IR 05000219/2004302
| ML050700265 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 03/11/2005 |
| From: | Conte R NRC/RGN-I/DRS/OSB |
| To: | Crane C AmerGen Energy Co |
| Shared Package | |
| ML041730211 | List: |
| References | |
| IR-04-302 | |
| Download: ML050700265 (17) | |
Text
rch 11, 2005
SUBJECT:
OYSTER CREEK NUCLEAR GENERATING STATION -
SENIOR REACTOR AND REACTOR OPERATOR INITIAL RETAKE EXAMINATION REPORT NO. 05000219/2004302
Dear Mr. Crane:
This report transmits the results of the Senior Reactor Operator (SRO) and Reactor Operator (RO) initial licensing written retake examinations administered on December 10, 2004. It also documents the results of a meeting conducted at your site on February 9, 2005. The examinations addressed areas important to public health and safety and were developed and administered using the guidelines of the Examination Standards for Power Reactors (NUREG-1021, Revision 9).
Based on the results of these examinations, one (out of three) Senior Reactor Operator upgrade applicant passed his written retake examination. The three applicants included one upgrade SRO, one instant SRO and one RO. On January 28, 2005, final examination results, were given during a telephone call between Mr. John G. Caruso and Mr. Jesse Hackenburg of your staff.
The meeting of February 9, 2005, was conducted in response to our letter of June 24, 2004, transmitting the results of an examination conducted in April of 2004. The retake applicants for the examination noted herein were failures on the April 2004 exam. The purpose of the meeting was twofold: 1) discuss the review of the relatively high number of post examination comments on an NRC developed written exam after respective reviews by NRC staff and your facility (then 12 comments, now 13 as a result of applicant appeals after our letter of June 2004 was issued); 2) your review of the relatively low average scores on the April 2004 examinations.
Additional details are included herein. The meeting was of mutual benefit from which lessons learned were obtained.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). These records include the final examination and are available in ADAMS (Master File - Accession Number ML041730211; RO and SRO Written - Accession Number ML0502270025; Post Exam Comment Submittal - Accession Number ML050330431, ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Mr. Christopher Should you have any questions regarding this examination, please contact me at (610) 337-5183 or by E-mail at RJC@NRC.GOV .
Sincerely,
/RA/
Richard J. Conte, Chief Operational Safety Branch Division of Reactor Safety Docket No. 50-219 License No. DPR-16 Enclosure: Initial Examination Report No. 05000219/2004302 cc w/encl:
Chief Operating Officer, AmerGen Site Vice President, Oyster Creek Nuclear Generating Station, AmerGen Plant Manager, Oyster Creek Generating Station, AmerGen Regulatory Assurance Manager Oyster Creek, AmerGen Senior Vice President - Nuclear Services, AmerGen Vice President - Mid-Atlantic Operations, AmerGen Vice President - Operations Support, AmerGen Vice President - Licensing and Regulatory Affairs, AmerGen Director Licensing, AmerGen Manager Licensing - Oyster Creek, AmerGen Vice President, General Counsel and Secretary, AmerGen T. ONeill, Associate General Counsel, Exelon Generation Company J. Fewell, Assistant General Counsel, Exelon Nuclear Correspondence Control Desk, AmerGen J. Matthews, Esquire, Morgan, Lewis & Bockius LLP Mayor of Lacey Township J. Lipoti, Ph.D., Assistant Director of Radiation Programs, State of New Jersey K. Tosch - Chief, Bureau of Nuclear Engineering, NJ Dept. of Environmental Protection R. Shadis, New England Coalition Staff N. Cohen, Coordinator - Unplug Salem Campaign W. Costanzo, Technical Advisor - Jersey Shore Nuclear Watch E. Zobian, Coordinator - Jersey Shore Anti Nuclear Alliance S. Glenn, Institute of Nuclear Power Operations D. McMillian, Director of Training - Oyster Creek, AmerGen
Mr. Christopher
SUMMARY OF FINDINGS
IR 05000219/2004302; December 10, 2004; Oyster Creek; Initial Operator Licensing Written
Retake Examination.
One of three applicants passed the retake examination (i.e., one SRO upgrade passed).
The written examinations were administered by the facility. There were no inspection findings of significance associated with the examinations.
NRC-Identified and Self-Revealing Findings
None
Licensee-Identified Violations
None ii
REPORT DETAILS
REACTOR SAFETY
Mitigating Systems - Senior Reactor Operator (SRO) and Reactor Operator (RO) Initial License Written Retake Examinations
a. Scope
of Review The licensee developed the written examinations. The NRC together with site training and operations personnel verified or ensured, as applicable, the following:
- The examinations were prepared and developed in accordance with the guidelines of Revision 9 of NUREG-1021, "Operator Licensing Examination Standards for Power Reactors. A review was conducted both in the Region I office. Final resolution of comments and incorporation of test revisions were completed.
- Simulation facility operation was proper.
- A test item analysis was completed on the written examination for feedback into the systems approach to training program.
- Examination security requirements were met.
The written examination was administered by the site training staff on December 10, 2004.
b. Findings
Grading and Results One applicant (an SRO upgrade) passed the initial licensing written retake examination.
The applicant had previously passed all other portions of the initial licensing examination and was granted a waiver for those sections.
The facility had three post-examination comments on the RO portion of the written examination. NRC resolution of these comments are attached. Based on these comment resolutions, the NRC regraded all three of the applicants written examinations. The regrading of the written retake examinations resulted in one SRO upgrade applicant achieving a passing grade, rather than a failing grade, as originally determined by the licensee.
Examination Administration and Performance During the exam administration there were no training deficiencies identified.
4OA6 Meetings, including Exit
Related to the Retake Examination On January 28, 2005, the NRC provided conclusions and examination results to site management representatives via telephone. The license number for the one SRO upgrade applicant that had passed the examination was withheld pending any potential appeals on the written examination.
Meeting of February 9, 2005 The meeting of February 9, 2005, was conducted in response to NRC letter of June 24, 2004, transmitting the results of an examination conducted in April of 2004 for Oyster Creek. Attendees are noted herein. The retake applicants for the examination noted herein were failures on the April 2004 exam. The purpose of the meeting was twofold: 1) discuss the review of the relatively high number of post examination comments on an NRC developed written exam after respective reviews by NRC staff and your facility (then 12 comments, now 13 as a result of applicant appeals after NRC letter of June 2004 was issued); 2) facility review of the relatively low average scores on the April 2004 examinations.
Overall, the meeting was of mutual benefit from which lessons learned were obtained.
The high number of post exam changes/comments reflected a certain number of problematic questions for which the validation review was not completely effective by both NRC staff and the facility. Enhancement actions related to effectiveness in the future are planned by both organizations; the focus is on improving the review of distractor quality and ensuring that the one correct answer is indeed correct. In a multiple choice written test, distractors are the three of four answer choices that are to be incorrect but plausible in order to enhance the question's discrimination value. The final examination with changes for April 2004 was viewed by NRC staff as valid and reliable.
With respect to the low average scores, the facility is reviewing needed improvements in the initial operator licensing training program including applicant screening, use of high cognitive questions, and factoring in additional lessons learned from the review of results for this retake examination. Planned improvements are also being considered for the licensed operator requalification program as applicable, such as in the area of validation reviews and the use of higher cognitive questions.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
- J. Hackenburg, Manager, Operations Training
- G. Young, Supervisor of Operator Training
NRC Personnel
- J. Caruso, Senior Operations Engineer
- S. Dennis, Senior Operations Engineer
Attendees for Meeting of February 9, 2005
NRC Personnel
- W. Lanning, Director, Division of Reactor Safety
- R. Conte, Chief, Operational Safety Branch
- D. Jackson, Senior Project Engineer, Projects Branch No. 2, Division of Reactor
Projects
Licensee Personnel
- B. Swenson, Site Vice President
- D. McMillan, Director of Training
- J. Hackenburg, Manager, Operations Training
- J. Randich, Plant Manager
- R. Detwiler, Director Operations
- J. Kandasamy, Manager Regulatory Assurance.
- V. Cwietniewicz, Exelon Corporate Training
- H. Tritt, Operations Support Manager
State of New Jersey
- R. Penna, Bureau of Nuclear Engineering.
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened/Closed/Discussed
None
NRC RESOLUTION OF LICENSEE COMMENTS
Licensees Post Written Examination Comments Publically Available
ADAMS Accession No. ML050330431
Note: The licensees post exam comments regarding these three questions were
received by the NRC on December 22, 2004. After NRC review, additional information
was requested from the licensee and provided on January 3, 2005 and January 7, 2005.
During the exam there was one question from one of the applicants regarding question
- 39. After further review by the NRC staff and discussions with the licensee, the
licensee submitted a revised comment for RO question #2, dated January 11, 2005, and
received in Region I on January 18, 2005. Finally, the licensee submitted a third and final
revision to the Region I staff that combined and summarized all previous discussions
and submittals for these three questions dated January 21, 2005, and received in
Region I on January 25, 2005.
RO question 02:
The plant has experienced a loss of offsite power, and the following conditions exist:
Buses 1C and 1D are being supplied by their respective EDGs.
RPV pressure is being maintained at 935 psig with Isolation Condensers.
Oyster Creek has been informed that offsite power will be restored no sooner than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
If a plant cooldown is commenced at the MAXIMUM allowable cooldown rate, what will be the
MINIMUM time it takes to clear the shutdown cooling interlocks, assuming a constant cooldown
rate?
A. 1.9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />
B. 2.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />
C. 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br />
D. 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br />
Submitted answer explanation:
Maximum allowable cooldown rate during loss of AC power is 10 deg. F/hr.
Starting temperature @ 935 psig is 538 deg. F
SDC interlocks clear @ 350 deg. F
Required cooldown of 188 deg. F to clear SDC interlocks.
A assumes a Tech Spec allowable cooldown rate of 100 deg. F/hr
B assumes the administrative limit of 90 deg. F/hr.
C is the correct answer.
D is incorrect, but plausible if a math error is committed.
Final Revised answer explanation:
On a loss of offsite power, both non-vital buses (1A/1B) are de-energized and their input supply
breakers open. Additionally, both vital buses (1C/1D) are separated from the non-vital buses,
and both EDGs automatically start. After approximately 10 seconds, both vital buses are
energized by their respective EDG, and USS 1A2, 1A3, 1B2 and 1B3 are energized from the
vital buses. After a 60-second time delay, both CRD pumps (powered from USS 1A2/1B2)
automatically start as part of the diesel loading logic on a loss of offsite power. This provides
high-pressure makeup capability to the RP
- V.
Additionally, when the non-vital buses lose power, the Fire Protection Pond Pumps lose power.
These pumps are designed to keep the fire header pressurized and available. When the pond
pumps trip, fire header pressure drops below 75 psig, causing both fire diesels to start and
provide makeup to the fire protections system to keep it pressurized. This happens
immediately following the loss of the pond pumps.
The fire protection system serves as an alternate makeup source to the Isolation Condenser
shells. The normal source of makeup comes from the Condensate Transfer pumps, powered
from 1B32. The breaker supplying 1B32 must be manually reset and closed following a loss of
power, as this breaker has a shunt trip device to trip the breaker on low voltage. With no
operator actions taken to reset 1B32, there will be no Condensate Transfer pumps available for
Isolation Condenser shell makeup. However, the automatic start of both fire diesels provides
more than adequate makeup capability to the Isolation Condenser shells, and it occurs
automatically.
Since both fire diesels automatically start following the loss of power, there is adequate makeup
capability to the Isolation Condenser shells. Since both CRD pumps automatically start
following the loss of power, this ensures adequate RPV high pressure makeup capability, since
use of the Isolation Condensers does NOT result in a loss of inventory. Therefore, these two
automatic actions satisfy the requirement of a high pressure injection source to the RPV and
adequate makeup to the Isolation Condenser shells, which then allows a maximum cooldown
rate of 90 deg. F/hr., IAW ABN-36, step 3.1.7, page 5 (previously provided). FSAR
sections/pages 15.2.6.2.2 (page 15.2-5), 15.2.7.2 (page 15.2-7), page 6.3-4, 6.3.1.1.2 (page
6.3-8), page 6.3-9 also support this. Therefore, the maximum cooldown rate is 90 deg. F/hr
and the correct answer is
- B.
Maximum allowable cooldown rate during loss of AC power meeting the conditions in ABN-36,
step 3.1.7 is 90 deg. F/hr.
Starting temperature @ 935 psig is 538 deg. F
SDC interlocks clear @ 350 deg. F
Required cooldown of 188 deg. F to clear SDC interlocks.
A is incorrect, as it assumes a Tech Spec allowable cooldown rate of 100 deg. F/hr
B while the administrative limit of 90 deg. F/hr is correct for this condition, a calculational
rounding error was committed (see below), which makes this answer incorrect.
C is incorrect, using 10 deg. F/hr cooldown rate.
D is incorrect, but plausible if a math error is committed using 10 deg. F/hr cooldown rate.
Calculation of time to reach SDC interlocks is 188 deg. F divided by 90 deg. F/hr which equals
2.088 hrs. Even when rounded to the nearest tenth, the calculated minimum time is 2.1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
Since none of the distractors state this particular answer, there is no correct answer for this
question.
Therefore, Oyster Creek recommends deleting this question.
NRC Resolution:
The NRC staff reviewed the documentation provided by the licensee in support of their
proposed change to the original correct answer. Specifically, the information contained in the
FSAR sections and pages noted above, ABN-36, Loss of Offsite Power, alarm response
procedures, and station electrical load diagrams. The examiners noted the following:
FSAR section 15.2.6.2.2. Loss of All AC Power - Event Description - Assumptions, states, in
part, The relief valves and Isolation Condensers would be available for decay heat removal
and A control rod drive (CRD) hydraulic pump, powered from the diesel generators, can supply
110 gpm makeup flow to the reactor. The CRD pump would be a high pressure makeup
system available to the reactor pressure vessel (RPV).
Alarm Response Procedures N-2-a, N-3-a, N-2-b, and N-3-b, for the Fire Protection System
describe the automatic actions which occur upon a loss of the fire pond pumps which would
occur under a loss of offsite power (LOP) condition. As stated in the automatic actions section
of the alarm response, if a LOP were to occur causing the pond pumps to trip, the diesel driven
fire pumps would auto start to maintain fire water header pressure.
ABN-36, step 3.1.3 states, Maintain the cooldown rate less than 10 degrees per hour.
However, ABN-36, step 3.1.7 states, When adequate high pressure makeup is available to the
RPV and Isolation Condenser shells, then MAINTAIN RPV cooldown rate #90 degrees per
hour.
Based upon the information in the FSAR and alarm response, the requirements, as stated in
ABN-36, for a cooldown rate of 90 degrees per hour would be met. A high pressure makeup
system for the RPV (CRD) and for the Isolation Condenser shells (Fire Water via the Diesel
Fire Pumps) would be available given the conditions stated in question stem. However, given a
degree per hour cooldown rate and the required cooldown of 188 degrees to clear the
shutdown cooling interlocks, the correct answer would be 2.1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> (rounded up from 2.088)
which is not a choice available from the possible answers provided.
Conclusion
In conclusion, the NRC staff accepts the licensee comment that there was no correct answer
for question # 02 and it should be deleted.
RO question 35:
During startup, when the reactor is critical, SRM detectors are initially withdrawn when
_____(1)_____ and SRM period will _____(2)_____ as the detectors INITIALLY start moving
A. (1) all SRMs are greater than 1 E5 cps
(2) become longer
B. (1) all SRMs are greater than 1 E5 cps
(2) become shorter
C. (1) three IRMs in each RPS system read 50% on range 1
(2) become longer
D. (1) three IRMs in each RPS system read 50% on range 1
(2) become shorter
Submitted answer explanation:
As SRM detectors are initially withdrawn, the move into a higher flux area of the core causing
period to become shorter. Period will become longer/go negative only after the detectors pass
beyond the high flux area.
A is incorrect, detector withdrawal is dictated by IRM indication and period will initially go
shorter
B is incorrect, detector withdrawal is dictated by IRM indication
C is incorrect, as period will initially become shorter
D is correct
Revised answer explanation:
When this question was developed, past knowledge of the BWR-5 product line was used as a
basis for the question. In BWR-5s, the SRM detector position when fully inserted is 3 feet (36
inches) above the core mid-plane position. This puts the SRM detectors closer to, and in most
cases, within the area of highest flux when taking the core critical. If the SRM detectors are
within the high flux area, pulling the detectors will result in the detectors seeing more flux per
unit time as the detectors are pulled (a Doppler effect), causing period to become shorter.
However, in BWR-2s, the SRM detectors are only 1.5 feet (18 inches) above the core mid-
plane. Since our rod sequence sheets are arranged such that criticality occurs nominally
between notch position 8 and 12, the area of highest flux will be ABOVE the SRM detectors.
As the detectors are being withdrawn, each detector will see a reduction of counts per unit time
(again, a Doppler effect), causing period to become longer (trend toward infinity.)
After a lengthy conversation with the Reactor Engineering Manager at Oyster Creek, we realize
our original thought process was wrong. Our pull sheets are designed to achieve criticality in
the range of Notch position 8 to 12. Since the Oyster Creek SRM detectors are located 18
inches above the core mid-plane when fully inserted, this corresponds to Notch position 18
when fully inserted. Therefore, the highest area of flux will be above the SRM detectors when
we go critical. Pulling the SRM detectors will therefore cause SRM period to become longer as
the detectors are withdrawn, since the detectors are seeing less flux per unit time as they are
being withdrawn away from the high flux area above them.
A review of SRM data from the most recent reactor startup following our refueling outage
supports this fact. When IRMs were above 50% of range 1 per procedure, all 4 SRM detectors
were withdrawn. As soon as the SRM detectors began moving outward, SRM periods
immediately became longer, trending toward infinity. Additionally, a simulator startup was
performed to replicate the question conditions. The reactor went critical with controlling group
rods between notch position 10 and 12. When all 8 IRMs had been ranged up to range 2, all 4
SRM detectors were withdrawn. As soon as detector movement was initiated in the outward
direction, and all 4 detector periods immediately became longer. As SRM detectors are initially
withdrawn, they move further away from a higher flux area of the core, causing period to
become longer.
Therefore, corrected explanations are:
A is incorrect, since detector withdrawal is dictated by IRM indication
B is incorrect, since detector withdrawal is dictated by IRM indication and period will initially go
longer
C is correct
D is incorrect, as period will initially become longer
Oyster Creek recommends changing the correct answer to C.
NRC Resolution:
In certain model BWRs, dependent on core loading, as SRM detectors are initially withdrawn,
they move into a higher flux area of the core causing period to initially become shorter. Period
will become longer/go negative only after the detectors pass beyond the high flux area. Based
upon that information the initial answer was correct. However, given the loading of the Oyster
Creek core, the location of the high flux area during startup, and the location of the SRMs in the
Oyster Creek BWR-2 reactor, the licensee stated that the correct answer was actually choice C,
that reactor period would initially become longer.
The NRC staff reviewed information provided by the licensee which documented graphically
how the SRMs responded during the most recent startup. Additionally, the staff reviewed data
tables documenting SRM response in the simulator startup which very closely modeled actual
plant response. In all documents reviewed by the staff, SRM response initially became longer,
which supports the licensee position that the correct answer should have been C.
Conclusion
In conclusion, the NRC staff accepts the licensee comment that the correct answer to question
- 35 is C.
RO question 39:
Given the following:
The plant is shutdown
RPV pressure is 700 psig
An I&C tech causes drywell pressure transmitter RE04A to fail upscale
RWCU system isolates
RE04A has been returned to service and drywell pressure is 1.2 psig
RWCU pressure is 140 psig
Filter bypass valve V-16-83 is OPEN
Based on the above, the RWCU system SHOULD _____(1)_____ and
the following actions are required, in the stated sequence, to open V-16-1: _____(2)_____
A. (1) have isolated
(2) Depress DW ISOLATION RESET pushbutton on 4F, and reduce RWCU
pressure to approximately 80 psig.
B. (1) NOT have isolated
(2) Reduce RWCU pressure to approximately 80 psig, and depress DW
ISOLATION RESET pushbutton on 4F.
C. (1) have isolated
(2) Depress DW ISOLATION RESET pushbutton on 4F, reset the redundant
high pressure isolation keylock in A/B Battery Room, and reduce RWCU
pressure to approximately 80 psig.
D. (1) NOT have isolated
(2) Reduce RWCU pressure to approximately 80 psig, depress DW
ISOLATION RESET pushbutton on 4F, and reset the redundant high
pressure isolation keylock in A/B Battery Room.
Submitted answer explanation:
In order for the RWCU system to isolate on either high drywell pressure or low-low RPV level, it
takes two (one-out-of-two twice) logic to cause this isolation, as the isolation circuitry is part of
the RPS system and uses the same detectors the RPS circuitry uses for these isolation and
initiation signals. However, a high system pressure causes the system to isolate. There are
two isolation circuits for high pressure: the primary circuit, and the Appendix R redundant
circuit. Both circuits are currently set at 130 psig for the isolation function, and either one will
cause the system to isolate. Therefore:
A is incorrect, as isolation should not have occurred.
B is incorrect, as the redundant high pressure trip must be reset also.
C is incorrect, as isolation should not have occurred.
D is correct
Revised answer explanation:
Besides the containment isolation signals (high drywell pressure or low-low RPV level), high
system pressure also causes the system to isolate. There are two isolation circuits for high
pressure: the primary circuit, and the Appendix R redundant circuit. Both circuits are currently
set at 130 psig for the isolation function, and either one will cause the system to isolate.
Based on the conditions stated in the stem, RWCU system pressure of 140 psig would trip the
system on both high pressure trip signals. Since there is no timeline or indication that the
RWCU pressure rose to 140 psig SUBSEQUENT to the isolation on high drywell pressure, it is
valid that the candidates would choose an answer stating the system SHOULD have isolated,
since a valid isolation signal is present in the question stem. However, neither final part of the
possible answers depicting the system should have isolated contains the correct sequence of
operation needed to recover the system. Therefore, since neither of the distracters (A & C) that
state the system SHOULD have isolated has the subsequent actions in the correct order,
there is no correct answer for this question.
Oyster Creek recommends deleting this question.
NRC Resolution:
The NRC staff reviewed the conditions stated in the question stem and also reviewed the
criteria for a Reactor Water Cleanup Pump trip as stated in ARP D-3-b, Cleanup System. The
ARP stated that the system would isolate with system pressure > 130 psig and, therefore, a
pump trip would occur on low suction pressure. Therefore, it is a valid answer, for the initial
part of the question, that the system SHOULD have isolated, since a valid isolation signal is
present in the question stem. Therefore, the only distractors which answer the first part of the
question correctly are in distractors A and C.
The second portion of the question asks what is the correct sequence to perform followup
actions to open valve V-16-1. The NRC staff reviewed the guidance contained in Procedure
No. 303 Rev.88, Reactor Cleanup Demineralizer System, step 4.3.6, for reopening valve
V-16-1 and found that distractors A and C did not state the correct method or sequence to open
the valve.
Therefore, given that distractors B and D were incorrect from the first part of the question and
distractors A and C were incorrect for the last part of the question, no complete correct answer
was provided for the question.
Conclusion
In conclusion, the NRC staff accepts the licensee comment that there is no correct answer for
question #39 and it should be deleted.
Attachment