ML20135B778
| ML20135B778 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 02/21/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20135B683 | List: |
| References | |
| 50-334-96-10, 50-412-96-10, NUDOCS 9703030195 | |
| Download: ML20135B778 (65) | |
See also: IR 05000334/1996010
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION I
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Report Nos. 50-334/96-10, 50-412/96-10
50-334, 50-412
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Docket Nos.
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Licensee: Duquesne Light Company (DLC)
Post Office Box 4
Shippingport, PA 15077 i
Facility: Beaver Valley Power Station, Units 1 and 2
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inspection Period: December 22,1996 through February 8,1997
Inspectors: D. Kern, Senior Resident inspector
F. Lyon, Resident inspector
G. Dentel, Resident inspector
B. Welling, Project Engineer
D. Brinkman, Project Manager
Approved by: P. Eselgroth, Chief
Reactor Projects Branch 7
9703030195 970221
PDR ADOCK 05000334
G PDR
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EXECUTIVE SUMMARY
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Beaver Valley Power Station, Units 1 & 2 ,
NRC Inspection Report 50-334/96-10 & 50-412/96-10 :
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This integrated inspection included aspects of licensee operations, engineenng, ;
- maintenance, and plant support. The report covers a 7-week period of resident inspection;
l in addition, it includes the results of a nation-wide' review of criticality monitoring in new i
fuel storage areas performed by the Office of Nuclear Reactor Regulation. ,
Ooerations
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! .e. . From September to early December 1996, the morning management meetings were
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.often ineffective.for communicating and managing plant issues. During this
l inspection period the Senior Vice President-Chief Nuclear Officer and the Plant ,
l Manager met with various managers and clearly expresced their expectations on key
issues including control of vendor work, issue management and accountability,
limiting condition for operation maintenance, and control room deficiencies. The ' ']
conduct and effectiveness of the morning management meeting has improved
throughout this inspection period. Managers have more readily taken responsibility e
to manage safety issues and equipment problems at an appropriate level without
prompting from senior management. (Section 01.2).
o On January 6, Unit 2 tripped from 98% power due to a main transformer protection
relay actuation. Operators responded appropriately to the reactor trip and the unit
was stabilized. Numerous secondary problems occurred before and after the reactor
trip; however, they did not cause the reactor trip or complicate the recovery. The
Event Review Team (ERT) generally evaluated all outstanding issues associated with ,
the reactor trip properly. The shift technical advisor and independent Safety
Evaluation Group (ISEG) provided effective reviews of the post trip data '
(Section 01.3).
e The inspectors noted effective communications and good control during the January
14 Unit 2 reactor startup. A source range alarm during control rod withdrawal was
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handled appropriately, although operator knowledge and the alarm response
procedure were weak. Overall startup activities were conducted safely I
(Section 01.4).
'e A smallleak from the Unit 2 B safety injection accumulator into the residual heat
removal system (RHS) necessitated frequent RHS system depressurization. The
e,ystem engineer provided an apptr+riate basis for continued operation. Operations
end chemistry personnel failed to oroperly implement station procedures when
.depressurizing the RHS system from January 23 to January 30,1997. Operations
personnel identified and corrected this procedural adherence deficiency on January
30 (Section 01.6).
e- From September 1996 to Februery 1997, the licensee identified numerous
components out of normal switch alignment (NSA) position. Although the licensee
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demonstrated a low threshold for identifying component misconfigurations and
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(EXECUTIVE SUMMARY CONTINUED)
initiated several comprehensive corrective actions during this inspection period, the
i inspectors determined that previous corrective actions initiated to address similar
problems in 1995 had been ineffective. Poor work practices and operator errors
including failure to properly implement written procedures continued to result in
configuration control problems. Failure to maintain adequate configuration control
l was an apparent Violation (Section 01.7).
- Non-safety significant control room deficiencies continued a w mulate in backlog
during 1996, which in the aggregate, made operator duties ...uw difficult to
perform. Deficiencies were not actively managed and routinely exceeded the
station goals. In December 1996 and January 1997 management placed a higher
priority on promptly correcting control room deficiencies and clearly delineated
responsibilities. The actions taken and initial results were positive in reducing the
number and duration of control room deficiencies (Section 02.2).
- The Unit 1 waste gas decay tank (WGDT) oxygen analyzers were inadvertently
deenergized on November 25 due to operator error and inadequate operator logs.
Previous corrective actions to address improper operation of the WGDT power
switch and pressure switch override control switch were ineffective. Licensee
investigation of this event was detailed and comprehensive. The licensee event
report (LER) accurately documented the event (Section 04.1).
- Communications errors between operators and procedure weaknesses resulted in
the failure to perform a Technical Specification required quadrant power tilt ratio
surveillance fo Unit 2 on December 20,1996. Causal assessment and corrective
actions were comprehensive and properly implemented. The LER accurately
described the event in appropriate detail and met the reporting requirements of 10
CFR 50.73 (Section 08.2).
- On January 15, station management held reactor power at 30% during power '
ascension to evaluate a potential water hammer issue with the recirculation spray
system. Engineers performed an evaluation and short term compensatory measures
were in place prior to commencing a load increase to full rated power. The long-
term corrective actions were still being evaluated at the end of the period. The
inspectors observed that management response to industry information regarding
this issue was proactive and comprehensive (Section 08.4).
- The Operations department developed a detailed discussion paper regarding the
January 11,1997 Unit 2 recirculation spray system operability determination. This
was an excellent teaching tool developed to enhance operators' skills regarding
operability determinations (Section E2.1).
Maintenance
- Beaver Valley Unit 1 and Unit 2 experienced numerous freeze protection problems
this winter. Although safety related equipment problems were minimal, the failures
resulted in an increased burden on the operations staff. The licensee failed to
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adequately address the problems identified in a QA audit and an NRC inspection I
} report. Corrective actions, although not fully implemented, appear apprcpriate to
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address the current problems. Determination of whether Unit 1 reactor water ;
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storage tank heat traced lines are properly designed is an unresolved issue (Section
M2.1).
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- * Prior to the reactor trip on January 6, Unit 2 experienced a secondary system
l transient as a result of lack of quality workmanship. The transient and additional
, secondary system problems did not cause the reactor trip or adversely impact the
operators' ability to place Unit 2 in a safe shutdown condition after the reactor trip.
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- The corrective actions to address the failures were appropriate (Section M2.2). ,
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Enaineerina
e Development of additional auxiliary river water pump performance criteria for i
l maintenance rule trending and risk assessment was a positive initiative by the
-system engineer (Section M1.2).
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i e The licensee evaluation of the Unit 2 trip was of sufficient depth to accurately ,
3 ' determine the root cause (inadequate original design implementation). ~Although the
j main transformer ground protection relay is not described in the UFSAR and is not a
j safety related Appendix B criteria component, the failure to adequately implement
- the original design is a noted weakness. Corrective actions generally addressed this
i weakness (Section E1.1).
l * Original Unit 2 construction deficiencies resulted in missing / defective recirculation
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spray (RS) pump flood seals. On January 11, both RS trains were declared
1- inoperable and mode 5 was entered as required by technical specifications. The
j inspectors determined that engineer persistence in investigating potential sources of
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water inleakage and the new UFSAR word search capability were instrumental in
identifying the flood seal deficiency and developing an appropriate operability
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f determination. Engineers demonstrated a detailed knowledge level regarding RS j
l flood seals and the repairs were of good quality (Section E2.1). l
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e On January 28,1997, operators found the EDG 2-1 governor cooling water outlet
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- valve (2EGS-19) 95% shut instead of full open. The valve was promptly l
[ repositioned and the EDG was successfully tested to verify operability. The j
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inspectors questioned whether the EDG had been capable of performing its design !
accident mitigation function with 2EGS-19 in the 95% shut position. The
inspectors determined that the initial engineering evaluation did not contain
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sufficient detail to resolve _the issue. The licensee reopened the engineering
j evaluation for further analysis. Long term operability remains an unresolved issue
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(Section E2.3).
o Failure to have the required criticality alarm system installed to monitor the Unit 1
< new fuel storage area, or to have a valid exemption from the criticality alarm
I requirements of 10 CFR 70.24, was a violation (Section E8.1). l
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e The inspector found the corrective actions in response to LER 96-06, " Potential
- Control and Protection System Interaction in Steam Generator Water Level Control," ;
to be extensive and ensure compliance with IEEE-279. Engineers and procedure !
writers effectively addressed allimmediate concerns associated with the control and ,
protection system interaction during calibrations of the affected channels l
(Section E8.2). l
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Plant Suooort
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e From December 26,1996, to February 7,1997, several valves and switches were
found out of their normal switch alignment (NSA) position. Station personnel i
demonstrated a very low threshold for identifying components out of NSA and :
treating them as potential tampering events until reasonably proven otherwise. -
Security compensatory measures and investigations were timely and thorough. )
Potential tampering procedures were comprehensive, and no indication of tampering -
was identified. Operator requalification training plan revisions to incorporate .i
additional insight on potential tampering issues were excellent (Section S1.1).
- On January 24,1997, a fire main ruptured underground causing a water stream to )
- shoot upward from beneath the ground near the protected area perimeter. Intrusion )
detection alarms were received and erosion degraded the sloping ground l
embankment along one side of the security perimeter. Security response to the
ruptured fire main and degraded security perimeter were excellent. Compensatory
measures were appropriately maintained through the end of the report period and
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security officers remained alert to their duties (Section S2.1). 1
Safety Assessment and Quality Verification
e On January 1,1997, a new condition report (CR) corrective action program was
established. It was implemented throughout the inspection period without
significant problems. The program was consistently administered with issue follow-
up clearly assigned to specific managers at the daily morning management meeting.
The objectives of the CR system were reasonable for improving deficiency
identification, resolution, and tracking. Additional assessment would not be
appropriate until the program has established a longer history (Section 01.5).
o A previously unresolved inspection finding involved certification of vendors to
perform safety related work. Inspector follow-up concluded that station procedures
were inadequate to assure vendors met qualified suppliers list requirements prior to j
performing safety related work. As a result, a vendor performed safety _related leak l
injection repair services on December 1-2,1996 without satisfying applicable :
quality requirements. This was a violation. Corrective actions initiated to address I
this issue were appropriate (Section M8.1). j
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(EXECUTIVE SUMMARY CONTINUED)
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TABLE OF CONTENTS
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EXEC UTIV E S U M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii !
01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 l
01.1 eneral Comments (71707) ............................ 1 ,
O 1.2 Daily Management. Meeting and Management Expectations . . . . . 1 ]
01.3 Unit 2 Reactor Trip ................................. 3 l
01.4 Unit 2 Reactor Startup and Power Escalation . . . . . . . , , , , . . . 4 j
01.5 Implementation of Condition Report System . . . . . . . . . . . . . . . . 5 j
01.6 Residual Heat Removal Depressurization .................. 7 !
01.7 . Configuration Control Problems . . . . . . . . . . . . . . . . . . . . . . . . . 9
O2 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . 14
02.1 Engineered Safety Feature System Walkdowns (71707) . . . . . . 14 y
02.2 Control Room Deficiencies . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 :
04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . 16 l
04.1 Deenergized Unit 1 Waste Gas Decay Tank (WGDT) Oxygen
A n a l yz e r s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
08 Miscellaneous Operations issues (92901) ..................... 17
08.1 Employes Concern Resolution Program .................. 17
08.2 (Closed) Licensee Event Report (LER) 50-412/96009 . . . . . . . . 18
08.3 (Closed) LER 50-334/96013 . . . . . . . . . . . . . . . . . . . . . . . . . . 19
08.4 General Comments (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . 19
11. M a int e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
M1 Conduct of Maintenance ................................. 20 I
M1.1 Routine Maintenance Observations (62707) . . . . . . . . . . . . . . . 20
M1.2 Routine Surveillance Observations (61726) ............... 20
M2 Maintenance and Material Condition of Facilities and Equipment ..... 21
M 2.1 Cold Weather Equipment Problems . . . . . . . . . . . . . . . . . . . . . 21
M2.2 Unit 2 Reactor Trip, Secondary System Performance ........ 22
111. E ng i ne e ri ng . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
E1 Conduct of Engineering .................................. 25
E1.1 Unit 2 Reactor Trip, Main Transformer Protection Relay
A c t u a t io n . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
E2 . Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . 26
E2.1 Unit 2 Recirculation Spray Pump External Flood Barrier Not
Installed . . . . ............................... ... 26
E2.2 High Temperature on RCP B Stator . . . . . . . . . ........ 29
E2.3 Emergency Diesel Generator (EDG) 2-1 Operabihv .:.ssessment . 29
E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
E8.1 Critice;ity Monitors ................................ 31
E8.2 Steam Generator Water Level Control System and Protection
Sy, tem Interaction ................................ 32
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I V. Pla nt S u p po rt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 j
R3 RP&C Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . 33 l
R3.1 Review of Chemistry Sampling and Analysis Procedures . . . . . . 33
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L1 Review of FSAR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 34 (
- S1.1 Security Response to Misaligned Components . . . . . . . . . . . . . 34 ,
j S1.2 Security Response to Degraded Protected Area Barrier . . . . . . . 35 i
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V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
- X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
- X2 Pre-Decisional Enforcement Conference Summary ............... 36
, .X3 Licensee Senior Management Changes ....................... 37 !
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ATTA C H M E NT A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
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l ATTA C H M E NT B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 l
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Report Details
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Summarv of Plent Status .
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Unit 1 began this inspection period at 100% power. On December 27-28,1996, and on I
January 24,1997, the unit reduced load for condenser tube inspection and leak repair. ,
The unit returned to 100% power and remained there for the extent of the inspection
period.
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Unit 2 was completing power escalation to 100% power at the start of the inspection [
period. The unit reached full rated capacity on January 4,1997, after repairs to a moisture !
separator drain receiver drain pump were completed. On January 6,1997, the unit tripped i
due to a turbine trip caused by a main transformer backfeed ground protection relay. The l
outage was extended to replace missing flexible boot flood seals for the recirculation spray
pumps. The seals were replaced, and Mode 1 was entered on January 14,1997.
Operators maintained the reactor below 30% power to evaluate a potential recirculation '
spray pump water hammer issue. The unit resumed power escalation and reached full j
rated power on January 17,1997, and remained there for the extent of the inspection
period.
l. Operations
01 Conduct of Operations
01.1 General Comments (71707)'
Using inspection Procedure 71707, the inspectors conducted frequent 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.
01.2 Daily Manaaement Meetina and Manaaement Exoectations
a. Insoection Scope (71707)
The daily management meeting is conducted each morning to discuss current
operational plant status, safety issues, and planned work. The inspectors observed
the meetings to assess whether significant information was effectively ,
communicated and acted upon.
b. Observations and Findinas
During the September through early December 1996 timeframe the inspectors had i
observed that the morning management meetings were often ineffective at l
communicating and managing plant issues. Although the meetings typically lasted j
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' Topical headings such a 01, M8, etc., are used in accordance with the NRC
standardized reactor inspection report outline. Individual reports are not expected to l
address all outline topics.
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over an hour, various managers were often unprepared to discuss equipment !
operability concerns and problems reported the previous day. Ownership for issue i
resolution did not appear to be consistently assigned and understood. Some :
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examples >ncluded emergency diesel generator maintenance and testing, cold
weather prep;c+ ions, and various equipment deficiencies. Questioning by the ;
Senior Vice President - Chief Nuclear Officer (SVP-CNO) was often necessary to
ensure safety and operability concerns were properly addressed at the meeting.
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in December and January the SVP-CNO held several seminars with managers: l
following the morning meeting to clearly define his expectations for how issues ~;
should be managed. Vendor ownership was clearly highlighted to assure lessons
-learned from recent vendor work problems were understood. Manager .
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accountability for issue ownership, resolution, and appropriate timeliness were key
topics.
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Throughout this inspection period, the inspectors noted that the conduct and
effectiveness of the morning management meetings improved. In most instances, N
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department and general managers were well prepared and took a more active role in ;
discussing safety issues for which they were responsible. The condition report
program which began on January 1,1997, was consistently administered with ;
issue follow-up clearly assigned to specific managers. Operations management !
clearly identified work priorities and demanded support to resolve ongoing
equipment problems. On several occasions the Nuclear Shift Supervisors (NSSs) '
demonstrated proactive risk management insights and postponed scheduled work
activities. The inspectors observed that the shift test adv!wrs and NSSs were
properly implementing station procedures to assess the tisk associated with
combined equiprnent outages.
In late December, the inspectors observed that some planned limiting condition for
operation (LCO) maintenance activities on safety related equipment took much-
longer than planned. Examples included corrective maintenance on
2HVC-ACU201 A, which took 5 days of a 7 day LCO-allowed period, and preventive
maintenance on two Unit 1 recirculation spray pumps (RS-P-1 A/2A), which took
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> although picnned for only one hour. In each case, the work was .
completed within the time permitted by TS. However, these examples indicated a
need to better manage LCO maintenance activities. The inspectors discussed these
observations with operations management. No further examples of extended LCO
maintenance were observed during this inspection period in late January, the new
Plant Manager expressed his expectations to all managers that LCO maintenance be
worked around the clock and control room deficiencies be given a high priority. ,
. c. Conclusions
From September to early December 1996, the morning management meetings were 4
often ineffective for communicating and managing plant issues. During this
inspection' period the SVP-CNO and the Plant Manager met with various managers
and clearly expressed their expectations on key issues including control of vendor
work, issue management and accountability, LCO maintenance, and control room
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deficiencies. The inspectors observed that the conduct and effectiveness of the
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morning management meeting improved throughout this inspection period.
Managers have more readily taken responsibility to manage safety issues and
equipment problems at an appropriate level without prompting from senior
management.
01.3 Unit 2 Reactor Trio
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a. Inspection Scope (71707,92901. 93702)
The inspectors reviewed DLC's response to the Unit 2 turbine trip and subsequent'
reactor trip that occurred on January 6,1997. The inspectors examined plant
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response to the reactor trip, events prior to the reactor trip, and the investigation
hto the cause of the trip.
b. Observations and Findinas ,
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On January 6, at 5:56 a.m., Unit 2 tripped from 98% power due to a turbine trip. ,'
The turbine trip was caused by an actuation of a main transformer backfeed ground j
protection relay. Operators responded appropriately, and the unit was stabilized in
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Mode 3 (hot standby) for post-trip review and analysis. The reactor trip was
reported within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to the NRC as required by 10 CFR 50.72(b)(2)(ii).
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The plant safety systems responded as designed during the trip; however, multiple l
secondary system problems occurred. Prior to and unrelated to the trip, problems ;
associated with the moisture separator reheaters (MSRs) and the heater drain ' 1
systems resulted in isolation of all MSRs and reduced flow from one train of the -!
heater drain system. After the reactor trip, six condensate and feedwater relief ;
valves lifted and failed to reseat.
- An Event Review Team (ERT) was established to review the events and to provide
recommendations to the Nuclear Safety Review Board (NSRB}. The inspectors
attended various ERT meetings and held discussions with members of the ERT
team. The use of an ERT for event analysie r.d review is a newly developed
process at Beaver Valley. The inspectors noted that team members were of
sufficiently different backgrounds and organizational departments to provide broad
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review of the event. The ERT generally addressed all the outstanding issues 1
associated with the trip in a thorough manner. Specific issues regarding the main
transformer relay and the secondary system problems are discussed in Section E1.1
and E1.2, respectively.
A separate review of the post trip response of the plant protection and control
systems was conducted by the shift technical advisor using OEDM 7.10, Rev. O,
" Post Trip Reviews." Independent Safety Evaluation Group (ISEG) conducted an
independent review of post trip data and performed a change analysis with respect
to past reactor trips at Beaver Valley. No new issues were identified by the
reviews. The inspectors noted the reviews provided effective means of identifying
any abnormal safety or non-safety related system responses.
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i c. Conclusions !
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Operators responded appropriately to the reactor trip and the unit was stabilized. i
Numerous secondary problems occurred before and after the reactor trip; however, j
they did not cause the reactor trip or complicate the recovery. The ERT. generally ;
evaluated all outstanding issues associated with the reactor trip properly. The shift ,
technical advisor and ISEG provided effective reviews of the post trip data. l
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01.4 Unit 2 Reactor Startuo and Power Escalation ?
a. Insoection Scope (71707)
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!- The inspectors observed startup activities in the Unit 2 control room on January 14. !
The startup commenced following completion of repairs to the recirculation spray
pump boots and corrective actions from the reactive trip due to the main
! transformer relay. The inspectors noted strong command and control of the startup l
evolution. The inspectors also observed good communications between reactor
operators, the reactor engineer, and system engineers.
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b. Observations and Findinas ;
On January 14, DLC conducted a reactor startup on Unit 2. During the actual
startup evolution, distractions to the reactor operators were minimized. Reactor
engineering support and communications to the operating staff were very good. ?
Independent checks of reactor engineering by the shift technical advisor
demonstrated sound work practices. The inspectors noted one weakness. While
withdrawing control rods to reach criticality, a " source range flux doubling" alarm !
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was received. The inspectors observed that operator knowledge of the alarm and
the alarm response procedure were weak. The withdrawal of control rods was j
temporarily halted. An operations supervisor determined that the alarm was j
appropriate and that it would clear after 10 minutes. At that time, the alarm cleared
and startup was resumed. After discussions with operations management, the l
inspectors determined that long term corrective actions would address the alarm l
response procedure and that there were no safety concerns. The Unit 2 reactor l
startup was completed without incident. The inspector observed that appropriate j
safety. precautions were observed throughout the startup evolution. :
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c. Conclusions j
The inspectors noted effective communications and good control during the Unit 2 ;
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reactor startup. A source range alarm during control rod withdrawal was handled
appropriately, although the inspectors noted that operator knowledge and the alarm
response procedure were weak. The inspectors concluded that overall startup ;
activities were conducted safely. !
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01.5 Imolementation of Condition Report System
a. Insoection Scoce (71707)
inspectors reviewed the implementation of the Condition Report (CR) system by
DLC. The CR system replaced the Problem Report system on January 1 as DLC's l
primary corrective action system for identifying, resolving, and preventing problems.
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b. Findinas and Observations
On January 1, DLC implemented the Condition Report (CR) system to document the i
j identification and resolution of deficiencies at Beaver Valley and the subsequent !
corrective actions taken to prevent recurrence. l
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Backaround i
At the end of 1993, in response to declining trends in plant operations, personnel !
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performance, and a noted increase in regulatory issues, violations, and safety '
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concerns, DLC formed two in-house review groups, a Program Review Team and a
Performance Review Team. Results of these reviews and responses identifying j
corrective actions were issued on March 1,1994. l
l
4 i
During the period June 18 - October 7,1996, the Quality Services Unit (OSU)
, conducted an audit (Audit No. BV-C-96-05) of the corrective action program. The
- audit was a technical specification requirement conducted under the cognizance of
<
the Offsite Safety Committee. QSU found that the corrective actions for several of
,
the areas addressed by the Program Review Team in 1994 were not effectively
,
implemented and other areas were only marginally effective. Weak corrective
4
actions were noted in several areas, including establishment of a structured formal
i root cause analysis program, development of a process for forming event review
i teams and a corrective action review board, self-assessments, effectiveness
reviews, and use of the Commitment Action and Tracking System.
As a result of the OSU audit findings and recommendations, DLC conducted a j
review of severalindustry corrective action programs that were highly regarded.
Based on the review, DLC chose to design a new system to replace the existing
problem report system that would address the audit weaknesses and strengthen the
corrective action program. Following tabletop exercises in November and some site ,
training sessions in December, the CR system was implemented on January 1. i
Additional training sessions were scheduled for January. i
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CR System l
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Inspectors attended one of the site training sessions for the CR system, discussed
the system with the Condition Report Program Administrator (CRPA), and reviewed
,
the following implementing procedures: Nuclear Power Division Administrative
- Procedure (NPDAP) 5.2, " Initiation of Conditions Reports," NPDAP 5.6, " Processing ;
,
of Condition Reports," and NPDAP 5.8, " Root Cause Analysis." l
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DLC had three main goals in developing the CR system:
(1) replace two previous deficiency reporting systems, the problem report and the
quality services deficiency report (OSDR), with a stronger single system;
(2) allow for five categories of evaluation based on the significance of the condition,
rather than the two levels under the old system. The intent was to provide a more
measured response to problems to focus DLC resources more efficiently; and
(3) provide a strong central administration of the system to enforce consistency and
4
allow easier trending.
At the end of January, about 866 problem reports and about 39 QSDRs were
outstanding from the old deficiency reporting systems. DLC expected to continue
resolving and closing problem reports and open item requests from the old
deficiency reporting system until completion in about early summer. DLC reviewed
the outsta'nding problem reports and all those from the fourth quarter of 1996 using
the cause codes of the CR system. The resulting information was then loaded into
the computer database established for the CR system for trending. Due dates for
evaluations and corrective actions for problem reports remained unchanged
i following the implementation of the CR system. Overdue items were tracked by the
Nuclear Licensing Department, which issued a weekly status report. As of January
24, there were 24 overdue Level 2 evaluations and 9 overdue open item requests.
There were no overdue QSDRs.
l To administer the CR system, DLC created the position of Condition Report Program
'
Administrator (CRPA). The CRPA reports to the Director of Licensing and has a key
position in the CR system. As defined in NPDAP 5.6, among his responsibilities are:
(1) establishing the category and due date of CRs, except those initiated by OSU,
(2) reviewing CR documentation for adequacy, completeness, and identification of
any overdue actions, (3) coordinating and tracking corrective actions, (4)
coordinating and tracking effectiveness reviews of corrective actions, (5) entering
applicable information into the CR database and performing periodic trend analysis,
(6) closure of CRs and their transmittal to records storage, (7) identifying the
assigned organization for investigation of CRs, and (8) coordinating reviews of CRs
by the licensing and system engineering staffs and the Nuclear Safety Review
Board, as applicable.
Another key component oi the CR system is expected to be the CR Evaluation and
Status Tracking System (CREST), which will replace the Commitment and Action
Tracking System (CATS) as the primary deficiency tracking system. CATS was
relative,1y inflexible. As a result, most trending was done by hand, and there was
relatively little analysis of data. DLC expects that CREST will allow much easier
trending, which should aid root cause analysis. As input to CREST, NPDAP 5.6
requires much more documentation of the CR process, particularly cause analysis
and corrective actions, than the old problem report system. At the end of the
period, the CREST system was only operable in the Licensing Department; DLC
expected to make it accessible site-wide within a month.
6
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NPDAP 5.6 established five categories for CR investigations, from category 1 (a ,
significant condition requiring the highest level of management overview and {
technical response) to category 5 (a condition generally well-understood, with j
corrective actions that have been completed or are well underway). The NPDAP ;
provided adequate criteria and examples as guidance in categorizing the condition. '
DLC did not change the threshold for initiating a CR from that of the old problem ,
'
report. For January,196 CRs were generated, including 29 involving equipment
failure and 25 involving human error. No CR action items were overdue.
c. Conclusions
inspectors concluded that DLC had implemented the CR system without significant
problems. The program was consistently administered with issue follow-up clearly
assigned to specific managers at the daily morning management meeting. The
objectives of the CR system were reasonable for improving deficiency identification, )
resolution, and tracking. Additional assessment would not be appropriate until the ;
program has established a longer history.
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01.6 Residual Heat Removal Deoressurization
a. Insoection Scope (71707. 92903)
Unit 2 experienced leakage from the 'B' safety injection accumulator past a Residual
Heat Removal System (RHS) isolation valve, which resulted in pressurization of the
'A' RHS system. The inspectors reviewed the methods and procedures used to
depressurize the system, the Basis for Continued Operation (BCO) of the valve, and !
reviewed applicable technical specifications (TS). The inspectors also reviewed
chemistry and operator logs to verify the actual sequence of events. The inspectors
discussed depressurization and trending with the system engineer, chemistry
personnel, and reactor operators.
b. Observations and Findinas
Since the plant outage completed on January 14,1997, Unit 2 has experienced
leakage past the closed and deenergized RHS isolation valve (2RHS-MOV720A). l
The licensee has observed the leak rate between 0.1 and 1.7 gph. Technical
specifications limit the leak rate to 5 gpm at full reactor coolant system (RCS)
pressure. The system engineer determined the leak was coming from the 'B' safety
injection accumulator based on trending of the accumulator level and pressures in
the RHS. Operators have not observed a notable increase in RCS leakrate. 'B'
accumulator level has been refilled approximately every 5 to 10 days. The inspector
reviewed the BCO and determined it was technically sound, i
l
On January 14, the nuclear shift supervisor instructed chemistry technicians to
perform their sampling procedure (Chemistry Manual 2-3.40 Part D, "RHS Grab
Sample Purging to Sample Sink," Rev. 6) to depressurize the 'A' RHS system. In
parallel, operations personnel requested that a procedure be developed for
depressurization. Operators were not aware of an alarm response procedure for
7
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high pressure in the RHS system, which was designed to depressurize the RHS. On l
about January 20, operators began using the guidance of the alarm response
procedure and chemistry technicians continued to use the sample procedure to align i
the system to depressurize. The system engineer and procedure writers completed )
a revision to the alarm response procedure on January 22, and placed it in the RHS )
shutdown procedure (20M-10AC, " Residual Heat Removal System Shutdown," i
Revision 20) to be used foi depressurization of the RHS system. The alarm ,
response procedure was retired at this point. The new procedure was available to
operations on about January 23. Besed on discussions with the operations
management and review of operator and chemist logs, the procedural steps of
20M-10.4.C were not followed at this point. Operators had reviewed the revised
2OM-10.4.C, but continued to depressurize the RHS relying on their memory of the !
retired alarm response procedure.
i
Beginning on about January 23, the nuclear shift supervisor and chemists agreed to i
leave the sampling valves open and allow operators to open the containment
isolation valve when they needed to depressurize the RHS. The chemistry ;
procedure would be entered and remain entered until a sample on a different line
(e.g. RCS hot leg sample) was obtained. After the other sample was taken, the i
chemists would return the RHS valves to their drain position. The agreement gave
operators additional flexibility to perform the frequent draining operation and to
attempt to minimize leakage.
On January 29, the control room operator opened the containment isolation valve to
depressur'.le the. RHS. The nuclear shift supervisor identified that the expected i
rapid decrease in Rri5 piessure did not occur and contacted chemistry to verify l
valve lineup. A chemist found a valve throttled vice opened as described in the
chemistry procedure for RHS sampling. The chemist repositioned the valve and the
RHS depressurized. This revealed problems with the following:
- Chemists improperly entering multiple procedures. Station
procedures do not provide this latitude.
- Failure by chemists to properly perform steps called out in their
procedures.
- Failure by operators to properly perform the steps specified in
procedure 20M-10.4.C after this was identified as the correct
procedure to use. Operators relied on memory rather than performing the
procedure which required sign-off for step-by-step completion.
- Possible communication problems between Operations / Chemistry shift
personnel.
The inspectors noted that the above problems changed the configuration control of
the RHS sampling system. The inspectors observed that the ability to provide
containment isolation and to monitor the TS limits on leakage into the RHS system
was maintained at all times. On January 30, the Technical Assistant to the General
Manager-Nuclear Operations required that all future depressurizations be completed
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by the approved depressurization procedure in 20M-10.4.C, " Residual Heat [
l Removal System Shutdown," Revision 20. Corrective actions to the above !
problems are being developed under Condition Report 97-0289.
.
TS 6.8.1 requires written procedures to be established and implemented covering i
activities recommended in Appendix A of _NRC RG 1.33, revision 2. Contrary to the i
above, during the period January 23 to January 28,1997, operators and chemistry
technicians failed to properly implement station procedures (CM 2-3.40 Part D,
"RHS Grab Sample Purging to Sample Sink," Rev. 6; 20M-10.4.C, " Residual Heat
l Removal System Shutdown," Revision 20; and 1/2 OM-48.2.C " Adherence and
l Familiarization to Operating Procedures," Revision 17) when repeatedly y
!
depressurizing the Unit 2 RHS system. This issue along w!th additional r
configuration control problems are addressed as a group in Section 01.7. ,
c. Conclusions j
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Unit 2 experienced a small leak from the B safety injection accumulator to the RHS J
system which necessitated periodic RHS system depressurization. The system "l
l
engineer provided an appropriate BCO. Operations and chemistry personnel i
repeatedly failed to properly implement station procedures for RHS depressurization I
- from January 23 to January 30. The licensee identified and corrected this
procedural adherence deficiency on January 30. -
01.7 Confiauration Control Problems
!
l
a. Inspection Scope (71707. 92901. 92903)
From September 1996 to February 1997, DLC identified numerous components out
of normal switch alignment (NSA) position. Immediate actions were taken to
address the potential for deliberate tampering, as described in Section S1.1. The
inspectors reviewed logs, interviewed personnel, and met with management to ,
assess the magnitude of the problem, causes, and corrective actions. I
l
b. Observations and Findinas
Backaround
A NRC team inspection was conducted at Beaver Valley in July 1995 to investigate
severalinstances of mispositioned components and evaluate perceived weaknesses -i
in timely security follow-up for potential tampering concerns. The team did not find i
evidence of potential tampering, but configuration control issues were raised
(Unresolved items 412/95080-01 and 334(412)/95080-04). Specifically, the team
noted weaknesses in procedural adherence during independent verifications and {
agreed with DLC findings that the mispositionings most likely resulted from poor i
work practices or operator error. DLC initiated several corrective actions including
departmental valve lineup verifications to ensure that controlled drawings, system
line up procedures, and actual in-plant alignments were consistent. The inspectors
reviewed the chemistry department results, completed December 13,1995, which
verified over 1100 valves. Four valves were found out of the correct position, and l
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69 valves were found in the correct position, but required procedure revisions to
reflect the correct as-found position.
Current issues
From September 1996 to February 1997, DLC identified numerous components out
of normal switch alignment (NSA) position. The inspectors reviewed component
misalignment trending with the Quality Services Unit manager. Data indicated a
steady reduction in the number of mispositioning events over the past year until
September 1996. Based on inspector observations and personnel interviews, the
inspectors determined that a significant portion of the increased events since
September 1996 resulted from a lower threshold for workers to report
mispositioned components. However, poor work practices and operator error
continued to account for several of the mispositioned components.
Components found out of NSA this period included:
- Both Unit 1 Waste Gas Decay Tank (WGDT) oxygen analyzers off
- 4KV circuit breaker ACB142A test switch 'B' in test -
- 2-1 emergency diesel generator (EDG) governor cooler outlet valve
(2EGS-19) shut
- 1-1 EDG instrument air dryer bypass valve (DA-169) open
- Three 120 VAC panel breakers open (AC-PNL-LWO1 breaker 6, AC-PNL SIO2
breaker.10, AC-PNL-Sl02 for TRS-CH-SI-03)
- Unit 2 Alternate service water system (SWS) strainer backwash valve
(2SWE-245) throttled
- Unit 2 SWS local pressure gage (2SWS-Pl105C and 101C) gage isolation
valves throttled
- 2SWS-Fl101 A open l
- Unit 1 river water system seal water filter inlet stop valve (RW-582) closed ;
- Unit 1 'C' component cooling water pump discharge valve (1CCR-9) open J
- Unit 2 auxiliary building radiation monitor system grab sample isolation valve j
(RMP-RQ-300) open i
- Unit 1 non-technical specification auxiliary feedwater (AFW) pump (FW-P-4, j
used as station blackout equipment) control switch off ~
i
Most components found out of NSA had little to no safety significance individually. i
Several were on portions of systems which were no longer in service, but had not i
been formally retired. However, several of the components were on safety related
systems (Emergency Diesel Generator (EDG), Component Cooling Reactor (CCR), ,
' Service Water (SWS), Auxiliary Feedwater (AFW), and Waste Gas Decay Tank. I
(WGDT) oxygen analyzers]. Operator error when positioning the WGDT oxygen
analyzer power switches resulted in failure to monitor oxygen for explosive gases
on November 30,1996 as described in Section 04.1. Poor work practices caused
the 2-1 EDG governor cooler outlet valve (2EGS-19) to be inadvertently shut which j
had the potential to adversely affect long term EDG operability as discussed in
'
Section E2.3.
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At least two recent component mispositionings represent repeat problems. 2EGS-
19 and 20 are EDG governor cooler outlet valves on the two Unit 2 EDGs. One
was found mispositioned on September 17,1996, the other on January 28,1997.
The second repeat problem involved the Unit 1 oxygen analyzer power and pressure ,
override switches which were misoperated due to a human factors issue (look-alike i
switches). Corrective action was previously taken, but it did not preclude
recurrence. ,
On January 14,1997 operators failed to shut the 'C' CCR pump discharge valve i
(1CCR-9) when securing the pump. The assistant NSS and the operator agreed to l
leave the valve open, contrary to procedures 10M-15.4.H, " Securing A CCR pump c
or Placing the Spare CCR pump in Service," Rev.1, and 10M-15.3.B.1, " Valve List- ;
1CCR," Rev. 7. This decision was made in anticipation that the 'B' CCR pump
'
post-maintenance test would fail and the 'C' CCR pump would soon be returned to
a standby lineup which would require the 1CCR-9 valve to be reopened. The -
operators failed to annotate this in the procedure and failed to update the control 3
room valve position deviation log. The 'B' CCR pump successfully passed its post l
maintenance test and operators left 1CCR-9 in the incorrect position, contrary to
procedure. ..
Licensee Corrective Actions
The inspectors expressed concern to licensee management that component .
I
mispositionings continued to occur despite previous corrective actions to address I
configuration control issues identified in 1995. Inspector follow-up of the 1-CCR9
mispositioning and RHS depressurization issues indicated recurring weaknesses in i
implementing station procedures. The licensee has initiated several corrective s J
actions to (1) determine the extent of component mispositionings by walking down
other systems and (2) raise the level of sensitivity to this issue through counseling
and group briefing sessions. NRC management conducted two conference calls
with licensee management to discuss the status of licensee event assessment and
corrective actions. The inspectors observed several corrective actions in progress
as listed below.
1) 1/2/97 Implementation of the Potential Tampering procedure was excellent as
discussed in Section S1.1.
2) 1/28/97 initiated weekly system lineups on all EDGs. Planned through at least
2/28/97 (No additional problems identified after 1/28 to date).
3) 1/28/97 Access to EDG rooms now requires NSS and security authorization
(continues pending Plant Manager decision).
4) 1/28/97 Safeguards Operability Checklist system walkdowns performed on
both Units. (No problems found.)
5) 1/28/97 Initiated emergency ' electrical supply system (4kV/480v/120v)
lineups. (No problems found).
6) 1/30/97 initiated system lineups for the 4 most risk significant PRA systems
on each Unit. (approx 9000 components verified). Completed
2/04/97. (No problems found).
7) 1/30/97 Initiate instrumentation valve verification on the Unit 1 river water
system and the Unit 2 service water system. This comprised
approximately 300 instruments (over 1000 valves). Some valves
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found out of position. Reasons for these were identified through !
licensee security investigations. No adverse impact on operability.
8) 2/03/97 QSU began doing a daily independent random valve verification on l
safety related systems. This is done by one person and continues as j
of 2/13/97. QSU is finding some process discrepancies such as the )
j procedure-specified NSA position for a given valve being different in .j
l two different departments' procedures. QSU had previously been l
tracking mispositioning events and was in the process of doing an ;
assessment when the issue grew larger in 1/97. Overall assessment .l
l
responsibility was transferred to ISEG. But OSU has identified l
component mispositioning to be pursued as a top issue. ,
j
9) 2/03/97 Operations department assigned one additional person to perform -
'
independent random safety system walkdowns for 3-4 days. (No
problems found).
10) U97 Operations department initiated a periodic audit of the NSA deviation I
log maintained in the Control Room. Problems were found in that Unit - l
l 2 control room staff was not consistently using the log to document ;l
l components out of NSA as intended. Unit 1 Audit is in progress. 1
i
'Many systems not in use anymore have not been formally retired in
place because no " Retire in Place" process exists at BVPS.-
l 11) 2/06/97 Peer oversight was initiated for critical tasks as identified by the NSS
l or by the operators performing a task. The peer oversees operator -
l self-checking and procedural use.
'
12) 2/07/97 in response to a radiation monitor grab sample isolation valve (RMP- 1
RQ-3OO) found out of position, health physics personnel performed a !
100% system lineup on all radiation monitor valves. (Over 900
valves were checked, no additional valves were found out of
position.)
13) 2/08/97 The Company President, VP-Operations, Operations General Manager,
and Security Manager performed a management assessment of the
i mispositioning issues. This review included detailed assessment of all
'
events in the past 2 months for which the potential tampering
procedure was entered. Findings were discussed with the NRC
- Resident Staff. Initial findings were meaningful and proposed
l immediate and long term corrective actions were developed.
14) 2/08/97 Ball valves (90 degree closure rotation with a straight actuator handle)
,c were identified as a likely mispositioning group as they accounted for
l five of the recent mispositioning reports. Management initiated a
l project to visually sight every ball valve at the station (several
! thousand valves) and identify likely mispositioning candidates based
on their location and proximity to other equipment or personnel
passageways. Several ball valve handles were secured the previous
- week based on recommendations which followed previous
l
mispositioning events.
15)'2/14/97 The ISEG mispositioned component / potential tampering aggregate
, assessment is scheduled to be complete in draft form.
L 16) 2/97 Senior managers stressed expectations for excellent configuration .
j control, self checking, and procedure use at daily management
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meetings, during shift turnover briefings, and at weekly operations
department seminars.
17) 2/97 Several of the recent mispositioning reports were associated with
equipment which had not been used in several years. Senior
management determined that the station did not have a formal
program to " retire equipment in-place." Management directed action
to (1) temporarily identify system boundaries for equipment believed
to be retired and (2) develop and implement a formal equipment
retirement program.
The inspectors determined that licensee threshold for identifying components out of
NSA is very low. Immediate corrective actions inr:luded individual position
verification of over 9000 components. Of that group about 10 were found out of
NSA, none of which was safety significant. Security and operations personnel have
responded promptly and comprehensively to identified mispositioning events.
Licensee corrective action during the December 1996 to February 1997 time frame
has been substantial and very conservative. However, the inspectors remain ~
concerned regarding improper operator use of procedures and poor work practices
including system restoration following maintenance activities.
Renulatory Concoms
-10 CFR 50, Appendix B, Criterion XVI states, in part, " Measures shall be - '
established to assure that conditions adverse to quality, such as failures,
malfunctions, deficiencies, deviations, defective material and equipment,
nonconformances are promptly identified and corrected. in the case of significant
conditions adverse to quality, the measures shall assure that the cause of the ' ,
condition is determined and corrective action taken to preclude repetition." -l
Inadequate control of plant component position, both safety related and nonsafety ;
related, is a significant configuration control condition adverse to quality. Poor - j
work practices and operator errors including failure to properly implement written i
procedures continued to result configuration control problems. )
i
The inspectors determined that, as of February 8,1997, licensee corrective actions
have not been fully effective and have not precluded repetition of a significant ;
configuration control condition adverse to quality. This is an apparent violation
(URl 50-334(412)/96010-01).
c. Conclusions
From September 1996 to February 1997, the licent *e identified numerous
components out of normal switch alignment (NT * , . ion. Although the licensee
demonstrated a low threshold for identifying compoib.it misconfigurations and
initiated several comprehensive corrective actions during this inspection period, the
inspectors determined that previous corrective actions initiated to address similar
problems in 1995 had been ineffective. Poor work practices and operator errors,
including failure to properly implement written procedures, continued to result in
configuration control problems. Failure to maintain adequate configuration control
was an apparent violation.
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02- ' Operational Status of Facilities and' Equipment i
1
O2.1 Enaineered Safetv Feature System Walkdowns (71707)
l
The inspectors walked down accessible portions of selected systems to assess
- equipment operability, material condition, and housekeeping.' Minor discrepancies j
were brought to DLC staff's attention and corrected. No substantive concerns were '
identified. The following systems were walked down:
l
l * Unit 2 Recirculation Spray System .
j. * Unit 2 Auxiliary Feedwater System l
I
l * Unit 2 Low Head Safety injection System
- Unit 1 Charging System
- .
O2.2 Control Room Deficiencies j
l
a. Inspection Scone (71707) i
!
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The inspectors reviewed the type and number of control room deficiencies to assess )
whether appropriate action was being taken to maintain control room equipment,
'
1
including annunciators and indicators, available to operators in good working -!
condition. This review did not specifically include assessment of existing operator l
work arounds. l
!
b.- Observations and Findinas l
s
!
During control room tours from September to December 1996, the inspectors noted 1
a large number of yellow caution tags on various control room equipment. Although -!
the total number gradually decreased since September, a significant number
remained. Control room deficiencies were mostly on indicators and annunciators.
The inspectors discussed the various tags and equipment condition with operators.
While none of the deficiencies individually had much safety significance, the
inspectors observed that the total number (approximately 80 deficiencies between
the two units), in the aggregate made operator activities more difficult to perform. q
Safety significant deficiencies were corrected promptly, but others tended to remain '
in backlog.
The inspectors noted one significant control room (CR) deficiency on December 23,
1996. Unit 2 nuclear instrument channel N41 received a positive rate trip signal
when aperators unlocked the gain potentiometer locking device. Operators routinely
adjust the gain potentiometer to ensure the signal to the high power reactor trip
circuitry remains conservative. A spurious N41 positive rate trip signal was also
received the previous day during core flux mapping. This deficiency was of concern
because it could cause an inadvertent reactor trip if it occurred while another
channel was being tested. The inspectors discussed this deficiency with the control
room staff and determined that operators were clearly briefed not to operate the
gain potentiometer while another nuclear instrument channel was in test.
Technicians completed corrective maintenance on the potentiometer on December
23 using maintenance work request (MWR) 59649. The shift supervisor signed the
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MWR as complete on January 5,1997, following a two week period of reliable
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performance. The inspectors determined that the timeliness for correcting this ;
deficiency was appropriate, i
I
The operations department had established a goal of 18 CR instruments and j
annunciators out of service (OOS) or caution tagged for a period of greater than 30 ;
days per unit. The inspectors reviewed station monthly performance indicators and "
observed that the goal had been exceeded for most of 1996. The inspectors further l
questioned why only those deficiencies lasting greater than 30 days were tracked. -l
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l -In December, an operations engineer was assigned to perform a detailed CR i
deficiency review and drive actions to get the deficiencies corrected in a more . j
l timely manner. In January, several of the longstanding control room deficiencies j
were corrected. The inspectors discussed the actions taken with the operations i
engineer. Prior to January, CR deficiencies had consistently been scheduled in the l
12 week work schedule, but were often deferred when higher priority work arose i
l and resources were limited. In a_ddition, severa! deficiencies awaited post q
1, maintenance testing (PMT), which was not defined in the work package. Some lj
! deficiencies failed their PMT, but rework MWRs were not written. During this
inspection' period, the operations engineer closely coordinated between ]
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departments, facilitated work on several longstanding CR deficiencies, and made [
several recommendations to operations management to maintain higher visibility on ;
this issue. l
!
ll In January, the plant manager placed a higher priority on promptly correcting CR -l
!
deficiencies. A dedicated instrumentation and controls crew was assigned to work l
CR deficiencies. CR deficiencies were listed in the daily plant status report for l
l higher visibility and were discussed individually at the daily management meeting. I
Specific managers were assigned responsibility for action to correct each individual ! '
CR deficiency. The station goal was revised to 120 CR deficiencies per unit. The
l inspectors noted that this tracked all CR deficiencies, rather than only those
l outstanding for greater than 30 days. The plant manager also directed that CR ;
deficiencies be scheduled for work within one to two weeks of identification to j
ensure they did not continue to get deferred in the 12 week planning schedule. ,
! .
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! C. Conclusions
! I
j Non-safety significant CR deficiencies continued to accumulate in backlog during )
l 1996, which in the aggregate, made operator duties more difficult to perform. -
i Deficiencies were not actively managed and routinely exceeded the station goals. l
In December 1996 and January 1997 management placed a higher priority on l
l promptly correcting CR deficiencies and clearly delineated responsibilities. The .j
l inspectors concluded that the actions taken and initial results were positive in '!
l reducing the number and duration of control room deficiencies. .l
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04- Operator Knowledge and Performance :
04.1 Deaneraized Unit 1 Waste Gas Decav Tank (WGDT) Oxvoen Analyzers
a. Insoection Scone (71707. 92901)
i
! The WGDT oxygen analyzers are normally energized and are used to verify the
i potentially explosive gas mixture contained in the waste gas holdup system is - !
l maintained below flammable limits. On December 26,1996, instrumentation and
.
1
l control technicians reported that both Unit 1 WGDT oxygen analyzers were . l
deenergized, while operations personnel thought the analyzers were in service. The - l
inspectors interviewed personnel and reviewed various station logs to assess i
l licensee investigation of this event and to determine whether appropriate oxygen
i. monitoring had been performed during recent WGDT operations. j
i !
l b. Observations and Findinas i
d
After identifying that the WGDT oxygen analyzers were deenergized, both WGDTs j
were promptly sampled and certified to contain less than 1% by volume oxygen, j
l
This concentration was within the limits specified by Technical Specification j
3.11.2.6. The analyzers were reenergized, and security personnel promptly initiated j
a potential tampering investigation and notified the inspectors as described in
l section S1.1. Immediate corrective actions were appropriate.
The inspectors questioned how long the oxygen analyzers had been out of service, ,
the reason they were deenergized, and whether WGDT oxygen concentration had l
been properly verified during WGDT filling operation. Operations and security ;
personnel each investigated this issue and determined that the WGDT oxygen !
analyzers were inadvertently deenergized on November 25,1996. An operator !
inadvertently pulled out the power switches, which deenergized both oxygen l
analyzers, when he thought he was restoring the pressure override switch to the
normal (pulled out) position. The analyzer power switch and the pressure override
switch are similar in appearance and operation. The switches are located adjacent
to each other on the analyzer control panel. Security personnel noted that poor .
housekeeping in front of the oxygan analyzer control panels further detracted from 1
the operators ability to clearly focus on the correct control switch. Following
discussion with operators and security personnel, the inspectors concluded that
adverse human factors contributed to these switches being misoperated in the past.
The inspectors viewed the control panels, and reviewed the control room WGDT -
oxygen analyzer chart recorders, and previous problem reports associated with
WGDT oxygen analyzer operation. The operations staff had previously placed
yellow caution tags on the pressure switch override control switches to ensure the j
switch override was returned to the " pulled out" position when completed with ]
alarm resets. in addition, permanent descriptive labels had recently been mounted j
on the panels to describe proper switch operation. Operations personnel had taken i
these corrective actions to address previous licensee identified difficulties operating
the system. The inspectors noted that these efforts to correct past switch
positioning errors were not fully effective.
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Operations personnel determined that the WGDT compressor had been used on
November 27 and 30,1996 during corrective maintenance activities. There was no
gas flow to the WGDT on November 27. However, there was gas flow to the
WGDT on November 30 and the oxygen concentration was not properly monitored
as required by TS 4.11.2.6.1. Operators incorrectly assumed that the WGDT
oxygen analyzers and the control room recorder were operable and in service. This
resulted from personnel error and operator log weaknesses.
Corrective actions included individual counseling on management expectations for
self-checking, revising the Unit 1 and Unit 2 primary auxiliary building operator logs
and the L5 surveillance verification logs to require periodic verification of oxygen -
analyzer operability, and assigning the associated licensee event report as required ,
reading for alllicensed operators and shift technical advisors. The inspectors I
determined that the log revisions were properly implemented. Corrective action
)
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effectiveness will be reviewed during follow-up inspection for this violation.
I
c. Conclusions r
The Unit 1 WGDT oxygen analyzers were inadvertently deenergized on November
25 due to operator error and inadequate operator logs. Previous corrective actions '
to address improper operation of the WGDT power switch and pressure switch
override control switch were ineffective. Failure to properly monitor oxygen
concentration during WGDT filling operation is discussed along with additional i
configuration control issues in Section 01.7. Licensee invastigation of this event I
was detailed and comprehensive. j
08 Miscellaneous Operations issues (92901)
i
08.1 Employee Concern Resolution Proaram
a. Insoection Scope (92901) l
The inspectors reviewed Employee Concern Resolution (ECR) program procedures, {
interviewed the site ombudsman who implements the program, and discussed the j
general purpose of the program with various site personnel.
b. Observations and Findinos
NRC inspection report 50-334(412)/96-04, dated June 6,1996, reviewed the
transition of the employee concerns resolution function from the Quality Concern
Resolution Program to the ECR program. The report noted that, based on initial
performance, the ECR program provided a satisfactory means to investigate and
resolve employee concerns.
The inspectors reviewed the program's overall implementation since the transition
period. The inspector observed that the ECR program posters and receipt forms
continued to be readily available at a number of locations throughout the site. ;
Based on discussions with a sampling of DLC employees, the inspectors determined i
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l that personnel generally understood the program's purpose and knew how to
submit a concern for resolution.
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The ECR program was found to be implemented as specified in Nuclear Power
Division Administrative Procedure 8.14, Employee Concern Resolution Program,
l
Rev. 3. The inspector noted that the program continues to receive a few employee
concerns each calendar quarter. The ombudsman has not identified any adverse
trends in the number, type, or sources of the concerns.
l
I
c. Conclusions
l
The inspectors concluded that the Employee Concern Resolution program continues l
to be implemented as intended and provides an appropriate, confidential means to I
resolve employee concerns.
08.2 (Closed) Licensee Event Report (LER) 50-412/96009: Missed Technical
Specification (TS) Surveillance Test - Quadrant Power Tilt Ratio Calculation (QPTR).
I
a. Insoection Scoce (92700. 92901) I
On December 20, the Unit 2 Nuclear Shift Supervisor (NSS) determined that a TS
required surveillance had not been performed within the specified time interval. The
inspectors independently assessed the licensee's root cause assessment and
corrective actions to preclude recurrence.
b. Observations and Findinas
Early on December 20,1996, operators successfully calculated the OPTR prior to
exceeding 50 percent thermal power as required by step 141.a in procedure M-
52.4A, " Increasing Power from 5% Reactor Power and Turbine on Turning Gear to
Full Load Operation," revision 26. During the next shift the reactor operator
observed that step 141.b, QPTR alarm check (20ST-2.4) was not signed off, and
asked the assistant NSS if the OPTR surveillance had been completed. The
assistant NSS reviewed the completed surveillance and responded that 20ST-2.4A
(QPTR Manual Calculation) was completed satisfactorily. The reactor operator
misunderstood this response and signed off step 141.b in procedure 20M-52.4A.
The NSS on the next shift could not locate the completed surveillance paperwork
for the QPTR alarm check.
Since the OPTR alarm check had not been performed, the QPTR alarm was
considered inoperable. TS 4.2.4 requires the QPTR calculation be performed within
12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> intervals while the OPTR alarm is inoperable. The NSS promptly directed
operators to perform a manual QPTR calculation and verified that the reactor's
performance characteristics were within the TS prescribed limits. Over 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />
expired between the OPTR calculations, which exceeded the time interval specified
by TS. The inspectors reviewed this event with operators and verified that QPTR
calculations were satisfactorily performed at the specified time intervals until the
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l OPTR alarm was returned to service in addition, a core flux map performed on j
December 21 confirmed a normal flux distribution. i
Operations personnel performed a root cause analysis (RCA) of this event to explore
human performance as well as other contributing factors. The RCA identified two i
primary causal factors. The first factor was inadequate verbal communications, in )
that standard terminology and repeatbacks were not used between the reactor -:
operator and the assistant NSS. The second factor was a weak procedure in that l
20M-52.4A did not specify a timeframe beyond 50% thermal power in which the l
QPTR alarm check must be successfully completed. Corrective actions included :
, procedure changes to ensure that Unit 1 plant start up procedures properly specified ;
l
when axial flux difference surveillances must be performed, counseling of
individuals involved, and an event lessons learned summary developed for
Operations Department required reading. The inspectors reviewed the propo: ed i
! procedure end standards changes and determined that they were comprehen ave. j
L 1
l c. Conclusions 'l
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Communications errors between operators and procedure weaknesses resulted in
~
- the failure to perform a TS required QPTR surveillance on December 20,1996. The
l inspectors concluded that causal assessment and corrective actions were
L -
comprehensive and properly implemented. The LER accurately described the event
L in appropriate detail and met the reporting requirements of 10 CFR 50.73. This
i licensee identified and corrected violation is being treated as a Non-Cited Violation,
l consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV
! 50-412/96010-02). J
- )
!
08.3 (Closed) LER 50-334/96013: Failure to Perform Gaseous Waste Disposal System
,
Oxygen Testing as Required by Technical Specifications.
l
l The event and corrective actions were previously described in section 04;1. The
LER documented the event in excellent detail, fully addressing the event, causal
factors, and corrective actions. Corrective action effectiveness will be evaluated
'
during inspector follow-up for the associated violation.
08.4 General Comments (71707)
l
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On January 15,1997, during Unit 2 initial power escalation following a reactor trip,
station management held power at 30% to evaluate a potential water hammer issue
with the recirculation spray system. A plant with a design similar to Beaver Valley
had recently identified the potential problem. Engineers performed an evaluation
- and short term compensatory measures were in place prior to commencing a load
l increase to full rated power. The long-term corrective actions were still being
'
evaluated at the end of the period. The inspectors observed that management
response to industry information regarding this issue was proactive and
comprehensive. The management hold on reactor power was a conservative, safe
decision.
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, 11. Maintenance
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M1 Conduct of Maintenance
M1.1 Routine Maintenance Observations (62707) !
The inspectors observed selected maintenance activities on important systems and
components. The maintenance work request (MWR) activities observed and
reviewed are listed below.
,
- MWR 059440 Repair MCC-1-E8, 480V Breaker Supply to FC-P-1B, the
! SFP
The activities observed and reviewed were performed safely and in accordance with
l proper procedures, inspectors noted that an appropriate level of supervisory .!
I
attention was given to the work depending on its priority and difficulty. !
M1.2 Routine Surveillance Observations (61726) j
i
The inspectors observed selected surveillance tests. Operational surveillance tests !
I
(OSTs), reviewed and observed by the inspectors are listed below.
- 10ST-30.3 " Reactor Plant River Water 1B Test" l
- 10ST-36.2, " Diesel Generator No. 2 Monthly Test"
- 10ST-30.1 A "[1WR-P-9Al Auxiliary River Water Pump Test" l
The surveillance testing was performed safely and in accordance with proper
procedures. Additional observations regarding surveillance testing are discussed in
the following sections. The inspectors noted that an appropriate level of
supervisory attention was given to the testing, depending on its sensitivity.
During the performance of 10ST-30.1 A, operators noted that acceptance criteria for
pump delta P (change in pressure across the pump from suction to discharge) was
missing from the OST. A note stated that, " Acceptance criteria is not available for
this test performance. It shall be determined prior to next performance. Therefore,
for this perfnrmance, delta P measurements are for information only." The note
was also in 10S'i-30.1B for the other auxiliary river water pump. Operators
discussed the lack of acceptance criteria with the system engineer, who
documented it in Condition Report 970193. The missing criteria was used for
balance of plant trending only. Additional criteria to meet technical specification
requirements was in the OST, and the pump performed satisfactorily. Inspectors
assessed that operators displayed a good questioning attitude in following up the
note.
The inspectors discussed the issue with the system engineer and reviewed
l Engineering Memorandum (EM) 113834. The EM requested that a minimum
l operating point be developed for the auxiliary river water pumps to help judge pump
i
performance for purposes of the Maintenance Rule and probabilistic risk
20
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.
assessment. The EM due date was before the next scheduled performance of the
OST. The criteria is not required for technical specifications (TS) or ASME testing,
inspectors assessed that the development of performance criteria in addition to the
minimum required by the TS was a good initiative by the system engineer.
M2 Maintenance and Material Condition of Facilities and Equipment
M2.1 Cold Weather Eauioment Problems
a. Inspection Scope (62707)
During the winter months, Units 1 and 2 have experienced numerous heat trace and
freezing of lines and instruments. The inspectors reviewed the significance of the
freeze protection problems and their impact on operation of the plants. The
inspectors also discussed with system engineers the current plans and corrective
actions to address the multiple cold weather issues,
b. Observations and Findinas
Over the past 2 months, Units 1 and 2 had cold weather related problems with
numerous systems. Many failures were the result of heat trace or insulation not
-
properly installed or failing to provide adequate freeze protection. Although almost
all problems were associated with non-safety systems, the failures resulted in an
increased burden on the operations staff to identify and compensate for the
equipment not functioning as designed. In NRC Inspection Report No. 50-
334(412)/96-08, the inspectors identified that a large number of work requests on
heat trace were outstanding, and that the non-safety related heat trace circuits
were not periodically calibrated. The licensee's quality assurance organization also
identified that an excessive number of work requests were not completed prior to
the onset of winter. Although the inspector could not determine at the close of this
period whether these two issues directly contributed to the failures, they highlighted
the lack of a focal point for freeze protection which did contribute to the many
failures.
The inspectors noted three lines associated with the refueling water storage tank
(RWST) were adversely affected by the heat trace problems, although only one was
considered safety related. On Unit 1, the operators received repeated control room
alarms for low temperatures on the NaOH chemical addition line. After each alarm,
the operators would run the chemical addition pump (OS-P-3) to clear the alarm.
Although no line freeze up occurred, this resulted in increased burden on the
operations staff and increase wear on the chemical addition pump. Also on Unit 1,
the makeup line to the RWST froze due to a heat trace failure and breaker trip.
Although considered a non-safety line, this condition presented an operational
challenge to refilling the RWST and the line is used in the Emergency Operating
Procedures (EOP). On Unit 2, a RWST level transmitter froze due to an insulation
gap. This level instrument is the narrow range RWST level instrument and has no
safety function, but is a control room instrument.
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i- -The inspectors reviewed the UFSAR and noted that for Unit 1 all " vital lines, such
L as those which contain boric acid solution which may not be in heated areas, are
l traced by two circuits." The inspectors reviewed with system engineers to
L determine if the preceding RWST lines met the UFSAR requirements. Based on
l extensive discussions with design _and system engineers and review of additional ,
material, the inspectors were not able to ascertain the licensee specific definition of .l
vital lines and whether those lines met UFSAR 8.5.2.8. The above RWST lines do t
not have redundant heat trace as described in the UFSAR. This item remains l
unresolved pending determination of the exact determination of the term " vital f
lines" and their relation to the above components and determination of whether the i
chemical addition line meets the above criteria with respect to the potential to - i
freeze. Determination on whether the licensee meets UFSAR 8.5.2.8 descriptions j
with respect to heat tracing of Unit 1 vital lines is unresolved (URI 50-334/96010- !
03). !
f
The licensee has addressed most of the immediate freeze protection problems. j
initially, they built several temporary enclosures to prevent further freezing of knes. t
The majority of problems are being addressed with more permanent corrective 'j
actions. Currently they are determining longer term corrective actions through a
. l
cold weather protection program review. The inspector observed increased {
management involvement in addressing the program deficiencies. 1
c. Conclusions ;
Beaver Valley Unit 1 and Unit 2 experienced numerous freeze protection problems-
this winter. Although safety related equipment problems were minimal, the failures 'l
l resulted in an increased burden on the operations staff. The licensee failed to I
adequately address the problems identified in their safety audit and in a previous -
NRC inspection report. Corrective actions, although not fully implemented, appear
to address the current problems.
M2.2 Unit 2 Reactor Trio. Secondary System Performance
a. Jnspection Scone (92902)
On January 6,1997, Unit 2 experienced a reactor trip. Prior to and after the
reactor trip several secondary problems occurred. The inspector discussed with
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system engineers and Event Review Team (ERT) members the associated problems,
and conducted plant walkdowns to assess the secondary systems failures on plant i
safety.
' b. Observations and Findinos
i
Approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> prior to the reactor trip, Unit 2 began to experience problems d
'
with moisture separator reheater (MSR) control valves closing. Eventually all four
i MSR control valves closed. This resulted in the loss of extraction steam to the
! second point feedwater heaters. The transient caused the 'A' heater drain and 1
separator drain pumps to trip on low level in the 'A' heater drain tank. 'B' heater
'
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drain tank was observed to be controlling normally. The 'A' pumps were restarted, )
j. 1
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) but normal flow was not reestablished. The condensate pumps were providing i
l additional flow to compensate. The feedwater pumps' suction pressure was
} reduced in this condition, and an increase in flow velocity is also observed. ;
Approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after the system was stabilized, the reactor tripped due to a >
- main transformer ground relay. The closing of the main feedwater regulator valves
- and increased flow velocity resulted in increased pressure seen on the secondary .
i
side. Six condensate and feedwater relief valves lifted and failed to reseat. !
4
l' The ERT determined that a loose wire connection for a low pressure turbine inlet
j steam temperature thermocouple resulted in the MSR control valves closing. This :
i thermocouple was worked this past outage and is considered a workmanship l
l problem. The immediate corrective action was to place the reheater control system l
,
in manual control during steady state operation. Other workmanship items were ' !
} identified involving governor valve position indication problems evident following the i
. last refueling outage and relief valve repair rework required during the January 1997 f
- forced outage. Long-term corrective actions are to evaluate a modification to the 1
- reheat control system and enhancements in work practices during major turbine j
- overhauls and inspections. Heater drain system valves, piping, and control systems a
- were extensively tested and evaluated. The relief valves stuck open due to various
i debris, and for two of the relief valves, the disc stuck in the guide. The relief valves i
! were repaired and placed back in service. System engineering are completing a !
- review of Beaver Valley relief valves performance versus the industry performance. !
{ The inspectors observed that corrective actions were appropriate and noted that
j long term actions to reduce the pressure transient were excellent initiatives. ,
! In addition to the specific corrective action noted above, additional hold points were I
l added during startup and power ascension for data collection and analysis by the
I system engineers on the MSRs and heater drain system. This action ensured that 6
4
the secondary system problems.were addressed and allowed for further
! improvement on the control systems. The inspectors concluded that the data -
4
gathering was well thought out and was relatively non-intrusive to operations.
- ,
4 t
- c. Conclusions
Prior to the reactor trip, BVPS2 experienced a secondary system transient as a
result of lack of quality workmanship. The transient and additional secondary
.
system problems did not impact the ability of operators to place Unit 2 in a safe
l shutdown condition after the reactor trip. The corrective actions to address the
f failures were appropriate.
M8 Miscellaneous Maintenance issues (f J02)
M8.1 (Closed) Unresolved item 50-334(4121/96009-01: Proper verification of qualified
,
suppliers list (QSL) prior to using vendor services for safety related work.
In December 1996, the inspectors determined that station procedures may not
.
properly assign responsibility for OSL certification prior to using a vendors services
j for safety related work. Annual vendor audits by the quality assurance department
may result in restrictions and conditions being established which must be' satisfied
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prior to using a vendor. These conditions are added to the QSL. However, it
appeared that if a blanket purchase order (PO) had been previously issued for the
- vendor's service, station personnel did not recertify the vendor against the updated
QSL requirements. The inspectors questioned whether the licensee properly
certified the vendor for two safety related leak injection repairs performed on
December 1-2, 1996.
!
During this insper.,b " p.,ood, the licensee reviewed the inspectors' concern and I
determined that the vendor was not properly certified for safety related work
performed on December 1-2,1996. In addition, station procedures did not address
recertification against the current OSL for vendors whose services were covered
'
under blanket POs Several departments incorrectly believed that some other
department was performing this function.
10 CFR 50, Appendix B, Criterion ll, Quality Assurance Program, requires in part
that the QA program shall provide control over activities affecting the quality of i
systems, structures, and components consistent with their importance to safety, j
Additionally, the program shall take into account the need for special skills to attain ,
the required quality. The program shall be documented by written policies, )
procedures, or instructions and shall be carried out throughout plant life. Contrary j
to the above, station procedures were inadequate to assure vendors met OSL l
requirements prior to performing safety related work. As a result, a vendor
performed safety related leak injection repair services on December 1-2,1996
without satisfying applicable quality requirements. This is a violation (VIO 50-
334(412)/96010-04).
- The inspectors met with QA and procurement personnel to discuss corrective
actions for this condition. Procurement specialists reviewed all outstanding blanket
,
POs for safety related services or materials and cross checked this with the current
QSL. Change orders were then issued for 22 safety related blanket POs to address
current OSL conditions which had changed since the blanket POs were initially
issued. The licensee reviewed all services and materials provided under those 22
original POs and determined that there were no resulting adverse safety
consequences.
Effective January 1997, procurement specialists have been assigned the
responsibility to verify OSL conditions are incorporated into the PO to a vendor. If a
. QSL change occurs affecting a vendor with an outstanding safety related PO,
procurement specialists immediately issue a change order to the associated PO
which incorporates the new QSL condition which must be satisfied by the vendor.
Procedure revisions to incorporate this practice were under development at the end
- of the inspection period. As an interim measure, a vendor service coordinator has
- also been assigned to verify QSL conditions are met prior to bringing a vendor on-
l site to perform work. The inspectors determined that the corrective actions initiated
were appropriate. Final implementation of the revised procedures remains subject
to inspector follow-up for this violation.
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E1 Conduct of Engineering
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l E1.1 Unit 2 Reactor Trio Mair Transformer Protection Relav Actuation
F
a. Insoection Scooe (71707. 92903)
Beaver Valley Unit 2 experienced a reactor trip on January 6 due to an actuation of
a main transformer backfeed ground protection relay. - The inspectors conducted
reviews of the root cause analysis, testing of the failed and associated relays, and l
corrective actions. '
b. Observations and Findinas !
i
On January 6,1997, at 5:56 a.m., Unit 2 experienced a reactor trip from 98% i
power. Immediately preceding the reactor trip, a main transformer ground alarm j
was received indicating that a main transformer ground protection relay (59-202G) l '
. actuated, thus causing the turbine trip and reactor trip. Review of alarm response
revealed that no other main generator or main transformer protective relay actuation
occurred during the event. The licensee assigned the Event Review Team (ERT) to I
determine the root cause of the reactor trip and provide corrective actions. ;
The licensee performed testing on the 59-202G and four other relays in the ;
protection system for the main generator and main transformer.' All relays I
performed as expected and within their tolerance bands. Relay engineers l
determined that if a ground on the system was present, a different alarm relay (259- ;
1201) would precede the 59-202G relay actuation. The testing also revealed that j
the 59-202G relay actuated near the lower end of its tolerance band. The licensee !
also conducted tests on the main transformer oil for indications of degradation l
expected from a fault. The oil was found to be satisfactory.- Based on the review,
'i
testing, and inspections of the equipment associated with a generator ground, the
licensee concluded that no actual ground occurred. The inspectors noted that a
lack of installed instrumentation hampered the investigation and prevented
engineers from determining an exact cause of the relay actuation prior to returning
the plant to power.
The licensee reviewed the purpose of the 59-202G. The original design setting
sheet identified that the relay was designed only for the main transformer backfeed
ground protection. Operations procedures and the elementary electrical diagram
had the relay " cut in" for both power and backfeed operations. Relay engineering
showed that the relay may be more susceptible to normal zero sequence voltage
swings when operated during normal power operations. The relay was in this
configuration since original plant startup. Unit 1 had a similar relay, but the relay
i was placed in operation only during backfeed through the main transformer. The
licensee determined that inadequate implementation of the design of relay 59-202G
was the root cause of the reactor trip.
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. The inspectors found the root cause evaluation to be thorough with the limited
amount of information available. All possible scenarios were reviewed and
extensive testing provided valuable information to determine if an actual fault
existed. Licensee corrective actions to address the root cause included:
- Ensuring 59-202G relay be in service for main transformer backfeed
operations, procedures and checklists were revised.
- Monitoring selected parameters and relays during field flashing of the main
generator and the power ascension to confirm that no ground existed and to
gain additional information about the reactor' trip.
- Perform reviews of relay setting sheets to ensure that they are consistent
with controlled drawings and procedures.
The above corrective actions were completed, however the review of relay setting
sheets was only of the' main transformer and station service transformer relays. A
more comprehensive review is ongoing.
Monitoring during the startup identified contributing causes. The monitoring
identified that the zero voltage readings across the 59-202G relay were high,'and
with vibration induced wear on the main transformer secondary wiring resulted in
the relay actuation.
c.' Conclusions
The licensee evaluation of the reactor trip was of sufficient depth to accurately
determine the root cause (inadequate original design implementation). Although the
relay is not described in the UFSAR and is not a safety related Appendix B criteria
component, the failure to adequately implement the original design is a noted
weakness. Corrective actions generally addressed this weakness.
E2 - Engineering Support of Facilities and Equipment
1
E2.1 Unit 2 Recirculation Sorav Pumo External Flood Barrier Not Installed
a. Insoection Scone (37551. 92903)
On January 11,1997, engineers determined that several recirculation spray (RS)
pump flood protection seals ware-not instal!ed or were degraded. The flood seals
were designed to protect equipment in the safeguards building from the effects of
the design probable maximum flood (PMF) to 730 foot elevation. Operators cooled
- down the reactor plant from mode 3 to mode 5 and the flood seals were
installed / repaired. The inspectors reviewed design drawings, maintenance work
packages, and interviewed personnel to assess licensee response to this event.
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- b. Observations and Findinas
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l Initial ldentification j
The inspectors interviewed various engineers to determine how the missing flood j
seals were identified and why they were missing. In early January 1997 operators j
received a RS valve pit sump high water level (12 inches) alarm. Engineers i
inspected the valve pit areas for potential water intrusion sources including RS '
system valve leakage, groundwater watertight membrane degradation, or degraded
shakespaco water stops. No visible sign of active water inleakage was evident.- A
previous waterstop splice repair appeared intact. Engineers next went up to the j
718 foot elevation level in the RS pump cubicles to search for a evidence of a j
[
'
potential water drainage path from above. On January 8, an engineer observed that !
the RS pump flange plates were not properly bolted into place. l
!
L Engineers reviewed construction drawings and past design documentation to I
I determine whether the existing configuration satisfied design requirements, l
l Engi.neers determined that each of the four RS pumps was missing its external d
! penetration flood protection seal which was to be installed between the 42 inch 1
l pipe sleeve and the concrete flooring at the 718 foot elevation. The flange plate j
j was to bolt down on top of the seal. In addition, the internal flood protection seal i
i between the 24 inch pump casing and the pipe sleeve was degraded on three of the !
L . four pumps. The inspectors walked down the RS pump cubicals and noted that the .
'
missing flood seals was not visually obvious. A solid grey material connected the' )
concrete floor to the RS pump pipe sleeve with no visible air gap. Discussions with
l- engineers revealed that this solid material was rotofoam, a slightly compressible'
non-watertight material which was installed to permit some lateral movement.
- The Updated Final Safety Analysis Report (UFSAR) was recently digitalized to
provide computer word search capability. Licensing engineers used this feature to
l aide in identifying flood protection design requirements. Licensing engineers using
the newly developed UFSAR word search capability, determined that the RS pump
flood seals were not installed as described in UFSAR sections 2.4.1.1 and 3.4.1.
The inspectors determined that the persistence in investigating potential sources of
water inleakage and the new UFSAR word search capability were instrumental in
identifying the flood seal deficiency.
Causal Analysis and Corrective Actions
Upon determining that the flood seals were not properly installed, corrective MWRs
were promptly initiated in parallel, a RS pump operability determination was
performed. The pertinent question was whether the RS pumps could perform their
design accident mitigation function reliably without the flood seals installed.
Licensing, operations, and engineering department personnel worked together on j
this assessment. The design basis for the RS system is to operate in the post loss j
of coolant accident environment to maintain the containment subatmospheric for a j
30 day period. If a PMF were to occur during the 30 day period without toe flood !
l seals properly installed, the RS system may fail to function. Specifically, the RS
l ' suction valves may become submerged which could cause them to inadvertently
'
shut. The inspectors determined that the licensee had properly evaluated the RS
system operability issue. The Operations department developed a detailed
i
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discussion paper regarding the January 11,1997 Unit 2 RS system operability
determination. This was an excellent teaching tool developed to enhance operators
skills regarding operability determinations.
On January 11, the operators declared both RS trains inoperable and placed the
plant in mode 5 in accordance with TS 3.0.3. Seal repairs were promptly initiated
and completed on January 13. The inspectors reywJeed the work packages with
engineers and visually inspected the repair workmanship. Engineers demonstrated a
detailed knowledge level regarding RS flood seals and the repairs were of good
quality.
.
The licensee identified the cause of the missing / degraded RS flood seals to be
incomplete construction contractor documentation and lack of overall knowledge of
flood protection by the RS flood seal installation crew. The quality services
department conducted over 200 additional flood seal and fire sealinspections to
determine the extent of the missing seal problem. No other damaged or missing
seals were identified. The inspectors discussed this sample inspection and the
results with engineering personnel and determined that the scope of this review was
appropriate. In addition, engineers identified additional enhancements to the flood
sealinspection program which are intended to be implemented on both units. The
inspectors determined that corrective actions were appropriate and completed in a
timely manner following issue identification.
Reportability
The licensee properly reported this event as required by 10 CFR 50.72 and 10 CFR
50.73. Based on initial discussions regarding the licensee's ongoing 100% UFSAR
review initiative, the inspectors determined that the missing RS pump flood seals
would most likely have been identified during the UFSAR reviews. Therefore,
consistent with Section Vll.B.3 of the NRC Enforcement Policy, this issue is not
subject to enforcement action.
c. Conclusions
Incomplete documentation and lack of overall knowledge of flood protection by the
original construction recirculation spray (RS) flood sealinstallation crew resulted in
missing and defective Unit 2 RS pump flood seals. On January 11, both RS trains I
were declared inoperable and mode 5 was entered as required by technical
specifications. The basis for the operability determination was technically sound.
The inspectors determined that engineer persistence in investigating potential
sources of water inleakage and the new UFSAR word search capability were
instrumental in identifying the flood seal deficiency. Engineers demonstrated a
detailed knowledge level regarding RS flood seals. The inspectors determined that
the flood seal repairs were of good quality.
28
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.
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E2.2 Hiah Temoerature on RCP B Stator .
1 l
a. Insoection Scooe (37551) {
i
Inspectors reviewed Unit 1 Temporary Modification (TM) 1-97-01 and its associated l
10 CFR 50.59 evaluation. The modification was to remove two of the four motor
stator inspection covers on reactor coolant pump (RCP) RC-P-1B to' bypass the .
motor air coolers, which were coated with boric acid, which reduced their heat j
transfer capability. t
I
b. Findinas and Observations j
,
l
' During review of -10ST-36.14, " Temperature Trending of Large Motors," engineers f
noted RCP B stator temperature was elevated above the other two RCP motor l
l stators. Trending data showed that the temperature had risen from 217 degrees F .!
on December 23,1996, to 252 degrees F on January 13. Temperature had been l'
approximately 185 degrees in the November timeframe. Over the same period of .
time, RCP A stator and RCP C stator had been steady at about 212 degrees and :i
206 degrees, respectively. The stator temperature limit recommended by the ;
vender is 311 degrees. ,
System engineering staff found what appeared to be a very light coating of boricJ
'
>
acid on one of the two motor air coolers. The source of the boric acid could.not be j
determined, however. After consultation with the vender, the TM was prepared j
and the inspection covers were removed. Stator temperature lowered to about 204 l
degrees and remained steady through the remainder of the inspection period.
Inspectors discussed the issue with system engineering staff and operators and
reviewed the TM. The evaluation thoroughly covered the safety impact of the
modification using sound engineering judgement. The stator temperature was being
monitored daily by the system engineer. Unless further degradation is detected,
DLC intends to investigate further and resolve the issue during the refueling outage
scheduled later this year.
f
c. Conclusions l
Inspectors assessed that the elevated temperature on RCP B stator had been '
satisfactorily identified and addressed by system engineering staff. The TM was
'
properly evaluated, reviewed, approved, and implemented by DLC, and provided
assurance that the RCP would perform its intended safety function. DLC intends to
resolve the issue during the next refueling outage.
E2.3 Emeraency Diesel Generator (EDG) 2-1 Ooerability Assessment
a. Insoection Scoos (37551. 92903)
l On January 28,1997, an operator observed that the EDG 2-1 governor cooling
i water outlet valve (2EGS-19) was 95% shut instead of its normal full open position.
Security initiated a potential tampering event investigation which is discussed in l
29 -
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j. Section S1.1. Engineers performed an operability evaluation to evaluate the effect !
- of the mispositioned valve. The inspectors reviewed the vendor manual and test
records, and assessed the operability determination.
I
! b. - Observations and Findinas
c ,
- The EDG governor oil heat exchanger functions to maintain governor control oil-
- within a limited temperature band to assure control oil maintains an appropriate l
'
, viscosity to support stable governor speed control. Internal governor adjustments
i
of various needle valves are established based on the known oil viscosity. The l
i inspectors reviewed the vendor manual for the Woodward Model EGB-50C governor ' l
l actuator and noted that the specified normal operating oil viscosity band was 100-
! 300 saybolt universal seconds (SUS). An expanded viscosity band of 50-3000 SUS ):
! is permitted for limited operation outside of the normal operating oil temperature l
l band. The vendor manual further states that the EDG is least stable when running
i at no load. Conversely, the inspectors determined that the EDG is inherently most
l stable when parallelled to the off-site power grid as is done during the monthly
_
surveillance run. When supplying the emergency bus loads, the EDG would be
!
'
more stable than when unloaded, but less stable than when synchronized to off-site
power. The inspectors questioned whether the EDG was operable and capable of
performing its design accident mitigation function with 2EGS-19 in the 95% shut
position.
On January 28,1997, operators reopened 2EGS-19 and successfully performed the
month!y EDG operability surveillance test the following day. No speed instability
was identified during the surveillance including when the EDG was running unloaded
. at normal speed. Engineers determined that the valve operating handle had most
likely been bumsed, and thereby mispositioned, during painting activities in
November 1990. Monthly surveillance tests were successfully completed in
December 19SS and January 1997. However, a slight speed control fluctuation
(+/- 0.1 hertz) was identified after the EDG was unloaded during both surveillance
tests. At the time engineers did not consider the slight speed oscillation to be
significant since it remained within the allowable range for normal operation. Based 1
on the successful surveillance tests, engineers determined that the EDG was !
operable, had remained operable during the time that 2EGS-19 was shut, and that j
the EDG governor was not damaged in addition, engineers believed that the EDG
'
would have been capable of performing its design seven day accident mitigation
function if called upon with 2EGS-19 in the as found position.
The inspectors quertioned the basis for the licensee operability determination. i
Although the EDG had passed the monthly surveillance tests at load for one hour,
several concerns had not been addressed. The maximum expected governor oil-
temperature and viscosity for a one hour and a seven day loaded run under design i
accident conditions had not been evaluated. Initial discussions with the system
engineer indicated that based on industry testing, an EDG governor failure due to i
high control oil temperature would occur rapidly. This failure would not be gradual ;
and therefore would not provide time for operators to diagnose and correct the !
problem once it began. The EDG governor oil had not been sampled. Engineers had
not documented the assumptions used in their operability determination.
30
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Following discussions with the inspectors, the EDG 2-1 governor oil was sampled
and engineers developed a documented operability evaluation. The inspectors
' agreed with the licensee determination that the EDG governor had not been '
damaged and that the EDG was currently operable, with the 2EGS-19 valve open. -:
However the inspectors noted that the documented operability evaluation was very !
qualitative in nature and lacked specific details, facts, and calculations to fully 1
- support several of the statement ar>d conclusions contained in the evaluation. Upon
'
discussion with licensing engineers, the inspectors were informed that the -
operability evaluation lacked sufficient analysis to support the EDG operability
determination necessary to assess whether the 2EGS-19 mispositioning was a
reportable event. At the close of the inspection period the licensee reopened the
EDG 2-1. operability evaluation for further analysis. The issue of EDG operability i
with 2EGS-19 mispositioned remains unresolved (URI 50-412/96010-05).
]
c. Conclusions
.
On January 28,1997, operators found the EDG 2-1 governor cooling water outlet '!
valve (2EGS-19) 95% shut instead of full open. The valve was promptly j
repositioned and the EDG was successfully tested to verify operability. The '
-inspectors questioned whether the EDG had been. capable of performing itt design
accident mitigation function with 2EGS-19 in the 95% shut position. The .
inspectors determined that the initial engineering evaluation did not contain- !
sufficient detail to resolve the issue. The licensee reopened the engineering l
evaluation for further analysis. Long term operability remains an unresolved issue. l
E8 Miscellaneous Engineering issues
E8.1 Criticality Monitors
a. Insoection Scoos (92903)
10 CFR 70.24 requires, in part, that a criticality alarm system shall be installed for
l detection of criticality during the storage of fuel assemblies. In August 1996 the
inspectors conducted an information gathering survey to determine whether BVPS
Unit Nos.1 and 2 had such alarm systems installed.
b. Observations and Findinas
The inspectors determined that neither BVPS unit had the required criticality alarm
systems installed. However, BVPS-2 had been granted an exemption from the
criticality alarm requirements of 10 CFR 70.24 in Special Nuclear Material License j
No. SNM-1954 on April 9,1986, and this exemption had been included in Facility l
Operating License NPF-73 when it was issued to the licensee on August 14,1987.
Therefore, a criticality alarm system is not required for BVPS-2.
The inspectors also determined that the licensee was exempted from the criticality
alarm requirements of 10 CFR 70.24 by Special Nuclear Material License SNM-1472
issued for the initial' receipt and storage of BVPS-1 fuel. This license and exemption
expired when the BVPS-1 construction permit was converted to Facility Operating
l
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License DPR-66. However, due to an apparent oversight, this exemption was not
requested for inclusion in Facility Operating License DPR-66, issued in 1976. In .j
'
December 1996, the licensee submitted an exemption request from the
requirements of 10 CFR 70.24 for Unit 1 which is under evaluation. l
c. Conclusions !
Failure to have the required criticality alarm system installed to monitor the Unit 1 ,
new fuel storage area, or to have a valid exemption from the criticality alarm ;
requirements of 10 CFR 70.24, is a violation (VIO 50-334/96010-06). i
- '
E8.2- Steam Generator Water Level Control System and Protection System Interaction
i
a. Inspection Scooe (92903) ]
!
The inspectors reviewed the corrective actions of LER 96-06, " Potential Control and i
Protection System Interaction in Steam Generator Water Level Control." The !
-inspectors further evaluated the following procedures to ensure that the revisions )
appropriately applied the requirements of ;
IEEE-279: ;
l
l
- 2 OM-24.4.ABK Annunciator Response to Main Steam F/ow Channe/ ; )
Selected Trouble
'
- 2 OM-24.4.lF instrument Failure Procedure
- 2 MSP 24.26-1 (24.29-l) (24.31-l) Loop 1 (Loop 2) (Loop 3) Feedwater Flow j
Channel IV Calibration i
- 2 MSP 21.07-l (21.08-1) (21.09-l) Loop A (Loop B) (Loop C) Steamline ' !
Pressure Protection Channel IV Test '!
b. Observations and Findinas i
i
On October 24,1996, engineers identified that BVPS2 had a potential for a
condition outside of their design basis. The immediate concerns and corrective .
actions were addressed in NRC Inspection Report No.50-334(412)/96-08. The '
condition outside the design basis was a control and protection channel interaction
between main steam flow and steam generator level channels, which did not meet
IEEE-279 standard. Based on IEEE-279, a second failure must be postulated under
those conditions. The immediate corrective actions by.the licensee was to select
the steam flow transmitter that did not have the control / protection interaction with
the steam generator level channel. The immediate corrective actions also addressed
the possibility of a failure of the steam flow transmitter. If the steam transmitter ,
(with the control / protection interaction) is selected in response to a failure, the
operators will receive a control room annunciator and would declare the !
corresponding steam generator (SG) level transmitter inoperable,thus entering the
Technical Specification. The inspectors raised further concerns whether the IEEE- 279 standards would be met during calibration or tests of the other channels.
Discussions with procedural writers and review of the procedures revealed a sound
method of ensuring IEEE-279 standard _were met. The immediate and intermediate
corrective actions were effective in maintaining the design basis. The inspector
32
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independently verified that all aspects of IEEE-279 were applied in the calibration
i procedures. Long-term corrective actions were still being pursued by the licensee. l
l ;
j c. Conclusion l
l
l The inspector found the corrective actions in response to LER 90-06 to be extensive
to ensure compliance with IEEE-279. Engineers and procedure writers effectively
addressed allimmediate concerns associated with the control and protection system
interaction during calibrations of the affected channels.
,
IV. Plant Suncort
,
I
R3 RP&C Procedures and Documentation '
R3.1 Review of Chemistrv Samolina and Analysis Procedures
a. Inspection Scooe (71750)
1
The inspector reviewed selected aspects of the chemistry sampling program,
including general procedure adequacy, chemistry sampling and analysis techniques,
and supervisory oversight. ;
.
b. Observations and Findinas
The inspector observed a chemistry specialist performing both primary and
secondary plant chemistry samples. The chemistry specialist demonstrated a high
level of knowledge of sampling procedures. The inspector noted that the specialist
did not refer to procedures during the sampling process, which was consistent with
chemistry department expectations for routinely performed samples. Analysts are
expected to be thoroughly familiar with routine sampling procedures, and step-by-
step referral to procedures is not required for routine samples.
The inspector also observed a portion of a chemical analysis of a sample for boron
concentration. The procedural steps were performed as specified in the appropriate
chapter of the Beaver Valley 1/2 Chemistry Manual. A current version of the l
'
Chemistry Manual was readily available for use in the laboratory as needed by the
analysts. The procedures reviewed by the inspector were detailed, with applicable
references.
During discussions with a chemistry specialist and the chemistry manager, the
inspector learned that chemistry procedures are reviewed for technical adequacy on
a routine basis. A number of procedures were upgraded within the past year. Also, ,
'
the inspector found that for infrequent or one-time samples, a sample procedure
may not be available. However, procedural guidance in the Chemistry Manual
allows for these types of samples to be taken with concurrence of the operations
nuclear shift supervisor.
33
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The inspector determined that the chemistry department has a formal process for i
supervisors and senior chemists to observe the performance of chemistry :
specialists / analysts. This surveillance process documents, through the use of ;
checklists, the observations of various samples and analyses. The checklists
'
specify that the observer review a number of attributes, including procedure ,
adherence, techniques, and general knowledge. The inspector reviewed several
completed checklists for the last several months and considered them adequate for
their intended purpose.
'
c. Conclusions ,
The inspector concluded that chemistry samples and analyses are generally
perforrned in accordance with approved procedures. Chemistry department
)
procedures were found to be adequate, and upgrades to the procedures were noted !
to be accomplished as needed. The department uses a documented supervisory
oversight process to review ther performance of chemists with regard to procedure i
adherence, laboratory techniques, and other attributes. -
L1 Review of FSAR Commitments
A recent discovery of a licensee operating their facility in a manner contrary to the
'
Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a l
4
special focused review that compared plant practices, procedures and/or parameters
to the UFSAR description.
4
l
While performing the inspections discussed in this report, the inspectors reviewed 1
the applicable parts of the UFSAR that related to the areas inspected. The j
inspectors verified that the UFSAR wording was consistent with the observed plant j
<
practices, procedures and/or parameters with the exception of the Unit 2 RS pump i
a external and internal flood barriers as described in Section E1.1; and the Unit 1
RWST heat trace circuits as described in Section M2.1. ;
l
S1 Conduct of Security and Safeguards Activities I
a.
S1.1 Security Resoonse to Misalianed Comoonents !
a. Inspection Scoce (71750,92904)
Several valves and switches were found out of their normal alignment during this
inspection period. Security responded and treated several of these reported
component mispositioning events as potential tampering events. The inspectors
reviewed operations, security, and management response to each event to assess !
station procedures and sensitivity to potential tampering issues,
b. Observations and Findinas
From December 26,1996, to February 7,1997, several valves and switches were
found out of their normal switch alignment (NSA) position. Station personnel have
developed a very low threshold for identifying components out of NSA and treating j
l
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- them as potential tampering events until reasonably proven otherwise. Components
found out of their NSA were promptly reported to the control room shift supervisor
(SS). The SS promptly notified security personnel for consideration of potential
tampering actions, with one isolated exception. On January 24,1997, a 4kV
, breaker overcurrent protection test switch was found out of NSA, but the SS did
.
not notify security until 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> later, while operations personnel evaluated
component operability. Management reiterated the importance of notifying security
promptly, and no repeated delays occurred. The inspectors determined this
,
corrective action was effective.
t
The inspectors reviewed security investigations and interim compensatory measures
4 for several of the potential tampering events. The security compensatory measures
i and investigations were timely and thorough. The inspectors determined that
Security Procedure 16.16, " Response to Indications of Potential Tampering, Arson,
i Vandalism, or Malicious Mischief," Rev. O, was comprehensive and was effectively
- impiamented. Security did not find any indication of malice or intentional tampering.
The mispositioning typically did not adversely effect system operability and most of
4 the affected components were unlikely tampering targets. Station management and
the Independent Safety Evaluation Group were performing broad based reviews of
4
the mispositioning events to assess trends and potential for tampering at the close
of this inspection peijod. Interim corrective actions are discussed in Section 01.7.
Security personnel revised the senior reactor operator Security Topic requalification
l training plan to incorporate additional insights regarding potential tampering events.
The inspectors reviewed the training plan including the discussion of Security
Procedure 16.16 and found it to be comprehensive,
c. Conclusions
The inspectors determined that station personnel demonstrated a very low threshold
for identifying components out of NSA and treating them as potential tampering
events until reasonably proven otherwise. Security compensatory measures and
investigations were timely and thorough. Communications between operations,
security, and NRC personnel were timely. Potential tampering procedures were
comprehensive, and no indication of tampering was identified. Operator
requalification training plan revisions to incorporate additional insight on potential
tampering issues were excellent.
S1.2 Security Response to Dearaded Protected Area Barrier
a. Inspection Scope (71750. 9290M
A ruptured fire main degraded the protected area security perimeter and reduced fire l
fighting capabilities on-site. The inspectors reviewed security response to this
event and compensatory measures established to maintain appropriate control
regarding assess to the protected area.
35
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.
.
b. Observations and Findinas
On January 24,1997, the fire main ruptured underground causing a water stream
to shoot upward from beneath the ground near the prote:ted area perimeter,
intrusion detection alarms were received and security personnel responded
promptly. No intruders were observed, however, the erosion from the water stream
degraded the sloping ground embankment along one side of the security perimeter.
An armed guard was immediately stationed as a compensatory measure.
A portion of the pressurized fire water header was isolated to stop the leak.
Additional fire protection equipment was prepositioned to provided coverage for the
area at which the fire main was isolated. The inspectors discussed the additional
,
fire protection measures with the station fire protection engineer and determined
they were appropriate.
Repairs involved a significant amount of excavation in the vicinity of the protected
area fence. A secondary protected area fence was erected and the armed guard
,
was maintained stationed throughout the end of this inspection period. The >
inspectors discussed the compensatory measures with the security manager and
determined they were appropriate. The inspectors frequently toured the degraded
perimeter area during backshift hours and interviewed security personnel. The -
guards were alert and clearly understood their responsibilities,
c. Conclusions
Security response to the ruptured fire main and degraded security perimeter were j
excellent. Security and fire protection compensatory measures were appropriately l
maintained through the end of the report period and security officers remained alert :
to their duties.
V. Manaaement Meetin_ga
X1 Exit Meeting Summary i
l
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on February 18 and 19,1997. The licensee acknowledged
the findings presented.
,
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified.
X2 Pre-Decisional Enforcement Conference Summary
On January 16,1997, a pre-decisional enforcement conference was held at the NRC
Region I offices in King of Prussia, Pennsylvania. The meeting was held to discuss (1) Unit
1 operation with two pressurizer power operated relief valve block valves shut for an
extended period of time and (2) Deficiencies associated with leak sealant repairs on the
Unit 2 reactor head vent system. The senior representatives present were Mr. William
36
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Kane, Deputy Regional Administrator, NRC Region I and Mr. James Cross, President,
Generation Group, Duquesne Light Company. A copy of the licensee's slides presented at
the meeting is included in attachment B.
l X3 Licensee Senior Management Changes
!
On January 19,1997, Mr. Ronald L. LeGrand assumed the duties of Division Vice
President, Nuclear Operations Group and Plant Manager for Beaver Valley Power Station. l
Mr. LeGrand has previously held two SRO licenses and held various positions with Georgia
, and Alabama Power Company including Shift Supervisor, Operations Superintendent,
l- l
Manager of Operations, and Manager of Health Physics and Radiochemistry.
Mr. Tom Noonan, prior Division Vice President, Nuclear Operations Group and Plant
Manager, was selected for the position of Technical Assistant to the Senior Vice President
and Chief Nuclear Officer.
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ATTACHMENT A
PARTIAL LIST OF PERSONS CONTACTED
DLL_Q
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R. LeGrand, Vice President, Nuclear Operations / Plant Manager
S. Jain, Vice President, Nuclear Services
L. Frc. eland, Manager, Nuclear Engineering
B. Tuite, General Manager, Nuclear Operations
C. Hawley, General Manager, Maintenance Programs Unit
R. Brosi, Manager, Nuclear Safety
J. Arias, Manager, Licensing
K. Ostrowski, Manager, Quality Services
R. Vento, Manager, Health Physics
M. Johnston, Manager, Security -
D. Orndorf, Manager, Chemistry
F. Schuster, Manager, System and Performance Engineering
G. Storolis, Unit 2 Operations Manager
A. Dulick, Manager, Operations Experience
R. Hart, Senior Licensing Supervisor
NRC
D. Kern, SRI
G. Dentel, RI
F. Lyon, RI
P. Eselgroth, Region I, DRP
,
4
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l lNSPECTION PROCEDURES USED
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IP 37551: Onsite Engineering
IP 61726: Surveillance Observation
IP 62707: Maintenance Observation '
( IP 71707: Plant Operations
!
IP 71750: Plant Support
IP 92700: Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor
Facilities
IP 92901: Follow-up, Operations
IP 92902: Follow-up, Maintenance
IP 92903: Follow-up, Engineering
'
IP 92904: Follow-up, Plant Support
IP 93702: Prompt Onsite Response to Events at Operating Power Reactors
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1 ITEMS OPENED, CLOSED AND DISCUSSED t
! Opened
50-334(412)/96010-01 URI Repetition of Configuration Control Problems Despite l
<
Previous Corrective Actions (Section 01.7). l
. 50-334/96010-03 URI Potential Unit 1 RWST Heat Trace Design Discrepancies j
'
(Section M2.1)
4
50-334(412)/96010-04 VIO Failure to Properly Certify Vendor for Safety Related
i Work in Accordance with OSL (Section M8.1)
50-412/96010-05 URI EDG 2-1 Operability with 2EGS-19 Closed (Section
! E2.3)
!
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50-334/96010-06 VIO Failure to ilave Criticality Monitor for New Fuel Storage !
'
Area (Section E8.1)
2
Closed
50-334(412)96009 01 URI Proper Verification of OSL Prior to Using Vendor ,
, Services (Section 08.4) 1
j 50-412/96009 LER Missed Technical Specification Surveillance Test -
Quadrant Power Tilt Ratio Calculation (Section 08.2) l
- 50-334/96013 LER Failure to Perform Gaseous Waste Disposal System l
! Oxygen Testing as Required by Technical i
,
Specifications (Section 08.3) j
50-412/96010-02 NCV Failure to Perform TS Required OPTR Calculation <
,4 Surveillance (Section 08.2) I
Discussed
50-412/95080-01 URI Independent Verifications of Valve Position Not
Performed as Required by Procedure (Section 01.7)
50-334(412)/95080-04 URI Mispositioning of 2SWS-82 and Two Instrument Root
Valves Due to Operator Error or Poor Work Practices
(Section 01.7)
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LIST OF ACRONYMS USED I
l BCO Basis for Continued Operation
i BVPS Beaver Valley Power Station
!
CATS Commitment Action Tracking System
l CCR Component Cooling Reactor
CR Condition Report
CR Control Room
CREST Condition Report Evaluation and Status Tracking System
CRPA Condition Report Program Administrator
DLC Duquesne Light Company )
ECR Employee Concern Resolution l
EDG Emergency Diesel Generator i
EM Engineering Memorandum j
EOP Emergency Operating Procedure l
ERT Event Review Team *
ISEG Independent Safety Evaluation Group
LCO Limiting Condition for Operation
LER Licensee Event Report
MSR Moisture Separe* % heater
MWR Maintenance W, ,equest
NCV Noncited Violation
NPDAP Nuclear Power Division Administrative Procedure l
NSA Normal Switch Alignment l
NSRB Nuclear Safety Review Board
NSS Nuclear Shift Supervisor
OEDM Operating Experience Department Manual
OOS Out of Service
OST Operational Surveillance Test
PDR Public Document Room
PMP Preventive Maintenance Procedure
PMT Post Maintenance Testing
QA Quality Assurance
OPTR Quadrant Power Tilt Ratio
OSDR Quality Services Deficiency Report
OSL Qualified Suppliers List ;
QSU Quality Services Unit !
RCA Root Cause Analysis
RCP Reactor Coolant Pump
RHS Residual Heat Removal System
RP&C Radiological Protection and Chemistry
RS Recirculation Spray
SS Shift Supervisor
SUS Saybolt Universal Seconds
SVP-CNO Senior Vice President - Chief Nuclear Officer
SWS Service Wcter System >
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TS Technical Specification i
UFSAR Updated Final Safety Analysis Report !
URI Unresolved item l
WGDT Waste Gas Decay Tank !
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ATTACHMENT B
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Predecisional Enforcement ,
Conference
, NRC and Duquesne Light Company
January 16,1997
King of Prussia, PA
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Predecisional Enforcement Conference Slide 1
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Duquesne Light Participants
+ J. E. cross President, Generation Group
+ S. C. Jam Vice President, Nuclear Services
+ R. L. LeGrand Vice President, Nuclear Operations Group & Plant
Manager
+ B. Tuite General Manager, Nuclear Operations
+ L. R. Freeland Manager, Nuclear Engineering
+ C. A. Hawley General Manager, Maintenance Programs Unit
+ K. L. Ostrowski Manager, Quality Services Unit
+ J. Arias Director, Licensing
+ R. D. Hart Supervisor, compliance i
Predecisional Enforcement Conference Slide 2
-- _ -_ - - - - - - - - - --- - - - ------ _ -- - _ -- - _ _ _ ---_ _ .
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Agenda
- + Opening Remarks S. C. Jain
+ Chronology R. D. Hart
+ Root Cause S. C. Jain
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- + Corrective Actions S. C. Jain
+ Beyond Design Basis S. C. Jain
+ Safety Significance S. C. Jain
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- + Closing Remarks J. E. Cross
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Predecisional Enforcement Conference Slide 3
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_ _ _ . _ . _ _ _ _ _ _ _ _ _ _ . _ . _ _ _ _ _ _ _ _ _ _ _ _ _ . . _ . . . _ _ . _ . _ _ _ _ _ _ . _ _ _ . _ _ _ _ _ _ _ . _ _ _ _ _ . _ _ _ . _ _ _ . _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ .
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Chronology
+ 1979-1980: NRC IE Bulletin 79-14 review.
+ 1980-1982: Enit 1 changes normal position
of PORV Block valves to 2 of 3 closed.
+ 1980-1981: XRC Inspection Reports 80-27,
80-30, & 81-10 discuss DLC commitments.
+ 1981: XRC issues license amendment #39
for BVPS E nit 1. t
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Predecisional Enforcement Conference Slide 4
_____ _-__ _ _ _ __-______ ______________ _ __ _ _ _______ _ _ ____-________ __- .
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Chronology (cont.) ,
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+ 1982-1986: Endocumented discussions
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between DLC and the NRC on Appendix R
concerns for the PORVs.
+ 12/90: DLC responds to GL 90-06. ,
+ 10/92: DLC submits the IPE for L nit 1.
+ 04/94: DLC submits TS change request as
per GL 90-06.
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- Predecisional Enforcement Conference Slide 5
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Chronology (cont.)
+ 3/95: DLC responds to an :SRC Request for
Additional Information about the L nit 1
IPE.
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+ 5/95: :SRC issues TS Amendment 187/69
for L nits 1 & 2 to incorporate GL 90-06.
- + 9/96
- Senior Resident Inspector questions
the PORV Block Valve normal alignment.
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Predecisional Enforcement Conference Slide 6
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Chronology (cont.) ,
+ 9/25/96: Nuclear Safety Review Board
(KSRB) reviewed a 10 CFR 50.59
evaluation to operate with the 3 PORV
Block valves open.
+ 9/30/96: NRC issued SER for L nit 1 IPE.
+ 10/08/96: PORV Block valves were opened
on L nit 1.
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Predecisional Enforcement Conference Slide 7
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Root Cause
+ The original commitment to restore the
PORV Block valve configuration to open
was not followed.
+ The processes in place in 1980 were
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insufficient to enable resolution of this
deviation from the EFSAR.
- + BVPS personnel did not question the
configuration and accepted it as normal
alignment.
Predecisional Enforcement Conference Slide 8
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Corrective Actions
+ NSRE reviewed and concurred with a 10
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CFR 50.59 evaluation to restore the PORV
Block valves to open.
+ DLC will conduct a detailed review of the
Lnit 1 and 2 LFSARs as described in DLC
l letter to the NRC dated 12/26/96.
+ A review was completed by the Quality
! Services L nit for selected IE Bulletin 79-14
modifications.
Predecisional Enforcement Conference Slide 9
_____ -____________ _______- _ _ _ _ _ ________ _ _ . _ - -__ - __ - - - _ _ -_ - - _ _ _ _ . .-
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Corrective Actions (cont.)
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+ DLC performed a limited scope review of
the L~ nit 1 LFSAR against the operations
- manual drawings & normal system ,
alignment. A similar review of the L~ nit 2
EFSAR is m progress.
- + This event and the importance of EFSAR
. . .
comph.ance is being reviewed with
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appropriate members of the Nuclear Power
Division.
Predecisional Enforcement Conference Slide 10
___._.-....-.__________________-_m-__-._____________m._-.._..- __ __--_____ _ _ ___-__ __ _ _ __Nr - -- m._ m --
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Corrective Actions (cont.)
+ Procedural guidance will be developed to .
define the process of formally
communicating IPE insights to the plant and
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plant input to the IPE.
+ Past IPE revisions will be reviewed to
ensure that vulnerabilities identified were
properly dispositioned.
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Predecisional Enforcement Conference . Slide 11
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_ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - - - - _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ - - - _ _ _ _ _ _ _ _ - - - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _
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Corrective Actions (cont.)
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+ The LFSAR for each unit is being placed on
the site computer network in a text
searchable format.
+ Commitment tracking has been improved.
+ Process controls are in place to address !
changes in normal system alignment.
Predecisional Enforcement Conference Slide 12
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Beyond Design Basis
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+ IPE review of the ATWS event showed a
vulnerability due to the PORV Block valve
configuration, but to reach an RCS
overpressure concern requires a series of
events which are beyond the design basis.
+ Revisions to the IPE for Unit 1 have
- changed the magnitude of the contribution
to the CDF from the PORV Block valve
configuration.
Predecisional Enforcement Conference Slide 13
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Safety Significance
+ The PORV Block valve operatmg
configuration was not in compliance with
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the system description provided in the
LFSAR.
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+ This operating configuration did not prevent
use of the PORVs from the control room in
the Emergency Operating Procedures.
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Predecisional Enforcement Conference Slide 14
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Safety Significance (cont.)
+ The PORV and Block valve operating
configuration was bounded by the LFSAR
Chapter 14 accident analysis.
+ This operating configuration had no adverse
safety significance for the Chapter 14
Accident Analysis.
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