ML20149J962
| ML20149J962 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 07/22/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20149J948 | List: |
| References | |
| 50-361-97-12, 50-362-97-12, NUDOCS 9707290173 | |
| Download: ML20149J962 (38) | |
See also: IR 05000361/1997012
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. ENCLOSURE 2 '
U.S.' NUCLEAR REGULATORY COMMISSION
REGION IV
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Dock'et Nos.: '50-361
50-362 ~
License Nos.: NPF-10
Report Nn.: 50-361/97-12
50-362/97-12 ,
Licensee: Southern California Edison Co.
Facility: _ San Onofre Nuclear Generating Station, Units 2 and 3 ,
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Location: 5000 S. Pacific Coast Hwy.
San Clemente, Ca!,ifornia
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Dates: May 18 through July 5,1997
Inspectors: J. A. Sloan, Senior Resident Inspector -
J. G. Kramer, Resident inspector
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J. J. Russell, Resident inspector l
D. E. Corporandy, Project inspector ,
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M. B. Fields, Project Manager, Units 2 and 3, NRR
F. R. Huey, Technical Assistant, Walnut Creek Field Office '
Approved By: Dennis F. Kirsch, Chief, Branch F
Division of Reactor Projects
ATTACHMENT: Supplemental information
9707290173 970722 W
PDR ADOCK 05000361
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EXECUTIVE SUMMARY
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San Onofre Nuclear Generating Station, Units 2 and 3
NRC Inspection Report 50-361/97-12;50-362/97-12
This routine announced inspection included aspects of licensee operations, maintenance, i
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e engineering, and plant support. The report includes inspection by the Office of Nuclear 9
Reactor Regulation Project manager for San Onofre Units 2 and 3, a technical assistant
frorn the Walnut Creek Field Office, and a regional project inspector. The report covers a
7-week period of resident inspection. .
Operatioris
- Midloop operations were conducted with due caution regarding the anticipated
risks. Management oversight was continuous and shift manning was excellent.
The level monitoring systems were closely monitored, although the diverse level
' monitoring system (DLMS) experienced intermittent failures. When functioning, all
of the level systems appeared to be acceptably accurate. The licensee's
contingency plan for reciosing the opening in Check Valve 2MUO21 was thorough.
The high-risk evolution packages prepared for each period of midloop operations
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were thorough and provided assurance that safety functions would be maintained
(Section 01.1). (
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- Operations during this inspection period were characterized by close management i
oversight and conservative action with respect to emergent plant conditions. The ;
license'e carefully evaluated significant plant deficiencies and acted to ensure that '
the problems were resolved in the interest of nuclear safety and regulatory
compliance. Operators were attentive to board indications, and were conscientious
in manipulating the urits in accordance with approved procedures (Section 01.1).
- Changes to the procedure for draining the reactor coolant system (RCS), with
respect to the DLMS alarm setpoint, were poorly verified. High use of the
procedure modification permit (PMP) process by operators decreased time spent on
other duties. Operations' failure to reverify that procedural prerequisites were not
affected by changed plant conditions was a weakness in implementing the
draindown procedure (Section 03.1).
- The Operations'self-assessment mechanisms were insightful and provided i
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" challenging criteria for improving performance. Self-assessment by Operations
management appeared to be particularly detailed and self-critical, with crew-specific
analysis and recommendations. .nis was a strength in Operations (Section 07.1).
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Nuclear Oversight provided critical analysis of Operations' performance in its
reports, contributing to enhancing Operations' performance. Compliance's
Integrated Performance Assessment Process (IPAP) Self Assessment provided a
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useful tool for enhancing the understanding of the cumulative scope of NRC findings l
'(Section 07.1). !
- The licensee implemented a comprehensive and well functioning Nachar Safety
Concems Pregram (NSCP). The licensee's process for NSCP self-assessment and
its use of peor audits was well focused and contnbuted to improved program ;
performance. The licensee also implemented a sound process for periodic reporting *. j
of program performance and recommended actions to senior management. l
However, some opportunities for broader-scoped evaluation and more formal I
acknowledgment of the correct characterization of an employee's concerns were
identified. as well as the need for rnore careful consideration of potential '
discrimination issues (Section 08.2).
Maintenance
- Engineering, Operations, and Maintenance personnel demonstrated good attention
to information and diagnostic techniques in identifying that Control Element
Assembly (CEA) 91 was uncoupled (Section M4.1). j
- Maintenance technicians displayed detailed knowledge of the auxiliary feedwater
(AFW) governor valve components and the maintenance procedure for inspecting
the valve. They exhibited excellent work practicec in self-checking and
cross-checking while performing the procedure (Section M4.2).
- Construction craftsmen and Nuclear Engineering Design Organization (NEDO)
personnel missed opportunitics to identify missing reactor coolant pump (RCP) oil
collection pan nuts. The licensee's ccrrective actions were thorough and detailed.
A noncited violation occurred as a result of not following the construction work
order requirement to reinstall the oil collection pans (Section M4.3).
A noncited violation was identified as the result of the licensee's identification of
having failed to perform required surveillance testing of portions of the containment
purge exhaust radiation monitoring system (Section M8.2).
A noncited violation was identified as the result of the licensee's identification of
failure to perform surveillances on reactor protection system operating bypass
functions (Section M8.3).
Enaineerina
The licensee's identification of an omission in testing reactor protection system
operating bypass functions was an example of thoroughness in the review of
system testing by NEDO pursuant to Generic Letter 96-01 (Section M8.3).
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A violation was identified as the result of the licensee's failure to report to the NRC,
within 30 days after a Station Technical engineer had knowledge that a required
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technical specification (TS) surveitlance requirement had not been performcd
regarding containment purge exhaust radiation monitors (Sa": tion MS.4).
+ A Station Technical engineer pvformed an inadequate walkdown of a spray valve
bollows leakoff line field change notice (FCN), and he then signed the FCN as being
omplete.
. This error subsequently led to the implementation of inaccurate control
room &awings and procedures and resulted in a concited violation (Section E1.1). 9
- The licensee's identification of the charging system check valve flow imbalance the
resultant technical resisw, and initial corrective actions were excellent. The
decision to shut down Unit 2 was conservative (Section E1.2).
- Site Technical did not provide programmatic guidance for the evaluation of the risk
associated with ;mplementing maintenance plans if plant configuration was not as
j anticipated by the plans, and Operations was not routinely evaluating the risk of
such changes. This was a weakness in implementation of 10 CFR 50.05 (the
Maintenance Rule); nowever, the licensea was correcting the weakness
(Section E2.1).
Independent Safety Engineering and NEDO were prompt ana thorough in responding
to a 10 CFR Part 21 notification associated with the plant protection system
(Section E2.2).
The licensee's root cause assessment of the failure of a containment main purge l
isolation valve in Unit 3 was thorough (Section E2.3).
The licensee's efforts to resolvo the degraded egg crate condition were excellent.
The licensee thoroughly inspected the Unit 3 steam generator (SG) intemals to
quantify the extent of degradation, and developed a comprehensive strategy to l
identify and address all relevant technical issues related to operation of Unit 3. The
licensee provided extensive technical support for the meetings held with the NRC
staff, and provided timely and accurate responses to NRC staff questions on this
issue (Section E2.4).
The licensee's response to a postulated event that was beyond the design basis
was conservative. The event involved simultaneous failures of the spent fuel
handling machino and the seal on the gate between the spent fuel pool (SFP) and
the fuel transfer pool (FTP; tha': could cause a loss of design function of the SFP
(Section E2.5).
A noncited violation was identified as 1he result of the licensee's identification that
the Unit 2 containment emergency hatch was not adequately closed during core
alterations (uncoupling and weighing of CEAs). The error was the result of failing to
recognize that the hatch equalizing valve was open as the result of modifications to
support steam generator chemical cleaning (SGCC). The licensee event report (LER)
was self-critical (Section E8.1).
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- 1 A nuclear plant equipment 4 i ased good radiological practices when verifying - :
vabe positions in the Unit e ment (Section 02.1) d
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- h During routine tours of the Unit 3 containment, the inspectors observed debris and .
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tools left in various areas. While most materials not actually in use were stored in 9
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- designated areas, some areas were very cluttered. ' Additionally, a considerable
', . amount of debris was left in and around the RCP oil collection pans aft'er the
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Emodification work and associated clean up act.'vities were completed. Subsequent
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cleanup of the containment was excellent (Section R2.1).
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l' 4 A violatiori was identified by the inspectors as the result of a licensee supervisor's '
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.i- failure to follow the procedural requirement for controlling.his security badge. A
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weakness in the licensee's procedure was identified because the procedure did not l
i. - reflect an exemption that was posted on signs in the locker room. The licensee's -l
- corrective actions were prompt and adequate (Section S1.1). )
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Menort Details - ,
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Summary of Plant status I
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- - Unit.2 began the inspection period operating at essentially full power. On June 26,1997, )
, ' power was reduced to 90 percent while the licensee resolved a flow imbalance in charging )
esystem loop injection Check Valve 2MUO21. On Jdne 29 the unit was shut down in order j
to repair Check Valve 2MUO21. The unit entered Mode 5 un June 30, and operated at
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midloop cond;tions in the RCS from July 2 through July 4,1997. The unit onded this
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inspection period in Mod (5. '
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'Ua>. 3 began this inspection period in Mode 6, on the 37th day of the Un!t 3 Cycle 9
idue6ng outage. The unit entered Mode 5 on May 28,1997, and operated at midloop ' 1
i conditions.in the RCS on June 7,1997, for rn. novel of SG nozzio dams. The unit entered.
- Mode 4 on June 14, and Mode 3 on June 16,1997. On June .18,1997, CEA 91 was
n ' found to be uncoupled, and the unit entered Mode 6 on June 22 to repair the CEA. After
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repairs to CEA 91 were made, the unit once again entered Mode 5 on June 20,1997. l
From June 27 through July 2,1997, the RCS was operated at midloop conditions to- j
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replace Check Valve 3MUO21. The RCS was egain drained tc midioop conditions on .
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July 4,1997, to replace four instrument nozzlea that were suspected to be leaking due to '
bconel-600 cracking. The unit ended this inspection period in Mode 5 at midloop.
1. Qp_erations
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01 Conduct of Operations
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01.1 Midlooo Oogra?lons '
a. Inspection Scoce (71707)
, The inspectors observed ontti ons of the preparations for, and conduct of, midloop
n operations in Unit 3 on Jun 6-7, June 27 through July 2, and July 4,1997. The
inspectors also observed portions of the preparations for and conduct of midloop
operations in Unit 2 on July 2-4,1997.
b. Observations and Findinos
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' During each of the observed periods, managers were continuously involved in
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providing onsite direction and direct oversight of control room activities. Operations
, staffing was augmented to provide extra licensed reactor operators to assist as
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Level monitoring was generally excellent, with essentially continuouc correlation
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between the refueling water level indicator narrow and wide range indicators, the
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rmw!y-installed DLMS primary and alternate indicators, and local sight glass
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Indicators, during draining evolutions. The heated junction thermocouples were also
in service.to provide discrete level indication, i
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On July 5,1997, with the Unit' 2 RCS'at 26 inches above the bottom of the hot leg,.
- - the DLMS was removed from service in order to support Unit 2 midloop operations.
t The DLMS was shared between the units. l
For each of the periods of midloop operation, the licensee prepared and
imolemented a'high-risk evolution package. The packages stipulated
defenac ia-depth strategies for the_various shutdown safety functions, and were i
approved by the Nuclear Safety Group.
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The Unit 2 core had high decay heat when the RCS was drained to midloop
( conditions'on July 2,1997, approximately 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> after having been shut down.
The licensee parformed time-to-boil calcelations to determine when the decay heat
- , 'was low enough to ensure that at least 17 minutes would elapse before boiling
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- would bLgin if' shutdown cooling was lort. j
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- During the midloop operation of Unit 2 on July 2-4.1907, the licensee was not at;te
to remove the SG hot leg primary manway to provide a hot leg vent path. The
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licensee developed a contingency plan to close the opening that was being created ;
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in the cold leg due to meintenance on Check Valva 2MUO21. The plan included I
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f abricating an easily-inttalled temporary cover to reolace the bonnet on the check
valve. Maintenance was to immediately install the cover (or the permanent bonnet) j
if notified by Operations, or if the containment evacuation alarm sounded, The I
i- licensce determined that the opening would have to be covernd within
approximately 1-2 minutes before water would come out the opening as Operations
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injectad water into the RCS. The plan included provisions for communications. !
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C The DLMS faiied frequently during draining evolutions. Each time, the drain down
L was immediately suspended until the DLMS was returned to service. However, ,
when in service, the DLMS appeared to indicate level accurately and provided useful l
!aformation to the operators. i
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c. Conclusiord .
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Midloop operations were conducted witii dus caution and regard for the anticipated )
risks. Management oversight was continuous and shift manning was excellent.
The level monitoring systems were closely monitored, altnough the DLMS
, experienced intermittent failures. When functioning, all the level systems appeared
to be' acceptably accurate. The licensee's contingency plan for reclosing the
opening in Check Valve 2MUO21 wa's thorough. The high-risk evolution packages
, prepared for each period of midloop operations were thorough and provided
, assurance that safety functions would be maintained.
Other operations activities during this inspection period were characterized by close
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management oversight and conservative action with respect to emergent plant
conditions. The licensee carefully evaluated significant plant deficiencies and acted
to ensure that the pr'oblems were resolved in the interest of nuclear safety and
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regulatory compiance. Operators were attentive to board indications, and were
, conscientious in manipulating the units in accordance with approved piocedures.
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02 Operational Status of Facilities and Equipment
. 02.1 RCS Valve Alianment Verification - Unit 3 (717J;L7J
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On July 3,1997, the inspectors observed a nuclear plant equipment operator verify
that the four vent valves and four drain valves downstream of each of the spray
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~ valves were in the required closed position. The inspectors also observed the -
operator properly close and lock Valve S31201MU995, the reactor head vent line
loss-of-coolant accident limiter orifice valve, in accordance with
, Procedure SO23 3-1.4, Revision 20, "RCS Post Fill Valve Alignment." In addition,
the inspectors observed the nuclear plant equipment operator use good radiological
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practices when verifying the valve positions.
03 Operatione Procedures and Documentation
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03.1 DLMS Ooeration - Unit 3
a. Inspection Scoce (71707J
On June 6-7, 1997, the inspectors observed Unit 3 operators preparing for, and
commencing, a draindown of the RCS from 41 percent pressurizer level to
26 inches above the bottom of the hot legs. The draindown was in preparation for
removal of SG nozzle dams. The inspectors reviewed Procedure SO23-3-1.8,
Revision 11, " Draining the RCS," which was used to perform the evolution.
b. Observations and Findincs
This draindown was the first, on either Unit 2 or 3, to be performed with the DLMS
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installed and procedura!ized This system indicated water level aad was used in
addition to local sightglass, heated junction thermocouple, and wide range and
narrow range differential pressure indications. The DLMS was accurate and
sensitive.
Step 1.18.7 of the procedure required, as a prerequisite to initiating the draindown,
that the alarm for the DLMS be set at 3 inches below the actual level. The
inspectors identified that, immediately prior to opening a low pressure safety
injection pump mini flow valve to the reactor water storage tank, to begin the
c draindown, the alarm was actually set to 1 inch below the actuallevel.
- Additionally, the critical functions rnonitoring system (CFMS) for low level was in
alarm, in response, the operators lowered the alarm to 3 inches below actual level
and cleared the CFMS alarm. The control room supervisor explained that the alarm
'had been' set 2 days before the evolution bad commenced, and that the actual level
had changed since the alarm had been set. As such, this was not a violation of the
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- . procedure. When the draindown commenced, initial level drop was about 4 inches
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per minute. : This caused numerous! control board alarms on DLMS :ow level.
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Operators had difficulty in resetting the alami continuously as level droppua, while
' maintaining the alarm 3 inches below actual level.~ .One of the extra reactor
. eperatora was then. assigned to ress< the alarm on tne CFMS touch screen on the
mair6 control boards Thu inspactors found that, with level still in the pressurizer, ,
- there was no meaningful information gained by having the alarm 3 inches from the
, actual level. it did, however, distract crew members from monitoring other
parameters. The licensee failed to verify that changed plant condMions had not
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affected the procedural prerequisites prior to procedure implementavnn.
Procedure S0'/ 3-31.3 was changed by thi operators, using the PMP
process, prior to use. One change involving the DLMS was to change the l
units on alarm setpoint stipulated in the procedure from feet to inches, .
agreeing with the unitr. ihat were ir.dicated on CFMS. .Other parts of the .l
. procedure were also char;ged. The incpectors determined that the operators'
extensive usege of the PMP process, as documented in NRC Inspection l
Report 50-361: 362/97-09, distracted operators from other d nies, including
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plant mon!!aring. ' However, plant monitoring was adequa'e. 2
c, - Conclusions
Changes to the procedure for craining the RCS, with respect to the DLMS alarm I
L setpoint,~ were not well verified. High use of the PMP process by operators )
. decreased time spent on other duties. Operations * failure to reverify that procedural
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prerequisites were not cffected by changed plant conditions was a 'neakness in ;
- implementing the draindown procedure. 1
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07 Quality Assurance in Operations
, 07.1 Self Assessment j
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l a. Jmpection Scone (717071
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The inspectors reviewed the "1997 First Quarter Operations Division Event Report
Assessment," dated April 25,1997, the " Operations Performance Annunciators"
report, dated April 23,1997, and an undated informal analysis, " Operational Event
Relative Significance," that had been prepared by Operations. The inspectors also
reviawed th9 "First Quarter 1997 Station Performance Report," and the "Hurnan
Performance Trending 1st Quarter 1997" report, prepared by Nuclear Oversight,
arid the "lPAP Self Assessment," performed by Compliance,
b. Observations and Findinas
The 1997 First Quarter Operations Division' Event Report Assessment, which ,
compared operator performance with the good.uperating practices identified in {
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Procecure ?023-0-44, Revistun 2, " Professional Operator Devalopment and
Evaluation Progrem," was objective and critical, and provided good <
recommendations. One af the strengths of the assessment was that it included
ciew specific onalyses and tecommendations.
The Operations Event Relative Significance report was a good e.nalysis of the
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signifhance of refueling perind events fcr t5e Cycle 6,7,8, and 9 refueling -
outages. The report conduded that the significance of reported events had dectined
sharply, while the threshold for reporting events had also been substantially
. lowered. In Cycle 6, the average event significance was 12.3 on a scale of 1 to 22
(22 being the most significant. In the current Unit 3 Cycle 9 outage, the average ;
cignificance is 1.6. Not6bly, ovants below what is new a level 10 were not even
tracked until Cycle 9. The report abo indicated that one event occurred about-
every 4 days in each outags. The tracking and analysis of low-significance events
and precursor conditions was a strength of this self-assessment effort.
Additionally, the reduction of the significance of recoided events demonstsated the
effectiveness of psrformance improvement efforts in Operations. ;
The Operatior.n Perforrnance Annunciators report provided queeterly assessments of
performance in various division-level and crew-level areas. The criteria were tuch
that personnel were challenged to improve, anc the Operations manager indicated
that Ms intent was to make the criteria rnore dif hcult to meet whenever meeting the
criteria was ne, songer challeng!ng. One of the strengths of this program was that it
fostered competition among crews for improved performance in the monitored
areas.
The first Guarter 1997 Station Performance Report assessment of Operations
documented the results of "205 ebservations in the Operations area during the
qucrter. The report gave Operations a satisfactory rating overall (the second
highest rating). Although this was the same rating achieved in each of the three
previous quarters, the report documented generalimprovement in performance. The
report acknowledged that Operations had a high self-reporting rate (79 percent) of
low-level events, and that improvements occurred in the areas of corrective action
effectiveness and control room supervisory oversight, Reductions were observed in
the number of operating instructions with greater than five temporary change
notices (TCNs), although an increase was observed in the number of 4
procedure-related open items. Action request (AR) assignments were high, but l
unchanged from the previous quarter The time spent by operators accommodating
work arounds was trending upward, This report was effective in providing a broad
perspective of Operations' performance in a number of areas, yet focusing attention
on performance areas that were stagnant or not improving. The high percentage of
self-reporting was a positive indication'of operators' desire for improvement.
The liurnan Pctformance Trending report focused on failed performance barriers ,
observed in all divisions, and included an analysis of the trends observed in
Operations. While some trends were improving, four of the five focus areas in I
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Operations showed declining performance. The most frequent failed barrier was
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" standard work practices," with " inadequate self-checking" being the rnost
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significant standard work practice deficiency. This critical analysis reinforced what
was apparent from Operations' own self-assessment tools, providing additional
impetus for supervisory ernphasis of the good operations practices described in j
Procedure SO23-0 44.
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The IPAP Self-Assessment was patterned after the in-office review portion of the i
. NRC's own IPAP process. The licensee's IPAP compiled NRC findings for the last i
two Systematic Assessment of Licensee Performance (SALP) periods and sorted tho l
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findings into relevant categories, from which performance themes for each SALP
cycle were drawn in each of the SALP functional areas (safety assessment / quality
verification was treated as a fifth SALP functional area by the licensee). The IPAP
self assessment appeared to characterize the NRC findings reasonably accurately. l
The conclusions were based primarily on the percentages of findings in each !
category, rather than on the significance of the findings. However, the compilation
appeared to be a useful tool for enhancing the understanding of the cumulative
scope of NRC findings,
c. . Conclusions
The Operations self-assessment mechanisms were insightful and provided I
challenging criteria for improving performance. The self-assessment by Operations' l
management appeared to be particularly detailed and self-critical, with crew-specific
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analysis and recommendations. This was a strength in Operations.
Nuclear Oversight provided critical analysis of Operations' performance in its
reports, contributing to enhancing Operations' performance. Compliance's IPAP
self-assessment provided a useful tool for enhancing the understanding of the i
cumulative scope of NRC findings.
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08 Miscellaneous Operations lesues (92700,40001) '
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08.1 LClosedLLffi.h.QJ61/97-002-00: increase in pressurizer level due to valve I
alignment error. I
This event was discussed in NRC Inspection Report 50-361; 362/97-02. No new
issues were revealed by the LER.
08.2 NSCP Review
a. Insoection Scone (4000.11
The inspectors reviewed five NSCP files that had been evaluated and closed within
the last year, and interviewed several employees in various licensee organizations.
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b. Observation and Findinos
1. . The licensee implemented a comprehensive and well-functioning employee
concerns program. Employees who had used the program consistently
informed the inopect. ors that the program had worked well, and that they !
were pleased with the results, even when the licensee concluded that an i
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employee's concem was not substantiated. Several emoloyees also S
cornmented that the licensee's newly revised AR process had greatly i
simplified and improved the employees' ability to get concerns addressed
and resolved in an efficient manner.
2. The licensee's process for NSCP self-assessment was well focused and
contributed to improved program performance. Particularly noteworthy was
a very thorough, recent peer audit performed by the empfoyee concern
plogram supervisor from Washington Public Power Supply System, which
identified numerous improvements which the license.e had implemented into
its program.
3. The licensee had implemented a good process for periodic reporting of
program performance and recommended actions to senior management. The
report was well formatted and provided helpful comparisons and analysis of
employee concerns activities, as related to NRC allegations and concerns
being raised at other plants nation wide. The repol' 3d appropriate
attention on allegation concern backlog and timei ' provided useful
information related to multiple concerns raised by idividual. The
trending tables that highlighted the dif ferent types s oncerns
(e.g., technical or discrimination) rais,ed within diffeu licensee
organizations provided useful information for targeting specific potential
problem areas. The report was effective in noting adverse trends, and the
recommended corrective actions were appropriate and promptly
implemented.
4. The licensee recently implemented a program to solicit anonymous NSCP
user feedback on how well the process had worked. The licensee's analysis
of the limited results received as of the end of this inspection period were
appropriate, noting the need for additional attention to evaluation timeliness.
However, the employee feedback that the NSCP had not properly addressed
the concern raised was a more significant concern than evaluation
timeliness. In this regard, the inspectors observed that the NSCP procedure
does not require that concemed employees be provided a prompt initial
letter, which clearly documents the scope and character of the employee's
cor.cerns as understood by the licensee. The inspectors also determined that
NSCP status log timeliness data may not be fully accurate when a Worker
Concern (WC) is subsequently upgraded to a Nuclear Safety Concem. In one
instance (NSCP File 97-14) the concern was 78 days older than indicated on '
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the NSCP log, and in another instance (NSCP File 96 56) the concern was
62 days older than indicated.
5. The inspectors' review of NSCP files identified some instances of a lack of
thorough licensee follow through on employee concerns. The licensee had
not aggressively addressed all related aspects of an employee's concern,
which could compromise NSCP credibility. This finding underscored 9
feedback to the licensee from some NSCP users that their concerns were not
fully addressed. The following specific examples were identified:
a. The licensee's response to an employee's concern about airborne
alpha contamination (WC File 97-13) appropriately addressed why
alpha contamination was not a significant issue, from a radiological
risk standpoint, at San Onofre. However. the response did not focus
on the employee's additional concern that management had not done
a good job training Health Physics technicians and radiological
workers about why alpha contamination is not a significant concern,
resulting in a weakened trust of management. The employee clearly
stated a concem that managernent had underreacted to the alpha ;
concern in a manner similar to its previous underreaction to " fuel
fleas." Although, when interviewed, the employee was satisfied that
the concem had becn well addressed, and management had not
underreacted to the issue, the inspectors concluded that the ;
licensee's NSCP response did not thoroughly address the employee's l
stated management concern.
b. The licensee's review of an employee's discrimination concern,
involving nonsolection for a promotion (NSCP File 96-21), was very
thorough, with the minor exception that it did not fully investigate the l
potential for peer involvement in the alleged discrimination. In i
particular, the licensee had not interviewed some individuals in the
employee's work group who had been specifically implicated by the
concerned employee,
c. The licensee's evaluation of an employee's discrimination concern
(WC Ple 97-19) included a well-documented basis for its conclusion
that discrimination had not occurred. However, the NSCP file
included no evidence that the licensee had conducted an appropriate
followup review of the employee's concern that some foremen did not
fully understand procedure requirements and pushed production at the
expense of proper procedure compliance. The inspectors concluded
that the employee had cited a specific example of a procedure
compliance problem that the licensee had not specifically reviewed.
6. The inspectors considered that the licensee had performed an outstanding
job of documenting a thorough investigation of an employee's discrimination
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concern (NSCP File 96-51). However, the licensee did not have policy
guidance to ensure more careful NSCP treatment of potential
discrimination-related issues. In particular, the inspectors identified the q
following concems: I
a. Although not the sole basis for concluding that discrimination had not
occurred, the licensee's conclusion that the employee had not been 9
engaged in a protected activity drew too fine a distinction between i
" procedure issues" and " safety concerns." The NSCP did not
emphasize that all supervisors should clearly recognize that any
" procedure issues" associated with safety-related activities are
" safety concerns."
b. Although the NSCP file included thorough documentation of the
licensee's basis for its conclusion that discipline of the involved
'
employee had been appropriate, the inspectors noted that NSCP did i
not emphasize the need for greater supervisor sensitivity and
understanding of the implications and vulnerabilities associated with
discipline of an employee, who has raised a safety concern, for i
unprofessional behavior,
c. The NSCP file did not include documentation of the employee's
.=greement for NSCP referral of associated technical issues to his line
organization. Although the licensee indicated that such agreement
had been obtained, the inspectors determined that such agreement is
best documented.
7. The NSCP did not include any method for determining why an employee felt
compelled to use the NSCP rather than more routine problem identification
and resolution processes such as chain-of-command or the AR process. The
inspectors noted that, although a licensee must be careful about its approach
to obtaining this type of information, such information is of ten helpful to
identify potential chilling problems within its organization that would
otherwise go unrecognized.
c. Conclusions
The licensee implemented a comprehensive and well-functioning NSCP. The
licensee's process for NSCP self-assessment and its use of peer audits was well
focused and contributed to improved program performance. The licensee also
'
implemented a sound process for periodic reporting of program performance and
recommended actions to senior management. However, some opportunities for
broader-scoped evaluation and more formal acknowledgment of the correct
characterization of an employee's concerns were identified, as well as the need for
more careful consideration of potential discrimination issues.
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II. ' Maintenana
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, M1L Conduct bf Maintenance -
E LM151 S.eneral Comments
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' a. Insoection Scocel62707) 4 - ,
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, The inspectors observed all or portions of the following work activities:
.
' ' -* Saltwater cooling Pump 2MP114 pump and motor removal (Unit 2):
.
- - Instrument Air Compressor 2/3C002 and COO 3 troubleshooting ;
-
, . (Units 2 and 3) '
2- '
- - Main turbine trip' test (Unit 3)'
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- -- Saltwater cooling Pump 3MP113 motor installation (Unit 3) ;
Y .. .
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b. ' Qpaervations and FiMirig.91 l
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t The inspectors found.the work performed under these activities to be thorough. : All; '!
work. observed was perforraed with the work package present and in active use, t
, Technicians were knowledgeable and professional. The inspectors frequently
/ observed supervisors and system engineers monitoring job progress, and quality ,
control personnel were present whenever required by procedure. When applicable, i
appropriate radiation controls wsre in place. ,
-1
a
In additiorb see the specific discussions of maintenance observed in Sections M4.2
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and M4.3, below. j
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M1.2L General Cpmmants gn Syvejlia_ rice Activities -
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a. Ln.apardp_rtjcooe (617201
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The inspectors observed all or portions of the following surveillance activities:
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- - Containment. integrity. Verification (Unit 2),
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- Fire Suppression . Water' System 18-Month. Test (Unit 2) i
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Turbineidriven AEW Pump and Valve Testing (Unit 2)
-* - 1CEA Rod Drop Time Test (Unit 3) <
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- Engineered Safety Features Actuation System (ESFAS) Response Time Test
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c (Unit 3):
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- - Automatic Transfer of Reserve Auxiliary Transformer. Breaker to Unit
. ; [ 7 '
' Auxiliary Transformer Breaker for Bussesi 3A03' 3A07,3A08 and 3A09
,
7(Unit 3)-
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- Fire isolation Switch Testing for Emergency Diesel Generator (EDG) 3G002
f . Output Breaker, EDG Building Emergency Cooling Fan, EDG Fuel' Oil Transfer -
'
,L 1 Pumps 3P093 and 3P096 (Unit 3!
'
.C t.oss of Off-Site Power, With ESFAS Surveillance (Unit 3)
i i
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y b. Qbyervati_ons and Findinas . i
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The inspectors found eli surveillances performed under these activities to be H
- thorough. All survei!:ances observed weie performed with the work package - I
5
present and in active use. Technicians wers knowledgeable and professional. The ;
<
inspectors frequently observed supervisors and system engineers monitoringlob j
, , progress, and Quality Control personnel were present whenever required by '
. procedure. When applicable,' appropriate radiation. controls were in place.
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i: M4 Maintenance Staff Knowledge and Performance
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M4.1L Eailure to Properly Qp_uole CEA - Unit Q-
, a. Jngnection Scone (71707. 37551. 62ZQ21 )
The inspectors reviewed the procedures and a maintenance order (MO) associated
l'
with coupling CEA 91, and interviewed Maintenance and Quality Assurance
personnel.
b. Observations and Findinos !
i ,
- ~ Unit 3 was in Mode 3, preparing for reactor startup from the Cycle 9 refueling
'
outage. Operations and Station Technical personnel had observed, for CEA 91, aa
' unexpected lack of a dashpor effect during rod drop testing, a lack of nuclear
H
excore detector response uporimovement of the CEA,~ abnormal position indication
traces and current indications during rod drop testing, and problems'with setting the i
rod bottom and upper electricallimit indicstions. On June 20,1997, Station !
, . Technical, Engineering, and Maintenance personnel concluded that the extension
_
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shaft for Unit 3 CEA 91 was not coupled to its'four-fingered CEA.
6 l
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Unit ' operators cooled down and depressurized the RCS, ano on June 24/1997,
with the unit in Mode 6 and the reactor vessel head remcved, CEA 91 was found
^decoupled. . Maintenance personnel removed the old extension shaft and CEA 91, i
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crid couhed a new extension shaft and four-fingered CEA This new CEA was then
. lowered through the upper guide structure into the core, and the rebetor head was ,
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reinstahed.
1
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- The inspectors found that the identification of the uncoupfed CEA by Mainteriance,
. Engineering, and Operations, prior to core physics testing and reactor startup, was
- good, end. indicated good attention to various data points. $
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- Asjlocumented in NRC Inspection Report 50-361: 362/97-09,- CEA G1 had become
lodged against orientation guides in the extension shaft housing while the Fcensee '
. , was raising the CEA in order to pin it to the upper guidance structure (UGS) at the
'
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beginning of the Cycle 9 outago. As a result, the CEA had been replaced with a
,
partially spent CEA and 'a new extension shaft.
Four-fingered CEAa were not usually uncoupled during refueling operations, but l
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were normally pinned to the UGS and removed with the UGS. The licensee used ;
MO 9704212000 to install the new CEA and replace the bent orientation guides. '
4
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- Maintenance personnel inserted a partially spent CEA, coupled to a new extension
,
shaft, into the core. .Then the CEA was uncoupled and the extension shaft was 1
' removed. New guides were welded in place. Then the extension shaft was )
[ lowered, through the UGS, and was to be coupled to the CEA. j
Five-fingered and four-fingered CEAs were coupfert to their extension shafts by
,y locking pins that extended out from the shaft and locked into the interior diameter
7 of the CEA spider hub. The fingers were extended out by springs and locked into
'
-place by.a follower pin, Coupling verification was accomplished by raisMg the i
extension shaft about 3 inches and checking weight, by verifying the follower pin )
indication on the handling tool was correct, and by visually comparing the heights
. of the four-fingered CEAs.
I
When the licensee had attempted to couple CEA 91, the extension shaf t had i
. actually lodged between the spider hub and one of the four-fingered extensions on l
.
the spider. The extension shaft locking pins had extended and temporarily locked
'
the CEA to the shaft, such that the weight checks were satisfactory. Visual checks
p for height were also satisfactory, es they were performed by an individual ;
, , comparing heights of the four-fingered CEAs without measurement, with one ;
four-fingered CEA on each outer quadrant of the core and not adjacent to each j
other. When the CEA was subjected to the movement caused by either the control I
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t
element drive mechanism, or by rod; drop testing, the CEA became decoupled.
Procedure SO231-3.34,.TCN 2-2, " Reactor - Remote Four Finger CEA Removal and
[ Reinstallation," contained instructions for decoupling and recoupling four-fingered
-
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'CEAs, with the CEA renioved from the core and both in the upender can and in a
L stand in the refueling cavity.' A caution on page 4 of Procedure S023-1-3.46,
L, ,
Revision 1, " Reactor - Reactor Remote Five Finger CEA Extension Shaft Coupling,"
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stated that the four-tingered OEAs were not normally coupled, and referred the
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Jeader to Procedure 3023-1-3.34 if coupling was required. MO 9704212000 had
planned the work such that the CEA would be coupled while in the core.
Consequently, any type of visual verification of the coupling was limited, and the
use of the stand and the upendor can to facilitate the process was not done. The
MO planner had developed this sequence of coupling, with Step 12 of tiie MO
-directing that the five-fingered coupling procedure be used to couple the CEA. This
was directed because it facilitated replacing the orientation guides and aEgning ?,he t
fingers of the CEA in the lower core support plate. An alternative plan, that coupled
the CEA per the four-fingered procedure, could have been developed. Essentially,
the difference in the procedures was that five-fingered CEAs were coupled while in
the ccre, and four-fingered while outside the core. Five-fingered CEA locations had
guides to facilitate the extension shaft aligning to the spider hub, but four fingered
CEA locations did not-
Procedure SO23 I-3.34, TCN 2-2, Step 6.1.30, directed that four-fingered CEAs be
coupled to ertension shafts in the upender can (in the refueling cavity) and that an ,
underwater camera be used te verify proper shaft and hub alignment. Step 6.1.32
directed, after coupling checks, placing the CEA and extension shaft in the
extension shaft holder on the side of the refueling cavity. Step 6.1.39 directed
changing a short gripper tool to a icog gripper tool. Step 6.1.45 directed that the
, CEA and extension shaft be lowered through tt.e upper guide structura into the core
using a long gripper tool. Refueling personnel actually lowered CEA 91 into the
core coupled to an extension shaft. Then the extension shaft was uncoupled and
removed from the vessel. Subsequently the extension shaft was coupled to the
- CEA again, with the CEA in tne core. This was performed without the use of an
underwater camera to verify proper alignment.
Procedure SO123-1-1.7, TCN 5 3, "MO Preparation and Prccessing," Step
S.3.3.1.1, stated that, for important-to-safety Mos, procedures that apply to the
maintenance activity performed shall be used. Step 6.3.7.1.1 of this same
procedure stated that vendor information shaji not be used in lieu of a station
procedute. Mor wcw originated by maintenance plantiars and reviewed by Station
Technical engineers, whereas sta: ion procedures were reviewed and approved by
2
cognizant division managers. The inspectors found that these requirements in the
licensee's program demonstrated that tFs intent was to use procedures already
known to accomplish activities. The licensee actually ured an MO fer an evolution
that had not been previously performed Icoupling a four fhigered CEA while the CEA
was in the core). The licensee had a procedure in effect to perform the evolution
{ coupling a four fingered CEA while the CEA vas in the upender) that had been
performed successfully befare and that could have been used, if the activity had
been planned differently.
This item is unresolved pending the inspectors' review of tha licensee's root cause
evaluation (URI 362/97012 01).
1
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c. 9JLg,glosions
Engineering, Operations, and Maintenance personnel demonstrated good attention
to ininrm ttion and diagnostic techniques in identifying that CEA 91 was uncouplad.
An unsesolved item was identiftsd to review she licenses's root cause
determination.
.
M4.2 AFW Pgmo Turbine Gove.rnar Valve AdiustmaD.; - Unit 316270Z1
On June 16,1997, the inspectors observed Maintenance technicians t.se portions
of Procedure S0231-5.79, Hevision 3, "AFW Turbine Governor Valve inspection,"
Section 6.3, as directed by Work Order 97061068 to reassemble and adjust the
AFW pump turbine governo: valve. The technicians used good self-checking and
cross-checking practices whea performing the procedure steps and accurately
obtained the required clearance measurements acceptance criteria. The technicians
displayed a detailed knowled0e of the maintenance procedure and AFW governor
valvo components. The inspectors concluded that the technicians demonstrated
excellent maintenance work practice.
M4.3 RCP Oil Colfgpfip.a System - _UriL;l
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a. 10apistion Scop _e.d37651&?MZ1
The inspectors performed a walkdown of the RCP oil tollection syste.n and
reviewed the work orders that rnodified the oil collection syatam.
a
b. Qbaryftlong
On June 10,1997, the inspectors performed a walkdown of the Unit 3 RCP oil
ecliection system (Seitmic Class 1) with a Station Technical engineer and identified
that three Allis Chambers RCP motors were each missing the nuts from four studs
that attached lube oil collection drip pans to the motors. In addition to the four
studs attached to the RCP motor housing, the oil collection pan was designed to be
held in place with four bolts. The inspectors informed the engineer of the
discropancy. The eng:neer informed the construction personnel perforrning the
modification about the missing nuts and the condition was corrected the following
day.
'
The work orde s associeted with the modification indicated that, on May 5,1997,
an electrician loosened and repositioned the oil collection pena to allow for the
installation of additional oil collection berms. On May 16, a dif ferent electrician
.
rehstalled the oil collection pan. The electrician did not observe the four stu;is
' without nuts, and with concurrence from the job foreman, used the additional nuts
to double nut the remaining four bolts. The electrician and foreman f ailed to
recognize that four studs holding the oil collection pans to the RCP motor did not
have plan required nuts on them.
,
_ _
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On June 5, a NEDO engineer performed a walkdown of the completed
modificadons. The engineer failed to recognize that the nuts were missing, and
Signed the construction work order step as having been completed. The inspectors
questioned the engineer utout the parformance of the walkdown. The engineer
indicated that the focus of the walkdown was to verify completeness of the actual
modifications to the system and not to verify that the interferences associatud with
the modification were properly re-installed. The inspectors considered this a missed 3
opportunity to identify the discrepancy and inconsistent with Engineering
managornent's expectations.
The licensse's program required that a postmodification walkdown be performed by
the system engineer before the f;re impainnent could be closed. The walkdown had
,
not yet been performed. I
The licensee performed several correctivo actions in response to th9 problem. The
craftarnan and field engineers involved were counseled ir, regards to the importance !
of thoroughly detailed work practices and walkdowns. The licensee planned to
'
change the construction wcck order procedure to include a double verihcation
signoff for removal and reinstallation steps of interfering components and to require
a nuclear construction engineer signoff that the associated work has been walked
, down. The licensee planned to perform training for all construction personnel
regarding verification of reinstallation of intarfering components and performing
thorough walkdowns. The licensee planned to initiate training for foramen on tne
importance of having a questioning culture and raising questions to the field
engineer. In addition, the licensee performed a calculation and determined that th9
oil collection pans would remain intact and capable of perfonning their designed l
c
functions durmg a seismic event with tha four nuts missing. l
The failure of the electrician to follow the construction work order and reinstall the
oil collection pans in accordance whh the work order requirements was a viclation '
of TS 5.5.1.1.a. This failure constitutes a violation of minor significance and is I
being treated as a noncited violation, consistent with Section IV of the NRC l
Enforqenent Policy (NCV 362/97012-02). !
l
C. QogQJhtfdQgf[ J
Construction craftsman and engineering personnel missed opportunities to identify
, the missing RCP cil collection pan nuts and revealed an insofficient sensitivity to
identifying and correcting material condition problems. The licensee's corrective
> actions were thorough and detailed. A noncited violation occurred as a result of not
, following the construction work order requirement to reinstall the oil col lection pans.
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, I 8- Miscell'aneous Maintenance issues (92700, 92712)
L
o M8.1L LQJosed) LER 361/07-005-9Q:' RCS leakage - shutdown cooling system valve -
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packing leakoff plug.- ,
V j This LER was voluntarily submitted. :The issue was previously discussed in ie :
V- -
Inspection Report 50 361;362/97-05. No new issues were identified in the LER. 3
Q M8.2 IQlqu$ LER 36lLQ7 007-00: missed surveillance test for the containment purge- ,
exhaust radiation monitors.
I
,On April 3,1997, the licensee identified that, between January 23,1989,and'
, .m 'Jenuary 2,1990, the outside containment main and mini purge valves were not J
A% always verified to isolate the containment purge exhaust pathway as required by
, N" the quarterly functional test. The time frame of the situation was from ihe time the
.
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Surveillance procedure revised the test methodology until the requirement Was
,
i
removed from TS. Subsequently, the licensee corrected the procedure and tested
d the valves. ,
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. The licensee determined thrst improvements made subsequent to the 1989 event.. 1
i; J strengthened the process' for revising the surveillance test procedures to the extent i
.that further program enhancernents were not required. The licensee concluded that
'
tho' safety significance of the missed surveillance was minimal since the valves were i
i periodically stroked during the inservice testing program and would have' closed if l
$ required. -
g The inspectors concluded that the licensee's corrective actions were appropriate.
i. 4The failure of the licensee to perform the surveillance test is a violation of TS. This
"
nonrepetitive, licensee identified and corrected violation is being treated as a l
[ noncited violation, consistent with Section VILB1 of the NEC En.fomment Pohcv ;
4 (NCV 361/97012 03). ,
L I
h M8.3 [Q1gs_pdLLW 50-3Q1/97-Q06-QO: missed surveillance on reactor protection system
[ operating bypa.ss functions,
..
! .On March 19,1997, during Generic Letter 96 01 review, the licensee identified that' I
y '
. the verification of automatic bypass removal function for the core protection )
F calculatar trips for departure from nucleate boiling ratio and local power density was i
3 not performed. As allowea by Surveillance Requirement 3.0.3, the licensee
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prepared a surveillance test for the missed functions and completed the test within ;
Q.1 p- v the alloved time interval. j
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Y , The license $ determined that the surveillance omission had existed since the ]
- A ' applicable. survoillance procedureSvas initially draf ted in 1982 and, due to the
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, , ipessage. of tirne, the specific cause of the omission was not identified. The licensee
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- planned to, revise the appropriate plant procedures to incorporate the testing"of all
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' operating bypass functions prior to the next required surveillance. The licensee
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noted that during reactor startup the operators manually remove the operating
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bypasses forLdeparture from nucleate boiling ratio and local power. density. ;if the.
1 c operator did not perform the action, reactor power'could be increased above IE-4,' ]
gg , but the plant would tripLwhen the bypasses were automatically removed.
.. ,
L TNe inspectors conclu'ded that the licensee's corrective actions.were appropriate. ^
4 '
," . The licensee's identification of an omission in testing reactor protection system
~
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operating bypass functions was an example of thoroughness'in the review of
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' system testing by NEDO pursuant to Generic Letter 96-01. The failure of thel .j
licensee'to' perform the surveillance test is a violationfof TS.-Thic nonrepetitive,
,y. '
.i: licensee ide'ntified and corrected violation is being treated as a noncited. violation, ;
f ' ' consistent with Section Vll.B1 of the NRC Enforcement Policv j
- #
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-(NCV 361/97012-04).
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b M8 4 (Closed) Onresolved Jarn 361: 1421R7006-04: failure to perform a required TS
Lsurveillance requirement for the containment purge exhaust radiation monitors and
, failure to report the condition within 30 days as required by 10 CFR 50.73(d). .
f ,
The licensee documented the missed TS surveillance requirement in .
-)
- LER 361/97-007-00. The insoectors reviewed and closed the LER in Section M8.2.- j
f v . . . <
g , . On April 3,-1997, the inspectors questioned the licensee about the reportability of
.u ' th's missed surveillances. The licensee agreed that the event was reportable and
P L' lssued I.ER 361/97-007 00 on April 23., On July 2, upon further review of the
7 < reportability issue, the licensee identified.that en January 24, a Station Technical
ij engineer had knowledge that a TS curveillance requirement had not oeen met.
m:
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F< The licensee identified and planned to' address several weaknesses that resulted in
k q missing the reportability classification of the event.' The AR description did not
- properly state the problern, and ARn did not have a feedback process to reassess
%o f reportabikty. Communications between Compliance and Station Technical
by venglneering on reportability did not properly address the issue.
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The failure of the licensee to submit a LEP. within 30 days of discovery of a
[
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" reportable event is a violation of 10 CFR 50.73(d) (Violation 361; 36.2/97012-05).
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Ill. Enaineering
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E1 Conduct of Engineering ;
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E1.1 Sorav Valve Bellows Leakoff Line - Units 2 and 3
a. Insnection Scooe (37551,71707) I
l
The inspectors questioned operators regarding the status of the spray valve bellows '
leakoff line and discussed the discrepancies of the Unit 2 bellows leakoff line with ;
Station Technical engineering. I
b. Qhervations and Findinas
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On April 22,1997, the inspectors questioned the Unit 3 operators about the status
of the spray valve leakoff lines. The inspectors and operators reviewed
Drawing 40111D, Procedure 8023-3-1.4, " Filling and Venting the RCS? and
Procedure SO2315-50.A2, " Alarm Response instruction," and concluded that the
leakoff lines were installed; however, the operato's exhibited reservations about the
actual status. Further review by the licensee confirmed that Unit 3 leakoff lines
were installed with the bellows failure alarm and the packing leakoff temperature
indication. However, the Unit 2 alarm and temperature indication were not active,
even though the drawing and procedures indicated they were. The licensee initiated
an AR to evaluats the problem and an operability assessment that concluded that l
the Unit 2 spray valves were operable.
l
In 1995 the licensee issued an FCN to remove the bellows assembly from the Unit 2
spray valves and installlive load packing. The FCN also disconnected the
thermocouples and the pressure switches, and removed the control room
annunciators. The thermocouples and pressure switches were temporarily
abandoned in containment. During the recent outage, under a new FCN, the
I!censee instal!ed an improved pressure bellows design and mechanically
reconnected the sealleakoff lines as well as the thermocouples and pressure
switches. The licensee deferred the electrical portion of the FCN until after the
outage. On February 8,1997, a Station Technical engineer performed a walk down
of the FCN end signed off the FCN as being complete, which subsequently led to l
the updating of control room drawings and procedures, j
On May 6,1997, the licensee performed the electrical portion of the modification
and, therefore, completed all aspects of the FCN. The licensee planned to provide
Station Techr>ical engineers with training regarding the expectations for FCN
walkdowns, acceptance activities, and followup documentation.
10 CFR Part 50, Appendix B, Criterion V, states, in part, that activities affecting
quality shall be prescribed by drawings appromiate to the circumstances. Contrary
to this, Piping and Instrumentation Diagram 401110 did not reflect the actual plant
i
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19
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configuration. This failure constitutes a violation of minor significance and is being '
. treated as a noncited violation, consistant with Section IV of the NRC Enforcement
Eqligy (NCV 361/97012-06).
- c. Conclusions i
,
. . A Station Technical engir.eer perform 6d an inadequate walkdown of an FCN, which, %
subsequently, led to the implementation of inaccurate control room drawings and
'
procedures and resulted in a noncited violation.
E1.2 Charoino Lspo iniection Chggk Valve Deficienciqs - Units 2 and 3
. a. jns_pffdion Scone (71707 and37551)
1 .
4- :( The inspectors monitored ficensee actions in response to the licensee's discovery j
$ that some charging system check valves were not prope*iy functionmg.
e l
b. Dhservations and Findinos
,
'
LOn June '26,1997, opurators in Unit 3 placed auxiliary spray in servics. Because
the charging loop injection isolation valves were open in a parallelinjection path, the
operators did not expect appreciable auxiliary spray flow. However, pressurizer
pressure decreased unexpectedly, even with all available pressuriter heaters
,
anorgized. Five of the 30 pressurizer heaters were not evailable. Operators initiated
,
an AR_for NEDO to review the adequacy of the pressurizer heaters.
, The charging system includes two parallel charging paths, to RCS Loops 1 A and
~
, 2A, arid a parallel auxiliary spray flow path. Each path comes from a common
'
charging header and contains a motor-operated isolation valve and a check valve.
The auxiliary spray flow path is about 20 feet higher than the charging injection
c flow paths.
.
NEDO revievved the configuration and determined that the heater capacity was
- adequate, nad that there should not have been any auxiliary spray flow until the
p charging loop isolation valves were throttled. Further review identified that the
' check valves were not identical, in that the 2-inch Kerotest spring-loaded check
vatves in the auxiliary spray line (Valve 3MUO19) and in the charging injection flow
. path to Lo'op 1 A iValve 3MUO21) contained springs rated at approxirnately
- . 2.3 pounds, and were not the valves originally installed. The Loop 2A charging
1
injection check' valve 1 Valve 3MUO20) wes the originally-installed valve with a
20-pound spring.
[H . Section 6.3.3.3.1 of the Updated Final Safety Analysin Report describes the safety
injection system assumptions for the small break loss of-coolant accident analysis.
lThis section states that the injection flow from the charging pumps is credited in the
f' small break loss-of-coolant accident analysis for both units, with a value of
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20
s
. 36.2 gpm assumed as the injection flow rate of one charging pump. For a reactor
coolant pump discharge line break, the analysis credited 44 percent of the flow
,
,
from one charging pun p,' or 15.9 gpm, with the remainder of the flow going to the
.
1 faulted loop. The licensee performed a test in Unit 2 and. determined that the flow
split was not within the bounds of the analysis. Furthermore, the licensee found
, that most of the flow was through Valve 2MUO20, which had the heavier spring.
.
This result was unexpected. 3
i
The licensee determined that the same check valve configuration existed in Unit 2,
which was operating at 100 percent. The licensee determined that the charging
pump contribution to the safety injection flow was only required when initial reactor
power was above 95 percent, and on June 26,-1997, lowered Unit 2 reactor power
to 90 percent pending further review. Addition 61ly, the licensee entered TS Limiting
' Condition for Operation 3.5.2, Condition A, for one or more traina of the emergency
ccre cooling system being inoperable and total available injection flow being
~
- equivalent to that of a fully operable train.
'
The licensee performed testing in Unit 2 on June 28-29,1997, and determined that
, a flow imbalance anomaly similar to that in Unit 3 also existed in Unit 2, with most
of the flow passing through the check valve with the heaviest spring.
- During.a conference call with NRC personnel on Juna 27,1997, the licens%'s Vice
President, Nuclear Generation, stated that if the flow imbalance could not be
resolved, Unit 2 would be shut down. The licenses made attempts to balance the
<
flow by adjustirig the position of the charging loop injection ico;ation valves, and
,
determined that the flow could not be balanced by that method without developing
too much backpressure in the system. On June 29,1997, thn licensee abandoned
-efforts to correct the flow balance and initiated a shutdown of Unit 2 in cecordance
with TS Limiting Condition for Operation 3.5'.2.
>
Additional examination of Va;ve 3MUO21 showed that the disc was slightly cocked
and hung up, prevent!ng full opening. The same condition was found in
-
Valve 2MUO21. The licensee removed Vabe 3MUO21 and replaced it with a
qustified check valve. Additionally, the !icensee performed a flow balance test in
Unit 3, resulting in adjusting the limit switches in tne rnotor operator for the
l
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isolation valve associated with Loop 1 A,in order to achieve the proper balance.
- The licensee also replaced the intemals of the auxiliary spray'line check
i Valve 3MUO19 with a stronger spring and a thicker disc. The th;cker disc was
intended to precludc, cocking from cansing the disk to hang up,
- The licensee replaced the internals of the affected Unit 2 valves,2MUO19 and
-
2MUO21,'in aiepair similar to that c,f Valve 3MUO19. ' Valve 2 MOO 21 did not pass
its postmodification tests and tbs condition was being reconsidered at the end of
,
this inspection period,
,
6
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t.- .
21
The licensee intended to review the procurement of the check valves with the - ,
Sghter springt.,'which had been supplied as equivalent to the original valves. The
licensee also determined that TS 3.5.2 had been violated in both units, in that the
as found condition existed during plant operation for a period longer than allowed by
TS 3.5.2. The licensee intended to submit an LER reporting this issue.
i
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A review of'the procurement and postmodification testing associated with the
instal!ation of the valves containing the lighter springs will be conducted in a future
,
- inspection. The inspect'o r will also review the
- significance of the potential violation i
of TS 3.5.2 as an unresolved item (URI 361;362/97012-07).
c. Conclusiong
>
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The licensee's identification of the charging system check valve flow imbalance and j
the resultant technical review and initial corrective actions were excellent. The
'
'
decision to shutdown Unit 2 was conservative. An unresolved itern was opened to )
'
, review the safety significance of the condition and to review the procurement and I
postmodification testing activities that led to the condition. <
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! !
E2 Engineering Support of Facilities and Equipment .!
E2.1 Mainte. nance Rule imolementation
,
a. Insoection Scu.p3 (71707. 37551) ,
<
1
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The in'spectors reviewed the Unit 2 control operator logs for May 7,1997, and
conducted foilowup inspection and reviews associated with a change in the i
electrical alignment of the swing charging pump, Pump EP191.
1
The inspectors reviewed 10 CFR 60.65, " Requirements for Monitoring the j
Effectiveness of Maintenance at Nuclear Power Plaats;" Maintenance Policy j
Guide SO123-G 31, Revision 1, " Utilization of me Safety Monitor in Support of ;
Work Control;" Operations Desktop Guida,Section V, " Safety Monitor;" and l
NUMARC 93-01, " Industry Guideline for Monitoring the Effectiveness of
Maintenance at Nuclear Power Plants." In addition, the inspectors interviewed l
- Operations and Nuclear Safety Group personnel. i
b. .Qbservations3nd Findinag.
On May 7,'1997, at 12:48 a.m., Train B EDG 2 GOO 3 had been declared inoperable
for failing a monthly surveillance. This was the Train 8 emergencv source of power.
-
, At 4 a.m., the operators declared Charging Pump 2P191 inoperable. They then
transferred the power supply from Train A to Train B and declared the charging
pump operable again.
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Unit 2 had a total of three charging pumps; the 't rain A and B pumps were operable
thraughout. This power supply shift was done'in preparation for chemical and
volume control system testing to be performed later that day.
The swing charging pump remained powered from Train B for the assentially 3 days
that EDG 2G003 was inoperable. The inspectors were concerned because the
swing charging pump had been transferred from an operable power train to a power '
train without emergency power, which was a less reliab;e plant configuration.
.
The inspectors questioned the Nuclear Safety Group parsonnel regarding the
increase in core damage risk, and were informed that, per probabilistic risk
asnestment, there was negligible increase in risk when the swing charging pump I
was on a less reliaole power supply. The inspectors considered, however, from a
deterministic sense, that risk had increased. The inspectors also determined that
there was no reason to have the pump.on Train B to perform the chemical and
volume control system flow testing.
10 CFR 50.65 and NUMARC 03-01 both stated that, in performing monitoring and
maintenance, an assessment of the effect on safety should be parformed.
NUMARC 93-01 also stated that this assessment should be reviewed prior to
tsctually performing the evolution. The inspectors noted that the Maintenance policy
guide and the Operations desktop guide both stated that personnel should assess i
emergent work in terms of the additional risk. However, operators implementing
the risk-evaluated work plans did not routinely reevaluate risk when emergent
failures occurred, or prior to implementing the plan, as in the situation described ;
above. i
The licensec was implementing on-shift capability to evaluate risk, using the shift
technical advisor to check current inoperabla equipmeat. This was being
implemented because maintenance plans were evaluated for risk for a given set of I
anticipated equipment available. The check would ensure that the risk was I
acceptable, given actual plant conditicas, which may have changed from the
previously evaluated anticipated equipment available. The inspectors considered
this a good addition to the use of probabilistic risk ossessmerit.
The licensee continued to use its Safety Monitor to assess the risk of planned
equipment outages and actual plant configuration.
c. 9.RDEl y siran g
Operations personnel had not been routinely evaluating risk associated with
implementing msintenance plans, if plant configuration was act as anticipated by
the plan. This was a weak. ness in implementation of the 10 CFR 50.65; however,
the licensee was correcting the weakness.
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o E2.2 10 CFR Part 21 Reoort Review
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I
a. Insoection Scone (37551) 1
-The inspectors reviewed the licensee's response to a 10 CFR Part 21 report initiated
by Arkansas Nuclear One.
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b. Observations and Findinas j
l
On May 19,1997, the licensee's Independent Safety Engineering Group and NEDO received an Internet notification that Entergy, the licensee for Arkansas Neclear One
Unit 2, intended to file a 10 CFR Part 21 report regarding an unacceptable i
single-failure condition that would result from placing one channel of the
l recirculation actuation signal (RAS) circuitry in a tripped condition. During the
injection phase of an inside containment high pressure transient (loss of coolant
accident or main steam line break accident), a spurious RAS was determined to be
unacceptable. The licensee documented its evaluation of this condition in
AR 970501476. The licensee determined that the reported condition was also
unacceptable at San Orofre, and initiated corrective actions, including revising
Operations procedures tt, disallow placing the RAS channel in a tripped condition.
On May 22,1997, the licensee determined that a similar unacceptable single failure
condition would result in the emergency AFW actuation signal (EFAS-1 and EFAS-2) i
circuitry. During a main steam line break or feedwater line break, a single failure
could result in a premature AFW initiation, or initiation of AFW to the wrong SG, if
, one channel of the oifferential pressure parameter was in a tripped condition. The l
licensee's evaluation of this concern was documented in AR 970501670. I
!
NEDO initiated a high-priority evaluation, and assigned a dedicated engineer, to
review all the safety-related four-channel logic to identify any other similar
vu!nerabilities.
c. Q2nclusiom
independent Safety Engineering and NEDO were very prompt and thorough in I
responding to the 10 CFR Part 21 notification.
E2.3 MaiaContainment Purae hghtign l Valve Failure - Unit 3
a. _ JE2Dectipn Scone (37551) l
The inspectors reviewed 'AR 970400691, which contained the root cause
assessment for the failure of the Unit 3 containment main purge isolation valve to !
open.
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b. Observations and Findinas
On April 14,1997, Unit 3 operators attempted to open containment purge exhaust
,,
Unit A060 Isolation Valve 3HV9950, in. order to establish a main purge of Unit 3
.
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7
l containment. The valve failed to open and the power feeder breaker tripped open.
F
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Station Technical personnel later determined that the motor stator windings .had
- become loose, and had become bound on the rotor cooling blades with consequent a i
'
insulation damage to the stator winding. This caused an overcurrent condition
which tripped the breaker open. At some time prior to the attempt to open the '
( . valve on April 14,19977the dacron ties that held the stator windings in place had ,
! ,
melted, indicative of a high temperature condition caused by the motor stalling. 1
3 Valve 3HV9950 was a 42-inch butterfly valve located inside containment, and was
'
one of two containment isolation valves for the main purge system. The valve'was'.
. included in the Generic Letter 89-10 program and was operated by a Reliance
- 3.2-horsepower Class B motor attached to a Limitorque actuator. The cognizant
engineer stated that Class B motors were acceptable for the application per i
i Limitorque (the vendor) guidance. Motors were not visually inspected internally j
i ~ during routine preventive maintenance, or during Generic Letter 89-10 testing. J
'
, Maintenance personnel replaced the damaged motor with a Class RH Reliance
i
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' motor. Class 8 motors were rated for 130*C temperature and Class RH were rated
for 180*C temperature.
I The licensee planned on replacing the other Unit 3 main purge isolation valve motor
(3HV9949), and both Unit 2 main purge isolation valves motors (2HV9949 and '
2HV9950), with Class RH motors at the next opportunity. The licensee also
p removed an access cover and visually inspected two other Reliance Class B motors
used on safety-rented valves, and found no similar problems. The licensee
postulated that, sometime in the past, the valve motor had stalled long enough to
melt the dacron windings, but not long enough to damage the aluminum stator;
L normally the case for a high temperature failure of a valve motor. This would have.
been a motor stall for about 8 to 15 seconds. The licensee also believed that the
F
location, the horsepower-to-frame-size ratio, and the large unseating torque required
e
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- for large butterfly valves, made Valve 3HV9950 susceptible to this failure
mechanism, and therefore, that 'other Class B motors would not be susceptible.
c. Conclusions
4
.
The licensee's root cause assessment was thorough. Licensee actions in response
to the failure were appropriate,
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E2.4 SG Eco Crate Sucoort Dearadation - Unit 3
a. Inspection Sggpe (37551)
During the Cycle 9 refueling outage for Unit 3, degradation of portions of several *
egg crate supports was identified in both SGs. The degradation was noted during
-prechemical cleaning assessments of the condition of the egg crate supports. %
b. Observations and Findinas
The licensee performed a comprehensive inspection of the internals of both Unit 3
SGs following chemical cleaning and confirmed the degradation was primarily
limited to the upper egg crates and was confined to their peripheral portions. To a
lesser extent the stay cylinder, blowdown lane areas, and cold leg portions of the
egg crate periphery were also affected.
The licensee concluded that the degradation was caused by a form of flow
accelerated corrosion (FAC), a general term describing processes which use
assistance from fluid flow to remove the protective oxide layer from base material.
Removal of the protective oxide layer exposes the base material to the fluid q
environment allowing further material removal via corrosion and/or erosion I
processes. The licensee believed that the FAC occurred during recent operation of I
Unit 3 as a result of SG secondary sido fluid parameter changes caused by the
buildup of deposits on the SG tubes. By using chemical cleaning processes to
remove the deposits, the licensee considered FAC to be arrested, and that no i
further.significant degradation of the egg crate supports will occur. For
conservatism, the licensee committed to perform a special midcycle inspection on ,
Unit 3 to verify that no further degradation is occurring in the egg crates. l
The licensee performed an extensive reanalysis of the egg crates in their degraded
condition, and submitted the results of their analysis in a letter dated June 5,1997.
The analysis results were acceptable for all normal and accident conditions.
Although excessive flow-induced vibration has not occurred, the licensee
conservatively plugged about 115 tubes in the two Unit 3 SGs to increase the
structural margins of the tubes. Internal stabilizers were added to each affected
tube prior to plugging to ensure tube vibration would not affect adjacent inservice
tubes. Although no indications of egg crate degradation were observed during the
prechemical cleaning assessments of the Unit 2 SG internals, the licensee has
committed to perform video inspections of the Unit 2 egg crates during its midcycle
outage, if warranted by the final cause assessment of the Unit 3 condition.
The licensee performed a 10 CFR 50.59 evaluation of the Unit 3 egg crate tube
supports in their present degraded condition, and concluded that no unreviewed
safety question existed. The NRC has selected this 10 CFR 50.59 evaluation to
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review as part of its normal review process of licensee's 10 CFR 50.59 programs.
_ _ _ __ _ . _ _ -. _ __- __. __ ._ _ _ . _ _ _ _ _ _ .
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On the basis of its review to date, the NRC staff had not identified any deficiencies ' '
in the licensee's shalysis of the adequacy of the egg crate supports. '
i
. c c. : Conclusions- ,
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The licensee's efforts to resolve the degraded egg crate condition were excellent.
! The licensee thoroughly inspected the Unit 3 SG internals to quantify the extent of
'
'
- degradation, and developed a comprehensive strategy to identify and address all i
'
' relevant technical issues related to operation of Unit 3. The licensee provided
~
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extensive technical support for the meetings held with the NRC staff, and provided -
J -- timely and accurate responses to NRC staff questions on this issue.
2 E2.5 - Soent Fuel Pol (SFP) - Units 2 and 3 ,
e
{ a. Insoection Scone (37551)
,
=The inspectors reviewed portions of the design basis for both the Unit 2 and Unit 3 ,
'
SFPs, as described in the Updated Final Safety Analysis Report, Section 9.1, " Fuel l
- ' Storage and Handling." .The inspectors also reviewed portions of operating ]
i procedures for the SFP, and interviewed cognizant engineers. '
b. Observations and Findinas
- The SFP dimensions are aa follows
"
Fuel Transfer Pool (FTP): Length 8 feet 3/8 inches
Width 23 feet -
Depth 46 feet
'.SFP: Length 44 feet 3/8 inches
- -Width 23 feet-
- Depth 46 feet
,
Cask Storage Pool (CSP)i Length 12 feet
- Width 23 feet-
' Depth 46 feet
2-
Concrete walls, approximately 18 feet high'(from the bottom of the SFP), divide the
total pool into three sections. The SFP is separated from the FTP by a gate with a .l
r nonsafety-related inflatable rubber seal; the other side of the SFP is separated from. 1
F
. the CSP by a'similar type gate. The FTP contains the' opening from the fuel transfer -
tube into' containment. The fuel transfer tube is isolated from the refueling cavity in ;
- containment by Valve 2/3MUO10 on the FTP side, and by a flange on the !
containment side. Neither the rubber. seals or the spent fuel handling machine are - !
' seismically qualified. j
e
a. _, -
._____ _---__ -_
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27
One design basis of the SFP is to maintain 8% feet of water covering the active fuel
of any fuel assembly raised in the spent fuel handling machine. Another design
basis is to maintain 23 feet of water above the fuel in the SFP storage racks. The
inspectors observed that, if the FTP and CSP were dry with the gates instalied, and
if the SFP were completely filled, then a failure of the rubber boot seal between the
FTP and the SFP would cause level in the SFP to drop approximately 7.3 feet. In
'
this situation, the 8%-foot design basis would not be maintained during fuel
movement in the SFP. By procedure, licensee actions in this case would be to
lower the fuel assembly to a safe location. As the assembly was lowered, the
8%-foot design basis could be maintained, depending on the rate of level drop. In
response to the inspectors' concern, licensee personnel initiated an equipment
defic;. icy mode restraint against moving fuel in the SFP unless the CSP was full
and the gate between the CSP and the SFP was open. The licensee later
incorporated this restriction into procedure. The design basis of the SFP did not
encompass a simultaneous failure of a rubber seal and the spent fuel handling
machine. The inspectors found that the licensee was, consequently, conservative
in responding to the inspectors' concern.
The licensee had previously analyzed a scenario in which the FTP was dry and
cross-connected to containment via the transfer tube. The licensee made l
procedural changes to prevent a failure of the rubber seal from causing levelin the l
SFP from lowering to the level of the approximate 18-foot high concrete wall. ;
Opening Valve 2/3MUO10 was procedurally prohibited unless water level in the
refueling cavity and the SFP were the same,
c. Conclusions
The licensee was conservative in responding to the concern that simultaneous
failures could cause a loss of design function of the SFP.
E8 Miscellaneous Engineering issues (92903,92712)
E8.1 (Closed) LER 361/96-010-00: containment escape hatch not closed while
performing core alterations.
On December 10,1996, the licensee identified that the emergency escape hatch
door outer pressure equalizing valve (PEV) was open, providing a 3/4-inch direct
access from containment atmosphere to the outside atmosphere, as a result of the
door having been temporarily modified to support SGCC. Although no fuel
movement occurred during the time that containment closure was not maintained, j
CEAs were uncoupled and weighed (a core alteration) and, therefore, the i
requirements of TS 3.9.3.c were not met.
Upon discovery of the open PEV, the licensee suspended core alterations and
plugged the PEV's flow path, in addition, the licensee performed a leak test of the l
SGCC fixture and the emergency escape hatch. The licensee concluded that the l
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safety consequence of the event was minimal due to the lack of containment i
pressurization potential during refueling and the small size of the opening. I
l
The licensee initiated an AR and an event report to evaluate the incident. In I
addition to the corrective actions indicated in the LER, the licensee planned to: j
"
- train NEDO personnel and SGCC personnel on the importance of the review -
of operational impacts associated with design changes: 1
l
- train NEDO personnel on the temporary modification process;
- train equipment control personnel, stressing that all restraints to a specified
mode need to be addressed during the work authorization request evolution I
and on the engineering deficiency mode restraint; and
1
- train nuclear construction personnel on the importance of communicating )
test results to appropriate organizations when expected results are not l
obtained. I
The inspectors concluded that the LER was self-critical and that the planned
corrective actions were appropriate. The failure of the licensee to maintain the
required containment penetration closure is a violetion of TS 3.9.3.c. This
nonrepetitive, licensee-identified and ccrrected viuiation is being treated as 3 l
noncited violation consistent with Section Vll.B.1 of the NRC Enforcement Policy
(NCV 50-361/97012-08). ;
l
E8.2 (Closed) Violation 361/97002-02: failure to follow SG in-situ testing procedure. !
l
The inspectors reviewed AR 97010161 and the licensee's response to the violation. ;
in a letter dated May 5,1997, the NRC responded to the licensee's April 14,1997, i
violation response letter. NRC did not agree with the licensee's assessment of the i
safety significance of the event and did not share the licensee's confidence that the
procedure error would have been identified prior to re+.urning the SG to service.
Further, the view that the violation was an isolated contractor personnel error was
not consistent with the inspectors observation that a site technical supr, art engineer
was actively involved in the process. In addition, the licensee's AR concluded, in
part, that the test was being observed by a site technical support engineer who
should have been knowledgeable enough in the procedural requirements to have
noted the discrepancy between the actual and required pressure hold times.
The inspectors concluded that the corrective actions described in the licensee's
response letter and AR included corrective measures that addressed more than the ;
cause of the violation. Therefore, the inspectors concluded that the corrective
actions as stated in the response letter to be reasonable and complete.
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IV. Plant Support
R2 Status of Radiological Protection and Chemistry Facilities and Equipment
R2.1 Housekeeoino in Unit 3 Containment (71750)
'
During routine tours of the Unit 3 containment, the inspectors observed debris and
tools left in various areas. While most materials not actually in use were stored in
designated areas, some areas were very cluttered. Additionally, a considerable
amount of debris was left in and around the RCP oil collection pans after the
modification work and associated cleanup activities were completed. Subsequent
, cleanup of the containment was excellent.
S1 Cr.,nduct of Security and Safeguards Activities
51.1 Unattended SecuritvJadae
a. Ern.p_egtion S;Lqoe (71750)
The inspectors reviewed procedures, portions of the licensee's Physical Security
. Plan, and interviewed Health Physics and Security personnel regarding the
'
inspectors' identification of an unattended security badge.
b. Observation _q and Findinnd .
'
On July 3,1997, the inspectors observed an unattended security badge in the I
lor;ker room in.the radwaste building, inside the protected area. l
After a brief search, the individual was not located, and a nuclear plant equipment
operator contacted Security to report the incident. The inspector then located the j
- individual,.a licensee supervisor, in another part of the locker room (not the shower {
area). The individual stated that he did not know that he had to safeguard his j
. badge while in the locker room. :
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General Security Procedure SO123-XV-24, TCN 2 2, " Security Responsibilities of
. Site Employees,"' Step 6.4.3, rcc/; ires personnel in the protected area to maintain
-
custody of the card-key badge at ah times'. There are exceptioris in the procedure,
. ,but not related to control of the badge while in the locker room.
~
The Physical Security Plan states that personnel are required to display their ,
. card-key badges in a conspicuous manner at all times while inside the protected l
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area, except when exempted for health physics and maintenanco reasons. j
$ Signs in the locker room stated: " Security Reminder - Securo Red Badge inside your
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loc'ker before showering;" (The security badge was also call a Red Badge.) '
-
However, this exception was not included in Procedure SO123 XV-24.
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TS 5.5.1.1.a requires licensees to implement procedures covering the applicable
proceduras recommended in Appendix A of Regulatory Guide 1.33, February 1978.
Appendix A of Regulatory Guide 1.33, February 1978, recommends procedures for
security and visitor control. The failure to follow the requirements of procedure
SO123-XV 24 was a violation of TS 5.5.1.1.a (Violation 361/97012-09).
The licensee counseled the individual involved and made a security event log entry. '
Additionally, the individual's security badge was deactivated until after Security
confirmed that it had not baen used by another person. The Security Manager also
, stated his intent to include an exemption in Procedure SO123-XV-24 allowing
badges to be stored in lockers while personnel were showering, consistent with the
signs in the locker room.
The licensee provided historical data regarding the numbers of unattended badges
identified each quarter. The dcta showed that an average of nearly 10 events per
quarter had been recorded, with the highest numbers occurring during outages.
Even though the lockar room was accersible only by passing through the
i radiologically controlled area, the li:ensee did not consider it past oi the
radiologically controlled area, Consequently, the failure to control the dosimeter did
not violate ficansee procedural reqtiirements. However, procedures and training
information reflected the intent that dosimetry also remain under positive control.
This isvue, regarding the acceptability of the locker room not being defined as
raciologically centrolled area, will be further reviewed as part of inspector followup
item (IFl 50-361; 362/97012-10).
c. . Conclusions
A violation was identified by the inspectors as the result of a licensee supervisor's
failute to follow the procedural regttirement for controlling his security badge. A
weakness in the licenseo's procedure was identified because the procedure did not
reflect an exernption that was posted on signed in the locker room. The licensee's
corrective actions were prompt and adequate.
V. Manaaement Meetinas
i X1 Er.it Meeting Summary
The inspectors presented the inspection results to members of licensee management
at the exit meeting on July 3,1997. The licensee acknowledged the findings
presented.
The inspectors asked the licensoe whether any materials examined during the
insr.ection should be considered proprietary. No proprietary information was
identified.
.
. .
ATTACHMENT
SUPPLEMENTAL INFORMATION
PARTIAL LIST OF PERSONS CONTACTED
Licensee
C. Balog, Manager, Nuclear Construction
'
D. Brieg, Manager, Station Technical
J. Fee, Manager, Maintenance
G. Gibson, Manager, Compliance
R. Krieger, Vice President, Nuclear Generation
J. Madigan, Manager, Health Physics (Acting)
D. Nunn, Vice President, Engineering and Technical Services
'
T. Vogt, Plant Superintendent, Units 2 and 3
R. Waldo, Manager, Operations
M. Wharton, Manager, NEDO
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 40001: Resolution of Employee Concerns
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations
IP 71707: Plant Operations
IP 71750: Plant Support
IP 92700: On Site LER Review
IP 92712: Inoffice Review of LER
IP 97902: Followup - Maintenance
IP 92903: Followup Engineering
ITEMS OPENED AND CLOSED
_Qpened
50-362/97012-01 URI failure to properly couple CEA
50 362/97012-05 VIO fai!ure to submit LER within 30 days
50 361;302/97012-07 URI charging system check valve failure
50-361;362/97012-10 IFl radiological control of locker room
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50 362/97012-02: NCV RCP oil collection system--
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- 50-361;362/97012-03-
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NCV . missed surveillance te'st for the containment purge.- ;
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exhaust radiation monitors:
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. ' 50-361/97012-04~ NCV missed surveillance on reactor protection system' j
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operating bypass functions !
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50-361/97012-06: NCV. piping and instrumentation diagram for pressurizer spray 1
. valve leakoff lines not in conformance with actual plant H
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% 50 361/97012-08 NCV.. failure to maintain required containment penetration -l
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-50 361/97012-09, VIO . unattended ses,arity badge
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'50-361/96-010-00 . LER - containment escape hatch not closed white performing .
b core alterations
-50-361/97-002-00 LER . increase in pressurizer level due to valve alignment error i
50 361/97-005-00' , LER . RCS leakage
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50 361/97-006-00 , LER . misse'd surveillance test for the containrnent purge -
exhaust' radiation monitors ,
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'50-361/97-007-00
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- -LER . . missed surveillance test for the containment purge l
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' 50 361/97002 02L . VIO c failute to follow SG in-situ testing procedure' i
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4 l 50-361; 362/97006-04 ~ URI f ailure to perform a required TS surveillance requirement ;
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for the containment purge exhaust radiation monitors )
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and failure to . report the condition within 30. days 'l
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LIST OF ACRONYMS USED
AR - action request -
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'CEA' control element assembly .
-
'CFMS
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. critical functions monitoring systern
CSP. cask storage pool- '.
3 DLMS . diverse level monitoring system -
2' 'EDG. - emergency diesel generator
'
, ESFAS~ . engineered safety feature actuation system
FAC cflow accelerated corrosion
FCN ' field change notice
FTP : fuel transfer pool
j i IPAP Integrated Perforrnance Assessment Process
,
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- LER. licensee event report
'MO maintenance order
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- NEDO - Nuclear Engineering Design Organization
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NSCP. Nuclear Safety Concerns Program ,
PDR Public Document Room J
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PEV pressure equalizing valve ;
PMP procedure modification permit
RAS recirculation actuation signal
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RCP reactor coolant pump
'
SALP Systemic Assessment of Licensee Performance
SFP. ' spent fuel pool
. SG steam generator '
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SGCC steam generator chemical cleaning
TCN- temporary change notice
TS technical specification
'UGS upper guidance structure
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WC. ~ worker concern
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