IR 05000302/1998007
| ML20239A517 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 08/31/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20239A512 | List: |
| References | |
| 50-302-98-07, 50-302-98-7, NUDOCS 9809090288 | |
| Download: ML20239A517 (43) | |
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U.S. NUCLEAR' REGULATORY COMMISSION
REGION II
Docket No:
50-302 License No:
DPR-72 Report No:
50-302/98-07 Licensee:
Florida Power Corporation Facility!
Crystal River 3 Nuclear Station Location:
15760 West Power Line Street Crystal River' FL 34428-6708
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Dates:
June 21 - August 1, 1998 Inspectors:
S.'Cahill. Senior Resident Inspector S. Sanchez Resident Inspector E Whitener. Reactor Inspector. (Sections M3.1-M3.4.
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Approved by:
1. Wert. Chief. Projects Branch 3
'ivision of Reactor Projects I'
l Enclosure
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gDR ADOCK 05000302 l
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EXECUTIVE SUMMARY Crystal River 3 Nuclear Station NRC Inspection Report 50-302/98-07 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a six-week period of resident inspection: in addition, it includes the results of an Inservice Testing. inspection by a regional reactor inspector.
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Operations-l l
Operator shift turnovers continued to be thorough and operators
were cognizant-of evolution and equipment status.
However,
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written documentation of turnovers was often on informal notepads instead of the turnover record forms, which did not meet
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L management's expectations (Section 01.1).
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The licensee identified an improperly positioned Service Water
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pump suction valve. Although several process barriers failed to prevent the mispositioning, the inspector noted that the licensee
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performed a prompt and aggressive investigation and that
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significant management attention was focused on the problem.
Licensee management is continuing efforts to reduce personnel errors-due to poor procedure usage and inadequate self-checking.
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(NCV 50-302/98-07-01. Failure to Fully Open and Seal Service Water l
Pump Suction Valve. Section 01.2).
Operators initially failed to note the inability to meet a
Technical Specification surveillance requirement for logging hot leg temperature due to unavailability of data from the plant computer and lack of evaluated alternate indications.
The licensee subsequently determined, using an engineering analysis, that the requirement was met using alternate-indications. Licensee management completed a thorough and prompt investigation of the.
issue (Section 01.3).
An example of ineffective corrective action was identified by the
inspector. A Night Order directed an operability determination review for the operating crews, without telling the crews'
supervision the reason for the review or the specific points to emphasize (Section 01.4).
Instances of poor equipment condition. standing water, and
unsecured equipment in the area around the borated water storage i
l tank were considered examples of poor maintenance and housekeeping of unfrequented areas and rooms with primarily abandoned equipment i
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that still contained operational components (Section 02.1).
Control room operators routinely used the practice of peer-
checking to verify their equipment and control manipulations and w_
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consistent implementation of this practice was considered a strength (Section 04.1).
An example of excellent questioning attitude was observed when an
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operator challenged the lack of a time limit requirement to inspect a service water heat exchanger removed from service for suspected blockage (Section 04.1).
A problem with alternate indications for hot leg tem)erature had
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been identified months earlier by the licensee, but lad not been corrected due to a corrective action program error that c;used corrective actions to be left in an indeterminate state.
The licensee's program only tracked the completion of finalized corrective actions and root cause evaluations, not the age of open precursor cards.
Questioning by NRC inspectors resulted in the identification of the problem (Section 07.1).
The performance of back-end corrective action effectiveness
reviews by the licensee was considered a beneficial and pro-active action (Section 07.2).
Maintenance Observed testing and surveillance activities were performed in a
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highly controlled manner by Operations personnel.
Preparation and briefings for testing were thorough, a single point of contact was assigned for coordination, operators were knowledgeable of the scope and purpose of the tests, communications were precise and formal, and supervisory oversight was strong (Section M1.1).
Licensee management identified a deficient practice involving
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testing of vital bus transfer switches.
A test failure could result in deenergizing a vital distribution panel, Potentially causing a reactor trip or transient. Operations subsequently prevented sJbsequent scheduled testing due to the risk of a transient (Section M1.1).
An excellent questioning attitude and attention to detail were
displayed by an Instrumentation and Controls technician that identified an anomaly during reactor protection system testing of the reactor coolant system low pressure trip.
Previous opportunities to identify the same anomaly were missed during validation testing and testing by other technicians.
(NCV 50-302/98-07-02, Inadequate Testing of Reactor Protection System Electrical Circuitry. Section M1.2).
The emergent job to replace a leaking service water pump
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mechanical seal was well executed.
Work packages were promptly prepared, workers displayed good teamwork, and excellent LCO time sensitivity was evident. Good component engineer support was
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observed for the seal replacement and the investigation of the seal leakage cause (Section M1.3).
The Program Manual for the third ten year Inservice Testing (IST)
interval was consistent with the Code Standards (Section M3.1).
The licensee identified the ASME Class 1.2. and 3 components which
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have a function in shutdown of the plant to a safe shutdown i
condition, maintaining safe shutdown, and in mitigating accident conditions. Appropriate procedures have been developed and testing is performed in accordance with plant procedures (Section M3.2).
The licensee has developed and implemented a review process which
assures IST requirements were considered for component failures.
It also assures that the IST Program Manager is informed of component conditions (Section M3.3).
The inspectors reviewed acceptance criteria in IST procedures and found them to be consistent with the ASME/ ANSI 0.M. Standards. Test criteria were indicated on the engineering data sheets (Section M3.4).
The corrective actions described in a Licensee Event Report (LER)
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were insufficient to address the problem and prevent recurrence.
The inspectors reviewed additional actions contained in corrective action program documents and concluded the licensee's corrective actions were adequate (Section M8.1).
Enaineerina Reliability of the plant computer remains poor and continues to e
present challenges to the operators. Modification and upgrade of the current system is in progress. Although corrective actions for previous computer malfunctions did not aid in warning of a subsequent computer display problem, operators alertly detected the problem during a power increase (Section E2.1).
A discrepancy with the licensee's implementation of reactor vendor
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owners group guidance for reactor coolant pump restart following a boron dilution event was determined to be an isolated occurrence of poor Emergency Operating Procedure control (Section E8.6).
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Report Details Summary of Plant Status The plant began the inspection period at' full power and operated at essentially that level until July 9, 1998, when power was reduced to 85% to remove a condenser water box from service for repairs. The plant returned to full power operation on July 11. 1998, and remained at full power for the remainder of the report period.
I. Ooerations
Conduct of Operations 01.1 General Comments (71707)
Using Inspection Procedure 71707. the inspectors performed routine reviews of plant operations which included observation of power changes, operator turnovers, extended control room operator watch standing, surveillance testing, and shift data logging.
Operators' verbal turnovers continued to be highly detailed. Operators at all stations'were fully. cognizant of equipment status, problem areas, and ongoing and upcoming evolutions. However, the inspectors observed
.that operators at all levels were not completely recording this information on the formal turnover sheet forms. Although these forms are retained as records, most operators kept current shift data on steno pads or planner note) ads.
The inspectors concluded that turnovers were-very effective but tlat the recording of information did not meet management expectations.
01.2 SW Pumo iA Suction Valve Imorocerly Positioned a.
Insoection Scooe (71707)
Following repair of a mechanical seal on Nuclear Services Closed Cycle Cooling Water.(SW) pump 1A, as discussed in Section M1.3, the pump was released.to Operations for removal of the clearance and filling and venting.
During preparations to start the pump, an operator observed that valve SWV-2, the suction valve to SW aump 1A, was indicating closed when it was required to be sealed open.
T1e inspectors reviewed the licensee response to the improperly positioned valve, attended root cause team deliberations, and walked down the system to verify valve
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Observations and Findinas Operations management promptly identified this problem as a significant concern and initiated a formal investigation. They raised their expectation for the thoroughness of the investigation beyond the normal requirements and directed the Nuclear Shift Manager (NSM) of the crew
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that had incorrectly mispositioned the valve to perform the review.
The inspector reviewed the completed report and a pending root cause report, and independently verified the cited procedural requirements and l
administrative guidance. The inspector observed that several licensee
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process barriers failed to protect'the incorrect positioning of the valve.. The fill and vent of the pump was done in conjunction with removal of the clearance tagout, causing an overlap of separate tasks l
which contributed to the incorrectly aligned valve.
The Category 1 Operating' Procedure (0P) for fill and vent of the SW pump, which was required to be in hand and followed step-by-ste). was not used. The existence of the OP section was not-recognized )y the two operators performing the tasks. the Clearance Chief coordinating the evolution, or the Work Control Supervisor (WCS) who authorized the removal of the clearance. The licensee's process for positioning and sealing valves was also not followed.
Per individuals' written statements, the initial o)erator opened SWV-2 a single turn for the fill and vent evolution but tien did not check valve position by hand, as required, when subsequently signing for the clearance removal position of sealed open.
He only visually verified the valve position indication and he did this incorrectly, partially due to poor butterfly valve position indicator markings.
The inspector verified that the raised letter position markings were hard to read due to being painted numerous times and that the indicator was o)posite of normal convention in that the arrow pointed in line wit 1 the pipe when closed.
However, the position indicator was functional and the determined upon close inspection. pro)er valve position could have been T1e initial operator also inappropriately sealed the valve.
Per Operations requirements, the second verifier, not the initial positioner, is to ) lace the seal on the valve after physically verifying valve position.
T1e'second operator, when independently verifying the valve position for the clearance restoration, also incorrectly read and relied on the valve indicator and did not question the seal already being in ] lace.
The licensee's investigation also identified that a pre-jo) brief did not occur for the clearance restoration and venting, contrary to licensee management expectations. The WCS was involved in another activity when authorizing the clearance removal and did not sufficiently direct or question the sequence of events. After reviewing the details of the personnel statements and written records of the investigation, the inspector determined.the licensee had not addressed the clearance chief, who did not sufficiently brief the operators prior to dispatching them and did not ensure the two tasks would remain separate.
The licensee modified
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The incorrectly positioned valve was found by a very alert auxiliary building operator on the next shift who was observing the pump to ensure it was ready to start. The investigation done by the NSM of the crew -
that had the problem was very thorough. Operations management a)propriately emphasized NSM accountability for problems on their shift.
T1e inspector observed the discussions of an Operations peer review committee on the preliminary root cause investigation, and noted it was emphasizing individual o)erator accountability and techniques to im) rove operators' use of self-clecking techniques at all times, not just w1en
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'being observed..The committee also discussed operators' claims of perceived time pressure and considered a broad range of actions that
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Finally, recently implemented corrective actions for some previous component mispositionings had not yet had time to be effective and would
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not have specifically precluded this event.
Consequently, this non-l repetitive, licensee-identified and corrected violation of TS 5.6.1 was
'1dentified as Non-Cited Violation (NCV) 50-302/98-07-01. Failure to
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. Fully Open'and Seal Service ~ Water Pump Suction Valve, consistent with Section VII.B.1 of the Enforcement Policy.
The licensee also identified three other improperly positioned valves during the inspection report period. These incidents involved non-safety related components or components in a maintenance status. The causal factors involved in these cases were different than in the above
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incident.
The licensee addressed those issues promptly.
.The licensee's. investigation of earlier component mispositionings concluded they occurred for numerous disparate causes.
The investigations noted deficiencies involving inadequate verification of components, poor procedural compliance, and perceived time pressure, c.
Conclusions-The licensee identified an improperly positioned SW pump suction valve.
Although several process barriers failed to prevent the mispositioning,
'the inspector noted that the licensee performed a prompt and aggressive investigation and that significant management attention was focused on the problem.
Licensee management is continuing efforts to reduce personnel errors due to poor procedure usage and inadequate self-checking.
01.3 Loaaina Surveillance Requirements Challenaed Due to Comouter Outaae a.
Insoection Scooe (71707)
i The inspectors reviewed the circumstances and consequences of a plant computer outage on July'21, 1998.
b.. Observations and Findinas The plant computer was removed from service for maintenance after
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operators had taken their last set of shift log readings at 8:03 a.m.
per procedure SP-300, Operating Daily Surveillance Log.
SP-300 details several contingency actions for the loss of some computer data and alarms. The inspector verified that the operators had addressed these contingency actions and completed the appropriate SP-300 Enclosure 2.
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However, SP-300 omitted alternative action to take for logging T-hot which was required by Surveillance Requirement (SR) 3.4.1.2 every 12
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hours. The operators did not recognize this omission.
The. inspector also observed that SP-300 step 4.2.5.5 was misleading because it stated that readings normally obtained from the plant computer could be substituted with plant instrumentation and recorded on Enclosure 2.
This was not applicable for the T-hot SR because SP-300 required the computer-data to be used due to the instrument inaccuracies of other indications. Section 07.1 of this report addresses a corrective action issue involving the surveillance requirement.
Delays extended the planned four hour computer outage to over 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />.
When the evening shift operator took SP-300 logs-at approximately 6:45 p.m., he entered "00S" in the field for hot leg temperature, indicating the computer point was out of service.
He did not cuestion how the SR reading was to be completed without the computer anc did not alert his supervisor. At 9:30 p.m., the Nuclear Shift Supervisor (NSS),
performing log reviews, noticed the error, obtained alternative readings of hot leg temperature from control room instruments, but recognized that these indications could not fulfill the SR.
The allowable period for SR 3.4.1.2 expired at 11:03 ).m.. so the NSS entered Improved Technical Specifications (ITS) SR 3.0.3 for a missed surveillance. The plant computer was restored and hot leg temperature readings were taken at 12:45 a.m. on July 22. 1998, and ITS SR 3.0.3 was exited.
The licensee subsequently performed an engineering analysis that justified the use of the control room indications as sufficient for fulfilling the SR. The inspector reviewed the analysis and did not identify any concerns with their conclusion that the SR was fulfilled and SR 3.0.3 did not have to be entered.
The inspector noted that Operations management was significantly concerned about the logging problem and directed the )rompt performance of an investigation by the NSM of the crew who made tie error.
The inspector reviewed the completed investigation report and noted that it was thorough and very self-critical. The licensee identified several failures of personnel to meet performance expectations and several process deficiencies. The proposed corrective actions were appropriate
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Conclusions Operators initially failed to note the inability to meet a Technical Specification surveillance requirement for logging hot leg temperature
due to unavailability of data from the plant computer and lack of evaluated alternate indications. The licensee subsequently determined, using an engineering analysis, that the requirement was met using
' alternate indications.
Licensee management completed a very thorough and prompt investigation of the issue.
01.4 Corrective Action for Operability Determination Problems (71707)
A delayed operability determination on an emergency feedwater-surveillance was discussed in IR 50-302/98-06.
As a corrective action
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for poor operator knowledge of operability determination requirements, a Night Order directed NSMs to review specified sections of the existing procedural guidance with all of their shift members. The inspector identified.that the Night Order did not tell the NSMs why they were reviewing the guidance and what points needed emphasis. The inspector observed one of the shift briefings and concluded it was cursory and did not adequately address the original problem.
The operator leading the brief was unable to state why the brief was being given and the brief was mainly a reading of the procedure sections, with little added emphasis reflecting management's concern. The inspector concluded this was an example of ineffective corrective action by Operations-management.
0perational Status of Facilities and Equipment
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02.1 Sodium Hydroxide Tank Room and BWST Area Material Condition (71707)
On July 16. 1998, following a period of heavy rainfall the inspector observed a large amount of water flowing down an Auxiliary Building wall and into the B train Decay Heat Removal (DH) system Jump pit.
Health Physics personnel were redirecting the leakage to a auilding sump drain, and the licensee subsequently verified the pumps were not affected by the water.
Six inches of standing water was found in the Building Spray (BS) sodium hydroxide tank room which had leaked into the Auxiliary Building via a pipe chase. The room was pumped down and the path sealed.
However, several days later, the inspector toured the area and identified several inches of standing water in the BS tank room again.
The BS tank room did not have automatic sump pumps due to concerns with unmonitored pumping of potentially contaminated liquid. Although the BS tanks have been abandoned in-place because sodium hydroxide is no longer used in the BS system, the inspector was concerned about the standing water. because it submerged several conduits which could affect the BWST level transmitters located in the same room. The room was again pumped dry by the licensee and the level transmitters verified to be unaffected. The ins)ector noted that the majority of the lighting in the room was inoperaale and that it was not regularly toured by operators.
The inspector also identified several other examples of poor housekeeping such as debris and scaffolding which could be missile hazards in severe weather conditions. The area behind the BWST enclosure was especially poor in that a pliable Reactor Building to Auxiliary Building roof seal was torn, temporary paint storage sheds were in disarray, recirculation lines from the BWST were missing insulation and had rusted supports and heat trace conduits, and heat trace thermostat boxes were not clamped closed. The licensee was addressing the deficiencies.
The inspector concluded these were examples of poor maintenance and housekeeping of infrequently toured I
areas.
Operator Knowledge and Performance 04.1 Peer Checkina and Questioning Attitude (71707)
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During evolution and testing observations, the inspectors noted consistent implementation of " peer-checking" by operators when performing manipulation of plant equipment or controls.
Peer-checking is defined in Operations Instruction 0I-10. Verification of Activities / Questioning Attitude, as an operator observing the actions of another operator performing a task, to verify the correct train or components are selected.
Management's ex)ectation in procedure 01-10 was that peer-checking would be used at t1e discretion of the operators but that most main control board manipulations would be checked.
The inspectors observed that operators exceeded this expectation in that virtually all main control board manipulations were checked and that operators performing other evolutions routinely requested a peer-check for their actions.
The inspectors observed that peer-check communications were formal and the operator performing the evolution waited for the peer-checker's feedback before actually performing the action.
The inspectors questioned various operators on their use of peer-checks and determined that plant operators considered the practice important and a significant tool at prevention of personnel errors.
The inspectors concluded the consistent implementation of peer-checks by operators was a strength.
The inspectors also observed an excellent example of questioning attitude by a reactor operator (RO) who questioned an indeterminate delay in inspection of a SW system heat exchanger (SWHE) removed from service due to suspected raw water tube blockage.
The R0 initiated PC 98-3302 to identify the lack of a requirement to perform a timely inspection, and that a delay in inspection of the SWHE effectively delayed implementation of time-dependent actions for cleaning other SWHE's and engineering evaluations.
These proceduralized actions were based on as-found blockage levels identified in a maintenance inspection.
The licensee was developing a time requirement for inspection of an SWHE removed from service for suspected blockage.
Quality Assurance in Operations 07.1 Corrective Action Proaram (40500)
j The inspector identified that Precursor Card (PC) 98-0904 had previously
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identified a problem with a lack of alternative indications for the computer point for T-hot in February 1998. This was also previously discussed in NRC Inspection Report (IR) 50-302/98-03. A cause evaluation had been completed for this PC. but the corrective actions had not been implemented.
The inspector questioned the apparent delay
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in the licensee's corrective action program (CAP).
The licensee subsequently identified that an anomaly in their CAP software caused the
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PC corrective actions to be in an indeterminate status, because they had
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not been electronically accepted by the manager of the department J
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developing them. The inspector determined the licensee's CAP
administrators only monitored the completion of individual PC corrective actions and root cause evaluations, and not the age of open PCs.
Therefore, even though PC 98-0904 remained open for five months, this problem was not detected because the corrective actions were never o_ _
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finalized and therefore never tracked.
A] proximately 70 other PCs were
.in a similar indeterminate status which t1e licensee reviewed and concluded were not safety-significant issues that' had not been acted upon.
The inspector verified their results and noted that the l
population was primarily lower significance level PCs.
The anomaly in l
the CAP software was also corrected.
07.2 Root Cause Determination Effectiveness Reviews
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Insoection Scooe (40500)
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The inspector reviewed the performance of Back-End Effectiveness Reviews for root cause corrective actions The ex)ectations-for these reviews were delineated in Compliance Procedure (C))-111. Processing of Precursor Cards in the Corrective Action System.
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Observations and Findinas The licensee instituted the review requirement late in 1997 and the first~ reviews were recently completed. The inspector reviewed the
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i tracking mechanism the licensee used and concluded that it sufficiently captured the more than 100 pending reviews.
The inspector observed several of the reviews that were presented to the Corrective Action Review Board (CARB) and noted that the participants effectively demonstrated the effectiveness of their corrective actions cnd that the expectations in CP-111 for the review content were thorough.
Licensee-management. noticed an over reliance on the absence of subsequent similar L
items in the corrective action program database to validate the-corrective action effectiveness. and issued guidance to consider other sources of data, such as Quality Assurance reviews and external assessments. The inspector noted that only a few of the reviews had been completed so far, and that none of them had yet identified any needed modifications to a corrective action plan, but considered the licensee's process was adequate to identify if revisions were needed.
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Conclusions The performance of _back-end corrective action effectiveness reviews by the licensee was considered a beneficial and pro-active action.
II. Maintenansg M1 Conduct of Maintenance M1.1 General Comments a.
Insoection Scooe (62707. 61726)
Using Inspection Procedures 62707 and 61726 the inspectors observed all or portions of.several Work Requests (WR), Surveillance Procedures (SP)
and Periodic Tests (PT). and reviewed associated documentation. The following activities are discussed:
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MAR 97-09-05-01 AHF-1C Reactor Building Fan Logic Test
Test Procedure 2 SP-457A Emergency Core Cooling System Res onse to a
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Safety Injection Test Signal (Mod 1-3)
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SP-358A Operations ES Monthly Automatic Actuation Logic
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Functional Test #1 J
PT-446 Functional Test of Vital Bus Redundant I
e Transformers and Static Transfer Switches
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Observations and Findinas j
The inspectors observed that the Modification Approval Record (MAR) Test Procedure had a thorough pre-job brief. ITS Limiting Condition for Operation (LCO) entry points were delineated clearly and discussed in advance, and operators performing the test had a detailed understanding
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of the test.
Communications between operators and with supervisors were j
formal and complete.
Oversight of the test by engineers and Operations
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supervision was constant.
j On July 10. 1998, the inspector observed portions of procedure SP-457A testing. The main SP-457 procedure was normally performed with the
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plant in a refueling outage, but the licensee had developed SP-457A to do this integrated emergency core cooling system (ECCS) testing online to reduce outage schedules and for better availability of Operational resources.
The inspector observed that the online testing was very well planned. An SRO had been assigned weeks in advance of the testing as the single point of contact for coordination.
Shift crews had been selected, scheduled, and trained to perform the testing beforehand.
The testing was considered an Infrequently Performed Test or Evolution (IPTE) and therefore had senior licensee management assigned as oversight. The inspector observed the IPTE pre-job briefing and noted that questions were directed to operators to verify their understanding of the testing, the role of each participant was very clearly defined, and precautions and limitations were thoroughly discussed. A summary briefing package had been prepared by the SR0 coordinator which delineated the scope of each section of procedure SP-457A. test equipment needed. ITS requirements, supporting equipment alignment procedures, and the designated testing crew and operators. The inspector observed that these thorough preparations were beneficial when a conflict with another evolution arose.
The inspector observed that the testing performance in the control room was professional, excellent three way communications were used, the NSS was constantly monitoring in a supervisory role and manipulations were peer checked consistently.
The inspector also observed good questioning attitude by the crew who challenged valve stroke time data norms in SP-457A that appeared to differ from Inservice Testing data.
On June 26, 1998, tesung of vital bus transfer switches (VBXS) 1A and
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3A and associated vital bus-inverter (VBIT) 1A was completed per procedure PT-446 as a post-maintenance test.
A malfunctioning relay resulted in the loss of power to vital bus distribution panel (VBDP) 8, which supplied power to some emergency feedwater control circuits. 'The-testing was also fortuitous in that an unsuccessful performance of PT-
. 446 on another VBXS would have deenergized a more safety-significant VBDP. such as one supplying power to reactor protection circuitry, and caused a reactor tri).
Licensee management recognized this poor practice, upgraded t1eir investigation to require a root cause and extent of. condition review, and was evaluating appropriate test-methodology changes.
However, the test method had not yet been changed when it was scheduled to run on another VBXS.
Even though maintenance technicians had already verified.the relay was operating correctly.
Operations personnel challenged and stopped the evolution to ensure the testing process was changed.
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Conclusions Observed testing and surveillance activities were performed in a highly controlled manner by Operations personnel.
Preparation and briefings for. testing were thorough, a single point of contact was assigned for coordination, operators were knowledgeable of the scope and purpose of the tests, communications were precise and formal, and supervisory oversight was strong.
Licensee management identified a deficient practice involving testing of vital bus transfer switches. A test failure could result in deenergizing a vital distribution panel, potentially causing a reactor trip or transient. Operations subsequently prevented subsequent scheduled testing due to the risk of a transient.
M1.2 Testina of Reactor Protection System Electrical Circuitry a,
Insoection Scooe (61726. 92902)
The inspector reviewed an issue with regard to testing of RPS electrical circuitry.
During the performance of Surveillance Procedure SP-1100.
"D" Channel Reactor Protection System Functional Testing, the licensee identified that the reactor coolant system (RCS) low pressure bistable was not adequately tested.
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Observations and Findinas
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During the performance of SP-110D. while testing the RCS low aressure
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-bistable, an attentive Instrumentation and Controls (I&C) tec1nician noticed the variable pressure / temperature (P/T) bistable trip)ed prior l
to the low pressure bistable. The technician questioned whetler the low pressure bistable was adequately tested with the variable P/T bistable tripping first.
The licensee identified that with RCS hot leg temperature (T-hot) greater than 590 degrees Fahrenheit ( F), the variable P/T setpoint was greater than 1828 pounds per square inch gauge (psig). Testing of the low pressure bistable required the simulation of
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'a lowering RCS pressure signal to the fixed set)oint of 1828 psig.
When simulated RCS pressure was decreased, the varia)le P/T trip was
' received, thus locking-in the RPS channel "D" common subsystem trip and preventing verification of the low RCS pressure trip.,
Review of previous surveillance identified that inade been performed on two other occasions for channels "B"quate testing had and "C".
Immediate changes were made to the procedures and satisfactory testing of the "B". "C", and "D" channels were completed. The "A" channel was already scheduled.for. a later date since the testing was done on a staggered basis as described in ITS.
Testing had also been conducted during mode ascension in January of 1998 but this issue did not surface then because T-hot was much less than 590 F (T-hot of 590*F also corresponds to a power level of 52%)..
Procedure validation had been 3erformed on the plant simulator prior to the initial use of the SPs.
]ut did not include 100% power operation since the surveillance was initially going to be performed prior to power operation.
The inspector and the I&C technician who identified the problem walked
' through the part of the surveillance where the anomaly occurred. The RPS cabinet containing the "D" channel trip modules has the low pressure trip module and the variable P/T tri) module separated by a row of other modules, and at opposite ends of eac1 other. However, the previously tested "B" channel RPS cabinet was configured such that the low pressure trip module and the variable P/T trip module were adjacent to each other.
The licensee had revised the surveillance procedures in 1997 to address bistable testing as a result of Generic Letter (GL) 96-01 reviews.-
However, the procedures did not address the effects of 3ressure and temperature inputs on testing of the low pressure bista)le.
The corrective actions initiated by the licensee were to: perform a review of RPS bistables to determine if other bistables could be subjected to a similar condition: revise training and qualification requirements for maintenance procedure writers performing activities involving the development of testing methodologies for safety related electrical circuitry: incorporate the incident into lessons learned for procedure writers and qualified reviewers; and, develop and implement an
" unexpected scenario" into I&C technician continuing training on the plant simulator.
The licensee took prompt and appropriate corrective actions once the issue was identified. Consistent with Section VII.B.1 of the Enforcement Policy, this non-repetitive, lkensee-identified and corrected violation of TS surveillance requirements was treated as a Non-Cited Violation. NCV 50-302/98-07-02. Inadequate Testing of Reactor Protection System Electrical Circuitry.
c.
Conclusions An excellent questioning attitude and attention to detail were displayed by an Instrumentation and Controls technician that identified an anomaly during reactor protection system testing of the reactor coolant system
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low pressure trip.
Previous opportunities to identify the same anomaly were missed during validation testing and testing by other technicians.
M1.3 Emeraent Work Item to Reoair SWP-1A Mechanical Shaft Seal a.
Insoection Scooe (62707)
The inspector observed the replacement of a Service Water (SW) pump 1A mechanical shaft seal performed after the failure of the seal several hours earlier.
The work was Jerformed under WR 0355014. SWP-1A:
Eliminate Leak From South Meclanical Seal.
b.
Observations and Findinas The inspector noted that maintenance planners and supervisors were immediately called out to the plant by Operations. and work packages were promptly prepared for the seal replacement. The seal vendor was also summoned to provide support to the plant. A thorough pre-job briefing was done that included refresher training on the seal replacement evolution and work began at 9:30 a.m.
The mechanical technicians were experienced and knowledgeable of their tasks and a supervisor and component engineers were present at all times at the job site for support.
The workers displayed good teamwork in that they were cautious and self-critical, frequently Jausing to discuss aspects of the evolution between the two workers and tie 3rocedure reader.
Excellent LCO time sensitivity was evident in that tie job was worked continually, the technicians were all aware of the LC0 duration, and the job was expeditiously released to Operations for clearance tag restoration when complete.
The inspector observed that the licensee Maintenance Procedure (MP) contained within the WR was used consistently by the technicians. The inspector considered this notable, because a procedure guide poster with detailed pictures for the seal installation had been supplied by the seal vendor in the seal package. The workers recognized this had not been evaluated or incorporated into the licensee's vendor document system, and consequently did not rely on it.
The inspector attended the maintenance crew's post-job critique and observed that the crew identified several enhancements and 3rocedural improvements. The critique discussion was open and all mem)ers participated. The inspector observed a good sense of ownership by the team for the condition and reliability of plant equipment.
The inspector interviewed the mechanical shop component engineers and.
reviewed their reports on previous mechanical seal problems.
The inspector observed the engineers were thoroughly evaluating the current failure of the SW pump mechanical seal and had been tracking and resolving previous mechanical seal concerns.
The WR had been designated as " repeat maintenance" since the same pump seal had been replaced on
.
May 5. 1998 and PC 98-3367 was initiated to pursue the cause of the repeat maintenance.
The cause of the current seal leakage was postulated to be due to a normal pressure transient in the SW system from swapping pumps.
The licensee determined that the gasket between
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the seal housing and pump stuffing box extension had dislodged, causing
l the leakage, and.that the seal assembly itself was intact and functional. Metal to metal cuts on opposite sides of the seal indicated it had become slightly cocked, which would have caused the gasket to leak. The inspector inspected the removed seal, verified the above
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indications. and considered the licensee explanation reasonable with the given indications. The licensee was obtaining an improved seal design from the vendor to correct the problem.
The inspector also reviewed the previous seal failure analyses and observed that the seal failures did not seem related.
c.
Conclusions The emergent job to replace a leaking service water pump mechanical seal was well executed.
Work packages were )romptly prepared, workers displayed good teamwork, and excellent _C0 time sensitivity was evident.
Good component engineer su) port was observed for the seal replacement and the investigation of t1e seal leakage cause.
M3 Maintenance Procedures and Documentation M3.1 Inservice Testina'(IST) Proaram a.
Insoection Scooe
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The inspectors reviewed portions of the inservice testing (IST) second ten year interval (ends 8/13/98) and the third ten year interval (starts 8/14/98) program manuals, b.' Observations and Findinas The inspectors determined that the program manuals were consistent with the ASME Section XI Boiler and Pressure Vessel ap)licable codes.
To ease the transition from the second interval to t1e third ten year interval, the licensee has already implemented the ASME/ ANSI Operations and Maintenance Standards (0M) Endorsed by 10 CFR 50.55a and ASME Section XI Boiler and Pressure Vessel Code. Subsections IWP and IWV.
10 CFR 50.55a(b) references the ASME/ ANSI OM standards 1987 edition and OM 1988 addenda as the applicable standards for the third ten year interval IST program at Crystal River.
The inspectors found the third ten year interval program document consistent with these OM standards.
Elements of the Code OM standards are incorporated into the Manual and in plant procedures.
The systems included in the program were identified and pump and valve tables identified the com tests, test frequencies, procedures and any deferrals. ponents. type of c.
Conclusions The Program Manual for the third ten year IST interval was consistent with the Code Standards.
M3.2 IST Proaram Manual Scooe
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.13 a.
Insoection Scone (73756)
The inspectors reviewed certain aspects of the licensee *s inservice
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testing including program, procedures.and implementation to verify that
the licensee has established and is following an acceptable program.
,
b.
Observations and Findinas
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System Scooe Reviews
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l The inspectors reviewed the Emergency Feedwater (EF) and Building Spray (BS) system procedures and P& ids to verify that all valves affecting the
,
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flow path of these systems were tested in the IST program. All of these valves were in the program. Additionally the inspectors verified the test frequency for the quarterly tested pumas and valves back to 1995.
Some valves in EF and BS systems which disc 1arge directly to the once thru steam generator or to the building spray header are cold shutdown L
or refueling outage tests and have not been performed since the plant l-restart in February of 1998. These valves haever are identified in the cold shutdown procedure and justification for cold shutdown testing is provided. -Some of the valves such as building spray valves must be i
disassembled per procedure SP 620."ISI Check Valve Inspection." Revision 5.
All valves were tested prior to plant startup in February 1998.
In this review the inspectors noted that many valves previously categorized as passive in one direction and having a safety function in the other
!
direction are now classified as Active and are stroke tested in both l
directions. This resulted after a meeting with the NRC where the position was promulgated that a valve with an active safety function could not be classified as a passive valve. The inspector reviewed the basis document for valves in these systems, pump and valve data sheets, test procedures, and verified test frequencies and cold shutdown justifications (CSJ) where appropriate.
i L
Procedures reviewed, in part, or totally included but were not limited L-to the following:
'SP-340B."DHP-1A. BSP-1A. And Valve Surveillance." Revision 35 SP-349A."EFP-1 And Valve Surveillance." Revision 32
i SP-370.~0uarterly Cycling of Valves." Revision 71 SP-640A,"EFP-1 Full Flow Test." Revision 11
SP-620."ISI Check Valve Inspection." Revision 5
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SP-340B."DHP-1A. BSP-1A And Valve Surveillance." Revision'35 The procedures were reviewed for consistency with the OM requirements rather than component manipulations.
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Conclusions L
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The licensee identified the ASME Class 1. 2. and 3 components which have a function in shutdown of the plant to a safe shutdown condition, maintaining safe shutdown, and in mitigating accident conditions.
Appropriate procedures have been developed and testing is performed in accordance with plant procedures.
M3.3 Comoliance Procedure (CP)-102."IST Pumo and Valve Data Review (73756)
a.
Insoection Scooe (73756)
The inspectors reviewed CP-102 to verify acceptable evaluation and resolution of IST problems.
b.
Observations and Findinas CP-102."IST Pump and Valve Data Review." Revision 28. provides the guidance for the review and evaluation of surveillance test data accumulated under the ASME Section XI IST program.
Res)onsibilities of the supervisor. Nuclear Engineering Programs. Nuclear Slift Supervisor, and IST Program Manager are delineated in the procedure.
Enclosures 1 and 2 of the procedure provide the required actions if a pump or valve fall into the alert or required action range.
Part 1 of the enclosures, completed by the Nuclear Shift Supervisor, documents the failed condition.
Parts 2 and 3 of the enclosures, completed by the IST program manager, documents the actions taken and the final resolution of the failed condition.
The IST Program Manager reviews all IST surveillance results and is responsible for transmitting CP-102 documents to document control.
The inspectors reviewed the following CP 102 reports:
07/08/98 BSV-4:
Valve stroked outside the acceptance criteria.
Declared inoperable until problem was identified. corrected.
and valve was rebaselined.
01/30/98 EFV-34 and EFV-35: This CP-102 evaluation was performed to establish the validity of a baseline change due to a plant modi fication.
12/18/97 EFP-1:
This CP was performed after excessive vibrations were measured at flow of 730 gpm for testing Cavitating Venturi. At referenced value the pump was in acceptance range.
12/14/97 EFV-35:
Differential pressure measurements indicated the Valve was not fully open.
Valve declared inoperable.
Problem was resolved when it was determined that a plant modification made the procedure differential pressure invalid.
A recalculation of differential pressure showed the valve was fully open.
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The inspectors found SP-435 to be in conformance with the requirements of ASME/ ANSI 0.M.-10. Part 10. 1988 Addenda. The procedure if-implemented before 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />'after cold shutdown, may be terminated when
. ready to return to power.
If implemented after 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. all valves must be tested.
Consequently scheduling becomes an important aspect of-cold shutdown testing. Some valves are tested at cold shutdown by a system procedure such SP-349A-and B or~SP-640 which tests certain EFVs at full flow into the OTSG.
Valves not tested in system tests are-tested per SP-435. The inspector talked with the scheduling coordinator to determine how the valves in SP-435 were tracked.
Each time the reactor descends in mode SP-441 is invoked to track required-surveillance prior to ascending in modes.
SP-441 identifies cold shutdown testing along with the instructions that testing is to begin within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of cold shutdown or the entire procedure must be performed. The coordinator is responsible for looking at previous performance of SP-435 to determine which valves need to be tested such that eventually all valves are tested, c.
Conclusions The inspectors reviewed acceatance criteria in IST procedures and found them to be consistent with tie ASME/ ANSI 0.M. Standards. Test criteria were indicated on the EDS.
M7
. Quality Assurance (QA) in Maintenance Activities M7.1 Self-Assessment of IST Procram (73756)
The licensee 3erformed an extensive self assessment (STSANEP 97-26 dated 10/15/97)of tie IST program from January 17 to September 26, 1987 to.
- verify that the current program meets the 1983 code requirements. The assessment was a review of the entire program system by system. Any item not meeting the current program was identified as an open item.
Additionally any item that would not meet the requirements of the 1989 code for the third interval was identified as an open item to be resolved before the third interval beginning 8/14/98.
Eleven Precursor Cards (PC) were issued to correct identified problems.
The inspectors reviewed these PCs and concluded that adequate corrective actions had been implemented.
For instance. PC 3-C97-1111 documented the engineering. review of Emergency Feedwater i. solation valves EFV-11, 14. 32. 33. These valves (part of D-70 restart item) were reviewed for design basis stroke time and the requirement to test in both open and closed direction.
PC 3-C97-3246 documented a preconditioning activity during surveillance testing due to the way the )rocedures were written.
The procedures were revised to correct this pro)lem.-
M8~
Miscellaneous Maintenance Issues (92902)
M8.1 (Closed) LER 50-302/98-06-00:
Personnel Error Resulted in a Condition Prohibited by Technical Specifications. The details of this issue are discussed in Section M1.2 and were identified as a non-cited violatio __-____
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05/08/96 EFP-1: This CP-102 was performed to rebaseline EFP-1 at full flow conditions after installation of a new rotating assembly The inspectors considered the evaluations and problem resolutions consistent with IST requirements.
c.
Conclusions The licensee has developed and implemented a review process which assures IST requirements were considered for component failures. It also assures that the IST Program Manager is informed of component conditions.
M3.4 IST Procedures (73756)
a.
Insoection Scone The inspectors reviewed procedures to verify that OM standards and controls were incorporated into the procedures. The procedures were not reviewed for component manipulations.
b.
Observations and Findinas Certain procedures were reviewed to determine their conformance with the requirements of the OM standards.
In addition to those identified in other Sections of this report, the inspectors reviewed the following for conformance with the ASME Section XI code and the referenced Operation and Maintenance (OM) standards:
SP-602:
"ASME Section XI Relief Valve Testing." Revision 25 SP-435:
" Valve Testing During Cold Shutdown." Revision 48 SP-441:
" Unit Shutdown Surveillance Plan " Revision 43 The inspectors found SP-602 to be in conformance with ASME/ ANSI OM-1.
Part 1.1987 Edition, which specifies the requirements for relief valve testing.
Minimum hold times were stated and the test methodology described. The inspector noted that the licensee did not include a step in the procedure to document that integrity of the balancing device was inspected and verified. The licensee directed that this would be addressed.
The inspectors also reviewed engineering data sheets (EDS).
The EDS is an integral part of the test procedures and is computerized in the IST data base.
There is a unique sheet for each component which provides component information, acceptance ranges. limiting values and reference values.
Also, data points to be recorded and the type of test are identified. Engineering has reviewed all data sheets and specified the most conservative of Technical Specification. Design Basis or code calculated limiting values.
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A previous LER (LER 50-302/97-03-05) also discussed testing deficiencies identified during the licensee's review of GL 96-01 issues. After reviewing the corrective actions described in'the LERs. the inspector determined them to be incomplete and insufficient to prevent recurrence.
However, taking into consideration the corrective actions described in the precursor card that captured the issue in the licensee's Corrective-Action System (PC 98-2509), the inspector concluded that the licensee's corrective actions were appropriate and should prevent recurrence.
This LER is closed.
III. Enaineerina E2 Engineering Support of Facilities and Equipment E2.1 Plant Comouter Malfunctions a.
Insoection Scooe (37551)
Malfunctions of the licensee's plant computer occurred on July 4 and 11.
<
1998. The inspectors reviewed logs, interviewed computer engineers, and
'
observed the indications exhibited on the latter malfunction.
There have been computer malfunctions previously.
The inspectors have been closely monitoring the licensee's implementation of an upgrade to the computer.
b.
Observations and Findinas The malfunction on July 11. 1998 occurred during a power increase from 85 to 90% and was quickly-detected by the NSS who was alertly monitoring plant parameters, when computer display points for thermal and electrical power stopped updating.
0)erations entered their Abnormal Procedure (AP)-430. Loss of the )lant Com) uter and the inspector verified they complied with several ITS _CO's for loss of reactor power distribution parameters and alarms.
The licensee had previously experienced problems with the plant computer that recuired entry into ITS LCOs. which were not recognized by operators, anc were the subject of Violation 50-302/98-03-01. Failure to Meet Surveillance Requirements for Axial Power Imbalance.
The licensee's corrective actions included warnings such as an alarm and a visual white "X" on the monitor screen to alert operators to a loss of the computer.
The inspector observed that none of these warnings were present during this l
malfunction and that parameters such as the plant computer clock and a
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few secondary plant points continued to change. The inspector also considered the timing of the computer malfunction to be fortuitous because the aforementioned indications would have made it very difficult
!
.for operators to detect the failure during steady-state operations and
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i:
l thus enter the required ITS LCOs.
I The licensee determined the failure was due to a malfunction in the l
point process monitor. which caused the computer to continue processing
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information but not update the display points.
The warnings developed
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18 for the 3revious corrective actions did not alert the operators to this problem )ecause the warning functions were monitoring for a malfunction of the computer in processing and sending information, which had not stopped.
The inspector considered the licensee's corrective actions for the previous computer failure were not broad enough.
The licensee determined the computer malfunction on July 4,1998, was due to the activation of a conflicting subroutine.
They were unable to determine how it was activated, but postulated it had been started by an operator attempting to activate a function that was no longer used.
The ins)ectors noted that Operations continues to be challenged by unrelia)ility of the plant computer.
However, the inspectors recognize that the licensee's computer upgrade will replace the present plant computer by the end of 1998.
The licensee was developing monitoring functions to alert operators to any further malfunctions, but limited the scope of the activity due to the pending replacement of the com) uter. The new system contains features that will address the pro)1 ems.
Until the upgrade is completed, the inspectors remain concerned about the reliability of the plant computer.
Malfunctions of
{
the system occurred twice in this report period and deficiencies with J
compensatory actions are discussed in Operations Section 01.3.
c.
Conclusions Reliability of the plant computer remains poor and continues to present challenges to the operators.
Modification and upgrade of the current system is in progress. Although corrective actions for previous computer malfunctions did not aid in warning of a subsequent computer display problem. operators alertly detected the problem during a power increase.
E8 Miscellaneous Engineering Issues ( 92700 and 92903)
E8.1 (Closed) VIO 50-302/97-17-04:
Inadequate Design Control for Thermal Relief Valves.
The licensee had removed thermal relief valves from
several heat exchangers when they incorrectly assumed that these valves
!
were redundant.
When reinstalling the valves, an engineer overlooked i
the replacement of a decay heat closed cycle cooling system valve (DCV-
!
109). The inspector verified corrective actions have been implemented by the licensee as follows:
thermal relief valves that had been ina)propriately removed have been reinstalled, including valve DCV-109:
worc requests were reviewed for e:ch component identified in the design change package to replace obsolete thermal relief valves and no
'
additional omissions were identified; and, enhancements have been made to the design change )rocess to emphasize adherence to applicable j
licensing and design )ases. The inspector considered these corrective actions to be appropriate and sufficient.
E8.2 (Closed) VIO 50-302/96-01-06:
Failure To Correctly Translate Design l
Basis Of SW System Into Procedures. Drawings. And Instructions.
This item was previously reviewed in irs 50-302/96-04, 97-13 and 98-01 and l
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involved the possibility of SW system valves for all three Reactor
, Building Cooling Units -(RBCU) opening with only one SW pump in operation, increasing total SW flow and load on the emergency ~ diesel generator (EGDG) above its approved load limit. The only remaining corrective action for this problem was an interlock to prevent loading two RBCus on one EGDG.
This modification was identified as an Unreviewed Safety Question (USQ). so License Amendment Request (LAR) 217 l-was submitted by the licensee on October 4, 1997.
License Amendment 166 l
.was issued by the NRC on April 29, 1998, to approve the LAR and allow installation of.the modification. The licensee installed and tested MAR 97-07-01-01 in June of 1998. The inspector observed testing of the
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r interlock and verified that procedures and surveillance testing were i
' changed to ensure no more than two RBCUs were aligned to the SW system.
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.E8.3- (Closed) IFI 50-302/95-15-02.
Design Requirements For Dynamic LOCA
!
Effects & Pressurizer Surge Line Effects
.
(Ocen) LER 50-302/98-01-00: Structures. Systems And Components Were Not j
Protected From The Dynamic Effects Of A Loss Of Coolant The first item was previously reviewed in IR 50-302/95-21 and in a letter from the Office of Nuclear Reactor Regulation (NRR) staff to the licensee dated April 10, 1997.
It involved the possibility of SW system piping in the reactor building to be impacted and breached by the dynamic effects of an RCS line break; specifically, the pressurizer surge line. The closed loop SW system piping is a containment integrity barrier and was required, per Final Safety Analysis Report (FSAR),
section 1.4.40, to be protected against the dynamic effects of a Loss of Coolant Accident (LOCA). The licensee had been actively pursuing resolution of this issue as a restart item during the )lant outage from September 1996 to January 1998 and the inspector and N1R staff had been closely following the licensee's progress throughout the outage.
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The licensee had originally considered leak-before break (LBB) RCS criteria to resolve this concern, but the April 10, 1997. NRR letter delineated that LBB did not apply to the licensee's RCS branch lines, such as the pressurizer surge line.
The licensee did field inspections
!
of the surge line, documented the results to the NRC in letter 3F0697-13 l
dated June 5. 1997, and determined there was no potential interaction with SW piping from pipe whip of the surge line, but that jet impingement effects were possible and would need to be further evaluated. The licensee subsequently concluded the jet impingement effects would not adversely affect the SW piping in letter 3F0997-01.
dated September 29. 1997.
However, the basis of the assessment relied upon changes to the plant licensing basis which they determined did not constitute a USQ because they were consistent with analytical methodologies already approved by the NRC for other )lants. The NRC staff questioned the validity and applicability of t11s determination in a letter to the license dated October 9. 1997.
In letter 3F1197-29 dated November 7. 1997, the licensee retracted the conclusion based on the licensing basis changes and committed to resubmit their conclusions following an analysis using their existing licensing basis.
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On December 13, 1997, the licensee reanalysis concluded that the jet-impingement on SW had a negligible deformation effect on the integrity of the SW piping. They documented the impact on the SW piping as a fully operable nonconformance with their licensing basis in a L
Justification for Continued Operation (JCO).
However, as part of restart inspections, the JC0 was reviewed by NRR staff, who issued a request for additional information for effects on systems other than SW i
in r letter dated December 22, 1997, based on questions regarding
'
exciusion of Regulatory Guide (RG) 1.97 instrument and Post-Accident Sampling System (PASS) lines. The-licensee did a walkdown of the affected areas which confirmed the staff concerns and identified several
'
more nonconformances which were documented in LER 50-302/98-01-00. The licensee issued letters 3F0198-34 on January 23, 1998. 3F0198-31 on January 28. 1998, and 3F0298-17 on February 18. 1998, to resolve the short term disposition of these specific concerns with the NRR staff for restart a) proval. The licensee submitted LAR 225 on May 28. 1998, to address tie permanent resolution of this problem by changing the licensing basis.
The inspector reviewed the LAR. reviewed the licensee Deficiency Report /JC0 for the remaining nonconformances, and interviewed the responsible licensee structural engineers overseeing this project..The inspector concluded that the proposed LAR changes to their licensing basis adequately resolved the originally-identified concerns in Inspection Follow-up Item (IFI) 50-302/95-15-02. so that item is considered closed.
However.. in the LAR the licensee stated that the remaining RG 1.97 and
. PASS instrument nonconformarices delineated in their February 18, 1998 letter and LER 50-302/98-01-00 would not be physically modified. The basis was that the instruments would not be relied u)on to limit or mitigate the consequences of the specific event whic1 could disable them and that they would change the design basis for these instruments to accept them as-is under the 10 CFR 50.59 process.
However, as of the
'
end of this inspection report period. the licensee had not performed the analysis for this change and was still utilizing the JC0 conclusion to justify operability. Consequently. LER 50-302/98-01-00 remains open pending completion of the analysis.
E8.4 (Closed) EA 96-365 VIO B-(02013): Error In Design Calculations For Service Water Heat Load i
.(Closed) LER 50-302/97-25-00 and 01:
Service Water Raw Water Temperature Calculation Contains Non-conservative Assumptions (Ocen) LER 50-302/97-25-02:
Service Water Raw Water Temperature Calculation Contains Non-conservative Assumptions.
' The inspector conducted further review of these items, as previously discussed in IR 50-302/98-06. The inspector also reviewed revision 2 to the LER which was submitted to address the failure to report additional problems with the control complex chiller starting ability at elevated i
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SW temperatures.
EA 96-365. V10'B (02013) was originally issued for errors in changing the design basis upper limit for the ultimate heat sink (UHS) from 85 to 95 degrees F.
The licensee has expended significant effort reanalyzing
!
those calculations, which the inspector verified in the course of reviews for LER 50-302/97-25. There are no more remaining open items in the original-scope of EA 96-365. VIO B (02013) so it was closed.
The inspector reviewed the licensee *s corrective actions to resolve the remaining SW and'RBCU heat transfer concerns and concluded they had com)leted implementation of the modification associated with this aro)lem.
The RBCU and SW concerns identified in revisions 00 and 01 of
_ER 50-302/97-25 have been addressed, so those items were closed.
The inspector reviewed revision 02 to the LER which was submitted on July 8, 1998, to discuss remaining problems with control complex habitability envelope (CCHE) chiller problems relative to SW.
These
)roblems were previously discussed in IR 50-302/98-06 and have not yet
)een finally resolved.
Interim corrective actions were implemented by a licensee JCO. which the inspector reviewed and considered adequate.
Consequently. revision 02 of the LER remains open for the licensee *s final resolution of the CCHE chiller limitations.
The inspector noted that the LER sup)lement for the CCHE chiller issue omitted several details on the c1ronology of the problem and did not address the lengthy delay.in reporting it. However, the licensee *s technical analysis was still ongoing and they were evaluating the need for a separate LER as part of it.
E8.5 (Closed) LER 50-302/97-40-00: Inadequate Engineering Documentation For Safety-related Large Bore Piping Analysis And Pipe Supports. This issue involved missing or inadequate design analysis documentation for large bore safety related piping and supports and the possible need to reconstitute these records.
It was originally identified as IFI 50-302/97-14-10. and Task Interface Agreement (TIA)97-024 was initiated to obtain further NRR staff input on the acce)tability of the licensee *s long term action plan.
In the interim, NRR staff obtained and reviewed licensee documentation on the scope of the issue. The licensee issued LER 50-302/97-40-00 on December 4. 1997, and letter 3F1297-33 on December 8.1997 delineating their plans to perform a comprehensive review program over two to three fuel cycles. Short term resolution was accomplished by a licensee Deficiency Report and JC0 which were reviewed by the staff.
TIA 97-024 was issued February 9. 1998, to document the above staff reviews and concluded that the licensee had adequately justified large bore piping operability and that no further review was needed.
TIA 97-024 is attached as an enclosure to this report.
IFI 50-302/97-14-10 was then closed, but LER 50-302/97-40-00 remained open to track the licensee's long term reconstitution of large bore piping calculations. because the licensee planned to supplement the LER as discrepancies were found. The licensee no longer plans to supplement the LER. and will disposition all discrepancies via their normal
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corrective action processes. The licensee submitted a final plan and
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schedule for the Large Bore Piping Project on June 30. 1998., and a meeting between the NRR staff and the licensee was held on July 24.
1998 to discuss the project. The NRR staff did not have any significant concerns with the licensee's plans. Although this item was a noncompliance with regulatory requirements, for the reasons discussed in IR 50-302/97-21, the licensee met the criteria for enforcement discretion per Section VII.B.2 of the Enforcement Policy as described in NUREG-1600.
Consequently. this item was closed and was identified as a further example of NCV 50-302/97-21-01. Examples of Noncompliance in Design Control. 50.59 Evaluations Procedure Adequacy, Deportability, and Corrective Actions That Are Subject to Enforcement Discretion.
E8.6 (Closed) IFI 50-302/96-15-03: Actions Taken To Resolve Recriticality Concerns Due To Localized Boron Dilution. This item was discussed and closed in IR 50-302/98-06, but the investigation ofsthe cause for an inspector-identified procedural problem was still ongoing.
Enclosure 16, Reactor Coolant Pump (RCP) Recovery, of Revision 2 of procedure E0P 14. E0P Enclosures, and contained unclear guidance for restart of a RCP.
in that it stated that it was " preferred" versus the required "must" to
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start the RCP in the loop with natural circulation. The licensee determined that the correct terminology had originally been used when E0P 14 was corrected in Draft B of revision 2. but that the subsequent Draft V had altered the terminology to address another problem, and the incorrect terminology was issued in revision 2.
The inspector verified the licensee drafts reflected this secuence of events. The. inspector reviewed their E0P control process anc concluded the current licensee controls on the E0P configuration were adequate, and their corrective action to incorporate interim owner's group guidance in their cross step document would address the problem. The inspector concluded that this was an isolated example, and that no other similar incorrect terminology changes had been implemented. The inspector considered it unlikely that the wrong RCP could have been started due to the incorrect terminology, which minimized the safety-significance of the error.
IV. Plant Sucoort R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 General Comments (71750)
The inspectors identified a minor concern with licensee Health Physics (HP) personnel's control of the painting contractors due to several personnel contamination events. However. licensee management shared similar concerns and was aggressively pursuing resolution of the problems with the HP staff. The inspectors considered the licensee's corrective actions were appropriate.
l V. Manaaement Meetinas X1 Exit Meeting Summary
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The inspection scope and findings'were summarized on July 30. 1998.
Proprietary information is not contained in this report.
Dissenting
- ' comments were not received from the. licensee.
X3 Management Meeting Summary X3.1 On July 2.1998..a meeting was held in Crystal River to discuss the NRC's Systematic Assessment of Licensee Performance (SALP) for Crystal River Unit 3. A Oparate meeting summary was issued on July 9.1998.
PARTIAL LIST OF PERSONS CONTACTED Licensees R. Anderson Senior Vice President. Energy Supply S. Bernhoft, Manager. Nuclear Licensing J. Cowan. Vice President. Nuclear Operations R.. Davis. Assistant Plant Director. Operations and Chemistry R. Grazio. Director Nuclear Regulatory Affairs
- G. Halnon. Director. Nuclear Quality Programs B. Hickle. Acting Director. Nuclear Operations Training-J. Holden. Director. Site Nuclear Operations S. Johnson. Assistant Plant Director. Nuclear Safety M. Marano. Director,. Nuclear Site & Business Support C. Pardee. Director. Nuclear Plant Operations W.-Pike. Manager. Nuclear Regulatory Comaliance M. Schiavoni. Assistant. Plant Director. Maintenance
'J. Terry. Acting Director Nuclear Engineering & Projects
- EC H. Whitener. Reactor Inspector. Region II (July 6 - 17, 1998)
INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering IP 40500:
Effectiveness of Licensee Controls in Identifying. Resolving and Preventing Problems IP 61726:
Surveillance Observations IP 62707:
Conduct of Maintenance IP 71707:
Plant Operations IP 71750:
Plant Support Activities
IP'73756:
Inservice Testing of Pumps and Valves i
IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92902:
Followup - Maintenance IP 92903:
Followup - Engineering L
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ITEMS OPENED, CLOSED, AND DISCUSSED Opened lyJ2g Item Number Status Description and Reference
.NCV 50-302/98-07-01 Closed Failure to Fully Open and Seal Service
Water Pump Suction Valve. (Section 01.2)
NCV.
50-302/98-07-02 Closed Inadequate Testing of Reactor Protection System Electrical Circuitry. (Section l
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M1.2)
Closed Tygg Item Number Status Description and Reference
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NCV:
50-302/98-07-01 Closed Failure to Fully Open and Seal Service Water Pump Suction Valve. (Section 01.2)
l NCV 50-302/98-07-02 Closed
. Inadequate Testing of Reactor Protection
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System Electrical Circuitry. (Section M1.2)
LER 50-302/98-06-00 Closed Personnel Error Resulted in a Condition Prohibited by Technical Specifications.
(Section M8.1)
VIO 50-302/97-17-04 Closed Inadeq-uate Design Control for Thermal Relief Valves. (Section E8.1)
l VIO 50-302/96-01-06 Closed Failure to Correctly Translate Design
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Basis of SW-System into Procedures, Drawings, and Instructions. (Section E8.2)
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IFI 50-302/95-15-02 Closed Design Requirements for Dynamic LOCA
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Effects / Pressurizer Surge Line Effects.
(Section E8.3)
VIO EA 96-365 VID B Closed Error in Design Calculations for SW (02013)
System Heat Loads. (Section E8.4)
LER 50-302/97-25-00 Closed Service Water Raw Water Temperature 50-302/97-25-01 Calculation Contains Non-Conservative Assumptions. (Section E8.4)
LER 50-302/97-40-00 Closed Inadequate Engineering Documentation for Safety-Related Large Bore Piping Analysis I
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& Pipe Supports. (Section E8.5)
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Discussed IX2e ' Item Number
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Description and Reference LER 50-302/97-03-05 Closed Personnel Error Causes Testing Deficiencies Resulting in a Condition Prohibited by Technical Specifications.
(Section M8.1)
VIO--50-302/98-03-01 Open Failure to Meet Surveillance Requirements.
for Axial Power Imbalance. (Section E2.1)
LER 50-302/98-01-00 Open Systems, Structures & Components were not Protected from Dynamic Effects of a LOCA.
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(Section E8.3)
'LER-50-302/97-25-02 Open Service Water Raw Water Temperature Calculation Contains Non-Conservative Assumptions. (Section E8.4)
.IFI-50-302/97-14-10 Closed NRC Follow-Up that Licensee Approach for Resolution of Deficiency Associated with Lack of Documentation for Original Piping and/or Su) port Calculations is Acceptable.
(Section E8.5)
NCV-50-302/97-21-01-Closed Examples of Noncompliance in Design Control. 50.59 Evaluations Procedure Adequacy. Deportability, and Corrective Actions That Are Subject to Enforcement Discretion. (Section E8.5)
IFI 50-302/96-15-03 Closed Actions Taken to Resolve Recriticality.
Concerns Due to Localized Boron Dilution.
(Section E8.6)
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MEMORANDUM TO:
Jon R. Johnson, Director Division of Reactor Projects Region ll FROM:
Fred J. Hebdon, Director Project Directorate ll-3 Division of Reactor Projects 1/11 Office of Nuclear Reactor Regulation SUBJECT:
NRR RESPONSE TO TASK INTERFACE AGREEMENT (TIA)97-024 PIPING AND SUPPORT DOCUMENTATION RECONSTITUTION (TAC NO.
M99948)
During the October 1997 Safety System Functional Inspection (SSFI) conducted at the Crystal River Unit 3 (CR3) facility, the inspectors identified a concern that the large bore safety-related piping and support calculations were not in the possession of the licensee.
The licensee determined that this was not a restart issue and planned to implement a long term action to reconstitute missing calculations.
By memorandum dated November 5. 1997 Region II requested assistance of the Office of Nuclear Reactor Regulation (NRR) in evaluating the acceptability of the licensee's planned actions.
In response to your request, the NRR's Mechanical Engineering Branch evaluated the CR-3 large bore piping, with emphasis on the licensee's assessment of the piping operability.
Our safety evaluation is attached.
This completes our action on technical assignment control (TAC) No.
M99948 and the TAC is closed.
Docket no.
50-302 Attachment:
Safety Evaluation cc:
C. Hehl. Region I G. Grant. Region III T.
Gwynn. Region IV CONTACT:
L.
Raghavan. NRR 301-415-1471 Distribution Docket File CR3 Reading J.
Lieberman E.
Adensam (A)
L.
Wiens J. Zwolinski (A) ACRS F.
Hebdon
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Raghavan R.
Wessman K
Manoly J.
Jaudon S.
Bloom (Email SDB1)
S. Richards B.
Clayton i
Document Name: G:\\ CRYSTAL \\TIA97024.clo To receive a copy of this document, indicate in the box:
"C" - Copy without attachment / enclosure
"E" = Copy with attachment / enclosure
"N" - No copy l0FFICE PDll-3/PM lE PDil-3/LA lE PDll-3/D l
D: DRPE l
l lNAME LRaghavan BClayton FHebdon JZwolinski lDATE 08/
/98 08/
/98 08/
/98 02/
/98 0FFIClAL RECORD CCPY
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SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION LARGE BORE PIPING ISSUE FLORIDA POWER CORP 0MTION CRYSTAL RIVER UNIT '
DOCKET NO.-50-302 1.0 INTRODUCTION An October 1997. Safety System Functional Inspection (SSFI) at Crystal River Unit 3 (CR-3) noted that Florida Power Corporation (FPC),
the licensee for CR-3, lacked adequate engineering calculations to support the qualification of large bore safety-related piping and Jipe supports. The SSFI also determined that the licensee has been aware of tais issue, has had two consultants (Wais Associates and J.
D.
Stevenson Consulting Engineer) assess the overall issue of pi)ing design and documentation at CR-3 and its implications on systems opera)ility, and is taking actions to address the identified discrepancies.
Subsequent to the SSFI inspection, the U.S. Nuclear Regulatory Commission (NRC) Region II issued a TIA on November 5,1997. recuesting NRR to determine if the licensee's actions are adequate, and indicatec that the SSFI team finding regarding this issue is a potential restart item.
2.0 BACKGROUND In 1991, the NRC issued NUREG-1397 (An Assessment of Design Control Practices and Design Reconstitution Programs in the Nuclear Power Industry). This report was based on a survey of six utilities. including FPC, and one Nuclear Steam System Supply (NSSS) vendor. The staff acknowledged in this report that some older facilities may lack certain design documentation, they may involve operability issues, and that reconstitution efforts could take 3-4 years.
On October 9,1996, the NRC issued requests for information to all reactor licensees Jursuant to 10 CFR 50.54(f) regarding the adequacy and availability of design Jasis information. This request was prompted by inspections and reviews that revealed various weaknesses in design and configuration deficiencies in operating plants.
FPC responded to this request on February 8, 1997, and concluded that their " current processes and 3rograms provide reasonable assurance that the configuration of CR-3 will >e maintained consistent with the design basis."
The CR-3 and other licensee responses were reviewed in early 1997. The review process was described in SECY 97-160, dated July 24. 1997.
In the case of CR-3. the staff did not agree with the above FPC assertion and noted that the Integrated Performance Assessment Process inspection in 1996 and a recent escalated enforcement action indicated that the licensee's programs for design control. 50.59 safety evaluations, and corrective actions were inadequate.
The October 1997 SSFI confirmed the above staff's review findings in that FPC lacked adequate engineering calculations to support the qualification of large bore safety-related piping and pipe supports.
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Attachment
"In atletter dated November 10. 1997. FPC~provided NRC its assessment of the
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large bore piping issue and other SSFI issues. FPC stated that "all currently identified code compliance issues associated with large bore pi)ing and pipe supports will be corrected prior to restart..." and concluded t1at "no condition exists that would challenge the ability of systems, structures or com)onents to perform their safety function of preventing or mitigating design ) asis events." FPC referred to reviews conducted by the above consultants and mentioned various
_ actions that have been or are being taken to sup) ort their conclusion.
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l Additionally. FPC. stated that they plan a compre1ensive inspection and revalidation /requalification project to address this issue that will span the next 4-6 years.. Subsequently. FPC provided additional details in a letter.
dated November 18. 1997.
In" order to respond to the Region II TIA, the NRR staff decided to conduct an
' expanded review of the CR-3 large bore piping issue. The review was structured to obtain a validation of the assertion and statements made by FPC
'in their November 10. 1997 letter regarding the o)erability and other design aspects relating to large bore piping at CR-3. T1e licensee was requested to provide specific examples of recent requalification actions for portions of piping systems, examples of identified code compliance concerns that have been corrected, and examples of some of the discre consultants (along with the FPC dispositions)pancies identified by FPC's
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3.0 EVALUATION A conference call was held between the st'aff and FPC personnel on November 26, 1997. This conference call served the purpose of clarifying the staff position on the large bore piping issue and the information that'would be-needed by the staff to assess the acceptability of FPC's operability determination of large-bore piping, as stated in their November 10.1997 letter. The staff also requested the licensee to provide a list of piping analysis packages in areas involving code compliance, operability determination, and observed design discrepancies identified by FPC's consultants. This list contains three general categories of piping analysis
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calculations. namely, piping and pipe support work done during the current outage. historical nozzle load calculations, and historical calculations for operability demonstration.
The staff selected samples of piping analysis packages from each category, in a request for additional information (RAI)
that was transmitted to the licensee on December 2. 1997.
In addition, the staff requested FPC to provide the technical basis for concluding the operability of piping systems in light of the findings identified by FPC's consultants (Wais Associates and J. D.-Stevenson Consulting Engineer) in various design aspects. A working level meeting was held on Lecember 2. 1997 at the NRC headquarters between the staff and the FPC personnel, to discuss
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the. eleven piping analysis packages that were provided by FPC in response to the staff's RAI.
During the staff review of these analysis packages, additional calculations were found to be needed by the staff in order to complete the review.
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Specifically, the staff requested the results of the licensee's ongoing evaluations of pipe supports for certain piping systems, evaluation packages
"for piping and pipe supports that demonstrated system operability. and additional information on uplift evaluations for hanger supports.
In all cases reviewed. the licensee was able to locate the calculation packages and provided them for the staff review.
3.1.1 Modification Calcul-1 tion Packaaes A total of five calculation packages under this category were reviewed, which are all controlled under the licensee's Modification Approval Record (MAR).
(1) MAR 97-09-05-02 - SW Piping Reanalysis Due to High LOCA Temperature This MAR is limited to a piping analysis for the Nuclear Service Closed Cycle Cooling (SW) system piping from the outlet of the reactor building (RB) fan coolers (AHHE-31A, 31B, and 31C) to the inlets of the SW heat exchangers (SWHE-1A,1B,1C, and 10) and the resultant modification of the pipe supports for this piaing. This analysis was required due to the postulated increase of post-LOCA S4 outlet temperature from 180 F to 260"F. The analysis evaluated the subject SW system for deadweight, pressure. thermal expansion induced loading due to the 260 F LOCA condition, and seismic inertia loading. The original calculations associated with the 180 F thermal loading was also provided by the licensee for comparison purpose.
The affected portions of the SW piping system inside the RB are Seismic Class 1.
The portion that is outside of RB and inside of the auxiliary building (AB) is Class 1 through the containment
)enetration isolation valves, with branch lines to the industrial coolers tlat are Seismic Class III. The system piping and supports were reanalyzed to document the structural integrity of the piping, supports, and RB fan cooler nozzle, with consideration of the effects of the increased post-LOCA RB fan cooler SW outlet temperatures.
The basic guideline for the design of piping is United States of America Standards (USAS) B31.1-1967. and, as stated in the CR-3 Pipe Support Design Guide (SP-88-019), the American Institute of Steel Construction (AISC) Code governs the design of all structural members and base plates. As a result of its review, the staff concurred with the FPC's evaluation that the stresses in the affected SW aiping, both inside and outside containment, are below the code allowables.
With the exception of a few pipe supports for which modifications were recuired, pipe supports were also found to meet the design allowables. These mocified supports include SWH-302/303, which are inside the containment, and CIH-047, CIH-049 SWH-002, SWH-522. and SWR-025, which are located outside the containment. The purpose of the modifications is to ensure that the pipe sup) orts meet the design requirements that takes into account the effects of t1e increased post-LOCA thermal load.
The staff concurred with the licensee's evaluations that the modified supports have also met the increased load requirements.
Based on the above review, the staff determined that the licensee's evaluation is acceptable.
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MAR 97-09-07-01-Spent Fuel Cooling From RB Penetration #347 to In-line Anchor SFH-691~(Outside Containment)
The purpose of this MAR is to bring into code comp #347 (outside containmen liance the Spent Fuel Pool Cooling (SFC) piping from containment Penetration through containment isolation valve SFV-19 and terminating at in-line anchor SFH-691. This piping is a continuation of the SFC piping inside containment i
from the fuel transfer canal to the containment penetration. which provides refueling canal fill, drain, and recirculation capabilities.
It is designed
.in accordance with USAS B31.1. 1967.
As shown in FSAR Figure 9-5. this portion of the SFC piping is Seismic Class I from the
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containment penetration to the outboard containment isolation valve SFV-19.
Beyond SFV-19. the piping is seismic class III (non-seismic).
In this MAR, the piping is analyzed as' Seismic Class I up to the in-line anchor SFH-691 in order to demonstrate that the non-seismic piping does not adversely influence the qualification of the seismic piping.
The piping analysis results indicate that uplifting would occur in five rod hanger supports.
Iterations of analysis were then made, each with the uplifted rods removed from the analysis, until there was no more uplifting involved. With this approach, the
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l analysis indicated that pipe stresses remained within the code allowables.
i The final hardware modifications made to the SFC piping supports included
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removal of four rod hangers. SFH-575. -577. -579, and -650, and modification
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of support SFH 576 from a rod hanger to a two way rigid restraint.
FPC also performed a code compliance calculation for the piping system in the modified configurations.
It was indicated that with the above changes, and as described in the MAR, the piping stresses met the requirements of the USAS B31.1 1967 and the affected su
" Manual of Steel Construction." pports met the stress allowables of AISC Code, c
Based on the review of the above calculation, the staff determined that the FPC's evaluation is acceptable.
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(3)
MAR 97-06-20-01-MUV Valve Addition to Letdown Line
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This MAR is required due to the installation of a new containment isolation valve (MUV-567) located downstream of the letdown coolers and adjacent to reactor building Penetration #333. This new valve will replace the emergency
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safeguards actuation system containment isolation requirement of MUV-40/41/505. The piping system is designed to USAS B31.1. 1967. This MAR will
. move the inservice inspection class break from the existing containment
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isolation valves. MUV-40/41/505, to down. stream of the new containment isolation valve. MUV-567. This new valve MUV-567, will be added to the IST 3rogram. This modification will not affect the design requirements of 3enetration #333 or the letdown coolers. The containment isolation requirements of Penetration #333 will be maintained.
FPC performed a calculation to provide the basis of qualification for th
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piping system with the changes as specified in the MAR. The calculation e_-____-
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Based on the above review, the staff determined that the FPC's evaluation is acceptable.
(4)
MAR 96-11-02-01 - HPI to RB Sump To provide additional safety-related recirculation capability to the High Pressure Injection (HPI) Jumps during piggyback operation, a new section of piping was installed whic1 cross-connects the existing recirculation line to the reactor sump.
The line is designed to support the operation of two HPI i
aumps.
The line starts in the Makeup Pump Valve Room in the auxiliary
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)uilding, with the tie-in downstream of flow orifices MU-82-F0 MU-83-F0 and I
.MU-84-F0.
The line is routed through the Makeup Piping Penetration Room and
.into the Southeast Piping Penetration Area. The line enters the RB by passing through an existing spare containment Penetration #353.
Once in the RB.
the piping is directed into the RB sump.
The outboard containment boundary will I
extend from the penetration to the first two of four solenoid valves.
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inboard penetration boundary will extend from the penetration to a check
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valve.
The penetration will be modified to accommodate the new 3-inch process pipe.
The calculation packages provided by the licensee include evaluations for: (1)
piping (M97-0025 Rev. 0) and supports (S97-0081 Rev. 0) from HPI pum) to containment penetration (outside containment): (2) piping (M97-0037 Rev. 0)
and pipe supports (S97-0082 Rev. 0) f,om containment penetration (inside containment) to RB sump; and (3) containment penetration qualification (S97-0087 Rev. 0).
The calculations were performed to demonstrate compliance with the design requirements of USAS B31.1.1967. The computer code used is CAEPIPE.
For the portion of piping outside the containment, the seismic effects were j
evaluated by response spectra analysis techniques using the composite floor i
response spectra for the RB shell El 123 ft. and the auxiliary building below elevation (El.) 119 ft.
Thisenvelobesthehighestpipingelevation.
The three earthquake directions were evaluated by considering the absolute I
summation of the worse horizontal (X.Z) with the vertical directions, i.e.. X-Y and Z-Y.
The analysis includes the closely spaced modes and the missing l
mass option.
The maximum sustained stress for piping is 8.459 psi, and the maximum i
sustained plus occasional stress is 13.307 psi.
These represent stress ratios of 0.50 and 0.66. respectively, of their allowable stresses.
The maximum thermal expansion stress, based on an operating temperature of 150 F. is 2.328
psi, which represents a stress ratio of 0.08 of the allowable stress.
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The supports outside containment which were evaluated include existing supports. MUH-623. -624. -625. -883. -884, and MUH-885, as well as small suppo ts. MUH-1021 through MUH-1034.
Supports MUH-1021 through MUH-1034. on the other hand, are new supports being installed on the new HPI recirculation piping. The allowable stress for structural steel members and connections are
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as given in the AISC Code. 8th Edition. 1980.
Based on the evaluations, the supports involved met the requirements for Seismic Class 1 pipe supports, and are acceptable for the design loads.
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For the portion of piping inside the containment, the thermal expansion effects considered an enveloping thermal load case, which accounts for the environmental temperature following a LOCA event. The seismic effects were evaluated by response spectra analysis techniques using the composite floor response spectra for the RB shell El. 123 ft.
and the RB interior El.
118.5 ft. This envelopes the highest piping elevation. The three earthquake directions were evaluated by considering the absolute summation of the worse horizontal (X.Z) with the vertical (Y) directions, i.e., X-Y and Z-Y.
The analysis includes the closely spaced modes and the missing mass option.
The maximum sustained stress for piping is 5.669 psi, and the maximum sustained plus occasional stress is 12.261 psi.
These represent stress ratios of 0.39 and 0.68. respectively of their allowable stresses.
The maximum thermal expansion stress, based on a post LOCA temperature of 294 F, is 10.401 psi, which represents a stress ratio of 0.38 of the allowable stress.
Valve accelerations for MUV-543. -544. -545. -546. -539, and MUV-540 were found to be less than the 3.0 g (horizontal) and 2.0 g (vertical) allowable, and were considered acceptable.
The HPI recirculation )ipe supports inside containment which were evaluated in this analysis include iUH-1039 through MUH-1042. MUH-1044 and MUH-1045. in their as-found field conditions.
The support loads considered for design envelope the analysis loads obtained from the B31.1, 1967 piping analysis and include worst case X-Y or Y-X response.
A friction load of 31 lbs. was a) plied to supports PUH-1041 through MUH-1043 due to axial pipe movements, w11ch was in excess of 1/8 inch.
The allowable stress for structural steel members and connections are as given in the AISC Code. 8th Edition.
It was found that the supports met all requirements for Seismic Class I pipe supports, and are acceptable.
For the analysis of the existing containment Penetration #353, the loads induced by the new 3-inch diameter process pipe included a design pressure of 3050 psig and a design temperature of 200 F.
The penetration is a spare Type-II penetration with a 10-inch diameter sleeve.
Typically. Type-II penetrations with 3-inch diameter process pipes are constructed with 12-inch aiameter sleeve therefore i
a qualification of the new configuration was necessary. The penetration I
sleeve was designed for full plastic moment and rupture thrust of the process
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aipe. consistent with the original design.
Based on the calculations provided I
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ay FPC, the existing 10-inch diameter sleeve and 2-inch thick attachment plate are found acceptable for the loads imposed by the new configuration of Penetration # 353 with a 3-inch diameter high energy process pipe.
Based on its review of the calculation as discussed above, the staff
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determined that FPC's evaluation is acceptable.
I (5)
MAR 96-10-04-02 - Thermal Relief Valves and Piping The purpose of this calculation is to evaluate the seismic adequacy of the l
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L various thermal relief valve configurations being installed by MAR-96-10-04-02. Thermal relief valves are being added to systems or portions of systems inside reactor containment that have single isolation valves. The.SW system and Decay Heat Closed Cycle Cooling (DC) system are included in this calculation since they are considered safety-related. Seismic Category I.
The piping within the scope ~of this calculation is Essential Service (ES) class.
The calculation is performed to ~ demonstrate compliance with the design requirements of USAS B31.1.1967. The calculation packages provided for the staff review are M97-0050 Rev. ' 0 and Rev.1.
The seismic effects were evaluated by res)onse spectra analysis techniques using the floor res)onse spectra-for the RB interior concrete El.160 ft.
This envelopes the lighest piping elevation and the a)plicable s)ectra for the large bore piping to which the bypass piping is attacled. The t1ree earthquake directions were evaluated by considering the absolute summation of the worse horizontal (X.Z) with the vertical (Y) directions, t.u.. X-Y and Z-Y.
The analysis includes the closely spaced modes and the missing mass option.
There are 33 thermal relief valves being modified / removed as part of this MAR.
The various piping / valve configurations were reviewed and grouped based on general similarity of configurations.
Each group was analyzed using CAEPIPE Version 3.75.
The loadings considered in the analysis included internal pressure, deadweight, thermal expansion, seismic effects and the differential thermal / seismic movements' associated with the movement of the main run piping.
All thermal relief valves are located on branch piping that will expand freely without introducing expansion effects into the existing run pipe.
The design pressure and temperature for the associated piping are 200 psig and 180 F.
-respectively.
Group 1 configuration consists of three general configurations, with thermal relief valves in parallel with a vent valve off of a common connection to the main run piping. The branch piping is decoupled from the run piping based on a moment of inertia ratio of 25:1. The resulted maximum sustained plus occasional stress is 13.925 psi, which represents a stress ratio of 0.77 of the allowable stress.
Group 2 configuration consists of twenty-two general configurations, with thermal relief valves mounted in a simple "L" configuration off from the main run piping. The branch piping is also decoupled from the run piping.
The resulted maximum sustained plus occasional stress is 6.533 psi, which represents a stress ratio of 0.36 of the allowable stress.
Group 3 configuration consists of four general configurations, with thermal relief valves mounted in a simple "L" configuration off from the main run
. piping. The branch piping cannot be decoupled from the run piping due to an inadequate moment of inertia ratio.
Each of these configurations, therefore, have been analyzed individually. The resulted maximum sustained plus occasional stress. 8.691 psi, occurs at configuration SWV-371, which
- represents a stress ratio of 0.48 of the allowable stress.
' Group 4 configuration consists of three general configurations, with thermal relief valves mounted in a simple "L" configuration off from the main run
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piping. The branch piping was not decoupled from the run piping due to an
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l inadequate moment of inertia ratio consideration.
However since these lines i
are rather similar only one analysis.was required..The resulted maximum
sustained plus occasional stress is 4.035 psi which represents a stress of l
0.22 of the allowable stress.
Valve accelerations for all thermal relief valves were less than the 1.5 g (horizontal) and 1.0 g (vertical) allowable, and are acceptable.
It is noted that Groups 1 and 2 configurations contain no Jipe supports and the pipe supports on the main run piping are not affected )y the decoupled branch piping.
For Groups 3 and 4 configurations. su) port loads are compared to the corresponding allowable load ratings.
Since t1e branch piping could not be decoupled from the main run for Group 3 and Group 4 configurations, the existing supports on the main run line were evaluated to ensure that the addition of thermal relief valves would not cause the support capacities to be exceeded.
Based on the above review, the staff found FPC's evaluation acceptable.
3.1.2 Operability Calculations A total of five operability calculation packages were reviewed by the staff in this regard.
These_ calculations were performed by FPC during the period from 1982 to 1993.
When requested. FPC also provided follow up calculations of some piping and related supports where code compliance have been demonstrated.
(1)
Calculation 5079-287-PAC-1 - Stress Analysis of DH Piping The purpose of this calculation was to perform a piping stress analysis of the Decay Heat piping to determine if the piping system was operable in its as-found configuration.
The FPC's operability calculation indicated that, except for Node A18 (an 8-inch by 8-inch by 3-inch Tee), all of the Decay Heat piping system included in the calculation met the USAS B31.1.1967 allowable stresses in its as-found configuration.
For Node A18. the calculation indicated that
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the piaing stress exceeded the code allowable, but was below the yield stress l~
(the Cl-3 piping operability requirement). Therefore. FPC concluded that the piping system is operable in its as-found configuration.
Subsequent to the operability evaluation. FPC initiated a modification effort, as documented in MAR 85-01-11-01, for the Decay Heat piping system.
The original Decay Heat piping system configuration downstream of support MK-DHH-663 to isolation valves DHV-9 and 10 had been qualified to Seismic III
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(non seismic) classification.
The purpose of this MAR was to upgrade that
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portion of piping system to the criteria of Seismic I classification to ensure that the Decay Heat removal crosstie system is not jeopardized by this portion of non-seismic piping during a postulated seismic event. The modification consisted of adding two new supports, removing one existing support. and modifying two existing supports. The FPC's calculation indicated that with i
these modifications, the piping stresses met the code allowables and the pipe support member stresses were within the AISC Code allowables or the l
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component allowables provided by the vendor.
L Based on its review as discussed above, the. staff determined that FPC's
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evaluation of the operability for Decay Heat piping system, as well as its evaluation for code compliance, were acceptable.
(2) Calculation 5079-287-PAC-2 - Stress Analysis of SW Piping This package details the stress analysis of SW system piping around piping anchors SWR-504 and SWR-522 for an operability assessment.
The anchors had'
been modeled as six-way restraints in the original analysis.
Questions were raised as to the appropriateness of such modeling technique, due to the uncertainty involving the rigidity of the anchors.
For operability consideration, a revised analysis was performed to demonstrate that the as-found piping system would have met the operability requirements.
The analysis was performed for a piping section that included anchors SWR 504 and SWR-522 and a sufficient amount of piping on both sides of the anchors to obtain accurate )ipe loadings on the anchors.
Separate analyses were performed with tie anchors being modeled either as three-way restraints or six-way restraints. This was to demonstrate that the affected system piping and supports would be able to meet the operability requirements. with either modeling assumption.
The four analyses performed for the operability evaluations are as follow; a.
Analysis SWR-504 (Run ID AAACIXW, 1/24/85)
Anchor SWR-504 was modeled as full anchor, with anchor SWR-520 model free in rotation about the x-axis.
b.
Analysis SWR-504 (Run 10 AAACJPW, 1/19/85)
Anchor SWR-504 restrain only three transnational disanchor SWR-520 modeled f axis.
c.
Analysis SWR-522 (Run ID AAACEBA. 1/18/85)
Anchor SWR-522 was modeled as full anchor, with support SWR-492 modeled with a spring constant of 100.000 lb/in.
d.
Analysis SWR-522 (Run ID AAACAGL, 1/21/85)
Anchor SWR-522 provides only resistance to the three transnational displacements, with support SWR-492 modeled with a spring constant of 100.000 lb/in.
The loading conditions considered for the analysis of this SW system included deadweight, thermal and the safe shutdown earthquake (SSE) load. The effects of three-directional earthquake were evaluated by considering the absolute summation of the worse horizontal (X.Z) with the vertical (Y) directions, i.e.. X-Y and Z-Y.
The operating temperatures considered for the analysis
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were 120 F for the 18-inch SW pumps discharge line. and 160 F for the 18-inch SW heat exchanger suction line.
The evaluation results indicated that for the piping stress consideration, the maximum ratio of actual stress to the code allowable stress did not exceed 0.56 for any stress combination of any computer run performed.
To demonstrate operability for supports. FPC provided the following calculations for the staff review:
Calculation 5079-256-SWR-504-C01 Calculation 5079-256-SWR-504-C02 Calculation 5079-256-SWR-522-C01 Calculation 5079-256-SWR-522-C02 The staff also reviewed support drawings, for SWR-504 and -522. before and after their modifications. The results of the calculations indicated that the pipe supports satisfied the operability requirements with the anchors resisting only three directions of restraint.
This demonstrated that the piping system satisfied the operability requirements during the time period from plant startup to the time of modification.
In addition, the calculations also indicated that the pipe supports satisfied the operability requirements with the anchors in their modified configurations, resisting all six directions of restraint. This demonstrated that the piping system would satisfy the operability requirements for continued operation after the support modi fication.
In addition, the staff review of a recent FPC calculation, documented in Calculation S97-0492 Rev. O. for the supports SWR-504 and SWR-522. for increased temperature loading from 180 F to 260 F. also verifies code compliance of the modified support configuration.
(3) Calculation M92-0040 (DC-5520-005.35PE) - RCV-13 and RCV-14 Operator Replacement The purpose of this calculation is to evaluate the effects on the 2-1/2-inch diameter Pressurizer Saray Line due to the replacement of the valve operators for Valves RCV-13 and RCV-14 (MAR 90-08-13-01).
Connected to the line is a 2-inch diameter Auxiliary Spray Line (Decay Heat Injection) which includes isolation valve RCV-53. All piping is Seismic Class 1.
The Pressurizer Spray piping is pd). art of the NSSS and had been
)reviously analyzed by Babcock & Wilcox (B&
Their analysis included t1e Auxiliary Spray Line through RCV-53 up to the vicinity of support DHH-42.
In this analysi.s. the change in system responses (stresses, loads, etc.) due to the operator replacements was evaluated.
The only effects subject to change were the primary responses due to deadweight and seismic loads.
It was the intent of this analysis to fully utilize the existing B&W calculation.
This was accomplished by calculating the changes in the piaing system deadweight and seismic responses, and then incorporating t1ose changes into the existing B&W calculatio _ _ _
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A CAEPIPE model of the piaing system both statically and seismically, was established to analyze t1e. system as it existed prior.to the replacement of
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the valve operators, and then to analyze it with the new operator weights, centers-of-gravity and revised spring settings. The relative change (percentage difference) in stresses was then calculated for each noda. This relative change was subsequently used to modify the B&W primary stresses.
The resulted changes in-stresses and loads were added to the existing stresses and loads from the B&W analysis. These new responses were finally evaluated'for code compliance.
The CAEPIPE analysis was performed using the American Society of Mechanical Engineers (ASME) Code Section 111-1986 Edition aption.
- The 1986 ASME Code uses the resultant of all three moments in conjunction with the stress index ap3 roach to calculate the primary stresses associated with deadweight and eart1 quake loading.
One exception to the above ap3 roach is that the accelerations (for valve
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qualification) from the CAEPIDE model are accepted as the new valve accelerations.
The horizontal res)onse spectra used for this analysis is curve CR-15. Reactor Building Interior lorizontal operating basis earthquake (OBE) at El.180.5ft.
with'O.5% damping. The vertical response spectra used for this analysis is 2/3 times the Ground Response Spectra.
The evaluation indicated that as a result of the increase in overall valve weights for RCV-13, RCV-14, and RCV-53, the Class l' piping stresses remained
- acceptable. The Pressurizer Spray Nozzle remained acceptable.
The Auxiliary Spray Nozzle (actually a welding tee) remained qualified per the Class 1
- piping qualification. The Cold Leg nozzle remained acceptable in view of the minimal changes in loads at this point in the system. Valve accelerations also remained acceptable.
The support load increases were found to be minimal and were, therefore, also found to be acceptable.
Based on its review as discussed above the staff found FPC's calculations I
I acceptable.
(4)
Calculation DC-5520-091.1 PE - CR-103 Rod Evaluation The purpose of this calculation was to evaluate the as-built configuration of the Chilled Water piping system regarding the concern of rod support upli fting. Rod hangers are designed to carry the weight of the pipe and its contents and are designed for downward load.
There can, however, be instances where the combined thermal and seismic in the upward direction is greater than the weight load thereby causing uplift.
For long, slender rods,
the support becomes ineffective in this situation.
In this FPC calculation, various support configurations. comprising of different combinations of active rod supports, were evaluated.
Two rod supports CHH-26 and CHH-32, were found to have more significant uplifting loads. A piping analysis with these two supports considered inactive was
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performed.
The calculation indicated that the resulting piJing stresses were
- within the USAS B31.1, 1967 Code allowables. All of the otler supports were
.. evaluated and found.to be qualified for the new loads generated.
Based on its review as discussed above, the staff found FPC's evaluation acceptable.
(5)
Calculation S-93-0084 - 18-inch and 14-inch Main Feedwater Lines The pu pose of this calculation was to evaluate the effects on the 18-inch and 14-inch diameter Main Feedwater (MFW) Lines from Penetration #423 to steam generator #3A due to the inadvertent installation of the travel stop in spring support EWH-114A. This portion of MFW piping is Seismic-Class I.
The effect of the travel stop was not found to influence the result of the original
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seismic evaluation.
The seismic evaluation would. therefore, remain unchanged.
The result of'FPC's calculation indicated that with the travel stop installed, the pipe stresses remained within USAS B31.1, 1967 Code allowables and all piping supports remained within design allowable loads. The travel stop has since been removed and the piping system is returned to its original design condition.
Based on its review of the calculation, the staff found FPC's evaluation
- acceptable.
3.1.3 Nozzle Load Calculations Among a list of historical nozzle load calculation Jackages. M89-1006 related to qualification of EFW nozzles, was selected for t1e staff review.
The pur)ose of this nozzle load calculation was to demonstrate the accepta)111ty of the interface loads on the CR-3 Emergency Feedwater (EFW)
- piping / steam generator interface flange.
The analysis was performed by B&W in accordance with the ASME Code Class Il criteria. The results.of the calculation indicated that the interface loads met the code criteria of ASME Section III Subsection NC, 1977 Edition with Summer 1978 Addenda.
However, this calculation did not include an evaluation of seismic loads on the interface flange. A later calculation, B&W Owners Group calculation 32-1240713-00,
" Structural Qualification of EFW Nozzles / Studs," has included both OBE and SSE loads and a fatigue evaluation for the CR-3 EFW nozzle qualification. This later calculation was performed by B&W in accordance with the criteria of ASME Code Section III, Subsection NB,1977 Edition with Summer 1978 Addenda.
Based on its review of the above information, the staff found FPC's evaluation acceptable.
4.0 OPERABILITY ASSESSMENT Based on the sam) ling review of the calculations discussed above, the staff considers that F3C has taken reasonable corrective actions in resolving the
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13 discrepancies identified in their large bore piping systems.
Specifically.
FPC has performed reanalyses for system piping which required modifications, as a result of changes in thermal loading, valve weight, as well as su) port and piping route configuration etc.
The results were found to meet tie licensing basis requirements as stated in the FSAR and the code of record.
FPC also performed operability evaluations for piping systems in their as-found configurations.
These evaluations were performed to demonstrate that while the state of the art of piping analysis technology has changed over time, the piping systems in their as-found conditions still met the operability requirements.
In addition, the licensee has followed up with the upgrading of the systems and components to further demonstrate that the piping systems in their modified configurations would be in compliance with the code requirements.
The staff has reviewed FPC's letter of December 18, 1997, which responded to the staff's RAI of December 2. 1997, concerning the operability assessment of the CR-3 large bore piping.
FPC has provided detailed discussion to address the concerns identified in the Wais re) ort, both from the point of view of individual and collective effects.
Su)stantiated by the past operability evaluations performed using conservative operability criteria. FPC concluded that the operability evaluations for discrepancies discovered in the past, have not revealed any systems that could not perform their intended design and/or safety function.
It should also be noted that most of the discrepancies identified in FPC's piping program reflect, in large extent, the prevailing general industry practice on piping analysis and design at the time of CR-3 construction. The staff, therefore, concluded that the CR-3 large bore piping, in its existing conditions, does not constitute a operability concern.
5.0 CONCLUSION Based on the above evaluation, the staff concludes that FPC has provided reasonable basis to support its conclusion regarding large bore piping operability.
The staff also concludes that based on FPC's satisfactory demonstration of piping system operability in the samples examined by the staff. further review of additional sample piping calculations is not warranted.
The program proposed by FPC in Attachment D of its letter dated November 18.
1997, to demonstrate compliance with all applicable licensing requirements for large bore piping and pipe sup) ort, was not reviewed as part of this review.
The proposed program represents a ) road frame work that lacks many necessary details that have not yet been developed by FPC.
The staff informed the licensee of its desire to review the licensee's program when it is fully developed.
Principal Contributors:
A.J. Lee. Y.C. Li Date:
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