ML17310A299
| ML17310A299 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 05/12/1993 |
| From: | Morrill P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17310A300 | List: |
| References | |
| 50-528-OL-93-01, 50-528-OL-93-1, NUDOCS 9306020276 | |
| Download: ML17310A299 (30) | |
Text
ENCLOSURE 1
Examination Report No.:
Facility:
Docket Nos.:
50-528/OL-93-01 Palo Verde Nuclear Generating Station 50-528/529/530 Examinations administered at Palo Verde Nuclear Generating Station, Units 1, 2,
and 3
Examiners:
Thomas
- Meadows, Senior Operator Licensing Examiner Todd Sundsmo, Operator Licensing Examiner Kent Faris, Operator Licensing Examiner Tom Vehec, Operator Licensing Examiner Approved:
Philip J or ill, Chief Operatio Section Date Signed Summary:
Examinations on March 8-26 1993 Re ort No. 50-528 OL-93-01 Pro ram Evaluation:
The facility licensee's requalification training program was found satisfactory according to the criteria of NUREG 1021, ES-601, "Administration of NRC Requalification Program Evaluations,"
Revision 7.
The criteria for a satisfactory rating are as follows [evaluation results follow in brackets]:
At least 75X of the licensees (operators) must pass all portions of the examination in which they participate.
The pass rate is determined by dividing the number of operators that pass all portions of the examination in which they participate by the total number of operators taking the dynamic simulator examination.
[Forty-seven operators took dynamic simulator examinations.
Thirty-eight of the operators passed all of their examinations (81X).]
2.
At least two-thirds (66X) of the crews pass the simulator examination.
[Seven of the nine examined crews passed the simulator examinations (78X).]
However, the NRC has observed that operator performance declined since the first requalification program evaluation was conducted at PVNGS in October 1989.
Overall, procedural adherence and discipline improved from that seen in previous evaluations.
But, it was also apparent that the operators generally required considerable time to use the emergency operating procedures (EOPs) to 9306020276 9305i3 PDR ADOCK 05000528 V
diagnose and mitigate simulated transients.
Additional Tests Com leted:
The following tests were also conducted:
a) a requalification retake walkthrough exam for one operator
{the operator passed];
b) continued simulator requalification examinations (continuation examinations) for two SROs who had not previously received complete examinations due to scheduling errors
{Both operators passed];
- and, c) an initial written reexamination for one RO applicant
{The operator passed and was subsequently awarded a license].
Generic Crew Performance Oeficiencies that were Observed:
2.
3.
Secondary plant operations:
Some operators lacked the ability to feed or, steam the steam generators to control RCS,.pressure and temperature during events; such as a steam generator tube rupture, a loss of power, or a loss of coolant accident (LOCA).
Electrical plant awareness:
Some operators lacked the knowledge of vital component or indicator power supplies and how these are affected during emergencies.
Also, they lacked the ability to quickly restore electric power supplies and vital equipment.
Some of the Shift Supervisors did not support their crews.
They did not assist the control room supervisor in emergencies.
Summar of Other Concerns:
2.
3.
A relatively large number of job performance measures (JPHs) were missed (twenty-nine were unsatisfactory) during the walkthrough exams.
Some operators stated that they did not receive training on JPHs; or, received very little training.
Four individuals failed due to two or more unsatisfactory JPMs.
The proposed scenario banks were not adequate for testing.
All proposed test materials presented to the NRC, including simulator scenarios, required significant revision before test administration.
This appeared to indicate a, lack of oversight on quality.
Procedure issues:
- 1) Not consistently using instruments to track RCS temperature changes in all emergency situations (cold leg temperatures or vs. representative core exit thermocouples),
and apparent operator confusion over which instrument to use;
- 2) Lack of guidance for operators to terminate immediate (emergency) boration procedures once begun;
- and, 3) some crews took 40-50 minutes to isolate an inter-system LOCA.
REPORT DETAILS Examiners T. Meadows, Chief Examiner, RV T. Sundsmo, Licensing Examiner, RV K. Faris, Licensing Examiner, PNL T. Vehec, Licensing Examiner, PNL Persons Attendin the Exit Heetin on March 26 1993 NRC:
T. Meadows, Chief Examiner L. Miller, Jr., Chief, Reactor Safety Branch D. Lange, Acting Chief, NRR, Operator Licensing Branch P. Horrill, Chief, Operations Section J. Sloan, Senior Resident Inspector K. Faris, Licensing Examiner, PNL T. Vehec, Licensing Examiner, PNL Note:
L. Hiller was also present during the period of March 8-12, 1993.
P. Horrill was also present during the period of March 16-26, 1993.
Arizona Public Service Com an APS W. Conway, Executive Vice President, Nuclear J. Levine, V. P. Nuclear Production L. Clyde, Unit 3 Operations Manager B. Picchiottino, Simulator Support Supervisor T. Barsuk, Emergency Planning Supervisor E. Shouse, Senior Test Operator N. Henry, Operations Standards Project Manager J.
- Dennis, Operations Standards Manager R. Fountain, guality Audits and Monitoring Supervisor R. Fullner, guality Audits and Monitoring Manager R. Schaller, Unit 1 Assistant Plant Manager P. Coffin, Nuclear Regulatory Affairs Engineer K. Hamlin, Nuclear Safety Director M. Baughman, Operations Training Supervisor R. Nunez, Operations Training Manager F. Riedel, Unit 1 Operations Manager B. Adnet, Unit 3 Plant Manager D. Garnes, Unit 3 Shift Supervisor/Training Liaison R. Stevens, Regulatory and Industry Affairs Director D. Burns, Unit Operations Supervisor/Training Coordinator D. Andrews, Palo Verde Communications Manager
Test Administration and Results:
a.
Re uglification Pro ram Evaluation Pre aration.
and the dministration of an Initial Written Retake Examination and of Two Continuation Examinations:
The NRC scheduled a licensed operator requalification training program evaluation at PVNGS over the three week period of Harch 8-26, 1993, in accordance with NUREG 1021, Revision 7, "Operator Licensing Examiner Standards."
Due to the scope of the evaluation (forty-seven operators grouped into nine crews) and the recent changes involving NUREG 1021, Revision 7 (Rev.
- 7) test administration, the NRC met with Palo Verde Nuclear Generating Station (PVNGS) management and staff on January 5,
1993.
The Chief Examiner reviewed the administrative requirements for the evaluation, focus'ing on the recent changes of NUREG 1021; particularly, the simulator crew evaluation and the associated individual followup examination, the concept of crew critical task and Rev.
7 requirements, and the Rev.
7 requirements for a satisfactory program rating.
The scope and dates of the evaluation. were confirmed.
The Chief Examiner reviewed and approved the proposed crew schedule for the evaluation simulator tests.
It was agreed to conduct an initial written examination retake examination for one reactor operator applicant during the on-site requalification preparation week of February 22-26, 1993.
It was also determined that an additional earlier preparation week would be coordinated (February 8-12, 1993) to review the proposed program evaluation material (including the additional initial written retake examination validation),
and brief nine crews of operators.
It was agreed to conduct a requalification retake examination (walkthrough test-only) for an operator whose license would shortly expire after the Harch 1993 evaluation period.
This individual's walkthrough test was integrated into the program evaluation plan;
- however, based on Rev.
7, the individual would not be counted towards the program evaluation.
Finally, two operators that had incomplete previous (September 1991) requalification examinations, were rescheduled for completion during this evaluation.
These two individuals (continued examinations) were counted towards the program evaluation since they were receiving simulator crew examinations.
After this meeting, the examination team worked to develop adequate test materials until the beginning of the program evaluation on Harch 8, 1993.
The NRC examiners found the facility's written and JPH banks to be marginal.
Pdrtions of all proposed test materials presented to the NRC, including simulator scenarios, required significant revision to clarify acceptable operator performance before test administration.
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During this preparation
- period, the Chief Examiner also administered and graded the initial written retake examination on February 22, 1993.
This individual passed and was subsequently awarded a reactor operator (RO) license.
0 namic Simulator Tests:
The scenarios met the Rev.
7 criteria for complexity.
- However, during examination preparation, the NRC examiners found that the proposed scenarios lacked cl'ear performance indicators for critical tasks.
Host critical tasks were rewritten during the validation preparation week.
The NRC observed one crew during the first week, and another crew during the second week, exhibit strong communications skills and teamwork.
Both of these crews were from PVNGS.Unit 3.
Overall, procedural adherence and discipline was improved from that seen in previous evaluations.
Conversely, the operators generally required considerable time to use the emergency operating procedures (EOPs) to diagnose and mitigate simulated transients.
Crew Performance Deficiencies Observed:
1)
Secondary plant operations:
Some operators lacked the ability to feed or steam the steam generators (SGs) to control RCS pressure and temperature during events; such as a steam generator tube rupture (SGTR),
a loss of power (LOP), or a loss of coolant accident (LOCA).
See for examples of this performance deficiency which was observed in all three examination weeks.
2)
Electrical plant awareness:
Some operators lacked the knowledge of vital component or instrument power supplies and how these are affected during emergencies.
Also, they lacked the ability to quickly restore electric power supplies and vital equipment.=-
See Attachment-1 for examples of this performance deficiency which was also observed in all three examination weeks.
3) 4)
Some of the Shift Supervisors (SS) support to their crews appeared -inadequate.
They did not assist the control room supervisor (CRS) in emergencies by helping with EOP usage.
They focused on emergency plan administrative duties instead of backing up their CRS's (as required by facility administrative procedures) in difficult situations.
Crew communications were generally adequate,
@though some individuals did not exhibit acceptable communications skills to the facility standards.
These individuals were marked by the facility for remediation.
Crews with individuals
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lacking in communications skills generally were the ones exhibiting difficulties outlined in items I) and 2) above.
In summary, seven out of the nine crews examined passed the dynamic simulator examinations.
Six of the forty-seven operators examined in the simulator failed their individual followup examinations.
These six tests were necessary after individual operator performances deficiencies were determined to be linked to associated dynamic simulator test critical tasks.
Two of the seven crews that passed and two operators that passed appeared to have performance deficiencies which were significant enough to require thorough NRC evaluation before a decision to pass them could be made.
These cases exhibited similar performance deficiencies to the crews and operators who failed, (see Attachment-l),
but to a lesser degree.
Walkthrou h Tests:
During test preparation and review, the NRC examiners found that most of the licensee's JPHs were current with existing PVNGS
- systems, but lacked consistency.
It appeared that JPHs varied considerably in their content and scope.
For example, two similar JPHs involving the same task, but different electrical divisions, would have identical'steps evaluated'inconsistently.
One step would be identified as critical, while the duplicate step in the similar JPM was not identified to be critical.
- Also, some steps in other JPHs that were identified to be critical were not necessary for, successful task completion.
This was inconsistent with the criteria for JPH development outlined in the Examiner Standards.
Consequently, the JPHs originally proposed to the NRC for the program evaluation were inadequate.
The NRC exam, team modified thirty-three of the fifty-five proposed control room JPHs to upgrade the test quality.
Some in-plant JPHs were also edited for the same reasons.
Forty of the forty-seven operators examined for the program evaluation were administered full NRC requalification examinations (simulator, walkthrough; and written examinations).
The other seven operators were necessary to complete the various crews, or, fill in for operators that became unavailable for their scheduled tests for valid reasons.
Six of the forty operators administered walkthrough examinations failed (one also failed the simulator examination).
A relatively large number of job performance measures (JPHs) were missed during the walkthrough exams (twenty-nine administered JPMs were rated unsatisfactory by the examiners).
Some dperators stated that they did not receive training on job performance measures (JPHs) or, received very little training.
Four operators failed the walkthrough
- exams, having failed two or more JPHs of the five administered.
The following were'he most frequently missed JPHs (associated by system area).
These are indicators of generic operator training weaknesses:
1)
Emergency Diesel Generator (EDG) operations, 2)
Starting the first reactor coolant pump during reactor startup (with the plant in mode 3),
3)
Chemical and volume control system (CVCS) operations, 4)
Classifying emergency
- events, and 5)
Assuming manual control of the steam generator feed water level control system.
d.
Written Tests:
The proposed written examination test questions required NRC editing to develop adequate written examinations.
Hany questions had more than one correct answer or invalid answers.
Some questions were not set-up correctly, in that they asked for an answer that was not among the choices.
Three written examinations were developed, one for each examination week.
Forty of the forty-seven operators examined for the program evaluation were administered full NRC requalification examinations (simulator, walkthro'ugh, and written examinations).
The other seven operators were necessary to round out the various crews, or, fill in for operators that became unavailable for their scheduled examinations (illness in family or personal illness).
The examination's administrative arrangements were satisfactory.
All of the operators passed their written examinations.
- However, four generic knowledge deficiencies were identified and are listed below:
I
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Test Week/Test Category
("Cat-A," static simulator)
"Cat-B " classroom uestion 0:
Fre uentl Missed Knowled e:
Wk-2/Cat-B/ glO RO test:
Operation of pressurizer (PZR) heaters from-the Remote Shutdown Panel (RSP) was missed by three of nine operators.
Wk-2/Cat-B/ f10 SRO test:
Resetting safety/containment/
auxiliary feed actuation signals (SIAS/CIAS/AFAS) was missed by three of six operators.
Wk-3/Cat-A/ g2 SRO test:
Auxiliary feed pump control during simultaneous, LOCA/LOP events and knowledge of the sequencing of vital auxiliaries under LOP conditions was missed by six of eight operators.
Wk-3/Cat-A/ gl2 -
SRO test:
PZR heater control under SIAS conditions/restoring vital auxiliaries was missed by four of eight operators.
The examiners noted that these knowledge deficiencies involved secondary plant operations, RCS control, or vital equipment restoration under EOP conditions.
Thes8 knowledge deficiencies were consistent with those identified in the other portions of the examinations (simulator and walkthrough).
At the conclusion of each week's written examinations,
-the Chief Examiner conducted a post-examination review with the licensee staff.
It was agreed that the examinations and keys remained valid.
However, during the first week's examinations, the
.licensee discovered that a question had been inadvertently compromised by the facility evaluators.
Therefore, the Chief Examiner deleted this question from the examination.
After the examinations, the deletion was documented on the master examinations and the keys were then finalized.
The deletion had no impact on the overall results of the examinations.
There were no further comments from the facility or changes to the previously validated examinations.
e.
Other Concerns:
On March 26, 1993 the Chief Examiner met with the PVNGS Operations Standards Group and EOP Group personnel to discuss issues of concern that were'observed during the program evaj uation.
These issues involved operator difficulties in the use of particular
- abnormal, emergency operating, and emergency planning procedures observed during this program evaluation.
The licensee responded
to these issues via a conference call with the Chief Examiner and the Operations Section Chief on April 22,
- 1993, as requested at the exit meeting on March 26, 1993.
The'RC found the licensee's responses timely and adequate.
The issues and subsequent PVNGS response/action taken were as follows:
The EOP flow chart for the secondary operator (SO) directs that the cold leg temperature instrumentation (Tc) be used rather than representative core exit thermocouple (REP-CET) to track RCS temperature changes.
The examiners thought that Tc may not be the best qualified instrument to track RCS temperature changes in all emergency situations, such as natural circulation (RCPs tripped).
Some operators also had this opinion and subsequently exhibited confusion over which instrument to use (Tc vs.
REP-CET).
The examiners asked the facility to clarify which instrument was appropriate for use.
The facility representatives said that they believed Tc was the best instrument for the SO to use for the following reasons:
a) In a natural circulation condition Tc has a
eight second loop response time.
REP-CET response times are about five seconds no appreciable difference for trending primary Tc (primary Tc is the controlling temperature at PVNGS);
b) Tc instruments track the lowest RCS loop temperatures coming out of the
- SGs, which is likely the most important parameter to trend for subcooling concerns;
- and, c) Tc instrumentation is the closest and easiest to monitor for the SO.
However, the licensee agreed that there was confusion over which temperature instrument to use because their Emergency Procedure Technical Guidelines (EPTGs) did not specify Tc or REP-CET.
Therefore, the facility committed to rewrite their EPTGs by June 1993 to require the use of Tc.
This would allow a technical basis for the training department to eliminate operator confusion in this area.
The examiners thought this explanation was adequate and closed the issue.
2)
Neither the licensee's Technical Specifications (TS) 3. 1. 1. 1 or 3. 1. 1.2),
abnormal procedure 4xAO-lZZOl (Emergency Boration), or EOPs (41EP-lE001 - Emergency Procedures) specify when to terminate boration operations even in a scenario with the pressurizer (PZR) going solid. 'All available guidance (including guidance from the CE owners group) require boration to continue until the specified boration worth of shutdown mar<fin (SDM) is reached in the RCS determined by chemical analysis.
The licensee determined that:
a) This was not possible for. the operators to accomplish within the time requirements uf the EOPs (the primary safeties would lift when the PZR went solid, and SDH goals would still not be met) and b) It may not be possible to achieve the required SDH at PVNGS under EOP conditions
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3) since they do'not have a concentrated source of borated water (>20,000 ppm).
PVNGS sources are 4000 ppm boron, which would require continuous boration under current CE guidance.
The licensee said that they intend to deviate from this guidance to allow operators to secure charging when reactor power is less than 10 -E4 and PZR level is above 70X high range.
The operators would continue to control the RCS around these valves for these two parameters until the event is over.
The licensee stated that their engineering analysis and necessary procedural changes would be completed as soon as possible, and that they would keep the NRC informed of the progress to resolve this issue.
EOP 41EP-1R003, "Steam Generator Tube Rupture.(SGTR),"
directs operators to use five condensate polishers to clean up a steam generator tube rupture when three or fewer might suffice.
After reviewing this issue with their chemistry and radiation departments, the licensee determined that only two polishers would be necessary.
They said that the SGTR EOP will be revised by June 1993 to reflect the new policy.
This chan'ge reduces the number of condensate polishers which would be contaminated by an SGTR.
The NRC examiners acknowledged this and considered the issue closed.
The examiners observed two crews taking 40-50 minutes to isolate an inter-system LOCA (RCS to NCW via RCP seal heat exchanger).
The applicable abnormal procedure 41A0-1ZZ29, "RCP Motor Emergency,"
was found to be flawed in that it gave operators the impression that upon determining any RCP parameter (seal
- pressure, seal temperature, oil temperature, etc...)
being exceeded to exit the procedure and enter the functional recovery procedures (FRPs) to mitigate the event.
The next few pages of 41AO-lZZ29 further direct the operators to trip all RCPs and isolate NCW to the containment - effectively stopping the leak.
However, if the operators go to the FRPs they would not get direction to isolate NCW and stop the leak until much later (working through the FRPs).
The licensee agreed that 4xAO-1ZZ29 was flawed and that it had already been revised to keep the-operators working towards isolating the leak directly (staying in the procedure) while entering the
- FRPs, as appropriate.
The NRC found this appropriate and closed this issue.
Pro ram Evaluation Results:
The facility licensee's requalification training prdgram was found to be satisfactory according to NUREG 1021, ES-601, "Administration of NRC Requalification Program Evaluations,"
Rev.
7.
Forty-seven operators took dynamic simulator examinations.
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Thirty-eight of the operators passed all of their examinations which is an 81M pass rate.
Seven of the nine examined crews passed the simulator examinations.
A requalification retake walkthrough exam for one operator was conducted.
The ope} ator passed.
Continued simulator requalification examinations (continuation examinations) for two SROs who had not previously received complete examinations due to scheduling errors were also conducted.
Both of these operators passed.
The two operators receiving continuation examinations were counted towards the program evaluation since they participated in simulator crew evaluations.
The examiners observed a downward trend in operator, performance since the previous requalification program evaluation was conducted. at PVNGS in October 1989.
During that evaluation thirty-five operators were examine'd in seven crew groups'.
All seven crews passed and one operator failed.
In a subsequent evaluation in September 1991, thirty operators were examined in six crew groups.
During this evaluation one of the six crews failed and four operators failed.
An exit meeting was held by the NRC with representatives of the licensee's staff on March 26, 1993 to discuss the NRC observations and program evaluation.
The NRC personnel present outlined the major observations previously described in this report.
The facility representatives stated that individuals who had tentatively been determined to fail by the NRC would not be placed on shift prior to the NRC program evaluation completion.
The NRC stated that overall program evaluation result was still being deliberated and that the results would be finalized within the following week.
On April 1,
- 1993, NRC management informed APS management that their program had been found satisfactory.
- However, NRC management expressed particular concern about the negative trend in operator performance and the unexpected poor performance on JPHs.
Facility licensee management acknowledged this concern.
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ATTACHMENT-1 (50-528/OL-93-01)
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EXAMPLES OF OPERATOR PERFORMANCE DEFICIENCIES OBSERVED DURING THE DYNAMIC SIMULATOR EXAMINATIONS BY EXAMINATION WEEK Secondar lant o erations:
Some ope} ators lacked the ability to feed or steam the steam generators (SGs) to control RCS pressure and temperature during events; such as a steam generator tube rupture (SGTR),
a loss of power (LOP), or a loss of coolant accident (LOCA):
Week I:
In one scenario, during an excess steam demand event (ESD),
a crew lost control of the intact SG level (level reaching 9I%%u wide range, WR).
The main steam isolation valves (MSIVs) were prevented from isolating on high level.
Only the automatic isolation at high containment pressure (3 psi),
due to the
- ESD, may have prevented the main steam lines (MSL) from flooding.
Also, the crew used the "normal containment" pressure and temperature curves while the containment was actually in "harsh" conditions.
This apparent lacking in awareness of plant conditions impacted the mitigation strategy directed by the emergency operating procedures (EOPs),
causing further reactor coolant system (RCS) degradation in RCS temperature and pressure control.
Week 2:
Crew Failure:
This crew failed due to significant competency deficiencies in understanding of plant/systems response
(¹2) and crew operations
(¹5).
Crew members were not involved in important decision making, and the control'oom supervisor (CRS) gave directives that appeared to inhibit safe performance.
In one scenario (NUV25), the crew failed to take timely action to isolate an intersystem LOCA (RCS to nuclear cooling water).
This task took approximately 40 minutes.
In another scenario (NUV28), the crew lost subcooling for approximately nine minutes.
They also challenged RCS pressure limits by not
, initiating auxiliary spray (aux-spray) before a high pressure alarm was received.
l At the end of scenario NUV28, while in the functional recovery procedures, the crew did not recognize RCS pressure trending up.
They did not sufficiently increase heat removal or use auxiliary pressurizer (PZR) spray to mitigate the
- trend, even when PZR pre-trip annunciators sounded (approximately 2280 psi).
Pressure eventually reached 2356 psi, before aux-spray was initiated.
In NUV28 the crew, after a main steam line break on ¹2 steam generator (SG),
the crew aligned the steam driven auxiliary feed pump (AFA) to faulted SG.
¹2 SG blew down to zero psi.
This was contrary to the emergency procedures, which require isolating a faulted SG.
Later in the scenario the SO attempted to steam the faulted SG (at 0 psi) with an atmospheric dump vol/e (ADV).
During NUV25, after receiving high seal temperature alarms on ¹IB reactor coolant pump (RCP), the crew failed to trip and isolate NCW to all RCPs
immediately upon identifying high RCP seal temperatures indications.
They also failed to take action when it was apparent that the nuclear cooling water system (NCW) surge tank,was receiving RCS water (high level alarms and report cues from equipment operators at the scene).
An immediate isolation of NCW was required by the applicable abnormal procedure, "RCP Motor Emergency."
Approximately 40 minutes later, when the CRS diagnosed LOCA using the
The crew failed to take timely action to isolate NCW to the containment to stop the ongoing inter-system LOCA.
This would have resulted in plant deterioration by degrading the RCP seals and releasing radioactive RCS water to the environment via the NCW surge tank overflow.
Also, at the end of this scenario, the PO failed to implement auxiliary PZR spray at 2150 psi as required by procedure.
PZR pressure increased to 2350 psi before the crew started aux spray.
After the SIAS/CIAS, the SO failed to override the low SG temperature permissive and manually control the steam bypass control system (SBCS) to regain control of RCS heat removal.
The SO tried to open a
SBCS valve before.manually overriding the low Tcold temperature permissive auto-inhibit.
The SO thought the system was faulted and then went to the ADVs for temperature control.
RCS heat removal control was delayed.
In scenario NUV25, the CRS directed tripping only 2 RCPs.
The applicable abnormal procedure and the EOPs required tripping all RCPs for the high seal temperature condition.
The CRS also failed to ensure that seal bleed off was isolated by the crew, as required by the procedures.
The CRS also directed the SO to stop steaming the steam generators with the ADVs when heat removal was required (PZR pressure was 2200 psi and increasing).
In scenario NUV28, the CRS directed the SO to steam a faulted SG at 0 psi pressure.
Week 3:
Crew Failure:
H This crew failed due to significant competency deficiencies in understanding plant/systems response
(¹2) and adherence/use of procedures
(¹3).
In scenario NUV-12, the crew lost RCS subcooling and dried out the pressurizer.
Pressurizer level went off-scale low. It was a critical task to restore high pressure safety injection (HPSI) flow before PZR level went off scale low.
In scenario NUV25, the crew delayed action to isolate an inter-system LOCA (RCS to nuclear cooling water) for approximately 45 minutes.
In scenario
- NUV28, the 'crew lost subcooling for approximately nine minutes when it was avoidable.
The crew also challenged RCS pressure limits by not initiating auxiliary spray (aux spray) before PZR pressure reached approximately 2450 psi (approximately 150 psi above the alarm point).
In scenario NUV25, the crew made serious omissions in interpreting valid symptoms of an RCS to NCW inter-system LOCA:
I) The RCS was experiencing an inventory loss with containment sump levels indicating normal>(the crew thought the normal sump indication was an invalid indication due to a power failure - the instrumentation was not failed); 2) High level alarms and reports of overflow conditions on the NCW surge tank;
- and,
- 3) High RCP seal
temperatures and erratic flows.
The crew continued to search for other LOCA
- sources, while the inter-system LOCA continued for approximately 45 minutes after event initiation.
An immediate isolation of NCW was required by the applicable abnormal procedure, "RCP Motor Emergency."
Approximately 45 minutes later, when the CRS diagnosed LOCA using the
The delay impeded plant recovery.
In NUV28, after ¹2 steam generator (SG) ruptured, the crew continued to feed the faulted SG.
¹2 SG blew down to 0 psi pressure.
This was contrary to the
The crew later under-steamed the intact ¹1SG with ADVs, reducing RCS heat removal.
This subsequently necessitated the use of pressurizer auxiliary spray three times in order to prevent lifting primary safeties.
The crew appeared to act without integrated knowledge of primary plant to secondary plant linkage to control RCS heat removal.
In NUV12, after the SGTR with the main steam isolation valves (MSIVs)
- isolated, the CRS directed the secondary operator to steam and feed both SGs with ADVs and auxiliary feed.
¹1 SG was ruptured and should have been isolated by procedure.
The crew also delayed the restoration of the electric plant vital auxiliaries by failing to restore HPSI for RCS inventory control in time to prevent PZR dryout.
This delay by the crew was a failure to follow procedures, which caused unnecessary plant degradation.
The crew eventually lost control of RCS inventory, (a critical task).
In NUV12, after the SIAS/CIAS, the crew failed to recognize
¹2 SG as ruptured (increasing level and pressure) and continued to unnecessarily release radioactive contamination by steaming
¹2 SG with an ADV.
The CRS directed the SO to steam the ruptured SG.
The steam generator tube rupture EOP was never
- entered, and the ruptured SG was never isolated.
In NUV28, the crew was distracted over HPSI throttle criteria concerns rather than controlling RCS pressure with secondary heat removal.
The CRS directed the SO to steam the faulted SG at 0 psi pressure.
The crew could have limited the RCS pressure transient induced by the lack of heat removal by the secondary plant.
PZR pressure exceeded the 2150 psi limit.up to 2450'psi towards the end of the scenario.
In NUV28, the CRS directed the SO to steam a faulted SG at 0 psi pressure.
In NUV12, the CRS directed the SO to steam a ruptured SG.
'lectrical lant awareness:
Some operators lacked. the knowledge of vital component or instrumentation power supplies and how these are affected during emergencies.
Also, they lacked the ability to quickly restore electric power supplies and vital equipment:
Week 1:
A crew was slow to implement the success path for the restoration of auxiliary feed (vital auxiliaries) while in the Functional Recovery Procedures (FRPs) in a los's of all feed (LOF) event.
The plant degraded in the LOF condition for 10 minutes with both steam generators dropping to OX narrow range (NR) level.
Also in week 1, during a loss of off-site power (LOP) event, a crew failed to realize the unavailability of condensate pumps.
Week 2:
Crew Failure:
In one scenario (NUV-25), after a SIAS/CIAS, a secondary operator tripped the running main feed pump (HFP) while the CRS looked on without intervention.
This action was unnecessary.
The crew appeared to mistake the normal feed system response to reduce feed upon a reactor trip condition.
They apparently thought the feed reduction was due to a problem with the HFP.
Upon recovery, the crew attempted to start the non-vital auxiliary feed pump (AFN) that was not available.
It was load shed on the SIAS/CIAS trip signal.
Subsequently, the crew lost subcooling for approximately 10 minutes.
These serious mistakes delayed feed restoration.
In another scenario, the crew failed to monitor the Safety Equipment Actuation System (SEAS) panels and determine that the containment spray pumps were not available whi.le in a large LOCA eve'nt.
Week 3:
During one scenario, involving a total loss of feed event, both the CRS and SS were responsible for a crew tripping the Division-B Class 1-E 4160 VAC safety bus (PB-S04) from its normal preferred offsite source.
This was done while the crew was in the functional recovery emergency procedures (FRPs) to address the LOF.
The SS and CRS made a significant error in transitioning from the strategy in the FRPs with no procedural guidance to perform this action.
The SS/CRS rationalized that B-emergency diesel (EDG-B) could be used to pick up the dead bus PB-S04, which was stripped automatically by their direction.
This action allowed resetting a faulted 86-lockout on the electric class auxiliary feed pumps (AFB) powered from PB-S04.
The scenario had the AFB pump faulted (malfunction),
such that it would not start even when reenergizing PB-S04-with EDG-B.
The rest of the crew continued to use correct mitigating strategies offered in the FRPs to restore feed to at least one steam generator using condensate pumps.
Although delayed, the crew also pursued regaining the available steam driven auxiliary feed pump (AFA).
They unnecessarily degraded the plant by challenging EDG-B to auto-load PB-S04.
This action tripped all running charging pumps and challenged the availability of
Division-B loads by forcing them to be properly sequenced back on PB-S04.
Loss of the charging pumps could have removed the crew's ability to use auxiliary spray to control RCS pressure.
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ENCLOSURE 2 SIMULATIONFACILITYREPORT 50-528/OL-93-01
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Enclosure 2
SIMULATION FACILITY REPORT Facility Licensee:
Palo Verde Nuclear Generating Station,,Units 1, 2, 8
3 Facility Docket No:
50-528/529/530 Operating Tests Administered on:
March 8-26, 1993 This form is to be used only to report observations.
These observations do not constitute audit or inspection findings and are not, without further verification and review, indicative of non-compliance with 10 CFR 55.45(b).
These observations do not affect NRC certification or approval of the simulation facility other than to provide information which may be used in future evaluations.
No licensee action is required in response to these observations.
During the conduct of the simulator portion of the operating tests, the following items were observed (if none, so state):
This simulator has performed well and presented no significant problems during this examination.
However, the programs and malfunctions are difficult to load and run.
Consequently, two to three individuals are required to operate the simulator to ensure that malfunctions and cues are properly inserted.
(The licensee has committed to build two state-of-the-art simulators with upgraded software and core modeling abilities.
The licensee said that these should be ready for training by September 1994.)
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