ML20137X663
| ML20137X663 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 04/15/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20137X597 | List: |
| References | |
| 50-361-97-05, 50-361-97-5, 50-362-97-05, 50-362-97-5, NUDOCS 9704220116 | |
| Download: ML20137X663 (23) | |
See also: IR 05000361/1997005
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ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.: 50-361
50-362
- License Nos.: NPF-10 ~
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NPF-15 i
Report No.: 50-361/97-05 I
50-362/97-05
Licensee: Southern California Edison Co. l
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Facility: San Onofre Nuclear Generating Station, Units 2 and 3
Location: 5000 S. Pacific Coast Hwy.
, San Clemente, California {
Dates: February 23 through April 5,1997
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inspectors: J. A. Sloan, Senior Resident inspector
J. G. Kramer, Resident inspector
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J. J. Russell, Residerit inspector ;
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D. E. Corporandy, Project inspector
P. C. Gage, Reactor Inspector
M. P. Shannon, Radiation Specialist !
Approved By: Dennis F. Kirsch, Chief, Branch F ~
, Division of Reactor Projects
Attachment: Supplemental information . !
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9704220116 970415 .
PDR ADOCK 05000361
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i EXECUTIVE SUMMARY
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San Onofre Nuclear Generating Station, Units 2 and 3 '
! NRC Inspection Report 50-361/97-05;50-362/97-05 i
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This routine announced inspection included aspects of licensee operations, maintenance,
l- engineering, and plant support. The report covers a 6-week period of resident inspection;
in addition, it includes the results of a regional inspection of the control of radioactive
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- Operations i
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Operations were characterized by conservative actions and methodical progress I
] through the extended Unit 2 refueling outage. Relatively few personnel errors were
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observed, compared to previous outages. Operations management oversight of i
! control room activities during the outage was essentia!!y continuous, and the active
involvement of Station Technical and Nuclear Engineering Design was apparent in
) the resolution of various emergent issues (Section 01.1).
Operator performance in starting a reactor coolant pump (RCP) in Unit 2.was strong,
and included a thorough prejob briefing, good communications and cross-checking
during the evolution, and proper annunciator response (Section 01.2).
Operator performance during the reactor startup at the end of the Unit 2 refueling ~
outage _ was good. Operations supervision and React ar Engineering demonstrated a
good oversight of the startup evolution. Operators and Reactor Engineering
personnel communicated well and independently performed inverse count rate ratio
_ (ICRR) plotting during the startup. Operators demonstrated good procedure usage
and conservative actions (Section 01.3).
A violation was identified by the inspectors when the pressurizer was cooled down
at a rate greater than allowed by Technical Specifications (TS). Operators failed to
verify the cooldown rate was within the limit every 30 minutes, as required by l
Surveillance Requirement (SR) 3.4.3.1.1. Two steps in the Operations procedure J
for the evolution that would have prevented the violation were not followed. This
represented a lapse in the attention to detail by the operator. Additionally, the i
licensee did not provide the operators with adequate tools (procedures, training, and I
oversight) to properly perform a pressurizer cooldown and collapse the pressurizer
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bubble (Section 04.1).
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A lapse in attention to detailin the use of procedures occurred when operators j
failed to follow the procedure for the mode of withdrawing control element '
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assemblies (CEAs) for a rod drop timing test in Unit 2. This was a noncited i
violation (Section 04.2).
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Shortly after cooling down to Mode 5, operators did not know the correct shutdown
cooling (SDC) flow rate limits. However, the actual flow rate was within the correct
limits. This is an example of a lack of awareness of important information, in part
due to an incomplete prejob briefing (Section 04.3).
An operator did not know why one of two SDC isolation valves had position
indication and the other did not, when both were required to be open and
deenergized. This represented a lapse in attention to detail and a weakness in the
awareness of control board indications. The operator's knowledge of the system
design and operation was incomplete (Section 04.4).
A minor noncited violation was identified by the inspectors when operators set the !
automatic makeup flow rate of the boric acid controller to a value less than allowed
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by the procedure. This was another example o' seakness in the operator's l
attention to detail (Section 04.5). !
Maintenance
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The inspectars observed that the control room emergency air cleanup system
(CR,EACUS) filter unit was open, with personnel and equipment inside, while the
CREACUS was still considered operable. Maintenance personnel had inappropriately
applied a 1-hour allowance, for CREACUS boundary doors being open, to the
CREACUS filter unit access doors. The licensee's subsequent evaluation concluded .
that the CREACUS remained operable while the doors were open. Licensee i
management conservatively decided to declare the CREACUS inoperable during
future performance of a surveillance activity (Section M1.3).
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The repair of a failed pressurizer instrument nozzle, which had resulted in reactor i
coolant system (RCS) pressure boundary leakage, satisfied the proper sections of
the ASME Code, and was performed as required by the applicable weld proceaure
specification (WPS). Licensee oversight of contract welders was good
(Section M1.4).
The licensee's actions in response to the identification of pressure boundary leakage
through a SDC isolation valve packing leak-off plug were prompt and thorough. The
failed plug had met all regulatory requirements for the application, and the internal
defects in the plug could not have been identified by the techniques required or
implemented for receipt inspection of the plug. The licensee's visual inspection of
the plug, that resulted in identifying the failure, exceeded regulatory requirements.
l Corrective actions were thorough and effective (Section M2.1).
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Enaineerina
Reactor Engineering proactively used the four safety power channels, in addition to
the required use of the two startup channels, to provide criticality projections. An
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extra hold point was also added during the startup to ensure that the projections
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were conservative (Section 01.3).
A noncited violation was identified after licensee engineers determined that 18
of 65 environmentally- qualified (EO) Raychem splices exceeded the minimum bend
radius criterion in Unit 2. The licensee aggressively inspected all susceptible Unit 2
splices, corrected allidentified deficiencies, and performed a thorough operability
determination for the Unit 3 splices (Section E1.2).
A noncited violation was identified after the licensee identified that both Unit 2
pressurizer safety valves had lift setpoints that were outside the TS limits
(Section E8.2).
Plant Sunoort
An adequate program was in place to control radioactive material outside the
radiologically controlled area / radioactive material area. No problems were identified
with security personnel's involvement with the release of items from the restricted
area. Some Health Physics (HP) personnel did not know to perform aggregate
surveys of items being released from the restricted area. Radiological areas within
the restricted area were properly posted (Section R1.1).
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Report Details '
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Summary of Plant Status
Unit 2 began this inspection period in Mode 5, in the 85th day of the Unit 2 Cycle 9
refueling outage. The unit entered Mode 4 on March 2,1997, and reentered Mode 5 on
March 4, due to RCS pressure boundary leakage from a pressurizer instrument nozzle
(Section M1.4). Repairs were made to the nozzle and the RCS was again heated up on
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March 14,1997.
While Unit 2 was in Mode 3 on March 19,1997, leakage from an SDC valve plug caused
the unit to again be cooled down (Section M2.1). Mode 5 was entered on March 20.
Repairs to the valve were completed and Mode 4 was entered on March 21. However, a
steam generator (SG) primary manway leak was discovered, and the unit was returned to
Mode 5 on March 23 for repairs (Section E1.1). After the repairs, Mode 4 was reached on
March 27, and Mode 3 on March 28,1997. The unit was started up on March 30
(Section 01.3). The unit entered Mode 1 on March 31, and was synchronized to the grid
on April 1,1997, ending the 122-day Unit 2 Cycle 9 refueling outage. Unit 2 ended this
inspection period operating at essentially 100 percent reactor power.
Unit 3 operated at essentially 100 percent reactor power throughout this inspection period.
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1. Operations
01 Conduct of Operations
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01.1 General Comments (71707) '
Operations during this inspection period were characterized by conservative actions {
and methodical progress through the challenges of the Unit 2 Cycle 9 outage. i
Decisions made by operators and management led to successful completion of the
outage with relatively few personnel errors. Operations management oversight of_
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control room actPeities was essentially continuous throughout the outage. Active l
involvement of Station Technical and Nuclear Design Engineering was also apparent
during the outage. -
Activities in Unit 3 were kept at a minimum to avoid distractions during the
performance of complex activities in Unit 2.
01.2 RCP Start - Unit 2(71707)
On March 21,1997, the inspectors observed the operators perform a start of
RCP 2P001, in accordance with Procedure SO23-3-1.7, " Reactor Coolant Pump
Operation," Revision 17. The' operators used good communications and
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cross-checking during the evolution. Prior to the pump start, the control room
supervisor performed a detailed briefing of pressure control expectations and
operator response. The operators eppropriately responded to the annunciators
received during the performance of the evolution. The inspectors concluded the
operators exhibited a strong performance during the RCr start.
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l 01.3 Reactor Startuo - Unit 2
a. Inspection Scope (71707,37551) l
On March 29,1997, the inspectors observed the reactor startup of Unit 2 following j
! the refueling outage. The inspectors reviewed Procedure SO23-31,1, " Reactor l
l Startup," Revision 13, and discussed the startup with Reactor Engineering and
Operations personnel.
b. Observations and Findinas
, Operators performed a detailed prestartup briefing. The operator dedicated to
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monitoring the startup and withdrawing the CEAs remained focused on the startup I
evolution. Operations supervision directed the operator withdrawing the CEAs to
stop the withdrawal every 25 inches to ensure proper instrument response. This ;
was a more conservative measure than that required by procedure. l
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. Reactor Engineering and a rei ctor operator independently performed the ICRR plots.
The reactor engineer conservatively allowed counts to stabilize for a period greater
l than the minirnum regneci 'y Procedure SO23-3-1.1, and used more than the
l minimum number of count rate readings. In addition to using the two startup '
channels of nuclear ir.strumentation, Reactor Engineering also utilized the four
excore safety log channels for comparisons of the ICRR plots. Operations and
! Reactor Engineerir g thoroughly discussed the results of the ICRR plots to determine
l if the next hold point was acceptable, and, in one instance, inserted an additional
hold point to e,1sure that the startup proceeded as expected. The inspectors
observed good communications between ' operators and a good Operations and
Reactor Engineeri.1g supervisory presence. l
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Operators and Reactor Engineering utilized good communications and independent
ICRR plotting during the reactor startup. Operations supervision and Reactor
, Engineering demonstrated a good oversight of the startup evolution. Reactor.
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criticality projections. Operators demonstrated good procedure usage and
conservative actions during the reactor startup.
02 Operational Status of Facilities and Equipment
j O2.1 Safety System Walkdown (71707)
- The inspectors performed a walkdown of the Unit 3 auxiliary feedwater system.
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Only one minor material deficiency'was identified (a valve packing leak), which was
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appeared capable of performing its design functions. Housekeeping in the pump
area was excellent, and no discrepant conditions were identified.
04 Operator Knowledge and Performance
04.1 Pressurizer Cooldown Rate Limit Exceeded - Unit 2
a. Inspection Scone (71707,37551. 42700)
On March 4,1997, the inspectors identified that the operators exceeded the TS
limiting condition for operation cooldown limit for the pressurizer. The inspectors ;
discussed the safety consequence of the pressurizer and surge line cooldown with '
Engineering. The inspectors interviewed the operators involved in the excessive
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cooldown, reviewed the Procedure SO23-5-1.8, " Shutdown Operations (Mode 5
and 6)," Revision 5, for adequacy, and discussed the cooldown process with the
Operations manager.
b. Observations and Findinas
Operator Performance
On March 4,1997, the operators cooled down the pressurizer and collapsed the
pressurizer bubble. The inspectors identified that the operators exceeded TS '
Limiting Condition for Operation 3.4.3.1, which limits the pressurizer maximum
cooldown rate to 200*F in any 1-hour period. The inspectors observed that the
maximum 1-hour cooldown was approximately 265'F and notified the shift !
superintendent (SS). The pressurizer temperature had reached its minimum value l
and was heating up. Therefore, no immediate operator action was required to stop
the cooldown. The licensee entered, and complied with, the appropriate action
statement for the excessive cooldown.
The inspectors reviewed the operators' plot of-the pressurizer cooldown as part of
the event followup. The operators plotted the following pressurizer temperatures:
at 2:30 p.m., 420 * F; at 3 p.m., 380 * F; and at 3:30 p.m.,160 *F. However, the
operators did not evaluate the results to determine the cooldown rate. The
inspectors informed the SS at approximately 4 p.m. that the pressurizer cooldown
rate limit had been exceeded. The inspectors considered that had the operators not
just plotted the pressurizer temperature but also verified the cooldown rate every 30
minutes, as required by SR 3.4.3.1.1, they would have identified the excessive
pressurizer cooldown rate. The failure of the operators to verify the pressurizer
cooldown rate every 30 minutes is a violation of TS SR 3.4.3.1.1
(Violation 361/97005-01).
The inspectors interviewed the operators involved in the pressurizer cooldown
evolution. The operators indicated that they were focused on monitoring
pressurizer pressure and level during the bubble collapse, and not the pressurizer
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cooldown rate. The operators were all aware of the TS cooldown rate limit
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of 200*F in a 1-hour period, but possessed a mind set that there was a large limit
and could not be exceeded. During interviews, operators indicated that there were s
minimal distractions, and that they felt they had proceeded in a controlled manner. ;
The operator specifically assigned the function of monitoring the cooldown rate '
plotted the pressurizer te.mperature as required by Procedure SO23-5-1.8, but failed i
to recognize that a procedural and TS limit on cooldown rate had been exceeded. ;
The inspectors determined that several of the operators possessed minimal
familiarity with collapsing the pressurizer bubble. None of the reactor operators j
performing the pressurizer bubble collapse had previousiv performed that evolution. '
However, the senior reactor operators and Operations management present in the
control room did have previous experience with collapsing the pressurizer bubble.
Licensed operator training had briefly discussed collapsing the pressurizer bubble in
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classroom training in 1992 and had emphasized having heaters on with plenty of
spray to control the cooling of the metal masses. This practice was not used during
the cooldown on March 4. The Operations superintendent indicated that the
licensee planned to include pressurizer cooldown methodology in upcoming licensed
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Technical Review and Safety Consecuence
The pressurizer bulk water temperature experienced a cooldown of approximately
265 *F in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, the surge line experienced a cooldown of approximately 320*F in
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> _ (430 to 110*F), and the spray line experienced similar temperature
fluctuations of approximately 320 *F. In addition, the 200*F cooldown limit of the
pressurizer bulk water temperature was exceeded in a 26-minute period. The ;
licensee initiated an evaluation of the effects on the pressurizer and related
components (spray nozzle, surge line, and surge line nozzle).
The licensee documented the evaluation 'in a letter to the NRC dated
March 14,1997. The licensee concluded that, during the thermal transient, the
pressurizer vessel remained within the acceptance criteria of the ASME Code,
Section XI, Appendix G. The cenclusion was based on the fatigue and pressurized
thermal shock evaluations performed on the critical locations in the pressurizer.
Procedure Revign
! The inspectors reviewed Procedure SO23-5-1.8, used by Operations to cooldown
and collapse the pressurizer tubble. The procedure contained steps that, had they
been followed, would have procluded the excessive pressurizer cooldown and the
violation of TS SR 3.4.3.1.1. Attachment 13, Step 2.5, required that the
pressurizer cooldown rate shalf not exceed 190*F per hour. Additionally,
Attachment 4, Step 1.3, required operators to maintain the pressurizer temperature
between 50*F and 200*F above the RCS cold leg temperature (the actual
temperature differential during the cooldown was 320*F).
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The Operations manager stated that Procedure SO23-5-1.8 provided steps to
cooldown the pressurizer, but did not provide adequate guidance to ensure the
evolution could be performed successfully every time. He indicated that a revised
procedure should be issued prior to the Unit 3 outage.
After this event, the licensee developed another method for collapsing the
pressurizer bubble. The inspectors observed that, during the subsequent plant
heatup, the new method resulted in avoiding a severe temperature transient.
Additionally, the licensee briefed the operating crews on the event, and was
working to develop a better method for tracking and evaluating the temperature
changes.
c. Conclusions
The licensee did not provide the operators with the adequate tools (procedures,
training, oversight) to properly perform a pressurizer cooldown and bubble collapse.
A violation was identified because the operators failed to verify that the pressurizer
cooldown rate was less than 200*F in any 1-hour period, as required by
SR 3.4.3.1.1. This represents a lapse in attention to detail by the operators.
04.2 CEA Withdrawal for Rod Droo Timina Test - Unit 2
a. Inspection Scooe (71707)
The inspectors observed the operators withdraw the CEAs using
Procedure SO23-3 2.19, Control Element Drive Mechanism Control System
Operation," Revision 7, and discussed the operators' performance with Operations
management,
b. Observations and Findinas
On March 17,1997, the inspectors observed a reactor operator withdraw the CEAs
using Procedure S023-3-2.19, in preparation for a CEA drop time test. During the
regulating group CEA withdrawal, Procedure SO23-3-2,19, in part, directs the.
operator to withdraw and insert all the regulating group CEAs 5 inches and then to
fully withdraw the regulating group CEAs using manual sequential mode. The
reactor operator performing the evolution withdrew and inserted the regulating
Group 1 CEAs 5 inches as required, and then proceeded to completely withdraw
Group 1 using the manual group mode. The reactor operator performed the similar
5-inc! exercise of regulating Group 2 CEAs, and then requested authorization from
the control room supervisor (CRS) to withdraw the CEAs in manual group mode.
The CRS informed the reactor operator that the regulating group CEAs were to be
withdrawn in the manual sequential mode.
Operators suspended the withdrawal activities to evaluate the condition. The
Operations crew and the Operations superintendent discussed the situation and I
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- concluded that since the reactor was significantly shutdown, by greater then
two percent, the incorrect CEA withdraw sequence had minimal effect on the core.
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The operators then exercised the remaining regulating group CEAs and withdrew .
l them in manual sequential. Operations concluded that the abnormal CEA
. withdrawal sequence had minimal effect on the core and that the method used to
j withdraw the remaining regulating group CEAs was acceptable.
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Operations management debriefed the event with the Operations crew after the test
, and discussed ways to improve Procedure SO23-3-2.19 to prevent recurrence of
i the situation. The Operations superintendent initiated an action request (AR) to
evaluate the problem. On March 19,1997, a preshift briefing was initiated to
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inform all Operations crews of the situation and avoid similar problerns. On
March 27,1997, the licensee revised Procedure SO23-3-2.19 to clarify the
- inadequate procedure steps that led to the abnormal CEA withdrawal sequence and
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to improve additional steps of the procedure that operators identified as needing
enhancement. In addition, the Operations superintendent issued a memorandum to
control room supervision emphasizing control room oversight responsibilities. This
licensee-identified and corrected violation is being treated as a noncited violation,
consistent with Section Vll.B.1 of the NRC Enforcement Policy s
(NCV 361/97005-02).
c. Conclusions
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The operators failed to adhere to the requirements of Procedure SO23-3-2.19 during '
a CEA withdrawal activity resulting in the use of a wrong mode for CEA withdrawal.
However, the event had minimal safety consequence and Operations management i
performed acceptable corrective actions.
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04.3- Operator Awareness of SDC Flow Rate Limits - Unit 2 i
a. Insoection Scone (71707) i
The inspectors observed activities in the control room on March 4,1997, shortly
after Unit 2 wa.s cooled down to Mode 5.
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b. Observations and Findinas
About 30 minutes after Unit 2 was cooled down to Mode 5, the inspectors asked
the Assistant Control Operator (ACO), who was monitoring the cooldown, what the
SDC flow rate limits were, and if they were specified in a procedure. The ACO
stated that the limits were 3500 to 4500 gpm, and that the ideal flow rate
was 4200 gpm. The inspectors observed that the actual flow rate was 4200 gpm.
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The ACO then opened Procedure SO23-3-2.6, " Shutdown Cooling System
Operation," Revision 11, Section 6.2, which contained a table stating the SDC flow
rate limits and preferred rate for various pump configurations and modes. The flow
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rate limits stated by the ACO were for one low-pressure safety injection pump
operating in Mode 4. The limits for Mode 5 (2300 to 4500 gpm, with a preferred
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flow of 3500 gpm) were broader, but different than, the limits given by the ACO.
The preferred flow rate for Mode 5 was lower than for Mode 4. Additionally, the
CRS was not aware that the Mode 5 limits were different than the ACO had stated.
The CRS consulted with the SS, and determined that the SDC flow rate should
remain at the higher value in support of the continued plant cooldown. The ;
inspectors determined, through discussions with the ACO and CRS, that the SDC {
flow rate limit changes had not been discussed during the tailboard for the
cooldown.
c. Conclusions
The ACO and CRS were not fully aware of the procedurally-specified SDC flow rate
limits. The tailboard conducted prior to the cooldown was incomplete, in that it did
not address the change of limits that occurred when the mode was changed.
However, there was no safety consequence to the oversight, because the actual
flow rate was within the correct limits.
04.4 Cor$ trol Board Indication Knowledae - Unit' 2 (71707) l
On March 25,1997, the inspecters observed that SDC isolation Valves 2HV9377
and 2HV9378, both motor operated valves, were deenergized in the open position '
as indicated by a clearance tag on the control board, and that Valve 2HV9377 still
had valve position indication while Valve 2HV9378 did not. The inspectors
questioned a reactor operator about the difference in the indications. The reactor
operator was unable to explain the difference. The CRS indicated that
Valve 2HV9378 has an independent power supply for valve indication as indicated
by the valve label. The inspectors discussed the reactor operator's weakness in
knowledge of the board indications with the Operations superintendent. The
Operations superintendent indicated that he would discuss the knowledge issue
with the reactor operator.
04.5 Boric Acid Makeuo (BAMU) flow Rate Setooint i.ess than Procedurally Reauired -
Unit 3
a. Insnection Scone (71707)
On April 2,1997, with Unit 3 at 99 percent power, the inspectors walked down the
Unit 3 main control boards, interviewed some members of the Operations crew, and
reviewed Operating Instruction S023-3-2.2, Revision 10, " Makeup Operations."
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b. Observations and Findinos
- The inspectors observed that the BAMU flow rate set on BAMU Flow
' Controller FIC-0210Y was 1.2 gpm. Volume control tank (VCT) level control was
selected to automatic. In automatic, if VCT level decreased to the low level
setpoint of 37 percent, then a blend of boric acid and pure water would initiate.
The flow rates of boric acid and pure water were set on the controllers, and the
blend would continue until the high level termination setpoint of 51 percent was
reached. The inspectors reviewed Procedure SO23-3-2.2 and observed that in
! Section 6.2, " Automatic Makeup Mode," the operators were cautioned not to use a
- BAMU flow rate setpoint of less than 1.5 gpm when in automatic makeup mode,
due to instrument and control inaccuracies. The operators were also cautioned in
the procedure that this set a lower limit of 100 ppm for the blend concentration.
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Contrary to this procedure, the operators had set in the 1.2 gpm boric acid flow,
) with a pure water flow rate of approximately 100 gpm, to match a RCS boric acid
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concentration of approximately 30 ppm. This was a violation of
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Procedure SO23-3-2.2. This procedure was applicable to Regulatory Guide 1.33
and Unit 3 TS 5.5.1.1.a.
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This violation involved reactivity control of the unit; however, due to VCT level
maintenance practices and end of core life, the inspectors found that the safety
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significance of this violation was minor. Operators normally maintained VCT level
approximately 51 percent, by manually raising level as it lowered; consequently, an
automatic blend rarely initiated. This was not a procedural requirement, but was
generally a standard operating practice. Also, if an automatic makeup had occurred,
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then the boric acid flow rate may have deviated from demand, due to the low flow
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rate. Operators would have been ab!e to manually compensate for a blend that
contained too much boric acid (the probable result), which would have caused
reactor power and, consequently, RCS temperature, to lower. The inspectors
considered the guidance of the NRC Enforcement Manual in assessing the
significance of this issue. This f ailure constitutes a violation of minor safety
significance and is being treated as a noncited violation, consistent with Section IV
of the NRC Enforcement Policy (NCV 362/97005-03).
In response to the inspectors' observations, the Operations crew raised the boric
acid flow setpoint to 1.6 gpm. Operations management also began evaluating
whether to change the makeup procedure in order to accommodate operation in
automatic, with RCS boric acid concentrations less than 100 ppm. This normally
occurred towards the end of a refueling cycle. The inspectors found that the
licensee's response to the immediate concern was satisfactory.
Based on conversations at the time of the observation, the inspectors found that the
CRS was generally unaware of the' procedural restriction against low boric acid flow
rates. This illustrated a weakness in knowledge of an operating limit in effect.
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c. Conclusions ,
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j- A minor violation was identified, but not cited, because the demanded boric acid ;
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flow to the VCT was less than procedurally allowed. The CRS was generally -l
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unaware of the procedural restriction, illustrating a weakness in knowledge of an
operating limit.
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04.6 Conclusions Reaardina Operator Performance and Knowledae
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While operators generally demonstrated excellent knowledge and performance, l
occasional lapses were observed. The above examples are significant in that they ;
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involved reactivity control and the maintenance of important RCS parameters,
j- including temperature, SDC flow rate, and SDC system alignment. In these l
- examples, operators demonstrated weakness in attention to detailin the
performance of their duties. l
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07 Quality Assurance in Operations -
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07.1 ility Manaaement Audit Review (71707)
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The inspectors reviewed the report for the Joint Utility Management Audit,
- condur.ed March 3 through March 10,1997. !
- 08 Miscellaneous Operations issues (90712) '
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} 08.1 (Closed) Licensee Event Reoort (LER) 50-362/96005-00_t reactor head vent valve
- - mispositioned. This issue was discussed and resolved in NRC Inspection
l Report 50-361; 362/96-17.
11. Maintenance
M1 Conduct of Maintenance -
M1.1 General Comments
a. Insnection Scone (62707)
The inspectors observed all or portions of the following work activities:
Eddy current testing of pressurizer Thermowell 2T101 (Unit 2)
Weld repair of pressurizer nozzle for pressurizer Thermowell 2T101 (Unit 2) ,
SG hot leg primary manway removal and gasket replacement (Unit 2)
Auxiliary feedwater pump ammonia check valve repair (Unit 2)
- Repack charging Pump 3P190 (Unit 3)
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b. Observations and Findinas
The inspectors found the work performed under these activities to be thorough. All
work observed was performed with the work package present and in active use.
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,
appropriate radiation controls were in place.
In addition, see the specific discussions of maintenance observed under
Sections M1.4, E1.1, and E1.2, below.
M1.2 General Comments on Surveillance Activities
a. Insoection Scope (61726)
The inspectors observed all or portions of the following surveillance activities:
- CEA Trip Verification (Unit 2)
, Verification of RCS Heatup Rates Within Limits (Unit 2)
Low Pressure Safety injection Pump 3P015 Leakrate Test (Unit 3)
High Pressure Safety injection Pump 3P019 inservice Test (Unit 3) l
b. Observations and Findinas ~
The inspectors found all surveillances performed under these activities to be
thorough. All surveillances observed were performed with the work package
present and in active use. Technicians were knowledgeable and professional. The ;
inspectors frequently observed supervisors and system engineers monitoring job l
progress, and quality control personnel were present whenever required by
procedure. When applicable, appropriate radiation controls were in place.
In addition, see the specific discussions of surveillances observed under
Section M1.3, below.
M1.3 CREACUS Doors Left Open - Units 2 and 3
a. Inspection Scone (37551. 61726, 627071
The inspectors observed Heating, Ventilation and Air Conditioning (HVAC)
technicians perform portions of Procedure SO23-I-2.44, "CREACUS - Control Room
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Emergency Air Cleanup System Operation and Operability Test Surveillance,"
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Revision 6, and discussed the performance with the HVAC technicians,
l Maintenance supervision, and Engineering.
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b. Observations and Findinas
On February 25,1997, the inspectors observed technicians perforrn a replacement
of a high efficiency particulate air filter. During the replacement of the filter, one
technician indicated that the CREACUS unit was considered operable during
Surveillance Test SO23-1-2.44 until one of the high-efficiency particulate air filters
failed its efficiency test. The inspectors questioned the technician about the
operability of the CREACUS unit with the doors open and test equipment installed in ;
the unit. The technicians stated that their guidance provided that as long as the
test equipment can be removed within an hour after the unit starts, the unit was
considered operable.
The inspectors questioned the licensee's practice of performing the surveillance test
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without declaring the CREACUS unit inoperable. The HVAC system engineer 4
initiated an AR and an operability assessment to evaluate the past performance of
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the surveillance test on the unit operability in both the toxic gas isolation signal and
control room isolation signal modes of operation. The licensee performed an ;
operability evaluation which concluded that with the door open and the test i
equipment inside, the unit was still capable of performing its design function and,
therefore, would remain operable.
In the toxic gas isolation signal and control room isolation signal modes of
operation, the engineer concluded that bubble-tight dampers isolate the system from
the outside environment. Irifiltration of toxic gases or radioactivity into an open
CREACUS unit access door would : occur since the unit is located within the
CREACUS boundary. In addition, , engineer determined that expeditious
- compensatory actions to remove the test equipment and ensure the doors are
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closed should take less then one minute. The engineer calculated that the
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maximum air flow velocity in the unit is approximately 3 miles per hour. At that
- velocity no equipment or other. materials would move or affect the air flow
distribution.
The inspectors determined that the technicians' perception that 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> was
available for closing the CREACUS unit door was inappropriately based on
establishing compensatory measures within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of identifying a deficient control
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room boundary door / doorway. Maintenance supervision conducted shop training
l for the HVAC planner and technicians to correct the potential discrepancy. In
i addition, the HVAC system engineer changed the work authorization requests to
declare the CREACUS unit inoperable during future 18-month surveillances.
c. Conclusions
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The licensee thoroughly evaluated the previous CREACUS unit maintenance
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activities for operability and conclu~ded that operability was maintained. The
inspectors assessed the licensee's evaluation and found it adequate.
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, M 1.4 Repair of Temperature Element 2TE0101, Pressurizer Liauid Space Temperature
Nozzle - Unit 2
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a. Inspection Scope (62707. 37551)
On March 9,1997, the inspectors observed machine gas tungsten arc welding
being performed by contract welders in the Unit 2 containment. The work was
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required to weld a new, partial, inconel 690 nozzle in place on the pressurizer. The ;
- nozzle was used to provide an opening for pressurizer liquid space temperature !
Therrnowell 2TE0101. The old Inconel 600 nozzle weld to the pressurizer had
cracked in the heat affected zone of the weld. Repairs were being made by welding
a new partial nozzle in place, and placing a pressure boundary weld on the exterior
of the pressurizer. This substituted for the old pressure boundary weld on the
interior of the pressurizer. An inconel weld buildup of a carbon steel base plate was
4
performed. Then an inconel-to-inconel weld was performed to install the new,
partial nozzle. The interior portion of the old nozzle was left in place, requiring the
pressure boundary weld to be the exterior nozzle to pressurizer weld. l
The inspectors reviewed the settings on the welding machine, argon flow, and the
performance of the machine during in-progress welding. The inspectors reviewed
Welding Procedure Specification (WPS) 2 A03249 and Procedure Qualification
Record A03256-N3432-52, Revision 2. Both were written by the weld contractor,
Weld Services incorporated, and approved by the licensee. The inspectors also '
reviewed Nonconformance Report 970300092, which contained the safety
evaluation for the repair, as well as portions of ASME Code Section XI,1992, and
- Code Case N-432, approved in 1986 and reaffirmed in 1994. In addition, the
inspectors reviewed a letter from the NRC Office of Nuclear Reactor Regulation to
the licensee dated February 13,1996, which granted relief to the licensee to use a
portion of the 1992 ASME Code for welds such as were performed for this repair,
b. Observations and Findinas
The ASME Code allowed nonessential variables to be, within set limits, varied from
the weld qualification, as the weld was actually performed on March 9,1997.
Essential variables had to be maintained, consistent with the weld qualification. For
the portions of the actual welding that the inspectors observed, the essential
variables, including total heat flux, were maintained. Current, voltage, machine
travel speed, and filler metal travel speed varied from the weld qualification, as
allowed.
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The 1992 Code and Code Case N-432 were applicable to this weld, and the WPS
and procedure qualification record conformed to these requirements. The planned
nondestructive examination also conformed to these requirements. The safety
evaluation in the nonconformance report was adequate to confirm that the repair
was not an unreviewed safety question.
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Based on the observation of portions of the actual performance of the weld, and on
review of the documents mentioned above, the inspectors found that licensee
oversight of the contract welders was good.
c. Conclusions
The repair plan for the 2TE0101 nozzle satisfied the proper sections of the ASME
Code, and the weld was performed in accordance with the applicable WPS.
Licensee oversight of contract welders was good.
M2 Maintenance and Material Condition of Facilities and Equipment
M 2.1 Pressure Boundarv Leakaae due to Faultv Packina Leak-off plua
a. Insoection Scope (62707. 37551)
The inspectors monitored the licensee's actions in response to the failure of a
packing leak-off plug on SDC isolation Valve 2HV9339 on March 19,1997.
b. Observations and Findinas
On March 19,1997, while Unit 2 was in Mode 3 being prepared for its return to
service at end of the Cycle 9 refueling outage, plant personnel identified a smallleak
(approximately 3 gallons per hour), coming from a packing leak-off plug on SDC
isolation Valve 2HV9339. This valve is inside the containment and is the isolation
valve closest to the RCS. The leak was determined to be through the center portion
of the solid plug. The licensee classified the leak as pressure boundary leakage, and
initiated a plant cooldown as required by TS 3.4.1.13.
The licensee had procured the plug in 1983. Of the ten plugs procured at that time,
eight had been installed in various plant components. The plugs were procured as
safety-related, but not as ASME Class 1. The design drawing for Valve 2HV9339
designated the plug as a "nonpressure retaining part nonessential to function." The
inspectors confirmed that this designation was consistent with ASME Code
requirements.
The licensee identified the applications of all eight of the plugs that had been.
installed. Of those that remained installed, most had been installed for several
years. The licensee inspected those that were accessible. Some were seal welded.
Other than minor leakage at the threads, none of the plugs had experienced similar
problems.
The licensee's initial root cause evaluation showed that the plug had microstructure
porosity inclusions. The failed plug had been installed in Valve 2HV9339 earlier
during the Cycle 9 refueling outage. The inspectors examined the plug and
observed an irregular hole, through the length of the plug, that was
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approximately 1/8" x 3/16". The licensee planned on performing destructive
examination of the plug.
The licensee replaced the failed plug with an ASME Class l plug. The retest of the
plug was satisf actory.
c. Conclusions
A failed plug resulted in pressur.: boundary leakage from the RCS. The plug met all
regulatory requirements for the application, and the internal defects in the plug
could not have been identified by the techniques required or implemented for receipt
inspection of the plug. The licensee's visual inspection of the failed plug exceeded
regulatory requirements and identified the f ailure. Corrective actions were thorough
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and effective.
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Ill. Enaineerina q
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E1 Conduct of Engineering
E1.1 Procurement and Use of Faultv SG Manway Gasket - Unit 2 I
a. Insoection Scone (37551)
The inspectors monitored the licensee's actions in response to the identification of
leakage from the SG 2E089 cold-leg manway. The inspectors reviewed the 4
maintenance and procurement documentation associated with the manway gasket, {
and met with Procurement personnel to discuss the issues identified by the 1
licensee's investigation of the cause of the leakage.
b. Observations and Findinas
On March 22,1997, after the plant was heated up to Mode 3, the licensee
identified a small amount of leakage from the SG 2E089 cold-leg manway cover.
The licensee determined that the gasket was leaking. The licensee reviewed the
maintenance records and verified that the gasket was new and that the correct stud
tension had been achieved during installation. The design was such that a
substantial margin should have existed, and leakage was not expected to occur.
Because the leakage indicated an unusual condition, licensee management decided
to return to Mode 5 to evaluate the cause of the leakage.
The licensee determined that the gasket installed was not correct for the
application. The gaskets had been classified as nonsafety-related in a change made
in 1989 by Asea-Brown Boveri (ABB) and accepted by the licensee. The installed
gasket was designed for 900 psi application, not 2500 psi as required for the RCS
pressure boundary. The gasket had been ordered from a third-party vendor, Pacific
Mechanical Supply, with the intent that the vendor would obtain the gasket from
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ABB. The purchase order did not provide design specifications for the gasket, but
listed the Combustion Engineering part number and provided a general description
(nominal dimensions, materials, and gasket type). The design specifications were
proprietary to ABB. The licensee had met with Pacific Mechanical Supply and other
vendors in mid-1996 to explain that if a part was ordered by part number,
substituted parts would not be accepted. Hov>ever, this condition was only verbal.
Prior to 1996, this condition had been included as part of the written purchase
order.
In the past, the licensee had procured the gaskets from ABB, which obtained them
from Flexitallic or other manufacturers, using the oroprietary design specification.
I The licensee's Quality Control and Maintenance personnel did not have the design
specifications to use to verify that the correct gaskets were received and used.
Only general information was available to validate that the correct items were
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received.
3
The licensee determined that Pacific Mechanical Supply had worked with another
company to manufacture the gaskets according to the general description provided
on the purchase order. The purchase order did not mention the pressure or service
application, and did not provide dimensional tolerances. The vendors made
assumptions regarding this information, and manufactured the gaskets without
notifying the licensee that the locally-manufactured gaskets would be substituted
for the ABB parts.
I
in response to the identification of the incorrect gasket, the licensee replaced all the i
primary manway gaskets (including the pressurizer manway gasket) with the proper I
gaskets. After more details of the design of the correct gaskets became known, the ,
licensee was able to confirm that the secondary manways had the correct gaskets j
installed. Additionally, the licensee initiated a review of all nonsafety-related ;
components that are part of larger safety-related components, with the intent of
identifying those components that should be more strictly controlled.
A similar event, involving incorrect gaskets substituted for Flexitallic gaskets for a
RCP heat exchanger occurred in 1993, and was documented in Division
Investigation Report DIR-SSS-93-02. As a corrective action, the licensee credited
the Augmented Quality Program that had been put in place after the original material
codes had been processed. Additionally, the licensee removed inappropriate -
gaskets from stock and reviewed existing material codes from gaskets that affect
primary plant components.
The licensee determined that changes made to the procurement process in 1996 to ,
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implement " strategic sourcing" of nonsafety-related parts unintentionally reversed
some of the controls that had been established to prevent such problems. In this
case, the licensee observed that gr'ouping highly-engineered items such as Flexitallic
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gaskets along with other nonsafety-related gaskets inappropriately led to a !
relaxation of the procurement controls. Corrective Action Report 007-97 was
issued to ensure that the weaknesses in the procurement process were identified
l and corrected.
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l The inspectors reviewed Maintenance Order (MO) 97021201001, by which the
j primary manway covers for SG 2E089 were installed. The MO was classified as
l Quality Class 1 and ASME Ill, Class 1. The MO @ecified the material requirements,
l Items 1 and 2, as Combustion Engineerir.g Part Number 119-04. Because of the
l procurement errors described.above, the licensee actually installed a gasket that
was not a Combustion Engineering Part Number 119-04. This item is unresolved,
! pending review of the licensee's response to Corrective Action Report 007-97
(Unresolved item 361/97005-04).
c. Conclusions '
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A gasket that was installed in the Unit 2 SG 2E089 cold-leg manway leaked. The l
gasket was not the same as had been ordered, and was not rated for RCS pressure.
The incorrect gasket was received as a result of a change in the procurement
pro, cess for nonsafety-related gaskets. The installation of the incerrect gasket is an i
unresolved item pending a review of the response to Corrective Action i
Report 007-97.
E1.2 Environmentallv-Oualified (EO) Solice Deficiencies Unit 2 !
a. Insoection Scoce (37551. 62707)
l The inspectors reviewed ARs and met with EQ personnel regarding the identification ;
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of defective Raychem splices in safety-related systems in Unit 2. I
b. Observations and Findinas -
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On March 18,1997, while evaluating damaged wire insulation in an EQ assembly
for a Unit 2 RCS temperature instrument, a licensee EQ engineer identified that the ,
tend radius of the Raychem splice (WCSF-N shrink tubing) on the Kapton leads in !
the condulet was smaller than allowed by Procedure SO123-I-4.61, "Conax Seal
l. Assembly - Removal, Cleaning, inspection, Repair, and Installation," Temporary
Change Notice 1-2, and the Raychem "WCSF-N In-Line Splice Application Guide,"
l dated March 1991. These documents stated that the splices should not be bent to
a radius tighter than five times the outside diameter of the splice. The licensee i
determined that the planner had not included a reference to
, Procedure SO123-1-4.61 in the work document because Drawing 39646 for that !
- assembly stated that Procedure SO123-1-4.59 applied to that portion of the
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assembly. Procedure SO123-1-4.59, " Wire / Cable inspection," Temporary Change ;
i Notice 1-3, lacked the bend radius restriction. This was documented in AR !
i 970300834.
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The licensee inspected a sample of six other splices in small condulets for some
other RCS temperature instruments and identified another similar deficiency. The
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licensee performed a review and determined that 65 EQ installations (wiring inside
small condulets) were potentially susceptible to the same deficiency in each unit,
and performed an inspection of t.ach such assembly in Unit 2. Of the 65
installations inspected in Unit 2,18 were found to be deficient.
The licenseo performed corrective maintenance on the deficient Unit 2 EQ
configurations, removing the affected areas of the leads, and, in some cases,
installing larger connection boxes for the terminations. At the time, Unit 2 was
operating in Mode 5. The corrective actions were completed before the mode was
,
changed. The licensee also determined that some of the deficient installations had
i been performed earlier in the Unit 2 outage, and that some wers older.
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Unit 3 was operating in Mode 1, and the licensee performed on operability
assessment, documented in AR 970300904, that concluded that the Unit 3 ,
systems remained operable. The inspectors reviewed the operability assessment
and determined that it provided an adequate basis for the licensee's conclusion.
The licensee planned to conduct inspections of the similar configura4ons in Unit 3, i
most of which are in containment, during the next refueling outage.
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The licensee established a task force, headed by Nuclear Oversight, to review the
broader scope of EQ issues revealed by these deficiencies, including the adequacy I
of procedures and training, the cause of the other deficiencies, and the controls for
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ensuring that EQ requirements are incorporated into work documents.
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AR 970301068 was initiated to document the results of the task force's !
investigation.
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c. Conclusions
The licensee was aggressive in inspecting, identifying, and correcting deficient EQ
splices in Unit 2. An operability assessment for Unit 3 splices that had not been
inspected, but may also be deficient, was thorough.
The procedure specified for the splicing of Temperature Element 2TE9178-3 was
inadequate, in that it did not provide the minimum bend radius criterion for the
Raychem splice. This was a violation of 10 CFR Part 50, Appendix B, Criterion V.
S
This licensee identified and corrected violation is being treated as a noncited
violation, consistent with Section Vll.B.1 of the .N_RC Enforcement Policy
(NCV 361/97005-05).
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l E8 Miscellaneous Engineering issues (90712,92700) :
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E8.1 (Closed) LER 361/96008-00: RCP oil collection system - voluntary report. This )
issue was discussed and resolved in NRC Inspection Reports 50-361;362/96-11 !
and 50-361; 362/9702.
E8.2 (Closed) LER 50-361/97003-00: pressurizer safety valve setpoints out of tolerance.
Following pressurizer safety valve setpoint testing, the licensee identified that the
two pressurizer safety valves were out-of-tolerance high by 1.72 percent and j
1.04 percent. These out-of-tolerance setpoints exceeded the TS allowable i
tolerance of i1 percent. The licensee believed the cause to be setpoint drift. !
L Following discovery, the licensee reset the safety valve setpoints within the
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allowable tolerance and evaluated the safety significance of the "as found"
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out-of-tolerance safety valves. The licensee's evaluation concluded that there was
no safety consequence to the event, since the conditions were bounded by a
previous analysis that showed that design conditions would be maintained. A
recently completed analysis confirmed that the TS values for acceptable
out-of tolerance conditions on the pressurizer safety valves could be expanded to
l + 3 percent and -2 percent without impacting the design basis. The licensee was
l. cor}sidering applying for a change to the TS to allow for such an increase in setpoint
l tolerance. The inspectors concluded that the licensee's corrective actions,
l following discovery of the out-of-tolerance pressurizer safety valves, were timely
and thorough.
IV. Plant Support
R1 Radiological Protection and Chemistry Controls
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R1.1 Control of Radioactive Materials and Contamination. Survevina, and Monitorina
a. Inspection Scooe (83750)
Selected radiation workers and radiation protection personnel involved with the
control of radioactive material outside the radiologically controlled area were i
interviewed. Areas reviewed included: l
- Control of radioactive material; l
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- Release survey methods;
! * Frequency of surveys performed in the restricted area; and
I * Posting of radiological areas within the restricted area.
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The inspectors reviewed HP Procedure SO123-Vil-8, Revision 7, " Control of
Radioactive Material," and a memorandum to file, dated April 23,1993, " Evaluation
performed to determine the need to survey trash from the Restricted Area."
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b. Observations and Findinas l
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The amount of radioactive materialitems found outside the radiologically controlled I
area / radioactive material area boundary, and the origin of these items for the period l
of August 1995 to December 1996, were reviewed by the inspectors. The I
inspectors concluded, and the licensee agreed, that 25 radioactive material items I
documented in 18 radiological observation reports were found outside a i
radiologically controlleo area / radioactive material area. The origin of the items was )
as follows: I
six radioactive materialitems and one magenta-colored item originated inside l
a radiologically controlled area / radioactive material area. l
sixteen radioactive materialitems originated outside a radiologically
controlled area / radioactive material area.
- the origin of two radioactive material items could not be determined.
The inspectors interviewed security officers assigned to the restricted crea exit
points (security hold down area) and determined that all personnel were aware of
the requirement to have HP personnel approval prior to releasing vehicles carrying I
plant-related components from the restricted area. The inspectors reviewed
Security Procedure SO123-IV-5.3.3, Revision 3, " Search and Inspection." No
problems were identified with security personnel's involvement with the release of
items from the restricted area.
In general, no problems were found with the surveys performed prior to the release
of items from the restricted area. However, when the inspectors first asked the
Acting HP Manager if an aggregate survey was performed to detect an
accumulation of low level contamination, the inspectors were informed that this
type of survey was not performed. In later discussions with the Acting HP
Manager, the inspectors were informed that the licensee's program included the
requirement for aggregate surveys, as described in Section 6.1.3 of Procedure
SO123-Vil-20.9.2, " Material Release Surveys," Revision 1, and that this survey was
performed prior to the release of items from the restricted area. However, the
Acting HP manager also stated that he identified that some HP technicians not
normally assigned to the release of radioactive material from the restricted area
were not aware of the requirement to perform this survey. The Acting HP manager
stated that the need to perform aggregate surveys will be clarified with the staff.
The inspectors interviewed HP personnel assigned to release items from the
restricted area, and determined that all personnel knew to perform aggregate
surveys prior to the release of items from the restricted area.
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The inspectors reviewed Nuclear Training's on-the-job training manual," Material i
Release Qualification," and determined that the requirement to perform aggregate I
- surveys was adequately addressed in the material release qualification section. ,
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The inspectors reviewed the material release log, which documented whether a !
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radiological survey or evaluation was performed prior to releasing items from the
restricted area. No problems were identified with the material release log '
documentation.
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The inspectors interviewed a number of mechanical maintenance workers and (
determined that they knew to contact HP personnel prior to removing valves and l
other plant components from the restricted area. However, the workers stated, i
- they normally placed plant-related components for disposal or recycle in skiffs
(metal boxes) located in various areas within the restricted area. The inspectors ,
determined that there were no controls pertaining to the removal of items from
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these skiffs. i
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HP pcrsonnel stated that they remove and survey items from the skiffs as
necessary, and that they do not control the items that are placed in, or removed !
from, the skiffs until they_are surveyed. The inspectors observed that radioactive
material has been found by the licensee during these surveys. l
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During discussion with HP management, the inspectors were' informed that " clean" !
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trash dumpsters were not surveyed because a licensee-conducted study, dated t
April 23,1993, determined that "the risk of an uncontrolled,' inadvertent release of 1
i a detectable gaantity of licensed radioactive material to a sanitary landfill via clean i
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trash from the Restricted Area at SONGS is less than one chance in a million." The
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inspectors determined that this study was conducted during a time in which plant
related components were brought to a HP survey station (dogpound) where HP
- personnel were stationed to sutvey these items. The inspectors determined that the
3 licensee eliminated this HP survey station in November 1996.
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( The inspectors commented that, with the present way of discarding plant-related
components, there was a possibility of an item being discarded in a " clean" trash
dumpster. The licensee acknowledged the comment, and stated that the release of
" clean" trash dumpsters would be reevaluated.
The inspectors conducted several tours of the restricted area and noted that all
areas were properly posted in accordance with licensee procedures,
c. Cr.nclusions
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Overall, an adequate program was in place to control radioactive material outside a
radiologically controlled area / radioactive material area. No problems were identified
with security personnel's involvement with the release of items from the restricted ]
area. Some HP personnel did not know to perform aggregate surveys of items
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being released from the restricted area. Radiological areas within the restricted area
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were properly posted,
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V. Manaaement Meetinas
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X1 Exit Meeting Summary
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The inspectors presented the inspection results to members of licensee management ;
at exit meetings on March 28 and April 9,1997. The licensee acka~viedged tho - '
findings presented,
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The inspectors asked the licensee whether any materials examined during the I
inspection should be considered proprietary. Some price information in procurement I
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documents reviewed (Section E1.1) were confidentla! No other proprietary
information was identified.
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SUPPLEMENTAL INFORMATION
PARTIAL LIST OF PERSONS CONTACTED
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Licensee
D. Brieg, Manager, Station Technical '
J. Fee, Manager, Maintenance l
l- G. Gibson, Manager, Compliance
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D. Herbst, Manager, Site Quality Assurance ;
j R. Krieger, Vice President, Nuclear Generation i
l- J. Madigan, Acting Manager, Health Physics -
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H. Newton, Manager, Support Services
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J. Scott, Supervisor, Health Physics j
S. Schofield, Supervisor, Health Physics
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l D. Nunn, Vice President, Engineering and Technical Services
I T. Vogt, Plant' Superintendent, Units 2 and 3
R. Waldo, Manager, Operations
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l INSPECTION PROCEDURES USED ,
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IP 37551: .Onsite Engineering o
l , IP 42700: Plant Procedures
l' IP 61726: Surveillance Observations '
IP 62707: Maintenance Observations ,
IP 71707: Plant Operations
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IP 83750: Occupational Radiation Exposure
IP 90712: Inoffice Review of LER
IP 92700: On Site LER Review
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4 ITEMS OPENED AND CLOSED f
- Coened
50-361/97005-04 URI procurement and use of faulty SG manway gasket
4
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Ooened and Closed
- 50-361/97005-01. VIO pressurizer cooldown rate limit exceeded
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50-361/97005 02 NCV CEA withdrawal sequence for rod drop testing
50-362/97005-03 NCV improper BAMU flow rate setpoint
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50-361/97005-05 NCV EQ splice deficiencies
, Closed
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,- 50-362/96-005-00 LER reactor head vent valve mispositioned
50-361/96-008-00 LER RCP oil collection system
50-361/97-003-00 LER pressurizer safety valve sotpoints out of tolerance
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, LIST OF ACRONYMS USED
1
ABB Asea-Brown Boveri
4 ACO assistant control operator
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AR ' action request
BAMU boric acid makeup
- CEA control element assembly
j. CREACUS control room emergency air cleanup system
. CRS control room supervisor
s EQ environmentally qualified
i HP health physics
HVAC heating, ventilation, and air conditioning ,
g ICRR inverse count rate ratio
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LER licensee event report !
MO maintenance order -
, PDR Public Document Room
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l RCP reactor coolant pump i
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SG l
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SR surveillance requirement
i SS shift superintendent
.TS Technical Specification
- VCT volume control tank
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WPS weld procedure specification
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