IR 05000412/1986039
| ML20211Q077 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 12/10/1986 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20211Q044 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-1.A.2.1, TASK-1.A.2.3, TASK-1.A.3.1, TASK-1.C.7, TASK-1.C.8, TASK-2.E.1.1, TASK-2.E.3.1, TASK-2.E.4.1, TASK-TM 50-412-86-39, IEB-86-003, IEB-86-3, NUDOCS 8612190191 | |
| Download: ML20211Q077 (9) | |
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i U. S. NUCLEAR REGULATORY COMMISSION
REGION I
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Report No.
50-412/86-39
Docket No.
50-412 License No.
CPPR-105
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Licensee:
Duquesne Light Company Nuclear Construction Division P. O. Box 328 Shippingport, PA 15077
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Facility Name: Beaver Valley Power Station, Unit 2 Dates:
November 3-30, 1986 Inspectors:
J. E. Beall, Senior Resident Inspector
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A. A. Asars, Resident Inspector R. J. Urban, Reactor Engineer i
W. M. Troskoski, Senior Resident Inspector, BVPS Unit 1 L. J. Prividy, Resident Inspector N. F Dudicy, Lead Reactor Engineer (Examiner)
I hM[d Approved by:fs,L. E. TrTW, Chief, Reactor Projects Section 3A/fho/84 Date p
Inspection Summary: Inspection No. 50-412/86-39 on November 3-30, 1986 Areas Inspected:
Routine inspections by the resident inspectors (150 hours0.00174 days <br />0.0417 hours <br />2.480159e-4 weeks <br />5.7075e-5 months <br />) of licensee actions on previous findings, site activities, fuel receipt, Hot Func-
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tional Testing, potential failures of multiple ECCS pumps, TMI Action Plan Require-monts, Auxiliary Feedwater System Testing, and Main Steam Safety Valve testing.
Results:
No violations or significant concerns were identified.
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DETAILS l
1.
Persons Contacted During the report period, interviews and discussions were conducted with mem-bers of the licensee's management and staff as necessary to support inspection activities.
2.
Project Status Summary Construction activities are currently estimated to be 97.7% complete, with 440 of 476 subsystems turned over for flushing and proof-testing.
For sof t-ware, about 93 out of 114 preoperational (PO) and initial startup tests (IST)
have been approved.
The remainder are in various phases of development.
Approximate dates for the major project milestones, as currently estimated by the licensee are as follows:
Loss of Power Test February 2, 1987
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Integrated Leak Rate Test February 23, 1987
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Fuel Load May 1, 1987
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Initial Startup May 16, 1987
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Commercial Operation August 30, 1987
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3.
Inspection Program Status Summary Preoperational Test Program Inspection completion status is approximately as follows:
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AREA
% INSPECTION COMPLETE Overall Program 35%
Procedure Reviews:
Mandatory 35%
Primal 50%
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Test Witness:
Mandatory 15%
Primal 5%
Results Review:
Mandatory 15%
Primal 5%
This inspection status is consistent with the applicant's test program pro-gress.
At the end of this inspection period, there were approximately 68 open NRC inspection items including 7 bulletins, 5 violations, and 15 construction deficiency reports. The remainder are unresolved items.
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4.
Licensee Actions on Previous Inspection Findings (Closed) Violation (85-07-04): Deficiencies in compliance with administrative procedures.
This violation concerned the lack of attention to detail by lic-ensee personnel in complying with administrative procedures.
Specifically, engineering documents were found with corrections and deletions that were not properly initialed and dated.
The licensee's corrective actions were de-scribed in a letter dated July 9, 1985.
DLC committed to issue a memo to all site personnel to reiterate the requirements for document corrections and deletions.
The licensee also stated that audits would be conducted to monitor personnel performance relating to this issue.
The inspector reviewed the results of several of these audits which concluded that this deficiency has been successfully corrected.
No deficiencies were identified and this item is closed.
(Closed) Violation (86-21-01): Controlled access aret barrier degraded.
This item involved the identification by an NRC inspector of an opening in the Fuel Building Fuel Transfer Canal that would have provided uncontrolled access to the Fuel Building.
Licensee personnel closed the transfer tube gate valve thus blocking the opening and caution tagged the valve shut.
The licensee reviewed Fuel Building structural drawings and determined that no other un-protected penetrations existed.
The inspector had no further questions; this item is closed.
5.
Site Activities Throughout the inspection period, the inspectors toured the licensee's facili-ties.
General work activities were observed including construction, surveil-lance, testing and maintenance.
The inspectors also monitored the licensee's housekeeping, security and preliminary radiation control activities.
During a tour of the containment building on October 30, 1996, the inspector noted that the pressurizer power operated relief valve solenoids were loose, with their cable ports open; no one was in the area at the time and no house-keeping zone was established.
Discussions with the Maintenance Supervisor indicated that cable installation work for environmental qualification had been initiated and would continue intermittently.
Subsequently, the licensee established a housekeeping zone and wrapped the unattended components per SUM standards.
On November 7, 1986, the inspector observed portions of the pressurizer safety valve work performed to disposition N&D 29059.
This item had been previously reviewed in detail 12.e of NRC Inspection Report 412/86-31.
New gaskets and bolt nuts were installed on all three valves under the review of a flushing group supervisor to ensure RCS cleanliness requirements.
Craft personnel were in the process of torquing the bolts to 680 ft. Ibs. per the ASME bolted joint data sheet.
No leakage was observed when the RCS was brought to operating temperature and pressure for hot functional testing.
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The inspector reviewed OST 2.6.8, Placing 0PPS In Service, to determine the technical adequacy of the procedure and the level of review received to ensure that the system would perform as intended.
The PORV stroke time was specified as 5.0 seconds.
Discussions with the procedures writer indicated that this was in error; the manufacturer's data specified 2.0 seconds to open and 5.0 seconds to close. Apparently, no review of the safety analysis assumptions used to bound the low temperature - over pressure accident was conducted for the OST preparation.
The Station Superintendent informed the inspector that such a review would be conducted.
No deficiencies were identified.
6.
Fuel Receipt The final fuel shipment of 12 assemblies was received during the inspection period.
The inspectors observed portions of the receipt activities and veri-fled adequate coverage by Health Physics technicians and Quality Control in-spectors and adherence to fuel receipt procedures for fuel unpacking, inspec-tion and placement into the storage racks.
This completes the fuel receipt for the initial core load, all of the assemblies are in storage in the spent fuel pool.
No deficiencies were identified.
7.
Hot Functional Testing The licensee commenced Hot Functional Testing (HFT) at 2342 on November 14, 1986.
The reactor coolant system (RCS) was heated up by running the reactor coolant pumps.
RCS temperature was increased gradually with frequent pauses for measurements of piping thermal " growth" and support loadings as well as physical walkdowns of piping to check for leakage, deformation, etc.
Normal operating temperature (547 F) was attained at about 1400 on November 23, 1986.
Feedwater flow to the steam generators was provided by the motor-driven auxiliary feedwater (AFW) pumps.
The non-safety related startup feedwater pump was originally planned to take over feeding the steam generators, but pump seal failures rendered the pump inoperable with no replacement seal package available until after the completion of HFT.
Another source of feed-water is the turbine-driven AFW pump; the licensee plans to place it in ser-vice after testing.
The turbine was tested successfully while not coupled to the motor, but a motor packing failure occurred when the motor and turbine were coupled and steam was admitted to the turbine.
The packing was replaced and the turbine-driven AFW pump was being tested at the end of the inspection period (see detail 10).
RCS chemistry was frequently checked during the heatup.
Initial sample re-sults showed a possible silica contamination problem with levels as high as 1460 ppb reported.
By the time the RCS reached normal operating temperature, the sample results were below 100 ppb silica.
Silica results remained below 100 ppb for the remainder of the inspection perio.
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Other testing activities monitored involved the charging pumps and their as-sociated flow controllers, main steam atmospheric and condenser dump valves, and pressurizer heaters and spray.
The cycling of the main steam safety valves was also witnessed (See detail 11). Major tests planned for December include the turbine-driven AFW pump endurance run, AFW system auto starts, main turbine roll, and main generator synchronization to the grid.
No deficiencies were identified.
8.
IE Bulletin 86-03, Potential Failures of Multiple ECCS Pumps IE Bulletin 86-03 was issued to inform all licensees of possible single fail-ures of minimum flow recirculation lines containing air-operated isolation valves which could result in a common-mode failure of the ECCS pumps in sys-tems with these valves.
The licensee responded to this bulletin in a letter dated November 13, 1986, and stated that BVPS Unit 2 is not affected by this failure mode.
The inspector conducted an independent review of the ECCS con-figuration and also that of the Auxiliary Feedwater and Service Water Systems and identified no examples of potential failure in the Beaver Valley, Unit 2 pump recirculation lines as described by the bulletin.
9.
TMI Action Plan Requirements (NUREG 0737)
Licensee commitments in response to TMI Action Plan requirements have been reviewed by the staff and are documented in the Safety Evaluation Report (SER)
and its supplements.
Several of the TMI items are still under review and items may require further attention if significant changes become necessary.
During this inspection period, the inspectors verified the licensee's compli-ance with the following items:
a.
Item I.A.2.1 Immediate Upgrading of Reactor Operator and Senior Reactor Operator Training Qualifications This requirement established minimum operator experience levels for SR0 candidates depending upon the candidates' individual educational and professional backgrounds.
The inspector reviewed the licensee's Training Administrative Manual (Rev. 2) and verified that it requires SR0 candi-dates to meet the current NRC eligibility requirements as specified in NUREG-1021, Section ES-109.
The NRC staff reviews each candidate's ap-plication and confirms that each candidate's experience level is in con-formance to current NRC requirements.
This item is closed, b.
Item I.A.2.3 Administration of Training Program This item established SR0 qualification requirements for facility in-structors who teach systems, integrated responses, transient and simula-tor courses.
The inspector reviewed the licensee's Training Administra-tive Manual (Rev. 2) and verified that it requires (in Section 2.4.7)
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that the training areas addressed by this item must be taught by Nuclear Operations and Maintenance Instructors who possess and maintain an SR0 license or Instructor Certification.
This item is closed.
c.
Item I.A.3.1 Revised Scope and Criteria for Licensing Examinations -
Simulator Exams Generic Letter No. 82-18, issued on October 12, 1982, stated that "...in response to SECY 82-232 the Commission removed the requirement for NRC conducted simulator examinations for those plants that do not have plant specific simulators." The BVPS simulator is not considered to be a plant specific simulator for BVPS 2 due to the major differences in the control boards.
Therefore, simulator examinations will not be included as part of the BVPS 2 licensing examination.
This item is closed.
d.
Item I.C.7 NSSS Vendor Review of Procedures Applicants for operating licenses are required to obtain NSSS vendor re-view of low power, power ascension, and emergency operating procedures.
The BVPS 2 SER concluded in Section 13.5.2 that this item was resolved based upon the following.
The applicant has committed to implement Emergency Operating Procedures (EOPs) based upon the NRC approved West-inghouse Emergency Response Guidelines (ERGS).
In addition, reviews of low power and power ascension testing procedures by Westinghouse is not necessary because a Westinghouse representative is a member of the on site Joint Test Group (JTG).
This group reviews and approves all pre-operational and initial startup testing procedures.
The licensee used the Westinghouse ERGS to develop their E0Ps.
Further review of the licensee's E0Ps will be carried out under TMI Action Plan Item I.C.I.
The inspector also reviewed Startup Manual (SUM) Chapter 3.3, " Joint Test Group," and spoke with the Westinghouse representative who is a member of the JTG.
The inspector determined that the licensee is meeting their commitment as stated in the SER.
Based upon the verification of the licensee's commitments, which are in accordance with the SER, this item is closed.
e.
Item I.C.8 Pilot Monitoring of Selected Emergency Procedures Applicants for operating licenses were required to utilize a pilot moni-toring program on an interim basis for evaluation of the E0Ps until the staff approved generic technical guidelines and developed the long term program for upgrading E0Ps.
The BVPS 2 SER, Section 13.5.2, states that this item is no longer ap-plicable because the NRC has approved the Westinghouse ERGS and the ap-plicant has committed to develop E0Ps based on these ERG.
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y The inspector determined that the licensee used the Westinghouse ERGS to develop their E0Ps.
Also, further review of the E0P content and effectiveness will be carried out under Item I.C.1.
Based on the above and the SER, this item is closed.
f.
Item II.E.1.1 Auxiliary Feedwater System Evaluation This item required evaluation of the Auxiliary Feedwater System (AFW)
by the licensee to determine the potential for the system to fail under various loss of-main-feedwater transient conditions.
The licensee is also required to perform a deterministic review of AFW and a re-evalu-ation of the system flow rate design bases and criteria.
The reliability analysis for AFW is contained in Appr v ix 10A to the BVPS 2 FSAR and is also in Section 10.4.9.
The analysis concluded that the reliability of the AFW is well within the AFW unavailability acceptance criteria as defined by the Standard Review Plan.
BVPS 2 SER, Section 10.4.9 states that the licensee's submittal for all three parts of this item are acceptable; this item is closed.
g.
Item II.E.3.1 Emergency Power Supply for Pressurizer Heaters The pressurizer heater banks and associated controls necessary to estab-lish and maintain natural circulation at hot standby conditions shall be energized from either offsite power or onsite emergency power.
BVPS-2 has four backup pressurizer heater groups, two of whi.h are powered by each Class IE division power supply; this configuration pro-vides the redundancy required by this item.
Furthermore, as described by the BVPS 2 FSAR 8.3.1.1.3, only one backup heater group is necessary to maintain natural circulation.
On a loss of offsite power, the backup pressurizer heaters are included in the non-Class IE loads which are stripped off of the emergency buses.
They must be manually reconnected.
These heaters are also shed from emergency power sources upon receipt of a safety injection signal.
The inspector reviewed the related procedures and system drawings, in-cluding those contained in OM Chapter 6, the Emergency Operating Proce-dures and the FSAR.
BVPS 2 SER Section 8.3.3.4 describes NRC's review of the licensee's proposal for compliance with this item and subsequent FSAR amendments.
Based on these reviews, this item is closed.
h.
Item II.E.4.1 Dedicated Hydrogen Penetrations Plants which utilize external hydrogen recombiners or purge systems for post accident combustible gas control of the containment atmosphere should provide containment penetrations for the recombiner or purge systems that are dedicated to that service only, that meet the redundancy and single-failure criteria, and that are sized to satisfy the flow requirements of the recombiner or purge syste r O
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The Hydrogen Recombiner System for BVPS 2 is discussed in FSAR 6.2.5 and OM Chapter 46.
Two redundant Hydrogen Control Systems have been provided; each includes a hydrogen analyzer, a flow control subsystem, and a skid mounted hydrogen recombiner unit.
The hydrogen analyzers are designed
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to automatically start on a safety injection signal and may be manually started.
They continuously monitor the containment atmosphere before and during'recombiner operation.
The skid mounted recombiner units are manually started from a local panel at least eight hours after the ac-cident and will operate automatically afterwards.
The recombiners are designed to maintain the hydrogen concentration in containment below four weight percent to preclude a possible hydrogen burn.
The recombiner units take suction from the containment atmosphere
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through two separate open taps in the containment dome.
These taps are also used as inlets for the containment vacuum pumps under normal operat-ing conditions.
Each containment vacuum pump suction has two solenoid operated isolation valves in series which will be de-energized closed on a containment phase A isolation.
The containment penetrations for the recombiner units discharges are dedicated and independent.
The inspectors reviewed the procedures associated with the Hydrogen Con-trol System.
These include operating procedures, emergency operating procedures and operating surveillance tests.
During the procedure review, the inspector noted that Hydrogen Analyzer Micropressor access codes are
not yet listed in OM 2.46.4.B. Post DBA Hydrogen Control System - Running.
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All other procedures were reviewed and no deficiencies were identified.
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Based on this review, the inspector determined that the Beaver Valley Unit 2 Hydrogen Control System adequately meets the requirements of NUREG 0737 II.E.4.1.
This item is closed.
10.
Auxiliary Feedwater System (AFW)
Turbine Driven Auxiliary Feedwater Pump (TAFP) Test Performance (P0 2.248.02)
Construction proof testing of the uncoupled terry turbine was successfully completed during the week of November 16, 1986.
Following the uncoupled tur-bine runs, the licensee coupled the pump and turbine for the TAFP performance verification with steam pressure at 600 psig (P0 2.248.02, Section B).
The inspector witnessed test preparations and initial terry turbine rolling for verification of Emergency Trip Lever operability.
However, as the licensee
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was opening the TAFP trip and throttle valve to slowly increase the turbine
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speed, the pump seized.
The licensee determined that the seizure wa due to pump packing interference.
Also, a slight misalignment in the turbint purp coupling was identified.
The Startup Group evaluated the necessity to delay the primary system heat up and secondary system pressure increases for per-formance of this test section and concluded that this portion of P0 2.248.02 can be performed during the descent from HF (
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g On November 29, 1986, after replacement of the pump packing and turbine pump realignment, the inspector observed the licensee conduct the pGrformance veri-fications which could be successfully completed with secondary pressure greater than 600 psi.
These include TAFP discharge check valve operability and turbine overspeed trip setting verification.
During this portion of testing, the terry turbine governor valve experienced control problems later attributed to mechanical linkage interference.
The linkage was realigned and the pump run continued.
At the conclusion of this inspection period, the licensee was in the process of completing the prerequisites for the TAFP cold quick start and 48-hour endurance run.
The results of these tests will be discussed in future inspection reports.
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No violations were identified.
11. Main Steam Safety Valve Testing Main Steam Safety Valve (MSSV) testing was performed on November 26, 1986, in accordance with P0 2.21A.02.
The inspector witnessed the cycling of 10 of the 15 valves.
Crosby, the MSSV vendor, performed the actual testing to verify proper valve operation and lift point setting at normal operating pressure and temperature.
The necessary lift pressures were achieved using an air set pressure device which produced the required valve opening force in addition to current main steam line pressure.
Vendor representatives ad-justed those valves whose setpoints were not already within the acceptance criteria and performed several tests on all 15 valves to ensure repeatability.
Following the completion of testing, the licensee noted that all of the valves had begun to weep steam slightly.
The vendor was called back to the site to u
evaluate the severity of the leaking and advised the licensee that the weeping'
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can be stopped by lapping the valve seats after HFT.
In addition, the licen-see is currently considering re-stroking all of the valves during the cool down from HFT.
No' violations were identified.
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12.
Exit Interview Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings.
A summary of inspection findings was further discussed with the licensee at the conclusion of the report period.
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