IR 05000334/1983007
| ML20023B556 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 04/18/1983 |
| From: | Lester Tripp, Troskoski W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20023B547 | List: |
| References | |
| 50-334-83-07, 50-334-83-7, NUDOCS 8305050180 | |
| Download: ML20023B556 (20) | |
Text
.
DCS Numbers 821213 800109 830225 830218 830309
.
810914 790823 8'0202 8303'O 830310 821231 810527 8'1001 830254 820914 810602 810327 630309 821221 810914 830121 791218 830225 810916 79D813 830228 830303 810923 830228 830307 811006 811215 830307 U. S. NUCLEA'l REGULATORY COMMISSION REGION 1 Report No.
50-334/83-07 Docket No.
50-334 Category C
License No.
DPR-66 Priority
--
Licensee:
Duquesne Light Company 435 Sixth Avenue P_ittsburgh, Pennsylvania Facility Name:
Beaver Valley Power Station, Unit 1 Inspection at: Shippingport, Pennsylvania Inspection Conducted:
March 1 - April 4, 1983 Inspector:
/I d,. I cc/[ M
//h/ /993 C
W. M. Troskoski, Resident Inspector
'date signed Approved by:
-[ d f/83 L. E. Tr'i p, Chief, Reactor Projects dat6 signed Section No. 2A, Reactor Projects Branch 2
Inspection Summary:
Inspection on March 1 - April 4, 1983 (Inspection No.
50-334/83-07).
Areas Inspected:
Routine inspections by the resident inspector (113 hours0.00131 days <br />0.0314 hours <br />1.868386e-4 weeks <br />4.29965e-5 months <br />) of:
licensee action on previous inspection findings, plant operations, housekeeping,
!
fire protection, radiological controls, physical security, maintenance activities, surveillance testing, engineered safety features verification, refueling preparation, mechanical snubber applications, in office and onsite licensee event report followup.
Results:
Two violations (Failure to provide supplemental LER information -
l detail 2, Failure to use an approved procedure - detail 7).
l l
!
l 8305050180 830420 PDR ADOCK 05000334 PDR O
.
_. -
.
-
_ _ - -
N
.
.
I DETAILS
'
1.
Persons Contacted F. Bissert, Manager, Nuclear Support Services J. Carey, Vice President, Nuclear Division
'
M. Coppula, Superintendent of Technical Services K. Grada, Superintendent of Licensing and Compliance
.
R. Hansen, Maintenance Supervisor i
l J. Indovina, I&C Supervisor
.
T. Jones, Manager, Nuclear Operatiens
'
J. Kosmal, Radiological Operations Coordinator W. Lacey, Station Superintendent
,
V. Linnenbom, Radiochemist J. Lukehart, Security Director L. Schad, Operations Supervisor
,
E. Schnell, Radcon Supervisor j
J. Sieber, Manager, Nuclear Safety and Licerising
R. Swiderski, Superintendent of Nuclear Construction I
N. Tonet, Manager, Nuclear Engineering T. Zyra, Plant Perfomance and Testing Supervisor
'
The inspector also contacted other licensee employees and contractors i
during this inspection.
I 2.
The NRC Outstanding Items (01) List was reviewed with cognizant licensee personnel.
Items selected by the inspector were subsequently
reviewed through discussions with licensee personnel, documentation
i review and field inspection to determine whether licensee actions
.
specified in the OIs had been satisfactorily completed. The overall i
status of previously identified inspection findings were reviewed, and planned and completed licensee actions were discussed for those
,
items reported below.
l (Closed) Unresolved Item (83-01-03):
Review corrective actions addressing i
environmental technical specification (ETS) reporting requirements.
I LER 82-54 detailed an over-chlorination of the circulating water system on September 23, 1982, that was not reported to the NRC until December
'
6, 1982. This was in violation of ETS 5.4 and 5.62 which require that
an ETS LCO violation be reported within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by telephone followed
,
within 15 days by a written report.
Since that event, responsibility
!
for the chlorination system has been turned over to the Operations
'
Department from the Chemistry Group. The inspector detemined that
'
though the proper Environmental Protection Agency notification was
-
made, the licensee failed to recognize the event as also reportable i
to the NRC under current ETSs. The inspector reviewed other environmental LCOs including chromium, liquid waste effluent specifications, liquid
!
waste sampling and monitoring, gaseous waste effluents, gaseous waste i
sampling and monitoring and specifications for solid waste handling i
and disposal to verify that the licensee's critique and incident report j
system would provide an adequate vehicle for identifying possible violations and reporting them to the appropriate authorities. With i
the chlorination system now under control of the Operations Group, the
~
inspector was satisfied that such a mechanism is in place. This item is closed.
.
!
i
.,_,,m,.__,-
, _, _ _
r..
_. _....,,.
.,,, _ _ _.. _ _, -, _ -.,,,,.. -..
, _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _, _ _ _ _ _ - _ -.
.-
..
-.
-3-
.
,
(Closed) Violation (81-16-01):
Contrary to Technical Specification 3.5.2, high head safety injection pump suction valve SI-26 was closed on June 6,1981, rendering both ECCS subsystem trains inoperable. The inspector reviewed and verified corrective actions undertaken by the licensee as outlined in their response to this violation dated January 12, 1982.
Inspection of the initial corrective action is documented in NRC Inspection Report 50-334/81-15.
Subsequent corrective actions (also described in DLC letter of December 31,1982) were inspected to verify that sufficient additional security measures were implemented to reduce the risk of recurrence of a similar incident. Those measures included:
l 1.
The addition of high strength locking devices on valves whose misposition would reduce the analyzed level of safety.
-
Key control was reviewed and verified by the inspector.
,
2.
Additional compartmentalization of certain vital plant areas.
3.
Development and implementation of a security incident response procedure that provides guidance for the initial response, investigation, evaluation and long-tem actions to be taken for similar security incidents.
l 4.
Increased reliability of the security computer by implementing additional hardware changes and upgrading software.
5.
Developent of temination procedures for the denial of access and positive controls over individuals whose employ-
,
ment is teminated under unfavorable circumstances.
6.
Limiting vital area access to individuals whose need for i
access has been detemined on a case basis and who have been authorized temporary access by use of a security work pemit. After successful software development for reviewing access authorization per 10CFR73.55, the method of controlling vital area access was appropriately expanded.
Additional NRC inspections of licensed requirements related to security program implementation are documented in Inspection Reports 50-334/82-14 and 82-28. This item is closed.
(Closed) Violation (81-16-03): Failure to maintain administrative controls of chains arid padlocks on valves WT-225, 226, 227 and SI-26 on June 5 - 6, 1980. The inspector reviewed the licensee's corrective actions for this violation as outlined in their letter dated January 12, 1982.
Each valve required to be administrative 1y secured by a lock and chain was re-evaluated to identify those whose mispositioning would reduce the margin of safety below analyzed levels as set forth in the facility licensing documents. Those valves, listed in plant log L10-2, were inspected in the field to verify that high strength security locking devices are affixed to each. The inspector also verified that key control to those locking devices was being actively maintained.
This item is closed.
.-.
.
_
__
_.
._ _ _
-4-i
.
.
>
(Closed) Violation (81-16-04):
Contrary to the administrative guides
.
provided in BVPS OM Chapter 48, Section 5.E.2 for activities affecting
,
quality, various manual valves in ESF systems were not pemanently tagged to indicate their normal position nor identified as part of an ESF system. To correct this problem, the licensee revised their method
'
for administrative 1y controlling ESF valve positions. BVPS OM Chapter
48, Section 5.E.2 was changed to require the use of a station equipment status board in the control room. The Operations Group is tasked with
,
maintaining this valve status board up-to-date at all times by high-
lighting designated valves that are out of nomal system alignment.
'
Additionally, a systems level status board was installed in the control i
room to readily identify appropriate ESF systems or trains whenever
'
a valve or piece of equipment belonging to it renders that system unable to carry out its intended function. The inspector has confirmed
'
!
licensee compliance to these requirements on routine tours. This item is closed.
'
.
(Closed) Unresolved Item (81-15-07):
Review acceptability of RCS pressure isolation valve leakage surveillance testing to meet technical
!
specifications 4.4.6.3 limiting condition for operation requirements.
!
The inspector reviewed the TS surveillance requirement, the last completed copy of Operational Surveillance Test 1.11.16, Leakage Testing RCS Pressure Isolation Valves, completed June 6, 1982, and the current revision (41) of the surveillance test. A previous inspector
!
concern noted that a common leakage test performed for the cold leg l
loop safety injection check valves (SI-10,11 and 12) was not capable
!
of identifying the specific valve and quantifying the individual leak i
rate. The last completed surveillance test was revised to separately test the individual check valves. Another concern noted that a previous
'
testofthecoldlegisolationvalvesinsidecontainment(SI-23,24and
PS) was conducted at test pressure ranges greater than that specified in the procedure. This appeared to be an individual procedure compliance
!
problem. The inspector noted that the last completed test was correctly i
documented, and that the licensee has presently strengthened their procedure adherence requirements. A final test conccrn noted that for i
the check valves installed in series, the procedure had made no provision for measuring simultaneous leakage of both valves. As each of the six valves are now required to be individually leak tested, the simultaneous leakage of both valves is required to be calculated as a step of the procedure. This item is closed.
(Closed) Violation (83-02-01): Transfer of a waste shipment of by-product
!
material with free-standing liquid. Licensee corrective actions as detailed in their letter dated February 18, 1983, were reviewed by the
inspector. Radcon procedures RP 3.11, Shipping Solid Radioactive Material
!
for Burial - Drums, and RP 3.17, Drumming of Solid Waste, Issue 2, were j
revised to require verification and traceable documentation of the contents I
of all drums, to ensure that all radwaste is in solid form with no free-
!
standing liquid.
i l
I
!
i
}
.
.
.. _ _ _ _... _,. _. _, _,. _ _,, _ _ _ _, _ _,,, _ _ _ _ _ _ _
_ _ _. _ _ _, _
, _ _
_
-5-
,
,
During tours of the PAB during the month of February, 1982, the inspector observed that radwaste containers in storage were being opened to verify that no free-standing liquid was present. The inspector also observed the licensee implementing those guidelines for compacting and labeling drums, and that the radwaste container content verification (RCM Form 3) was being completed as specified.
The licensee is in full compliance at this time.
(Closed) Unresolved Item (82-25-01): DLC to review notification procedures and make changes to prevent future confusion. During i
the partial loss of offsite power / reactor trip event of October 18, 1982, the NRC was not notified that an Unusual Event was declaired per the emergency plan. However, notification of the initiating plant trip and partial loss of offsite power was made via the Emergency Notification System. This confusion arose after the shift supervisor initiated the EPP notification and then assigned the administrative assistant to complete the notification.
Because the NRC had already been notified of the plant trip, the administrative assistant assumed that the unusual event notification had also been made. Since this (
occurrence, all administrative assistants have received additional
training in the notification procedures. They are now assigned the responsibility for perfoming all notifications to eliminate the possibility of missing a call when passing the list from one individual to another. The effectiveness of these corrective actions has been successfully demonstrated during two different emergency plan imple-mentation drills conducted during the month of February, 1983. This item is closed.
(0 pen) Unresolved Item (80-09-14):
DLC to assess quality of as-built information.
By NRC letter of July 8, 1980, transmitting the results f
of IR 50-334/80-09 to the licensee, DLC was requested to provide l
additional information assessing the quality and accuracy of station i
drawings and engineering information. This assessment of past practices was to be based upon a systematic review of potentially affected safety
'
related activities and was to provide the basis for the conclusion drawn. Additionally, plans and schedules for correcting any identified deficiencies and issue drawings and engineering documents which have resulted from construction phase changes was to be provided. The inspector reviewed the licensee's response that provided their basis for concluding that any unquantified deficiencies that may exist do not l
have an impact on the quality of operations and the ability to respond to emergency conditions.
In arriving at this conclusion, the licensee stated that a systematic review of all Category 1 design changes completed during the period from plant startup (after initial testing),
to the issuance of Station Engineering Procedure 2.3, Design Change Coordination, was made to assure that the necessary information is available to all station groups. The inspector could not detemine through document review that such a systematic assessment occurred.
i This was discussed with the senior compliance engineer and is open l
pending further NRC review.
l
.-
-.
-.
- _ _ _ -.
.
__
___
_
.-
- -- -
--
/
-6-
.
.
(Closed) Unresolved Item (81-15-08):
OST 1.11.16, Leakage Testing RCS Pressure Isolation Valves, does not have a leak rate adjustment for testing at less than design pressure. This test is perfomed in Mode 5 with RCS pressure between 250 and 350 psig. The licensee has reviewed and detemined that no adjustment for the leak rate measured under those conditions is necessary because the valves being tested tend to seat more tightly as RCS back pressure increases.
Since this does not adversely impact the RCS pressure isolation valve leakage surveillance requirement of Technical Specification 4.4.6.3, this item is closed.
(Closed) Inspector Follow Item (82-25-08): Verify the establishment and implementation of a river water heat exchanger tube cleaning program. As a result of LER 82-36, where an emergency diesel generator was declaired inoperable due to the fouling of cooling water heat exchanger tubes from river water silt, the licensee instituted a heat exchanger perfomance program. This program is outlined in internal DLC memorandum NDlTPP:
46, dated November 15, 1982, and formally tasks the testing and plant performance group with the evaluation and testing of some 65 heat exchangers in 18 different plant systems. The program outlines both the methodology and. test frequency. The inspector has no further concerns.
(Closed) Inspector Follow Item (83-04-01):
Review DLC maintenance program for confomance to the recommended Westinghouse program provided in Nuclear Service Division Data Letter 74-2. The inspector.
discussed this with the senior electrical maintenance engineer and reviewed preventative maintenance procedures for the reactor trip
,
I switch gear inspection (PMP Nos. 1-lRP-BK-RTA, RTB, RVA, RVB, lE) for conformance with recommendations contained in the Technical Bulletin.
As noted in DLC response to IEB 83-01 dated March 3, 1983, the reactor
'
trip breakers at BVPS Unit 1 are lubricated, inspected and maintained on a 18 month frequency with the lubricant recomended by Westinghouse.
l Based on past maintenance experience with those breakers, DLC believes that the 18 month frequency specified in the PMP's is appropriate for this application. Additionally, because of the'past successful bi-monthly testing history of the' solid state protection system, the
!
breaker testing frequency will be left at 18 months. This completes
,
i the required licensee actions for this item.
(Closed) Unresolved Item (82-01-10):
DLC disposition of 4160 VAC cable failures. This item was left open pending OSC review and approval of cable splicing. The inspector reviewed the Okonite Company (cable vendot) Engineering Report No. 358 dated March 26, 1982, and DLC
' Engineering Memorandum No. 44398 dated February 4, 1982. Technical recommendations were translated into Corrective Maintenance Procedure 1-36EE-lC2-lE, Repair of 4 KV Bus, 1C2 Cables, approved by the OSC on September 1,1982. The CMP included provisions for QC hold points and proof testing. Because the C and D transformers are being replaced under DCP-540, the licensee has not yet determined what final testing is necessary.
l
.
-7-
.
.
(Closed) Inspector Follow Item (83-04-02): Verify preparation and implementation of procedure to track open fire penetration barriers.
DLC Construction Department, Nuclear, issued a change to Procedure CDN-3.6, Revision 3, that established a control for temporary installations and penetrations thru fire barriers by listing the location and roll sleeve numbers utilized for temporary access on area work permits. Additionally, the contractor is now required to perform a daily verification that such temporary penetrations have an approved fire seal installed and that the temporary seals are secured by taping, unless otherwise specified by a cognizant construction specialist.
During plant tours, the inspector verified procedure implementation.
(Closed) Unresolved Item (83-01-02):
Develop procedure to trouble-shoot 125 V DC System. Corrective Maintenance Procedure 1-390C-BC-l-2-3-4-5-lE, Troubleshooting Battery Chargers, has been prepared and approved by the Onsite Safety Committee and the Station Super-intendent on March 23, 1983. This closes out the licensee's commitment for this item.
(Closed) Inspector Follow Item (79-22-06):
DLC to submit supplemental report for LER 79-23, Emergency Diesel Generator Breaker Failure.
As documented in NRC Inspection Report 50-334/79-22, the licensee was requested to provide a supplemental report to LER 79-23, detailing
the results of an engineering evaluation into the breaker failures and overall reliability of the emergency' electrical system. This was previously discussed with the licensee's representative on or about December 6, 1982. To date, no additional information describing the results of that investigation or corrective actions undertaken has been forwarded to the NRC. Technical Specification 6.9.1.9, Thirty-Day Written Report, requires the licensee to submit a completed copy of a licensee event report form, for any condition that leads to operation in a degraded mode pemitted by a limiting condition of operation.
Additionally, the information provided on the LER must be supplemented as needed, by additional narrative infomation to provide a complete explanation of the circumstances surrounding the event. Failure to provide the supplemental information describing the cause and corrective actions is a violation of TS 6.9.1.9(83-07-02).
(Closed)InspectorFollowItem(81-15-06):
DLC to issue supplemental report for LER 81-42 and 81-48, MOV Task Force Results. As described
-
in Inspection Report 81-15, the licensee committed to issuing supplemental LERs providing the results of a task force effort into identifying the cause of several motor cperator valve failures. The expected target date was August 30, 1981. The LERs were never updated.
This is another example of a violation of TS 6.9.1.9(83-07-02).
l
!
_ _ _
.. _ _..
-.___.-,
_,
_ _ _ _ _ _ _ _. _ _ _. _, _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _,, - _ _. __ _ __ _ __,
-8-
.
,
(Closed) Inspector Follow Item (81-25-13):
DLC to resubmit LERs 81-77, 81-78 and 81-83 to correct errors. As of this inspection report, only LER 81-77 and 81-78 have been resubmitted by the licensee.
Inspection Report 81-25 documents an NRC request that LER 81-83 be corrected to include the number of previous events of that type, as specified by NUREG 0161, Instructions for Preparation of Data Entry Sheets for Licensee Event Report File. The licensee connitted to correct the LERs by November 13, 1981. To date, LER 81-83 has not been corrected.
This is another exartple of a violation of TS 6.9.1.9 (83-07-02).
,
3.
Plant Operations a.
General Inspection tours of the plant areas listed below were conducted during both day and night shifts with respect to Technical Specification (TS) compliance, housekeeping and c*eanliness, fire protection, radiation control, physical secuiity and plant protection, operational and maintenance administrative controls.
Control Room
--
-- Primary Auxiliary Building Turbine Building
--
-- Service Building Main Intake Structure
--
Main Steam Valve Room
--
-- Purge Duct Room East / West Cable Vaults
--
Emergency Diesel Generator Rooms
--
Containment Building
--
Penetration Areas
--
Safeguards Areas
--
Various Switchgear Rooms / Cable Spreading Room
--
Protected Areas
--
l Acceptance criteria for the above~ areas include the following:
BVPS FSAR Appendix A, Technical Specifications (TS)
--
BVPS Operating Manual (0M), Chapter 48, Conduct of Operations
--
OM 1.48.5, Section D. Jumpers and Lifted Leads
--
OM 1.48.6, Clearance Procedures
--
OM 1.48.8, Records
--
OM 1.48.9, Rules of Practice
--
OM Chapter 55A, Periodic Checks - Operating Surveillance Tests
--
BVPS Maintenance Manual (MM), Chapter 1, Conduct of Maintenance
--
--
10 CFR 50.54 (k), Control Room Manning Requirements
--
BVPS Site / Station Administrative Procedures (SAP)
--
BVPS Physical Security Plan (PSP)
--
Inspector Judgement
--
i
-
-
_ -
-
.
-
_.
. __
_.
-
-9-
.
.
b.
Operations The inspector toured the Control Room regularly to verify compliance with NRC requirements and facility technical specifications (TS).
Direct observations of instrumentation, recorder traces and control panels were made for items important to safety.
Included in the reviews are the rod position indicators, nuclear instrumentation systems, radiation monitors, containment pressure and temperature parameters, onsite/offsite emergency power sources, availability of reactor protection systems and proper alignment of engineered safety feature systems. Where an abnormal condition existed (such as out-of-service equipment), adherence to appropriate TS action statements were independently verified. Also, various operation logs and records, including completed surveillance tests, equip-ment clearance pemits in progress, status board maintenance and temporary operating procedures were reviewed on a sampling bases for compliance with technical specifications and those administrative controls listed in paragraph 3a.
During the course of the inspection, discussions were conducted with operators concerning reasons for selected annunciators and knowledge of recent changes to procedures, facility configuration and plant conditions. The inspector verified adherence to approved procedures 'for ongoing activities observed. Shift turnovers were witnessed and staffing requirements confirmed.
Except as noted below, inspector coments or questions resulting from these daily
,
reviews were acceptably resolved by licensee personnel.
'
(1) As a result of the NRC fact-finding. investigation into the ATWS events at the Salem Nuclear Generating Station, Unit 1, i
on February 22 and 25, 1983 (detailed in NUREG-0977), additional generic concerns were identified above those contained in IE
'
Bulletin No. 83-01, Failure of Reactor Trip Breakers to Open on Automatic Trip Signal. Those relating to operations are
,
discussed below, while those pertaining to maintenance and
!
procurement of parts and vendor services for safety related systems will be addressed in the next inspection report. The inspector did confirm that the reactor trip breakers are considered safety related at BVPS and are treated as such.
One concern involved the adequacy of the post trip reviews
.perfomed by licensees. The inspector reviewed the require-ments for outlining responsibilities and authorities of the plant staff to determine the circumstances, analyze the cause, and detemine that operations can proceed safely before the reactor is returned to power after a trip or an unscheduled or unexplained power reduction, as set forth in ANSI N18.7-1972, Administrative Controls for Nuclear Power Plants.
__
_ _ _ _,
.
. _ _.
_ _ _ _ _ _
__
_
_-., _ _ _ _ _
..
_
-10-
,
.
,
The inspector verified that those requirements were translated into the Station Administrative Procedures (SAP), Chapter 4, Operation. The SAP requires that an investigation be made to
. determine the cause of the trip and any repairs that are required and that the approval of the Station Superintendent or his alternate is obtained before the plant can be restarted.
Implementation of these requirements were discussed in detail with the Station Superintendent on March 16, 1983. The inspector notedthatthecurrentplantmethod(IncidentReport/ Critique)
of investigating plant trips, makes no reference to the sequence of event recorder or the first out annunciator alarms. The Station Superintendent acknowledged the inspector's concern and stated that the post-trip review program would be strengthened by recording the first out annunciator and provide documentation for the review of the sequence of event recorder information.
This is unresolved item 83-07-03.
An additional review of SER information and post trip review computer printouts for the 1983 reactor trips at BVPS was
,
conducted by the licensee and reviewed by the inspector. No anomalies were noted. The inspector noted that sequenced information provided by the SER was clear, and easily under-standable with a timing resolution of 2 milliseconds. Discussions
>
with licensed personnel indicated that they were adequately
.
trained in this area.
Emorgency Operating Procedures E-0, ECCS Actuation - Immediate (
Actions and Diagnostics, and E-5, Reactor Trip, were reviewed I.
and discussed with the licensed personnel on several shifts.
l The inspector confinned that they understood the E0Ps and were l
properly trained to respond insnediately to a condition indicated by annunciator or instrumentation where a reactor trip signal
,
is initiated and control rods fail to fully insert.
(2) During a Control Room tour on March 15, 1983, the inspector noted that many of the Hagen process controllers had no function indicating lamps lit. The reactor operator stated that there were no spares currently available on site.
During subsequent discussions with the Instrument and Control Supervisor, the inspector expressed a concern that this appeared to be a poor practice from a human factors standpoint. Replacement parts were obtained and procurement practices were revised to avoid depleting the onsite stock. The inspector had no further concerns at this time.
.
!
.. -- -
._.
-
-. -.. -
. -
- -
-
-
-.
-
_
_.
-11-
,
.
(3) On March 11, 1983, the inspector was informed by the Manager of Nuclear Safety and Licensing, that the procedure used to calculate the heat flux hot channel factor FQ(Z), per Technical Specification 3.2.2, was neither reviewed by the Onsite Safety Committee nor approved by the Station Superintendent as required by Technical Specification 6.8.1, Procedures, and Reg Guide 1.33 -
November,1972, Quality Assurance Program Requirements - Operation.
This discrepancy apparently evolved because the required computer calculations are performed by the fuel analysis group offsite, The Manager of Nuclear Safety and Licensing stated that the procedure would be submitted to the Onsite Safety Committee for proper review. Further, to insure that all procedures referenced in TS 6.8 and Reg Guide 1.33 were receiving the required reviews and approval, a matrix would be prepared that related each surveillance requirement to the appropriate procedure. Verification of these corrective actions is unresolved item 83-07-04.
(4)
Currently, Technical Specification 6.2.2, Facility Staff, requires a minimum shift crew composition of 2 senior reactor operators (SR0s) and 2 reactor operators (R0s) for operation in Modes 1 thru 4.
Proposed TS Change No. 82 would revise those requirements to require 2 SR0s and only 1 R0. This change would be effective until December 1,1983, and implemented only when necessary to fully comply with the restrictions on work hours as specified by the NRC policy on overtime (per applicable recomm-endations of NUREG-0737 items in response to Generic Letter No.
82-16). When in effect, a non-licensed individual under the supervision of'a licensed SRO could manipulate controls that do not directly affect the reactivity of the reactor. To demonstrate the feasibility of this proposal, the licensee substituted a start-up operator (SUO) for the regularly assigned plant operator on the day shifts of March 3 - 4, 1983.
Guide-lines provided for the 500 activities include:
plant operator log keeping; liquid waste and gaseous waste discharges; start-up, nomal operations and shut down of evaporators, nomal pump runs for scheduled OSTs; control room OSTs; fill of safety injection accumulators; and, placement of caution tags and out-of-service stickers. The inspector observed these activities on an intennittent basis during the specified time period, and verified that the SUD was under the direct supervision of the Nuclear Shift Operating Foreman (an SRO). The inspector also noted the time and effort involved in familiarizing the 5U0 with log keeping duties.
Normal plant operations were not impaired during the demonstration and normal control room activities were conducted smoothly.
. -.
.
. - _ - _
-
-
.
_
. _ _
12-
-
.
.
Because of the effort needed to become familiar with routine log keeping duties, the inspector expressed a concern that a SU0 could not be. pulled from routine duties and relieve the plant operator without prior familiarization with the new duties.
Licensee plans to familiarize several start up operators on each shift with those duties are currently being discussed.
I c.
Plant Security / Physical Protection Implementation of the Physical Security Plan was observed in the areas listed in paragraph 3a above with regard to the following:
Protected area barriers were not degraded;
--
Isolation zones were clear;
--
Persons and packages were checked prior to allowing entry
--
into the Protected Area;
.
Vehicles were properly searched and vehicle access to the
--
Protected Areas was in accordance with approved procedures; Security access controls to Vital Areas were being maintained
--
and that persons in Vital Areas were properly authorized;
,
Sec'urity posts were adequately manned, equipped and security
--
personnel were alert and knowledgeable regarding position requirements, and that written procedures were available; and, Adequate lighting maintained.
--
On March 3, 1983, the inspector performed a field review of valves with high strength security locking devices. When obtaining the security key to an area containing safety related valves, the inspector was informed by the security watchman that the particular area was not l
considered vital. This was brought to the attention of the security director, who immediately instituted security work permit procedures to control access to this area.
In a DLC letter dated February 2,1981, the licensee responded to an NRC letter dated October 1,1981, concerning the security plan l
vital area analysis for the Beaver Valley Power Station, providing the results of their review and proposed changes to the BVPS security
plan to insure compliance with 10 CFR 73.55.
In this letter, the subject area was identified as being presently protected as vital in accordance with BVPS security plan. A subsequent NRC letter of March 27, 1981, noted the transmitted security plan modifications, but deferred action in regard to certain vital areas for which
!
additional proposed security measures would be needed, because the NRC staff is currently formulating policy on the most effective way to incorporate the additional protective measures in response to the
,
w,-e+----------,
-,,
y-,7-,+,m+----
m
r e.-,-,
. - -,
.
-
- - - - - - - - - - - - - - - - - - -
-
-
c
.
_
-13-
.
.
Los Alamos National Laboratory study. This item was further discussed with Regional security specialists, and because it is not currently
_
an NRC' requirement, no citation will be issued. However, the licensee hasxdetermined that an internal commitment exists, and completed vitalization of the area. The inspector had no further questions at this time.
\\
d.
Radiation Controls Ra'diation controls, including posting of radiation areas, the conditions of step-off pads, disposal of protective clothing,
-
completion of Radiation Work Permits, compliance with Radiation s Work Permits, personnel monitoring devices being worn, clean-
- '
liness of wor.k areas, radiation control job coverage, area monitor operability (portable and pemanent), area monitor calibration, and personnel frisking procedures were observed on a sampling basis.
While touring the Primary Auxiliary Building on March 3, 1983, the inspector observed a radiation technician and an electrician performing i
work in a contaminated area of solid waste under RWP 10802-01.
Upon reviewing the RWP documentation package that was left outside of the contaminated area, the inspector noted that the pre-job review portion had been signed by both individuals; however, required documentation for the points of discussion were left blank. This was immediately discussed with the Radcon Supervisor and corrected.
The inspector verified that all Radcon Foreman were made aware of this event through a memo issued on March 4, 1983. The inspector had no further concerns at this time.
No violations were identified.
e.
Plant Housekeeping and Fire Protection Plant housekeeping conditions including general cleanliness conditions and control of material to prevent fire hazards were observed in areas listed in paragraph 3a. Maintenance of fire barriers, fire barrier penetrations, and verification of posted fire watches in these areas was also observed. No inadequacies were observed.
4.
Engineered Safety Features (ESF) Verification
,
!
l A.
The o)erability of various ESF systems was verified by perfoming a wal cdown of all accessible portions that included the following as appropriate:
.
.
._
-
-14-
.
.
i (1) System lineup procedures match plant drawings and the as-built configuration.
(2) Equipment conditions were observed for items which might degrade performance. Hangers and supports are operable.
(3) The interior of breakers, electrical and instrumentation cabinets were inspected for debris, loose material, jumpers, etc.
(4) Instrumentation was properly valved in and functioning; and had current calibration dates.
(5) Valves were verified to be in the proper position with power available. Valve locking mechanisms were checked, where required.
(6) Technical specification required surveillance testing was current.
The 125 VDC System was inspected on March 14, 1983. No abnormal conditions were observed.
B.
Other selected ESF trains were inspected on a weekly basis to verify operability of major flow paths and components. ESF trains so inspected were:
(1) Auxiliary Feedwater System (March 8,1983)
(2) Quench Spray System (March 15, 1983)
(3) AC Power Distribution, including Emergency Diesel Generators (March 17,1983).
Alignments were correct.
5.
Surveillance Activities To ascertain that surveillance of safety-related systems or components is being conducted in accordance with license requirements, the inspector observed portions of selected tests to verify that:
r a.
The surveillance test procedure conforms to technical specification requirements.
b.
Required administrative approvals and tagouts are obtained before initiating the test.
c.
Testing is being accomplished by qualified personnel in accordance with an approved test procedure.
_.., _
.. - -
. _ ---. -
- - -
..--
- -. --
.-
.
.
-
-15-
.
.
d.
Required test instrumentation is calibrated.
e.
LCOs are met.
f.
The test data are accurate and complete. Selected test result data was independently reviewed to verify accuracy.
g.
Independently verify the system was properly returned to service.
h.
Test results meet technical specification requirements and test discrepancies are rectified.
i. The surveillance test was completed at the required frequency.
(1) OST 1.7.6, Centrifugal Charging Pump Test (CH-P-lC), March 4, 1983.
(2) BVT 1.1-1.2.1, Moderator Temperature Coefficient Test, March 7, 1983.
(3) MSP 43.35, Rad Are Monitor RM-217B, Multisample - Gaseous Activity Calibration, March 31, 1983.
(1) Portions of OST 1.7.6, Centrifugal Charging Pump Test (CH-P-lC),
were observed by the inspector from both the Control Room (CR)
and the Primary Auxiliary Building (PAB), on March 14, 1983.
The reactor operator had the CR master copy of the OST out for ready reference. This copy was not being used to formally document the test perfomance. When the inspector observed a latter portion of the test from the PAB, it was noted that the start-up operators copy of the OST was only initialed for those steps that he personally completed. The remainder of the OST, including the initial conditions section, was uninitialed and left blank. The Site Administrative Procedures, Chapter 4, Section 5, Adherence to Operating Procedures, requires that the operating procedure must be present and followed for any operation requiring documentation. The inspector discussed this with the Station Superintendent and expressed a concern that the current
,
method of completing OST signoffs after the test was perfomed was inconsistent with good practice. Though there are instances when a throw away field copy would be appropriate, as when a portion of the work is conducted in remote or contaminated area an up-to-date master copy is still necessary.
In this particular case, documentation of operational actions requiring coordination between the control room and the PAB was not kept current as the operational surveillance test progressed.
i
-
- ~
~ ~-
--
w o-
---
-,, -. _
,, _, _ _ _ _ _ _ _ _ _ _ _ _ _ _,
,
__ ___ _
__
.
-16-
.
.
ANSI N18.7 - 1972, Administrative Contmls for Nuclear Power Plants, Section 5.1.2, recommends that guidance be provided to identify the manner in which procedures are to be implemented; including when a written procedure is to be present and followed step-by-step, and when verification of significant steps, by initials or signatures on a checkoff list is required.
If documentation of an action is necessary, it further recommends that the procedure be present and followed step-by-step, and necessary data recorded as the task is performed. Review of OM Chapter 48, Section G, and the Station Administrative Procedures, Chapter 4,Section V, Adherence to Operating Procedures, require-ments indicated that all of the guidance recommended in ANSI N18.7-1972, has not been incorporated into administrative procedures.
This item is unresolved (83-07-05), pending revision of the Site Administrative Procedures to incorporate ANSI N18.7 - 1972 guid-ance on procedure adherence.
(2) The inspector witnessed portions of BVT 1.1 - 1.2.1, Moderator Temperature Coefficient Test, on March 7, 1983. The inspector reviewed the test data and compared it with the design values presented in the Nuclear Design and Core Management of the BV Unit #1 Power Plant Cycle 3, for HFP, AR0, equilabrium Zenon conditions, with a fuel burn up of approximately 73 GWD/MTtf. The-26pcm/gMTCdesignvalueforthatfuelburnupwasapproximately expecte F.
The MTC calculated from the experimental data yielded a value of - 12.9 pcm/0F. This meets Technical Specification 3.1.1.4 requirements that the MTC shall be less positive than
Zero pcm/ F, but less negative than - 50 pcm/ F at rated thermal j
power. The inspector noted that the previous MTC determination made at about 5% of rated thenngl power after fuel loading was slightly positive at +.255 pcm/ F as compared to an estimated design value of -8 pcm/ F.
This was discussed with NRC Regional management and no safety concern was identified. During discussions with the supervisor of plant performance and testing, the inspector expressed a concern that any apparent discrepancies
!
between projected and actual measurements should be satisfactorily l
accounted for by the licensee prior to test acceptance.
l 6.
Maintenance Activities The inspector observed portions of selected maintenance activities on safety-related systems and components to verify that those activities were being conducted in accordance with approved procedures, technical
specifications and appropriate industrial codes and standards. The inspector conducted record reviews and direct observations to detennine that:
-
--=.
._
-
. _ _
.-
_.
-
-
-17-
.
.
.
Those activities did not violate a limiting condition
-
for operation.
Redundant components were operable.
-
Required administrative approvals and tagouts had been
-
obtained prior to initiating work.
Approved procedures were used or the activity was within
-
the " skills of the trade."
- The work was performed by qualified personnel.
The procedures used 'were adequate to control the activity.
-
Replacement parts and materials were properly certified.
-
Radiological controls were properly implemented when necessary.
-
Ignition / fire prevention controls were appropriate for the
-
activity.
QC hold points were established where required and observed.
-
Equipment was properly tested before being returned to service.
-
,
An independent verification was conducted to verify that the
-
equipment was properly returned to service.
(1) Repair of charging pump 1B per MWR 830458 on March 3, 1983.
(2) Troubleshooting diesel driven fire pump (FP-P-2) on March 30 - 31, 1983. The pump was declaired inoperable on March 27, 1983, due to overheating. A special report is due per TS 3.7.14.1 if it is not restored to operable status within 7 days.
7.
Cycle 3 - 4 Refueling Preparation On March 17, 1983, the inspector conducted preliminary discussions with the Director of Operations-Quality Control (0QC), concerning the upcoming refueling outage. Topics addressed included DLC - 0QC inspector qualifications and training, new fuel and burnable poison assembly inspections and QC requirements on proposed vendor services. Westinghouse is scheduled to provide assistance for refueling operations and replacement of control rod guide tube pins.
For the latter topic, the inspector was informed that Westinghouse had a qualified QA program that is audited by DLC. The inspector contacted the QA Department and requested copies of the ongoing QA fuel audit. This item will receive further attention in the next inspection report.
- __
___
_ _ _
..
_ _. -
--
-
-
_
_
-18-
.
.
During receipt of the first two new fuel assemblies on site on March 29, 1983, the inspector noted that the 0QC inspectors had an unapproved and obsolete copy of procedure, NSQC 10.2, Fuel Assembly and Shipping Container Receipt and Inspection, in their possession. When questioned about the use of an unapproved procedure, the inspector was informed that it was the copy issued to them. The Director of 0QC was immediately notified and an authorized copy of 0QC Procedure 10.2 was obtained. Failure to have an approved copy of 0QC Procedure 10.2 at the location where new fuel is received and inspected is a violation of Nuclear Division Directive No.
12, Operations Quality Control, Issue 2(83-07-08).
8.
Steam Generator Blowdown Supports Infomation was received on March 29, 1983, from the Unit 2 (under construction) NRC inspector relating to the application of Pacific Scientific Company (PSA) mechanical snubbers installed under Design Change Package 408, Steam Generator Blowdown Supports, during the last refueling outage (see NRC Inspection Report 50-334/82-29). By letter from the Stone & Webster Engineering Corporations (Architect Engineer),
Project Engineer dated August 13, 1979, to the Duquesne Light Company's Project Manager, it was noted that PSA mechanical type snubbers, currently utilized for earthquake type loads, cannot be used at locations where an occassional dynamic load is expected to remain unidirectional for a critical period of time. This is due to the non-locking characteristics that allow displacement of a pipe member to a level of unacceptable stress during loading greater than a critical period. These conditions are expected to be encountered in the event of a high energy line break, a design objective of DCP 408. This was brought to the attention of the Manager of Nuclear Operations on March 29, 1983. Acceptability of PSA mechanical snubbers for this type application is unresolved (83-07-09)
pending DLC engineering evaluation.
9.
Inoffice Review of Licensee Event Reports (LERs)
l The inspector reviewed LERs submitted to the NRC:RI office to verify that the details of the event were clearly reported, including the l
accuracy of the description of cause and adequacy of corrective action.
,
The inspector detemined whether further infomation was required from t
l the licensee, whether generic implications were indicated, and whether the event warranted onsite follow-up. The following LER's were reviewed:
i l
LER 83-05/99X * Safety injection from steam line high DP rate
--
due to main steam trip valve closure.
'
LER 83-06/03L * Trip Valve TV-MS-101-B failed to stroke after
--
inadvertent closure.
LER 83-07/04T High tritium activity in quarterly composite of
--
weekly grab samples.
I a
- - - - -
. - -
- -... - -.
<.-----..,-....--,..,,,~,.--,,...--c
-.,,,,---m,n..4-w,-r
--...-.-r%
,.,
,-w -.
w y
- - -.,----,
--m--v--
, - - - -,,
-19-
,
,
LER 83-08/03L * Overheated packing on turbine driven auxiliary
--
feedwater pump.
LER 83-02/03L Partial loss of offsite power and reactor trip.
--
- Denotes those reports selected for onsite followup.
The inspector noted that LER 83-02 did not identify the cause of the back-up timer relay (62-Z41) malfunction, but that possible causes and corrective recommendations from the Substations and Shops Department were under consid-eration. At the exit meeting of this inspection, the licensee was requested to issue a supplemental LER providing additional information regarding those details. This is unresolved item (83-07-10)
10. Onsite LER Followup The inspector reviewed the licensee's actions for the following LERs:
LER: 83-05:
Initial Review of the safety injection event caused by a high steam pressure rate was documented in NRC Inspection Report 50-334/83-04.
To date, this was the 17th inadvertent safety injection (SI) at~ Beaver Valley Power Station. A generic review of SI nozzle stress associated with coldwater injection was provided by the Division of Operating Reactors, NRC, in a letter to DLC dated December 18, 1979. A safety evaluation report prepared as an attachment to this letter concluded that after performing analysis using conservative assumptions, a typical nozzle should be able towithstandagleast50injectioneventswithatemperaturedifferential as high as 500 F.
It further concluded that a facility could probably withstand more than 50, because in most cases, the temperature differential would be less than that assumed in the analysis. The safety evaluation report
<
did recomend that a plant specific analysis be considered after approaching 25 inadvertent safety injections.
.
The inspector discussed this item with the Superintendent of Licensing and Compliance and expressed a concern that DLC should not rely on a safety I
analysis that has not been reviewed and approved by their appropriate safety committees. The Superintendent of Licensing and Compliance acknow-ledged the inspector's concern. This item is unresolved (83-07-11) pending DLC's review and approval of a safety evaluation defining the number of safety injection transients pemitted on the hot SI nozzles by ASME Code Section III.
During review of Section 14 of the updated FSAR, it was detemined that an erroneous number of SI transients was referenced (10 postulated), as meeting the requirements of ASME Section III. The licensee stated that pending completion of the safety analysis review, this section of the updated FSAR would be revised.
..
.
.
._
__ _
-20-
,
.
_LER:
83-06: The inadvertent safety injection and reactor trip of February 12, 1983, was caused by a loss of instrument air to the B main steam trip valve (TV-MS-101B). During recovery operation prior to plant restart, the trip valve failed to close during an operational stroke test. Licensee investigation found scoring on one of the actuator cylinder walic. From piston diameter measurements, the loading end appeared to have been slightly mushroomed due to impact with the cylinder seat when the valve tripped.
In response to engineering recommendations provided in EM No. 60684, the piston OD was restored at the loading end
,
to its original dimension. This work was accomplished per Corrective Maintenance Procedure 1-21-TV-MS-101-B-14M on February 13, 1983. The valve was then tested per OST 1.21.5, Main Steam Trip Valve Full Closure Test, and accepted by Operations. Licensee corrective actions were acceptable.-
LER:
83-08: Theturbinedrivenauxiliaryfeedwaterpump(FW-P-2)was f
declaired inoperable on February 18, 1983. The inspector observed i
maintenance activities relating to the shaft repacking as detailed in NRC Inspection Report 50-334/83-04. Under the cause description and corrective action section of the subject LER, the packing follower heat-up was attributed to a burr which developed on the follower. The inspector noted that this had not been observed during those maintenance activities.
This was discussed with the maintenance engineer, who stated that a burr had been previously observed on one of the motor driven auxiliary feedwater pumps during preventative maintenance. The inspector discussed this further with the licensee's representative and stated that the LER would have to be resubmitted with the correct cause description and corrective actions.
This is unresolved item 83-07-13.
11.
Unresolved Items l
Unresolved items are matters about which more infomation is required to detemine whether they are acceptable, items of noncompliance or deviations. Seven unresolved items were identified and are discussed
..
in sections 3, 5, 8,9 and 10 of this repor.t. Followup on several previous unresolved items are discussed in section 2.
,
'
- 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 sunmary of inspection findings were also
-
provided to the licensee at the conclusion of the report period.
i
!
l
.
- - -.
.
...
...
---
-.
--,
=-.
-
- - - -