IR 05000334/1980020
| ML19343C197 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 11/25/1980 |
| From: | Beckman D, Blumberg N, Hegner J, Mccabe E, Nicholas H, Troskoski W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19343C187 | List: |
| References | |
| 50-334-80-20, IEB-79-27, IEB-80-06, NUDOCS 8102180903 | |
| Download: ML19343C197 (44) | |
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NEC (2) , U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT Region I Report No.
50-334/80-20 Docket No.
50-334 License No.
DPR-66 Priority -- Category C . Licensee: Duquesne Light Company 435 Sixth Avenue Pittsburgh, Pennsylvania 15219 Facility Name: Beaver Valley Power Station, Unit 1 Inspection at: Shippingport, Pennsylvania Inspection conducted: July 1-August 15, 1980 Inspectors: (".C. d M h it[2 r[J o D. A. Beckman, Sr. Resident inspector date signed V C.h Q-L h ; kt Itl2T(Fe ent Inspector d te signed H. h hqholas,, Reqc_ tor Inspector ":tions which ma, be determined as necessary (</br>to achieve cold shutdown with such fM1eres.</br></br>The inspector revie-ad the licensee's March 4,1980 response to the IEB, and inspected documentation provided in support of that submittal, including:</br>Onsite Safety Committee (OSC) Meeting Minutes Nos. BV-0SC-18-80,</br>--</br>-25-80, and -32-80; Memorandum, L. Schad to R. Burski, dated February 22, 1980, Subject:</br>--</br>IEB 79-27; and,</br>--</br>Memorandum, P. Valenti/H. Kahl to R. Burski, dated February 23, 1980, Subject:</br>IEB 79-27.</br></br>The licensee's submittal to NRC and the above documentation stated that the OSC, Operations Department, and Power Station Engineering Group had reviewed all or portions of the IEB and summarized the results of indivi-dual reviews and procedure revisions.</br></br>Each document concluded that the reviews and actions pursuant to the IEB were acceptable and complete.</br></br>'</br>.</br>s,</br>.,</br>_.,.</br>.-</br>,</br>.</br>--</br></br>*</br>.</br></br>The inspector noted that the licensee had concluded that no design changes /</br>plant modifications were required to meet the IEB requirements but that revisions to the BVPS Operating Manual, Chapter 38, Abnormal Procedures F through M (Loss of, various 120 VAC Vital Busses) were required and issued.</br></br>The inspector confirmed the issuance of these revisions during a control room tour on July 23, 1980 but questioned the absence of similar procedure revisions to BVPS OM Chapter 39,125 VDC Control System, Abnormal Proce-dures, in that these systems ware also subject to review in accordance with</br>.</br>the IEB and appeared to require similar revision.</br></br>The existing abnormal</br>'</br>procedures of OM Chapter 39 address only restoration cf a faulted DC bus and do not address the actions necessary to place the plant in cold shut-down with an extended loss of a DC bus.</br></br>Procedures for the 120 VAC Vital Busses addressed both bus restoration and extended losses and, although not reviewed in detail by the inspector, appeared to provide acceptable, alternate methods of plant operation to mitigate a faulted AC bus.</br></br>The inspector noted that none of the documentation discussed above indi-cated any exceptions to completion of the IEB requirements and, on July 23, 1980, asked the DLC Senior Compliance Engineer and Operating Supervisor</br>;</br>about the DLC disposition of DC instrument and control power system reviews l</br>and about the documentation which identified the scope, depth, and findings j</br>of all reviews conducted.</br></br>During additional discussion with licensee per-sonnel during the period July 23 August 19, 1980, the inspector determined that no review of DC instrument ar control power systems had taken place</br>-</br>and that documentation which would substantiate the conclusions of the licensee's completed reviews was uitvailable as noted above.</br></br>During an exit meeting on [[Exit meeting date" contains a listed "[" character as part of the property label and has therefore been classified as invalid., the inspector informed the station Chief Engineer, Superintendent of Licensing and Compliance, and others present that the review of DC instrument and control power systems is required by tha IEB, that development and issuance of any required pro-cedures must be accomplished prior to plant restart and that any modifica- , ' tions deemed necessary should be identified to NRC prior to restart.
The licensec stated that the matter would be considered by DLC management.
On August 29, 1980, the Station Superintendent and Superintendent of Licens-ing and Compliance discussed this matter with the inspector and stated that the above actions would be completed by September 30, 1980 but that plant modifications, if any, would likely not be implemented during the present outage.
The inspector acknowledged the licensee's comments and stated that , ! the need for any identified modifications would be evaluated by NRC and requested that he be informed of any such modifications by September 30, 1980.
At the various meetings above, the. inspector also expressed concern to the ' l licensee regarding the information provided in the March 4,1980 DLC letter which stated that "...the review of Class IE and non-Class IE busses sup-plying power to all instrumentation and control systems which would affect the ability of the station to achieve cold shutdown has bean completed and
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l reviewed by the onsite Safety Committee.
The review included the alarms and indicators provided in the control room, identification of the instru-ment and control systems bus loads, and the effects of loss of power to the s ta ti on.... " In light of the findings discussed above, this statement appears to be incorrect.
Additionally, the only plant records available to substantiate this statement are the documents listed herein which state only that reviews were conducted, that certain procedures were revised / developed, and provide the conclusions reached by the licensee.
The inspector was unable to determine the specific bases for the licensees reviews, or to establish by review of records that all systems or subsys-tems had been completely reviewed (i.e., which circuits had been reviewed with no action required vs. those requiring procedure changes and the bases for such determinations, or the basis for the conclusion that no design changes / modifications are necessary), nor obtain licensee records which substantiate the conclusions presented in the fiarch 4,1980 DLC letter.
This constitutes an item of noncompliance with 10 CFR 50, Appen-dix B, Criterion XVII; BVPS FSAR, Appendix A.8, 0QA Program, Paragraph A.2.2.17; and QA Procedure OP-15, Quality Assurance Records, Revision 1, Section 15.2.1.a) (1), which requires permanent retention of records that would be of significant value in demonstrating the capability of safe ope-ration of the facility (80-20-09).
IEB 80-06: Engineered Safety Feature (ESF) Reset Controls.
This inspection was conducted during the week of July 14-17, 1980 and August 12, 1980.
The inspector reviewed tne licensee's response dated July 4,1980 and a support-ing letter from the facility's architect engineer (AE) dated flay 5,1980 (Ltr. No. DLS 16124).
The inspector also interviewed members of the Opera-tions and Licensing and Compliance Departments concerning their participa-tion in the reviews and evaluations and the planning for proposed system / equipment testing in accordance with the IEB.
IEB 80-06, Item 1, required the review of schematic drawings for all systems serving safety-related functions to determine whether or not the reset of an ESF actuation signal would result in a change of equipment condition / position which is contrary to design criteria specified by the BVPS FSAR.
The basis for this IEB was previously discussed in IE Inspection Report No.
50-334/79-24 and Unresolved Item 79-24-06.
Portions of this review involving valve and damper control circuits affected by ESF actuation and reset signals were conducted by the AE and documented in the aforementioned letter.
This portion of the review was also conducted in response to a request from NRR: DOR in an !!RC letter dated April 4, 1980.
The results of the AE review were evaluated by the inspector and found to be acceptable subject to the comments below.
During inspector review of the licensee's response relating to equipment other than valves and dampers, the inspector was unable to locate or obtain formal documentation of licensee review of pumps, fans, or other similar equipment subject to the IEB.
The extent of licensee review of these items was established by per-sonnel interviews and review of informally maintained schematics which had ~ . .. , _ _ . . . - -- .
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. been " yellow-lined" to partially identify circuits which had been reviewed.
On the basis of these reviews and discussions, the inspector determined the following: a.
Safety injection (SI): Review of SI valves was documented in Appen-dix A of the AE letter.
A licensee representative stated that he also did a schematic review of safety injection systems.
That review was not documented.
The licensee reply noted that, if the SI accumulator discharge iso-lation valves were in the closed position and the control switches were maintained closed, the valves would open on a SIS signal but close again on reset.
The licensee further stated that these valves . are procedurally opened and control power is then physically removed from the valves via " banana plug jacks".
This would prevent any closure until power is restored.
The inspector observed that the procedure of BVPS OM, Section 1.50.4.C, Plant Heatup from Hot Shutdown to Hot Standby, requires opening of the accumulator isolation valves and the performance of OST 1.11.9, " Accumulator Isolation Valve Breaker Alignment Verification", which verifies the valves open and the power removed by removal of the plug in the lock out jack.
The inspector considered the licensee response and procedures adequate concerning the SI accumulator i slation valves.
b.
Reactor Trip: Not applicable to IEB 80-06.
c.
Feedwater line isolation by closing all main control valves, feedwater pump trip, and closure of main feedwater pump discharge valves: Review of valves was documented in Appendix A of the AE letter.
A licensee representative stated that he did a review of pumps and l valves.
That review was not documented.
The licensee response noted l that the feedwater control and bypass valves will return to their ' control function on ESF reset, but that this would have no effect on flow to the steam generators as feed pumps remain tripped and upstream isolation valves remain closed.
The reply also noted that procedures require resetting of the valve controllers to the "0" (open) position prior to resetting the feedwater isolation signal.
The inspector reviewed BVPS OM, Section 1.50.4.I, " Turbine Plant Startup With Reactor Plant in the Startup (Mode 2) and BVPS OM, Section 1.24.4.N, Feedwater System Operation after HI-HI SG Level Trip".
Both required placing Main Feed Regulating Valve controllers outputs to zero.
The inspector found the licensee's response that no corrective action is required for the reset opening of feed regulating and by-pass valves to be . acceptable.
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d.
Auxiliary feedwater system actuation: Since no valves are involved in system actuation, this was not included in the AE review.
A licensee representative stated that he reviewed the pump ESF reset logic.
That review was not documented.
e.
River water (pump start and system isolation): Review of valves was documented in Appendix A of the if.
etter.
No review was apparently ~ accomplished for the River Water Pump ESF reset logic.
f.
Containment Depressurization System: Review of valves was documented 'in Appendix A of the AE letter.
A licensee representative stated that he reviewed the ESF reset logics for the containment Recirculation and Quench Spray Pumps.
That review was not documented.
g.
Containment Isolation: Review of valves was documented in Appendix A of the AE letter.
In addition, a licensee review was performed onsite.
This review was documented on marked up simplified ESF logic schematics maintained by the Licensing and Compliance group.
The licensee response to IEB 80-06 noted that four modifications were required concerning ventilation system dampers.
The licensee stated these modifications would be accomplished and tested prior to startup.
h.
Control Room Ventilation System Isolation and Pressurization: Review of valves was documented in Appendix A of the AE letter.
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Emergency Diesel Generator Startup: There appears to have been no documented review of the effect of ESF reset on emergency diesel gene-rator startup or reset.
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Main Steam Isolation: Review of valves was documented in Appendix A of the AE letter.
The inspector discussed with members of the Operations, Licensing and Com-pliance, and Results and Test Departments, the testing of ESF actuation and reset features required by Item 2 of the IEB.
Licensee personnel , stated that performance of Operations Surveillance Tests 1.36.3 and 1.36.4, Diesel Generator Nos.1 and 2 Automatic Tests, would test the circuits associated with the Safety Injection, Auxiliary Feedwater, and River Water systems, and Emergency Diesel Generators.
The licensee further stated that these tests were identified as requiring revisions to ensure that ESF equip-ment was rechecked after ESF reset.
River Water System valves MOV-RW-113A, -B, -C, and -D are not directly checked by OST's 1.36.3 and 1.36.4; however, their operation is indirectly checked by monitoring of diesel generator cooling conditions and engine temperatures.
The inspector informed the licensee that the OST's should be revised for direct verification of valve operation to prevent potential overheating or damage of the units for purposes of the IEB.
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During the current outage the licensee is also modifying the safety injec-tion system to provide automatic switchover from injection phase to recir-culation phase operation.
The licensee stated that test procedures are being developed to ensure that valves would not reposition on an ESF reset signal following automatic switchover.
The inspector was unable to identify an existing test for main feedwater control valves, feedwater pump operation, or feedwater pump discharge valves. A licensee representative stated that such a test was in preparation.
Containment Isolation Phases A and B are normally tested by OST's 1.1.4 and 1.1.5.
A licensee representative stated that these tests were being revised to check containnent isolation valve condition following ESF reset.
The inspector reviewed these procedures od determined that the tests conformed to the TS and included valves listed in Appendix A of the AE letter.
OST 1.1.4 for isolation train "A" contained numerous typographi-cal errors in valve nomenclature.
These errors were identified to the licensee.
Containment Depressurization System Quench Spray Pumps are tested by OST 1.13.11.
A licensee representative stated that this test is being revised for system modifications and verification of ESF reset functions.
OST 1.13.7 for the Containment Recirculation Spray Pumps will be similarly revised.
Control Room ventilation system isolation and pressurization is tested by OST 1.44.A1.
This test does re. heck equipment status after ESF reset and tests those devices listed in Appendix A of the AE letter.
The test does not, however, directly test the following: EP-VS-101A & B - Outside air intake, outside air exhaust and recir- -- culation damper isolation; and,
EP-VS-101-14A & B - Outside Air Intake Damper Isolation.
-- The procedure only verifies that the control room ventilation has isolated and is operating in recirculation.
The licensee representative stated that OST 1.44.Al would be reviewed in regard to the inspector's comments.
No testing is planned for the Main Steam Trip Valves.
The licensee stated that no test is contemplated as it is not possible for the valves to reopen without operator action due to the high differential pressure across the valves after closure.
Even after reset, if an open signal were received by the valves, they could not open.
The inspector acknowledged the comment and had no further questions on these valves . .
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The inspector noted that a number of discussions with licensee personnel were required to establish the status of licensee test planning and that there appeared to be no coordinating individual or document to provide the accountability necessary to ensure that all. ices were satisfactorily tested. Although the inspector was able to es, + the status of the licensee's intentions, he expressed concern that ; apparent lack of organization could easily result in oversights in the testing of both existing systems and new plant modifications.
On July 17, 1980 the inspector conducted a meeting with the Nuclear Engi-neering and Refueling Supervisor, the Senior Licensing Engineer, the Results Coordinator, a Nuclear Shift Supervisor, the Station Operating Supervisor, and the Chief Engineer (Acting Station Superintendent).
At this meeting the inspector informed the licensee on the findings dis-cussed above.
The licensee stated that the incomplete response to the bulletin was due to a misunderstanding and to similarity to the NRR:00R letter of April 4,1980 (previously discussed).
- The licensee stated that a supplementary response to IEB 80-06 would be submitted by July 31, 1980 that response to paragraph 1 of the bulletin will specify all ESF actuation systm. reviewed and the results of that review. The inspector informed ;r a licensee that the AE letter should be included or referenced in P "esponse but it would not be necessary to repeat the review of valves and dampers.
Any new deficiencies identified as result of the additional licensee review are also to be identified in the supplementary response as required by para-graph 3 of IEB 80-06.
Previous deficiencies requiring modification were identified in the initial bulletin response dated June 4,1980.
The licens-l ee stated that all testing required by IEB 80-06 would be completed prior l to plant restart.
, On July 31, 1980 the licensee subri',ted to NRC Region I a supplementary letter which stipulated the systems reviewed and that the review was con-ducted for all pumps, valves, fans, and dampers in the subject systems.
On August 12, 1980, the inspector reviewed records (developed by the DLC . Senior Licensing Engineer) which documented and substantiated the scope i of the additional reviews he had performed on the equipment identified i above as lacking prior review or review documentation. With respect to the lack of documentation and records to substantiate the conclusions provided by the DLC response of June 4, 1980, failure to maintain records which are of significant value in demonstrating the capability of safe facility ope-ration and which document the results of such reviews is contrary to 10 CFR 50, Appendix B, Criterion XVII; the BVPS FSAR, Appendix A.2, 0QA Program; and QA Procedure OP-15, QA Records, Revision 1, Section 15.2.1.a)(1) and constitutes an item of noncompliance (80-20-14).
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At an exit meeting on August 9.1980, the inspector expressed concern over the apparent trend (of poor documentation) which may be developing as illus-trated by the findings above and those discussed for IEB 79-27.
The inspec-tor stated that the absence of sufficient documentation to substantiate submittals to NRC would also appear to affect the ability of OLC management to perform high quality internal review and evaluation of the various departnents' inputs to such submittals.
The inspector asked that manage-ment attention be directed to both the quality of records and quality of internal reviews and evaluations for matters identified by NRC correspon-dence or personnel. Similar concerns were previously identified by NRC:RI and addressed by DLC management as discussed in IE Enforcement Conference Report No. 50-334/79-21.
On August 15, 1980, this matter was discussed by the inspector with the DLC Director of Nuclear Operations who acknow-ledged the inspector's comments.
During additional discussion at that exit meeting, the licensee stated that a method of accountability for the testing of each device subject to IEB 80-06, Item 2 would be established and documented to ensu e that all testing was satisfactorily completed.
The inspector stated that completion , of the modifications and testing discussed in the foregoing would be reviewed during future inspections and that the acceptability of the remaining licens-ee actions purusant to IEB 80-06 would remain unresolved pending completion of review by NRC:RI (80-20-10).
IEB 79-21: Temperature Effects on Level Measurements.
In a supple. mental _ response to NRC: Region I dated July 24, 1980 the licensee stated tnat the following actions were being taken in response to the subject bulletin: 1.
To minimize reference leg heatup due to increased containment tem-perature caused by a high energy line break (HELB) insulation was applied to the reference leg water columns in accordance with instruc- , tions provided by the Westinghouse Electric Corporation.
t 2.
The steam generator low-low trip setpoint has been set at 12 percent of narrow range level span, as recommended by Westinghouse for the insulated condition of the legs.
3.
The review and revision of emergency procedures has been completed to reflect the new reference guidelines developed by Westinghouse and the Utility Owners' Group, and the operators have been instructed on the potential for and magnitude of erroneous level signals caused by adverse environments.
' On August 12 and 14, 1980 the inspector reviewed information supplied by l the licensee and conducted independent visual inspection of work activi-ties associated with Item 1 above.
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The inspector reviewed the following guidance provided by the vendor: Westinghouse letter dated July 30, 1979, entitled Insulating Steam -- Generator Reference Loops (HS-RPS-I-1057).
Westinghouse letter dated June 27, 1980, entitled Transmittal of a -- Summary of Options Concerned with Steam Generator Reference Leg Heatup (DLW-80-77).
The inspector reviewed the following information in order to determine whether the licensee had adhered to the criteria specified in the vendor guidance: Diesel Change Package 277 - Insulate Steam Generator Reference Legs; -- -- Engineering Change Notice 277-8-0EG; and, BVPP 141-1, Installation Procedure for the Steam Generator Level -- Transmitter Reference Leg Modifications.
In addition the inspector entered containment on August 14, 1980 and con-firmed, through visual inspection of reference legs on the A and B Steam Generators, that insulation was being applied in accordance with the guidance and procedures referenced above.
The inspector had no further questions pertaining to Item 1.
Items 2 and 3 will be reviewed during a subsequent inspection (79-8U-21).
IEB 79-17: Pipe Cracks in itagnant Borated Water Systems at PWR Plants.
IEB 79-17 was issued after visual inspections had disclosed through wall cracks at welds on the spent fuel cooling system and the decay heat remo-val system at Three Mile Island Unit 1.
The inspector noted that the licensee had recently experienced weld crack-ing problems on two 3/4" lines on the Residual Heat Removal System (refe-rence: LERS 80-31/01T, 80-36/03L, and Inspection Report 50-334/80-12 ~ paragraph 6). On August 6,1980, prior to receipt of the licensee's final response to the IEB 79-17, the inspector asked whether the licensee had l considered the possibility of intergranular stress corrosion cracking ! (IGSCC) as described in the bulletin during evaluation of the referenced RHR weld cracks.
The Nuclear Engineering and Refueling Supervisor and Station Engineer acknowledged that.they were aware of the IGSCC failure mechanism but that, because of the configuration of the subject lines, j their engineering analysis addressed vibration or weld fatigue as the ' primary failure mechanisms.
That analysis concluded that vibration was the cause of the cracks in the above cases.
The licensee is currently considering corrective actions to mitigate this problem (reference Inspec-tion Report 50-334/80-12, paragraph 6)_.
Aiditional review of licensee actions with respect to the subject bulletin will occur after receipt of the licensee's final report on IEB 79-17 (79-BU-17).
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IE Circular Followuo The inspector reviewed licensee actions taken in response to the following IE Circular (s) in order to determine that the Circular was received by licensee management, that a review for applicability to the facility was performed, and that, if applicable, appropriate corrective actions have been taken or planned.
The following Circular was reviewed: IEC 80-02: Nuclear Power Plant Staff Work Hours.
IEC 80-02 was issued on February 1, 1980 and provided guidance to be used in reducing the poten-tial for work induced fatigue in personnel performing safety-related func-tions.
The inspector reviewed the results of the DLC evaluation of the IEC as reflected by the following documents: OSC Meeting Minutes No. BV-0SC-28-80; - Memorandum BVPS: JAW:819, J. A. Werling to G. W. Moore, Same Subject, -- dated March 24, 1980; and, . DLC Letter, C. N. Dunn to D. G. Eisenhut, Five Additional TMI-2 -- Related Requirements, dated June 9, 1980.
Review of these references indicated that the subject matter of the IEC had been reviewed, conflicts with existing practices or policies identi-fied, and recommendations made to corporate management for future actions necessery to achieve or approach the working hour guidelines for station personnel.
The DLC letter of June 9,1980 further provided a commitment to the Director, Division of Operating Reactors, NRC:NRR, which adopted tne guidance of IEC 80-02 as it applied to shift manning.
That letter noted that further commitment for non-shift personnel would require addi-tional NRC:NRR clarification of the personnel requirements.
Discussions with plant personnel revealed that implementation of the IEC guidelines for shift personnel was in a planning status but that its achiev-ability was questionable on the basis of available manpower, particularly with respect to those positions requiring NRC Operator or Senior Operator licenses.
These discussions further indicated that implementation of the guidelines for non-shift personnel was not being considered for the fore-seeable future due to potential conflict with labor contracts and station work loads.
During the inspection period, the inspectors received several inquiries from bargaining unit members regarding the status of the NRC position on work hours and the applicability of the IEC 80-02 guidelines to personal working situations.
These discussions indicated that the individuals were required to periodically work forced overtime hours which may be in excess of the IEC guidelines.
Although each individual msking such inquiries could identify personal fatigue and family impact from extended working hours, no one identified specific instances of work induced fatigue which affected the safety of the facility through errors in maintenance, modifi-cations, testing, operations, etc.
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On July 10-11, 1980, the inspector reviewed the work-hours records main-tained by the station, selecting a random 25% sample of personnel in the Operations, Maintenance, Radcon, and Chemistry Departments qualified to perform safety related work, reviewed their work hours for the period of May 1 - July 1,1980 to identify possible departures from the IEC guidance, including: Periods of work of more than 12 hours straight; -- -- Periods of work without at least a 12 hour break between periods; Periods of work of greater than 72 hours in any 7 day period; and, -- Periods of 14 consecutive days of work without 2 consecutive days -- off.
Records were reviewed for 11 individuals who are qualified to perform safety-related work as First Class Mechanics, Electricians, Meter and Con-trol Repairmen (I&C technicians), Welders, Operators, etc.
Of these individuals, nine of eleven had worked one or more periods of 14 consecu-tive days without two consecutive days off; three individuals had worked more than 72 hours in one or more 7 day periods; and six individuals may have had a less than a 12 hour break between periods of work on two or more occasions each.
The 12 hour break period concern could not be substan-tiated because of the method of record keeping used by the licensee.
No instances of work periods in excess of 12 straight hours were identified.
Between July 11 and 14,1980, the inspector interviewed 10 individuals other than those whose records were reviewed.
These included unlicensed operators assigned to plant testing, maintenance personnel, chemists, first level supervisors, and Radcon Technicians.
These interviews established that the personnel contacted were working nominal 60 hour weeks with intermit-tent overtime in excess of the nominal; that none of the individuals were i aware of any problems with plant equipment or operations resulting from personnel fatigue or morale; and, that the individuals could not recall being required to work more than twelve continuous hours, having less than twelve hours break, or working more than 14 consecutive days with less than two consecutive days off.
Tne inspector also held discussions with station management concerning this matter and reviewed aspects of the overtime rules and company policy for assignment of overtime, forcing of overtime, and methods of overtime control.
On July 11 and 14, discussions of the above findings were held with the station Superintendent, who provided additional perspective regarding overtime assignments and goals during the outage.
The Superintendent stated that, to the extent possible, all personnel were being maintained on a schedule of six,10 hour days, Monday through Saturday, but that addi-tional overtime would be scheduled on an as-needed basis to address outage work and schedule needs.
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This matter was further discussed by NRC and DLC senior management on July 18, 1980 as documented in IE Enforcement Meeting Report No. 50-334/ 80-21(0ps).
By letter dated July 31, 1980, DLC informed NRC:NRR that the commitment provided by the DLC letter of June 9,1980 was being withdrawn due to an unacceptably broad scope of applicability of the IEC and the potential for conflict with existing labor contracts.
Until such time that the applicability of NRC requirements for plant staff work hours is resolved, the inspectors will rcutinely evaluate the poten-tial effect of personnel work hours on observed deficiencies in safety-related activities.
8.
Radioactive Material in Unrestricted Area On July 1, 1980, the inspectors were informed hy Radcon Department super-visors that five pieces of piping, apparently removed from the safety injection system during system modifications.. had been fourd on the Turbine Deck on June 30, 1980.
These pieces of piping, each 1-2 feet long, were found to have low levels of fixed contamir.ation on their bores which exceeded the BVPS administrative limits ?or release of the material for unrestricted use.
Two pieces of the piping had loose surface contamina-tion which was slightly in excess of the administrative limits.
The piping was found to have a maximum internal, fixed contamination level which resulted in a dose rate of 0.16 mR/hr. as measured by an RM-14 meter.
A maximum smearable contamination of 500 pCi/100 cm2 was found on two pieces of the piping.
The station limit for smearable contamination permissible
in unrestricted areas is 450 pCi/100 cm, The piping had been removed from controlled areas for retention as possible metallurgical test samples.
The craft foreman responsible for the material had requested a resurvey of the material as an additional precaution result-ing in identification of the contamination on June 30.
The material had been stored, prior to resurvey, at the west end of the Turbine Deck.
The licensee was unable to establish the circumstances under which the material had been initially surveyed and released for unrestricted use.
The licensee immediately initiated surveys of potentially affected unre- , ! stricted areas frequented by the craft personnel who had been in possession of the piping. On June 30 and July 1,1980 areas of the plant yard, tur-bine building, tool cribs, and piping fabrication shops were surveyed with no additional radioactivity detectable.
These survey results were reviewed by the inspectors with the Radeon Foreman on July 7,1980, at which tire l the Radcon Foreman stated that the following corrective action was in ' progress: . All surveys of the Turbine Deck area performed between January 1980 -- and June 30, 1980 had been re-reviewed and found to be adequate.
No j contamination had been identified during those surveys.
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All material to be removed from plant controlled areas will now be -- restricted to removal via either the monitoring room (at the Primary Auxiliary Building access point) or via the machine shop (for larger i tens ). No other points of egress will be used.
Interim measures requiring documentation of all items leaving the con- -- trolled area were immediately implemented by requiring individual sur-vey sheets to be completed for each item.
Examples of implementation were reviewed by the inspector.
The licensee was pursuing refinement of the methods to be used for identification of generic items such as common tools.
Radcon Manual Procedures were being revised to provide more specific -- data on the survey, release, and tracking of material removed from the controlled areas to permit traceability of the activities.
A new material tagging system was being devised to support these procedure changes.
The inspectors reviewed a Radcon Department memorandum to the craft - -- safety engineers requesting the matter above be included as discussion topic in future safety meetings.
The inspectors confirmed that all Radcon Technicians had already been briefed by their supervision regarding the interim measures discussed above.
During subsequent plant tours, the inspectors confirmed that the interim measures were being adequately implemented via observation of personnel who were processing material being removed from the controlled area at the monitoring room.
Additional inspection of material control was con-ducted with acceptable findings as discussed in IE Inspection Report No.
50-334/80-22.
The inspector also confirmed that the Radeon Manual, Chapter 3, procedures , l for control of potentially contaminated material leaving the controlled area or site were being appropriately revised and would be issued pending the < receipt of new format tags from the licensee's vendor.
The inspectors had no further questions on this matter at the close of this inspection and informed the licensee that the area would continue. to be observed during both routine inspections and an upcoming Health Physics Appraisal Team inspection.
9.
Emergency Preparedness Plan Drills a.
Background In a letter dated March 5,1980, to the Office of the Nuclear Reactor Regulation, DLC submitted a revised draft Emergency Preparedness Plan for NRC review and requested relief for the schedule for perforsance f a
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. of the annual EPP drill, postponing the drill until July 1980. On July 24, 1980, the resident inspectors were informed that the drill would be conducted on July 31, 1980, and were provided the information below: The drill was to be based on a simulated rupture of the CVCS -- Volume Control Tank resulting from inadvertent pressurization and would be escalated to a site emergency from a local emergency.
The drill would not' involve the large numbers of construction -- contractor workers onsite; drill activities would be conducted so as to minimize impact to outage related work.
Only limited mobilization of radiological monitoring teams would -- take place.
A separate personnel accountability drill would be held to mini- -- mize the effect of the large number.of outage-related personnel presently onsite.
The state and local agencies involved in emergency response were -- notified of the drill on July 24, 1980 for optional participation.
These drill plans were discussed with the Station Superintendent on July 24, 1980 with respect to the goals of the drill and its effective-ness in testing and exercising key aspects of the licensee's newly issued Emergency Implementing Procedures, Issue 0, dated July 18, . 1980.
The inspector noted that the drill did not appear to exercise portions of the EPP and procedures for response to najor planning basis events or significant radioactive releases.
The drill scenario appeared to include a more minor radioactive release simulation and a . more limited exercise of monitoring and-accident management functions than is appropriate for the initial evaluation of the new plan and pro-cedures or as recommended by NUREG-0654/ FEMA-REP-1, Criteria for Pre-paration and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants.
The superintendent acknowledged the inspector's comments and stated that the drill would be conducted on July 31, 1980 to satisfy the EPP annual drill require-ments and that a separate, more comprehensive drill would be conducted prior to station restart. The Superintendent stated that the July 31, 1980 drill would have the primary goal of testing the notification and communications procedures with limited testing of other plan features.
The inspector acknowledged the licensee's commitmer.t and stated that the acceptability of the licensee's emergency planning and preparedness for the upcoming plant restart would remain unresolved pending imple-mentation of the mere comprehensive drill (80-20-11).
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Drill Observation On July 31, 1980 from 6:00-8:30 a.m., the inspector observed portioqs of the Emergency Preparedness Plan drill conducted by the licensee in fulfillment of the annual drill requirement.
Drill activities in the Control Room, Emergency Control Center (Shift Supervisors Office), and interim Techr,1 cal Support Center were observed.
The following day the inspectar participated in the second of two post-drill cri-tiques conducted by the licensee.
Specific observations by the inspector included: Initial and followup notifications of offsite personnel and -- agencies; -- Implementation of Emergency Implementing Procedures; Command and control functions of designated Emergency Coordinators; -- -- Adherence by operators to Emergency Operating Procedures; Control Room access control measures; -- Licensee dose assessment capabilities; -- Communications (radio, telephone, licensee internal phone system / -- paging system, and NRC Emergency Notification System; and, Deployment of radiological survey teams.
-- The inspector observed that, when the initial notification to NRC via the Emergency Notification system (ENS) was completed, the responsible ! licensee individual did not maintain an open line of communications ! with the NRC Operations Center.
When questioned by the inspector, the individual stated that he was not aware of specific requirements , l for maintaining an open communications channel with NRC and stated that he would have expected the NRC representative on the line to pro-vide any such guidance.
The inspector also observed that the guidance provided to the watch- , l persons controlling access to the Control Room consisted of a single j hand-written sheet specifying the criteria under which access to the Control Room was permitted during periods when the EPP was being imple-mented.
The inspector determined that any individual who informed the watchpersons that he was involved with the emergency (drill) in progress would be allowed access to the control room.
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' The observations were brought to the attention of the licensee during the drill, during the post-drill critique, and in an informal list provided to the licensee Senior Engineer responsible for emer-gency cianning.
Regarding the first observation, the inspector informed the licensee that 10 CFR 50.72(b) requires the licensee to establish and maintain an open, continuous comunications channel with the NRC Operations Center within one hour of the occurrence of any event requiring initiation of the licensee emergency plan or any sec-tion of that plan and to close the channel only when notified by NRC.
Regarding the second observation, the inspector stated that control-l ling access to the Control Room and other facilities involved in responding to emergencies would minimize confusion and noise caused by unnecessary personnel in the areas.
The licensee acknowledged the inspector's concerns and agreed to address them as part of the lessons learned from the drill.
The inspector stated that licensee actions in this regard would be observed during the emergency drill to be con-ducted prior to startup (80-20-12).
10.
Seismic Event Monitoring - a.
On July 28,1980 at 6:30 p.m. the NRC Operations Center notifited the , licensee that a seismic event had taken place with its epicenter in ' Kentucky and that the effects of the earthquake may have been detect- . able at the Beaver Valley site.
Discussions by the inspector with ' personnel who were onsite at the time of the event indicated that the earthquake had been felt by several individuals.
Initial licensee i review of seismic instrumentatien found that the portion of the seis-mic monitoring system sensitive enough to have detected the tremor and easily accessible, (the SMA-3 Accelerograph Recording System) appeared to be out of service for maintenance at the time of the inci-dent.
The inspector informed the Station Superintendent on July 30, 1980 that the NRC Show Cause Order of August 8,1979 required the licensee to shutdown and perform an inspection of piping systems in the event of an earthquake greater than 0.1g.
In order to determine the magnitude of the event at' the site, the licensee obtained informa-tion from local sources, including the University of Pittsburgh, but was unable to determine the magnitude of the event at the site.
Subsequent licensee review concluded that the seismic monitoring sys-tem above was operable at the time of the event and that a ground motion of 0.01g would have activated both the instrument and annun-ciated in the Control Room.
Since neither activation nor annuncia-tion took place, the licensee concluded that no ground motion greater than 0.01g had occurred and that the limit imposed by the Show Cause - order had not been exceeded. An Out of Service sticker on the instru-ment during the event remained posted only because the administrative aspects of the maintenance procedure had not yet beer completely signed off after the maintenance activities were completed.
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. of Maintenance Surveillance Procedure ha. MSP 45.03, Seismic Monitor-ing SMA-3/SMP-1 Calibration, Revision 3, performed July 9, 1980, and discussions with the Instrument Engineer verified that the system was operable during the seismic event.
The inspector had no further questions on this item.
b.
On August 12, 1980 at 0859 operators acknowledged annunciator A11-59 " Seismic Accelerograph Operation" and examined the SMA-3 Accelerograph Recording System recording and control unit (XR-ER-105). The system is normally in a stendby mode and begins to record acceleration data upon receipt of a start signal from the sei.smic trigger.
Setpoint for the trigger is 0.019 The operators observed that the recording system was not operating but that the Event Indicator was white, indicating that the unit had received a start signal.
Following Operations Manual Procedure 1.45.4.L.
Accelerograph Recording System Runnir.g. Revision 5, the operators placed calibration s%als on the tapes, placed the recorded cassettes on the SMP-1 Magnet b. 7 ape Playback unit (XR-ER-105-1), made strip chart records, ". records.
The operators observed no indications of an and examine- ' ip charts.
In addition, when the tape plaf>ack unit event on th begins pla,".s cck a recorded signal, a timing mark is placed on the right hand.ide of the chart paper at 1/2 second intervals.
No timing marks were evident on the strip charts until that portion of the chart where the operators had input calibration signals.
The operators con-cluded that no seismic event had taken place.
Independent review of the following strip chart recordings was performed by the inspector on August 12, 1980: Auxiliary Building tape, dated 8/12/80 9:52 A.M.
-- Containment 693' Channel 1 dated 8/12/8910:04 A.M.
-- Containment 693' Channel 2 dated 8/12/8010:12 A.M.
-- ! Containment 693' Channel 3 dated 8/12/8010:12 A.M.
-- The inspector confirmed the observations made by the operators and had no further questions.
11.
Se'.saic Adequacy of Safety-Related Cable Trays During inspections at BVPS, Unit 2, Region I inspectors identified potential deficiencies in the acceptability of seismic analyses / qualification for safety-related cable trays which are of the type also used at BVPS, Unit 1.
Those inspections and discussions between those inspectors and the cable l l
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tray vendor indicate that the aluminum, open (ladder) type straight cable tray sections typically used outside containment for safety-related cabling may be subject to failure during design basis seismic events.
The trays in question utilize cold swaged joints between "D" shaped rungs and the tray side rails.
The mode of failure, according to the vendor, involves stresses at the rung-to-side rail juncture which are aggravated by the cable bearing flats on the rungs.
Preliminary review by the resident inspectors during the period prior to July 23, 1980, identified trays of the type identified above to be in extensive use in the BVPS Unit 1 switchgear and cable spreading rooms. On July 23, the inspectors requested the DLC Licensing and Compliance (L&C) Senior Licensing Engineer to provide design, procurement, and installation information pertinent to these trays for NRC review.
This information provided included the original purchase specification (No. BVS-382, Revi-sion 1, dated January 22,1971), correspondence between the licensee, the facility AE, and the cable tray vendor, and a " Letter of Compliance" issued by the vendor on March 19, 1975 certifying compliance of the trays with the requirements of the above specification.
The requirements of the above specification appear to be consis+.ent with the design criteia set forth in the BVPS-1 FSAR, Appendix B.1 on July 23, 1980.
The DLC Sen1or Licensing Engineer informed the inspector that, based on the above documentation, DLC considered the trays to be acceptable.
The information provided, however, appeared to be in conflict with the pre-liminary information received by Region I personnel from the cable tray vendor.
Although that information may only be applicable to BVPS, Unit 2, which has more stringent seismic design criteria, this matter will remain unresolved pending resolution of the apparently conflicting information (80-20-13).
12.
Review of Licensee Training Staff Qualification Status On March 28, 1980, the Director, NRR, issued a letter to all licensees request:ng that license applications for Senior Operator licenses be sub-mitted for all utility staff instructors (involved in training on systems, integrated response, transients, and simulator courses) who did not already l possess a Senior Operator license.
On July 7,1980, the inspector held discussions with the station Training Coordinator and reviewed training and i licensing records for all DLC employed training instructors subject to the above letter. The inspector established that five instructors are so employed and that four of the five had current NRC Senior Operator licenses.
The fifth individual held a current Operator license but had been scheduled for NRC examination for the Senior Operator license on the basis of an application made to NRR:0LB by DLC letter dated July 3,1980.
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. . The individual's NRC license examination was administered on July 22-23, 1980 by an NRR:CLB examiner.
The individual did not pass that examination.
Discussions with the station Training Coordinator on August 28,1980 esta-blished that the individual is not assigned to provide license-related instruction on integrated response, transients, and simulator courses.
The individual is conducting training on plant systems under the direction of other instructors who bear a Senior Operator license.
The individual is not authorized to certify satisfactory completion of students' training requirements or performance.
The inspector had no furthar questions on this matter.
13.
Preoperational and Startup Test Program Review - Outage Recovery a.
Discussion The inspectors conducted preliminary reviews of licensee programs for the control of preoperational testing and startup testing that is required to be performed as a result of station modifications and - refueling.
This inspection involved discussions with members of the DLC Construction Department and station management regarding the organization and progrars involved in the preoperational and startup test program to be conducted during recovery from the outage, including: Construction activities; -- -- Construction prooftestir.g; -- Preoperational and startup testing; -- Surveillance testing; Control of Design Change Packages (DCP); and, -- -- Integrated administration of the above activities.
The inspectors also reviewed the documents listed below which provide the basis for administration of the test program and which were used.
as acceptance criteria for review of specific application of the test program (s) to design changes and modifications: Construction Department Nuclear Power Plant -- Procedures Manual CDN - 1.1 Revision 1 Approved May 24, 1976 Design Change Status List -- June 25, 1980 . -- i
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. Prerequisites for Plant Startup -- June 12, 1980 Joint Planning / Scheduling Group -- July 8, 1980 Station Engineering Procedures -- January 16, 1980 Operating Surveillance Tdsts -- July 8, ;980 Resource Leveled Schedule, Major Modifications Outage -- July 10, 1980 Regulatory Guide 1.68, Initial Test Programs for Water Cooled -- Nuclear Power Plants Reviews The inspectors examined the following documents with respect to the requirements and guidance of the references: Modification Work Package 191-1 -- Design Change Package DCP-0191 Deletion of Reactor Trip Below 50% Power Test Package TP-1, 2, 3 Equipment Release ER-1, 2, 3 System Release 191-1 Acceptance Date July 9,1980 Modification Work Package 200-1 -- Design Change Package DCP-0200 Low Power Steam Generator Level Control Test Package TP 200 Equipnent Release 200-1 System Release 200-1 Acceptance Date July 2,1980 --' Modification Work Package 190-1 Design Change Package DCP-0190 Steam Line Break Protection Test Package TP-1, 2, 3, 4, 5 Equipment Release ER-1, 2, 3, 4, 5 System Release 190-1 Acceptance Date July 2,1980 - O w im
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Modification Work Package 205-1 -- Design Change Package DCP-0205 Solid State Protection System, Trains A and B, Internal Modification Only.
Test Package TP-205-1 System Release 205-1 Acceptance Date July 2,1980 Test Specification for DCP-268 -- S&W Task 12690.85 Fire Protection System Item 2B Underfloor Cable Area of CR-4 T.S. - 268 Approved June 25, 1980 Installation of Two Auto-On, Manually Operated Total Flooding Halon 1301 Systems b.
Findings The preoperational and startup test restart program will be further examined on subsequent inspections.
14.
Um esolved Items Unresolved items are matters about which more information is required to determine whether they are acceptable, items of noncompliance or deviations.
Unresolved items addressed during this inspection are discussed in para-graphs 2, 3, 6, 9, and 11 of this report.
15.
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 also provided to the licensee at the conclusion of the report period.
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