IR 05000440/1990002
| ML20012D939 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 03/19/1990 |
| From: | Ring M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20012D938 | List: |
| References | |
| 50-440-90-02, 50-440-90-2, GL-89-04, GL-89-4, NUDOCS 9003290118 | |
| Download: ML20012D939 (23) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No. 50-440/90002(DRP)
F-Docket No. 50-440 License No. NPF-58 Licensee: Cleveland Electric Illuminating Company Post Office Box 5000 Cleveland, OH 44101
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Facility Name: Perry Nuclear Power Plant, Unit 1 -
Inspection At: Perry Site, Perry, Ohio
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Inspection Conducted: January 3, 1990 through February 28, 1990 Inspectors:
P. L. Hiland G. F. O'Dwyer G. West W. Liu B. Drouin
$!/7['Jd M
Approved By:
M. A. Ring, Chief-Reactor Projects Section B Dite '
Inspection Summary Inspection on January 3.1990 through February 28.1990 (Report'
No. 50-440/90002(DRP))
Areas Inspected:
Routine, unannounced safety inspection by resident inspectors of licensee action on previous inspection items; allegation followup; fitness for duty training;; monthly surveillance observation; monthly maintenance observations; ope'ational safety verification; onsite followup of events; l
enforcement confnence meeting; and monthly plant status meeting.
l Results: Of the nine areas inspected, one non-cited violation was identified L
in the area of onsite followup of events (para. 8.b.(3)). That violation concerned the inoperability of the reactor core isolation cooling system under 1:
certain operational conditions. One unresolved item was identified in the area of onsite followup of events concerning inadequate valve stroke
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surveillance testing (para. 8.b.(7)). The inspection of an allegation (para. 3)
I that the licensee had provided misleading information in a Licensee Event Report (LER) found that allegation to be unsubstantiated. Two open items identified in the area of operational safety verification (para. 7.b.(1)) concerned the licensee's review of a USAR accident analysis that was considered deficient at 9003290118 900320
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another BWR facility.
The remaining open item concerned the licensee's evaluation of-staff recommendations following an on-site inspection of root
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'cause_ for the January 7 reactor trip (para. 8.b.(2)).
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For this inspection period, the area of plant operations was considered a strength based on routine observations of plant evolutions and the inspectors review of operator response to events. The area of maintenance and
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surveillance activities was considered adequate; hcwever, weaknesses were
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identified in specific surveillance test activities.
The inspectors considered the licensee's investigation and followup corrective action to
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g events.and unexpected system (offgas) transients to be adequate with the appropriate level of management involvement.
In general, the inspectors a
considered the licensee's implementation of security and radiological control
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programs to be a strength based on routine observations throughout the inspection period, f
r At the conclusion of the report period, licensee management was aware of the identified open items and was taking appropriate actions.
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DETAILS
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1.
Persons Contacted a.
Cleveland Electric 111uminatino Company (CEI)
- + A. Kaplan, Vice. President, Nuclear Group i
+ M. Lyster, General Manager, Perry Plant Operations Department
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(PPOD)
P. Bordley, Reactor Engineer, Fuel Management Lead
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+ D. Cobb, Senior Operations Coordinator
+*V. Concel, Manager, Technical Section (PPTD)
W. Coleman, Manager, Operations Quality Section (NQAD)
- 'M. Gmyrek, Manager, Operations Section (PPOD)
- L. Hartline, Manager, Quality Control Section (NQAD)
- + H. Hegrat, Compliance Engineer (NSD)
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- H. Kelly, Shif t Supervisor (PPOD)
- +*S. Kensicki, Director, Perry Plant Technical Department (PPTD)
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- +*R. Newkirk, Manager, Licensing and Compliance Section (NSD)
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- E. Root, Manager, Operations Support (PPTD)
R. Stracman, Director, Nuclear Engineering Department (NED)
- +*F. Stead, Director (NSD)
- +*D. Takacs, Acting Director (NQAD)
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U. S. Nuclear Regulatory Commission
C. Paperiello, Deputy Regional Administrator, RIII
+ W. Forney, Deputy Director, Division of Reactor Projects. RIII
- +*P. Hiland, Senior Resident Inspector, RIII
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- +*G. O'Dwyer, Resident Inspector, RIII
- + R. Knop, Chief, DRP Branch 3. RIII
- + T.'Colburn, Percy. Project Manager, NRR
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J. Grobe, Director of Enforcement, RIII
- + M. Ring,- Section Chief, Perry, RIII
R. Perfetti, Office of Enforcement, OE
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- + B. Drouin, Reactor Engineer, RIII
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M. Kopp, Inspector DRS, RIII
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C. Weil, Enforcement Specialist, RIII
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+ J. Smith, Senior Resident Inspector, Zion NPS, RIII
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+ W. Liu, Inspector, DRS, RIII
-# Denotes those attending the enforcement conference held on January 18, 1990.
+ Denotes those attending the plant status meeting held on February 9, 1990.
- Denotes those attending the exit meeting held on February 28, 1990.
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2.
Licensee Action on Previous Inspection Findings (92701)
a.
(Closed) Violation (440/89023-02(DRP)):
Failure to Perf xm Required Independent Verification During Performance of Surveillance Instruction. The subject violation resulted in a loss of control
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p example, the annunciator window.that had read "TB/HB VENT GAS
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SAMPLE / STACK FLOW LOW", was changed to read "TB/HB VENT IS0 KINETIC j
SMPL FLOW HI/ LOW".
The licensee also considered but rejected a
" Locked-in Alarm Log" because it would not aid the operators but rather add to their administrative burden and reduce their
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effectiveness. The inspectors concur with this assessment particularly in view of the progress the licensee had made towards reducing the number of locked-in alarms.
Based on the corrective actions as stated above, this item is closed, e
No Violations or deviations were identified.
i 3.
Review of Allegation (99014)
(Closed) _ Allegation (RIII-90-A-0009). Licensee management allegedly included misleading statements in Perry LER 89030 (two untrippable control rods).
Allegation:
On January 17, 1990, the NRC received a telephone call from an anonymous individual who stated that licensee management was aware of control rod 34-47's inoperable status much earlier than the time indicated in LER r
89030 (9:30 p.m. (EST), November 25,1989).
Review:
In order to address the allegation, personnel who were closely involved in scram time testing on November 25, 1989, were interviewed by the inspectors.
In addition, the Reactor Engineer's (RE) and the Shift Technical Assistant's (STA) logs from November 25th were reviewed.
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RE,.the swing shift STA, the day shift unit supervisor (US), the day shif t shif t supervisor (SS), and the operations manager were interviewed on January 22 and 23, 1990.
A note in the RE log at 1:40 p.m., November 25, 1989, indicated that control rod 34-47 was slow on November 25, and it had been slow during Startup Testing (first refueling outage July 1989) which was documented on Condition Report (CR)89-301. A note at 2:37 p.m., in the RE log indicated that rod 34-51 was declared inoperable /untrippable and that there were indications that the test switches functioned as designed.
(Note: According to LER 89030 rod 34-51 was declared inoperable at 2:39 p.m.; however, the discrepancy was not significant).
The inspectors determined through interviews that the RE informed the US on November 25, 1989, about past scram time test problems on rods 34-47 and 34-51 which occurred in July 1989. The US attributed the initial November 25 scram time failures on rod 34-47 to faulty test switches until he was informed of CR 89-301 near the end of day shift. The US then became concerned of control rod 34-47's operability status; however, the US was also turning over his duties to the swing shift US.
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power to an emergency service water pump discharge valve when a test o
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lead was installed improperly.
That loss of control power resulted
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in the necessity to declare the emergency service water pump and all
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of its dependent safety related components inoperable.
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c The licensee responded to the subject violation in letter PY-CEI/NRR-1098L,-dated November 22, 1989, in a timely manner.
As stated in that response, the immediate corrective action was accomplished by restoring the control power supply to the emergency service water pump discharge valve. The licensee's corrective actions to prevent recurrence included counselling of the plant
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technicians who had failed to properly perform the required -
independent verification.
In addition, those same technicians
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prepared _ lesson plans and provided training to other plant
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technicians as corrective action.
The inspectors review of that
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lesson plan indicated that a clear understanding of the violation
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o was identified. As stated in the prepared lesson plan, "the verifier asked the performer if Term.Bd. EE-124 to 126 were correct.
The error was not discovered because the verifier did not read the step himself."
The inspectors concluded that the licensee's corrective actions for the subject violation were appropriate and complete. Of particular i
note was the licensee's corrective action approach which included the active participation of personnel involved in the violation.
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This item is closed.
b.
(Closed) Violation (440/88003-05(DRP)):
Failure to follow procedure by tagging out the Turbine Building / Heater Day (TB/HB) vent radiation monitor instead of the TB/HB vent isokinetic sample pump.
A second plant operator failed to identify the discrepancy during the independent verification. When the radiation monitor was taken uut of service, the control room operators received and cleared the
"TB/HB VENT AIR RAD MON FLOW LOW" annunciator but did not respond correctly because they mistook it for the expected pump out-of-service annunciator ("TB/HB VENT GAS SAMPLE / STACK FLOW LOW").
The subject violation resulted in the TB/HB vent radiation monitor being inoperable for a period of time during which compensatory gaseous effluent measurements were not accomplished as required by Technical Specification 3.3.7.10.
The licensee responded to the subject violation in letter PY-CEI/NRR-0831L, dated March 30, 1988, in a timely manner. As stated in that response, the icmediate corrective action was
accomplished by correcting the ty ging error and sampling in accordance with Technical Specification 3.3.7.10.
The licensee's corrective actions to prevent recurrence included disciplinary actions for the control room operator and plant operator involved.
In addition, design change package (DCP)86-768 revised the wording of the annunciator windows for the isokinetic samplers for each of the four vents at Perry, to more clearly differentiate them from their associated radiation monitor trouble annunciator windows.
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The day shift SS became aware of the existence of CR 89-301 after he
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informed the RE to initiate a condition report on the failure to scram of rod 24-51 on November 25.
The $$ requested a copy of CR 89-301 so that he could review the report. He also misunderstood information communicated by the RE concerning the operation of the test switches
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for control rods 34-47 and 34-51 during scram testing. The SS believed
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the initial failures of control rod 34-47 to involve the test switches.
The RE actually stated that the test switches for 34-51 functioned as designed as indicated by his entry in the RE log at 2:37 p.m., on November 25, 1989. At that time, the SS was also involved in critical plant activities which could have resulted in the shutdown of the reactor (establishing a reliable seal water supply to the circulating water pumps,
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t repairing steam leaks, and completing Technical Specification (TS) action
requirements for one untrippable control rod (34-51)). Therefore, the SS i
believed there was no reason to question rod 34-47 initial test failures or rod 34-47 operability status until he reviewed CR 89-301 at the end of the day shift (approximately 6 p.m.).
The day shift SS passed his concerns including CR 89-301 on to his relief.
The swing shift STA after reviewing CR 89-301 believed rod 34-47 to be inoperable because of its past performance in July 1989 and its initial
test failures on November 25, 1989. The STA informed the day shift SS of
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his concerns at 6:15 p.m., on November 25, 1989, as noted in the STA log.
The night shift SS became concerned with rod 34-47 operability after reviewing CR 89-301 and the results of November 25th testing of 34-47,
and after discussions with the swing shift STA. The night shift SS than notified the Operations Manager of the 34-47 operability concerns at
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approximately 7 p.m.
The operations manager provided guidance to the SS on further analysis and required actions to be taken if 34-47 was l
incperable. After further analysis, rod 34-47 was declared inoperable
at 9:30 p.m., and the SS began complying with applicable technical
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specifications.
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The inspectors concluded that the licensee's difficulty in determining control rod 34-47 operability status involved the following factors:
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A poor testing philosophy which made little or no distinction
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between testing and troubleshooting.
The licensee's actions during
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s:: ram time testing in July 1989 and on November 25, 1989, were consistently inappropriate and inadequate.
Scram testing was allowed to continue on 34-47 until acceptable test results were
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obtained without adequate analysis of the initial failures. A testing philosophy of this nature provided no assurance that a
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sys:em would function es designed when initially called upon.
A similar philosophy was exhibited by the licensee while conducting main steam isolation valve testing in 1987.
(Note:
Escalated enforcement action (EA 89-253) was initiated in Inspection Report 50-440/89028(DRP) to address the violations associated with inadequate scram time test controls, two untrippable rods, and
failure to control nonconforming materials.)
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The plant staff's undue emphasis on CR 89-301 which resulted from
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the licensee's poor test philosophy distracted the operating staff l
from focusing on the critical initial test failures of rods 34-47
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and 34-51 on November 25, 1989. Management action was delayed until
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i CR 89-301 could be reviewed, although past performance history was
actually irrelevant. Appropriate corrective action should have been initiated after the first test failures of rods 34-47 and 34-51 at
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1:37 p.m. and 2:13 p.m., respectively, on November 25, 1989. The plant staff's preoccupation with CR 89-301 delayed the inoperability j
declaration of rod 34-47 until 9:30 p.m, and resulted in an entry i
p into T.S. 3.0.3.
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c.
Poor communications between the operating staff and other plant
staff resulted in the late identification of a problem with rod 34-47 operability. Communications within the plant staff were further degraded by staggered shift turnovers between the
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STAS /USs and the SS on November 25, 1989, d.
Other critical activities being conducted on November 25, 1989, (e.g., seal water to circulating water pumps, steam leaks, TS actions required for one untrippable rod) distracted the operating staff from properly evaluating the initial test failures on 34-47.
l Conclusions:
The plant staff had numerous opportunities to identify problems with I
control rod 34-47 operability beginning with the initial scram test failure at 1:37 p.m., before rod 34-47 was declared inoperable at l
9:30 p.m., on November 25, 1989.
However, there was no indication that licensee management suppressed information and submitted misleading information. Therefore, the allegation was unsubstantiated.
This allegation is closed.
I No violations or deviations were identified by review of this allegation.
j As noted in paragraph 3.a. Inspection Report 50-440/89028 describes
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violations associated with this issue.
4.
Regional Request (92701)
l Fitness-For-Duty Initial Training (2515/104)
During the report period the inspectors observed initial training programs required by 10 CFR 26, " Fitness-For-Duty Program" which became effective January 3, 1990.
The purpose of those observations was to verify that training provided to personnel requiring site access i
addressed specific areas.
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As guidance for performing this inspection, the inspectors utilized NRC Inspection Manual Temporary Instruction 2515/104, dated November 27, 1989.
Training sessions observed included " escort training,"
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" orientation training," and " training for supervisors." The inspectors i
noted the instructor was well versed in the subject matter, appropriate
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training aids were utilized, and areas required by the 10 CFR 26 were addressed.
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. Temporary Instruction (TI 2515/104) is considered closed.
No violations or deviations were identified.
5.
Monthly Surveillance Observation (61726)
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For the below listed surveillance activities the inspectors verified one
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or more of the following:
testing was performed in accordance with
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procedures; test instrumentation was calibrated; limiting conditions for i
operation were met; removal and restoration of the affected components
were properly accomplished; test results conformed with technical
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specifications and procedure requirements and were reviewed by personnel
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other than the individual directing the test; and that any deficiencies
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identified during the testing were properly reviewed and resolved by
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appropriate management personnel.
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i Surveillance Test No.
Activity E22-T1319, Revision 4
" Division 3 Diesel Generator Start
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and Load" N31-T1151, Revision 3
" Main Turbine Valve Exercise Test" Details
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a.
During the performance of Surveillance Instruction (SVI)-E22-T1319, Revision 4, " Division-3 Diesel Generator Start and Load," on
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January 4,1990, licensee personnel were unable to achieve 1300 kilovars as required by step 5.1.2.10.f.
At 2:30 p.m. the Unit Supervisor declared that the Division-3 diesel generator had failed
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the SVI and therefore was inoperable and entered the limiting condition of operation (LCO) for Technical Specification 3.8.1.1.
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Engineering personnel determined that the diesel voltage regulator was set to produce a maximum output of 4500 volts (nominal 4160 volts)
on the diesel bus; however, the grid voltage was unusually high which caused the diesel bus voltage to be high.
This prevented the control room operator from achieving the.3300 kilovars that the SVI
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required.
Since in a design basis accident the diesel bus would not have had to be paralleled against the grid voltage there was no reason to believe that the diesel generator would not have accomplished its safety function and therefore this was not considered a valid test failure by the licensee or the inspectors.
Engineering personnel reset the voltage regulator to a maximum of 4550 volts, recommenced testing, achieved the 1300 kilovars, and
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passed the SVI at 3 a.m. EST, on January 5,1990. The Division-3 diesel was not declared operable and the LCO was not exited until 9:30 p.m. because the Division-3 battery had become inoperable for
other unrelated reasons (see paragraph 8.b.1 below).
No violations or deviations were identified.
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Monthly Maintenance Observation (62703)
Station maintenance activities of safety related systems and components listed below were observed / reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides and industry codes or. standards and in conformance with technical specifications.
The following items were considertd during this review:
the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or callbrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; i--
radiological controls were implemented; and, fire prevention controls were implemented.
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Work requests were reviewed to determine status of outstanding jobs and to assure that priority was assigned to safety related equipment maintenance which may affect system performance.
The following specific maintenance activities were observed / reviewed:
Details a.
Work Order (WO) 89-7198, on January 11, 1990, the charging water riser for control rod 10-19 was replaced, b.
Work Order 88-5653, on February 14, 1990, which accomplished setpoint change request (SCR)-1-90-1024, generic electrical instruction (GEI)-056, " Motor Operated Valve Analysis and Test
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System (MOVATS) Testing," and applicable portions of-surveillance instruction (SVI)-E12-T2002, " Residual Heat Removal B Pump and Valve Operability Test on the residual heat removal "B" heat exchanger outlet valve IE12F0003B.
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Work Order 90-0493, on February 14, 1990, which inspected and
replaced the torque switch on the emergency service water inlet isolation valve to residual heat removal heat exchanger "B" as required by Limitorque 10 CFR 21 Notification (dated 9/29/89)
because Fiber Spacers were used in the Leaf (CAM) Type torque switches.
No violations or deviations were identified.
7.
Operational Safety Verification (71707)
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a.
General The inspectors observed control room operations, reviewed applicable logs, and conducted discussions with control room operators during this inspection period. The inspectors verified the operability of
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selected emergency systems, reviewed tag-out records and verified
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tracking of Limiting Conditions for Operation associated with affected components. Tours of the intermediate, auxiliary, reactor,
and turbine buildings were conducted to observe plant equipment
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conditions including potential fire hazards, fluid leaks, and L
excessive vibrations, and to verify that :naintenance requests had been initiated for certain pieces of equipment in need of
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maintenance.
The inspectors by direct observation and interview-verified that the physical security plan was being implemented in p.
accordance with the station security plan.
The inspectors observed plant housekeeping / cleanliness conditions
and verified implementation of radiation protection controls.
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These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under technical specifications,10 CFR, and l
administrative procedures.
b.
Details (1) On February 1,1990, the NRC resident inspector office at the Limerick Generating Station issued a morning report because that licensee had determined during an engineering study that the emergency operating procedure (EOP) on a reactor scram placed the plant outside the design basis described in their Final Safety Analysis Report (FSAR). After a reactor scram the E0P directed the operator to place the mode switch in the
" shutdown" position to backup the automatic scram.
That position also bypassed ths low pressure main steam line isolation valve (MSIV) closure.
The FSAR stated that an Electro-Hydraulic Control (EHC) regulator failure in-the high direction caused a low reactor pressure followed by high reactor level, and took credit for the low pressure MS1V closure function to limit the transient. With the mode switch in " shutdown," the automatic MSIV closure was prevented and therefore the procedure took the plant outside the design basis as described in the FSAR, section 15.1.3.
On February 6,1990, the inspectors found that Perry Off-Normal Instruction (ONI)-C71-1, Revision 1 " Reactor Scram (Unit 1)",
placed the Perry plant outside the design basis as described in its Updated Safety Analysis Report (USAR), section 15.1.3.
Step 3.1 of the ONI directed the reactor operator, after a scram, to immediately place the reactor mode switch in shutdown. This position also bypassed the low pressure main steam line isolation valve closure. The USAR in section 15.1.3 i
stated that if an EHC pressure regulator failed open the reactor would have scrammed on high reactor vessel water level and it appeared to have taken credit for the low pressure MSIV closure to limit the transient. However, with the mode switch in " shutdown," the automatic MSIV closure was prevented and therefore the procedure took the plant outside the design basis as described in the USAR, section 15.1.3.
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When advised of the concern that'was initially identified at-
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Limerick, the licensee $nitiated Condition Report (CR) 90-023_
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to evaluate the potential generic-implication at the Perry
iw pl a nt'.. Initial discussions with the-licensee indicated that-t procedural controls were already in place to direct plant
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operators to' manually close MSIVs if the main steam'11ne
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pressure fell-below the automatic isolation setpoint. The j
inspectors will review the final disposition of CR 90-023-to
verify that the' licensee addressed the generic safety analysis.
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The subject documented in licensee Condition' Report 90-023, is-a
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considered an Open Item (440/90002-01(DRP)) pending. the inspectors review of the final disposition.
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'(2) On January.7, 1990, while' securing the offgas system followingL
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an automatic: reactor trip (discussed below in paragraph 8.b.(2)),
y-a.high radiation alarm was received in the plant vent pipe
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exhaust. The operators responded to the high radiation-alarm L,
in accordance_with appropriate off normal instructions. The'
cause for the increased _ radioactivity was found_to be a drained
loop-seal in the'offgas system,that. allowed the mechanical u
vacuum pumps;to draw radioactive gases from the offgas system
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charcoal adsorbers back into the main condenser and subsequently-l
' discharge to the plant vent. pipe.
Immediate' operator _ actions
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. seal isolation valve. 'As documented in Condition Report o
-(CR)L90-006, dated January-7, 1990, the calculated offsite
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release rates were below the Technical Specification limits.
The inspectors reviewed the licensee's investigation as to the
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root cause for this event and discussed corrective ~ actions.to prevent recurrence. The f;1ow path that allowed radioactive-
. gases to be drawn from the offgas system charcoal _adsorbers by
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the mechanical vacuum pumps was incorrectly established during
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the plant cooldown evolution-on January 7.
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evolution. required the shutdown =of the offgas-system'in accordance with System. Operating Instruction (SOI)-N64, l
"Offgas/ Condenser Air Removal. System," paragraph 6. 'At the time of performing the system shutdown,-control room operators
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did not immediately close the affected loop seal isolation
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valve when shifting from the steam jet air _ ejectors to the 3.
mechanical vacuum pumps.
This error allowed the' loop seal
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water volume to be drawn into the main _ condenser over a period
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of,about one-half hour.
Once the water volume was drained,~a L>
direct flow-path for gaseous radioactivity'from-the offgas
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system to vent pipe was established.
The licensee attributed the root-cause for the error made-while L.
shifting to the mechanical. vacuum pumps to be an inadequate
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procedure.
The inspectors agreed that the existing procedural format may'have been a contributing factor; however, the inspectors also considered the error was indicative of inadequate system understanding (i.e., training) on the part u
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of personnel involved in the shutdown evolution.
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The, corrective action implemented by the licensee was to revise
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the system operating instruction to clearly delineate the i
requirement to'" expeditiously" close -the affected loop seal e
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isolation valve when shifting to the mechanical vacuum pumps,
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t incorporated new instructions to isolate the offgas system
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~ harcoal adsorwrs prior to shutting down-the steam-jet air
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ejectors, and training on the procedural changes and the root
cause for the drained loop seal wast provided to operations
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department personnel.
The inspectors concluded that the corrective actions taken by I
the licensee were appropriate.
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(3) On January 31,:1990, while operating at 100 percent power, i
the licensee experienced an unexpected loss of a loop seal'
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t in the offgas system. At the time of._ event occurrence, plant
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operators were in the process: of' restoring the " cooler-condenser" loop seal that had been isolated for an instrument calibration on the associated level switch. Although no increased gaseous.
activity-resulted from the drained loop seal, the inspectors discussed the root cause of this event with licensee management
to verify root cause identification and appropriate corrective
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action. The licensee's investigation and corrective action
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were documented in Condition Report (CR)90-019 dated C
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January 31, 1990.
Following. cal.ibration of the cooler-condenser loop seal, maintenance personnel informed control room operators-that
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the affected loop seal was ready to be restored to service.
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Control room operators directed non-licensed plant operators to restore the loop seal to service; however, due to a personnel-
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error (i.e., miscommunication) the as,left condition of the
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recently calibrated loop seal instrument was not made known to'
.i the non-licensed plant operators performing the loop seal
restoration.
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The.non-licensed personnel performing the loop. seal restoration
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in accordance with approved system lineup instructions found
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the local level instrument gauge reading "0" when in-fact that_
instrument had been left isolated following the calibration
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process and actual loop seal water level was probably full
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(i.e., about 14 feet)'. After commencing the fill _ operation-by using.the available 100 psig water supply, the loop seal was-unisolated. Since the loop had been pressurized with the 100 psig water supply, when the drain inlet valve (IN64-F0348) was opened, a water intrusion resulted in several process stream
_'
variables (e.g., pressure, delta pressure, flow, and temperature) to begin oscillating around the normal measured rate. After several hours of troubleshooting, the "A" dryer was isolated from the offgas system whereupon the system variables returned to normal.
Apparently the water had collected in the "A" dryer and isolating that component
,
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stabilized system flows.
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.As documented in Condition Report (CR)90-019, dated
,
-January 31, 1990s the proposed corrective actions to_ prevent.
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recurrence of.this event included:L 1) revising:the system-i operating instruction-to prohibit loop seal isolation for
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maintenance unless previous calculations support the activity;,
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-2) training of all Operations personnel.will be conducted detailing the sequence of events, and available administrative-controls.not used;.3) a. review of alarm response instructions
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was to be performed to assure adequate response to low loop seal leve's and elevated system pressure; and, 4) a new section
_
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was to be added to the system operating' instruction describi,.,
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filling and restoring'an isolated loop.
Based on the above corrective actions and discussions with
' cognizant licensee management personnel, the' inspectors considered the licensee's response to this event to be adequate.
The inspectors note that continued offgas system
,
transients, _while not safety significant by themselves, have been a distraction-to plant operators.
In re;ponse to the offgas system transients that occurred in recent months (Ref.
IR 50-440/89028, dated January 12, 1990), the licensee had established an~"Offgas Task Force" that was evaluating the history of offgas system transients and proposed system improvements. At the end of this report period, that task
' force had. established an agenda with'a number of
. recommendations for improving the overall offgas system
,
I performance. The inspectors, with the assistance of a Region-III specialist, will continue to monitor licensee actions to improve offgas system performance.
Completion of licensee corrective actions was being tracked as Open Item 440/88020-04(DRP).-
One_0 pen Item was identified.
No violations or deviations were identified.
-8.
Onsite Followup of Events at Operating-Power Reactors (93702)
a.
General
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The inspectors performed onsite followup activities for events which occurred during the inspection period.
Followup inspection' included
'
one or more of the following:
reviews of operating logs, procedures, condition reports; direct observation of' licensee actions; and i
~ interviews of licensee personnel.
For each event, the inspectors reviewed one or more of the following:
the sequence of actions; the
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functioning of safety systems required by plant conditio.ns;, licensee actions to verify consistency with plant _ procedures and license conditions; and verification of the nature of the event. Additionally, in some cases, the inspectors verified that licensee investigation
'
had identified root causes of equipment malfunctions and/or personnel errors and were taking or had taken appropriate corrective actions.
,
Details of the events and licensee corrective actions noted during the inspectors' followup are provided in Paragraph b. below.
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--f (1)I Loss of Division-3 Battery On January 5,1990, at about 10:10 a.m. (EST), whi:le operating
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at 100 percent reactor power, the licensee experienced a loss a
of the Division-3 battery when the inservice battery was found to have an electrolyte temperature of-less than the 72 degrees
.
required by technical specifications. The cause for tha ' -
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battery temperature was a chilled water bypass valve fe
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"B" of the ventilation system which failed and was supt:v-L excess cooling to the battery room resulting in the low electrolyte temperature.
Since the affected Division-3 battery-L-
was the only available support system for Division 3, 120 volt DC, the licensee declared the battery, the high pressure core i
spray (HPCS) system, and the Division-3 emergency diesel inoperable. The licensee shifted the battery room ventilation to train "A" which operated correctly and the electrolyte-
. temperature satisfied technical-specifications about-11 hours-later.
The licensee declared the battery, the HPCS system and the Division-3 diesel operable at 9:30 p.m.
The licensee reported this event to the NRC Operations Center via the ENS at about 12:00 noon, on January 5,1990.
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(2) Unusual Event - Reactor Trip Due to Loss of Feedwater
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On January 7, 1990, at about 11:30 a.m., while operating'at 100 percent power, the licensee experienced an automatic reactor-trip due to a loss of feedwater.
Prior to event occurrence, I-the two turbine driven reactor feedwater pumps (TDRFP) were operating with their control systems selected to " master" and controlling the automatic governor.. The motor driven feedwater
pump (MFP) was in a " standby" condition.
In order to perform a preplanned maintenance activity, two
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480-volt electrical distribution panels (F-1-C and-F-1-D) were
.to be cross connected. That electrical lineup would allow the normal supply transformer to the F-1-C electrical-panel to be removed from service for maintenance while maintaining the i
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F-1-C electrical bus energized from the F-1-D electrical bus.
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System Operating Instruction (S0I)-RIO, " Plant Electrical-l System," revision 5, Section 7.13.2, provided the necessary i
instructions to perform the intended electrical switching
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evolution.
However, during the switching evolution, incorrect-d contr'o1 power fuses were removed and when plant operators
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attempted to cross connect the two 480-volt distribution
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panels, Panel F-1-C was deenergized.
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l With the loss of electrical power to the non-safety,
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balance-of plant 480-volt electrical panel F-1-C, several
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480-volt motor control centers and 120-volt electrical power i
supplies became deenergized. The immediate impact on overall plant operations was due to the loss of 120-volt electrical
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power-to the feedwater control system. : With the loss of 120-volt control power, the two operating turbine driven i
feedwater pumps reduced their running ~ speed.-to minimum with a-corresponding rapid drop in reactor water level. About'10
".
seconds after the initial loss of electrical power reactor
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water level had decreased from a~ normal level of about:200
>
inches (measuredfromtopofactivefuel)to-the' automatic
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reactor trip setpoint of 177 inches. (level-3). At that time, all 177 control rods inserted-as designed.
Reactor water level i
continuedtodecreaseandatabout130. inches (level-2),the
high pressure core spray (HPCS) and reactor core isolation
cooling (RCIC) systems received automatic start signals to restore reactor: vessel water; inventory. - The HPCS and RCIC -
systems performed as designed and_ restored reactor vessel water inventory. The minimum recorded reactor water level was about 80 inches;- therefore, _the low pressure emergency core cooling-
.
systems were not automaticall of 'about 17 inches (level-1) y initiated since their setpoint
'
was not reached.
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The inspectors observed licensee actions in the control room.
shortly after the event occurrence. The inspectors noted that
,
p in accordance with the licensee's emergency plan,' the on-duty
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shif t supervisor had declared an " Unusual Event" due to the f-
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automatic reactor trip.and subsequent automatic use of the high
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pressure core spray system to restore reactor water level. The
" Unusual Event" was properly terminated at about 12:30 p.m.
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with the plant stable'in HOT SHUTDOWN and reactor level control maintained by the motor-driven feedwater pump.
The inspectors reviewed the licensee's post scram restart-report to assure the root _cause for this event and any. required corrective actions had been completed prior to the plant li-restart on January 17, 1990. Two unexpected. component / system
operations occurred following the' automatic reactor trip:
1) the reactor core isolation cooling (RCIC) system automatically isolated on-a sensed high differential tem 30 minutes after the reactor trip; and.2) perature aboutan offeas system
'
L transient occurred while shifting to the mechanical vacuum; l
pumps. The unexpected isolation of RCIC is discussed below in
_.
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paragraph (3) and the'offgas transient was discussed above in i
paragraph 7.b.(3).
-
i As stated above, the reactor trip was initiated from a i
switching error in the non-safety electrical distribution system. The licensee's root cause for this switching error, detailedinLicenseeEventReport(LER) 90-001-01, dated February 2,1990, was " personnel error - inattention to
-
detail." Corrective actions taken to prevent recurrence included:
counseling of the personnel involved in performing the switching operation; training of all plant operators on the sequence of events; and the system operating instruction used to perform the switching evolution was revised to reduce the
_
possibility of deenergization.
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R-NRR Staff Review
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- The inspectors considered the licensee's root cause evaluation
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s and the corrective actions taken as stated 'above to adequately;
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address the specific error that initiated;this event. However,-
as: discussed below several recommendations were made to the b
licensee after an on-site followup review was conducted by the
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Human Factors. Assessment Branch of Nuclear Reactor' Regulation-(NRR).
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i The NRR staff's on-site followup review consisted of'a field
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walkdown of the procedures used during the electrical switching
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' operation and interviews conducted with licensee personnel.
In
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L addition to the inattention to detail on thefpart of the-plant'
operator performing the switching operation on January 7,'the
.
staff concluded that four factors contributed to the human
error.. First,'the operator expected to find the control power
,
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fuses for breaker FIC17 in the' center area of. the back panel
' because of the breaker location on the front panel. - Second,
- the' location of the labels for. fuses on the door of the
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back panel was inconsistent with actual fuse -location inside
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the panel.. Third, the procedure in use (S0I-RIO) used the.
ambiguous statement "in rapid succession" close one breaker and
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- open-the other.
Fourth, allowing two. operators to implement:
the procedure'may have hindered rather than helped the activity-and the roles of the two operators' implementing the procedure
.were not defined.
The staff review identified several other issues that could adversely affect operator performance in activities of this I?
type:
1) the system operating instruction (S01-R10) provided no cautions to emphasize the importance of removing the correct.
' fuse; 2) cautions that were contained.in SOI-R10 appeared on
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page I while the affected live bus transfer section was on
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"E page 98; therefore, it appeared unlikely that cautions 97 pages-away would be effectively remembered; and 3) the ~ alphanumeric identifiers in brackets for Unit 2 that were-located in the
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n system operating instructions appeared to be unnecessary and-
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potentially distracting " visual noise."
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Recommendations Based on the on-site followup review, the staff recommended that the licensee consider the following:
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(a) Provide a caution statement immediately prior to
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step 7.13.2.d of 50I-R10 reinforcing the importance h
of removing the correct fuse.
(b) Enhance training to ensure procedural steps are verified l
before proceeding to the next step.
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-(c). Locate labels in more appropriate positions and
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orientation relative to the labelled item.
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'(d):. Revise 50I-R10, step 7.13.2.e to. indicate a meaningful-
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. time (e.g', x seconds) within which the next: action should ?
.be' completed. : Eliminate ambiguous' terms such as " rapidly" 7 $.
or " expeditiously."
L-(e) Remove the information in brackets for Unit 2 for all
' procedures.
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(f) Evaluate whether the procedure should be performed by two; operators; and, if so, specify and train.
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.-(g) " Assess whether demarcation and color coding are needed to more clearly show the relationship among equipment.
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The,above recommendations were provided t'o the licensee at'the
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close of.this report period.
The. licensee's evaluation and.
response to the subject recommendations is considered an Open-
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f Item (440/90002-02(DRP)) pending the. inspectors' review.
(3). Reactor' Core' Isolation Cooling (RCIC) High Differential
_Temperature-On January 7,1990, about 30 minutes after i.he reactor trip
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. discussed above in paragraph (2), the RCIC system automatically--
isolated on a high differential temperature (delta-T) in the
'RCIC area.
Shortly after event occurrence, the inspectors
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monitored the licensee's response to this isolation 'from~ tt e.
main' control room.
Initial actions on the part of plant operators included: verified proper isolation of RCIC; verified an actual steam leak'did not exist as evidenced by
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area temperature monitors; and~ verified room cooler valve
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lineup.
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-The licensee documented this unexp'ected isolation of RCIC
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- on Condition Report (CR)90-007, ' dated January 7,1990. lIn
addition,: Licensee Event Report (LER) 90-002-00, dated February 2,1990, documented the licensee's investigation into the' root cause and corrective actions taken. As-stated in those documents, the root.cause was attributed to a design deficiency'
4, involving-the delta-T isolation instrument setpoint.
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i The inspectors reviewed historic technical information to
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evaluate whether adequate controls had been used to establish
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K the high delta-T isolation trip on RCIC.
Condition Report
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(CR)'87-043, dated January 22, 1987, documented unacceptable
'
surveillance test results due to high delta-T alarms on the
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RCIC system. The documented investigation of-that CR resulted
i in the establishment of a " cold weather" RCIC room cooler flow
.i setpoint of 4.3 gpm.
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i The-high delta-Ts experienced during testing in 1987 and again l
on January 7, 1990, were due to the method of leak detection L
system measurement where the high side temperature sensor E
y :
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monitored ambient-room' temperature!(about a~ constant 100 degree
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F) and;the -low side _ temperature sensor measured the RCIC room.
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cooler outlet. temperature-(variable dependent on: Lake Erie-
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temperature).
- The inspectors review of CR87-043. noted that Work Order--
87-1271, dated February 9, 1987, established the " cold weather" flow rate of 4.3 gpm. That work order. documented the-required flow rate was established-at 5/24 turn open of RCIC room cooler outlet valve 1P42F0572. Of particular. note was the 1/24 turn
,sh,
- delta' between the 1987 measured valve position (5/24)_and the-
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required cold weather valve position'(1/4) translated into the-system operation instruction.
The inspectors noted that the
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1987 condition report (CR 87-043). implemented precise engineering calculations to establish the cold weather throttle
_ position of the RCIC room cooler outlet valve (i.e., with a -
temporary pressure gauge installed cooling water flow was adjusted to the precise value of 5.7" H2O +/- 0.5" H20). The H.
precision of that calculation and_ initial throttle position setting was not capable of being maintained through_ routine operating instructions.
In response to the unexpected isolation that occurred on January 7, the licensee implemented Special Test Instruction (SXI)-0045,'"RCIC Room Leak Detection Monitoring," revision 0,
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that was performed when the plant was returned to operation on-January 18, 1990. The established test acceptance criteria were 1).RCIC-operate for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> without isolation on high RCIC room temperature or differential temperature, 2) RCIC room differential temperatures measured were at least 5 degrees F-away from.the_ trip setpoints.
Since the measured room differential temperature was less than-5 degrees F-from the trip setpoints, the licensee considered the results unacceptable and declared RCIC inoperable. The licensee requested an
. emergency Technical Specification change in letter PY-CEI/NRR-1127L, dated January 26, 1990, to increase the delta-T trip.setpoint-from 37.25 degrees F to 70.9 degrees F.
On January-31, 1990, Amendment No. 26 was. issued to the facility operating licensee increasing the RCIC delta-T trip'setpoint to the' requested 70.9 degree F value (until lake temperatures exceed 55 degrees F).
As detailed in the Perry Updated Safety Analysis Report (USAR)
section 5.4.6, the RCIC system was a' safety system designed to'
provide core cooling following a reactor vessel isolation to HOT STANDBY, reactor vessel isolation with a loss of feedwater,-
or following a plant shutdown with loss of feedwater before reactor depressurization-to a point where the-shutdown coolant system can be-placed in service. At Perry, the RCIC system was not considered an emergency core cooling system nor an engineered safety feature.
However, the RCIC system was a Technical Specification required safety system for continued plant operation beyond a 14 day limiting condition for operation (LCO). As detailed in LER 90-002-00, the RCIC system 18 N,
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was considered:to be in an inoperable condition:since about
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J November 1,.1989.(cold weather t bottle position implemented).-
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During:the time between November 1, -1989, and the January 7,-
.1990 discovery date, the associated Technical Specification:
high pressure core spray (HPCS). system was declared inoperable
for brief periods on three separate occasions.. Technical Specification 3.5.1, Action statement c.2 required placing the=
.
reactor plant in at least HOT SHUTDOWN:within the.next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
with both HPCS and RCIC inoperable.
Failure of the licensee to--
meet that. Action statement is a Violati_on (440/90002-03(DRP));-
however, a Notice of Violation was not issued in accordance-with 10 CFR 2, Appendix C, Section V.G.1 because: =the r
inspectors considered the licensee to have identified the
violation in that following the system isolation on January.7,
,
a thorough: review of the cause was performed as documented in
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CR90-007; the Technical Specification Violation for this
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specific event would normally be classified at a Severity-Level IV or V; the> violation was reported by the licensee.in LER 90-002-00; the immediate corrective-actions-included performance'of a special test with established acceptance criteria, engineering analysis,'and performance of calculations to improve reliability of RCIC by increasing the high delta-T
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trip setpoint; addi.tionally, the licensee was' committed to evaluating long term corrective action by evaluating the
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necessary. trip setpoint'for Lake Erie temperature greater than m-55 degrees F; and the-inspectors determined, based on review of available records, that the subject violation was not a willful-violation or a violation that could have been prevented by-licensee corrective action for a previous. violation.
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(4) Mechanical Vacuum Pumps Discharged Radionuclides
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At about 9:45 p.m. -on January 7.,1990, control room operators secured steam jet air ejector (SJAE) "A" and started the
' mechanical vacuum pumps to maintain a vacuum in the-main
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condenser.
Plant operators noted;a 1arge flowrate through
.i s
the offgas system and found the loop seal drain valve-for SJAE
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"A", (N62-F220A) not closed.
That. lineup allowed outside air
at.40 degrees fahrenheit to be drawn through the offgas charcoal
beds resulting in increased activity in the main condenser.
Mechanical vacuum pump operation resulted in alert and high alert alarms on the radiation monitors for-the offgas building vent pipe (a-release point). Operators entered off normal instruction (0NI)-D17, "High radiation levels within the plant", secured the mechanical vacuum pumps, closed N62-F220A and started an air purge of the offgas system. The licensee informed the State and three local counties about the radiation s
releases in accordance with separate agreements at 8:05 a.m.
on January 8,1990 and notified the NRC via the Emergency Notification System (ENS) in accordance with 10 CFR
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50.72(b)(2)(vi). The inspectors followup review of this
.
event is documented above in paragraph 7.b.(2).
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(5) Fuel pin Clad Damage:
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.On January 31, 1990, while performing a detailed. inspection of
,
a-known fuel cycle 1 leaking fuel. assembly, the licensee-
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identified an'"open clad defect." The failed fuel pin was-i located in fuel bundle LY0-382 at position E-6.
That fuel assembly. had been removed:from the reactor during the. first
- refueling outage when. fuel " sipping" inspections identified itj
'
as a leaking fuel assembly. The observed _ defect was located
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about nine inches from the bottom of active fuel, was about one t
inch'in length, and radiated about 300 degrees at the. widest point.. The licensee initiated Condition Report (CR)90-021,
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dated January 31, 1990, to document the event discovery and
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root cause. The determination of the root cause was to be performed by the fuel manufacturer, General Electric, after review of the inspection results.
The. licensee informed the~
NRC operations center of this event via the ENS at about 6:00 p.m. on January 31, 1990.
(6). On February 11, 1990, at about 10:20 p.m., while the plant was
.
at 100 percent reactor power, an electrical fault occurred at cross tie breaker FIG 10 between non-essential 480 volt electrical buses FIG and F2G which injured a plant operator.
The operator. suffered 1st and 2nd degree burns to his face and
. neck. The. operator received treatment for the burns at a local
~ hospital and was released the same day.
The operator was.
wearing safety glasses, safety gloves, and an overcoat at the time of event occurrence.
In preparation to perform routine maintenance, 480 volt cross-
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tie breaker FIG 10'was tagged open.and the operator started to.
" rack out" the breaker (" rack out" the breaker means to physically move it so it was no longer in contact with'any
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electrical bus stabs). After the operator turned the' racking
.
tool.about two turns, an electrical explosion occurred and the plant operator was injured.
Simultaneous with the explosion, an overcurrent fault tripped open the main supply breaker to bus F2G and deenergized that bus'and its associated' loads ' Bus
,
FIG remained energized and no significant plant operations were affected. The most significant load on~F2G that deenergized
,
was a motor-driven fire pump.
In impairment / fire barrier
"
removal! notice number 90-EW-023 (which was prepared on February 12,1990) the licensee's fire protection engineer and fire protection system engineer documented that the plant's fire. protection was adequately provided by the diesel driven fire pump and a " construction" fire pump. The licensee issued a press release and notified the State of Ohio.
Notification to the NRC operations center via the ENS was made at about 9:30 a.m. on February 12, 1990.
,
Since bus FIG did not deenergize after the explosion, its loads were subsequently shifted to temporary power assuring tie breaker FIG 10 was deenergized. On February 14, 1990, upon
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' disassembly of the tie breaker, the licensee discovered a "go,
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-no go"' gage adhering to the breaker just above the contact
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finger assemblies that connected the breaker to the electrical-
'
stabs of..the.F2G bus Licensee perso.nnel removed the gage and
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placed it on the contact finger assemblies for two of the
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phases and found corresponding indentations on the gage. -The
. licensee believed that the cause of the explosion was:the gage-l left in the breaker on a small ledge above the contact finger assemblies after previous maintenance activities in 1986-When
.
the operator was racking the breaker'out.on. February 11. the?
physical agitation apparently made the gage fall which caused-a
,
phase to~ phase electrical fault-on the F2G bus,-the overcurrent.
-
trip on its supply breaker, and-the electrical explosion. _The.
t licensee inspected all circuit breakers located at the 480 volt m'otor' control centers FIG and F2G,land repaired electrical
equipment'affected by-the explosion.
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(7) Missed IST Surveillance Tests
.
- On February 22, 1990, and again on February 23, 1990, while'
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operating at 100 percent power, the licensee identified missed surveillance testing which resulted in required entries into Technical' Specification 3.0.3.
During a' surveillance instruction review process on' February 22, the licensee identified ten motor-operated-valves that were not stroke-time tested in both the open and closed direction in
.
accordance with Technical Specification 4.0.5 requirements.
' Upon ' discovery, the licensee declared all three low pressure
',
coolant injection systems,.both trains;of containment spray,
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and the reactor core 1sclation cooling-system inoperable. With.
'those systems inoperable, the licensee was: required to comply.
with the associated action statement for Technical:
Specification 3.0.3.
Required action included initiating steps
'
to place the plant in an OPERATIONAL CONDITION within one hour for which the specification did not apply and at least STARTUP within the next six hours. -The licensee determined that the
~
ten motor operated valves could be stroke-time tested; therefore, while making preparations to commence an orderly plant shutdown, stroke-time. testing was-initiated. The inspectors observed performance of stroke-time testing in the
main control room. All ten valves identified on February 22 were successfully stroke-time tested and the provisions of
'
Technical Specification 3.0.3 were exited prior to an actual '
reduction in plant power level. The licensee initiated
- Condition Report (CR)90-034 to document the root cause investigation into this event.
l Followup investigation on February 23 by the licensee identified an additional six motor operated valves in the i
centainment and drywell vacuum breaker system that had not been stroke-time tested.
Again, the licensee was required to comply with the provisions of Technical Specification 3.0.3.
The o
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. licensee successfully. stroke-time tested the six valves and -
r an actual reduction in power was not started. The licensee
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initiated Condition Report (CR).90-036 to document the.
additional missed stroke time tests and to document their investigation into the root cause of the event.
.
The inspectors noted through discussions with the NRR. Project'
.,
Manager-that the licensee had recently responded to Generic
'
Letter 89-04, " Guidance On Developing Acceptable Inservice
'
. Testing Programs." - The above missed surveillance test
-
requirements are considered an Unresolved Item (440/90002-04(DRP))
pending the inspectors review:of the root cause for the events
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and the inspectors review of past licensee submittals regarding
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IST program status.
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One Open Item (8.b.(2)) and one Unresolved Item (8.b.(7)) were identified.
In addition, one non-cited violation was identified (8.b.(3)).
9.
Enforcement Conference (EA No.89-253)
On January 18,11990,.an enforcement conference was held between the
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licensee and NRC management at Region -III offices in Glen Ellyn,
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Illinois.. The subject of.that meeting was apparent violations documented
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in Inspection Report 50-440/89028 concerning surveillance testing and maintenance activities. The purpose of the enforcement conference, as t
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detailed in 10 CFR 2, Appendix C, Paragraph IV, was-(1) to discuss the
. violations, their significance and causes, and the licensee's' corrective t-actions; (2) determine whether there were aggravating or mitigating circumstances; and (3) obtain other information to determine the appropriate enforcement action.
Personnel attending the enforcement conference are designated by (#) in paragraph 1 of this report.
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Licensee management. discussed the proposed violations, corrective actions i
taken, and their evaluation of the safety significance. Attached to the-
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copy'of this report that goes to the Public Document Room ~is the January -18 enforcement conference licensee handout of discussion topics L
and a copy of the NRC slides employed at the conference. At the conclusion of-'the_ conference, NRC management acknowledged the licensee's presentation
and corrective actions.
Enforcement action following the staff's evaluation l-of the licensee's-presentation will be provided under separate correspondence to'the licensee.
L l
10. Plant Status Meetings (30702)
NRC management met with CEI management on February 9, 1990, at the Perry. Power Plant, in order to discuss the current status of Monthly-L~
Performance Indicators; Control Rod Selection for Scram Time Testing;
Zebra Mussel Program; and Offgas System Corrective Actions.
Personnel attending that meeting are designated by (+) in paragraph 1 of this
!
report.
Licensee management discussed surveillance test selection criteria for l
control rod testing.
In addition to the criteria established, the licensee management agreed to review an NRC comment that the selection i
"
y
-
I yj,3,
,
criteria include consideration of actual core location. The licensee
_then pres'nted their current plans to evaluate / test processes to control
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'
e
~
,
" Zebra Mussel" infestation. A discussion on offgas system status was
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provided by-the-licensee's system engineer followed by an. update on the
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offgas transients that occurred on January 7 and 31,.1990.
,
W, NRC management acknowledged the licensee's plans and current plant status.
11. Violations For Which A " Notice of Violation" Will Not Be Issued
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The NRC.uses the Notice 'of Violation as a standard method for formalizing theLexistence of a violation of a legally binding requirement.
However,
'
t because the NRC wants to encourage and support licensee's initiatives for self-identification and correctirn of problems,-the NRC will not
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generally issue a Notice of Violation for'a violation that meets the ter.ts of 10'CFR 2,' Appendix C,Section V.G.
These tests are:
1) the
,
violation was identified by the licensee; 2) the violation would be categorized as Severity Level IV or V; 3) the violation was reported to the NRC,.if required; 4) the violation will be corrected, including measures-to prevent recurrence, within a reasonable time period; and 5)-
)
it was not a violation that could reasonably be expected to have been prevented by-the licensee's corrective action for a previous violation.
A~ Violation. of regulatory requirements identified daring the inspection period for which a Notice of Violation will not be issued was discussed in Paragraph 8 b.(3).
12. Open Inspection Items
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Open inspection items are matters which have been discussed with the
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licensee, which will be reviewed further by-the inspector, and which-involve seme actinn on the part of the NRC or licensee or both.- Open inspection items disclosed during the inspection are discussed in
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Paragraphs 7.b.1 and 8.b.(2).
13. Unresolved Items
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Unresolved items are matters about which more information is required in order to ascertain whether it is an acceptable item, a violation or a deviation. An unresolved item is identified in Paragraph 8.b.(7).
14. Exit Interviews (30703)
The inspectors met with the licensee representatives denoted in Paragraph 1 throughout the inspection period and on February 28, 1990.
The inspectors summarized the scope and results of the inspection and discussed the likely content of the inspection report. The licensee did not indicate that any of the information disclosed during the inspection could be considered proprietary in nature.
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