa' in response to *.he following areas:
previous concerns regarding Si timeli.. ass; current concerns regarding ST per'.rmance and adequacy; and, LER 2-88-18 (section 6.2.7).
The licensee revised their surveillance program regarding reportability of overdue STs.
In response to a 1985 NRC open item, NRC Generic Letter L7-09, and to impleinent current station philosophy, the following changes have been made:
A-43, "Surveillance Testing System". Revision 20,
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now requires that a missed test be considered a violation of Technical Specifications (TS),
including NRC reporting and a determination of system operability.
A-43 requires an ST nonconformance report form
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(exhibit A-43:2) to be initiated for a missed test.
A-43 requires Shift Manager and PORC review for a
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missed test.
The inspector reviewed A-43 and verified 'mplener.tation of these new A-43 requirements by station personnel. No unacceptable conditions were noted.
In response to NR(
ne- 'ns regarding the adequacy of STs (NRC Inspection 277/89 38-35). the li ensev initiated a program to walk.iown and pe 'i ;
selec'a2 in field.
The sample size was 18 STs or abot of t.5e n-k safety related systems.
The purpose o' tt erify that the procedural
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steps of the Si (,
irmed by appror '2te station
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The
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,Kdowns, the following items
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were checked:
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-28-Tecb1ical errors such as incorrect steps, missing
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steps, or incorrectly referenced steps;
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Valve / instrument identification;
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Reading being recorded by the instruments;
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Annunciator labeling;
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S procedure references;
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Graphs and data records needed to complete the ST;
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Switch nomenclature;
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Tolerances for required values.
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The results of these walkdowns were described in a letter and discussed at a meeting on October 14, 1988.
The following is a summary of the licensee's results of the ST walkdowns:
1.
Four STs (ST-9.2, CR0 Exercise, ST 4.2 Reactor Building Radiation Monitor Functional, ST 3.2.3.A, IRM Functional, and 5T~6TfDT2, HPSW Pump and VaTve) observed could not he completed as written without temporary procedure change.
ST 9.2 Part C of the procedure does not correctly describe what actions should be taken in the event of a drifting rod (rod with stuck collet fingers).
ST 4.2 Step 4 references the wrong recorder.
ST 3.2.3.A Steps 360 and 410 reference incorrect computer points.
ST 6.10-2 Step 1 references an incorrect ST for determining HPSV pump data. Step 3 does not clearly desc.ibe how to measure MO-2803 stroke time.
Step 14 incorrectly references step 11 (should be step 13).
2.
One ST (ST 6.16, Motor Driven Fire Pump Operability Test)
does not appear to satisfy Technical Specification, 4.14.A.la, in that the test does not run the pump with recirculation flow through the piping with a flow indicator.
The licensee initiated an SLER.
3.
Most of the STs observed need human factors improvement which would make the tests easier to perform by operatcrs.
The licensew proposed recommendations include:
1.
The problams nated above should be permcnently corrected before the next performar.ce of the ST.
I 2.
Personnel performing STs should be requi-ed to perform the ST using line-by-line reference. Any deficiencies should be temporarily cnanged as needed to perform the ST or reported to the System Engineer for procedure upgrade. A form to
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o-29-o indicate this line-by-line review '.111 be included in all STs issued starting with those issued for the first week of November.
3.
A plan to perform a complete human factors upgrade of the STs should be developed as soon as possible.
During follow-up for an tradequate rod worth minimizer ST (LER 2-88-18), the inspector questioned licensee engineers whether there are other TS surveillance requirements that are not implemented by an ST. The licensee stated that an independent contractor had performed a review of ST procedures and TS surveillance requiroments during September 1988. The licensee reviewed the contractor's report and concluded the following concerns:
(1) some TS surveillance requirements may not be implemented in any procedure; and, (2) some TS su.veITTance requirements are being implee.ented by procedures that are not STs, Concern number (1) above includes the following examples with appropriate TS references:
Reactor protection system channel check when other
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channel is out of service (T; 4.1,C).
SRM/IRM detector not in startup position functional
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test (TS Table 4.2.C.1.8 and 9).
Reactor water level instrument checks (Tf Table
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4.2.F.1, 2 and 3).
Seismic monitor triaxial response spectrum recorder
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monthly instrument check (TS Table 4.15.3).
Torus visual exam after safety relief valve lifts
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and temperature exceeds 200 degrees F (TS 4.1.7.3).
These results were communicated to the plant staff via a letter dated October 3, 1988. The licensee is pursuing this item, l
including potential reportability.
During a meeting on October i
17, 1988, the licensee indicated that all bu' one of the above items had been resolved.
Daly the seismic monitoring item continues to be under review.
l The inspector reviewed the licensee letter, applicable TS requirements, and selected STs; and, discussed this item with licensee engineers and management personncl.
These above concerns are collectively considered unresolved (UNR 277/88-34-04; 278/88-34-04).
8.0 Maintenance Activities (62703)
The inspectors reviewed administrative controls and associat,d documentation, and observed portions of work on the following maintenance activities:
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-30-Document Equipment Date(s) Observed TL-12-00532 Personnel Contamination Monitor September 21, 1988 MOD 2390 Diesel Cardox Modification Various Administrative controls checked, if appropriate, included blocking permits, fire watches and ignition source controls, QA/QC involvement, rad alogical controls, plant condition:, Technical Specification LCOs, equipment alignment and turnover information, post mainter.ance testing and reportehility. Documents reviewed, if appropriate, included maintenance procedures (M), maintenance request forms (MRF), item handling reports, radiation work permits (RWP), material certifications, and receipt inspections.
No inadequacies were identified.
9.0 Radiological Controls (71707)
9.1 Routine Observations During the report period, the inspector examined work in progress in both units, including health physics procedures and controls, ALARA implementation, dostmetry and badging, protective clothing use, adherence to radiation work permit (RWP) requirements, radiation surveys, radiation protection instrument use, and handling of potentially contaminated equipment and materials.
The inspector observed individuals frisking in accordance wi+h HP procei;res. A sampling of high radiation area doors was verified to be 1ccked as required. Compliance with RWP requirements was verified during each tour.
RWP line entries were neviewed to verify that personnel had provided the required information and people working in RWP areas were observed to be meeting the applicable requirements. No unacceptable conditions were identified.
9.2 Hot Particle Control On September 8, 1988, the licensee's sample of the plant sewer system sludge accumulator tank revealed by analysis a small amount of Cobalt-60.
The concentration in the sample was 5.69E-07 microcuries per milliliter. The tank is sampled by a sludge sampling device" which takes a composite sample, top to bottom, of a tank containing semi-solid dispersed material in liquid.
The sample size is one liter using the sampling device.
The tank was sampled on September 9, 12 and 13, 1988, three samples each day.
Each analysis was the lower limit of detection for all radionuclides. The l
licensee concluded that either a hot pcrticle had entered the sewer
system or that either the 51 49e sampling device" or the sample l
container was contaminated, she licensee subsequently disposed of l
the non-contaminated sludge to & municipal sanitary sewer system.
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The licensee is examining the sampling method to prwvent possible contamination of containers and devices.
The sampling program will continue to monitor the sludge talk for possible hot particle inclusion and based on positive results in the future will examine the sewer system and policies to prevent hot particles from entering the system. The inspector had no further questions on this issue.
10.0 Physical Security (71707)
10.1 Routine 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 controi, observation of protected area access e,ntrol and badging procedures on each shift, inspection of protected and vital area barriers, checks on control of vital area access, escort procedures, checks of detection and assessment aids, and compensatory measures. No inadequacios were identified.
10.2 Safeguards Event Report on September 23, 1988 On September 23, 1988, the licensee made a one hour Safeguards Event Report to the NRC regarding a contrar.t QC inspector who tested positive during a random drug test.
The employee tested positive on September 21, 1988, and the licensee immediately denied him access to the protected area.
In addition, a determination of his duties determined that he was involved in reading and the acceptance of radiographs for safety related systems. Based on this information, the licensee determined this condition to be reportable.
The work performed by the individual is being reviewed by licensee quality assurance personnel.
The inspector reviewed the licensee's investigation report and discussed the item with security and quality assurance personnel.
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At the close of the insbection period, the licensee's investigatten was still (r. progress. The inspector will review the Safeguards Event Report and as;nciated corrective actions during I
a future inspection.
11.0 Assurance of Quality.
11.1 Licensee Event Reports (LER)
In response to an NRC violation and due to the corporate reorganization, the licensee initiated enhancements to the LER process.
The LER process is currently managed on site, and the LERs are signed by the Peach Bottom Site Vice Prosident.
Recent LER quality has been good, end LER timeliness has been adequate (s:e section t 0).
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0-32-11.2 Surveillance Test (ST) program and Procedures Deficiencies exist regsrding the ST program, including procedure useability and adequacy, and Technical Specification surveillance requirement implementation (see sections 7.1 and 7.2).
Recent NRC Inspections (277/88-35; 278/88-35 and 277/88-41 and 278/88-41)
have also identified problems with the ST program. Although the licensee has initiated actions to 6etermine the scope and root cause of these problems, actions to assess the technical adequacy of STs were not initiated until questioned by the NRC.
12.0 In-Office Review of Special Reports (92713)
The inspector reviewed the following:
1987 Annual Decommission Report No. 15 for Unit 1,
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semi-Annual Effluent Re'. ease Report No. 25, August 29
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Peach Bottom Monthly Operating Report for August 1988,
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No u acceptable conditions were noted.
13.0 Unresolved Item,s Unresolved items are items about which more information is required to ascertain whether they are acceptable violations or deviations. An unresolved item is u t scussed 1.1 section 7.2.
14.0 Management Meetleg; 14.1 Preliminary Inspection Findings (30703)
A verbal summary of preliminary findings was provided to the i
Manager, Peach Bottom Station at the conclusion of the inspecti7n.
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 dr.fermation is included in this repor _ _ _
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-33-14.2 Attendance at Management Meetings Conducted by Region Based Inspectors (30761)
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Inspection Reporting Date Subject Report No.
Inspector
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l 9,22 Security N/A Lancaster Enforcement Conference 9/29 Simulator 88-32/32 Walker Evaluations 9/26-29 Mod'fications and 68-35/35 Rebelowski Surveillance 9/27-28 Emergency Exercise 88-36/36 Conklin 9/26-29 Health Physics 88-37/37 Dragoun 9/26-29 Environmental 89-38/38 Cheung Qualification 10/3-7 Fire Protection 88-41/41 Krasopoulos 14.3 Harford County (Maryland) Council Meeting September 13, 1988 On 3eptember 13, 1988, the licensee gave a presentation and responded to questions regarding the status of Peach Bottom at a routine Harford County Council Meeting.
Licensee corporate and site management personnel addressed current plant status, hardware issues, computer changes, fitness for duty prograto, and current schedule. One of the council members was concerned regarding plant aging issues.
The licensee responded to this concern by discussing the corrective and preventive maintenance prcgrams and the surveillance testing srooram.
The public in attendance had no questions for the licensee or for the council regarding Peach Bottom.
14.4 NRC/PECo Meeting on September 29, 1988 On September 29, 1988, a management meeting was held in Region 1 to discuss the licensee's self assessment program, current schedule and power asceasion program plan. Meeting attendees are listed in Attachment 2.
In addition, questions regarding the Itcensee's restart plan were discussed.
These items will be addressed in the NRC Safety Evaluation Report for the restart of Peach Bottom.
14.4 NRC Commission Meeting on October 5, 1988 The NRC Commissioners reviewed the status of the Peach Bottom Atomic Fower Station during a meeting in Rockville, Maryland, on October 5, 1988.
Licensee corporate and site management gave a presentation on restart plan actions and schedules.
In addition, the NRC staff updated the Commission regarding NRC actions completed to date and those actions to be performed.
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o ATTACHMENT 1 Analytical Results of Spiked Split Samples unit =ppp_
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Item Matrix Sample 10 Peach Bottom Brookhaven Chloride Refuel Water Sample No. 1 51.6 + 0.5 72.4 + 0.5 Storage Tank Sample No. 2 52.450.2 59.030.3 Sulfate Refuel Water Sample No. 1 66.5 + 0.5 137.0 + 1.0 Storage Tank Sample No. 2 72.7i5.6 52.130.4 Iron Refuel Water Sample No. 1 254.0 + 1.5 229.0 + 0.0 Storage Tank Sample No. 2 252.032.1 206.010.0 Copper Refue. Water Sample No. 1 244.0 1 3.2 256.0 + 0.0 Storage Tank Sample No. 2 243.0 1 1.2 253.0 1 5.0 Nickel Refuel Water Sample No. 1 243.0 + 1.5 247.0 + 0.0 Storage Tank Sample No. 2 240.0i3.2 247.030.0 Chromium Refuel Water Sample Ns. 1 240.0 + 2.1 256.0 + 1.0 Storage Tank Sample No. 2 241.0 1 1.7 248.0 1 0.0 Z i,1c Refuel Water Sample No. 1 (20
<100 Storage Tank Sample No. 2
< 20
< 100
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e ATTACHMENT 2 September 29, 1988 Meeting - NRC/PECo
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Name Organization NRC WT Butler NRR, Director, Project Directorate, PD I-2 E. Wenzinger, Sr.
Region 1, Chief Reactor Projects Branch 2 W. Kane Region 1, Director Division of Reactor Projects
'. Linville Region 1 Chief Projects Section 2A R. Ramirez NRR/DLPQ W. Johnston Region 1, Deputy Director, Division of Reactor Safety R. Keimig Region 1 Chief, Safeguards S. Ebneter Region 1, Director, Division of Radiation Safety and Safeguards H. Wilitams Region 1, Project Engineer T. Johnson Region 1, Senior Resident Inspector, PBAPS S. Shankman NRR, Chief Human Factors Assessment Branch R. Gallo Region 1, Chief Operations Branch (
R. Martin NRR, Project Manager A. Howe Region 1, Senior Operations Engineer PECo J.~Rartore Restart Licensing J. Basilio Restart Licensing Manager C. McNeill Executive Vice President - Nuclear D. Smith Vice President, PBAPS
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l F. Polaski Assistant Superintendent - Operations G. Lipscy PBAPS Restart Power Testing Manager l
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Others W. Dornsife Pennsylvania DER S. Maingi Pennsylvania DER R. Reichel Delmarva Power
M. Phillips Public Service Electric & Gas H. Abendroth Atlantic Electric T. Magette State of Maryland t
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