ML20151Z323
| ML20151Z323 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 09/15/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20151Z313 | List: |
| References | |
| 50-334-98-04, 50-334-98-4, 50-412-98-04, 50-412-98-4, NUDOCS 9809210284 | |
| Download: ML20151Z323 (58) | |
See also: IR 05000334/1998004
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U. S. NUCLEAR REGULATORY COMMISSION
REGION 1
Report Nos. 50-334/98-04,50-412/98-04
Docket Nos. 50-334,50-412
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Licensee: Duquesne Light Company (DLC) i
Post Office Box 4
Shippingport, PA 15077
Facility: Beaver Valley Power Station, Units 1 and 2 i
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Insperin Period: June 28,1998, through August 15,1998
Inspectors: D. Kern, Senior Resident inspector
G. Dentel, Resident inspector
G. Wertz, Resident inspector !
E. King, Emergency Preparedness / Safeguards Specialist
J. Furia, Senior Radiation Specialist
J. Laughlin, Resident inspector
D. Brinkman, Senior Project Manager, NRR
J. Brand, Resident inspector
K. Kolaczyk, Mechanical Engineering Specialist ;
J. Trapp, Senior Risk Analyst ;
M. Ferdas, Reactor Engineer -
S. Hansell, Resident inspector
Approved by: P. Eselgroth, Chief i
Reactor Projects Branch 7
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9909210284
990915 '
ADOCK 05000334
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EXECUTIVE SUMMARY
Beaver Valley Power Station, Units 1 & 2
NRC Inspection Report 50-334/98-04& 50-412/98-04
- This integrated inspection included aspects of licensee operations, engineering,
i maintenance, and plant support. The report covers a 7-week period of resident inspection.
In addition, it includes the results of announced inspections by regional security and
radiological protection specialist inspectors.
Ooerations
- Command and c,ontrol prior to and during the August 11, Unit 1 reactor startup
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were good. The prestartup containment walkdown as well as the preevolution
l briefing for startup were comprehensive. Maintenance personnel responded
promptly and effectively coordinated with operations personnel to resolve concerns
regarding instrument indications. (Section 01.2)
L * On August 11, Unit 1 tripped from 24% reactor power due to a steam generator
(SG) level transient experienced while transferring feedwater flow control from the
bypass feedwater regulating valve (FRV) to the main FRV. Prior to the trip, I
operators did not fully discuss and recognize the effects of placing a failed steam
flow instrument in trip, which enabled the reactor to trip at a higher SG water level.
Operators responded properly to the reactor trip. (Section 01.3)
o -* The post trip critique and event response team report identified several important "
causes and corrective actions for the trip. The inspectors identified several
information gathering / assessment deficiencies, including the lack of recommended
actions to improve steam generator level control during subsequent feedwater
regulating valve transfer evolutions. Plant management took appropriate actions to
address these concerns prior to authorizing plant restart. Operating crew seminars,
conducted prior to unit restart, effectively focussed on crew awareness and
communications. (Secticn 01.4)
- The licensee developed and implemented a Unit 1 Restart Action Plan (RAP) to
provide assurance that known conditions adverse to quality were corrected and that l
personnel, processes, and equipment were ready for unit restart. Corrective actions )
to address weaknesses in Technical Specification compliance were comprehensive. !
The RAP and its implementation were appropriate to address the root causes for the )
extended forced unit outage. (Section 07.1)
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Maintenance
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- A design change to modify the Unit 1480 Volt emergency bus under voltage relay
scheme was implemented correctly. The maintenance personnel performing the
work were knowledgeable and appropriately briefed. Missing motor control center
panel fasteners were identified by the maintenance crew and properly dispositioned
by the site staff. The infrequently performed test or evolution briefing was
professional, notwithstanding two minor deficiencies. (Section M1.1)
- Human performance errors continued to impact plant operations. Maintenance
personnel failed to adhere to procedures for configuration control and work control
when attempting to resolve excessive packing leakage on the Unit 1 turbine driven
auxiliary feedwater pump. These actions delayed pump restoration by twenty-two
hours. (Section M1.2)
- The current Fix-it-Now (FIN) team current work scope and volume was relatively ;
low. FIN team maintenance work performance was methodical and good self l
checking and radiological control practices were noted. (Section M1.3)
o Maintenance on safety related check valves to correct a motion binding issue was
properly performed and supervised. (Section M1.4)
Enaineerina
- The licensee identified binding issues associated with thirty Unit 2 check valves.
Causal analysis for this issue during the last refueling outage was incomplete, which
contributed to several additional failures occurring during this outage. Although the
va!ves affected multiple safety systems, the safety significance was low due to
redundant, diverse isolation valves for each of the check valves affected. Licensee
investigation, root cause analysis, quality controls, and corrective action during this
period were comprehensive. (Section E1.1)
- System and Performance Engineering Department personnel developed a systematic
and comprehensive process to evaluate system status and readiness. System
engineers were knowledgeable and consistent in their implementation of the
required system health reviews, providing appropriate recommendations to station
management regarding readiness for Unit 1 restart. Insights gained during the
system health reviews were shared with appropriate departments for
implementation. (Section E2.1)
- In response to an NRC violation, the licensee performed an extent of condition
review which identified numerous design issues for which the TSs were non-
conservative. Appropriate corrective actions including interim administrative
controls, development of TS amendment requests, and process revisions to ensure
the facility is operated within its design basis were established. Interdepartmental
coordination and the quality of engineering work to resolve the issues were
excellent. The safety significance of the design issues was low and the licensee
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- correctly determined that Unit 1 could restart prior receiving TS amendment
approval from the NRC for the subject issues. (Section E8.1)
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- ' . The program for the control of contaminated materials and equipment was effective. !
The licensee appropriately identified and maintained records of spills and other j
occurrences as required under 10 CFR 50.75(g)(1). (Section R1) i
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- - The program for identifying and tracking hot spots, and shielding to reduce j
occupational exposures was effectively implemented. The Unit 1 refueling outage ;
in 1997 (1R12) was completed with the lowest total dose in unit history. (Section l
R1) l
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- . Records of occupational exposures were appropriately maintained in accordance
with.10 CFR 20. (Section R1)
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- The annual radworker training program, using a mock-up facility, was effective. !
(Section R5) I
' * - . Security and safeguards activities were conducted in a manner that protected public ,
health and safety in the areas of access authorization, alarm stations, i
communications, and protected area access control of personnel and packages. ;
(Section S1)
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- - Security facilities and equipment in the areas of protected area assessment aids,
protected area detection aids, personnel search equipment, and illumination and
- surveillance hardware were well maintained and reliable. (Section S2)
-* Security force members adequately demonstrated that they had the requisite
l~ knowledge necessary to effectively implement the duties and responsibilities
associated with their position. Security force personnel were trained in accordance
! with the requiremer of.the Training and Qualificaitons Plan and training
i documentation was y iperly maintained and accurate. (Sectfons S4 and S5)
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- Management support was adequate to ensure effective implementation of the
security program, and was evidenced by adequate staffing' levels and the allocations
of resources to support programmatic needs. (Section S0)
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- Audits of the security program were comprehensive in scope and depth, audit ;
y findings were reported to the appropriate level of management, and the program j
h was properly administered. In addition, a review of the documentation applicable to ;
the self-assessment program indicated that the program was effectively I
implemented to identify and resolve potential weaknesses. (Section S7) l
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TABLE OF CONTENTS
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EX EC UTIVE S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii
TA B LE O F CO NT ENT S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v
1. Operations .................................................... 1
01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01.1 General Comments (71707) ........................... 1
01.2 Unit 1 Reactor Startup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01.3 U nit 1 R e a ctor Trip . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
01.4 Unit 1 Reactor Trip Evaluation and Restart ................. 4
07 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
07.1 Assessment of Unit 1 Restart Action Plan implementation . . . . . . 6
08 Miscellaneous Operations issues ........................... 11
08.1 Inspector Review of Independent Plant Assessment (71707) ... 11
11. M a i nt e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
M1.1 Modification to Unit 1480 Volt Emergency Bus Under Voltage Relay
Scheme ........................................ 11
M1.2 Improper Response to Unit 1 Excessive Turbine Driven Auxiliary J
Feedwater (AFW) Pump Packing Leakage . . . . . . . . . . . . . . . . . 12
M1.3 : Beave Valley Fix-It-Now (FIN) Maintenance Process . . . . . . . . . 14
M1.4 Check Valve Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
111. E n g i n e e ri n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
E1.1 Check Valve Binding ............................... 15
E2 Engineering Support of Facilities and Equipment ................. 18
E2.1 Unit 1 System Health Reviews for Restart ................ 18
E8 Misce!!aneous Engineering Issues ........................... 19
E8.1 (Closed) eel 50-334(412)/98-03-05 . . . . . . . . . . . . . . . . . . . . . 19
E8.2 (Closed) LER 5 0-412/9 7-01 1 . . . . . . . . . . . . . . . . . . . . . . . . . . 22
I V . Pl a nt S u p po rt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . 22
R5 Staf f Training and Qualification in RP&C . . . . . . . . . . . . . . . . . . . . . . . 24
S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 25
S2 Status of Security Facilities and Equiprnent . . . . . . . . . . . . . . . . . . . . . 26
S3 Security and Safeguards Procedures and Documentation . . . . . . . . . . . 27
S4 Security and Safeguards Staff Knowledge and Performance . . . . . . . . . 28
S5 Security and Safeguards Staff Training and Qualiiication . . . . . . . . . . . 28
S6. Security Organization and Administration . . . . . . . . . . . . . . . . . . . . . . 29
S7 Quality Assurance in Security and Safeguards Activities ........... 29
V. M a n a g e m e nt M e e ting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
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X1 Exit Meeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
l X2 Management Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
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l PARTIAL LIST OF PERSONS CONTACTED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
l INSPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 3 3
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! ITEMS OPENED, CLOSED AND DISCUSSED . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . 34
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- LIST O F ACRONYM S U SED . . . . . . . . . . . . . . . . . . . . . . ' . . . . . . . . . . . . . . . . . . . 35
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L Report Details
Summarv of Plant Status ,
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l Unit 1 began the inspection penod in cold shutdown (Mode 5). The plant entered hot
shutdown (Mode 4) on August 6 and synchronized to the grid on August 11. This
completed a 192 day forced outage during which numerous technical specification (TS)
surveillance testing and design issues were corrected. The plant experienced a reactor trip
on August 11 at 3:12 p.m. due to "A" Steam Generator (SG) low water level coincident
with steam flow and feedflow mismatch while attempting to place the main feedwater
regulating valves (FRVs)in service. Unit 1 restarted and synchronized to the grid on
August 15.
Unit 2 remained in Mode 5 throughout this inspection period in order to correct
longstanding design discrepancies and to resolve various TS limiting condition of operation
(LCO) and surveillance testing issues. Major work involved a detailed review of the current
licensing basis to validate TS and surveillance requirements compliance, steam generator
tube inspections, and repairs to various check valves. (Section E1.1)
1. Operations I
01 Conduct of Operations
01.1 General Comments (71707) !
The inspectors conducted reviews of ongoing plant operations. In general, the
conduct of operations was professional and safety-conscious. Specific events and
noteworthy observations are detailed in the sections below, in particular, the
inspectors noticed good plant and system knowledge by the Nuclear Operators (NO)
while performing their plant rounds and prompt resolution of NRC identified
deficiencies.
01.2 Unit 1 Reactor Startuo
a. inspection Scope (71707)
On August 11,1998, the inspectors observed Unit 1 reactor startup activities from
the main control room. The review included the completion of the startup
requirements contained in operation procedure 10M-50.4.D(ISS3)," Reactor Startup
from Mode 3 to Mode 2," Rev. 31, achievement of reactor criticality, and unit
synchronization to the grid,
b. Observations and Findinos
! The operations crew was professional and very knowledgeable of plant equipment
status. Station personnel conducted a thorough equipment walkdown inside
containment after pressurizing the reactor coolant system. Minor discrepancies
were identified and properly corrected. The Nuclear Shift Supervisor (NSS)
performed a detailed briefing prior to the mode change and the start of control rod
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withdrawal to criticality. The briefing included a review of all applicable
precautions, limitations, and a clear standard for reactivity management. The
reactor engineer provided a good overview of the estimated critical position for the
reactor startup.
The NSS and assistant NSS demonstrated noteworthy command and control
throughout the reactor startup. The startup requirements were completed after
thorough evaluation and the evolution was conducted at a controlled pace. Crew
communications and the use of proper repeat backs were evident for the entire
startup. Senior plant management provided proper oversight for the back shift
evolution. An additional reactor operator and senior reactor operator were assigned
to control room duties to assist the normal crew. Control room distractions were
minimized with the exception of a nuisance alarm related to a reactor coolant pump
temperature recorder. The reactor achieved criticality at 7:15 a.m.
Control room operators carefully observed feedwater flow and steam flow
indications during power ascension from 5% to 15% reactor power. Several
channels of this instrumentation were slow to indicate flow at this low power level.
While this is not uncommon at low power levels, operators requested
instrumentation and control technicians to investigate the indications to confirm
whether they were providing appropriate signals. Technicians confirmed that "A"
SG steam flow channel IV instrument (F-MS-475) had failed downscale due to a
failed signalisolator. Operators properly declared the irestrument inoperable and
entered the TS 3.3.1.1 Limiting Condition of Operation (LCO) which permits
continued power operation provided that the instrument is fixed or its protection
signal bistable is placed in the trip position within the following six hours.
The main turbine was synchronized to the grid at 1:13 p.m. The inspectors noted
excellent communications among the operating crew. The shift technical advisor
demonstrated close teamwork with the reactor operator as he alerted the crew to
the initiation of a minor reactor coolant system (RCS) pressure transient as turbine
load was increased.
c. Conclusions
Command and control prior to and during the August 11, Unit 1 reactor startup
were notable. The prestartup containment walkdown as well as the preevolution
briefing for startup were comprehensive. Maintenance personnel responded
promptly and effectively coordinated with operations personnel to resolve concerns
regarding instrument indications.
01.3 Unit 1 Reactor Trio
a. Insoection Scoce (71707)
On August 11, approximately two hours after being placed on-line, the Unit 1
reactor tripped. The inspectors responded to the control roorn, interviewed
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personnel, reviewed station records, and observed licensee activities to assess the
cause of the trip and operator response to the trip.
b. Obsecrations and Findinas
Steam flow instrument F-MS-475 failed at 12:40 p.m. (see Section 0.1.2), with the
reactor at 15% power and the main turbine off-line. This instrument provides a
signal to one of two channels of the steam flow /feedwater flow mismatch
coincident with low SG level reactor trip protection logic. This trip function is
designed as a preemptive protection action and is not credited in the station
accident analysis. While technicians prepared a correct lve maintenance work
package the NSS directed that the main turbine be placed on-line and reactor power
was stabilized at 24%.
Technicians informed the NSS that instrument repairs would not be complete prior
to expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> TS 3.3.1.1 LCO action time. The NSS directed
technicians to place the instrument bistable in trip. Immediately prior to placing the
bistable in trip, the "A" SG level was stable at 44%, with level being controlled by
the bypass feedwater regulating valve (FRV). The next planned activity was to
transfer feedwater flow control from the bypass FRV to the main FRV. This transfer !
typically results in some amount of SG level fluctuation as control is shifted to the '
main FRV. The NSS had previously informed the inspectors that F-MS-475 would
be placed in trip later within the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> LCO period, when the plant was stable. The
inspectors questioned the NSS regarding whether placing the instrument bistable in
trip now, prior to transferring feedwater control to the main FRVs, was prudent. ,
The NSS stated that he believed this action was appropriate since it places the j
instrument in a safe condition (protective signal active) and the repairs would not be
complete within the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> LCO period. At 2:40 p.m., technicians piaced the F-MS- )
475 bistable in trip which inserted one of the two trip signals necessary for the
reactor trip function to actuate. The remaining signal necessary for a reactor trip
was a low "A" SG level signal at 25% narrow range level. Without this bistable in
trip, the reactor would not receive a trip signal based on SG level, until reaching the
low-low SG level trip setpoint of 15%. Based on subsequent interviews, the
inspectors determined that operators were aware of the 25% level trip setpoint.
Shortly after placing F-MS-475 in trip, operators transferred "A" SG level control
from the bypass FRV to the main FRV. "A" SG levellowered as the main FRV was
slower to ope 7 than operators had anticipated. Operators had not been pre-briefed
that the gain adjust for the "A" main FRV had been adjusted to slow valve response
following the last reactor startup in January 1998. Operators were unable to
restore SG level prior to receiving a reactor trip at 3:12 p.m. Operators properly
responded to the reactor trip and the subsequent RCS cooldown. Prompt operator
actions included manualisolation of the main steam isolation valves, isolation of the
RCS letdown system, and manual alignment of the charging pump suction to the
refueling water storage tank. Operators properly reported the automatic reactor trip
as required by 10 CFR 50.72.
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c. Conclusions
y . .On. August 11, Unit 1 tripped from 24% reactor power due to a steam generator
l' (SG) level transient experienced while transferring feedwater flow control from the
bypass feedwater regulating valve (FRV) to the main FRV. Prior to the trip,
operators did not fully discuss and recognize the affects of placing a failed steam
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flow instrument in trip, which enabled the reactor to trip at a higher SG water level.
' Operators responded properly to th i reactor trip.
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01.4 Unit 1 ' Reactor Trio Evaluation and Restart
a. Inspection Scope (71707. 92901)
The inspectors' attended the post trip critique and reviewed the event response team
(ERT) report to evaluate licensee assessment of the trip and actions taken to
preclude recurrence,
b. Observations and Findinos
. The acting General Manager of Nuclear Operations (GMNO) conducted a post trip.
critique, one hour after the trip.'The inspectors noted that written statements were
obtained and personnel freely responded to questions. However, the inspectors
also observed deficiencies during the critique. Some questions (e.g., regarding main
FRV control signals and valve position) were asked and responded to in a general
nature rather than detailed specifics, in some cases the responses were provided -
by personnel who were not present in the control room, based on what they
expected to occur rather than what was witnessed. Additionally, several
departments who would typically be represented at a post trip critique, were not
notified of the meeting. The inspectors noted that while not required, use of the
newly established critique process described in NPDAP 5.10, " Conduct of Critiques
and Multi-Discipline Analysis Team investigations," Rev.- O, would have provided the
. structure to preclude these deficiencies. The inspectors discussed these
observations with the acting GMNO and the plant manager. The plant manager had
similar observations and assigned actions to reevaluate the post trip review process.
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An ERT was established to investigate the trip and provide associated i
recommendations to plant management prior to unit restart. The inspectors
observed the ERT report presentation to the Nuclear Safety Review Board (NSRB). i
The report provided a detailed review of equipment response and causal factors. !
The primary cause of the trip was determined to be cognitive error by the shift
crew, failure to fully recognize and respond to the tripping of the steam
. flow /feedwater flow mismatch bistables enabling a reactor trip to occur at a higher
SG level. Specifically, the operating crew did not stop and verbalize the fact that ,
they would now have a much smaller margin between operating SG level and the l
protective trip prior to transferring FRV control. Appropriate recommendations were !
L ' made to address this root cause. Senior plant management conducted additional l
l operating crew seminars, pnor to each shift, to emphasize crew awareness and
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communications. The inspectors noted that the selection of visual aids and scenario
examples was outstanding.
The NSRB endorsed the ERT findings and recommended additionallong term actions
to evaluate the FRV control design to determine whether improvements could be
made which would limit the magnitude of SG level transients. While these
recommendations were appropriate, the inspectors observed that no action had
been completed or assigned which would directly improve the operator's ability to
minimize the SG level transient associated with transferring from the bypass FRV to
the main FRV on the subsequent reactor startup. The NSRB accepted the condition
that SG level may change 10-20% during this evolution. The inspectors questioned
this performance and asked whether the NSRB had taken sufficient action to
preclude a repeat of the reactor trip. The burden on operations personnel, created
by the SG level transient while transferring FRV control, had not been addressed.
The NSRB chairman responded to the inspectors' comments by directing the acting
GMNO to evaluate options to improve SG level control during the FRV transfer
evolution prior to reactor restart.
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Operations, engineering, maintenance, and training personnel worked closely
together and revised the procedure for transferring FRV control. This new method
was presented to the NSRB in a subsequent meeting along with the identification of
an additional steam flow transmitter that had failed during the trip. The steam flow
transmitter failure had been overlooked by the ERT, but was subsequently identified !
by system engineers and corrected prior to reactor startup. Operators were properly )
trained on the revised FRV transfer procedure. Operators noted much improved SG l
level control during the next FRV transfer on August 16. The transient was
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approximately 5-8% level deviation in place of the 20% deviation experienced on !
August 11. The plant manager met with the inspectors to discuss several potential
areas of improvement identified by the plant manager during August 10-16.
c. Conclusions
The post trip critique and event response team report identified several important
causes and corrective actions for the trip. Yet the inspectors identified several
information gathering / assessment deficiencies, including the lack of recommended
actions to improve steam generator level control during subsequent feedwater
regulating valve (FRV) transfer evolutions. Plant management took appropriate l
actions to address these concerns prior to authorizing plant restart. Operating crew
seminars, conducted prior to unit restart, effectively focussed on crew awareness
and communications.
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07 Quality Assurance in Operations
07.1 Assessment of Unit 1 Restart Action Plan implementation
a. insoection Scope (71707. 37551)
The 'icensee developed and implemented a Unit 1 Restart Action Plan (RAP) to
pr; lo assurance that known conditions adverse to quality were corrected and that
personnel, processes, and equipment were ready for unit restart. The RAP
contained 65 individual action items, each of which was identified for completion
prior to one or more restart milestones (e.g., reactor coolant system pressurization,
Mode 4, Mode 2, and 30% reactor power). The action items were subdivided into
tiie areas of process and program enhancements (P), culture enhancements (C), self
assessments (S), plant material condition (M), and management oversight (O). The
NRC formed a Beaver Valley Oversight Panel (BVOP) to provide inspection oversight l
regarding licensee readiness for unit restart. The inspectors reviewed the RAP, !
observed licensee actions, interviewed personnel, and reported to the BVOP l
providing assessment of licensee readiness to restart Unit 1.
b. Observations and Findinas
Based on licensee performance during the past year, the BVOP identified five root j
causes associated with problems leading to the extended dual unit shutdown. ;
- - Deficiencies in site-wide knowledge of TS and Licensing Basis.
- Weaknesses in day-to-day operational activities as a result of poor
communication, control room awareness, and work management
breakdowns. Recognition and resolution of degraded conditions was
inconsistent.
- Poor previous corrective action (prior to January 1997) and operating
experience programs. Many current problems were previously identified, but
not corrected.
- Failure to plan and work activities (maintenance in particular) according to
schedule.
- Low overall performance standards in the past and acceptance of problems.
Based on reviewing the RAP and attending daily restart assessment panel meetings
during which licensee management discussed the status of RAP action items, the
inspectors determined that the RAP and its implementation were appropriate to
address the root causes listed above. The inspectors independently evaluated
licensee implementation, validation, and oversight for the various RAP action items.
Inspector assessment of several RAP action items associated with maintenance or
training are being documented in NRC Inspection Report Nos. 50-334(412)/98-301.
Additional selected inspectors observations are listed below.
RAP Action items S-3. 0-5: TS Compliance
The inspectors reviewed the licensee's root cause analysis and corrective actions
for the programmatic weakness concerning TS compliance. The root cause analysis
was thorough and determined that weaknesses existed in personnel knowledge of
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7
TS, as well as management expectations regarding TS compliance. The inspectors
determined that the scope and implementation of the RAP, combined with station-
wide TS compliance training appropriately addressed the TS compliance issue prior
to Mode 4. Additionally, the Independent Safety Evaluation Group was assigned
the future task of performing an effectiveness review to determine if corrective
actions ht v 5een effective in eliminating TS compliance problems.
RAP Action items P-1. P-2. P-4: Procedures
The inspectors reviewed the licensee's process for ensuring that all necessary
procedure revisions were completed prior to Mode 4. These plans were
appropriately supervised and executed. The inspectors verified that the revisions
were completed by reviewing a representative sample of revised procedures.
Additionally, the inspectors verified that the procedure review and approval process
was revised to ensure that all future procedure revisions were in compliance with
TS. This revision required additional reviews, including a 10 CFR 50.59 applicability i
review for all procedure revisions. The inspectors concluded that these changes
were appropriate to ensure that safety related procedures received the proper level
of review.
RAP Action items S-8. M-3: Condition Reports. Problem Reports, Desian Chanaes
The inspectors reviewed DLC's process for reviewing condition reports, problem
reports, design change packages and corrective actions prior to ascension to Mode
4, and interviewed associated managers to determine the extent and adequacy of
the process. The inspectors con::luded that DLC's efforts were methodical,
thorough, and received the appropriate level of management attention.
RAP Action item M-10: Open Enaineerina Memorandum (EM) Backloa
The inspectors reviewed the actions that were performed to determine if any open
ems constituted a TS operability challenge. The inspectors reviewed the open EM's
list, reviewed a sample of safety related systerns' ems, interviewed three system
engineers and reviewed the documentation prepared for this issue. The inspectors
noted that system engineers had included a review of open ems on their system
health reviews, and that adequate focus was given to the potential aggregate
effects of the issues on their assigned systems. The inspectors concluded the
actions, reviews, and documentation were adequate.
RAP Action item P-17: System Recovery to Ensure Adeauste Fillina & Ventina Of
Systems
The inspectors reviewed the actions performed to ensure adequate filling and
venting of systems prior to returning to service. This action was assigned to
prevent water hammer or gas binding events, such as those previously identified on
the quench spray, high head safety injection, and low head safety injection
systems. The inspectors interviewed the responsible program manager, and
reviewed applicable documentation including training requirements. The inspectors
noted that adequate measures were in place to ensure that draining requirements
were identified in the work package, and that an Operations Department Stai.Jard
had been developed to require filling of drained systems as part of the system
clearance restoration process. Additionally, the licensee has implemented a
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8
I
comprehensive void monitoring process, which included procedures and periodic
ultrasonic testing (UT) for void monitoring and prevention. The inspectors
determined that these actions were appropriate to resolve the concern for presence
of gas in safety related systems.
RAP Action item P-26: Troubleshootina Process.
The inspectors reviewed the actions to ensure that troubleshooting activities were
appropriately recognized, prioritized, and tracked to a timely closure. The licensee
developed a new procedure to provide administrative instructions for tracking the
removal of equipment from service and the return equipment to service following
testing or repairs. The procedure revision also included provisions to identify
affected departments and responsible individuals. Additionally, the procedure
established requirements for data collection for root cause analysis, and provided
guidance for definitions of risk levels involved with troubleshooting and established
management approval requirements based on risk. Administrative actions were in
place to ensure that the Equipment Out-Of-Service Form was attached to any
maintenance work requests (MWR) generated for troubleshooting activities, and to
ensure that the MWR remained the controlling document. The inspectors observed
portions of two troubleshooting activities during Unit 1 power ascension. Both
activities were properly controlled. The inspectors concluded that the licenseo
implemented adequate actions to enhance the overall effectiveness of the
troubleshooting process.
RAP Action item P-5: Timeliness of Operability Determinations
On several occasions during the past year, operations department personnel failed
to evaluate degraded conditions in a timely manner. To ensure operability
assessments were timely and conservative, BVPS recently developed Appendix E,
" Operable / Operability Determination of Systems, Structures and Components
(SSC)s," to operation's procedure 1/20M-48.1.1" Technical Specification
Compliance." The new appendix contained guidance that reflected current industry
practice regarding how the operability of equipment was determined and assessed.
For example,1/2OM-481.1 indicated the timeliness of operability determinations
should be commensurate with safety significance. To assess safety significance,
the originator of the operability assessment was instructed to use the allowed
outage times contained in TS. Additionally, consistent with industry practice,
1/2OM-48.1.lindicated equipment operability was dependent on the availability of
support systems.
Training on the new appendix was accomplished by providing a " Required Reading"
package to operation's personnel. BVPS reinforced the training by providing
classroom instruction, and a written test administered during the licensed operator
requalification training program. At the close of the inspection report period, all
licensed operators and licensed operator candidates had completed the required
training. The inspectors determined that Appendix E of 1/20M-48.1.1 provided
adequate guidance to assess the operability of equipment. The training provided to
operators on the new appendix was thorough. Quality Services Unit personnel
identified deficiencies in operations personnel awareness of the new process
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9
following training and appropriately raised this issue to station management for
action.
RAP Action items P-24, P-25: Enaineerina Review and Analysis of Technical
Specification Related items
Between 1994 and 1998 the licensee failed to implement appropriate administrative
controls or requested license amendments for several design issues as discussed in
Section E8.1. Most of these issues were originally processed using technical
evaluation reports (TERs) or ems. As corrective action, the licensee revised NEAP
2.13, " Technical Evaluation Reports," Rev. 5, and NPDAP 2.4, " Engineering
Memoranda," Rev. 7, to ensure that questions or issues associated with compliance
to TS were appropriately recognized, prioritized, and tracked. The revisions
emphasized the need for the preparers of ems and TERs to complete timely reviews I
of issues, which could affect the plant design basis or TS. Further, these changes I
reinforced the need for the preparers of ems and TERs to consider how the analysis
conclusion could affect the plant design basis.
For example, NPDAP 2.4 required the preparers of TERs, to assign a priority code of
one, the highest priority, for evaluations which were needed to determine if the
plant met TS or Updated Final Safety Analysis Report (UFSAR) requirements.
Similarly, procedure NEAP 2.13 indicated, when ems were prepared, evaluators
should consult the TS and UFSAR and determine if the plant design basis needs to
be changed by preparing a safety evaluation.
Based on interviews and reviewing the recent procedure revisions, the inspectors I
determined that NPDAP 2.4 and NEAP 2.13 provided sufficient instruction for ;
engineers to ensure TS and UFSAR related issues are recognized and adequately I
resolved during the preparation of ems and TERs.
RAP Action item M-8: Temporary Modification Review
The inspectors conducted a review of temporary modifications (TMs) to determine if
TMs individually or collectively represented a challenge to safe operation of Unit 1
or could violate plant TS As on July 28,1998, there were seven TMs installed on J
Unit 1. None of the TMs compensated for the loss of risk significant equipment or
violated plant TS. The inspectors determined that the number and content of the
TMs was reasonable.
RAP Action item P-12. Manaaement Response Team
The inspectors reviewed the charter and implementation of the management
response team (MRT). The MRT charter was completed and contained sufficient
details to properly implement the team. The inspectors questioned whether training
was provided for each MRT member as stated in the restart action plan description.
The plant manager stated the training for MRT members and nuclear shift
supervisors would occur after completion of the item but prior to Mode 4 entry.
The training was conducted and the MRT properly established prior to Mode 4
entry.
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10
M-5. M-6. Review of Operator Workarounds and Control Room Deficiencies
The inspectors reviewed the Unit 1 operator workarounds and control room
deficiencies to independently assess the impact on the operators. The inspectors
determined that the operator workarounds and control room deficiencies did not
adversely affect operation of the facility. However, the inspectors identified several
additional control room deficiencies that were not currently being tracked. The end
result is these items did not receive the higher priority that control room deficiencies
normally receive. The licensee assigned the fix-it-now manager as the owner of the
control room deficiency list to address the inspectors' concerns. Senior
Management conducted similar control room inspections and identified deficiencies
not tracked on the control room deficiency list. At the close of the report perbd,
the control room deficiency list had been properly updated with work priorities
assigned for each item.
!
RAP Action item B-8: Cumulative Unit 1 Basis for Continued Operation (BCO)
Review
Thirteen BCOs were written prior to restart to assess degraded or non-conforming i
Unit 1 conditions. The inspectors reviewed each BCO and attended the NSRB l
meeting at which the cumulative affect of the BCOs was discussed. The inspe.: tors 1
determined that the rationale for each BCO was technically sound with appropriate
compensatory measures implemented when necessary. The established time limit
for each BCO to be in effect was appropriately developed based on risk insights. ,
Reactor operation with the 13 BCOs in effect did not pora a challenge to reactor i
safety.
i
RAP Action items O-3. O-4: Onsite Safety Committee (OSC) and NSRB Oversicht
The Unit 1 restart manager prepared a restart readiness report listing the status of
each action item and presented the report to the OSC and NSRB prior to Mode 4.
The inspectors observed OSC and NSRB oversight activities, including action
validations and reviews of the report. The inspectors determined that the OSC and
NSRB members demonstrated a questioning perspective throughout their oversight
activities. Following resolution of their questions, both the OSC and NSRB
recommended to the plant manager that the unit was ready for Mode 4 and
subsequent recommendations for power ascension.
c. Conclusions
The licensee developed and implemented a Unit 1 Restart Action Plari (RAP) to
provide assurance that known conditions adverse to quality were corrected and that
personnel, processes, and equipment were ready for unit restart. Corrective actions
to address weaknesses in Technical Specification (TS) compliance were
comprehensive. The RAP and its implementation were appropriate to address the
root causes for the extended forced unit outage.
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08 Miscellaneous Operations issues
08.1 Insoector Review of Indeoendent Plant Assessment (71707) !
The Industry of Nuclear Power Operations (INPO) performed an independent plant
assessment in August 1997. The INPO assessment findings were documented in
an interim report in October 1997, and a final report issued in May 1998. The
inspectors reviewed the interim report upon issuance, and reviewed the final report ;
during this report period. The inspectors determined that the INPO plant I
assessment findings were consistent with the performance assessments contained I
in the NRC inspection reports for 1997. No additional NRC regional follow-up j
inspection is planned. l
11. Maintenance
M1 Conduct of Maintenance i
M 1.1 Modification to Unit 1480 Volt Emeraency Bus Under Voltaae Relav Scheme.
a. Insocction Scooe (62707)
The inspectors observed partial performance of design change package (DCP) 2336,
" Unit 1480 Volt Emergency bus Under Voltage Relay Scheme." The inspectors
also observed the infrequently performed tests and evolutions (IPTE) briefing in
accordance with (iaw) site procedure NPDAP 8.23, " Infrequency Performed Tests or
Evolutions," Rev. 3.
b. Observations and Findinas
The IPTE briefing was professional and thorough with the exception that lessons
learned from industry operating experience were omitted. The inspectors
questioned the responsible test manager (RTM) about the omission. The RTM
indicated that he did not have sufficient tirne to obtain any lessons learned
information for the briefing. The IPTE briefing was performed in the control room
just prior to the normal shift briefing. This disrupted the normal shift briefing which
occurred later and with limited shift participation as the crew members with
assignments frorn the IPTE briefing had left to perform their tasks. Both of these
minor issues have been communicated to Operations management.
The temporary operating procedure (TOP); 1 TOP-98-05, was written for installation
of the new relays. The inspectors determined the TOP was complete and accurate
for the work activity being performed. The installation and testing of the new relays
was performed iaw DCP 2336. The DCP involved replacing the 480 volt
undervoltage (UV) relays and relocating the relay's sensing location from the ground
detection potential transformers (pts) to the load pts. The DCP also modified the
wiring of the switch gear to include a " pallet" switch to defeat the UV application of
I the relay when the bus supply breaker is open or racket out. The relay crew spent
the previous week familiarizing themselves with the DCP and were knowledgeable
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of the work being performed. The inspectors observed selected portions of the
relay installation and testing and determined the work was properly performed law
the approved DCP. Lifted leads were properly identified,-the work area was clean
and uncluttered, and mobile work carts were properly secured.
The lead technician, in removing a cabi..et panel for access, identified that it was ;
missing all of its fasteners. He promptly notified his supervisor who initiated a
condition report and MWR to replace the missing fasteners. Other motor control
center panels in both safety divisions were checked and a few missing fasteners ,
were identified and replaced. l
c. Conclusions
A design change to modify the Unit 1480 Volt emergency bus under voltage relay
scheme was implemented correctly. The maintenance personnel performing the
work were knowledgeable and appropriately briefed. Missing motor control center
panel fasteners were identified by the maintenance crew and properly dispositioned
by the site staff. The infrequently performed test or evolution briefing was i
professional, notwithstanding two minor deficiencies. l
!
M1.2 Imorocer Resoonse to Unit 1 Excessive Turbine Driven Auxiliarv Feedwater (AFW)
Pumo Packina Leakaae
a. Insoection Scope (61726)
The inspectors observed the partial performance of 1-OST 24.9, " Turbine Driven
AFW Pump (1-FW-P-2) Operability Test," Rev.19. including observation of the
outboard pump packing leak and corrective measures implemented.
- b. Observations and Findinas
On August 8, the inspectors observed, during the performance of 1-OST 24.9, a
packing leak on the turbine driven AFW pump consisting of both water and steam
vapor. The pump was in service and performance engineers were obtaining
temperature readings from both the inboard and outboard shaft area. The ;
performance engineers requested maintenance personal to assist in assessment of
the leak. The maintenance supervisor who arrived to support the leak assessment
immediately commenced to open the packing stuffing box supply valve. This is
contrary to the requirements of station procedures 1/20M-48.3.D," Equipment
Administrative Control," Rev.18, which states that permanently installed valves
and equipment will only be operated by personnel of the BVPS Operating Group,
and Maintenance Programs Unit Administrative Manual (MPUAM) Section 4.2,
" Work Order Control," Rev. 7, which states that plant equipment shall not be
manipulated unless procedurally enntrolled by an approved work procedure, a
clearance or a caution tag.
The nuclear operator (NO) supporting the test in the field did not attempt to stop the
maintenance supervisor from manipulating the valve or subsequently adjusting the
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13
packing gland nuts. During the performance run, no operations supervision
observed the leak for assessment purposes. The inspectors determined that
inadequate command and control of this evolution contributed to the maintenance
supervisor's actions.
After three adjustments to the packing supply valve failed to make any improvement
in the leak and steam plum, the maintenance supervisor obtained a pipe wrench that
was lying on the floor and applied torque to the packing gland nuts. This action
was contrary to the requirements of MPUAM Section 4.2, which states that "all
Maintenance related activities to be performed (including troubleshooting) SHALL be
clearly defined by a work order control document..." No change in steam vapor
leakage rate resulted from this action and the pump was subsequently shut down
and later repacked.
The inspectors discussed the two apparent inappropriate actions with the
maintenance supervisor immediately after the event. The supervisor explained that
he took the immediate actions that he did because of his concern for the health of
the pump shaft. The inspectors noted that performance engineers had been
monitoring temperature readings on the pump and were satisfied that the packing
seat-shaft was not overheating. However, the maintenance supervisor didn't
property resolve his concern with the NO or the performance engineers prior to his
actions. These actions by the maintenance supervisor, represented a continuance
of human performance errors as documented in NRC Integrated Inspection Report
Nos. 50-334(412)/98-03.
The inspectors determined that a maintenance supervisor failed to adhere to site
procedures while investigating excessive turbine driven AFW pump packing leakage.
These actions delayed restoration of the safety related pump by twenty-two hours.
The licensee was slow to enter this event in their corrective action program as it
took three days for a condition report to be written. Failure to properly implement
1/20M-48.3.D and MPUAM Section 4.2 violated T.S. 6.8.1.a , which requires that,
" written procedures shall be established, implemented and maintained covering...
the applicable procedures recommended in Appendix "A" of Regulatory Guide 1.33,
Rev. 2, February 1978." (VIO 50-334/98-04-01)
Other portions of the test included observations by the inspectors of the reactor
operator (RO) initiating the surveillance. The operator was knowledgeable of the
test and when he became aware that he could not concurrently start the test and
time a relay needed for the procedure, he appropriately requested a second operator
to provide assistance.
c. Conclusions
, Human performance errors continued to impact plant operations. Maintenance
l personnel failed to adhere to procedures for configuration control and work control
when attempting to resolve excessive packing leakage on the Unit 1 turbine driven
auxiliary feedwater pump. These actions delayed pump restoration by twenty-two
j hours.
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M1.3 Beaver Vallev Fix-It-Now (FIN) Maintenance Process
a. Insoection Scooe (62707)
The FIN team maintenance process was established to enable workers to complete
minor maintenance items more quickly with less administrative controls than are in
place for larger maintenance items. The licensee has recently proposed revisions to
the FIN process to permit the FIN team to perform additional emergent work items
and thereby reduce the adverse impact that emergent work has on scheduled
maintenance activities. The inspectors reviewed various documents, conducted
interviews, and observed FIN team maintenance activities to assess FIN team
effectiveness.
b. Observations and Findinas
The FIN team maintenance process, procedure guidance, daily meetings and plant
work activities were reviewed by the inspectors. The FIN process written procedure
guidance was referenced in the Maintenance Programs Unit Administrative Manual,
section 4.11, "Fix-It-Now Maintenance Program," Rev 4. The procedure contained
a basic description of the FIN process and contained clear examples of the work
activities that were allowed and not allowed to be performed by the FIN team. The
FIN program implementation was relatively new at Beaver Valley and additional
program enhancements were planned at the time of the report period end date. The
proposed changes were intended to improve the FIN team effectiveness and time
efficiencies.
A daily 9:30 a.m. meeting was held in the FIN work area to review the prior day's
work request tags. The review evaluated each equipment deficiency for the proper
work priority and applicability for FIN work. The FIN team selected work tasks that
were a priority 3 or lower work request, minor maintenance items, jobs with a
duration of 2-3 hours, and short term TS LCO work. Currently the FIN teams do not
work on safety related, EQ, or Appendix "R" work request items.
The inspectors observed FIN team mechanical maintenance personnel during the
performance of four maintenance work request (MWR) job tasks. The jobs were
pre-planned and signed on by the work control senior reactor operator. Radiological
control personnel reviewed the MWRs and coordinated the assistance from a
radiological controls plant technician. The mechanics assembled all of the
equipment and materials to perform the job. The work included the cleaning and
inspection of boric acid leaks on four primary plant motor operated valves. The
mechanics work performance was methodical and good self checking and
radiological control practices were noted. l
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c. Conclusions
The Fix-it-Now (FIN) team current work scope and volume was relatively low. FIN
team maintenance work performance was methodical and good self checking and
radiological control practices were noted.
M1.4 Check Valve Maintenance
a. Insoection Scope (62707. 37551)
In response to weighted arm check valve issues at Unit 2 (see Section E1.1), the
inspectors observed disassembly of 2 SIS *42, examined various disassembled check
valve components and interviewed mechanical maintenance technicians and vendor
representatives.
I
b. Observations and Findinas '
The maintenance was conducted in accordance to maintenance work instructions.
Maintenance workers were generally knowledgeable on the work requirements and
the check valves design. Radiological controls were followed by the maintenance
crews. Radiological controls personnel provided good support. Problems in the
field were properly handled with good supervisor and vendor support. !
c. Conclusions
Maintenance on safety related check valves to correct a motion binding issue was ;
properly performed and supervised.
Ill. Enoineerina
E1 Conduct of Engineering
i
E1.1 Check Valve Bindina
a. Inspection Scoce (71707. 37551. 92902. 92700)
The inspectors reviewed licensee's actions in response to binding of various
containment isolation check valves. The inspectors reviewed surveillance tests,
examined check valve components after disassembly, and interviewed system
engineers, mechanical maintenance technicians, and vendor representatives. The ;
following procedures were reviewed: !
- 1/2 CMP-75-ATWOOD CHECK-1M, " Repair of Atwood & Morrill Bolted
Bonnet Backweighted Check Valves," Rev. 3
- 2BVT 1.47.11, " Safety injectior, and Charging System Containment
Penetration Valve Integrity Test," Rev. 4
- 2BVT 1.47.5, " Type C Leak Test," Rev. 4
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16
- 2BVT 1.47.3, " Containment Isolation Check Valves Test," Rev. 2
- 20ST 11.16, " Leakage Testing RCS Pressure isolation Valves," Rev.10
b. Observations and Findinas
On April 1,1998,2OSS*3 was found to be binding through its entire stroke and
would remain open when released from any open position. The licensee identified
that increased breakaway torques were experienced for several other check valves.
2 SIS *42 had failed its torque test earlier in 1998 and was disassemb!cd and
overhauled. During testing 2 SIS *46 failed to open with 350 ft-lbs, and corrosion
residue was found in this valve. Additional valves also required higher than normal
torque values to stroke the valves. Separately, a system engineer identified three
valves (2 SIS *84,2 SIS *94,2 SIS *95)that had stuck in the open position after the
high head full flow test. The combination of these events resulted in extensive
review of the susceptibility of weighted arm check valves to binding and the
possibility of a common mode failure mechanism.
The licensee identified that the primary contributor to the binding was that the shaft
and o-ring bushings experienced excessive corrosion in a borated water
environment. The licensee attributed this failure mode to improper material
selection for the bushing material. Additional problems identified included: 1)
alignment and clearance problems,2) non-ideal shaft material selection; 3) o-ring
seat design inadequacies; 4) improper disk stop design; 5) degraded o-rings; and 6)
improper angle to vertical of the weighted arm (when the valve is full open). The
evaluation of degraded o-rings and the angle for the weighted arm was ongoing at
the close of the inspection period.
In response to the above issue, the licensee planned to inspect, modify, and test all
thirty-three weighted arm check valves of this design. The list of valves consisted
of Unit 2 high head safety injection, safety injection, recirculation spray, quench
spray, fire protection valves and Unit 1 fire protection valves. Twenty-two of the
Unit 2 valves are containment isolation valves and required operable per TS 3.6.3.1.
The modifications included replacement of the shaft and o-ring bushings with a
materialless susceptible to corrosion in a boric acid environment. Additional
changes included shaft materialimprovements, o-ring seat design changes, weld
buildups on the disk stops, and alignment and clearance changes. The licensee also '
plans to evaluate the preventive maintenance tasks for the check valves. The
inspectors noted that the root cause analysis was not completed at the end of the ;
inspection period, but the licensee analysis to date was generally thorough and
corrective actions were extensive. Additional problems encountered during the
inspection and repair of the check valves were appropriately addressed. Quality
Services Unit (OSU) personnel provided timely assistance by identifying quality
deficiencies at the vendor's facilities. The inspectors observed selected
maintenance activities (see Section M1.1).
System engineers reviewed past performance and identified that the binding issue
existed since 1992 and possibly earlier. Initial corrective actions were to replace j
'
and lubricate the check valve bushing o-rings on an increased frequency. In 1995
l
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and 1996, the licensee identified that five check valves failed to close under the
weight of its own weight arm (2OSS*3,2OSS*4,2 SIS *42,2 SIS *47, and
2CHS*472). In response to these issues, the licensee identified possible causes as
o-ring bushing corrosion deposits and incorrect shaft clearances. Corrective action.s
identified included replacement of the o-ring bushings with new materials. The
corrective actions to address the root cause identified in 1996 were not planned
and scheduled until after the additional failures occurred in 1998.
Upon reviewing the previous material history, the inspectors determined that
previous licensee causal analysis and corrective actions were incomplete. Valve
opening breakaway torque on several valves, including 2 SIS *46 and 2 SIS *47 was
not sufficiently evaluated to identify an increasing trend and support development of
focused corrective actions prior to their failure during the current outage.
10 CFR 50, Appendix B, Criterion XVI, requires that measures shall be taken to
promptly identify and correct conditions adverse to quality. The failures identified in
1996 were not fully evaluated and associated corrective actions were not
implemented in a timely manner. The incomplete corrective actions contributed to
multiple valve failures in 1998, and represented a violation of 10 CFR 50, Appendix
B, Criterion XVI. During the current outage, the licensee identified the valve
f ailures, identified additional causal factors, and initiated extensive corrective
actions. The inspectors determined that the safety significance was low due to
redundant, diverse isolation valves for each of the check valves affected. This non-
repetitive, licensee-identified, and corrected violation is being treated as a Non-Cited
Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV
50-334(412)/98-04-02).
The inspectors reviewed the licensee event report (LER) for the common mode
failure of containment isolation check valves. The licensee described the issue, root
causes, and corrective action. The inspectors observed minor discrepancies
including additional failures and causal factors that were not described in the LER.
The issues were brought to the licensee attention and appropriate action taken. The
LERs (98-22-00 and 98-22-01) are closed.
c. Conclusions
The licensee identified binding issues associated with thirty Unit 2 check valves.
Causal analysis for this issue during the last refueling outage was incomplete, which
contributed to several additional failures occurring during this outage. Although the
valves affected multiple safety systems, the safety significance was low due to
redundant, diverse isolation valves for each of the check valves affected. Licensee
investigation, root cause analysis, quality controls, and corrective action during this
period were comprehensive.
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E2 Engineering Support of Facilities and Equipment
E2.1 Unit 1 System Health Reviews for Restart
a. Insoection Scope (37551. 71707)
The inspectors independently reviewed applicable documentation, held individual
interviews with three system engineers, and their managers, and verified completion
of activities on a sample basis to determine whether the licensee had properly
evaluated system readiness for unit restart.
b. Observations and Findinas
The inspectors determined that System and Performance Engineering Department
(SPED) personnel developed a systematic and comprehensive process to evaluate
system status and readiness. The inspectors verified that safety related systems
were included in the evaluation. SPED management participated in individual
system health review meetings with the system engineers The reviews were based
upon system walkdowns combined with aggregate assessment of all activities
which could potentially affect system performance. These activities included
operational concerns and workarounds, maintenance work requests, open
engineering memorandums, temporary modifications, open design change requests,
condition reports, equipment out of service logs, deficiency tags, and caution tags.
The three system engineers interviewed were knowledgeable on their specified
systems and were consistent in their implementation of the required system health
reviews.
Adequate documentation and record keeping of system health reviews were also
observed. Operations department personnel performed an independent system
health assessment which was a beneficial complement to the reviews performed by
SPED personnel. The inspectors observed that the results of the system health
reviews were clearly presented to the NSRB. During this inspection the inspectors
questioned the current methodology used by instrumentation and control
technicians to calibrate the lead / lag or rate lag circuits of the reactor protection
system channels. The licensee discussed the issue knowledgeably and initiated EM
116752 to further evaluate this issue.
c. Conclusions
System and Performance Engineering Department (SPED) personnel developed a
systematic and comprehensive process to evaluate system status and readiness.
System engineers were knowledgeable and consistent in their implementation of the
required system health reviews, providing appropriate recommendations to station
management regarding readiness for Unit 1 restart. Insights gained during the
system health reviews were properly shared with appropriate departments for
implementation.
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19
E8 Miscellaneous Engineering issues (90712,92700)
E8.1 (Closed) eel 50-334(412)/98-03-05: Failure to implement Adequate Administrative
Controls and Submit TS Amendment Requests for Conditions Outside of Station
Accident Analysis
a. Inspection Scope (37550,37551)
In response to NRC Violation 50-334(412)/98-01-03the licensee conducted a
detailed extent of condition review and identified 14 additional issues for which the
current technical specifications (TS) were non-conservative with respect to the
station (s) design basis. The largest issue involved reactor protection system (RPS)
and engineered safety feature (ESF) allowable actuation values. The licensee l
evaluated each issue, made operability determinations, applied associated l
compensatory measures, and began preparation of TS amendment requests where j
they determined one was needed. The inspectors independently reviewed station {
records, interviewed personnel, and evaluated system operability to determine that ;
safety significance of the issues.
b. Observations and Findinas
lhe inspectors reviewed each of the 14 issues in detail, including assessment of
associated licensee operability evaluations, position papers, and basis for continued
operation (BCO) documents. In each case, using NRC Generic Letter 91-18,
information to Licensees Regarding NRC inspection Manual Section on Resolution
of Degraded and Nonconforming Conditions", Rev.1, the licensee determined that
no TS amendment was needed prior to unit restart. A selected group of the issues
is discussed below:
RPS/ESF TS Setooints end Allowable Values
in 1994, the licensee conducted a technical review of the RPS and ESF actuation
system instrumentation trip setpoints. This initiative was conducted to ensure that
plant specific documentation was correctly reflected in the design analysis, address
several generic industry issues, reflect protective equipment replacements, and
include vendor specification changes. The results of this review identified that
some TS trip setpoints and allowable values were not conservative. The inspectors
confirmed that in 1994, the licensee revised the calibration surveillance procedures
to reflect the new trip setpoints. However, in approximately 20 instances
(documented in NRC IR Nos. 50-334(412)/98-03),where the original trip setpoints
were acceptable and only the allowable values required revision, the new allowable
values were not properly incorporated into the surveillance procedures. The failure
to incorporate the allowable values in the surveillance procedures was caused by a
combination of weak administrative controls and poor verification by engineering
personnel and procedure writers to ensure that the procedures were appropriately
revised.
,
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20
Failure to revise the surveillance procedures affected the licensee's ability to
determine if the as-found setpoints had changed to an extent where the channel
was inoperable and potentially reportable to the NRC. However, since the setpoints
in the surveillance procedures were appropriately revised in 1994, the as-left trip
setpoints were not affected. Therefore, the safety significance for the failure to
appropriately include the new allowable values into the test procedures was low, in
addition, the licensee reviewed the as found surveillance test results dating back to
1994 to determine whether the failure to revise the allowable valves had resulted in
inappropriate operability determinations. This review determined that the affected
instrumentation was never inappropriately declared operable. Therefore, there was
no adverse safety consequence as a result of the failure to update the allowable i
values in the surveillance procedures. The inspectors independently reviewed I
maintenance history records and concluded that the failure to implement the correct I
allowable values did not result in a reportable event.
Upon identification, the surveillance test procedures were revised to reflect the
appropriate allowable values. The inspectors verified that the procedures were j
appropriately revised. The licensee implemented several additional corrective '
actions including the development of TS amendment requests, BCOs (until a TS
amendment is approved), implementation of plant design changes where needed,
and improving administrative procedures to prevent recurrence. The inspectors
determined that the Unit 1 BCO for the RPS/ESF issue was technically sound. The
Unit 2 BCO remained under development at the close of the inspection period.
Dynamic Time Constants for RPS Setooints
The licensee identified an issue regarding the use of dynamic time constants in Over
Pressure delta Temperature, Over Temperature delta Temperature, and Low
Pressurizer Pressure RPS trip functions. TS state that the time constant used will ,
equal an exact time in seconds (e.g. T1 = 30). The installed plant equipment is not !
capable of meeting an exact equality value. As manufactured, the equipment has f
an inherent accuracy band (e.g. T1 =30 +/- 10%). UFSAR Accident analysis used ;
the exact T1 value without allowing margin for the + /- accuracy band.
I
Beaver Valley engineers, with assistance from the Nuclear Steam System Supplier
recently performed new calculations which demonstrated that the plant can operate
with the +/-10% time constant band and remain within UFSAR analysis. The l
licensee generated a position paper which demonstrated that this issue was not a
safety issue. The inspectors reviewed the position paper and agreed that the issue
does not pose an adverce safety concern. But the TS still specified an exact time !
constant value, in lieu of a tolerance range, which the plant does not meet.
Following NSRB review of the approved position paper, the licensee planned to
await the improved Standard TS project to revise the TS. The inspectors informed
the licensee that this corrective action would be untimely. In response, the licensee
revised their schedule to submit a TS amendment request in the next two to three
months to correct this problem. At the close of this report period the proposed TS ;
amendment request had been presented to the OSC and was being properly tracked l
for accountability.
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BVPS-1 EDG Freauency Tolerance Discrepancy
CR 980569 noted that TS 4.8.1.1.2.a.5 was non-conservative in that this TS
required the output frequency of the EDGs to be within 2% of 60 hertz, while
design analysis 8700-DMC-3072 assumes a frequency range of only 1% based
on high head safety injection (HHSI) pump operation during safety injection. The
speed of HHSI equipment (pumps and motor operated valves) is affected by the
EDG generator frequency during an accident. CR 980569 noted that exceeding the
1 % frequency specified could result in a run-out condition of the HHSl pumps. CR
980569 also noted that although the analysis stated that this 1 % frequency
would be administratively controlled by the OSTs, the applicable OSTs did not
provide sufficient administrative controls. Therefore, DLC created an administrative
insert for the TSs which specified the 1 % frequency limit and initiated j
appropriate revisions to 10ST-36.3 and 10ST-36.4, respectively. The inspectors
reviewed the proposed changes to these OSTs and concluded that these
administrative controls were adequate for plant restart prior to receiving a TS
amendment.
1
In each case, the licensee identified the discrepancy and initiated appropriate I
corrective actions. During this inspection period, additional non-coriservative TS for
which the licensee had either failed to implement appropriate administrative controls
or failed to submit a TS amendment included:
l
- BVPS-1 Emergency Diesel Generator (EDG) Largest Single Load Rejection
Test
- Refueling Water Storage Tank Level
- EDG Fuel Oil Storage Tank Level
As discussed above and in NRC IR 50-334(412)/98-03,ections to resolve technical
design issues as described in this section, from approximately 1994 to 1998, were
inadequate in that station design was not properly maintained, conditions adverse to
quality were not fully corrected in a timely manner, and TS were not properly
maintained. These were violations of 10 CFR 50, Appendix B, Criterion lli " Design
Control" and Criterion XVI " Corrective Actions," and 10 CFR 50.36(b). The
inspectors determined that, in response to NRC Violation 50-334(412)/98-01-03,
the licensee performed an appropriate extent of condition review, identified
pertinent design issues, performed technically sound operability assessments and
BCOs, and put appropriate administrative controls in place for Unit 1. Appropriate
actions were initiated using the licensee condition report system for Unit 2. The
root causes for the violations listed in this section are similar to the causes for the
original violation. The collective safety significance of the additional design issues
was low, and based on material history reviews, there was no adverse safety
consequence. This non-repetitive, licensee-identified, and corrected violation is
being treated as a Non-Cited Violation, consistent with Section Vil.B.1 of the NRC
l Enforcement Policy. (NCV 50-334(412)/98-04-03).
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c. Conclusions
in response to an NRC violation, the licensee performed an extent of condition
review which identified numerous design issues for which the TSs were non-
conservative. Appropriate corrective actions including interim administrative l
controls, development of TS amendment requests, and process revisions to ensure l
the facility is operated within its design basis were established. Interdepartmental l
coordination and the quality of engineering work to resolve the issues were
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excellent. The safety significance of the design issues was low and the licensee !
correctly determined that Unit 1 could restart prior receiving TS amendment
approval from the NRC for the subject issues.
1
E8.2 (Closed) LER 50-412/97-011: Inadequate Electrical isolation in Secondary Process
Rack Circuitry Due to Design Error.
The inspectors conducted an in-office review of the LER. The issue was
documented in NRC Inspection Report 50-334(412)/98-80and resulted in an NCV.
The LER properly described the event. The root cause evaluation and corrective
actions were comprehensive. No new issues were identified in the LER.
IV. Plant Support
R1 Radiological Protection and Chemistry (RP&C) Controls
a. Insoection Scope (83726)
The inspectors reviewed the programs for: (1) control of radioactive materials; (2)
maintaining occupational exposures as low as is reasonably achievable (ALARA);
and, (3) personnel radiation exposure records.
Areas reviewed under control of radioactive materialincluded transport of
potentially contaminated tools and equipment within the radiologically controlled
area (RCA), examination and free release of tools and equipment from the RCA, and
documentation of spills or other unusual occurrences involving the spread of
contamination in and around the facility, in accordance with 10 CFR 50.75(g)(1).
This review was conducted by examination of records, interviews with plant
personnel, and direct field observations.
Areas reviewed under ALARA included preparations for steam generator inspections
at Unit 2, installation and tracking of shielding packages in the RCA, and tracking of
hot spots. This review was conducted by examination of records and interviews
with plant personnel.
Areas reviewed under personnel dosimetry records included maintenance of NRC
required record forms, annual and special whole body count records and termination
records. This review was accomplished by examining a random sampling of
records, including records for current and former radiation workers, both licensee
employees and contractors.
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l b. Observations and Findinas !
Control of Radioactive Material
The program for control of radioactive material, especially potentially contaminated
l materials, was conducted in accordance with licensee procedures (HP Manual,
Chapter 1, Part lil, " Contamination Control", Rev. 2; RP 3.4, " Handling Radioactive
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Material," Rev. 5; and RP 3.5, " Removing Material From an RCA," Rev. 0). The
two RP procedures were undergoing significant revision at the time of this
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inspection, with Health Physics Manual Change Notices (HPMCN) issued for each.
These changes were made to clarify that numericallimits listed in these procedures
for the free release of materials from the RCA were minimum detection limits and
not release limits. I
Equipment stored in support of radiological work, especially for refueling outages,
were placed at the Shippingpert Atomic Power Statioa (SAPS) warehouse. This I
material is generally contaminated, with limitations for storage based on direct
radiation levels on packages and on the aggregate radiation level seen at the
- warehouse fence line. The licensee does not have a hot side tool storage facility.
Consequently, during outages, large numbers of hand tools are required to be
surveyed out of the RCA on a daily basis. The licensee is currently considering the
establishment of a contaminated tool facility inside of the RCA to reduce the
potential for inadvertent release of contaminated tools from the RCA.
A " Green h Clean" program has been established to provide for the disposition of
non-radioacdve materials which are brought into the RCA. A number of containers
and postings are located throughout the RCA to support this program. Bags of
material from these receptacles are surveyed prior to removal from the RCA, then
transported to a vendor for sorting, item recovery and disposal. The licensee does
not directly release this material to the local landfill.
Records of spills and other occurrences made in accordance with 10 CFR l
50.75(g)(1) were maintained by the licensing department, based on information l
provided by health physics. At the time of this inspection, extensive records of two l
areas outs;de the RCA where contamination has occurred have been maintained.
These areas (near the Unit 1 river water pipe and by LW-TK-7A/78) were identified
in 1994 and 1996 respectively. The records include documentation on the cause of
the contamination, remediation efforts undertaken, and residual contamination
remaining. Additionally, six other spills which occurred and/or were identified
during the 1970's and 1980's have also been documented. These records are not
as extensive, although post-remediation records do identify the level of residual
contamination. ,
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Maintainina Occuoational Exoosures ALARA
The program for maintaining occupational exposures ALARA includes processes and
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procedures to track hot spots within the facility and to provide shielding as a means
of reducing area ambient radiation dose rates. Hot spots, when identified, are
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documented and evaluated by the health physics staff and records of periodic
surveillances are maintained and trended. Health physics is also responsible for
.
identifying hot spots to be reduced in scope through engineering controls or
shielding. Shielding packages are prepared by health physics based on total job
work scope dose savings projections, and are placed in accordance with
specifications provided on a case-by-case basis by plant engineering.
Radiation exposure goals established for 1997 included an outage exposure goal of
201 person-rem for the Unit 1 rJueling outage (1R12). Total exposure for the
outage was 223.9 person-rem, which included significant expansion of the outage
scope and length. Although the exposure total exceeded the established goal, it
does represent the lowest refueling outage exposure total ever at Unit 1. Exposure
estimates for 1998 were based on a full operating year at Unit 1 and a month-long
refueling outage at Unit 2, r:either of which have occurred. The licensee is planning
to conduct steam generator inspections during August-September 1998, and has
written radiation work permits and ALARA reviews to support this effort.
Dosimetrv Records
The licensee maintained records of personnel exposures in accordance with 10 CFR
20.2106. A review of a random sampling of these records demonstrated that
appropriate records were being properly maintained. Records of external exposures,
potential internal uptakes, annual whole bcdy counts and other pertinent exposure
data were maintained by the dosimetry section of health physics. Termination
reports for workers no longer employed at Beaver Valley were available for review.
Instances where workers had terminated without having an exit whole body count
were documented, together with records demonstrating the attempts to contact
these workers.
c. Conclusions
..
The program for the control of contaminated materials and equipment was effective.
The licensee appropriately identified and maintained records of spills and other
occurrences as required under 10 CFR 50.75(g)(1).
, The program for identifying and tracking hot spots, and shielding to reduce
l occupational exposures was effectively implemented. The Unit 1 refueling outage
in 1997 (1 R12) was completed with the lowest total dose in unit history.
Records of occupational exposures were appropriately maintained in accordance
'
with 10 CFR 20.
R5 Staff Training and Qualification in RP&C
I a. Inspection Scone (83726)
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The inspectors reviewed the program for training radiation workers, including the
control of potentially contaminated materials. This inspection was accomplished by
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reviewing training records including lesson plans and handouts, and by attending
portions of the general employee training (GET) program, specifically the dress-
out/ mock-up facility training.
b. Observations and Findinos
All employees having access to the RCA are required, on an annual basis, to attend
GET and radworker training. As part of this three-day training program, workers
must successfully complete a mock-up training exercise in a simulated RCA.
Workers are graded on their ability to detect problems, respond to audible and visual
alarms, and to be able to safely enter, work, and then exit a posted contaminated
area,
c. Conclusions l
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The annual radworker training program, using a mock-up facility, was effective.
S1 Conduct of Security and Safeguards Activities
a. Insoection Scope (81700)
The inspectors determined whether the conduct of security and safeguards
activities met the licensee's commitments in the NRC-approved physical security
plan (the Plan) and NRC regulatory requirements. The security program was 1
inspected during the period of July 6-9,1998. Areas inspected included: access !
authorization program; alarm stations; communications; and protected area (PA)
access control of personnel and packages.
b. Observations and Findinos l
Access Authorization Prooram. The inspectors reviewed implementation of the
access authorization (AA) program to verify implementation was in accordance with
applicable regulatory requirements and the Plan commitments. The review included
an evaluation of the effectiveness of the AA procedures, as implemented, and an
examination of AA records for 17 individuals. Records reviewed included both
persons who had been granted and had been denied access. The AA program, as
implemented, provided assurance that persons granted unescorted access did not
constitute an unreasonable risk to the health and safety of the public. Additionally,
the inspectors verified, by reviewing access denial records and applicable
procedures, that appropriate actions were taken when individuals were denied i
access or had their access terminated. Those actions included the availability of a {
formalized process that allowed the individuals the right to appeal the licensee's !
decision.
Alarm Stations. The inspectors observed operations of the Central Alarm Station
(CAS) and the Secondary Alarm Station (SAS) and verified that the alarm stations
! were equipped with appropriate alarms, and surveillance and communications
capabilities. Interviews with the alarm station operators found them knowledge:, ole
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of their duties and responsibilities. The inspectors also verified, through i
observations and interviews, that the alarm stations were continuously manned,
independent and diverse so that no single act could remove the plants capability for
detecting a threat and calling for assistance, and the alarm stations did not contain
any operational activities that could interfere with the execution of the detection,
assessment and response functions. l
Communications. The inspectors verified, by document reviews and discussions
with alarm station operators, that the alarm stations were capable of maintaining
continuous intercommunications, communications with each security force member
(SFM) on duty, and were exercising communication methods with the local law
enforcement agencies as committed to in the Plan. I
Protected Area (PA) Access Control of Personnel and Hand-Carried Packaaes. On
July 7- 8,1998, the inspectors observed personnel and package search activities at
the personnel access portals. The inspectors determined, by observations, that
positive controls were in place to ensure only authorized individuals were granted
access to the PA and that all personnel and hand carried items entering the PA were
properly searched.
1
c. Conclusions
Security and safeguards activities were conducted in a manner that protected public
health and safety in the areas of access authorization, alarm stations,
communications, and protected area access entrol of personnel and packages.
This portion of the program, as implemented, mat the licensee's commitments and
NRC requirements.
S2 Status of Security Facilities and Equipment
a. Insoection Scone (81700)
Areas inspected were PA assessment aids, PA detection aids, and personnel search
equipment,
b. Observations and Findinas
PA Assessment Aids. On July 7,1998, the inspectors evaluated the effectiveness
of the assessment aids, by observing on closed circuit television, a SFM conducting
a walkdown of the PA. The assessment aids, in general, had good picture quality
and good zone overlap. However, as noted in the previous inspection conducted in
January 1998, due to long fields of view and walling effect in several zones, the
alarm station operator's ability to properly assess the cause of an alarm would be
l limited if it were not for the use of the video capture system as an enhancement to
'
the assessment program. The inspectors were informed, by security management,
that an assessment aid upgrade is being developed which will address the
assessment aid concerns. Additionally, to ensure the Plan commitments are
satisfied, the licensee has procedures in place requiring the implementation of
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compensatory measures in the event the alarm station operator is unable to properly
assess the cause of an alarm.
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Personnel and Packane Search Eauipment. On July 8,1998, the inspectors I
observed both the routine use and the daily performance testing of personnel and I
package search equipment. The inspectors determined, by observations and
procedural reviews, that the search equipment performs in accordance with licensee
procedures and the Plan commitments.
EA Detection Aids. On July 7,1998, the inspectors observed a SFM conducting
performance testing of the perimeter intrusion detection system (PIDS). The testing
consisted of 26 intrusion attempts in 25 zones, that resulted in the SFM being
detected in each intrusion attempt. The inspectors determined that the equipment
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was functional and effective and met the requirements of the Plan. '
illumination and Surveillance Hardware. While performing the inspection discussed
in this report, Section 3.1.3 of the Plan, titled "lliumination and Surveillance ;
Hardware," was reviewed. The inspectors determined, by conducting a lighting !
survey accompanied by a security supervisor with a calibrated light meter, that the
security lighting program clearly exceeds the minimallighting requirements as
specified in the Plan,
c. Conclusions
Security facilities and equipment in the areas of protected area assessment aids,
protected area detection aids, personnel search equipment, and illumination and
surveillance hardware were well maintained and reliable.
S3 Security and Safeguards Procedures and Documentation
a. inspection Scoce (81700)
Areas inspected were implementing procedures and security event logs.
b. Observations and Findir1gs
Security Proaram Procedve_s. The inspectors verified that the procedures were
consistent with the Plan commitments, and were properly implemented. The
verification was accomplished by reviewing selected implementing procedures
associated with PA access control of personnel and packages, testing and
maintenance of personnel search equipment, and performance testing of PA
detection aids.
Security Event Loas. The inspectors reviewed the Security Event Log for the
previous six months. Based on this review, and discussion with security
management,it was determined that the licensee appropriately analyzed, tracked,
resolved and documented safeguards events that the licensee determined did not
require a report to the NRC within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Additionally, the inspectors noted, during
( the review of the safeguards event logs, that since the last core inspection
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conducted in January 1998, there was a reduction in log entries associated with
personnel errors,
c. Conclusions
Security and safeguards procedures and documentation were properly implemented.
Event Logs were properly maintained and effectively used to analyze, track, and
resolve safeguards events.
S4 Security and Safeguards Staff Knowledge and Performance
a. Inspection Scope (81700)
The area inspected was security staff requisite knowledge,
b. Observations and Findinas
Security Force Reauisite Knowledae. The inspectors observed a nurnber of SFM's
in the performance of their routine duties. These observations included alarm
station operations, personnel and package searches, and performance testing of the
intrusion detection system. Additionally, the inspectors interviewed SFMs and,
based on the responses to the inspectors, determined that the SFMs were
knowledgeable of their responsibilities and duties, and could effectively carry out
their assignments. I
c. Conclus!qns
The SFMs adequately demonstrated that they had the requisite knowledge
necessary to effectively implement the duties and responsibliities associated with
their position.
S5 Security and Safeguards Staff Training and Qualification l
1
a. Insoection Scope (81700)
Areas inspected were security training and qualifications and training records.
b. Observations and Findinas
Security Trainina and Qualifications (T&Q). On July 9,1998, the inspectors
randomly selected and reviewed T&Q records of 10 SFMs. Requalification records
were inspected for armed, unarmed, and supervisory personnel. The results of the
review indicated that the security force was being trained in accordance with the
approved T&Q plan. Additionally, on July 8,1998, the inspectors observed initial
qualification classroom training which addressed proper handcuffing techniques.
The instructor was very knowledgeable of the course material, presented it in an
effective manner, and safety was always stressed.
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Trainina Records.' The inspectors were able to verify, by reviewing training records, i
that the records were properly maintained, accurate and reflected the current
,
qualifications of the SFMs.
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c. Conclusions
Security force personnel were trained in accordance with the requirements of the
Training and Qualifications Plan. Training documentation was properly maintained
and accurate. i
S8' Security Organization and Administration
a. Insoection Scope (81700)
Areas inspected were management support, effectiveness, and staffing levels. j
b. Observations and Findinas
. Manaaement Suonort. The inspectors reviewed various program enhancements
made since the last program inspection, which was conducted in January 1998.
These enhancements included the allocation of resources for bench marking
initiatives, the allocation of resources for the remodeling of the CAS, and the
assessment aid upgrade that is presently in the developmental phase.
,
Manaaement Effectiveness. The inspectors reviewed the management i
organizational structure and reporting chain and noted that the Manager of
Security's position in the organizational structure provides a means for making '
senior management aware of programmatic needs. Senior management's positive .
initiatives to address programmatic concerns is evident by the programmatic l
improvements as noted in this report.
Staffina Levels. The inspectors verified that the total number of trained SFMs
immediately available on shift met the requirements specified in the Plan. ,
c. Concluttiong
Management Lupport was adequate to ensure effective implementation of the
security program, and was evidenced by adequate staffing levels and the allocations
of resources to support programmatic needs.
S7 Quality Assurance in Security and Safeguards Activities
!
a. Insoection Scone (81700)
>.
ll Areas' inspected were audits, problem analyses, corrective actions and effectiveness
of management controls.
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b. Observations and Findinas
A_udits. The inspectors reviewed the 1998 quality assurance (QA) audit of the AA
program, (Audit No. BV-C-98-06) and the 1998 QA audit of the security program,
(Audit No. BV-C-98-01). Both audits were conducted February 3 - March 12,
1998, and were found to have been conducted in accordance with the Plan and AA
rule. To enhance the effectiveness of the audits, both audit teams included an
independent technical specialist.
The AA audit report identified no condition reports (CR) and six recommendations.
The security audit identified five CRs and ten recommendations. Two security CRs
were associated with administrative issues and three CRs were associated with
maintenance of security equipment. The inspectors determined that the findings
were not indicative of programmatic weaknesses, and the findings would enhance
program effectiveness. Discussions with security management and AA staff :
revealed that the responses to the findings were completed, and the corrective
actions were effective.
Problem Analyses. The inspectors reviewed data derived from the security
department's self-assessment program. Potential weaknesses were properly
identified, tracked, and trended.
Corrective Actions. The inspectors reviewed corrective actions implemented by the
licensee in response to the QA audits and self-assessment program. The corrective
actions were effective, as demonstrated by a reduction in personnel performance
issues and loggable safeguards events.
l Effectiveness of Manaaement Controls. The inspectors observed that the licensee
I
had programs in place for identifying, analyzing, and resolving problems. They
included the performance of annual QA audits, a departmental self-assessment
program, and the use of industry data such as violations of regulatory requirements
identified by the NRC at other facilities, as a criterion for self-assessment.
c. Conclusions
Audits of the security program were comprehensive in scope and depth, audit
findings were reported to the appropriate level of management, and the program
j was properly administered. in addition, a review of the documentation applicable to
,
the self-assessment program indicated that the program was effectively
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implemented to identify and resolve potential weaknesses.
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V. Manaaement Meetinag
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X1 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management after
the conclusion of the inspection, on August 26,1998. The licensee acknowledged the l
findings presented. l
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified.
X2 Management Meeting Summary ;
.On July 16,1998, an onsite management meeting was conducted between Duquesne
Light Company and members of the NRC Beaver Valley Oversight Panel (BVOP, chaired by ,
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R. V. Crienjak, Deputy Director of Reactor Projects, NRC Reg!on 1. The meeting was
conducted to review the current status of Beaver Valley Unit 1 readiness for restart. A
copy of the slides presented at this meeting are attached as enclosure (3).
- On August 4,1998, a Unit 1 Plant Status call was conducted between Mr. J. Cross and
members of the DLC staff and the NRC BVOP. The licensee discussed the status of
completing their Unit 1 Restart Action Plan, management oversight activities, and pending
licensing action.
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PARTIAL LIST OF PERSONS CONTACTED
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D.kG
R. Brandt, Vice President, Nuclear Operations
S. Jain, Senior Vice President, Nuclear Services
M. Pergar, Acting Manager, Quality Services Unit
B. Tuite, General Manager, Nuclear Operations
R. Hansen, General Manager, Maintenance Programs Unit
R. Vento, Manager, Health Physics
D. Orndorf, Manager, Chemistry
F. Curi, Manecer, Nuclear Construction
J. Matsko, Manager, Outage Management Department
T. Lutkehaus, Manager, Maintenance Planning & Administration
T. Cosgrove, Coordinator, Onsite Safety Committee
J. Macdonald, Manager, System & Performance Engineering
K. Beatty, General Manager, Nuclear Support Unit
S. Hobbs, Acting Director, Safety & Licensing
W. Kline, Manager, Nuclear Engineering Department
R. Brosi, Manager, Management Services
- O. Arredondo, Manager, Nuclear Procurement
N. Mulig, Technical Assistant, Vice-President
D. Huff, General Manager - Nuclear Support Unit
M. Johnston, Manager of Security
D. Kline, Director Nuclear Security Operations
N. DiPietro, Supervisor Security Services
R. Dibler, Coordinator, Security Procedures and Training
B. Sepelak, Senior Licensing Engineer
D. Miller, Supervisor NED
. J. Belfiore, Quality Assurance Auditor
A. Castagnacci, Senior Health Physics Specialist - Radwaste/ Transportation
E. Cohen, Director, Radiological Operations, Unit 2
D. Girdwood, Director, Radiological Operations, Unit 1
C. Haney, Training Supervisor
R. Hart, Licensing
R. Pucci, Health Physics Specialist - ALARA
J. Saunders, Health Physics Supervisor
D. Weitz, Senior Health Physics Specialist - ALARA
MBC
D. Kern, SRI
, G. Wertz, Rl
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L
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations
IP 71707: Plant Operations
IP 71750: Plant Support Activities l
lP 81700: Physical Security Program for Power Reactors l
lP 83726: Control of Radioactive Materials and Contamination, Surveys, and Monitoring l
lP 90712: In-Office Review of Written Reports of Nonroutine Events at Power Reactor i
Facilities l
lP 92700: - Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor
Facilities
IP 92901: Follow-up Operations
IP 92902: Follow-up Maintenance i
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ITEMS OPENED, CLOSED AND DISCUSSED
Opened
50-334/98-04-01 VIO Inadequate Unit 1 Turbine Driven Auxiliary Feedwater '
Pump Maintenance (Section M1.2)
Ooened and Closed
,
50-334(412)98-04-02 NCV incomplete Cccrective Actions for Safety Related Check
Valve Binding issues (Section E1.1) ,
50-334(412)98-04-03 NCV Failure to Maintain Design Control and inadequate ,
Corrective Actions (Section E8.1)
Clpsed
50-412/97-11 LER Inadequate Electrical isolation in Secondary Process
Rack Circuitry Due to Design Error (Section E8.2)
50-334/98 22 LER Common Mode Failure of Containment Isolation Check
Valves (Section E1.1)
50-334/98-22-01 LER Common Mode Failure of Containment isolation Check
Valves (Section E1.1)
50-334(412)/98-03-05 eel Failure to implement Adequate Administrative Controls
and Submit TS Amendment Requests for Conditions
Outside of Station Accident Analysis (Section E8,1) :
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. LIST OF. ACRONYMS USED ;
iAA' Access Authorization- !
AFW-- Auxiliary Feedwater i
ALARA As Low as'is Reasonably Achievable
ANSS Assistant Nuclear Shift Supervisor. i
BCO~ Basis for Continued Operation . 'l
BVOP - Beaver Valley Oversight Panel '
.BVPS-' Beaver Valley Power Station )
CAS- Central Alarm System
CFR Code of Federal Regulations
-l
CR' Condition Report
DCP.. . Design Change Package
DLC; Duquesne Light Company
DRO Director of Radiological Operations
EDG Emergency Diesel Generator
=EM Engineering Memorandum
ERT. ' Event Response Team
.ESF Engineered Safety Feature
.FFD Fitness-for-Duty
FIN Fix-It-Now
FRV. Feedwater Regulating Valve
GET. General Employee Training
GMNO General Manager Nuclear Operations
' HHSI . High Head Safety injection
HPMCN Health Physics Manual Change Notice
~
IPTE Infrequently Performed Tests and Evolutions
'
- law . In Accordance With
,LCO' Limiting Condition of Operation
LER Licensee Event Report
MPUAM ' Maintenance Program Unit Administration Manual
L: MRT Management Review Team -
'MSSV. Main Steam Safety Valve
MWR ' Maintenance Work Request i
NEAP Nuclear Engineering Administrative Procedure i
NO- Nuclear Operator ' !
'NPDAP Nuclear Power Division Administrative Procedure I
NRC Nuclear Regulatory Commission ]
Nuclear Safety Advisory Letter
'
NSRB Nuclear Safety Review Board
NSS. Nuclear Shift Supervisor
NUREG - NRC Technical Report Designation
r
OM Operating Manual
'OSC: :Onsite Safety Committee
OST, Operational Surveillance Test
- RO Reactor Operator
- PA Protected Area
PDR. Public Document Room
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PDR Public Document Room
PIDS Perimeter intrusion Detection System
PT Potential Transformer l
QA~ Quality Assurance !
QSU Quality Services Unit I
RAP Restart Action Plan
RCA' Radiologically Controlled Area
RP&C Radiological Protection and Chemistry j
RPS- Reactor Protection System 1
RO Reactor Operator
RTS Responsible Test Manager
SAPS _ Shippingport Atomic Power Station
SAS Secondary Alarm System
SFM. Security Force Member
)
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SPED System and Performance Engineering Department
l
SSC - System Structures and Components- '
T&Q Training and Qualification
TER Technical Evaluation Report ,
the Plan NRC-approved physical security plan j
>
TOP Temporary Operating Procedure
TS Technical Specification
UFSAR Updated Final Safety Analysis Report
UT Ultrasonic Testing
'UV Undervoltage i
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Management Meeting
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Nuclear Regulatory Commission
&
Duquesne Light Company
July 16,1998
Beaver Valley Site
V
Duquesne Light Participants
+ J. E. Cross President Generation Group
+ S. C. Jain Sr. Vice President, Nuclear Services l
+ R. D. Brandt Vice President, Nuclear Operations
+ R. L, LeGrand Vice President, Operations Support
+ W. R. Kline Manager, Nuclear Engineering
+ K. L. Ostrowski Unit 1 Restart Manager
+ B. T. Tuite General Manager Nuclear Operations
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Agenda
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+ Opening Remarks (JEC)
+ Plant Status (RDB)
+ Restart Strategy (SCJ)
+ AdministrativeIssues(WRK)
+ ProcessIssues(RLL)
+ Hardware Issues (KLO)
+ Restart Action Plan (KLO)
+ Operations Staffing (BTT)
.
+ Closing Remarks(JEC)
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Plant Status
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R. D. Brandt
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Plant Status
+ Plant Condition
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+ Critical Path Activities .
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+ Technical Specification Training
+ Human Performance
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Restart Strategy l
S. C. Jain
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Restart Strategy ,
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+ Administratiye Issues l
+ Process Issues i
+ Hardware Issues
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Administrative Issues I
Multi-Discipline Analysis Team
(MDAT)
W. R. Kline
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MDAT
+ Goals
+ Discovery Process
+ Issues
+ Root Cause
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+ Conclusions
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+ Prior to Startup
+ Post-Startup
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MDAT Goals
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+ Process Control
l + Change Control
+ Extent of Condition
+ Determine Root Cause
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+ Establish Startup Requirements
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MDAT Discovery Process !
+ Team Representation
+ Document / Process Investigation
+ Issue Identification
'
+ Restart Protocol
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MDAT Issues
+ Setpoint/ Allowable Value Changes
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+ Processes
+ Mindset
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MDAT Root Cause
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+ Feedback Inconsistencies j
+ Administrative Controls
+ Procedure vs. Licensing Changes l
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MDAT Conclusion
+ Equipment Operable :
+ Process Deficiencies
+ FeedbackInconsistencies
+ Licensing Changes vs. Procedure
+ Interim Measures Appropriate
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MDAT Activities Prior to Startup
+ Complete BCO's
+ Revise Processes
+ ProvideTraining
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Post-Startup Activities
+ Submit LAR's
+ Post-MDAT Activities !
- Improved Technical Specifications
- Best Estimate LOCA Reanalysis
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Process Issues
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R. L. LeGrand
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Approach
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+ Process
+ Causal Factors
+ Pre-Startup Actions
+ Post-Startup Actions
+ Summary
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Approach
+ Condition Reports
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- Change Process
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- NPDAP / Section Procedures
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Causal Factors I
+ Management Oversight
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+ Feedback Mechanism
+ Mindset
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Pre-Startup Actions ;
i
+ Change Process :
- Flow Charted .
t
- Revised Change Process Procedures
- Trained Personnel
- Executive and NSRB Review
- Independent Review
+ NPDAP's !
- Compared and Revised as Necessary
- Implementing Procedures
- Feedback Mechanism
n i
Post-Startup Actions ,
+ DEMMAND
+ Remaining Processes
+ Self-Assessment - 6 Months Effectiveness
Review
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Summary
.
+ Management Oversight .
+ Feedback Mechanism ,
+ Mindset Change
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Hardware Issues
K. L. Ostrowski
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Hardware Issues l
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+ Items Completed
- CREBAPS
- PORV's
+ Ongoing Items
- Undervoltage Relays ;
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Restart Action Plan
K. L. Ostrowski
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13
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1
BEAVER VALLEY RESTART PROCESS
";
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Oversight
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. Restart Milestones
+ RCS Pressurization (complete)
+ Mode 4
+ Mode 2
+ 30% Power
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Operations Staffing
B. T. Tuite
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Operations Staffing 4
+ SeniorReactorOperators
- 12 in 1997
- 7 in 1998
+ Active RO and AO Training Program
+ Active Pipeline
+ Good Performance
- 100% Examination Pass Rate
- Best Scores in Region 1
30
15
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Operations SRO Staffing
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40 /
35 !
30
25 _
20 -
l ; - -
- ; ;
Jan- Jan- Mar. Apr- Jul- Dec- Apr- Jun- Aug
96 97 97 97 97 97 98 98 58
(est)
- Star,ng increase'of 75% in 1997- 1998 period.
31
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