ML20036B310
| ML20036B310 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 03/02/1992 |
| From: | Wenzinger E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | AFFILIATION NOT ASSIGNED |
| Shared Package | |
| ML20036A053 | List:
|
| References | |
| FOIA-92-162 NUDOCS 9305190084 | |
| Download: ML20036B310 (6) | |
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m oz a DearM I am responding to the concerns that you provided to us on May 28 and 30,1991, asserting that (1) a Millstone Unit 2 Instrumentation and Controls technician was not adequately trained to be a " job supervisor", resulting in an incorrect safety tagout, and (2) there were procedural adherence problems evident during the reactor trip on May 25,1991.
Your concem regarding the quali5 cation of the job supervisor was referred to Northeast Utilities (NU) for their evaluation; attached for your information is their response. The overall program for safety tagouts was independently inspected by the NRC, and the nndings of those inspections relative to tagging were pre ziously provided to you as an attachment to our letter to you dated December 12, 1991. In addition, routine resident inspection of tagouts dunng the May-June 1991 time frame found that appropriate controls for selected equipment were impbmented.
With regard to your speci5c issues, the tagout associated with the maintenance on the Clean Liquid Radioactive Waste Effluent Monitor (RM 9049) was concluded to be a valid concern.
The roci cause of the tagging error was an error made by a Plant Equipment Operator (PEO), although the error was not initially detected by the I&C personnel assigned to the task. Based on our independent inspection and the response from NU, no further action is planned by the NRC in this matter, and we consider this concern to be resolved. The recommendations of an NU Task Group instituted to review the tagout program at all three Millstone units will be evaluated by the NRC in the future.
Regarding the Unit 2 trip on May 25,1991, our inspection concluded that Operations appropriately adhered to operating procedures. An excerpt of the report documenting these nndings is attached for your information.
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i We appreciate you informing us of your concerns and feel that we have been responsive.
Should you have any additional questions regarding these matters, please call me collect at (215) 337-5225.
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Edward Wenzinger, C[e Reactor Projects Br Attachments: (1) NU Response Letter A09699 of September 13,1991 Gssue 116, pg. 7).
(2) Excerpts fret NRC Inspection R port 50-336/91-15 (Detail 3.0-3.2).
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September 13, 1991 Docket No. 50-336 A09699 FI: E=ployee Concerns i
Hr. Charles V. Eehl, Director Division of Reactor Projects U. S. Nuclear Regulatory Cot =ission Region I 475 Allendale Road King of Prussia, Pennsylvania 19406 i
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Dear Mr. Eehl:
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Millstone Nuclear Pover Station, Unit No. 2
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RI-91-A-0113N i
Ve have completed our reviev of the identified issues concerning activities l
at Millstone Station.
As requested in your transmittal letter, our does not contain any personal privacy, proprietary, or safeguards response infor:ation.
The material contained in this response may be released to the public and placed in the NRC Fublic Document Roo= at your discretion.
The NRC letter and our response have received e.ontrolled and limited distribution on a "need to knov" basis during the preparation of this l
Additional ti=e in which to respond to these issues vas granted response.
by the Staf f in tebohone conversations of August 12 and August 30, 1991.
ISSUE 113N:
On May 20, 1991, an operator observed an abnormal indication on the Unit 2 stack radiation monitor (RM B168).
The abnorcial indication was no variation on the meter. The operators secured and immediately reinstated power to the monitor and the meter response vas noted to have returned.
On May 21, operators again observed no variation in the monitor output. A trouble report was initiated and-the technica; specification action was entered for an inoperable monitor. The one day delay is an statement example of operators failing to promptly initiate a corrective action and failing to enter the technical specification action state =ents request when required.
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Mr. Charles V. Eehl, Director r
U. S. Nuclear Regulatory Commission A09699/Fage 2 September 13, 1991 c
'equest:
as.ertions.
If any deficiencies
. lease discuss the validity of the above
=
are identified, please provide us with the corrective actions you have taken to prevent recurrence and assess the significance with regard to safety of the identified deficiencies.
ISSUE 136:
From June 3 to June 5, 1991 repetitive failures vere noted in the control room indication for the Unit 2 vent stack high range radiation :onitor RM8168A/B. On June 3 the " failure" la:p vas lit, and on June 5, 1991 a l
" Trouble Tag" vas found to be in place.
The required technical specification action state:ents vere not co: plied vith during these l
repetitive failures.
Request:
Please discuss the validity of the above assertions. If any deficiencies in equip =ent availability or procedure co:pliance are identified, please j
recurrence provide as with the corrective actions you have taken to prevent and provide an assess:ent of tne significance of the deficiencies with l
l respect to safety.
t Responses 113 & 136:
As issues 113 and 136 both deal vith technical specification acticn state:ents relating to radiation monitor RM 8168, they vill both be ansvered in a single response as follovs.
The chrerology of observations reported in the two issues agrees with en; ries in the Millstone Unit No. 2 Shift Supervisor's log, and with a chronology of Instru:entation & Controls (I&C) Department troubleshooting i
and repair activities.
c to the specific decisions cited or implied in Issues 113 and 13f, Relative no f ailures to take required action occurred, as discussed in the folloving co :ents.
Taking immediate action to restore nor:al system output following an observed abnor:a1 indication on RM 8168 vas an appropriate response for a Such occurrences single ' lockup' of this :icroprocessor-based instru=ent.
are not unusual.
Re:oving power to this monitor and then immediately restoring it, in effect " resets" the device to its normal : ode of operation.
For this reason, the instru ent is :onitored routinely. It vould not be necessary to sub:it a Trouble Report (TR) for such an isolated anc:aly since the operator was able to 1 :ediately restore expected display and the full operational capability of the device vas confir:ed.
- outputs, entry into an action state:ent vould not te appropriate since Furthermore, the radiatien enitor operated pre;erly ence it was reset.
M. Charles V. Bohl, Director g
U. S. Nuclear Regulatory Commission A09699/Page 3 September 13, 1991 The RM 8168 performance anomaly observed on the morning of May 21 was repetitive, not understood, and not resettable.
Evaluating the radiation monitor as 'out of service" as indicated by the Shift Supervisor's log entry of 0800, the operators entered the applicable Technical Specification action statement, and remained in that condition until May 23, 1991, when replacement of a f ailed power supply was completed af ter IEC identif'ed the cause of the indication problems es a broken vire and failed 24 volt output.
Since the performance anomaly observed on the morning of May 21 vas repetitive, not understood, and not resettable, both actions (i.e.,
submitting the Trouble Report and entering the Technical Specification action statement. Table 3.3-6, Action 17) vere clearly appropriate.
During the period from June 3 to June 5, 1991 Millstone Unit No. 2 was in Mode 5.
In Mode 5 radiation detector RM 8168 is not required to be operable, hence under no conditions of RM B168 performance vould the plant have entered into, or been operated in accordance with, the Technical Specification action statement for RM 816e.
The two scenarios noted above vere the result of a single problem. During the period f rom approximately May 24 through late July 1991, the LIC-8168 power supply anomaly caued intermittent power failure interrupts to be processed by the microprocessor. The intermittent lockup problem ceused RM 8168 to stop normal processing functions, recognizable in the control room by the radiation monitor display not changing and set responding to the test push button. This problem vas knovn to the control room operators, and corrective action to reset the radiatien monitor was taken as needed.
Throughout this period, it was the judgment of on-shift supervisory personnel, Operatiens management, and I&C management (specifically discussed in a draft Operability Evaluatien approved by the I&C Manager on July 19, 1991),
that RM 816e remained cperable, i.e.
fully capable of meeting its Technical Specification functions.
In summary, after troubleshooting was completed, it was concluded that RM 8168 vas operated in a slightly degraded state for several veeks. This degradation manifested itself to control room operators as an intermittent lockup of the radiation monitor, easily reset by on-shift operations personnel.
These personnel vere alerted to the problem and checked the monitor regularly for proper operation.
On-shift supervisory personnel are tasked with initiating the appropriate i
corrective action and compensatory measures for equipment performance problems encountered during their shift. Judgment is frequently involved j
in such determinations.
Supervisors in the Operations Department are
- selected, trained, counseled and evaluated on their performance in such activities. The Operations Manager, other members of plant management, and specifically the Unit Duty Officer are available to consult with the Shift
__m Mr. Charles V. Fehl, Director U. S. Nuclear Regulatory Commission A09699/Page 4 September 13, 1991 level of response required for a given plant Supervisor concerning the Similarly, various sembers of the staff review plant performance ano=aly.
performance and corrective actions taken on a regular basis during the and j
vorkday; in this fashion shift operators' responses receive frequent l
multidisciplinary reviews on a continuing basis.
described in Issues 113 and 136, nor at any At no time during the events time during the period of degraded RM 8168 operations, vere the Shift or the need for corrective Supervisors' judgments concerning operability action found to be in error. Therefore, these assertions are not valid.
Ve vere not aware that these vere issues of concern prior to receiving your-letter of July 9,1991.
I 1
5 ISSUE 114-1 (Unit 3):
1 On May 22, 1991 during the MP-3 refuel outage a calibration error of the 1
tank level transmitters was identified. The error vas in the j
accu:ulator range of 25% due to static fluid between the transmitter and the instrument i
The calibration procedure did not address the error due to the level I
taps.
instrumentation piping configuration; therefore, the procedure was inadequate. Further, if the present instrument indication is correct, then it vas achieved by using zero span adjust:ents without adhering to the i
calibration procedure.
\\
I Request (Unit 3):
Please discuss the validity of the above assertions.
If any deficiencies are identified, please in calibration procedures or procedural co=pliance vith the corrective actions you have taken to prevent provide us Please provide us with an assessment of the significance with recurrence.
regard to safety of any identified deficiencies.
Response
made in issue 114-1.
A Ve have found no justification for the statements calibration of the accumulator tank level transmitters was started on February 7, 1991 and successfully completed on March 18, 1991.
No vork vas on May 22, 1991, nor does the Shift Supervisor's log indicate performed that such an error vas identified on or near that date.
An error of 8.5% vas found to exist between level indications on a common accu ulator after co:pletion of the refuel outage calibration dated yebruary 18, 1991.
This was in excess of the 5% desired maximum error between cotmon channels and pro:pted a survey of "As-T.uilt" transmitter c-March 16, 1991.
The Engineering Calculation and installations vere revised to reflect the survey data. A second calibration Surveillance was ce:pleted en March 18, 1991 vith a noted raxi=um error of 0.47%.
Mr. Charles V. Behl, Director
]
U. S. Nuclear Regulatory Commission
{
A09699/Page 5 September-13, 1991 j
The difference betveen indicated and actual level for the period of j
February 18, 1991 to March 18, 1991 vas 13.3%.
)
elevation differences discovered between channels, we
]
As a result of the know that the maximum and minimum indicated range is different for each i
i transmitter.
An example is that one indicator vould read dovn to 6550 1
gallons while the other indicator on the same tank vould stop at 6555 There is no safety significance involved with the difference as j
i gallons.these indicated ranges are vell beyond the operating-limits specified l
l l
both in Technical Specifications.
Tellov caution tags have been placed on the indicators to specify the minimum and maximum display values for each transmitter.
New readout scales have been generated for the indicators to allow removal of the yellov caution tags. Ve are currently verking to install these readout l
y scales.
Ve are confident that the new method of calibration is more accurate, more l
7 repeatable and less ti:e consuming to perform.
Indication differences l
between redundant channels on all accumulators are less than 44 gallons.
t The present instrument Indication is correct and the new calibration method The calibration procedure vas always adhered to
}
improve reliability.
vill i
calibrations. No zero or span adjustments vere made unless directed during by procedure, which is based on the Engineering Calculation.
This is therefore not valid, and ve vere not aware that this was a assertion concern until notification by the Staf f's letter of July 9,1991.
ISSUE 114-2 (Unit 1):
On May 22, 1991 during the installation of the IRM cable detector under the reactor vessel, the RiTP/EP controls vere inadequate assemblies and resulted in the possible ingestion of radioactive caterial by a vorker, t
The cable was identified as "5K smearable" on May 22, 1991 and the RVP required workers to vear respirators.
Hovever, on May 21, 1991, the RVP did not require respirators to do the sa:e job.
Request (Unit 1):
Please discuss the validity of the above assertions. If any defielencies are identified, please provide us with the corrective actions you have taken to prevent recurrence.
Please provide us with an assessment of the significance with regard to safety of any identified deficiencies.
Response
This assertion is not valid. The Eealth Physics controls for the under vessel IPydSRM vork vere both adequate and conservative.
Mr. Charles V. Eehl, Digector U. S. Nucloar Regulatory Commission 7
A09699/Page 6 September 13, 1991 The "5K smearable" referred to in issue 114-2 is the loose surface 4
contamination detected during health physics surveys. This information is expressed in terms of thousands of disintegrations per minute (dps) over a surface area of 100 square centimeters (cm2).
On May 22, 1991, the radiological data for the IRM cable verk indicated a range of smearable contamination from SK to 300K dp /100 cm2 loose surface contamination. On the previous day the loose surface contamination had been 20K to 50K dps/100 cm2.
2 The Bealth Physics department uses air samples in conjunction with a threshold loose surface centamination value of 100K dps/100 cm2 for considering the required use of respiratory protection for this type of vork.
On May 21, conditions vere such that the RVP required face shields and respiratory protection only if the work area contained dripping vater from above. On May 22, as a result of the work done the previous day the loose surface contamination survey results increased from the previous day's maximum of SCK to a new value of 300K.
The air sample data obtained during and after the previous day's work did not require the use of respirators.
Bovever, based on this change in smearable contamination in the vork area, Eealth Physics took the conservative step of requiring rerpirators.
r The actions of Health Physics in requiring respirators on the day at issue was a conservative step and no safety deficiencies are indicated. A review of personnel contamination events for the month of_May 1991, reveals no result of IRM/SRM under-vessel vork.
personnel contamination events as a Ve vere not aware of this concern until receipt of the Staff's letter.
I ISSUE 116:
Recently, a tagging error occurred during preparations for maintenance on the Clean Liquid Radioactive Vaste Effluent Monitor (RM 9049).
The i
solenoid valve isolation valves that needed to be tagged in accordance with prerequisites for the job vere not tagged.
Specifically, the valves to be traced by procedures IC2404AA and IC 2404AC vere not designated The traced because the operations tag form was used to verify the tagging.
root cause of the error can be attributed to the I&C technician (who verified the tagging) not being trained and qualified as a " job supervisor". Although there was a qualified job supervisor associated with the work, this individual was allowed to leave the vork area while an l
unqualified individual continued the job.
Request:
Please discuss the validity of the above assertions. If any deficiencies in vork control are identified, please provide us with the corrective i
actions you have taken to prevent recurrence and assess the significance of the deficiencies with respect to safety.
i
Mr. Charles V. Echl, Director U. 5. Fuelear Regulatory Commission A09699/Page 7 September 13, 1991
Response
This is a valid concern. The root cause of the tagging error at issue was a personnel error made by a plant equipment operator who placed the tags on the wrong ulves.
This error vas not detected by the IEC personnel assigned to the task who vere expected to verify the adequacy and placament of the tagging. Verification was only made of the adequacy of the tagging documented by the completed tag log sheet in the Automated Vork Order (AVO) l package.
The actual placement of the tags was not verified as correct as l
required bf procedure ACP 2.02C - Vork Orders.
l Ve vere avere of this issue prior to receipt of the Staff's notification.
As one action to prevent recurrence, all I&C personnel have been reminded of their responsibility to verify both the adequacy and the placement of safety *agging. There vas no safety significance to the tagging error that was made. There vere no releases as a result of this event.
A task group has been formed to reviev tagging errors at all three Millstone units and provide an assessment of the level of performance of the station regarding the quality and implementation of the tagging program.
This group vill also provide recommendations to station manage ent for ensuring that plant procedures and their use by our employees are adequate to minimize tagging errors in the future.
This group vill present its recommendations to improve the program along with an action plan far enhanced human performance to station management for reviev.
If appropriate, a meeting with Region I Staff vill be s :heduled at the completion of this review to discuss the results of any actions planned.
ISSUE 122:
On or about May 29, 1991 vork=en vere dispatched to troubleshoot a flow problem with the plant vent stack monitor (RM 8032AB) [ sic). At the time, the "A" sample pump vas running, pump "B" vas of f and flov vas as expected.
The pumps vere switched to permit the workers to investigate the flow problem. Pump "A" vas stopped, but "B" did not start due to a preventive maintenance action that sas still in progress.
As a result, the stack l
monitor was out of service for 10-15 minutes.
Request:
Please discuss the validity of the above assertions. If any deficiencies in vork control are identified, please provide us with the corrective actions you have taken to prevent recurrence and assess the significance of the deficiencies with respect to safety.
?
Mr. Charles V. Behl, Director U. S. Nuclear Regulatory Commission A09699/Page 8 September 13, 1991
Response
This assertion is not valid.
On May 27, 1991 e trnuble report was submitted to the Maintenance department to determine why the RM 8132 sample fan vould not develop proper flov. Later that same evening the sample fan was tagged out of service. On May 29, 1991 I&C personnel vorked on RM 81323, using AVO M2-91-05446, to check the lov flow problem identified on May 27.
The " Tagging Required" section of the AVO indicated that a Technical Specification action statement was involved. This entry vns ande by the control room operator at the tice the AVO vas released.
May 29, at 1310 hours0.0152 days <br />0.364 hours <br />0.00217 weeks <br />4.98455e-4 months <br />, the plant entered Technical Specification action On statement 3.3.3.10.a. Table 3.3-13, Action 2 fer RM 8132 being out of service.
The plant was logged out of the action statement at 1740 hours0.0201 days <br />0.483 hours <br />0.00288 weeks <br />6.6207e-4 months <br /> that same day. Nothing in the Shift Supervisor's log indin' 's this vas anything other than a planned event. Realizing that one :< am, e pu=p vas out of service for preventive =aintenance and that the other might have j
flow proble=s, it was proper to enter the action statement and
[
trouble-shoot the re=aining pu=p.
Ve find no work control deficiency associated with this mainte-nance / trouble-shooting activity. Ve vere not aware that this vas an issue of concern prior to receipt of the Staf f's letter.
ISSUE 128:
On June 1,1991 a vorker learned that he had been assigned duty as the on-call I&C technician (Unit 2 Emergency plan) for a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period from the corning of May 30 through the corning of May 31, 1991. The worker vas l
unavare of this assign =ent on May 29 vhen he informed his supervisor that he vould not be at vork on May 30 for personal reasons. The verker did not pick up the department radio paging device and no one else was assigned as his replace =ent.
Lapses in on-call coverage such as this exa=ple occur on a routine f requency.
i Reques t:
Please discuss the validity of the above assertions. If any deficiencies in the on-call coverage for e=ergency planning are identified, please provide us with the corrective actions you have taken to prevent In addition, please assess the frequency and significance with recurrence.
respect to safety of lapses in on-call coverage by the Instrument and Controls and Maintenance technical staffs.
Response
This is a valid concern, of which Northeast Nuclear Energy Company (NNECO) is vell avare.
A lapse in on-call coverage for this particular I&C Technician position did occur on May 32, 1991.
- Eevever, three I&C Technicians and three Maintenance Technicians, ene per unit, are on call at any ti:e.
~
Mr. Charles V. Behl, Director U. S. Nuclear Pegulatory Commission A09699/Page 9 September 13, 1991 On-call schedules are published monthly and cover a period of one sonth and five days. They are distributed at the end of each month so that the on-call personnel know their assignments for the upcoming month. A person assigned to be on-call May 30/31 vould have been made avare of that by receiving a copy of the on-call list in late April.
It is assignment responsibility of the individual to review the list on a regular basis the to ensure that they pick up a radiopager on their assigned days.
Being excused from vork for personal reasons does not automatically release an individual from on-call responsibilities. Emergency Plan Implementation (EPIP) 4211 directs an individual on-call but unable to fulfill Procedure their on-call obligations to arrange for a qualified substitute themselves.
An exception to this is if a person calls in sick on the day they are to assume the on-call responsibilities. Then supervision vill assign another individual. If an individual beco:es incapacitated or otherwise unable to fulfill their on-call responsibilities outside of normal vorking hours, 4211 directs that individual to notify the Hillstone Unit No.1 Shif t EPIP Supervisor (SS) vho vill assign the Millstone Unit No.1 Shif t Supervisor Staff Assistant (SSSA) to find a qualified relief.
The purpose of the on-call Station Emergency Organization (SEO) is to provide augmentation of shift personnel to previde adequate and timely to abnormal and emergency conditions. Any one syste has failure response probabilities, e.g., individual pager failure, auto accident or breakdown response, etc. In view of this, Millstone Station has developed a during response in-depth program which provides reasonable assurance that adequate SE0 staffing is available in a timely manner. The I&C and Maintenance Supervisors also supplement the SEO thereby exceeding Emergency Plan requirements.
Lapses in on-call coverage for certain technician positions occur more frequently than ve consider acceptable f rom a management perspective but from a safety perspective. Ve have not had a total lapse in coverage not for any of the Maintenance or I&C technician positions this year because of our resp,nse in-depth approach.
If an individual from Millstone Unit No. 2 did not respond to a radiopager message during an emergency, the Hillstone Unit No. 1 SSSA, upon notificatien by the Millstone Unit No.
2 SS, vould call that individual at home using the telephone. If the individual could be reached or vas not able to respond, the Hillstone Unit No. 1 SSSA not vill contact the next person on the on-call schedule for the same position to determine availability to assume the on-call assignment. If necessary the SSSA vill continue to call until a qualified relief is found.
This process limits the significance of any lapses in coverage.
NNECO has recently upgraded the Emergency Notification System to automatically verify the on-call SEO positions that have been notified of the event (called into the station syste ).
This enables ti.e on-shift emergency coccunicators to make back-up calls to alternate SEO ce=bers.
Each SEO pesition has a mini u: of five trained staff and most non-manager positions have betveen ten and tventy. Ve have taken further steps to strengthen the on-call assignment to the SEO, disse:ination of on-call schedules to individuals, and have a traceable reans ef verificatic::
Mr. Charles V. Hehl, Director
]
U. S. Nuclear Regulatory Commission a'
A09699/Poge 10 September 13, 1991 revision is planned to EPIP 4211 "On Call Procedure",
i 1.
A majcr and strengthening the responsibilities of the Lead Managers 4
clarifying s
and on-call individuals.
Emergency Plan Coordinator has been assigned t
2.
The station's for maintaining and monitoring of the on-call schedule.
responsibility l
l 3.
A new procedure, EPIP 4617. " Station Emergency Organization Response Verification Drill", to require a quarterly unannounced activation of i
the SEO is under final reviev.
ISSUE 129:
June 3,1991, the periodic evolution of refilling the volume control (VCT) level instru:ent reference leg vas perforced in accordance with On procedure IC-2428P.
During the reference leg fill, a vorker noted an tank unexpected increase in VCT level. Because of this unexpected increase, it suspected that the evolution actually drained the VCT reference leg.
This observation was reported to supervision. Pressure in the primary was L
eakeup vater supply was checked, and it vas discovered that valve 2CB-195 in the supply path vas red tagged closed instead of being in the open specified by step 6.2 of procedure IC-2428P.
The valve l
position as At that check had been performed by a Plant Equipment Operator.
time the PE0 did not perform a hands-on position check of valve 2CS-195 and alignment There was a to notice the red tag indicating the valve vas closed.
failed betveen the vork procedure IC-2428F, which required valve 2CH-195 conflict to be open, and the requirement to prevent boron dilution during reactor shutdovn, which required the valve to be closed.
Request:
Please discuss the validity cf the above assertions.
If any deficiencies in vork centrol, attent2cn to detail, or vork procedures are identified, the corrective actions you have taken to prevent provide us with please and provide an assessment of the significance of the deficiency recurrence with respect to safety.
Response
In stating that valve 2CE-195 was tagged closed, as required to prevent boron dilution during reactor shutdowm, the assertion is accurate.
vith the I&C and Operations personnel involved have determined Interviews there was a miscommunication regarding whether or not the valve lineup The Plant Equipment Operator (PEO) had not previously that had been completed.
told the I&C technician that the valve lineup had been completed when he vas informed that the valve had been found closed.
The importance of cc:plete and precise co==unications is stressed regularly to M111stene Unit No. 2 operators, and exa:ples of intra-and inter-depart ental co==unicatien shortco ings are used in training and counseling sessi:ns.
Mr. Charles V. Behl, Director U. S. Nuclear Regulatogy Commission A09699/Page 18 September 13, 1991 As this was the required valve position for the reactor conditions, and i
procedure IC 2428F is designed to ensure that the reference leg filling evolution does not adversely impact the VCT level indication process, there no safety significance involved.
Ve ve.e not aware that this was an vas l
issue of concern prior to receipt of the Staff's letter.
ISSUE 130:
On May 31, 1991, during the replacement of a local pressure indication gage PIB167 in the condensate recovery system a vorker was issued the wrong part (diaphragm isolated liquid filled gage [ sic]) to replace a conventional gage that was already in service. Instrument and Controls supervision is i
responsible to verify plant and equipment conditions, such as replacement part suitability before authorizing vork on a system.
Request:
Please discuss the validity of the <bove assertions. If any deficiencies are identified, please provide us with the corrective actions you have taken to prevent recurrence and provide an assess:ent with respect to safety of the deficiency.
I
Response
The issue of the vrong gauge being issued to be installed is accurate. The difference in gauge type vas noted by the instrument specialist and he obtained and installed the correct codel gauge.
Issuing replace:ent parts is not a normal activity for the first-line supervisor.
Typically, replacement parts are identified and drawn from those maintained in stock. In this case the parts vere kept in the I&C shop and the box in which the parts vere stored was mislabeled. The j
supervisor mistook the diaphragm isolated gauge as one appropriate to be installed in this application.
There is no safety significance to this event. The pressure gauge monitors the discharge pressure of the auxiliary steam system condensate recovery tank.
This system has no safety function and the proper gauge vas identified and installed. For safety-related systems, the parts required for maintenance are obtained from the Stores Department via a Material Issue Form which documents traceability of the parts issued. No additional action to prevent recurrence, other than review of the issue with the supervisor, is planned.
After our reviev and evaluation, ve find that these issues did not present any indication of a ec promise of nuclear safety. Ve recognize the need to strive for a higher level of performance in these areas and we are aggressively working toward that objective. Ve appreciate the opportunity
Mr. Charles V. Behl, Director U. S. Nuclear Regulatory Commission A09699/Page 12 September 13, 1991 to respond and explain the basis of our actions and we appreciate your granting additional-time beyond the original 30 days for us to complete our vork.
Please contact my staff if there are further questions on any of these matters.
Very truly yours, NORTHEAST NUCLEAR ENERGY COMPANY M
E. J.~ Kroczka 6/
Senior Vice President cc:
V.
J. Raymond, Senior Resident Inspector, Millstone Unit Nos.
1, 2, and 3 E.
C. Ven:inger, Chief, Projects Branch No.
4, Division of Reactor Projects E. M. Kelly, Chief, Reactor Projects Section 4A J. T. Shedlosky, NRC, Millstone Nuclear Pover Station i
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475 ALLENDALE ROAD E.NG cF PRusstA, PENNSYLVANIA 19436-1415
\\.*.... f M 12 M Docket No. 50-336 Mr. E. J. Mroczka Senior Vice President - Nuclear Engineering and Operations Northeast Nuclear Energy Company P.O. Box 270 Hartford, Connecticut 06141-0270
Dear Mr. Mroczka:
Subject:
Millstone Unit 2 Inspection 91-15 This refers to the routine safety inspection conducted by Mr. P. Habighorst of this office on at Millstone Unit 2. The preliminary findings were discussed with May 14 - June 22,1991, Mr. J. S. Keenan and other members of your staff at the conclusion of the inspection.
l t
Within these Areas examir.ed during the inspection are described in the enclosed report.
areas, the inspection focused on issues important to public health and safety, and consisted of performance obsenations of ongoing activities, independent venfication of sarety system status and desigr. configuration, interviews with personnel, and review of records.
Overall facility operation and the conduct of shutdown activities were satisfactory. Plant staff responded conservatively to increasing steam generator leakage trends and performed well to bring the plant to cold shutdown to repair a tube leak in the No. 2 steam generator. Better crew coordination and communication could have avoided an automatic trip during the shutdown. Actions to repair the tube leak and to characterize steam generator tube conditions were extensive and thorough. Plant actions to assure contammenrmtegrity and redundant i
power supplies during reduced inventory operations demonstrated good awareness of and management of shutdown risks.
Your cooperation with us is appreciated.
- incerely, q,, /
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o Edward C.
'enzinger, Chi Projects Branch No. 4 Division of Reactor Projects
Enclosures:
As Stated I
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(;0
M 1S Cc W/efici.
W. D. Romberg, Vice President, Nuclear Operations D. O. Nordquist, Director of Quality Service:
j R. M. Kacich, Manager, Nucier Licensing S. E. Scace, Nuclear Station Director, Mills:one i
J. S. Keenan, Nuclear Unit Director, Millstone Unit 2 Gerald Garneld, Esquire K. Abraham, PAO (2)
Public Document Room (PDR) l Local Public Document Room (LPDR)
Nuclear Safety Ir. formation Center (NSIC)
NRC Resident inspector i
State of Connecticut bec w/ enc!:
Region 1 Docket Room (with concurrences)
Management Assistant, DRSIA (w/o enc!)
E. Wenzinger. JRP 1
E. Kelly, DRP W. Raymond. SRI, Millstone J. Shedlosky, SRI, Haddam Neck K. Brockman, EDO l
G. V:ssing, PM, NRR P. Rosa, NRR (Section 6.4)
J. Jo, er, DRSS (Sections 3.3.1 and 4.0) n J. Jang, DRSS (Section 6.1)
J. Durr, DRS (Sections 6.* and 6.5) bc: w!Repon Cover Sheet and Executive Summary only:
W. Hehl, DRP J. Wiggins, DRP W. Hodges. DRS W.12nning, DRS j
L. Bettenhausen, DRS R. Cooper, DRSS J. Stolz, NRR/PDI-4 S. Stewart, DRP i
- - =
U.S. NUCLEAR REGULATORY COMMISSION REGION I Report /
Docket No.:
50-336/91-15 License No.:
DPR-65 Northeast Nuclear Energy Company Licensee:
P. O. Box 270 Hanford, CT M141-0270 l
Millstone Nuclear Power Station, Unit 2 i
Facility Name:
l Inspection At:
Waterford, CT
\\
Dates:
May 14 - June 22,1991 P. J. Habighorst, Resident Inspector, Unit '
laspectors:
W. L Raymond, Senior Resident Inspector, MiUstone R. A. McEreany, Reactor Engineer, MPS, DRS
~*
-/
4M Approved by:
Dat'e Eugene M. Kelly, Chief..'
Reactor Projects Section 4 A Routine NRC inspection of plant operations, radiological controls, Areas Inspected:
maintenance, sur eillance. outage activities, licensee self-assessment, and periodic repons.
Results: See Executive Summary
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EXECUTIVE
SUMMARY
MILLSTONE UNIT 2 INSPECTION 91-15 Plant 09eratiens Generally good performance was noted by plant personnel to complete a a steam generator tube leak. An exception to good performance was a defici coordination and communication during the shutdown of the main turbine, result subcritical automatic reactor trip. NNECO actions were appropriately focused performance deficiency.
Controls during mid. loop operations were satisfactorily implemented. Licensee m of both emergency power sources availability and implementation of containm controls exemplified good awareness of and management of shutdown risk.
t l
E_adiologica! Protection R2diation pro:ection controls for outage activities inside the containment were w implemented, and a signi5 cant personne! exposure reduction was noted l
steam generator manways.
Main'enance'Surs eillance NNECO correctise ac:fons to address the cracked charging pump b!ock were satisfa f
The preventive progra:n to trend the modined block performance was a good response to a design problem. Other maintenance and surveillance activities acceptably implemented. The NNECO program to use limiting conditions for o perform preventative maintenance is adequate to assure plant safety while l
equipment rehability.
Enginee-ine and Technical Sutmort A questioning attitude regarding quality indicators for the emergency diese exemplified a good safety ethic; however, engineering interface with opera regarding the operability status of the valves.
I An unresolved item (91-15-01) was opened to determine whether the Millstone 2 electrical distribution system complies with 10 CFR 50 Appendix A, Criterion 17.
Scope and selection basis for the steam generator tube inspections we r e$ odica].
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Safety Assessment Ouality Vedficatim
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LER 91-003-00 documented an inadequate design modification as a contributing root cause for a postulated loss of DC switchgear cooling, yet no corrective action existed at the time of this inspction. Furthermore, NRC Generic Letter 88-14 requested verification of system design based on instrument air failure modes. NNECO actions to meet their commitments and to correct identified deficiencies in this instance were an exception to generally good performance. This item is unresolved pending future inspection of NNECO action address root causes of deficiencies (UNR 91-15-02).
1 I
I 1
115
TABI E OF CONTENTS 1
1.0 SCOPE............................................
1 2.0
SUMMARY
OF FACILITY ACTIVITIES......................
1 3.0 PLANT OPERATIONS (IP 71707) 1 3.1 Operations! Safety verification.........................
4 3.2 Onsite Followup of Operational Events....................
8 3.3 Outage Activities..............................
13 3.4 Operator Requalification Exams.................
3.5 NRC Information Notice 90-54: Summary of Requalification 13 Program Deficiencies...............................
14 RADIOLOGICAL AND CHEMISTRY CONTROLS (IP 71707) 14 4.0 4.1 Posting and Control of Radiological Areas...............
14 l
4.2 Radio!cgical Controls During the Forced Outage l
15 MAINTES ASCE/ SURVEILLANCE (IP 61726!62703/37701/927 15 5.0 5.1 Observation of Maintenance Activities....
15 l
5.2 Charging Pump Block Crack 17 5.3 LCO Maintenance.....
19 Reactor Building Component Cooling Water Sea! Rsturn 20 5.4 5.5 Previously Identified Items.
21 5.6 Observation of Surveillance Activities 24 5.7 Previously Identified items 25 ENGINEERING' TECHNICAL SUPPORT OP 92701/93702) 25 6.0 6.1 Change m Engineering Organization
. 25 Previous!y Identified items....
6.2 26 Emergency Diesel Generator Air Stan Vent Solenoid Classinc.ation 6.3 27 6.4 Elec:rical System Compliance with GDC 17..
30 6.5 Steam Generator Tube Inspections.....
32 6.6 Seismic Qualification of Diesel Gages....
34 SAFETY ASSESSMENT / QUALITY VERIFICATION (IP 90713/927 34 7.0 7.1 Licensee Event Reports.........................
... 35 7.2 Periodie Reports.............
36 7.3 Previc4y Identified Items.......
36 S.0 MANAGEMENT MEET 1h'GS....
The inspection procedure (IP) or temporary instructions (TI) from NRC Manu that was used as guidance is parenthetically listed for each report section.
r.
DETAILS 1.0 SCOPE Within this report period, interviews and discussions were conducted with members of Northeast Nuclear Energy Company (NNECO) mana;;ement and staff as necessarf to support inspection activity.
Resident activities during this report period included 167 hours0.00193 days <br />0.0464 hours <br />2.761243e-4 weeks <br />6.35435e-5 months <br /> of inspection. In addition to normal working hours, review of plant operations was conducted during periods of backshifts (evening shifts) and deep backshifts (weekends, holidays, and midnight shifts). Inspection coverage included 31 hours3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br /> of backshift and 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> of deep backshift.
2.0
SUMMARY
OF FACILITY ACTIVITIES Millstone 2 began the inspection period at full rated power. On May 25 at 1:25 a.m., the licensee identified an increase in primary-to-secondary leakag:: on the main steam line (Nitrogen-16 monitors). The leakage in the No. 2 steam generator increased to approximately 50 gallons per day (gpd) at 6:00 a.m. At 1:55 p.m., NNECO management ordered a plant shutdown. The shutdown was originally scheduled for 18 days to identify and repair the steam ger.crator tubes. On May 30, NUSCO management decided to extend the outage to perform a comprehensive and expanded steam generator tube inspection.
At the end of the inspection period, the plant was in cold shutdown, and steam generator eddy current inspections were in prog ess.
3.0 PLANT OPERATIONS (IP 71707) 3.1 Operational Safety Verification This inspection consisted of selective examinations of control room activities, operability reviews of engineered safety feature systems, plant tours, review of the problem-identification systems, and attendance at periodic planning meetings.
~
Control room reviews consisted of verification of staffing, operator procedural adherence, operator cognizance of control room alarms, conformance with technical specification limiting l
conditions of operation, and electrical distribution status verifications.
i Administrative control procedure (ACP) - 6.01,
- Control Room," identifies the minimum I
staffing requirements and the required protocol within the control room. During this inspection period, the requirements were observed by the inspectors to met for the number of licensed operators in the control room during power and shutdown conditions. Operator attentiveness and cognizance of plant conditions was acceptable.
2 Inspection was performed of operator prc>:edural adherence during the plant reactor trip (repon detail 3.2), and routinely during periodic equipment outages, in i
tests, daily technical specification surveillances, steam generator leak testing, an equipment surveillance. Operator actions were coordinated and well controlle room operators were ecgnizant of control room alanns both during power opera shutdown operations. Actions taken in response to alarms were timely and appro Primarv to Secondary leakaze The inspector reviewed the status of primary-to-secondary leakage following th repair the tube leak in the #1 steam generator. The review was completed the plant operating at 100% full power. NNECO monitored steam generator the nitrogen-16 (N 16), blowdown and offgas radiation monitors, and by direct ch sampling and analysis of secondary water.
The leakage rates in both generators were below the technical specification limit of gaHons per day. Residual activity was present in the SG No. I secondary s hide-out return from the activity and tube leak present before the shutdown. Allleak ind;cators showed low, decreasing trends for primary-to-secondary leak rates.
NRC review noted an abnormal value on the daily Chemistry Status Sheet on May 13 30 a.m. entry for N-16 showed a 115 gallon per day (GFD) leak rate on the #1 steam generator. The inspector noted that the N-16 readouts at 5:00 p.m. were 0.1 4:
for SG No. I and SG No. 2. respectively. The abnormal value was discussed with cont room personnel, who de: ermined the entry was in error. The inspector noted that th abnormal ent:y had not been highlighted by operators during routme review of chemistr cata, which was contrary to otherwise good performance in maintaining operating status records. NNECO performance in operating status reviews will be reviewed in the future as part of routine resident inspections.
Radiation Monitorine LCOs Tne inspector reviewed adherence to technical specification (TS) requirements. The limiting conditions for operations were entered during the outage for various radiation monitors and fire protection seals. The radiation monitors that were out of senice at vario times during the outage were the steam generator blowdown monitor, stack radiation aerated liquid radiation monitor, and containment radiation monitors. NhTCO took appropriate actions for allinstances reviewed, including chemistry grab sample of the ventilation systems. The inspector verified through fire watch log entries, that the required hourly watches were being performed on inoperable fire ' carriers.
3 Svs'em Alienments Inspection of the onsite electrical distribution system determined that operability of the emergency core cooling pumps and valves, emergency diesel generators, radiadon mo and various engineered safety feature equipment was acceptable. The distribution system wa also reviewed during outages on the non-emergency 4.16KV 24A and 24B buses to verify independence, when required, and proper alignments. During emergency diesel outa facility emergency core cooling pumps on the operable emergency source was preser Operability reviewr of the engineered safety feature systems included periodic v t
valve lineups, power supplies, and flow paths for the high pressure safety injection system the low pressure safety injection system (during shutdown cooling operations), the ch system, the containment spray system, the containment purge isolation system, cont air conditioning system, emergency diesel generators and auxiliaries, and the auxiliary feedwater system. Satisfactory conditions were observed.
Jumners Various bypass jumpers were reviewed for conformance with ACP-QA-2.06B with emp on installation, and,if applicable, the content of the safety evaluations. Specific bypass jumpers reviewed were 2-91-36, " Tie in temporary outside compressor station air su during station air compressor maintenance," 2-91-37, " Installation of a temporary gaug the "A" boric acid pump discharge," and 2-91-24, " Removal of automatic closure of shutdown cooling suction valves.' Additionally, the inspector periodically reviewed all open jumpers for age, and penodic Plant Operations Review Committee (PORC) evaluations disposition longstanding evaluations. The jumpers reviewed were found to be in accord with administrative requirements.
Tagouts Inspection was performed of equipment tagouts according to applicable sections of AC 2-1042 91, " Prevent Inadvertent Loss of Shutdown Cooling 2.06A. Tagouts reviewed were:
on loss of the normal station service transformer *; 2-1361-91, ' Caution tagging of potential injection sources without nozzle dams *; 2-1097-91, " Isolation of the No. 2 atmospher valve"; 2-1146 91,
- A service water pump isolation"; 2-1044-91, " Low Temperature 2-1098-91, Overpressurization"; 2-1061-91, " Removal and installation of primary manways";
" Overhaul on non-return main steam line check valve (2-MS-l A)*; 2-1240-01 and 2-1239-91
" Electrical insulation tests on non-emergency bus 24A." Aside from specific tagouts reviewed, partial reviews were completed of the tags installed in the plant by compariso with the tagout sheet maintained in the control room. A review of the tagouts verified that the proper equipment was tagged, equipment identified in wic 1 speciEcations was
' ssed on work observations, and appropriately controlled, and equipment isolation was proc consideration of controlled diag ams a-d procedu al guidanct
4 Lee Keecine and Tumovers Control room logs, night order logs, radwaste logs, plant incident report log, and crew tumover sheets were reviewed. Satisfactory conditions were noted. On June 5, NNECO altered the format of the crew tumover sheet. The alterations included the addition of sections on evolutions in progress, long term evolutions, changes in equipment in the last 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, security key accountability, and beeper information. On May 31, the operations supervisor documented expectations on the additional turnover sheet format. The mspector considered the tumover sheet additions to be a generally positive :;tep towards providing clarifications and accountability of plant activities.
NRC inspection verified that shift tumovers were satisfactory, with the shift supervisor controllirg the rumover and additional information presented by the work control supervisor.
Accurate information on plant conditions and evolutions in progress were discussed with all members of the crew.
Control room trouble repms were reviewed for age, NNECO planned action, and operator awareness of the reason for the trouble repon. The rouble repons were generally recent with very few longstanding items.
Attendance at daily planning meetings identified upcoming quality service department audits, h
maintenance and sur,eillance activities in progress, exposure estimates, and actual exposure incurred for the previous day, and discussions of work control and authorizations. Upcoming qt.ality services and audits planned for late 1991 include: AShE Section XI program, Fitness for Duty program. EEQ Maintenance Program Review, Authorized Work Order and Work Control, and long tenn effects of Non-Conformance Repons.
Periodic plant tours were conducted of the auxiliary building, turbine building, containment building, enclosure building, and intake structures. Plant housekeeping was satisfactory, no fire hazards were observed, and good material condition of safety equipment was noted.
3.:
Onsite Followup of Operatintal Events l
3.2.1 Subcritical Reactor Trip During Plant Shutdown Event Descriction 1
I During plant operation at 10% full pc wer on May 25, a primary to secondary leak developed on the No. 2 steam generator. The leakage was detected by radiadon monitors on the main steam line (N-16) and on the steam jet air ejector discharge from the main condenser. The leak rate increased from zero at midnight to about 50 gallons per day (gpd) at 6:00 a.m. Plant operators entered abnormal operating procedures to monitor leakage status and notified the NNECO duty officer and management. The leakage stabihzed between 45 to 50 gpd for the next S hours, with periodic spikes to 61 and 73 ppd. After plant engineerin
5 review of leak rate trends and with leak rate at 55 gpd and trending up, plant management at 1:55 p.m. ordered the plant shutdown to conduct repairs. The resident inspector went to the site to monitor the shutdown. The plant status and licensee actions were reviewed in a telephone conference call with NRR and Region I management at 4:00 p.m.
While insening control rods to shutdown the reactor, an automatic scram on low steam generator pressure (nominal setpoint 600 psia) occurred at 5:32 p.m. The reactor was suberitical at the time of the scram with insertion of regulating group four in progress. Plant operators noted the decreasing Tavg and steam pressure, but actions to remove excess steam loads were unsuccessful to aven the scram. The plant responded as expected following the scram.
The steam geterator leakage remained at about 55 gpd following the scram and during the shutdown. The reactor was placed on shutdown cooling using the "A" LPSI pump at 1:25 p.m. on May 26, and the plant entered Mode 5 (Tavg less than 200F) at 4:40 p.m. on May 26.
NNECO reported the automatic reactor trip at 6:12 p.m. to the NRC Operations Center, pursuant to 10 CFR 50.72 (b)(2)(ii) as any event that results in automatic actuation of the reactor protection system. NNECO initially reponed that the low steam generator pressure uas caused by the plant cooldown attributed to low reactor decay heat following 13 days of operation after the last outage. Subsequent NNECO review of the post-trip data on May 26 concluded that the plant cooldown cecurred because the main turbine was not removed from service before the reacter was shut down. NNECO corrected its repon to the NRC duty officer.
Seccence of Events The following lists the chronology of critical plant parameters or actions during the event:
Time Event 17:01:00 Operators take the main generator off-line by opening off-site breaker 15G-9T-2 17:08:32 Reactor Coolant System Average - Reference Temperature 14w Alarm 17:16:26 Reactor Protection System Pre-Trip Alarm 17:31:24 Steam Generator Low Pressure, Reactor Protection System Channel "A" 17:32:01 Steam Generator low Pressure, Reactor Protection System Channel "B" 17:32:01 Reactor Trip 17:32 Operators Commenced Emergency Operating Procedure (EOP) 2525,
" Standard Post-Trip Actions" 17:40 Operators Completed Actions Within EOP 2525 and initiated actions widin EOP 2526. " Reactor Trip Recovery" 15:15 Cc=ple:ed Ac:icns wiiin EOP 2526
6 The inspector reviewed the licensee's pre-trip, post trip, sequence of event log, post-trip review summary, and the duty of6cer trip repon. NRC reviews focused on plant response and operator actions.
De inspection confirmed an appropriate reactor protection system rm=ne to a low steam generator pressure condition. The ruiew included a consideration of setpoint values as detailed in Technical Specincation Table 2.2-1, the "as-left" functional test data per procedurt SP-2402P, " Spec 200 Safety Parameters Functional Test," and review of the post-trip steam header pressure. The inspector concluded the reactor tripped within design specifications and requirements.
NRC review evaluated plant cooldown values and compared them with the requirements of Technical Specification 3.4.9.1. The cooldown rate is limited to 80 degrees Fahrenheit (F) per hour. The calculated average cooldown rate for a one hour period prior to the reactor trip was 46.8 degrees F/hr.
The inspector reviewed reactor power and shutdown margin prior to and after the trip to determine the effects of the inadvenent plant cooldown from 532 degrees F to 507 F.
Reactor conditions were evaluated to determine whether the criticality requirements of Tednical Specification 3.1.1.5 were met with the reactor below 515 F. At the time the reactor coolant system (RCS) was at 515 degrees F and, prior to the trip, the reactor was suberitical with a 2% delta k/k shutdown margin (keff 0.98). This shutdown margin was attributed to the inserted control element assembly (CEA) reactivity wonh (rod group 5 insened to 45 steps) and the RCS boron concentration. Additionally, just prior to the plant trip, the reactor shutdown margin was 2.6% delta k/k based on a CEA pattern with group 4 fully insened. The shutdown margin was offset somewhat by the contributions from the moderator temperature coefficient of reactivity during the cooldown to 507 degrees F. The positive reactivity added by the cooldown as calculated to be 0.225% delta k/k. At the time of the trip, the shutdown margin was further increased by the insertion of the wonh from the remaining control and shutdown rod groups. The reactor was suberitical at 515 degrees F just prior to the automatic reactor trip. The technical specification requirements were met.
09eratine Crew Performance The assessment of operating the crew performance was based on interviews, a review of procedural actions, and the overall control of plant activities. Crew performance was assessed on inter-crew communication, command-and-control, and procedural adherence.
Overall inter-crew communications were acceptable; however, deficiencies were noted.
Generally good communications were noted in the awareness of plant conditions prior to the trip by the senior reactor operators, the reactor operator to senior operator communications, and the communications between both senior reactor operators on shift. However, the communication between the senior reactor operators prior to the trip was deficient in that the shift supe.n.isor was gene ally unaware of the plant cooldown and the supervisory control
-t 7
operator actions to reduce excess steam loads. Reactor operator to senior operator communications were generally satisfactory, with a noted exception involving the status of the main turbine. Crew awareness of plant conditions and the initial actions to address the ongoing cooldown were acceptable; however, general understanding of the pnmary cause of the cooldown was lacking.
Command-and-control was acceptable with a noted deficiency on the supervisory control operator's decision to leave the control room to perform switchyard breaker alignments in the Unit I control room at a time when reactor protection system pre-trip alarms existed on low steam generator pressure. Additionally, the shift supervisor was distracted fmm his primary operational oversight functions by unrelated communication from utility management and outside organizations.
Procedure adherence by control room operators was assessed. Procedures in-use prior to and after the reactor trip were: OP-2204, *I. cad Changes"; OP-2205, " Plant Shutdown"; OP-2206, " Reactor Shutdown *: OP-2323A, " Turbine";, OP-2324A, " Main Generator"; EOP-2525, " Standard Post-Trip Actions"; EOP-2526, " Post-Trip Recovery"; and AOP-2569,
" Steam Generator Tube 12ak." The assessment of procedural adherence was based on control room log entries, sequence of events logs, and operator interviews. Procedural adherence was generally good.
}
One procedure adherence deficiency was noted in completing the action step 3.17 EOP 2525 which states that if steam generator pressure is not controlled between 880-920 psia, then as a contir gency step, at 800 psi shut the main steam isolation valves (MSIVs). The senior reac:ct operator on-shift made a decision not to shut the MSIVs based on indications that reactor coolant temperatures were rising and steam generator pressure was returning to its normal hot shutdown value. Additionally, NNECO management felt that the operator's actions were reasonable and expected based on the restoration of critical plant parameters to the expected values and on the preservation of a monitored and controlled pathway for the ongomg primary-to-secondary leakage.
Inspector assessment of procedural adherence included consideration of NNECO expectations as documented in ACP-QA-3.02E, " Procedural Compliance,* and OP-2260, " Emergency Operating Procedure (EOP) Users Guide.' ACP-QA-3.02E states full and total compliance is expected for controlled procedures. OP-2260 states that if an EOP action results in an expected plant response and that response is obtained, then the user of the EOP passes - the l
next step or substep. Inspector evaluation of plant conditions at the t.ime EOP-2525 w.
being implemented concluded that the expected response occurred, and thus the intentions of OP-2260 were preserved, and the operators were in control of the plant.
Root Cause and Corrective Actions NNECO determined that the root cause of the event was the initiation of a reacter shutdown without fully secu-ing t. e main turbine a-d t'e :ac' of a specific s ep in the piant shutcorn
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8 prceedure OP-2205 containing criteria for closing the MSIVs. NNECO identif ed that contributing causes for the trip were inter-crew coordination, crew communications, and pressures felt from extemal NNECO and NRC management interest in the status of the plant shutdown.
NNECO corrective actions included: addressal of performance deficiencies within tLe operating crew, additional procedural improvements to the plant shutdown procedure to address specific plant conditions to close the MSIVs, and reinforcement of managemen' expectations for senior licensed individuals to maintain overall plant perspective and oversight.
NNECO reviewed specific crew performance issues for the event for programmatic deficiencies and found none. The conclusion was based on management expectations presented to the crew and ongoing observation of the balance of the crew's performance.
The inspector noted that the crew associated with this particular event successfully performec a plant shutdown in April,1991, with a larger primary-to-second y 5kage value and an extracdon steam line rupture in progress (refer to Inspection Repon 50-336/91-09).
Assessment and Conclusions Inspector assessment of the reactor trip concluded that the plant responded as designed and requirements were preserved. Appropriate reporting criteria were met. The operating crew performance was deficient in imer-crew communications and in selected coordination efforts.
NNECO planned corrective actions were appropriately focused on crew performance deficiencies. Procedural adherence prior to and after the trip was acceptable. NhTCO also identified an area ofimprovement in the plant shutdown procedure to develop a specific criterion to close se MSIVs.
3.3 Outage Activities On May 25, based on an increase in primary-to-secondary leakage in the No. 2 steam generator, NNECO decided to shut the unit down to identify and repair the cause of the leakage. The initial shutdown duration was 18 days to accomplish a limited eddy current inspection program. On May 30, NNECO management decided to extend the shutdown to increase the scope of the steam generator examinations.
The inspection of outage activities included plant shutdown activities, licensee controls during mid-loop operations, observations and assessments of the work control center, and outage maintenance activities.
3.3.1 Plant Shutdown Activities and C1cara Generator (EG) h.
The inspector reviewed plant shutdown and cooldown activities in progress on May 25 and 26
- o independently assess reac:or safe:y and p! ant conditions. The inspector also reviewed
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