ML20151P091
| ML20151P091 | |
| Person / Time | |
|---|---|
| Issue date: | 05/07/1998 |
| From: | Racquel Powell NRC OFFICE OF ADMINISTRATION (ADM) |
| To: | Omealia M AFFILIATION NOT ASSIGNED |
| References | |
| FOIA-97-252 NUDOCS 9805130014 | |
| Download: ML20151P091 (2) | |
Text
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NRc Fona6464 Parti U.S. NUCLEAR REGULATORY COMMISSION RESPoMsE NUMBER hD N
FOIA/PA 97 252
[ **
6th RESPONSE TO FREEDOM OF I
INFORMATION ACT (FOIA) / PRIVACY
RESPONSE
k*e,<*
ACT (PA) REQUEST TYPE b
b neoussTER DATE
' Michael O'Mealla b 971l98 PART l. -INFORMATION RELEASED (See checked boxes)
No additional agency records subject to the request have been located.
' Requested records are available through another public distribution program. See Comments section.
N5 O
Agency records subject to the request that are identified in the listed appendices are already available for public inspection and copying at the NRC Public Document Room.
O ANoscEs Agency records subject to the request that are identified in the listed appendices are being made available for N1 F
public inspection and copying at the NRC Public Document Room.
Enclosed is information on how you may obtain access to and the charges for copying records located at the NRC Public Document Room. 2120 L Street, NW, Washington, DC.
d Agency records subject to the request are enclosed.
O e referred to that agency (see comments section) for a disclosure determination and direct response to
], We are continuing to process your request.
Q This completes NRC's action on your request.
PART 1.A - FEES
] You will be billed by NRC for the amount listed.
Q None. Miqlmum fee threshold not met.
4Mouwr -
- I~
] You will receive a refund for the amount listed.
] Fees waived.
g PART l.B -INFORMATION NOT LOCATED OR WITHHELD FROM DISCLOSURE
] ' o agency records subject to the request have been located.
N
{*.
Certain information in the requested records is being withheld from disclosure pursuant to the exemptions described in and for the reasons stated in Part II.
n This determination may be appealed within 30 days by writing to the FOIA/PA Officer, U.S. Nuclear Regulatory Commission, U
Washington, DC 20555-0001. Clearly state on the envelope and in the letter that it is a "FOIA/PA Appeal."
PART l.C COMMENTS (Use attached Comments continuation page if required)
The records identified on enclosed Appendix F are additional records found after your FOIA request was completed. Copies
- f these records are enclosed.
O I fRd-r%
70 RE a FREE RNACY ACT OFFICER w
Russei A. Powel 9805130014 980507
l O'MEALI97-252 PDR ye 3 m
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Re: FOlA-97-252 APPENDIX F RECORDS BEING RELEASED IN THEIR ENTIRETY (if copyrighted identify with *)
i M
DAIE DESCRIPTION #PAGE COUNT) 1 1.
09/16/94 Letter to D. Gipson from M. Phillips re: Inspection Report 50 341/94011(DRP) with attached Fermi 2 Restart Action Plan (30 pages) 2.
11/08/94 Letter to D. Gipson from E. Greenman re: Inspection Report 50-341/94013(DRP) with attached Fermi 2 Restart Action Plan (Revision 1)(26 pages) 3.
08/05!37 Memorandum to A. Beach from J. Caldwell re: Clinton Power Station Restart (Partial Approval) with attached Modified Manual Chapter (MC) 0350, Restart Action Plan for Clinton Power Station l
(CPS) (40 pages) l f
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,d l
i July 2,1997 F0h*A REQUEST Mr. Carlton C. Kammerer, Dinctor Division of Freedom ofInformation hNo:
.8M -y-and Publication Services Des 8tedd:
, G D Office of Mmlateration 20E:
Fo@
y U.S. Nuclear Regulatory Commission gg-Washington, D.C. 20555 Re: Freedom ofInfonnation Act Rmue_tt
~
Dear Mr. Kammerer:
Pursuant to the Freedom of Information Act (5 U.S.C. I 552) and the U.S.
Nuclear Regulatory Commission's (NRC) regulations (10 C.F.R. Part 9. Subpart A), I request a list of all plant outages in which NRC Manual Chapter 0350, " Staff Guidelines for Restart Approval," has been used. Additionally, please provide a copy of NRC's restart plan, matrix, or other specifically prepared guidance for each such outage.
I would appreciate your 3rompt response within ten (10) working days of the receipt of this' request, as provic ed by 10 C.F.R. P d
NRC's policies. If you require additional information, please contact me at ince y e
Michael. O'Mealia e.
-99erta yw.f /f, f
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UNITED STATES jfI 3*g NUCLEAR REGULATORY COMMISSION fh a
REGION m e
Bol WAABENVILLE ROAO k
8 LISLE,ILUNCIS60532 O$1 e....
septa ber 16, 1994 The Detroit Edison Company ATIN:
D. R. Gipson Senior Vice President Nuclear Generation
[\\
6400 North Dixie Highway
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Newport, MI 48166
Dear Mr. Gipson:
This refers to the routine safety inspection conducted by Messrs. T. Vegel, S. Ray and X. Riemer of this office from July 25, 1994, through September 9, 1994. The inspection included a review of activities at your Fermi 2 facility. At the conclusion of the inspection, the findings were discussed with those members of your staff identified in the enclosed report.
Areas examined during the inspection, are identified in the report. Within these areas, the inspection consisted of a selective examination of procedures i
and representative records, observations, and interviews with personnel.
During this inspection, certain of your activities appeared to be in violation of NRC requirements, as specified in the enclosed Notice of Violation. The violation is of concern because of the failure of your operators to identify and resolve the locked valve discrepancy prior to its discovery by an NRC inspector.
The poor performance of the operation staff in this event, and the failure of operations to recognize equipment status during core spray system testing, indicate a lack of attention to detail.
Further emphasis on operator attention to plant configuration appears warranted.
You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing your response.
In your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence. After reviewing your response to this Notice, including your proposed corrective actions and the results of future inspections, the NRC will determine whether further NRC enforcement action is necessary to ensure compliance with NRC regulatory requirements.
In accordance with 10 CFR 2.790 of the Commission's regulations, a copy of this letter and the enclosed inspection report will be placed in the NRC Public Document Room.
l
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, ij g
Detroit Edison Company 2
The responses directed by this letter and the accompanying Notice are not subject to the clearance procedures of the Office of Management and Budget as required by the Papenvork Reduction Act of 1980, PL 96-511.
r We will gladly discuss any questions you have concerning this inspection.
Sincerely, j
n e P. Phil lef Reactor Pro cts Section 2B Docket No. 50-341 License No. NPF-43
Enclosures:
I Inspection Report No. 50-341/94011(DRP);
cc w/ enc 1:
J. Conen, Principal Compliance Engineer l
P. A. Marquardt, Corporate
[
Legal Department OC/LFDCB l
Resident Inspector, RIII James R. Padgett, Michigan Public Service Commission Michigan Department of Public Health l
Monroe County Office of Civil Preparedness Fermi, LPH, NRR E. G. Greenman, RIII l
IPAS (E-Mail)
I
t NOTICE OF VIOLATION Detroit. Edison Company Docket No. 50-341 License No. NPF-43 During an NRC inspection conducted from July 25, 1994, through September 9, 1994, a violation of NRC requirements was identified.
In accordance with the
" General Statement of Policy and Procedure for NRC Enforcement Actions,"
I 10 CFR.Part 2 Appendix C (1994), the violation is listed below:
A.
Technical Specification 6.8.1.d. requires that written procedures shall be established, implemented, and maintained covering the surveillance and test activities of safety-related equipment. Attachment 2 of Surveillance Procedure NPP-43.401.404, " Local Leakage Rate Testing For Penetration X-201A," requires, in part, that Valve Ell-F0180 be restored l
to a " Locked Open" position.
Contrary to the above, on August 22, 1994, the NRC inspector determined l
that Residual Heat Removal (RHR) pump "D" recirculation isolation valve Ell-F0180 had not been locked in the open position'in accordance with the restoration specified in Surveillance Procedure NPP-43.401.404.
This is a Severity Level IV violation (Supplement I).
Pursuant to the provisions of 10 CFR 2.201, Detroit Edison Company is hereby required to submit a written statement or explanation to the U. S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D. C.
20555 I
with a copy to the Regional Administrator, Region III, and a copy to the NRC Resident Inspector at the facility that is the subject of this Notice, within 30 days of the date of the letter transmitting the Notice of Violation (Notice). This reply should be clearly marked as a "Re)1y to a Notice of Violation" and should include for the violation:
(1) t1e reason for the violation, or,,if contested, the basis for disputing the violation; (2) the l
corrective steps that have been taken and the results achieved; (3) the corrective steps that will be taken to avoid further violations; and (4) the date when full compliance will be achieved.
If an adequate reply is not received within the time specified in the Notice, an order may be issued to show cause why the license should not be modified, suspended, or revoked, or why such other action as may be proper should not be taken. Where good cause is shown, consideration will be given to extending the response time. Under the authority of Section 182 of the Act, 42 U.S.C. 2232, this response shall be submitted under oath or affirmation.
Dated at Lisle, Illinois, i
this 16th day of September,1994
%'AM wW /,
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U.S. NUCLEAR REGULATORY COMMISSION REGION III Report No. 50-341/940ll(ORP)
Docket No. 50-341 License Nos. NPF-43 Licensee: Detroit Edison Company 2000 Second Avenue
?
Detroit, MI 48226 Facility Name: Fermi 2 Inspection At: Fermi Site, Newpoi Michigan L
Inspection Conducted: July 25,1994 through September 9, 1994 Inspectors:
T. Vegel S. Ray K. Riemer N
Approved By:
MonfeP.Ph fips, Chief Dats Redctor Pr ects Section 2B Insoection Summary Insoection from July 25. 1994 throuch September 9. 1994 (Recort No. 50-341/940ll(ORP))
Areas Insoected: Routine, unannounced safety inspection by the resident inspectors of action on previous inspection findings, operational safety
/
verification, engineered safety features systems, onsite event followup, current material condition, housekeeping, radiological controls, security, L
startup issues, safety assessment and quality verification, maintenance activities, surveillance activities, engineering, and licensee generated report review.
Results: Of the fourteen areas inspected, one violation was identified pertaining to the failure to follow procedures (paragraph 3.a) which resulted in a valve being inadequately locked.
The following is a summary of the licen..e's performance during this inspection period:
Plant Ooerations Operators' knowledge of equipment status and operating practices were poor during Core Spray Systam testing. Operators also missed several opportunities to identify and resolve an instance of an improperly locked valvo, resulting in a violation.. Generally, plant housekeeping and cleanliness in well traveled areas was good, but areas not normally accessed were poor, specifically the drywell, steam tunnel, and general service water pump house.
dW D7ceM Mg.
' O Increased management attention appears warranted in the area of problem reporting and documentation.
Plant Sucoort No concerns were identified in the area of plant support.
Maintenanca Activities associated with post maintenance restoration were weak and resulted in several NRC inspector identified material condition deficiencies.
Post maintenance testing of Emergency Diesel Generator (EDG) 13 was good.
Enaineerina 1
System engineer walkdowns of plant sy; teas were not consistently thorough and i
did not always identify problems or deficiencies. The licensee initiated an
)
area walkdown program to improve in this area.
I 4
1 i
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2
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19 DETAILS 1.
Persons Contacted Detroit Edison Comoany
- S. Booker, Manager, Startup
- C. Bridge, Hechanical Maintenance
- D. Buley, Maintenance
- C, Cassise, General Supe,visir, Hechanical Haintenanco
- J. Conen, Supervisor. ;omr.ance, Licensing
- R. Delong, Nperintendent, Radiation Protection
- P. Fessler, Plant Manager, Operations
- J. Flint, NASS'
- B. Good, Maintenance
- L. Goodman, Director, Licensing
- J. Green, Supervisor, Corrective Actions
- B. Hensley, Maintenance
- J. Korte, Director, Nuclear Security
- J. Malaric, Hodifications
- R. McKeon, Assistant Vice President and Manager, Operations
- W. Hiller, Superintendent, Technical
- D. Nordquist, Director, QA
- R. Newkirk, Supervisor, Licensing
- J. Holloth, Superintendent, Maintenance
- P. Ockerman, DNT, Nuclear Training
- R. Peters, Supervisor, Electrical
- D. Pettinari, Outage Coordinator
- G. Pierce, Supervisor, Work Control
- J. Plona, Superintendent, Operations
- W. Romberg, Assistant Vice President and Manager, Technical
- G. Teribery, Operations
- H. Thrift, Operations
- W. Tucker, Assistant to Technical Manager
- V. Vuyovich, Haintenance
- J. Waszak, HPPO
- J. Walker, Director, Plant Engineering
- Denotes the:;o at!ending the exit interview conducted on September 9, 1994.
The inspectors also had discussions with other licensee employees, including members of the technical and engineering staffs, reactor and auxiliary operators, shift supervisors, and electrical, mechanical and instrument maintenance personnel, and security personnel.
2.
Action on Previous Insoection Findinas (92701) a.
(Closed) Insoector Followuo Item (341/94007-07):
Fire Brigade response concerns identified by the Augmented Inspection Team (AIT).
Six specific concerns were identified with the performance of the fire brigade in response to the hydrogen fire resulting 3
i g 'g ND 6
from the December 25, 1993, turbine event.
The licensee issued Deviation Event Report (DER) 94-0090 to document its evaluation of the findings and corrective actions.
The inspectors determined that appropriate corrective actions had been completed or were committed to for each issue.
l e
The full fire brigade did not function as a team and did not respond to the turbine building until approximately 37 minutes after the event.
j One of the main reasons for the brigade being somewhat disorganized at the beginning of the event was that the brigade assembly and dressout area was very near the fire and was difficult to get to, especially for the brigade i
leader from the control room. Some brigade members went to
,c an' alternate assembly area and some were able to get to the primary area.
As one corrective action, the licensee emphasized quick assembly and early communication of problems in the assembly area in its first quarter 1994 fire brigade training.
Procedures were evaluated and found to be adequate. A new assembly area has been planned that will be closer to the control room, further from likely fire sources, and enclosed to minimize assembly problems from smoke, water, oil, et'c.
During this inspection period, turbine equipment laydown in the planned area prevented construction of the new brigade room, but the area will be built shortly after the turbine is reassembled.
Communication problems were encountered, especially with the e
face mask microphones.
The licensee's investigation determined that most of the communication problems were attributed to malfunctions of the built-in face mask microphones. It was determined that many of the microphones had been damaged by the mask laundry process. The licensee changed their laundry procedure so that the microphones are removed from the masks before the mask is washed.
In addition, a monthly functional check of the microphones was added to Surveillance Procedure 28.508.04. The licensee determined, lifter discussions with consultants and vendors, that the comnunications equipment at the plant was " state-of-the-art" and the corrective actions above should keep it in good operating order.
There was no abnormal procedure for turbine building flooding.
The licensee recently received a completed turbine building flooding study from a contractor and was in the process of 4
reviewing the study and developing a flooding procedure from it. The projected date for completion of the procedure was
.the end of 1994. Due to the large number of possible water sources and complex.ity of the flooding issue, the inspectors considered the licensee's timetable reasonable.
Plant personnel experienced difficulty securing systems causing flooding.
The flooding procedure discussed above will contain drawings of isolation valve locations and instructions for isolating systems. Training will be held when the procedure is issued.
Plant personnel did not have a procedure for manually aligning the CO2 system to purge the generator and fire brigade members were unable to operate the CO2 system valves.
The licensee determined that the procedure for manually aligning the CO2 system had been available locally at the beginning of the event, but had been washed away due to the large amounts of water and oil flooding the area. However, lack of the procedura did not contribute to the inability to start the purge. Brigade members have been trained to communicate with the control room for instructions for system operation when they are not available locally.
The difficulty with operation of the manual valves was not a mechanical problem. All the valves on the manifold were inspected and found to be in good shape. The brigade members were not able to manipulate the valves because the large amount of oil on the floor prevented the operators from getting adequate leverage. Due to the limit 3d amount of hydrogen available to supply a fire, operation of the CO2 purge system was not necessary during'the event and failure to initiate it did not contribute to the severity of the
- fire, Motion detectors worn by plant personnel during the response e
to the event malfunctioned.
The licensee determined that the motion detectors were all functioning normally. The alarms received during the event were attributed to personnel remaining motionless for 30 seconds or putting the switch on the detectors into the
" test" position. Refresher training on the proper operation of the detectors was being included in third quarter 1994 brigade training.
In addition to the corrective actions discussed above, the licensee conducted fire brigade training on many other lessons learned from the response to the event. As discussed in the AIT report, overall the response of the fire brigade was adequate.
The actions taken and comitted to above should further improve their abilities. This item is considered closed.
b.
(Closed) Insoection Followuo Item (341/94007-03): This item pertains to the failure of the Turbine Building Heating Ventilation and Air Conditioning (TBHVAC) Exhaust fan that occurred on May 21, 1994.
The event occurrence and prelimina v licensee investigation efforts were documented previously in. C Inspection Reports 341/94007 and 341/94009. During this inspection period, the inspectors reviewed licensee corrective action plans.
Prior to plant startup from the current outage the licensee plans to balance and refurbish two of the three TBHVAC exhaust fans. The licensee plans to balance and refurbish the third fan following plant startup.
In addition, the inlet screens for the fans will be modified to minimize the pressure drop at the fan inlets. Following installation of the refurbished fans, testing will be conducted to assess fan performance to assure that operation is not in the unstable region on the fan curve.
Based on the results of the testing, system modifications or enhancements are to be evaluated.
Licensee long term corrective actions are to be documented in DER 94-0026.
Based on reviews of documentation, discussions with the licensee's engineering staff, and inspections of the TBHVAC system and repairs in progress, the inspectors concluded that the licensee corrective action plan appears retsonable and adequate to prevent recurrence. The inspectors will continue to assess licensee activities with respect to TBHVAC system restoration during routine observation of licensee maintenance and engineering activities. This item is closed.
3.
Plant Ooerations Fermi 2 remained in cold shutdown for the inspection period due to the extensive outage activities required as a result of the December 25, 1993, turbine generator failure. During the inspection period, the licensee continued with activities associated with the plant's fourth refueling outage.
a.
Ooerational Safety Verification (71707)
The inspectors verified that the facility was being operated in conformance with the license and regulatory requirements, and that the licensee's management control system was effective in ensuring safe operation of the plant.
On a sampling basis, the inspectors verified proper control room staffing and coordination of plant activities; verified operator 6
adherence with procedures and technical specifications; monitored control room indications for abnormalities; verified that electrical power was available; and observed the frequency of plant and control room vi. sits by station management. The inspectors reviewed applicable logs and conducted discussions with control room operators throughout the inspection period.
The t
inspectors observed a number of control room shift turnovers.
The turnovers were conducted in a professional manner and included log reviews, panel walkdowns, discussions of maintenance and i
surveillance activities in progress or planned, and associated 1
1.imiting Condition for Operation (LCO) time restraints, as applicable.
1 1)
Inadeouate Awareness of Plant Conditions Durina Testina On August 4,1994, dynamic testing of Core Spray System (CSS) Valves E21-F0158 and E21-F031B was attempted using the d
"B" and "D" CSS Pumps. The test was conducted in accordance with Work Request No. 000Z940513. However, adequate flow for the test could not be established and the test was aborted. The reason for the problem was because the 65F 4160 VAC Bus which supplied power to the "D" CSS Pump was deenergized. However, operators and engineers attempting i
the test did not realize the deenergized bus was the reason i
for the testing problems until the test was reattempted 24 j.
hours later.
The 65F Bus had been deener refurbishment of breakers. gized on August 3,1994, for The fact that the bus was deenergized was clearly indicated in the control room and had been discussed during shift turnover on the morning of August 4.
The CSS test had originally beca scheduled for August 5, but outage management requested the shift to perform it early.
This request was made after the shift turnover. No one among the control room, testing, or outage management groups realized that the dienergized bus would prevent the test from being run successfully.
This event pointed out numerous weaknesses in operator performance and test control. Many of the weaknesses were identified by the licensee in its critique of the event and corrective actions were identified. However, some of the weaknesses were not identified by the licensee, The scheduling group which requested that the test be e
performed were not familiar enough with the actual test procedure to know that both pumps were needed to be run, A pre-evolution brief for the test was held in the e
control room.
However, not all of the test personnel 7
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who would actually be performing the test in the field were present.
For example, the CSS system engineer was not present at the pre-evolution brief.
Prerequisite 5 in the work request job instructions to e
" Verify Division'II Core Spray System in Standby Mode" was initialed off without verifying power available to CSS Pump "D."
When the pumps were started, the cor. trol room operator e
did not wait for flow in the CSS to stabilize after starting the "B" Pump before attempting to start the r
i "D" Pump. Thus it appeared that flow increased when the "D" Pump was " started" even though the pump did 1
not start.
j e
The control room operator did not lock at the ammeter above the control switch for the "D" Pump.
If he had, i
it would have been apparent that the pump was not running. The inspectors reviewed several operating procedures, surveillance tests, and the Conduct of Operations Manual. None contained instructions to monitor the ammeters when starting pumps.
2 The in-plant operator who was assisting the test personnel inspected the CSS pumps shortly after the start. He apparently did not notice any difference in the two pumps and reported " normal start on core spray pumps." The "B" and "D" Pumps were located in a non-contaminated area and were easily accessible. The operator's inspection of the pumps was inadequate i
since the inspection unable to tell that one of the i
two pumps was not running.
l e
The CSS system engineer was not present for the test.
This was the first run of the Division II CSS after a major divisional outage.
A Shortly after the unsuccessful test, the NRC resident inspector went to the CSS pump room and noticed a i
distinct temperature difference between the "B" Pump Motor and the "D" Pump Hotor. He gave that information to the control room operators and asked if both pumps had been run. He was informed that both pumps had been running, and the difference in temperatures was normal. The operators missed an opportunity to oiscover that the "D" Pump had not been running during the test.
The operators and engineers spent 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> troubleshooting the system trying to determine why 8
3
t l
system ficw had been low. They vented the system instruments and refilled and vented the entire system.
In all that time, through three shift reliefs, no one realized that the "D" CSS Pump had no power because the 65F Bus w s deenergized.
On August 9, 1994, the control room operator walked e
through his actions in the August 4 event with an NRC inspector. At that time a light bulb was burned out on the "D" CSS Pump Control Switch. The operator did not notice the burned out bulb until it was brought to his attention by the inspector after the walkthrough.
The event occurred primarily due to the licensee's i
staff lack of knowledge of equipment status and poor work planning. Contributing to the event was a lack of teamwork, in that the test was commenced without the system engineer present.
In addition, the l
operators demonstrated a lack of attention to detail l
in failing to note the pump motor amperes upon pump S
start and failing to recognize upon visual inspection that the pump was not running. Overall, the performance of the operations staff during this event l
was poor. Another example of poor operator l
performance is described in the next paragraph.
2)
Locked Valve Discrecancy On August 22, 1994, the inspector noted that Valve E1100 F018D (RHR Pump "0" Recirculation Isolation Valve) was not properly locked in position. Specifically, the inspector l
noted that a length of chain was padlocked to the valve's handwheel and the free end of the chain was then positioned i
between the valve stem and the valve yoke; the free end of the chain was not attached in any manner to the valve body and would not have prevented valve mahipulation. The corresponding valve associated with the "B" pump in the division had a length of chain padlocked to the handwheel, and the free end of the chain was welded to the valve yoke.
The inspector discussed his observations with the control room operators and subsequently verified that the valve had been properly locked in position.
The valve in question is listed in both NPP-0P1-09, " Locked Valve Guidelines," and Procedure 27.000.01, " Locked Yalve Lineup Verification."
The inspector determined that the guidance specified in NPP-1 OPI-09 did not apply in this instance because the procedure is required to be verified complete prior to Primary Containment closecut; a condition that was not applicable at the time of discovery. However, the Operations department i -
i had other documentation in effect that required the valve to be properly locked in position.
i
l.
The valve had been manipulated on July 23, 1994, to support testing on another valve in the system. The procedure used was NPP-43.401.404, " Local Leakage Rate Testing For i
Penetration X-201A," Test documentation showed that the valve had been :, hut as a boundary valve for the test. The restoration lineup for the evolution restored the valve to a l
l locked open position. However, the test in question failed and was re-performed on July 29, 1994. The valve was again
" verified" by initial position and independent verification, i
to be restored to a locked open condition. Additionally, valve lineups were performed upon completion of Olvision II work on the RHR system and on approximately August 4, 1994, the valve was " verified" to be properly restored to a locked open condition. Finally, on approximately August 6, 1994, a
" Locked Valve Lineup" verification was performed and the l
l valve was again " verified" to be locked open.
The inspector concluded that between July 29 and August 22, 1994, five operators had signed off that the valve was locked open, when, in actuality, it had not been properly locked in place following system testing.
The operators' failure to properly lock the valve in accordance with Local Leak Rate l
Testing Procedure NPP-43.401.404 is considered an example of 3
a violation of Technical Specification 6.8.1 (341/94011-01).
t Similar to the inadequate core spray system testing event describe in paragraph 3.a.(1) of this report, the failure to i
properly lock a valve was another example of inadequate operator attention to detail. Further licensee management t
attention appears warranted to improve operators attention l
to detail to plant configuration in preparation for plant i
restart.
I b.
Enaineered Safety Feature (ESF) Systems (71707)
During the inspection, the inspectors selected accessible portions of several ESF systems to verify their stat'us. Consideration was given to the plant mode, applicable Technical Specifications, Limiting Conditions for Operation requirements, and other app.licable requirements.
4 i
Through observation, the inspectors verified that the following I
was acceptable:
installation of hangers and supports; l
housekeeping; freeze protection, if required, was installed and I
operational; valve position and conditions; no potential ignition i
sources; and major component labeling, lubrication, cooling, etc.
i The inspectors also verified that instrumentation was properly installed and functioning and that significant process parameter values were consistent with expected values; that instrumentation was calibrated; that necessary support systems were operational; and that locally and remotely indicated breaker and valve i
positions agreed.
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During the inspection, the accessible portions of the following g
ESF systems were walked down:
-[
e Division II Residual Heat Removal System
- c e
Division II Core Spray System e
Division I and II Emergency Diesel Generators a.
j.'
c.
Onsite Event Follow-un (93702)
During the inspection period, the licensee experienced several events,'some' of which required' prompt notification of the NRC 1,
pursuant to 10 CFR'50.72.' The inspectors pursued the events T
onsite 'with licensee and/or:other NRC officials.
In each case, i
the inspectors verified that any required notification was correct i
and timely. The inspectors also verified that the licensee initiated prompt and appropriate actions.
were'as follows:
The specific events 1)
Low Pressure Coolant In.iection (LPCI) Looo Select Loaic Actuation: On August 13, 1994, an inadvertent actuation of the LPCI loop select' logic occurred. The actuation isolated the LPCI "A" Valves and lined up the LPCI "B" Valves for injection. However, in the mode the plant was in at the i
time (de-fueled), the RHR system was not required to be eperable and both divisions'of RHR pumps were in OFF/ RESET.
J Control room operators reset the logic and returned the RHR valves to'their normal configuration. The actuation occurred during troubleshooting activities in the Division
-(
II RHR relay cabinetsi The licensee initiated DER 94-0371 to document the event. Prior to the end of the inspection period, the licensee retracted;the 10 CFR 50.72 i
notification; the inspectors will continue to follow this issue'through routine review of licensee DERs.
(-
2)
Fermi 1 Floodina: On August 13, 1994, operators in the S
Fermi 2 control room received a Fermi'1 Water Intrusion h
alarm. The alarm was'due'to extremely heavy rainfall the area was experiencing at the time.
Licensee personnel performed walkdowns of the Fermi 1 buildings and discovered standing water in some of the buildings.
Flooding in the various basement rooms ranged from six inches to three feet of water. The inspector also toured the Fermi 1 site, including the flooded areas. Prior to pumping out the water, itcensee personnel sampled the water and performed surveys of the affected areas. The water sample results showed no detectable activity. The licensee documented the event per DER 94-0383. The inspectors will follow this issue through routine review of licensee DERs.
3)
Containment Isolation Inadecuacy: During an engineering review of the design of the reactor recirculation pumps seal 11
p.
purge line air operated isolation valves, the licensee discovered that the line may not properly isolate under accident conditions. The design of the valves, whose purpose is containment isolation, is such that they may have inadequate closing force to close against accident conditions. Specifically, the valves were origina11y' installed in the reverse orientation and the original spring set pressure is inadequate to provide enough force to close the valves under design basis accident conditions.
In addition, the licensee also discovered that check valves installed in the lines had their internals removed. The check valves' purpose is to minimize radioactive material transport from the containment due to a pipe rupture when the automatic isolation capability is not initiatTd! The licensee notified the NRC Operations Center on August 22, 1994, of the discovery and intends to submit a Licensee Event Report (LER) to formally address the issue. The NRC will further investigate this issue during review of the associated LER.
4)
Division I_I Actuations: On August 26, 1994, craft personnel performing modification work loosened a terminal to add a connection at that point. Other wires were attached to the affected terminal screw and when the screw was loosened, continuity was lost to the circuit. The power feed was lost to most of the Division II isolation logic which caused the
~
expected isolations and actuations to occur. The licensee stopped the work, re-tightened the terminal, and reset the logic and components. The HRC will further investigate this event through review of the associated LER.
5)
Source Ranae Monitor "B" Ooerability:
On September 4,1994, during refueling operations, the operators observed that the response from source ranga monitor "B" was less than expected wh'en fuel bur.dles were placed in the quadrant of the detector. The operators suspended core alterations in accordance with Technical Specification (TS) 3.9.2.
Subsequent licensee investigation determined the cause for the SRM "B" indicating problem was an inadequate undervessel cable connection which resulted in SRH "B" being inoperable. The problem with the connector was corrected and core reload activities were resumed on September 5.
The licensee initiated DER 94-429 to document event investigation and track corrective actions. At the end of the inspection period, licensee event investigation was in progress. The licensee intends to submit LER 94-006 to formally document the event. The apparent failure of the licensee to have an operable SRH channel in the quadrant where core alterations were being preformed was a potential 12
^ ~
.... ~ :.
violation of TS 3.9.2.
The inspectors will assess potential enforcement actions during review of the associated LER in a future inspection report.
6)
On September 7, 1994, while refilling the condenser hotwell, a leak develcped resulting in approximately 2,000 gallons of water spilling into the condensate pump bay. The water, which was being transferred from the torus, leaked past the seat of the shut center condensate pump suction valve and i
out p ;t the pump shaft. The' pump seals were not installed due to maintenance. Approximately one to two inches of slightly contaminated water covered the floor of the condensate pump bay. No personal contaminations or equipment damage occurred.
The licensee collected the water for subsequent treatment with no release of contaminated water occurring.
The inspector toured the affected area and concluded that licensee cleanup activities appeared reasonable and adequate.
d.
Current Material Condition (71707)
The inspectors performed general plant as well as selected system and component walkdowns to assess the general and specific material condition of the plant, to verify that work requests had been initiated for identified equipment problems, and to evaluate housekeeping. Walkdowns included an assessment of the buildings, components, and systems for proper identification and tagging, accessibility, fire and security door integrity, scaffolding, radiological controls, and any unusual conditions. Unusual conditions included but were not limited to water, oil, or other liquids on the floor or equipment; indications of leakage through i
ceiling, walls or floors; loose insulation; corrosion; excessive noise; unusual temperatures; and abnormal ventilation and lighting.
1.
Reactor Buildina Steam Tunnel and Drv4 ell Material Condition: On August 11, 1994, inspectors conducted an inspection of the reactor building and the drywell.
Based on numerous observations of dirt, debris, and damaged components, the inspectors concluded that the drywell housekeeping and material condition was poor.
Specific exampics of poor housekeeping included the following:
Large accumulation of debris including lagging e
materials, tools, clothing, and tape. Helmets were observed underneath the main steam lines in tne steam tunnel.
Tools, clear plastic bags, two cans of glue, helmets, gloves, and tape were observed in the drywell.
13 l
r h
s j
i Examples of damaged plant equipment included:
Damaged flexible conduit on recirculation pump "B".
o Nitrogen lines to outboard "D" Main Steam Line were bent and had numerous dents.
The inspectors observations were contrary to previous licensee assessments of the area. A Quality Assurance Surveillance report :hted July 15, 1994, noted that a special' effort by the Deconner Group was being made to keep the drywell in the best condition ever for an outage.
i i
On August 20, while performing flow testing of the drywell floor drain sump'and pumps, operators observed that the east pump (Pump G1101-C0018) had run indication'but no flow i
indication. The other (west) sump pump operated satisfactorily and proper flow indication was received.
Troubleshooting efforts performed on August 26, August 29, and August 31 did not indicate any abnormalities with the pump motor itself. Subsequently, licensee maintenance personne1' cleared a priming hole on the pump and the pump subsequently performed satisfactorily.
In parallel with troubleshooting efforts on the pump itself, the licensee was preparing a work package to investigate possible blockage of the suction line.
Preliminary decontamination efforts to support the work discovered a rag, a three inch roll of duct tape (3/4 full), and several small pieces of debris (lockwire, nuts and washers) in the sump. Since the pump performed properly after clearing the priming hole, the licensee did not perform the work package to disassemble and inspect the pump's suction path for possible blockage.
The above observations indicate a lack of sensitivity by the licensee staff to maintaining adequate cleanliness during and following maintenance activities.
In addit' ton, the damaged wires and'other components appeared to have occurred during maintenance activities during the current outage. The inspectors recognize that the licensee will inspect and clean the drywell prior to plant startup. The inspectors are concerned that the failure of the licensee to maintain adequate cleanliness in the drywell and the failure to promptly identify equipment deficiencies will result in increased radiological exposure to clean up affected areas and an increased potential that equipment deficiencies may be missed prior to drywell closure and plant operation.
Further licensee attention appears warranted to ensure plant housekeeping is maintained during maintenance and that equipment deficiencies are identified, documented, and corrected.
The inspectors will assess licensee corrective actions during routine inspections of plant material condition and observations 14
- ~. -.
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['
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' i.:
W of. maintenance activities.
In addition, the inspectors will k,;
assess dg' ell c{eanliypss pri.or_ to plant startup from the outage, d'
~
e.
General Plant Housekeeoino 'and Cleanliness
\\ft:A~
.The inspectors' mon'itored the status of housekeeping and plant 7(* '
cleanliness for fire protection and protection of safety-related 7;'
equipment from' intrusion of foreign matter.
In addition to the observations'noted'in paragraph 3.d above, the inspectors
. identified'other examples of housekeeping deficiencies during the performance' of routine ~ plant tours.' Examples ! included an' '
S electrical' cord' draped across' differential pressure transmitter y,M equalizing valves'on an' instrument rack; a droplight'and extension V
cord' hung from valves on'the control' rod hydraulic control ~ units (HCUs);' scaffolding roped off to spring mounting' clips for the particulate' iodine, filter on the Division II' standby gas' treatment sa system'-(SGTS) exhaust-radiation monitoring ' rack;'and duct ' tape
~
covering a turbine building floor drain in the gland seal
+
condenser room.
The inspector's identification of the tape 4
covering'the floor drain was a repeat' example ~of an issue previously identified by the licensee. The duct tape / floor drain issue'had been previously identified by the licensee, and '
documented in DER 94-0232.
Immediate corrective actions included removing all tape from floor drains while the DER was being evaluated. Due to the relatively short time frame between the licensee's identification of the problem and the inspector's observations, the inspectors concluded that not enough time had elapsed for the licensee to implement final corrective actions to resolve the issue. The inspectors will follow this issue during routine plant inspections and through routine review of DERs.
The inspectors discussed all housekeeping concerns with on-shift control room personnel and verified that the items were corrected in a timely manner. Further licensee attention is warranted to improve housekeeping and plant cleanliness prior to plant startup, to preclude the poor housekeeping practices observed during this inspection period from negatively impacting' plant operations.
f.
Radioloaical Controls (71707)
The inspectors verified that personnel were following health physics procedures for dosimetry, protective clothing, frisking, posting, etc., and randomly examined radiation protection instrumentation for use, operability, and calibration.
No significant deficiencies were identified.
g.
Security (71707)
Each week during routine activities or tours, the inspectors monitored the licensee's security program to ensure that observed actions were being implemented according to the approved security plan. The inspectors noted that persons within the protected area displayed proper photo-identification badges, and those 15
Vf p
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~
X; Lindiv'iduals requiring. escorts were properly escorted.
Additionally,"the impectors also observed that personnel and 7
E packages' entering the protected area were searched by appropriate R
equipment.or by hand.
.Ho~ significant deficiencies were r.
ident i,fi ed.'
(
o y-g One ' violation was identified.
p.
4.-
Startuo issues-
[
Following the' December 25, 1993, turbine generator event, the NRC
(#
compiled a listing'of items that require completion prior to unit restart.]he,fol,lowingare1.ssuesreviewedbytheinspectors:
n b;
a.
IBHVAC Failurei Based on NRC inspections of licensee
'7,
efforts associated with the TBHVAC failure (reference g
paragraph 2.b of this report), this'startup item is closed.
p' b.
Fire Briaade performance: Based on NRC inspections of g
Itcensee initiatives addressing the fire brigade performance issues' (reference paragraph 2.a of this report), this startup issue-is closed.
c.
Condenser Reoairs: A large number of condenser tubes suffered damage as a direct result of the December 25,1993, turbine generator failure event.;' As part of licensee restoration efforts,'all debris was' removed from the
~
condenser and approximately 5300 tubes were replaced.
Licensee personnel performed eddy current testing to determine the extent of damage to the condenser tubes. The E,-
testing covered a portion of the tube bundle from the' top of the bundle down until no more indications of damaged tubes a
were received. The licensee replaced all damaged tubes.
In addition, the licensee also replaced all damaged tubes
+;. --
(with the exception of a single' tube) that had been plugged 1,
prior to the turbine failure event. ' The licensee also 3;,
replaced all tubes (both damaged and undamaged) around the v. '.a
. periphery of the condenser tube bundle with thicker walled tubes. With the exception of the one tube r,entioned, the condenser will have no plugged tubes when the licensee comences plant restart activities.
In addition to tube replacement actions, the licensee inspected all anti-(
vibration stakes and replaced damaged stakes as necessary.
When repairs were completed, the licensee chemically cleaned the inside (north end) of the condenser to remove oil and
,,i contaminates that entered the system as a result of the turbine failure event. As a part of startup activities, plant personnel will perform a condenser floodup to check for tube leaks.
Based on discussions with licensee personnel, and inspections performed inside the condenser to assess damage and observe repair efforts, the inspectors concluded that the licensee's corrective actions appear 16 7
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W adequate and reasonable to restore the condenser to an y
~' operable' status. 3This. item is' closed.
4;.
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d.-
H'oh Pressure' Coolant Iniection (HPCI) Test' Return Line i
hf li '
iValve: M The NRC'AIT: report (Inspection Report No.350-
%C
'341/93029) indicated'that the HPCI test line isolation-NL 2 3-
,,, Valve; E4150'Foll,ifailure to operate was'due to operator SD
. error.Z The: licensee had previously determined that'the N^
linstalled'. valve operator was'not' capable; of opening the-
~ valve ~without'first' venting tho' upstream piping and the standard operating' procedure had been~ revised to include the T
venting requirement.1' During the event, the operator fi attempted to'open the valve without following the procedural requirement to vent the upstream' piping. The inspectors '
4 Y further reviewed'the. event'and determined that control roos 9
ipersonnel were fully cognizant of the' valve's limitations w
.when the' initial: attempt was made'to' operate the valve for ih.L reactor pressure control purposes. The Nuclear Shift
%y
^
' Supervisor (NSS) made a conscious decision to first attempt to. operate the valve without venting the piping in order to Q1 possibly preclude sending personnel out into a hazardous g, ' <
environment in the plant when actual conditions (fire,-
cv'
~, flooding,. smoke) were not yet fully understood. The initial 4p attempt was treated as an effort to determine'if the valve y
'would operate, as opposed to omitting steps in a procedure, y
- Based on~ theilnspectors' further review of the event, the W
actions ~taken by the control room staff in this instance' 8
appeared prudent and reasonable. The operator performance
.C" aspect of this issue is closed.
[
5.
Safety Assessment /Ouality Verification (40500 and 92700) y The inspectors reviewed the licensee's DER's generated during the a.
'R inspection period. This was done in an effort to monitor the conditions related to plant or personnel performance, potential trends, etc. -DERs were also reviewed to en'sure that they were a
t generated appropriately and dis with the' applicable procedures. positioned in a manner consistent During the inspection period, the inspectors reviewed various events and then reviewed the occurrences against the licensee's corrective action program criteria for documenting adverse conditions via a DER. The inspectors reviewed the events to determine if all issues were being appropriately addressed and documented in a timely manner. The inspectors reviewed the events p
to ensure that the licensee was not potentially missing opportunities to trend adverse conditions or benefit from lessons learned in preventing future similar occurrences.
Soma of the specific events reviewed were:
(1)
Reactor Pressure Vessel (RPV) level indication - During a documentation review of prior control room logs, the p.
F 17 p
e
],9.i
,MP 3~
inspector noted that on April 14, 1994, the Reactor Vessel S.
Floodup Level. Indication pegged high during RPV floodup M'
activities conducted to commence the plant's refueling outage. During discussions with licensee personnel, several Q
apparent weaknesses were identified. The physical l y'4' configuration of the level indication piping was misunderstood by licensee personnel in that three t
i 1 interconnected flanges were thought to be physically l
. separate. : Sin _ce the flanges were thought to be separate, permission was given to break'a specific flange to install a temporary reference leg for floodup indication. In effect, breaking of the one flange caused a loss of the reference O<
1eg for the floodup level indication'in the Main Control o
Room. ' Also,L the procedures used for directing floodup g
activities appeared to be weak. The sequence of two steps MM in the procedure was reversed which mistakenly directed 9\\
removal of the reactor head vent line piping prior to placing the temporary floodup reference log in service.
a.
J' Finally, comunications between the various groups involved in the evolution were not clear.
Information presented to the control room operators did not clearly comunicate that the temporary reference leg was installed, but not properly valved in. The safety significance of this particular event a-was low since there was other level indication available to i...
the control room operators at the time of event.
Licensee 4
personnel conducted an on-shift critique, performed imediate corrective actions to resolve the issue, and 1'
continued with floodup activities. The inspectors were E
concerned with the licensee's decision not to write a DER because the opportunity was lost to address potentially l.t
' y generic issues that could apply to other situations (proper briefings, comunications between groups, proper l
coordination across shifts and work areas) and, therefore, prevent future similar occurrences.
[p]
(2)
Breaker Trips - On August 15, the licensee performed Procedure 24.307.13, "EDG 14 - Emergency Core Cooling System 4
(ECCS) Start and Load Rejection Test" and the EDG 14 output I
tripped open. The problem was due to a procedural error in which steps were out of sequence. Per discussion with L
Engineering personnel, the miss-sequencing of steps resulted i
in a situation where trip signals (undervoltage condition)
F were not cleared prior to restoring the normal lineup.
F Licensee personnel corrected the problem on-shift and I
continued with the testing.
The inspectors were concerned i.
that a DER was not written until four days after the event, Ps and then was apparently not forwarded to management until b
nine days after the event occurrence.
o e'
One week later, on August 22, the licensee performed Procedure 24.305.01, "480 Volt ESF Bus Load Shed Verification" and received a trip of the 72EA-2C and 72EA-2D 18 51.
p
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Breakers. The problem was similar to the prior event in D
that a procedural error resulted in steps being performed W
out of sequence. The problem was due to closing trip cutoff U
switches prior to resetting the undervoltage relay.
' Licensee on shift' personnel corrected the step order, re-
- /
closed the breakers, and continued with the work. A DER was N
not written to document the problem because the event k
- ., occurred during y " validation" run' of t.he procedure, w
,a.
s.
U" (3)?.EmergencyEquipment'CoolingWater(EECW)inoperability. On August'24,4 operators manually: initiated Division I EECW in
,i preparation.for testing.:~ Unexpectedly, the Emergency
.E:
Equipment Service Water (EESW) system pump immediately indicated a' tripped condition. ~ The licensee's J
investigation revealed that the Division I EESW Pump 52xx f
-Relay was~not reset. The operators manually reset the relay and verified that the EESW pump operated properly, further
- S investigation' revealed that the same situation existed on Division'II'(i.e., the division II EESW 52xx relay was not reset and the pump would have tripped immediately). The problem had apparently existed since August 22 when a' procedural error did not ensure the relays were reset after performance of a surveillance test. Operations personnel tc, contacted engineering personnel to notify them that changes 4
.R would be required to correct the procedure. The problem was 3
corrected on shift and testing continued. A DER was initiated two days later by the Independent Safety y%,,
Engineering Group (ISEG) organization. Though it was positive that ISEG initiated the DER, the inspectors y
questioned why one of the involved groups (operations or y
engineering) did not capture the event and document the p ' '.
occurrence via DER.
Although by themselves the above events were not of safety significance, the inspectors were concerned about the y
potential for events to be lost for tiending.
The events in
' indicate a need for reemphasis, to working groups, the F
importance of identification of problems so that long term
^
C-corrective actions, if necessary, can be determined. The inspectors will continue to follow this issue during routine Resident inspections.
a c
l No violations or deviations were identified.
- f,.
6.
Maintenance (62703 & 61726) a.
Maintenance Activities (62703)
Selected station maintenance activities were observed and 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.
19 It 4
8 M
W:y X ',
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wg The7following items were also considered during this review:
m limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; functional testing and/or calibrations
.were performed prior to returning components or systems to service; quality control records were maintained; and activities I
we,re accom..plished by qualified' personnel.
i y,,
Portions of the following maintenance activities were observed or reviewed:
e Overhaul Emergency Diesel Generator (EDG)-13 Engine e r.
t e,
Overhaul EDG-14 Engine j
'M e
Horth' Reactor' Feed Pump turbine repairs W
e
-Heater Drain Pump maintenance - repair i.
e Main' Turbine repairs
?
e.
TBHVAC Center Exhaust Fan repairs e
Circulating Water Pump repairs Inspect suction of Drywell Floor Drain Sump
}
e e
4160/480 volt breaker inspection and refurbishment As discussed in paragraphs 3.d and 3.e of this report, housekeeping and material condition in the drywell and steam tunnel were generally poor.
In addition, other areas in the plant were also noted to be in poor material condition partially due to i
poor post maintenance re @ ation. For example, based on NRC l
inspectorsand' licensee Quality Assurance inspectors' observations'on August 18, 1994, the' General Service Water pump house'was dirty and tools were improperly stored.
In addition, j
- h' the diesel fire pump had oil leaks and the NRC inspectors noted i
that four bolts were missing from the oil pan. Maintenance en the t,
- e diesel. fire sump had recently been completed but due to the leak:,
the missing solts,'and the debris noted by the inspectors,'the
,3 post' maintenance restoration and cleanup was unsatisfactory. On August 18, a priority two work request was' initiated to install l
the missing' bolts'.
In addition, the licens'e' initiated DER 94-j e
0387;to document the occurrence of the deficiency and track-
' corrective actions.s Another example of poor post maintenance restoration was observed by inspectors on August 11, 1994, in the Reactor Building Steam Tunnel. The inspectors noted that plastic packing plugs were installed in several outboard main steamline isolation valve (MSIV) operators.
Subsequent licensee investigation identified plugs also installed in some inboard MSIVs. The licensee determined that the installed plugs would have affected the operation of the HSIVs. The licensee initiated DER 94-0408 to document the occurrence of the discrepancy, investigation results, and track corrective actions.
Based on the above observations, further licensee attention is warranted to ensure proper equipment restoration following maintenance activities.
Inspectors will assess licensee 20 i
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The7following'itemswerealsoconsideredduringthisreview-rs;,,
. limiting: conditions for operation were met while components'or b-systems"were removed from service;. approvals were obtained prior to]nitiating.the work;ifunctional testing and/or calibrations
. were' performed prior to returning' components or systems to t
service; quality control records were maintained; and activities I
r" were accomplished by qualified personnel.
q n,
1 Portions of the following maintenance activities were observed or reviewed:'.
4 go o
e M ' Overhaul. Emergency Diesel Generator (EDG)-13 Engine
- 4 4 0verhaul EDG-14 Engine V.
ed',iNorth* Reactor' Feed Pump turbine repairs e%
- W LHeater Drain Pump maintenance - repair e v iMain Turbine repairs:
W' W9.,
e.
TBHVAC Center Exhaust' Fan repairs
- s. - /
Circulating Water Pump repairs e
Inspect suction'of Drywell Floor Drain Sump e
4160[480 volt breaker inspection and refurbishment As discussed in paragraphs 3.d and 3.e of this report, housekeeping and material condition in the drywell and steam tunnel were generally poor.
In addition, other areas in the plant were also noted to be in poor material condition partially due to
"?
poor post maintenance.reptuation. For example, based on NRC inspectors'~and' licensee Quality Assurance' inspectors' observations?on' August 18, 1994, the' General Service Water pump thouse was' dirty and tools were improperly stored.
In addition,
- R
'the'diese1~ fire pump had oil leaks and the'NRC inspectors noted W{y,
3 thatifour bolts were missing from the oil pan.- Maintenance on the O
diesel' fire ) ump had recently been completed but'due to:the' leaks,
- the missing aolts, and the debris noted by)thecinspectorsV the 34 post: maintenance restoration and cleanup:was unsatisfactory.- On p5 ':
' August'18; a priority two work request wasiinitiated to install T
the missing' bolts'. :In addition, the licensee' initiated DER 94-l
/
0387lto document the occurrence of the. deficiency and track-B'..,
' corrective actions.v Another example of> poor post maintenance restoration was observed by inspectors on August 11, 1994, in the Reactor Building Steam Tunnel. The inspectors noted that plastic packing plugs were installed in several outboard main steamline isolation valve (MSIV) operators.
Subsequent licensee investigation identified plugs also installed in some inboard MSIVs. The licensee determined that the installed plugs would have affected the operation of the HSIVs. The licensee initiated DER 94-0408 to document the occurrence of the discrepancy, investigation results, and track corrective actions.
l Based on the above observations, further licensee attention is warranted to ensure proper equipment restoration following maintenance activities.
Inspectors will assess licensee 20
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k The"followingilt'ess' were'also considered during this review:
limitingiconditions for operation were met'while components'or Pd e,
sys,temshwere removedffrom service;; approvals-were obtained prior.
to initiating the ' work;; functional! testing.and/or calibrations W,%
zwere! performed prior:to returning' components or systems to service
- were?acc;tquality: control recordstwere maintained; and activities omplished by: qualified' personnel.
- g Q_
g:7W L
Portions of)the'following maintenance activities were observed or y
reyjewe_d:U m
y Egg e i ov'erhaul. Emergency Diesel Generator (EDG)-13 Engine
'?.
e Y Overhaul EDG-14 Engine
.M" o @M North'ReactoF Feed Pump turbine repairs e
R %p Heater Drain Pump' maintenance - repair n
e
- # FMainlTurbine repairs ' '
t M6,
- C '.TBHVAC Center Exhaust Fan repairs j
'en er Circulating Water Pump repairs C ;v e-Inspect suction'of Drywell Floor Drain Sump V.
14160/480 volt breaker inspection and' refurbishment v
W As ' discussed in paragraphs 3.d and 3.e of this report, housekeeping.and material condition in the drywell and steam cm tunnel were: generally poor.
In addition,'other areas in the plant 4
were also noted to~ be in' poor material condt: tion aartially due to B,
' poor post maintenance.reMxation.. For example, sased on NRC
.inspectorsMand" licensee Quality Assurance' inspectors'-
-observations'on August 18,t1994, the General Service Water pump bz thouse'was'dirtytand tools were improperly stored. ;In addition, M
'tha' diesel: fire pump:had oil leaks and the NRCfinspectors noted Q,
thatifourl bolts'were' missing from the oil' pan" Maintenance:on the de
' diesel; fire; sump'had recently been1 completed but 'due'to the11eaks,
{pp.4,
-the'aissing.solts,fand theLdebris noted byitheiinspectorsN the n
't postimaintenance restoration and cleanup;was unsatisfactory.<0n r.1 l August 18Faprioritytwo'workrequest'was!initiatedto'. install Q
the'aissing boltsi 'In addition,'the~ licensee' initiated DER 94-
~
E..,
' corrective ~ actions'.e Another example'of poor post 0387/to: document t and track o restoration'was observed by inspectors on August 11, 1994, in the Reactor Building Steam Tunnel. The inspectors noted that plastic packing plugs were installed in several outboard main steamline
' isolation valve (MSIV) operators. Subsequent licensee investigation identified plugs also installed in some inboard MSIVs. The licensee determined that the installed plugs would have affected the operation of the MSIVs. The licensee initiated DER 94-0408 to document the occurrence of the discrepancy, investigation results, and track corrective actions.
j Based on the above observations, further licensee attention is warranted to ensure proper equipment restoration following maintenance activities.
Inspectors will assess licensee 20
,e
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N corrective action to address post maintenance restoration and
./
~ housekeepi.ng. concerns during routine observation of maintenance act,ivities and' plant' equipment inspections.
.; y.
No violations or deviations were identified, b.
Surveillance Activities (61726)
During the inspection period, the inspectors observed technical E
specification required surveillance testing and verified that testing was performed in accordance with adequate procedures, that F'
test 1 instrumentation was calibrated, that rasults conformed with
{(1 ; g '
technical' specifications and procedure requirements and were reviewedpand'that any deficiencies identified during the testing were. properly resolved.
?~
The inspectors ~also witnessed or reviewed portions of the 7
following surveillances:
e EDG-14 Post Maintenance Run l.
e Emergency Diesel Generator' Inspection Locked Valve Lineup Verification s-e Dynamic Test of Core Spray System Motor Operated Valves e
Cal 1Dration and functional of Undervoltage Relays
//.-
e-
. Division II Core Spray System Leakage Monitoring Test
+
e Mode 5 Shiftly, Daily, and Weekly Surveillances e
480 volt ESF Bus Load Shed Verification EDG 14 - ECCS Start And Load Rejection Test No violations or deviations were identified, v..
T, 7.
Enaineerina (37700)
E
/^
During the inspection period, inspectors observed numerous material O.
deficiencies during routine plant tours.
Some of the discrepancies are h
documented in paragraphs 3.d and 6.a of this report. The failure of the
. licensee staff to recognize the deficiencies was of concern. There a' pears to be a lack of system engineer involvement in verifying p
equipment restoration following maintenance activities.
Specific examples of apparently obvious deficiencies that could have been noted by system engineers observing maintenance activities were the plastic plugs left in the main steam line isolation valve actuator exhaust ports and the bolts missing from the diesel fire pump oil pan. The inspectors discussed the concern with licensee management and action was initiated to enhance system engineer involvement in post maintenance walkdowns.
During the latter portion of the inspection period, the licensee implemented a team approach to perform area walkdowns and assess overall conditions of the plant. The effort was an organized approach to assessing plant material condition and the walkdown teams irit.uded 21 J
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s Dl personnilfromtheMaintenance, Engineering, Operations,andQuality M*
' Assurance organizations. The licensee's~ strategy was to have the team b
- 90 out:as a' group and to assess overall condition of specific areas of d
the' plant ~(as' opposed to a specific system walkdown). Management h
representatives attend'the pre-walkdown briefs to enforce their t
expectations:as to the team's mission. The' system engineers are to be the focal point of the team walkdowns. The first team walkdown occurred on August 23, 1994, and covered the RHR complex. At the end of the inspection period, the' licensee was developing a strategy for the best way to fix'the' problems identified on the team walkdowns.
If implemented.fal the licensee's.thfully, the initiative has the potential to strengthen ability to assess and improve the material condition of the plant ~. ' The inspectors ~will assess the adequacy of the licensee's area walkdowns during routine inspection of plant areas and reviews of
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licensee findings.
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yoviolationsordeviationswereidentified, q.,,
L 8.
Reoort Review During the inspection period, the inspector reviewed the licensee's Monthly Operating Status Report for July 1994. The inspector confirmed that the information provided met the requirements of Technical Specification 6.9.1.6 and Regulatory Guide 1.16.
The inspector also reviewed the licensee's Monthly Performance Report
[,
for the month of July 1994.
No violations or deviations were identified.
9.
Meetinos and Other Activities F
a.
~Manaaement Meetinas (30702) e, On August 4,1994, Mr. Greenman, Director, Division of Reactor M
M Projects; Mr. Hannon, Project Directorate III-1; and others of the regional and headquarters staffs toured the Fermi plant and met
( 1,.
with licensee management to discuss fermi 2 restart efforts and the NRC's associated Restart Action Plan.
The NRC ' Fermi 2 Restart Action Plan" is provided as an attachment to this report.
On September 8,1994, Mr. Miller, Deputy Regional Administrator, Mr. Greenman, Mr. Hannon, and others of the regional and headquarters staff met with licensee management at the Region III office to discuss Fermi 2 restart efforts, b.
Exit Interview (30703)
The inspectors met with the licensee representatives denoted in paragraph I during the inspection period and at the conclusion of the inspection on September 9, 1994.
The inspectors summarized the scope and results of the inspection and discussed the likely 22 h
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content of this inspection report. The licensee acknowledged the i
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g information' and did not indicate that any of the information F-disclosed during the inspection could be considered proprietary in nature.C ?
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Attachment:
6.0,
~ Fermi 2 Restar,t Action, Flan I
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FER.MI 2 RESTART ACTION PLAN yJ
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4 PROJECTED ISSUE RESPONSIBLE OR ACTUAL U'
iX ORGANIZATION COMPLETE
}.':4Evaluateaccepthilityloponde,nsatestoragetankreleases Complete -
a4 9 to Lake Erie M P ' ' '
DRSS 03/30/94
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~ 42.4 S Evaluate plant 'actNities:to restore reactor coolant Complete -
Isystem chemistry ', acceptable conditions.
DRSS 02/07/94
,m m..
f 3.<', s Assess.adequacyfor implementation of emergency plan given Complete -
sAIT findings.5 '
DRSS 03/18/94 3
[0 * [> As' essiadequacy?cf ' security plan implementation given AIT 4h s
Complete -
findings; DRSS 04/25/94
'5f~1actionstaken.to'restoresystem.lEvaluatedamage'toneutralreturnlineand
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During E&TS 17 DRS Insp.-
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.- n 9/16/94 6.i cEvaluate adequacy of the" licensee's actions to address the
- h.l Doperator performance deficjencies identified in the AIT Complete -
' report.
a DRS 07/12/94 7.
IConsolidate' findings from AIT report and issue appropriate Complete -
1
-inspection followup' items or violations, as appropriate.
DRP 06/15/94 q.
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Evaluate' damage'to generator and exciter.
DRP 06/15/94 Complete-
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9;3
assistance 08/30/94
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'10.
Root cause of the turbine failure is submitted to NRC (CAL
- F item #1 complete).
Licensee 03/19/94 IQ : Evaluation of licensee's corrective action plans for Expect from
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- restoration'of the turbine by operating with.both 7th and licensee
%(b 18th stage blades removed from all LP turbines completed.
around Review to include evaluations 'of the following: pressure 9/1/94 plate analysis, UT exam results, root cause of failure 3 weeks m
analysis, missile analysis, shaft analysis, turbine post support and foundation assessment, and turbine vibration licensee t
analysis given the expected bow in the installed rotors.
NRR submittal
' 12. '- -NRC review of MOV failure corrective actions, and results F
' of MOV static and dynamic testing problems, including
- pressure locking issue, completed (IFI-341/94007-05).
DRS 10/01/94
- 13., Determine and conduct inspections necessary to evaluate licensee
,L licensee's repairs for structural damage suffered during summary
^
the event. Areas to be evaluated by NRR include support complete by beams, bearing boats, and cradle for the turbine; and 9/10/94
, floors and walls of turbine building. Areas to be
~
evaluated'by DRS include the steam lines, oil lines, water During E&TS
-lines and-their associated hangers, supports, and DRS with NRR inspection J
assistance
- 09/16/94 i X
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renus a nasTART ACTION PLAN l Continued) w,,
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^ ISSUE:
RESPONSIBLE PROJECTED Q,
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ORGANIZATION OR ACTUAL COMPLETE d.y 'Ensureithat all Appendix R' requirements are met for DRS with DRP l
7 'those: areas' formerly containing Thermo-Lag material.
assistance.
09/30/94 3
l5blEffects:offthe_chemistryexcursiononthefueland j
v b ' reactor l vessel: internals are! submitted to the NRC i
V'
~(CAL' item 12 complete)'" '
Licensee' 08/19/94 i
16MEffects of the $mistry excursion 'on the control
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C ' crod' drive' mechanisms'ai r'ubmitted to the NRC.
Licensee 08/19/94 s
IK 3C evaMt'on ok chemistry excurifon effects on Meeting will i
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be scheduled
< potentia 17 reactor internals damager cracking.
susceptibility,'need for modification to standard in HQ during ISI: program,' and' acceptability:of operations week of 8/22 if completed:(IFI-341/94007-06.' Areas for review to present
% ' include' length of the"excurs)'ionf the exact values of Chemistry
.chemi'stry-parameters'during the excursion, analysis.
,'s(pec water for different chemical species, conductivity, pH and chemical ~ analysis of the c
especially those which can'cause damage to the in-
- vessel components, e.g. chlorides, sulfates'etc.);
and a' quantitative and qualitative analyses of any 3 weeks post deposits ~on fuel and'different components inside the licensee
- 3 " vessel'.
NRR submittal t JNRClinsp'ect ion of operability 'of Turbine Building
'l HVAC syster. completed (IFI-341/94007-03).
DRP 08/30/94 Ib,. NRC inspection of adequacy of condenser repairs
. completed.
DRP 08/30/94 20.
' Inspection of modifications ' implemented to allow F
continued operation of BOP and _ turbine generator and 6
' bounding.of moisture intrusion problems occurring P>
prior to event (e.g.,-modified rotors,new static 6
exciter, restoration of turbine support systems such G
asslube oil and cooling' water, modifications to During E&TS t'
feedwater heater string instrumentation, heater Inspection -
drain pumps, etc).
DRS 9/16/94 1
21' NRC evaluation of adequacy of repairs to fire
' protection system damaged during event.
DRS 09/15/94 2.
'All. safety-related 480 volt and 4160 volt ABB breakers are replaced / repaired to resolve hardened During E&TS grease concerns and the cracked starting crank Inspection -
l fconcern.
DRS 09/16/94 23.:
NRC verification that corrective actions necessary
'.to address deficiencies identified in AIT report regarding fire response are completed (IFI-341/94007-07).
DRP 08/30/94 NRC review of licensee's determination regarding IST 3 weeks post applicability for valves between radwaste building licensee and ECCS corner rooms completed.
(IFI-341/94005-01)
NRR decision e
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FERMI 2 RESTART ACTION Pt.AN (Continued)
ISSUE RESPONSIBLE PROJECTED ORGANIZATION OR ACTUAL COMPLETE 2b.
Assess the licensee's staff readiness for power operations; 1.e., has the staff been trained on the new mods on the turbine and feedwater systems, have-the operators been given training to prepare for startup.
DRP 10/01/94 26.
HRC evaluation of' adequacy of pre-startup, start up, l
and power ascension testing program completed.
Evaluation to ensure vibration limits for operation throughout the cycle are clearly specified for alert and trip setpoints, as well as actions for "off-normal" equipment performance such as fluid pulsations, flow mismatches, pressure pulsations, valve hunting, effective control of the feedwater 3 weeks post system, sensitivity of 80P to various DRP with NRR licensee instrumentation or control transients, etc.
concurrence completion 27.
Assess management readiness for restart and ensure viable self-assessment program in place to fix as Week of well as find problems.
RA/RP 10/3/94 28.
Provide various Congressmen with information When info.
previously requested.
provided and associated reviews NRR completed i
NRC inspection of pre-start up activities completed.
DRP 10/01/94 30.
NRC inspection of start t? activities completed.
1 DRP 10/15/94 31.
NRC inspection of power ascension activities
., completed.
DRP 11/01/94
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O, FERMI 2 RESTART ACTION PLAN (Continuftd}
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-ISSVE NO.
REFERENCE INFORMATION FOR CLOSEOUT l.
Inspection Report 50-341/94003, c.
J, f.i 2.
Inspection Report 50-341/93029 (AIT report),
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A' 3.
Inspection Report 50-341/94004.
4.
Inspectior. Report 50-341/94006.
1 6.
Inspection Report 50-341/94008, 7.
Inspection Report 50-341/94007.
g, 8.
Inspection Report 50-341/94007.
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i gg November 8,1994 wl v k;.y b(
The Detroit Edison Cornpany ATTN:. Mr. D. R.'Gipson
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7 Senior Vice President i
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. 5, ENuclear Generation l
6400 North Dixie Highway i
D Newp' ort, MI '_48168 ' '
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Dear Mr. Gipson:
This refers to the routine safety inspection conducted by Messrs. A. Vogel, Y,
K. Riemer, and others of this office from September 9 through October 21,1994. The inspection
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. included a review of activities at your Fermi 2 facility. ' At the conclusion of the inspection, the
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findings were discussed with th' se members of your staffidentified in the enclosed report.
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, Areas examined d' uring the inspection are identified in the report. Within these areas, the inspection consisted of a selective examination of procedures and representative records,
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ob,se,rvation.s,' and i.nterviews with personnel.L O
. During this inspection, we identified an unresolved item conceming a surveillance procedure that f,,,
established a pathway to drain water from the reactor pressure vessel to the forus sump. Of 79 (particular concem to the NRC was the failure of the operators to recognize the drain pathway g
. created by the surveillance.- Given the inconsistent operator performance noted during this and the previous inspection period, raanagement action is needed to assure that operations is adequately prepared to restart and operate the facility.
In accordance with 10 CFR 2.790 of the Commission's regulations, a copy of this letter'and the
'y enclosed inspec; ion report wi!! be placed in the NRC Public Document Room, w
7, We will gladly discuss any questions you have conceming this inspection.
Sincerely, t
I Original signed by Edward G. Greenman, Director Edward G Greenman, Director l
Division of Reactor Projects Docket No. 50 341 cl License No. NPF-43
Enclosure:
Inspection Report No. 50-341/94013 (DRP)
See Attached Distribution t
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The Detroit Edison Company 2
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6 Distribution:
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J. Conen, Principal l
Compliance Engineer
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P. A.' Marquardt, Corporate f-Legal Department. l James R.'Padgett, Michigan Public l
' Service Commission Michigan Department of
~ Public Health Monroe County Office of j
Civil Preparedness e
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U.S. NUCLEAR REGULATORY COMMISSION REGION 111 Report No. 50-341/94013 (DRP)
Docket No. 50-341 License Nos. NPF-43
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Licensee: Detroit Edison Company 7
2000 Second Avenue
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Detroit, MI' 48226 Facility Name: Fermi 2 3;
Inspection At: Fermi Site, Newport, Michigan inspection Conducted: September 9 through October 21,1994 Inspectors: A. Vegel K. Riemer 5
J. Neister C. Harper
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M. Bielby y.
D. Roth -
Approved By: Oriainal Sianed by-11/03/94 M. P. Phillips, Chief Date Reactor Projects Section 2B
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inspection Summarv
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Inspection from September 9 throuah October 21.1994 E
(Report No. 50-341/94013(DRP))
Areas inspected: Routine, unannounced safety inspection of operational safety verification, J
engineered safety features systems, onsite event followup, current material condition and general
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housekeeping, plant support activities, startup issues, maintenance activities, surveillance g,
activities, and engineering.
.cm Results: Of the 11 areas inspected, one unresolved item was identified pertaining to evolutions with the potential to drain the reactor pressure vessel (paragraph S.b).
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The following is a summary of the licensee's strengths and weaknesses during this inspection period:
1 Plant Ooerations Operations performance this inspection period was mixed. The operator's timely identification f,
and proactive response to a degrading condition of the "B" Reactor Water Cleanup Pump and identification of an incorrectly positioned knife switch was indicative of good operator performance. Conversely, operator performance was poor in failing to identify a pathway to drain the reactor vesselintroduced by a surveillance test; emergency diesel generator (EDG) No.11 standby luba oil pump problems; failure to address the trip of a control rod drive pump during a ha
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p4 routine evolution, and operators acceptance oflow, out of sight oillevels in several general i
l service water pumps. These actions demonstrated inattention to plant conditions and a lack of a questioning attitude by operators.
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L Maintenance inadequate post maintenance restoration associated with work on the turbine main tube oil system resulted in'a' spill of approximately 150 gallons of oil. A lack of attention to detail by l&C
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technicians contributed to a loss of reactorwaterinventory during the performance of a i
surveillance procedure.
l Plant Suocort
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Radiation protection personnelidentified and responded promptly to two deliveries of radioactive material with inappropriate shipping conditions. Severalinstances of radiological boundary control problems were identified by the inspectors. Radiation Protection response was prompt j
and corrective actions were effective. A security perimeter walkdown was conducted with no deficiencies identified.
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Engineering support of outage activities was good. However, weak engineenng review of several surveillance procedures resulted in equipment not being restored to normal following testing.
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DETAILS 1.
Persons Contacted Detro:t Edison Comoany 7S. Booker,'Ma ager, Startup iB. Britt', Maintenance
- L; Collin', Electrical Supervisor, Plant Engineering s
' ?W. Colonnello,' Director, Safety Engineering"
- J.'Conen, Supervisor, Licensing * ' ' M ~ '
- J. Coritoni, Supervisor, Plant Engineerin
.*J. Crews 7 Executive Consultant' '" '" g
- 'D. Delong, Maintenance :
~ *R. Delong, Superintendent, Radiation Protection
~T, Dong, Supervisor NSSS, Technical Engineering
- R. Eberhardt, Assistant to Pla'nt Manager
- P. Fessler,' Plant Manager,~ Operations
- R. Fitzsimmons, Supervisor,' Nuc! ear Security
- L.' Fron, Director Turbine / Projects. Technical Engineering
- D. Gipson,' Senior Vice President, Nuclear Generation
-L'. Goodman, Director, Licensing : " ' ' '
- E. Hare, Senior Compliance Engineer
< *R. Haupt, Acting Supervisor l&C' Plant Engineering
- K. Howard, Supervisor Mechanical and Civil. Piant Engineering
- J. Malaric, Supervisor Modifications,' Technical Engineering
- R. McKeon, Assistant Vice President / Manager, Operations
- *D. Noetzel, Supervisor, Maintenance
'J. Nolloth, Superintendent, Maintenance
- D. Nordquist, Director, NQA-
- P. Ockerman, DNT, Nuclear Training
- J. Pendergast, Compliance, Licensing
- S. Peterman, NSS, Operations
- D. Pettinari, Outage Coordinator
'G. Pierce, Supervisor, Work Control
- J. Plont., Superintendent Operations
- D.' Powel, Operations Engineer, Operations
- W. Romberg,' Assistant Vice President and Manager, Technical
- J. Sahli, Supervisor, Simulator Training
- L. Schuerman, Engineer
- R. Stafford, Manager, Nuclear Assurance
'G. Teribery, NSO, Operations
- W. Tucker, Assistant to Technical Manager
- E. Vinsco, General Supervisor l&C, Maintenance
'B. Wood, Supervisor I&C, Maintenance
- Denotes those attending the exit interview conducted on i
October 21,1994.
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9 The inspectors also had discussions with other licensee employees, including members of the technical and engineering staffs, reactor and auxiliary operators, shift supervisors, and electrical, mechanical and instrument maintenance personnel, and security personnel.
2.
Plant Operations Fermi 2 remained in cold shutdown for the inspection period due to the extensive outage activitics required as a result of the December 25,1993, turbine generator failure. During the inspection period, the licensee continued with activities associated with the plant's fourth refueling outage. On October 18,1994, refueling of the reactor was completed. At the end of the inspection period reactor reassembly and balance of plant system restoration were in progress.
2.1 Operational Safety Verification (71707)
The inspectors verified that the facility was being operated in conformance with license and regulatory requirements, and that the licensee's management was effective in ensuring safe operation of the plant. On a sampling basis, the inspectors verified proper control room staffing and coordination of plant activities; verified operator adherence with procedures and technical specifications; monitored control room indications for abnormalities; verified that electrical power was available; and observed the frequency of plant and control room visits by station management. The inspectors reviewed applicable logs and conducted discussions with control room operators throughout the inspection period.'
The inspectors observed a number of control room shift tumovers. The tumovers were conducted in a professional manner and included log reviews, panel walkdowns, discussions of maintenance and surveillance activities in progress or planned, and associated LCO time restraints, as applicable.
During the inspection period, the inspectors made several observations conceming operator performanem. Overall, the inspectors concluded that operator performance was mixed, based on tht,,ollowing observations:
2.1.1 Inadeouate Response to Control Rod Drive (CRD) Pump Trio: On September 14, the "A" CRD pump tripped when a full scram was inserted. The inspector discussed the event with the Nuclear Shift Supervisor (NSS), and was informed that a DER was not written because the trip was not an unusual occurrence. Further investigation by the inspectors and discussions with licensee personnel indicated that the event was not an expected occurrence. The inspectors also determined that the A" CRO Pump had tripped on several other occasions during the outage without a DER being generated to document the occurrence. The licensee subsequentlyinitiated DER 94-0479 on September 20 to investigate the pump trip and assign corrective actions. Since the control rod drive pump is not a safety related component, the requirements of 10 CFR Part 50, Appendix B do not apply.
2.1.2 Failure to identify Potential to Drain Water From Reactor Vessel Durina a Surveil lance:
On October 7, while performing surveillance procedure 44.010.061, " Functional Test of 4
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the SCRAM Test Switches and Backup SCRAM Valve Operation," control room operators received the reactor building torus sump level high-high alarm (reference paragraph 4
5.b.1).' The operators were not fully aware of the procedure's impact on plant conditions in that they did not realize that the procedure established a drain pathway from the reactor vessel to the torus sump.
2.1.0 Failure to Respond to Steo Chance Drop in Lube Oil Temoerature: On October 9,1994, operators in the main control room received the Division i Emergency Diesel Generator (EDG) No.11 Lube Oil High/ Low Temperature Alarm. A non-licensed operator
~
discovered that the standby lube oil pump was not running, even though the switch was in AUTO. The op'erator placed the switch in HAND and the temperature of the tube oil began to rise ' A work request was submitted to allow l&C technicians to troubleshoot the circuit and no problems were found. The switch was placed in AUTO and the pump subsequently worked properly. Further investigation by the inspectors determined that the tube oil temperature, as logged on a daily basis'during the evening shift, consistently read between 136' and 140* fahrenheit.~ However, on October 8, the tube oil temperature was logged as 114 degrees fahrenheit, a step change down of approximately i
16 percent. Even with the step change, the operators did not question the cause or investigate the status of the diesel until the control room operators received the alarm during the following shift. Additionally, until questioned by the inspector, a DER was not initiated to document a potentially generic EDG materialissue.
2.1.4 Failure to Ensure Adecuate Oil Level for Pumos: On October 11, the inspectors toured the General Service Water (GSW) Pump House and identified that the GSW Pump No. 6 motor oil sight glass indicated no visible oillevel. Another of the GSW pumps also indicated a low oil level. The inspector discussed the observation with licensee management and operators were subsequently dispatched to check the oillevel of the pumps. The following moming, the inspectors again toured the GSW Pump House with the Maintenance Superintendent and Assistant Vice President and Managur, Operations.
The No. 6 GSW oil sight glass still appeared empty indicating no effort to refill the oil since observation of the empty sight glass the previous day. Further review of the motor by the licensee indicated that the condition was indeed unacceptacle and the licensee initiated actions to resolve the matter.
2.1.5 Quick identification of Potential for Damaoe to a Pomo: On October 11, a control room operator noticed an increase in the pump / motor amps for the 8" Reactor Water Cleanup (RWCU) Pump. The control room operator directed a non-licensed operator to investigate the physical status of the pump. The control room operator monitored the pump's indication and, as its amperage continued to increase, tripped the pump and throttled down RWCU flow so as not to adversely impact the "A" RWCU Pump. The operator, dispatched to investigate the status of the pump, not;ced smoke coming from the speed reducer and a melted gasket on the motor end of the pump. The licensee initiated DER 94-0544 to document the occurrence and at the end of the inspection period was in the process of troubleshooting the cause of the pump failure.
2.1.6 Attention to DetailIdentifies Mis Positioned Switch: Also on October 11, a non-licensed operator performing rounds noticed a cover removed from a knife switch located in the Division 11 Switchgear Room and noted that the switch was in the OPEN position. He reported his observation to the Main Control Room. Further investigation revealed that the switch was left in the OPEN position due to a recently performed surveillance 5
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procedure. The surveillance procedure did not restore the switch to its normal position.
A preliminary determination by the licensee indicated that the misp ositioned switch had 4
no adverse Technical Specification ramifications. The licensee inhiated DER 94 0543 to e
g investigate the issue.
The inspectors were concemed because the first four examples above, taken collectively, 4
2 indicated a lack of a questioning attitude and demonstrated an inadequate appreciation for acceptable levels of equipment material condition on the part of operations personnel.
i These examples are similar in nature to other examples of a lack of attention to detail on the part of operators described in Inspection Report No. 50-341/94011. The operators' actions as documented in the last two examples above demonstrated aggressive, proactive responses and a good questioning attitude to abnormal conditions. Further t
management emphasis appears warranted to ensure consistently good operator 1
performance' o
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2.2 Enaineered Safety Feature (ESF) Systems (71710)
During the inspection, the inspectors selected accessible portions of several ESF systems to verify status. Consideration was given to the plant mode, applicable Technical Specifications, Limiting Conditions for Operation requirements, and other applicable requirements.
i Through observation, the inspectors verified that the fo!!owing was acceptable:
installation of hangers and supports; housekeeping; freeze protection,if required, was installed and operational; valve position and conditions; no potentialignition sources; and major component labeling, lubrication, cooling, etc. The inspectors also verified that instrumentation was properly installed and functioning and that significant process i
parameter values were consistent with expected values; that instrumentation was calibrated; that necessary *,upport systems were operational; and that locally and remotely indicated breaker and valve positions agreed.
1 F
During the inspection, the accessible portions of the following ESF systems were walked
(
down:
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Division I and 11 Emergency Diesel Generators e
Division I and il Residual Heat Removal System e
i 2.2.1 Failure to identify and initiate Corrective Actions for Oil Leaks Durino Operator Rounds:
During a walkdown of the emergency diesel generators (EDGs) Nos.11 and 12, inspectors observed that lubricating oil had been leaking from each of the diesel engines and accumulating in puddles on the floor beneath the engines. One source of the oil leaks on EDG No.11 appeared to be a crack on a weld that joined the lubricating oil fill pipe to the engine lubricating oil sump. Following ths inspectors' identification of the source of the leaks, the licensee performed a nondestructive examination (NDE) on the weld using the liquid penetrant NDE method. The nondestructive examination revealed a linearindication about one-fourth inch long at the bcttom of the pipe weld. Further examination determined that the indication resulted frcm a line of pinhole porosity bleeding together to form a linearindication. Penetrant efficiency was impeded by active oilleakage through the weld.
6
On EDG No.12, the inspectors observed oilleaking from a hole in the side of the lubricating oil sump. The hole was located five to six inches from the bottom of the sump.
Licensee NDE results indicated an approximately one-fourth inch depression in the side of the sump. Porosity from a weld repair during the manufacturing process provided a leakage path thorough the oil sump ray plate.
Based upon the results of the NDE of the leakage paths and the small amount of oil leaking from the holes, the licensee concluded that no immediate corrective action was warranted. However, the failure of the licensee staff to identify the source of the leaks indicated a lack of attention to detail and a questioning attitude on the part of operators performing inspection rounds. The licensee issued DER 94-0532 to document the oil sump leaks. The inspectors will continue to monitor the leaks during future routine EDG walkdowns.
2.2.2 Emeroency Diesel Generator No.12 Failed to Start: On September 17,1994. Emergency Diesel Generator (EDG) No.12 failed to start during testing during two successive start
' attempts. The licensee's investigation determined that the diesel was apparently not getting sufficient fuel to support ignition. Cause of the failure was traced to a faulty govemor actuator and/or actuator booster. The govemor actuator and servo booster were replaced. The EDG was started several times after the actuator and servo booster
- were replaced. Based on the inspectors' review of troubleshooting efforts and discussions with cognizant system engineers, licensee actions were thorough.
2.3 Onsite Event Follow-vo (93702)
During the inspection period, the licensee experienced several events, some of which required prompt notification of the NRC pursuant to 10 CFR 50.72. The inspectors pursued the events onsite with licensee and/or other NRC officials. In each case, the inspectors verified that any required notification was correct and timely. The inspectors also verified that the licensee initiated prompt and appropriate actions. The specific events were as follows:
2.3.1 Packaae Shioment to Site in Excess of Radiation Limits: On September 9 and 16,1994, during package receipt radiation surveys by licensee radiation protection technicians, the i
extemal package on contact readings were in excess of Department of Transportation I
(DOT) requirements. The packages, containing compacted low-level radioactive waste, were received from Scientific Ecology Corporation. The survey results indicated up to 350 mrem per hour dose rates on top of the packages once the wooden cribbing was removed.10 CFR Part 71.47 requires that packages be prepared for shipment so that i
radiation levels do not exceed 200 mrem per hour at any point on the extemal surface of the package. The licensee took immediate corrective actions and reported the event to the delivery carrier and the Region til office in accordance with 10 CFR 20.1906.
2.3.2 Unexpected Trio of Diesel Outout Breaker: On September 27,1994, at 1:55 p.m., the output breaker for Emergency Diesel Generator (EDG)
No.14 unexpectedly tripped while the engine was operating at approximately 1500 kw.
At that time, the engine load had been reducsd for normal shutdown following surveillance testing The plant was in Operating Condition 5, Refueling, with no core alterations or handling ofirtadiated fuelin progress. Emergency Diesel Generator No.14 is one of two Division ll emergency diesels. The other Division 11 diesel (EDG 13) was 7
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n
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r' available in the standby lineup although it was inoperable pending completion of surveillance testing which later proved to be satisfactory.
At the time of this event both Division I diesels were also considered inoperable pending completion of surveillance testing (which was subsequently completed with satisfactory results), although EDG No.- 11 was available in its standby lineup. EDG No.12 was out of service for corrective maintenance and wa's'not available.
With a Division i EDG out of service (EDG 12), the unexpected trip of the EDG 14 output breaker was considered, by the licensee, to be an event which alone.could have potentially prevented the fulfillment of a safety function of systems needed to mitigate the consequences of an accident. At 5:14 p.m., the licenses notified the NRC Operations Center of the event via the Emergency Notification System.
2.4 Current Material Condition. General Housekeepino and Foreion Material Exclusion (FME) i Controls (71707 and Ti 2515/125)
The inspectors performed general plant as well as selected system and component walkdowns to assess the general and specific material condition of the plant, to verify that work requests had been initiated for identified equipment problems, and to evaluate housekeeping. Walkdowns included an assessment of the buildings, components, and systems for proper identification and tagging, accessibility, fire and security door integrity, scaffolding, radiological controls, and any unusual conditions. The inspectors monitored the status of housekeeping and plant cleanliness for fire protection and protection of safety-related equipment from intrusion of foreign matter.
The inspectors identified several examples of housekeeping deficiencies during the
~
performance of routine plant tours. Examples included used oily rags on the floor in the 1
turbine oil reservoir room and tools stored on off-gas valve handwheels. Of particular j
concem to the inspectors were the lack of foreign material exclusion controls to the torus suppression pool. The inspector observed an open access to the north and south torus I
suppression pool without accountability being maintained. Revie'w of Primary Containment Procedure 23.425.01, revision 19. for entry and close out of the suppression pool, provided no instructions for temporary closure of the torus to prevent foreign material entry. The openings provided a potential path for debris to enter the torus suppression pool. Foreign materialin the suppression pool could lead to emergency core cooling system (ECCS) strainer clogging. The inspector observed anti contamination clothinq and other loose articles on the floor immediately adjacent to the first floor torus opening. Detection of debris in the suppression pool would be very difficult due to the l
lack of clarity of the suppression poolwater. In addition, the inspectors noted that, i
periodically, foreign material exclusion control was lax on the turbine floor. The inspectors discussed all housekeeping concerns with on shift management personnel and verified that the items were corrected in a timely manner. Further licensee attention was warranted to improve housekeeping and plant cleanliness prior to plant startup and to preclude questionable foreign material exclusion practices from negatively impacting plant operations. The inspectors will review the licensee's FME controls program and the adequacy of torus water cleanliness in a future repod.
l On October 7, the inspectors toured the Auxiliary Building, a radiologically restricted area, l
and observed magazines and newspapers as well as fresh cigarette butts stashed in 8
i i
f.
several secluded locations. The inspectors discussed their observations with licensee supervision. Subsequent to the inspectors' observations, licensee quality assurance personnel discovered additional evidence of smoking and eating (cigarette butts and candy wrappers)in the same building. The inspectors will continue to follow this item and assess licensee corrective actions during future inspections.
On October 11, the inspectors toured the General Service Water (GSW) Pump House including the Diesel Fire Pump Room. The inspectors noted several material condition deficiencies as well as poor ' general area housekeeping. For example, one of the GSW pumps showed no visible oilin the sight glass (see Section 2.1 above). In addition to the GSW pumps, the inspectors identified several deficiencies associated with the diesel driven fire pump such as a partially clogged inlet air filter, a coolant leak, and an oily type
{
substance covering the engine's altemator. The inspectors toured the area again the next day with the Assistant Vice President and Manager, Operations and the l
Maintenance Superintendent to discuss the above observations. Of particular concem n
was the failure of the licensee to improve the poor housekeeping conditions of the GSW pump house following identification of similar deficiencies by NRC inspectors and
. licensee Quality Assurance _ inspectors on August 18,1994. Inspection report No. 50-341/94011 documented deficiencies previously identified in the GSW pump house. One deficiency previously identified by the inspectors as a material condition problem, missing bolts on the diesel driven fire pump, was subsequently dispositioned as not required by the licensee. The inspectors will continue to follow licensee efforts and corrective actions i
associated with maintenance of material condition and housekeeping of the GSW pump I
house during future inspections.
No violations or deviations were identified.
3.
Startuo issues Following the December 25,1993, turbine generator event, the NRC compibd a listing of items that required completion prior to unit restart. The updated NRC "Femti 2 Restart Action Plan"is provided as an attachment to this report. The following are 13 sues reviewed by the inspectors:
3.1 Restart Issue No. 5 (Closed): Evaluate damaae to oenerator neutral bus to aroundino transformer. During the turbine / generator event, the bus was bumed, insulators damaged and duct melted. The licensee has completed evaluations that concluded the neutral bus damage was a result of the turbine / generator event and not a contributor to the event. The inspector concurs with the licensee's conclusion. The inspector examined the reinsta!!ation of the neutral bus prior to closure of the bus duct. The old bus had been refurbished, new insulators installed and new ductwork fabricated. This issue is closed.
3.2 Restart issue No. 9 (Closed): Verify operational readiness of flooded radioactive waste handlino eauipment. Based on review of cleanup and test documentation, interviews with cognizant plant personnel, and visualinspection of the flooded radioactive waste handling equipment, the inspector verified that the radioactive waste equipment flooded as a result of the December 25,1993 event was operationally ready. Electrical and instrumentation components had been cleaned, dried, tested and replaced as necessary. Pump and valve packing had been inspected and replaced where needed. Much of the equipment 9
Z s
was in service and satisfactorily performing its design function during the visual inspection. This issue is closed.
3.3 Restart issue No. 27: Assess the licensee's staff readiness for power operations. The inspectors reviewed preparations by the Operations Department for transition from a Shutdown to Operating mode of plant operation. Classroom and simulator training were observed, and the status of operation's procedure changes was reviewed.
3.3.1 Classroom Lectures: The inspectors observed three classroom lectures on plant modifications made during the corrent outage. System engineers conducted the lectures.
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Licensed and non licensed operators,' operations management, and training personnel were in attendance. The system engineers did a good job of presenting the material and answering questions. However, none of the system engineers listed leaming objectives or appeared to use prepared lesson plans covering course objectives during the lectures.
In addition, the instructors did not question the operators to assess effectiveness'of the training.
Followup discussions with the system engineers indicated that the same basic material had originally been presented during the previous training cycle. Lesson plans and handouts had been prepared, reviewed by the' training staff and utilized during those presentations. The current training cycle lectures were being given a second time to the same operators and were intended to be a review to inform operators of any revisions to the modifications and to reinforce the previous material.
The inspectors concluded that the training was gcod, however, the training staff missed an opportunity to reinforce lesson plan learning objectives. Additionally they did not evaluate the effectiveness of the previous lecture by asi.ing questions of the operators prior to starting review training sessions.
3.3.2 Simulator Instn;ction The inspectors observed an operating crew perform a star.
from cold plant through turbine synchronization on the simulator. During perfomtance of a required surveillance on the Rod Worth Minimizer (RWM), the crew identified an actualincorrect immediate action step in the plant Alarm Response Procedure (ARP) for verifying the status of alarm window 117. The shift technical advisor (STA) verified the correct status of the alarm window and submitted a procedure change. After pulling rods to establish criticality, time compression was used to advance through redundant parts of the scenario. Conductivity alarms were initiated by the instructor when feedwater flow was established. After the crew took immediate ARP actions the simulator was stopped in time and the instructor led the crew in a discussion of when high conductivity could be expected during the actual plant startup, as well as where it would likely come from. The plant's four action levels based on conductivity were also discussed.
The inspectors observed that the instructor missed an opportunity to evaluate the crew and individuals when he led the discussion instead of asking probing questions of the
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crew and/or individuals to determine their knowledge of the subject.
l The inspectors also observed a crew evaluation during performance of an Emergency Operating Procedure (EOP) scenario on the simulator. The scenario was challenging.
10
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r The operating crew demonstrated good teamwork and generally good communications w.'th minor exceptions.
3.3.3 Simulator Outaoe Modifications The inspectors reviewed the status of simulator hardware and software changes as a result of plant modifications. A majority of the significant simulator changes appear to have been incorporated with the exception of the High Pressure Core Injection (HPCI) flow and pressure control and the static exciter modifications.
3.3.4 Operations Procedure Chanoes The inspectors reviewed the status of required Operations procedure changes as a result of plant modifications. The inspectors noted that 35 modifications were affecting a total of approximately 68 system operating and alarm response procedures. Informal interviews of operators on shift indicated that most were aware of the plant modifications and their effect on system and plant operation; however, training of crews and operators for plant startup and power operation was limited since the operations procedures did not have the actual changes incorporated.
Based on the inspectors observations, the training provided to the operations staff was good. However, the training staff did not appear to be aggressively evaluating the effectiveness of the training to assess if the operating crews understood the training and were ready to start up the plant. The inspectors also noted that a number of procedures still needed updating due to numerous plant modifications performed during the outage.
The inspectors will review licensee training on modified procedures in a future inspection prior to plant startup. This restart item remains open.
3.4 Restart issue No. 26: Cable pullinadecuacies. As documented in NRC inspection report No. 50-341/94012, inspectors identified that cables were puUed without proper tension monitoring devices. The potential existed that cables in safety related applications may have been damaged during installation. Pentiing assessment oflicensee evaluation of the acceptability of the cables, a new restart item was opened.
4.
Safety Assessment / Quality Verification (40500 and 92700) 4.1 Deviathn Event Reports Followup: During the inspection period, the inspector reviewed the licensee's Deviation Event Reports (DERs). This was done in an effort to monitor the conditions related to plant or personnel performance, potential trends, etc. DERs were also reviewed to ensure that they were generated appropriately and dispositioned in a manner consistent with the applicable procedures.
During the inspection period, the inspectors reviewed various events and then reviewed the occurrences against the licensee's corrective action program criteria for documenting adverse conditions via a DER. The inspectors identified several examples where a DER appeared warranted but was not written until the inspectors questioned licensee personnel about the issue. Examples included the CRO pump trip and EDG 11 standby tube oil pump failures (reference sections 2.1.1 and 2.1.3). The timeliness and communication of DERs at times was also weak. For example, on September 11, incorrect material was issued to personnel in the plant. Maintenance personnel received 11
,p 4,
a cleaning solution that was labeled "TF, cleanirig solution, FREON." However, upon use in the field the material smelled like alcohol. Furtherinvestigation revealed that the
.7 original source for the cleaning solution was labelled "High!y Flammable"(freon is non-flammable) and it was issued for work on energized / hot equipment creating a potentially serious personnel hazard. A DER was not written for three days, and licensee senior management was not aware of the issue untilinformed by the resident inspectors. The inspectors discussed their concerns with licensee senior management and will continue
.i to review this issue to assess whether DERs are appropriately initiated.
.c 4.2 Personnel Performance Council On September 12,1994, the Senior Resident inspector attended a meeting of the licensee's Personnel Performanco Council. The purpose of the council was to minimize the amount and severity of personnel errors that have a negative impact on the performance of the Nuclear Generation Organization. The council, made up of individuals from various plant organizations, monitored personnel performance and developed strategies to improve performance. The inspector noted that during the course of the meeting interaction between members was open and dynamic. The effectiveness of the council to decrease personnel errors will be assessed based on continued inspector observa' ion of plant activities and evaluation of events.
4.3 Shutdown Risk imoact On September 27,1994, both divisions of EDGs were declared inoperable following the unexpected trip of the EDG No.14 output breaker. The event description is discussed in paragraph 2.3.2 of this report. On September 28, an inspector attended the daily licensee outage management meeting and noted that the. impact on shutdown risk due to i-"
the unavailability of both divisions of EDGs was not discussed. 'In addition, the licensee's daily status report was incorrect in that EDG No.14 was listed as available. The x.
inspector was concemed that the impact oflosing the availability of two of four onsite power sources and the impact on shutdown risk was not clearly communicated to the licensee staff. The inspector discussed the concem with the Plant Manager and the Senior Vice President Nuclear Generation. During subsequent outage management meetings, the inspectors noted that detailed and accurate shutdown risk status reports were presented.
No violations or hviations were ide.ntified.
5.
Maintenance (62703 & 61726) 5.1 Maintenance Activities (62703)
Selected station maintenance activities were observed and reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides.wnd industry codes or standards, and in conformance with technical specifications. The following items were also considered during this review: limiting conditions for operation were met wh'..e components or systems were removed from service; approvals were obtained prior to initiating the work; functional testing and/or calibrations were performed prior to retuming components or systems to service; quality control records were maintained; and activities were accomplished by qualified personnel.
12 1
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i; Portions of the following maintenance activities were observed or reviewed:
l e
Main Turbine Repairs / Restoration
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e Static Exciter installation i
Reactor Feed Pump Turbine Repairs e
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e Static Exciter Replacement Replacement of Standby Liquid Control Discharge Pressure Gauge e
With the exceptions noted below, the maintenance activities were accomplished acceptably.
)
5.1.1
!nappropriate Use of Mixed Compression Tube Fittinas: On September 14,1994, while l
conducting a routine tour of the reactor building, the inspectors noted that on Panel H21 P481, components on a compression tube fitting were htercnanged with those of another manufacturer. Specifically, the tube fitting body and an mociated nut were manufactured by different vendors. This questionably configured compression fitting was installed upstream of the Standby Liquid Control (SLC) Pump Discharge Pressure Gauge (C41 R003). The inspector discussed the observation of the mixed compression fitting with the licensee. Subsequently, on September 15, Deviation Event Report 94-0468 was initiated to document the deficiency and track corrective actions. In addition. Work Request 000Z946717 was initiated to correct the mismatch. On September 16 the mismatched fitting problem was corrected.
As discussed in NRC Information Notice 92-15, " Failure of Primary System Compression Fittings," the interchanging of hardware from different manufacturers was one of the problems that might impact the effectiveness of the compression fit. Due to previous incidents at Fermi 2 involving compression fitting failures on reactor water cleanup instrument line in May and July of 1989, the licensee was cognizant of the potential problems that could result from improper compression fitting installation.
Based on discussions with the licensee, the incorrectly configured compression fitting was worked on August 11,1994, during performance of Work Request 000Z944938.
During performance of the job task, which involved removing one of the nuts on the "T" fitting, the workers failed to recognize that mismatched components were installed.
Specifically, one of the nuts not worked was mismatched. The failure of technicians to identify that the compression fitting was not configured in accordance with procedural requirements indicates a lack of attention to detail and a lack of knowledge concerning proper compression fitting installation. On October 21, inspectors identified additional examples of improperly configured fittings installed on air lines to reactor feed pump cooler temperature control valves. Further management attention appears warranted to ensure maintenance personnel are adequately trained to ensure that compression fittings are properiy installed.
f 5.1.2 Main Turbine Lube Oil Leak i
On September 16,1994, after starting the Min Turbine Lube Oil flush, the discharge flange on the North Main Lube Oil Pump leaked because several flange bolts were missing and other nuts were not adequately torqued. Approximately 150 gallons of tube oil sprayed the second floor Turbine Building Lube Oil Room. Upon initiation of the leak, the pump was immediately secured and cleanup was commenced. No significant 13 b
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,A equipment damage occurred as a result of the leak. The flange had not been restored adequately following maintenance due to inadequate maintenance procedures and a lack of attention to detail during maintenance restoration. As part of corrective actions for this event, the licensee established a pretest and tumover team to assure that systems were ready for testing or tumover to operations. The inspectors will continue to monitor licensee efforts in this area during observation of system restorations as the licensee prepares for plant restart.
q 5.2 Surveillance Activities (61726) 1 During the inspection period, the inspectors observed technical specification required y
surveillance testing and verified that testing was performed in accordance with adequate M
procedures, that test instrumentation was calibrated, that results conformed with technical specifications and Z
procedure requirements and were reviewed, and that any deficiencies identified during the testing ivere properly resolved.
N The inspectors also witnessed or reviewed portions of the following surveillances:
a Emergency Diesel Generator No.13 LOOP /LOCA Test Reactor Protection System - Logic Function Test e
Emergency Diesel Generator No.14 Slow Start Surveillance e
p With the exception noted below, the surveillances were accomplished acceptably.
R 5.2.1 Reactor Cavity Drainino Evolution: On October 7, with the reactor partially refueled and the reactor cavity flooded, control room operators received the Reactor Building torus yi sump level High-High alarm during performance of surveillance Procedure 44.010.061,
]
Functional Test of the SCRAM Test Switches and Backup SCRAM Valve Operation."
Per the surveillance procedure, the following conditions were established: The scram diccharge volume vent and drain valves were opened as a result of pulling their fuses, and a full scram was inserted. These actions resulted in a pathway being created for water to go from the reactor vessel to the torus sump via the control rod drives.
Operators subsequently recognized the pathway and had the fuses reinstalled, closing the vent and drain valves and stopping the leak. Several hundred gallons of water were i
loct from the reactor cavity. Radiological protection personnel responded to a spillin the
/
torus room when the sump overflowed. The sump overflow occurred because the torus v
sump pumps didn't pump as a result of their logic not being reset following the
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performance of a prior surveillance procedure. At the time of the performance of the surveillance, all four emergency diesel generators (EDG) were technically inoperable.
c Technical Specification (TS) 3.8.1.2 requires that for the mode the plant was in at the time, no evolutions be performed with the potential to drain the reactor pressure vessel (RPV). The operators were not aware that conduct of the surveillance would cause a loss of water inventory from the reactor vessel.
The licensee established a team to investigate the event and determine corrective
/
actions. By memo dated October 12,1994, the team concluded that the event was not an evolution with the potential to drain the RPV; however, the team concluded that the procedure was inadequate in that it contained no wamings to the operator about the flow pnh created. Laterin the day, after the Licensing and Operations departments concurred 14
6 that the evolution did not constitute a potential for draining the RPV, the surveillance was 6
re-performed. On October 13, the EDGs were declared operable and the LCO action
- l statement for TS 3.8.1.2 was exited.
The inspectors reviewed the licensee's evaluation and conclusions with respect to the event and identified that the investigation was not adequate in that it did not address a prior similar occurrence on November 26,1985. As documented in DER NP 85-0625, the same fuses were pulled and a manual scram inserted which resulted in a 30 inch l
decrease in reactor water level. DER NP 85-0625 stated that an "open drain path was created from the reactor vessel to the torus sump." To preclude repetition, the licensee installed placards on the relay cabinet doors which stated, in part, that removal of the 1
fuses,"may result in draining of the RFV via the scram discharge volume drain valves if a
[
scram signalis present. ' Prior to removal of any of these fuses specific permission must be obtained from the NSS." The licensee's evaluation of the October 1994 event did not
' incorporate any of the lessons leamed from the past event, and the licensee concluded
-!(
that this event did not constitute an evolution with the potential to drain the RPV. After
,yq the inspectors pointed out the lessons leamed from the 1985 event, the licensee team d*
performed another analysis and concluded, via memo dated October 14, that the event still did not constitute an evolution with the potential to drain the RPV. Their analysis n
made reference to severalindustry interpretations discussing " operations with the potential for draining the reactor vessel." included were positions taken by the Boiling
.(,
Water Reactor Owners Group, General Electric, Grand Gulf, River Bend, and the Fermi 2 y
"RFO4 Refueling Outage A
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Plan Safety Review." Of these interpretations, three would conclude that the Fermi event i
would not be an event that violated technical specifications, and two would conclude that
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it was, j,
The inspectors had the following additional concems relative to the event:
The potential safety significance of the event could have been greaterif different l
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3 initial conditions had been in effect.
g 4
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The surveillance procedures used were inadequate: The previous EDG LOOP /LOCA surveillance left the torus sump pumps inoperable and the event
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surveillance procedure did not contain any wamings or precautions about the drain path created.
The operators were not aware of the procedure's impact on RPV level; specifically, operators were not aware that the surveillance established a drain path from the reactor to the torus sumps.
The l&C technicians' attention to detail was poor in that the placard containing the F
e warning of the reactor drain path was not noticed nor observed prior to performing the surveillance and pulling the fuses.
e The operators were not aware that torus sump pumps were not available prior to 3.-
performance of the surveillance; (i.e., configuration control was poor).
e The post event analysis was weak in that the prior occurrence was missed and l
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..'h the I&C technicians were not interviewed until one week later (the team's formal A
conclusions were reached and the surveillance reperformed prior to the time the
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technicians were interviewed).
j The corrective actions taken after the event documented in a previous DER did e
not prevent recurrence.
The surveillance was re. performed on September 12, without procedure changes being incorporated to address the concems raised with respect to the drain path created f om the RPV to the torus sump.
j While the inspectors acknowledged the licensee's positions following the event, they disagreed with the conclusion that the event did not constitute an evolution with the ootenti_al to drain the RPV. However, given the multiple interpretations that exist within i
the industry, this issue will be forwarded to NRR for evaluation and determination of a 7l-uniform definition. Pending NRR completion of that review, this is an Unreso!ved item
'l (341/94013-01(DRP)).
Y No violations or deviations were identified. One Unresolved item was identified.
4 6.
Enaineerina (37700) 6.1 Deteriorated Cables in Turbine Buildino Second Floor Steam Tunnel: The licensee identified numerous cables in Cable Tray OC-690 that had apparently deteriorated as a result of prolonged exposure to high temperatures. The licensee's continuing investigation has identified approximately 75 cables in the steam tunnel with jackets or Insulation that had deteriorated beyond acceptable limits. The corrective actions planned by the licensee were to replace the affected cables with cables rated at temperatures higher than the worst case temperature expected for that area.
There is no ventilation or temperature monitoring in the area where cable tray OC-690 was located. The licensee is evaluating installation of temperature monitors and ventilation in the area in addition to installing higher rated cables in the tray.
6.2 Damper Inocerability: During the inspection period, the licensee discovered a deficiency
.c M'
associated with fire dampers in the Control Center Heating, Ventilation and Air Conditioning (CCHVAC) and Reactor Building HVAC (RBHVAC) systems. The thermal expansion spacing requirements associated with the dampers were not property implemented in all cases, which resulted in the dampers' potential inoperability in the case of a fire. The keensee identified 88 dampers that required inspection to determine the acceptability of their installation. At the end of the inspection period the licensee was stillin the process of formulating corrective action (s) to resolve the issue. The inspectors will follow licensee corrective actions during future inspections.
No violations er deviations were identified.
7.
Plant Suooort (71750) 7.1 Radioloaical Controls 16
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J The inspectors verified that personnel were following health physics procedures for k
dosimetry, protective clothing, frisking, posting, etc., and randomly examined radiation U
protection instrumentation for use, operability, and calibration. However, areas of concem to the inspectors were personnel following health physics procedures for protective clothing and contamination control practices. The inspectors noticed the i
following:
F Tools, hoses, and anti contamination clothing not being contained within the e
k contamination boundaries in the sub basement of the RHR Division I pump room, and the third floor turbine building Overflowing used anti-contamination clothing bins on the first floor torus room e
entrance A contamination boundary sign adrift on the third floor turbine area, and access y
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boundary to the turbine building not being maintained.
Y P.
The inspectors ciscussed all radiation protection (RP) concems with on shJt RP supervision and verified that the items were corrected. Licensee RP management responded promptly to the inspectors concerns.
7.2 Security Each week during routine activities or tours, the inspectors monitored the licensee's security program to ensure that observed actions were being implemented according to
. the approved security plan. The inspectors noted that persons within the protected area
~ displayed proper photo-identification badges, and those individuals requiring escorts were property escorted. Additionally, the inspectors also observed that personnel and R
packages entering the protected area were searched by appropriate equipment or by y
~ hand.
q On September 27,1994, the inspectors conducted a walkdown of site security facilities F
with the licensee security manager. The walkdown included inspection of the protected V
area boundary, primary and secondary alarm stations and access control points. Based f.-
on inspectors observations, security equipment appeared to be in good material condition. The security force personnelwere alert and knowledgeable. No significant l'
deficiencies were identified.
}
No violations or deviations were identified.
8.
Reoort Review l
During the inspection period, the inspector reviewed the licensee's Monthly Operating Status Reports for August and September,1994. The inspector confirmed that the information provided met the requirements of Technical Specification 6.9.1.6 and Regulatory Guide 1.16.
The inspector also reviewed the licensee's Monthly Performance Report for August 1994 17 J
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y-i No violations or deviations were identified.
M 4
9.
Unresolved items Unresolved items are matters about which more information is required in order to g'
ascertain whether they are acceptable items, violations, or deviations. An unresolved l
item disclosed during the inspection is discussed in paragraph S.2.
/.
10.
Meetinas and Other Activities
.'j 10.1 Manaaement Meetinas (30702)
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On October 5 and 6,1994, Mr. J. Martin, Region lit, Regional Administrator; Mr. E.
Greenman, Director, Division of Reactor Projects: Mr. J. Hannon, Project Directorate, 2
Region IV; and others of the regional and headquarters staffs toured the Fermi plant and i
met with licensee management to discuss Fermi 2 restart efforts and the NRC's t
associated Restart Action Plan. The updated NRC "Formi 2 Restart Action Plan"is provided as an attachment to this report.
1 10.2 Exit Interview (30703)
The inspe: tors met with the licensee representatives denoted in paragraph 1 during the inspection period and at the conclusion of the inspection on October 21,1994. The
.1 inspectors summarized the scope and results of the inspection and discussed the likely i
content of this inspection report. The licensee acknowledged the information and did no!
indicate that any of the information disclosed during the inspection could be considered proprietary in nature.
.i 1
Attachment:
Fermi 2 Restart Action Plan
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L FERMI 2 RESTART ACTION PLAN (Revision 1)
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ISSUE RESPONSIBLE PROJECTED ORGANIZATION OR ACTUAL i
COMPLETE 1.
Evaluate acceptability of condensate storage tank Complete -
relaises to Lake Erie.
ORSS 03/30/94 2.
Evaluate plant activities to restore reactor coolant Complete -
system chemistry to acceptable conditions.
DRSS 02/07/94 i
3.
Assess adequacy of implementation of emergency plan Complete -
given AIT findings.
DRSS 03/18/94 4.
Assess adequacy of security plan implementation Complete -
given AIT findings.
DRSS 04/25/94 5.
Evaluate damage to neutral return line and Complete -
corrective actions taken to restore system.
DRS 11/08/94 6.
Evaluate adequacy of the licensee's actions to address the operator performance deficiencies Complete -
identified in the AIT report.
DRS 07/12/94 7.
Consolidate findings from AIT report and issue appropriate inspection followup items or violations.
Complete -
as appropriate.
DRP 06/15/94 Complete -
8.
Evaluate damage to generator and exciter.
ORP 06/15/94 9.
Inspect flooded radwaste handling equipment and DRP with ORS Complete -
verify operational readiness.
assistance 11/08/94 l0'.
Root cause of the turbine failure is submitted to Complet'e -
NRC (CAL item #1 complete).
Licensee 08/24/94 11.
Evaluation of licensee's corrective action plans for restoration of the turbine by operating with both 7th and 8th stage blades removed from all LP turbines completed.
Review to include evaluations of the following: pressure plate analysis. UT exam results, root cause of failure analysis, missile analysis, shaft analysis, turbine support and foundation assessment, and turbine vibration analysis given the expected bow in the installed rotors.
NRR 11/10/94 19 l
c.
L.
')2.; :NR.C review of HOV failure corrective actions, and j'
'results of H0V static and dynamic testing problems.
including pressure locking issue, completed (IFI-l 341/94007 05).
ORS 11/10/94 ISSUE RESPONSIBLE PROJECTED ORGANIZATION OR ACTUAL COMPLETE
$3.
Determine and conduct inspections necessary to evaluate licensee's repairs for structural damage suffered during the event. Areas to be evaluated by NRR include support beams, bearing boats, and cradle for the turbine; and floors and walls of turbine 3
building. Areas to be evaluated by ORS include the i
steam' lines. Oil lines, water lines and their DRS with NRR associated hangers, supports. and snubbers.
assistance 11/10/94 l14.
Ensure that all Appenk. R requirements are met for DRS with ORP those areas formerly containing Thermo Lag material.
assistance.
11/10/94 15.
Effects of the chemistry excursion on the fuel and reactor vessel internals are submitted to the NRC Complete -
(CAL item #2 complete).
Licensee 08/24/94 4
- 16. ' Effects of the chemistry excursion on the control Complete -
rod drive mechanisms are submitted to the NRC.
Licensee 08/24/94 17.
NRC evaluation of chemistry excursion effects on po:cntial reactor internals damage, cracking susceptibility, need for modification to standard ISI program, and acceptability of operations completed (IFI-341/94007 06). Areas for review include length of the excursion. the exact values of chemistry parame*ers during the excursion.
(conductivity, pH and chemical analysis of the off-spec water for different chemical species, especially those which can cause damage to the in-vessel components, e.g. chlorides, sulfates etc.):
and a quantitative and qualitative analyses of any deposits on fuel and different componcnts inside the vessel.
NRR 11/10/94 I
20 M.,.
+
~
FERMI 2 RE& TART ACTION (RTision 1) PLAN (Continued) 18.
NRC' inspection of operability of Turbine Building Complete -
HVAC system completed (IFI-341/94007 03).
DRP 09/16/94 19.
NRC inspection of adequacy of condenser repairs Complete -
completed.
DRP 09/16/94 20.
Inspection of modifications implemented to allow continued operation of BOP and turbine generator and bounding of moisture intrusion problems occurring prior to event (e.g., modified rotors. nes static exciter, restoration of turbine support systems such as lube oil and cooling water, modifications to feedwater heater string instrumentation, heater drain pumps. etc).
DRS 11/10/94 21.
NRC evaluation of adequacy of repairs to fire protection system damaged during event.
DRS 11/10/94 22.
All safety related 480 volt and 4160 volt ABB breakers are replaced / repaired to resolve hardened grease concerns and the cracked starting crank concern.
DRS 11/10/94
)
21
+,
p
-4
FERMI 2 RE8 TART ACTK)N (Revision 1) PLAN (Continued) x ISSUE RESPONSIBLE PROJECTED ORGANIZATION OR ACTUAL COMPLETE 23.
NRC verification that corrective actions necessary to address deficiencies identified in AIT report G
regarding fire response are completed (IFI-Complete
/
341/94007-07).
DRP 09-16 94 1
.24.
NRC review of licensee's determination regarding IST applicability for valves between radwaste building and ECCS corner rooms completed.
(IFI-341/94005 01)
NRR 11/10/94
~25.
Acceptability of completed proof test on the four sections of ductwork in the CCHVAC system that would see approximately -22" water gauge pressure at the l
worst case system pressures. The test would inspect seam integrity during the test, hold pressure for at least 5 minutes. and visually inspect for plastic deformation and system leakage at accessible worst case points (co_rners joints in seams).
NRR 11/10/94 26.
Assess acceptat'ility of the 65 safety-related cables that were pullad without tension monitoring devices.
DRS 11/10/94 27.
Assess the licensee's staff readiness for power i
operations: 1.e.
has the staff been trained on the new mods on the turbine and feedwater systems. have the operators been given training to prepare for DRP with ORS
.startup.
assistance 11/18/94 28.
NRC evaluation of adequacy of pre startup. start up, and power ascension testing program completed.
Evaluation to ensure vibration limits for operation throughout the cycle are clearly specified for alert and trip setpoints as well as actions for "off-normal" equipment performance such as fluid pulsations, flow mismatches, pressure pulsations, valve hunting. effective control of the feedwater system, sensitivity of BOP to various DRP with NRR instrumentation or control transients. etc.
concurrence 11/18/94 29.
Assess management readiness for restart and ensure viable self assessment program in place to fix as well as find problems.
DRP/RP/RA 11/18/94 30.
Provide various Congressmen with information As needed when previously requested, review l
NRR completed.
l
??
l
FERMI 2 RESTART ACTION (Revision 1) PLAN (Continued) 31.
NRC inspection of pre start up activities completed.
~
DRP 11/18/94 32.
NRC inspection of start up activities completed.
DRP 11/27/94
{ 33.
NRC inspection of power ascension activities i
completed.
DRP 1/31/95 POTENTIAL ADDITIONS:
5 i
r e
I
?
e i
i 23 t--
FERMI 2 RESTART ACTION PLAN (C1'ntinued)
O;o
s W
ISSUE l
}';
NO.
REFERENCE INFORMATION FOR CLOSE0UT k
1.
Inspection Report 50-341/94003 dated 03/30/94.
2.
Inspection Report 50-341/93029 (AIT report) dated 02/07/94.
3.
Inspection Report 50 341/94004 dated 03/18/94.
4.
Inspection Report 50-341/94006 dated 04/25/94.
5.
Inspection Report 50-341/94013 dated 11/08/94.
6.
Inspection Report 50-341/94008 dated 07/12/94.
7.
Inspection Report 50 341/94007 dated 06/15/94.
8.
Inspection Report 50 341/94007 dated 06/15/94.
9.
Inspection Report 50-341/94013 dated 11/08/94.
10.
Letter from D. Gipson to NRC dated 08/24/94 (NRC-94 0075).
11.
12.
13.
14.
15.
Letter from D. Gipson to NRC dated 08/24/94 (NRC-94-0075).
16.
Letter from D. Gipson to NRC dated 08/24/94 (NRC 94-0075)-.
17.
18.
Inspection Report 50 341/94011 dated 09/16/94.
19.
Inspection Report 50 341/94011 dated 09/16/94.
{
20.
21.
22.
23.
Inspection Report 50-341/94011 dated 09/16/94.
24.
25.
26.
27.
28.
29.
30.
31.
32.
33.
i 4
f
.f
. -. ~. -- ---
. - -. ~.. - -
fUhdk 4
UNITO STATES M
- g h
LEAR REGut.ATORY COMMISSION o
REGloN 111 5
5 801 WARRENVILLE RoAo h,...../
UsLE. ILUNots 60632-4351 August 5, 1997 L4AEMORANCUM TO:
A. Bill Beach, Regional Administrator FROM:
James L. Caldwell, Deputy Regional Ad inistrato
SUBJECT:
CLINTON POWER STATION RESTART (PARTIAL APPROVAL)
I am writing to inform you that the Clinton Restart and Performance Review Panel (the Panel), following a modified Manual Chapter (MC)-0350 format developed in November 1996 (Attachment B), has determined that Illinois Power (IP) has satisfactorily completed those items and corrective actions identified as restraints to restarting the Clinton Power Station (CPS) with an exception described below. Further, the Panel has determined that CPS personnel performance and equipment status are capable of supporting facility restart.
Following the September 5,1996, reactor recirculation pump seal failure event, the NRC Issued Confirmatory Action Letter (CAL) Rlli-96-013 to confirm actions IP would take to j
identify issues associated with the event. Following completion of IP's investigation into the event and the NRC special inspection and Operational Safety Team inspection (OSTI),
IP committed to implement a Startup Readiness Action Plan (SRAP) prior to restarting CPS.
The SRAP items were documented in CAL No. Rill-97-001 and were designed to improve procedure adherence and quality, safety and operability evaluations, address a number of long-standing equipment problems, and improve IP's corrective action program. A third CAL, Rill-97-006, was issued in June 1997, addressing degraded coatings in the containmont. In addition to the CALs, specific equipment issues were identified as restart issues including degraded voltage, breaker maintenance, and control room neon bulb sockets.
IP's corrective action implementation and effectiveness were inspected by the resident staff, resident inspectors from other Region lli sites, and non-resident inspection activities.
The Panel monitored IP's activities through direct observations and feedback from inspectors. The Panel met weekly and held public meetings with IP on April 18, May 1, 15,28, June 13, and July 3,1997, to discuss the status and effectiveness of the specific items and emergent technicalissues.
The Panel reviewed the actions IP took to address programmatic and equipment I
deficiencies identified at the CPS. The review included assessments of IP's actions and responses to commitments in the three CALs, actions to address equipment deficiencies at I \\
b,. p p/
d g9 CONTACT:
Geoffrey Wright, DRP 630/829-9602 m
V
$lhlllllhlhllhl PDR ADOCK 05000461 6
n A. Bill Beach CPS, actions to address discrepancies between the as-built facility and the Updated Safety Analysis Report, actions to address degraded but operable equipment, and current allegations for trends or startup issues. A summary of the Panel's review of the issues is in Attachment A. While recognizing that IP's improvement program is not completed, the Panel, with the exception of the electricalissue discussed below, concluded there is reasonable assurance that the facility can start up and operate safely.
The final restart issues deal with offsite electrical power source capability, electrical circuit breaker reliability, and equipment qualification in the Emergency Diesel Generator (EDG) rooms. To address offsite power source capability, IP has requested a Technical Specification amendment and an exemption from General Design Criterion 17. To address i
safety related breaker reliability, IP performed extensive inspections, tests, and overhauls of safety related breakers to demonstrate reasonable assurance that these breakers were capable of performing their safety function. Despite these efforts, a safety related breaker failed in service on July 22,1997. IP is performing additional tests, reviewing their maintenance procedures, and developing and implementing corrective actions to re-establish reasonable assurance that safety related breakers will function when called upon.
To address high EDG room temperatures, IP is performing extensive reviews and analysis to demonstrate that the EDGs and their supporting equipment will remain operable under foreseeable conditions of high temperature. These issues will be discussed and the licensee's determinations and corrective actions will be evaluated prior to restart of the facility. A separate memo to you will document the Panel's review and agreement that these electrical issues have been resolved sufficiently to allow restart.
To ensure appropriate monitoring of IP's activities during startup, a special startup monitoring program consists of 24-hour coverage by six inspectors during startup and power ascension was developed (Attachment C). The Panel reviewed the program and found it acceptable.
I Restart Review Panet Results and Recommendation are Approved:
A. Bift Beach, Regional Administrator Region IH Attachments:
A. Issue Assessment B. Modified MC-0350 Restart Action Plan for Clinton Power Station (CPS)
C. Startup Inspection Plan Docket No. 50461 Inspection Report 97016
A. Bill Beach Distribution cc w/ attachments:
G. Tracy, OEDO J. Roe, NRR G. Marcus, NRR D. Pickett, NRR J. Caldwell, Rlli G. Grant, Rlli J. Grobe, Rlli G. Wright, Rlli K. Perkins, WCFO, RIV
' SRI, Clinton Docket File PUBLIC IE-01 l
Attachment A ISSUE ASSESSMENT l
CAL No. RIII-96-013:
Confirmatory Action Ixtter (CAL) No. RIII-96-013 was issued shortly after the September 5,1996 event. The CAL addressed actions Illinois Power (IP) committed to perform to assess the event. IP addressed the actions in a number of letters to the NRC, the last being on December 9,1996, where IP's Startup Readiness Action Plan (SRAP) was addressed. All actions associated with the CAL were completed, carried over to the SRAP, or addressed in IP's long-term Strategic Improvement Program.
CAL No. RIII-97-001:
l Procedure Adherence:
Improvements in procedure adherence have been noticed site-wide, with significant improvements noted in the Operations Department. The most effective actions taken by IP management occurred in April 1997 when fundamental changes were made to the administrative procedures governing procedure adherence and temporary procedure changes. Special training was provided to plant staff on the new j
procedures and management used the training to re-enforce its expectations in the area. IP also brought in outside contractors to assist in evaluating and correcting problems in human performance regarding procedure adherence.
4 j
Procedure Improvement:
IP implemented a procedure enhancement program for important operating procedures and selected surveillance procedures. This activity improved the procedures' technical content and usability. The program initially reviewed the procedures for technical accuracy. Following the April changes to the procedure adherence guidance, procedures were reviewed to ensure they could be accomplished as written.
The combination of the two reviews has resulted in much improved procedures.
Safety Evaluations & Operability Determinations:
IP revised its programs for safety evaluations and opembility determinations.
Training was also provided to engineering and operations staffs on both topics with emphasis placed on the purpose of 10 CFR 50.59 safety evaluations. One of the 4
notable changes was in the operability determination program where the Operations Department now has the responsibility for initial equipment operability determinations rather than engineering. While the licensee experiences growing pains in the program's implementation, the essential elements of a successful program exist.
\\
Corrective Action Program:
IP addressed short and long term improvements to its corrective action program.
Short term activities involved increased staff sensitivity towards condition reports, improved critique process, and improved nueument timeliness. Long term actions, addressed in IP's July 3,1997 letter, include items such as a separate group responsible for the corrective action program and improved corrective action determinations. IP's short term actions have resulted in a considerable improvement in the process.
57 Individual CAL No. RIII-97-001 Items:
The Panel reviewed IP's actions associated with 57 items in CAL No. RIII-97-001.
The review included review of IP's documentation, meetings with IP to discuss actions taken and their effectiveness, and independent inspection activities. The inspection activities involved routine observations and discussion with Clinton Power Station (CPS) staff, inspection effort directed at individual issues, and observations of IP's training and seminars addressing specific issues. The results from these activities formed the bases for the Panel's closure of the 57 items documented in Inspection Report 50-461/97012. As noted in the report, three items require additional activities during startup and power ascension: control room starmp monitoring, feedwater check valve performance, and reactor recirculation pump seal performance. Raced on the aforementioned activities, the Clinton Restart and Performance Review Panel (the Panel) determined that IP has taken the actions they committed to take prior to unit startup and that those actions have improved CPS staff performance.
LONG STANDING TECHNICAL ISSUES:
Significant modifications were made to the two outboard feedwater check valves.
Modifications to the valves' operators were made to improve seat alignmerit during closure and closing forces. Post modification leak rate testing indicated a very low leakage rate. IP committed to perform a mid-cycle local leak rate test on the feedwater check valves to validate the effectiveness of the design changes.
Degraded Voltage:
Significant modifications were made to address degraded voltage condition.
Modifications were made to the electrical distribution system to improve the facility's response to an electrical distribution safety function inspection identified degraded voltage condition. This item was the critical path item for the outage from January to the end of the outage. Resolution of the onsite problem of degraded voltage led to the identification of the need for a Technical Specification amendment and an exemption A-2
i.
l 3
2 from General Design Criteria 17. These were still pending and required the Panel j
review and approval prior to restart.
Safety Related Breaker Maintenance:
i In response to NRC identified deficiencies in its maintenance program for safety related breakers, IP completed an extensive testing and inspection program on 480 V, 4160 V, and 6900 V safety related circuit breakers. The Panel concluded that additional information is required to ensure reasonable assurance that the breakers will j
perform satisfactorily during the next refueling cycle.
1 Control Room Neon Bulb Replacement:
IP replaced, for the second time, all main control room neon bulb holders due to j
inadequate initial installation. The licensee identified the root cause of this problem 1
to be a programmatic breakdown in the control of consumable material on plant components and poor workmanship. Actions were taken to address both issues.
Main Control Room Deficiencies:
IP also identified and repaired in excess of 400 main control room deficiencies, significantly improving the material condition of the main control room. The Panel found IP's actions to be acceptable.
Excessive Backlogs of Non Safety and Safety Related Preventive Maintenance (PM) Tasks Following an NRC inspector question on the timeliness of the calibration of radiation monitors, the licensee found an error in a computer program used to schedule PMs had caused 1,464 PM for safety and non-safety components to be late. The licensee is prioritizing necessary tasks, performing critical PMs or performing engineering evaluations to justify not performing the PMs prior to restart.
CAL No. RIII.97-006 DEGRADED CONTAINMENT COATINGS:
CAL No. RIII-97-006 was issued to document actions IP agreed to take in response to the NRC identified issue of degraded containment coatings and their impact on suppression pool emergency core cooling system suction strainer operability. IP addressed the CAL by removing known and suspected degraded coatings and by sampling non-suspect coatings to demonstrate conformance to the applicable standards. The program was reviewed by the Panel and Nuclear Reactor Regulation coating experts and found to be acceptable.
A-3
~.
ALIRGATIONS. UPDATED SAFETY ANALYSIS (USAR) DISCREPANCIES. AND DEGRADED BUT OPERABLE EOUIPMENT:
j The Panel's review of existing allegations did not identify any specific trends or issues which would impede unit startup. Likewise, a review of USAR discrepancies and degraded but operable equipment evaluations did not identify any items affecting unit restart. Equipment that had been identified as degraded but operable had been identified by IP as mode change restraints indicating the degraded condition would be corrected prior to changing modes. The Panel found no restart items in this area.
i l
i l
l l
l l
l I
A-4 2
=
Attachment B l
i j
Modified Manual Chaoter (MC) 0350 Restart Action Plan for
.Clinton Power Station (CPS)
A.
GENERAL l
A.1 PURPOSE l
The CPS Restart Action Plan (Action Plan) is to plan and coordinate NRC review activities for the Clinton Station restart following the shutdown from the September 5,1996 event.
A.2 OBJECTIVES The Action Plan has been developed to ensure NRC review efforts are consistently developed and implemented, with specific guidance to support the following activities, a.
Determine issues requiring NRC review prior to facility restart.
b.
Identify the basic tasks needed to be reviewed and approved prior to facility restart.
c.
Restart review activity coordination and tracking.
A.3 BACKGROUND Following the plant startup from the April 9,1996 reactor scram, one of two reactor recirculation pump shaft seals began to degrade. Pump seal pressure was initially observed to be decreasing and drywell unidentified leakage was observed to be increasing; both indicative of seal degradation. On September 5,1996, due to increasing trends in drywell unidentified leakage, isolation of the reactor recirculation loop believed to be the leakage source was initiated. While isolating the loop, unidentified drywell leakage increased above the five gallons per minute technical specification limit. An Unusual Event was declared and a number of actions were taken by the plant staff, including actions to decrease unidentified leakage. During these actions the pump seal failed, causing a large and rapid increase in the drywell leakage rate. The plant was shut down, leakage terminated, and actions were started to replace the pump seals.
The NRC was concerned with the decisions and actions taken in response to plant conditions during the event. Based on these concerns, a special NRC team l
inspection was initiated on September 6,1996, to evaluate the actions taken in response to the event. In addition, the NRC was concerned with the slow response by senior B-1 i
+
management to thoroughly assess the actions of the operating crew under the direction of the Shift Supervisor and the Assistant Director for Operations.
4 Further, the licensee's initial actions to assess the event and the actions taken during the event were not sufficient to identify the numerous errors and problems associated with the event. This required the licensee, after discussions with the NRC, to reassess the event and submit a second corrective action plan for NRC review.
B.
PROCESS-B.1 INITIAL NRC RESPONSE a.
Initial notification and NRC management discussion of the known facts and issues were conducted on September 5,1996, upon notification of the event.
b.
Region lli identified the need for an NRC special inspection to specifically address the event and licensee actions pertaining thereto. The special inspection was started on September 5,1996, and concluded on October 4, 1996. Based on the event and the preliminary findings from the special inspection a second inspection was initiated. The second inspection, an Operational Safety Team inspection (OSTI) commenced on September 16, 1996, and concluded on October 4,1996.
c.
Based on the event and the slow and limited management response to the event, the NRC issued a CAL No. Rlil 96-013 on September 11,1996.
)
Based on the information identified through the Special and OSTI inspections, further discussions are being held to determine whether additional actions in this area are needed to ensure the licensee is fully aware of NRC concerns.
B.2 NOTIFICATIONS a.
Issue Daily and Directors Highlight:
Unknown I
b.
Issue Preliminary Notification (PN):
PN 96-058 issued 9/6/96 c.
Conduct Commissioner Assistants' Briefing:
None conducted d.
Issue Commission Paper:
None issued B-2
~
_.~
B.3 ESTABLISH AND ORGANIZE THE NRC REVIEW PROCESS a.
After reviewing the preliminary finding from the two inspections, a Rostart Panel was established on October 29,1996.
Senior Executive Service Oversight:
James Caldwell, Director, Division of Reactor Projects (DRP),
Region til Assistant:
Gail Marcus, Project Director, PD 3-3 Team Leader:
Geoffrey Wright, Restart Manager, Division of Reactor Safety, Region lll Team Members:
Fred Brown, Acting Senior Resident inspector Doug Pickett, Project Manager, Nuclear Reactor Regulation (NRR)
Karla Stoedter, Resident inspector (RI), CPS Ron Langstaff, Acting RI Dave Zemel, Illinois Department of Nuclear Safety (IDNS) b.
Information Available for Review:
Inspection Reports: 50-461/96-009,10,11,12,13,14,15,16 50-461/97-001 (Systematic Assessment of Licensee Performance (SALP) Report) 50-461/97-002, 3, 5, 6 Ccnfirmatory Action Letter (Rill-96-013)
Confirmatory Action Letter (Rlll-97-OO1)
Confirmatory Action Letter (Rill-97-006)
Licensee Action Plan dated September 24,1996 Licensee Event Assessment dated September 22,1996 Licensee Startup Readiness Action Plan (SRAP) dated December 9,1996 i
Licensee Response to CAL Rlli-97-001 dated July 2,1997 Licensee Corrective Action /Self Assessment Program improvements letter dated July 3,1997.
c.
Conduct Regional Administrator Briefing STATUS: COMPLETE d.
Develop Case-Specific Checklist STATUS: COMPLETE e.
Develop CPS Restart Action Plan STATUS: COMPLETE 4
B-3
t f.
Obtain NRR Projects input for Action Plan STATUS: COMPLETE g.
Division Director's Approval of Restart Action Plan STATUS: COMPLETE i
h.
Implement Action Plan l
STATUS: COMPLETE l
i.
Modify Confirmatory Action Letter (CAL) as Necessary STATUS: No modifications were necessary.
B.4 REVIEW IMPLEMENTATION 8.4.1 Root Causes and Corrective Actions a.
Team has evaluated findings from the special and OSTI team inspections.
l STATUS:
COMPLETE: Escalated enforcement actions against Illinois l
Power (IP) and individuals proposed. Enforcement for l
September 5,1996 event, radiation protection issues, High Pressure Core Spray (HPCS), Emergency Diesel Generator I
(EDG) inoperability, and feedwater check valve failures has l
been issued. Actions against individuals from the September 5,1996 event were limited to a letter to the two senior individuals. An additional escalated enforcement action against IP was issued for safety related breaker reliability issues.
l Several apparent violations associated with the administrative l
procedure on procedure adherence have not been dispositioned by the NRC, but licensee corrective actions for this problem have been implemented and were effective. This problem does not represent a startup issue.
b.
Licensee Assessments Performed:
1.
Initial event assessment 2.
Revised event assessment dated September 22,1996 l
3.
Initial Corrective Action Plan dated September 17,1996 4.
Revised Corrective Action Plan dated September 24,1996 5.
SRAP submitted December 9,1996 B-4 I
c.
NRC reviewed the licer.see's initial event assessment and Corrective. Action l
Plan and found them lacking in content and detail. After discussions with the NRC, the licensee revised both documents and resubmitted them.
d.
Review of Revised Corrective Action Plan and SRAP found them responsive to NRC concerns and generally acceptable. CAL Rlli 97-OO1 was issued to confirm IP commitment to the plans. Two items IP had agreed to were added: emphasis on safety vs. production training and qualitative / qualitative evaluation criteria for IP to assess effectiveness of their programs.
1 B.4.2 Equipment Damage Assessment Licensee assessment of equipment damage caused or contributed to the event.
l Damage appeared to be limited to the failed reactor recirculation seal package.
3 j
a.
Preliminary Assessment on Cause of Seal Damage and Failure STATUS:
COMPLETE: Dirt and flashing of water to steam, was caused by securing cooling water, which forced the second stage seal faces apart appeared to be the primary cause.
b.
NRC Evaluation of Licensee's Damage Assessment STATUS:
COMPLETE: NRC observed seal disassembly and inspection.
Licensee's assessment was consistent with seal condition.
c.
Licensee Determined Corrective Actions STATUS:
COMPLETE:
1.
Old seal package removed, new package installed.
Questionable discussions on installing the new seal package with the primary system hot and known isolation valve leakage. Plant was cooled down p.ior to work being performed.
~
2.
Disassembly of failed seal package revealed that dirt was the most probable initial failure mechanism.
3.
Licensee has sent seal components out for more extensive analysis.
4.
Licensee has assembled an engineering team to resolve long standing reactor recirculation pump seal degradation problems at CPS.
B-5
. -... _. - ~ ~
... - - ~ _ -.. - - -.. - -
(
0 d.
NRC Evaluates Corrective Actions STATUS:
COMPLETE: Immediate corrective action for failed seal was comprehensive and well implemented.
B.4.3 Determine Restart issues and Resolution a.
Review / Evaluate Licensee Generated Restart issues STATUS:
COMPLETE: Initial review against special and OSTI inspections identified deficiencies in IP's restart issue list.
NRC discussions with IP subsequently resolved issues. IP submitted restart issues list on December 9,1996.
b.
Independent NRC Identification of Restart Issues l
STATUS:
COMPLETE: Augmented resident team developed restart issues list. The list was used to assess IP's restart issues in B.4.3.a. Issues were included in IP's SRAP, which was confirmed through a CAL.
c.
NRC/ Licensee Agreement on Restart issues STATUS:
COMPLETE: NRC and IP agreed on issues list and IP submitted its SRAP on December 9,1996.
d.
Evaluate Licensee's Restart issues Implementation Process STATUS:
COMPLETE: An interim readiness inspection was performed during the week of January 6,1997. Augmented resident inspection activities continued to monitor implementation of the licensee's corrective actions. This inspection was documented in Inspection Report 50-461/97012.
e.
Evaluate Licensee's Implementation Verification Process STATUS 1 COMPLETE: Same as B.4.3.d. Program is having a positive impact on designated activities.
B.4.4 Obtain Comments SBTUS:
COMPLETE: Obtained comments and agreement on restart issues from NRR - Doug Pickett, Gail Marcus, and Cynthia Carpenter.
1 B-6
1 i
\\
B.4.5 Closeout Actions When the actions to resolve the restart issues and significant concerns are substantially complete, closeout actions are needed to verify that planned inspections and verification are complete. The licensee should certify that corrective actions required before restart are complete and that the plant is physically ready for restart.
j a.
Evaluate Licensee's SRAP (Region) l STATUS:
COMPLETE: Bi-weekly meetings with final meeting conducted on July 3,1997, indicated appropriate understanding of past issues and remaining issues effecting restart.
b.
NRC Evaluation of Applicable items from Section C " Issues" Complete STATUS:
COMPLETE: See Section C.
c.
Restart issues Closed STATUS:
COMPLETE: Allidentified restart issues have been resolved.
Major issues were associated with the three CALs, safety related breaker operability / reliability, containment coatings, and degraded voltage.
d.
Conduct NRC Restart Readiness Team inspection (Region)
STATUS:
NOT APPLICABLE: Due to the human performance issues and I
the protracted nature of the outage, resident and regional based inspections conducted throughout the outage were j
focused on assessing licensee readiness to restart.
e.
Issue Augmented Restart Coverage inspection Plan STATUS:
COMPLETE: Plan development hour coverage is to be provided by residents and supplemented by other site residents and regional personnel. Coverage will continue ~ over a 2-week period.
f.
Comments from Other Parties Considered i
STATUS:
COMPLETE: Comments solicited from NRR Projects and resident office. Input obtained from NRR indicated no restart issues associated with human factors, safety related breaker, or containment coatings issues.
i B-7 4
4 i
l l
l l
_ g.
Determine That all Conditions of the Order / CAL are Satisfied l
l STATUS:
COMPLETE: Letter from A. Bill Beach, Rlli Regional Administrator to John Cook of IP.
l h.
Re-review of Generic Restart Checklist Complete STATUS:
COMPLETE: See Section C.
B.5 RESTART ACCEPTANCE a.
Prepare Restart Readiness Review and Basis Document STATUS:
COMPLETE: Contained herein.
b.
NRC Restart Panel Approves Restart Readiness Review STATUS:
COMPLETE: Contained herein.
c.
No Restart Objections from Other Applicable HQ offices.(NRR, Analysis of Events and Operational Data)
STATUS:
COMPLETE: No objections from NRR on containment coatings or human factors issues.
d.
NRR Concurs with Restart Readiness Review STATUS:
COMPLETE: Contained herein.
e.
Regional Administrator Approves Restart Readiness Review STATUS:
COMPLETE: Contained on cover memorandum to this document.
B.6 RESTART AUTHORIZATION NOTIFICATION Notify the applicable parties of the restart readiness review approval. Notifications should generally be made using a memorandum or other format consistent with the level of formality required. Communication of planned actions is important at this stage to ensure that NRC intentions are clearly understood, a.
Public Affairs (Region)
SIATUS:
COMPLETE: Notification made by DRP.
i B-8
' b.
IDNS (Region)
STATUS:
COMPLETE: Notification made by DRP.
c.
Additional notification to be considered: Executive Director of Operations (EDO), NRR l
STATUS:
EDO consultation indicated by Regional Administrator approval i
of the cover memorandum for this document.
C.
ISSUES The following sections contain items for consideration by the Panel during the restart review. These items are based on issues found during other restart reviews.
The experience is primarily based on plant shutdowns due to management deficiencies, hardware issues, or a combination.
C.1 ASSESSMENT OF ROOT CAUSE IDENTIFICATION AND CORRECTION The root cause(s) of the event or the conditions requiring the shutdown should be identified and corrected. A comprehensive licensee corrective action plan should be developed tl.at addresses the root cause(s) and all applicable issms including corrective actions, implementation, and verification. The licenwe should revise its corrective action plan as necessary to ensure emergent issues are addressed and 3
resolved. The Panel should ensure that emergent issues identified by the NRC are promptly conveyed to the licensee for incorporation into the licensee's corrective 4
~
action plan._ The corrective action plan should also include sufficient measures to prevent recurrence of problems. The NRC shall review the licensee's corrective action plan to verify its completeness and adequacy and to determine which corrective actions will be required to be implemented before restart and which can be deferred to some later date as long-term corrective actions.
The NRC will review the licensee's corrective action activities and use the tools available in the regulatory program to determine the acceptability of these actions with respect to safe operations. These tools include staff reviews; the SALP report; inspections, including special team inspections; requests under 10 CFR 50.54(f); senior management meetings; enforcement conferences; and a Restart Panel. The results of the NRC staff's reviews will be documented as appropriate by safety evaluations, licensee amendments, orders, CALs, in,spection reports, Commission meeting transcripts, and enforcement documents.
l C.1.1 Root Cause Assessment a.
Conditions Requiring the Shutdown are Clearly Understood STATUS:
COMPLETE: Reactor recirculation pump seal package failures are a continuing problem at the CPS. Initialinspection of the failed seal package revealed dirt as a prime contributor to the 4
B-9
l initial seal package leakage. Operational decisions during loop isolation activities may have contributed to ultimate seal package failure.
The causes for poor operational and management decisions can be generica!!y attributed to a lack of conservative decision making and possibly economic pressures.
b.
Root Causes of the Conditions Requiring the Shutdown are Clearly Understood STATUS:
COMPLETE: Root cause for failure of the. specific sealis believed to be dirt. Cause(s) for continued seal package failure for Pump B is not yet fully understood. Special IP engineering team planned to assess all Pump B failures.
1 Excessive leakage during event attributed to the flashing of water to steam and forcing seal stage faces apart.
c.
Root Causes of Other Significant Problems are Clearly Understood STATUS:
COMPLETE: Causes for out-of-service equipment, poor decision making, poor engineering support, poor understanding of design basis and 10 CFR 50.59 safety evaluation process traced to a number of issues: Shift in focus over time to increase the importance of production, lack of knowledge, lack of management expectations, lack of attention to detail, etc.
Major cause of issues are addressed in IP's SRAP of December 9,1996.
d.
Effectiveness of the root cause analysis program STATUS:
COMPLETE: initial event assessment by the licensee was not comprehensive. Subsequent assessment was improved.
Subsequent assessments were adequate - some issues well addressed others required NRC input. Overall program is adequate with improvements planned long term.
C.1.2 Damage Assessment a.
Damage Assessment was Thorough and Comprehensive STATUS:
COMPLETE: Licensee's assessment of seal package failure has, to date, been both thorough and comprehensive.
B-10
4 b.
Corrective Actions Clearly Restored System and Equipment l
STATUS:
COMPLETE: Seal package was replaced with new seal. Failed seal was disassembled, inspected, and sent to outside laboratory for a more detailed examination.
l C.1.3 Corrective Actions j
l a.
Thoroughness of the Corrective Action Plan STATUS:
COMPLETE: SRAP covers allitems identified by IP and NRC. In addition, IP is using the SRAP to force corrective action for other issues and has developed a Strategic Performance improvement Plan including numerous items not included in the initial plan.
b.
Completeness of Corrective Action Programs for Specific Root Causes STATUS:
COMPLETE: The corrective actions address the identified root causes including equipment and human performance. Additional actions were taken, due to outage length, to address system readiness and organizational readiness, via the Strategic Performance Improvement Plan. The Strategic Performance improvement Pian addresses both short and long term actions, c.
Control of Corrective Action Item Tracking STATUS:
COMPLETE: Licensee put in place a special oversight team to monitor and assess corrective action program items, d.
Effective Corrective Actions for the Conditions Requiring the Shutdown Have Been Implemented STATUS:
COMPLETE: Corrective actions for all of the items have been implemented. Actions to cddress recirculation pump seal failures on Pump B are continuing.
e.
Effective Corrective Actions for Other Significant Problems Have Been implemented STATUS:
COMPLETE: Actions have been taken to address a wide range of problems. IP initiated a Strategic Performance improvement Plan which identified problems with equipment and programs.
Many human performance issues were also identified by IP and NRC. Short term corrective actions have been completed to provide reasonable assurance of safe operation. Observations of site activities have indicated generalimprovement in B-11
~
i performance, especially in the procedural adherence and quality areas. Long term corrective actions, including a modified Diagnostic Evaluation Team (DET) inspection are 1
scheduled following restart of the unit.
f.
Control of Long-Term Corrective Actions STATUS:
COMPLETE: IP,in addition to the SRAP and the Strategic Performance improvement Plan, has developed a long term action plan to address those issues which are not of immediate significance to safe plant startup. Refer to IP's July 3,1997 letter on corrective actions and self assessments.
]
l g.
Effectiveness of the Corrective Action Verification Process j
STATUS:
COMPLETE: Corrective action verification process for actions associated with the September 5,1996 event and associated issues have been handled adequately, initial actions treated actions as a check list without sufficient emphasis on effectiveness. Recent activities on closure of CAL items have included discussions on action effectiveness.
C.1.4 Self Assessment Capability The occurrence of an event may be indicative of potential weaknesses in the licensee's self-assessment capability. A strong self assessment capability creates an environment where problems are readily identified, prioritized, and tracked.
Effective corrective actions require problem root cause identification, solutions to correct the cause, and verification methods that ensure the issue is resolved. The effectiveness of senior licensee management in ensuring effective self-assessment is treated separately.
a.
Effectiveness of Quality Assurance (QA) Program STATUS:
COMPLETE: IP recognizes OA program was not effective in identifying the problem and trends associated with the September 5,1996 event. Plans are in place,'along with a new Nuclear Assessment Director, to review the program and 1
identify corrective actions. Ownership of the Corrective Action process vested in a newly created middle level management position. Integration of the assessment and corrective action functions was emphasized by creation of a new senior level management position, b.
Effectiveness of Licensee's independent Review Groups STATUS:
COMPLETE: As with other QA programs, independent Safety Engineering Group (ISEG) reviews did not identify the B-12
significant performance issues at CPS. Subsequent reviews of ISEG activities indicates improved assessment of information for example, reviews of surveillance tests for adequacy identified a number of deficiencies.
c.
Effectiveness of Deficiency Reporting System STATUS:
COMPLETE: The program, prior to September 1996, had a very high threshold for reporting issues on condition reports.
Subsequent changes in management expectations has significantly lowered the threshold. Since August 1996, there has been a substantial increase in the number of issues being reported via condition reports. Recent changes have included application of the system to the radiologically protected area.
Long term monitoring required to assess effectiveness.
d.
Licensee Staff Willingness to Raise Concerns STATUS:
COMPLETE: Discussions with individuals from the line and QA organizations indicates staff is willing to raise concerns.
Increased number of condition reports issued also indicates people are raising and documenting concerns.
e.
Effectiveness of Probabilistic Risk Assessment (PRA) Usage STATUS:
COMPLETE: It did not appear that PRA was used in the past te assess collective impact of control room deficiencies.
However, recent observations have indicated that PRA is being used to evaluate plant conditions and being used to input into decisions on equipment outages.
C.2 ASFei3SMENT OF LICENSEE MANAGEMENT EFFECTIVENESS Evaluate the effectiveness of the licensee's management in assessing, evaluating, and resolving the problems and the associated root causes that resulted in the plant shutdown and contributing problems. Licensee management effectiveness should be measured against the results achieved by the licensee. The results should demonstrate a coordinated and integrated approach to resolving the problems and developing corrective actions, the problems and corrective actions should be assigned priority consistent with their safety significance. Licensee's management must demonstrate an ability to recognize safety problems, develop and implement adequate corrective actions, and verify the effectiveness of the corrective actions in a timely manner.
B-13
C.2.1 Management Oversight and Effectiveness a.
Goals and Expectations Communicated to the Staff STATUS:
COMPLETE: Action has been taken to address this area.
Human performance has improved; however continued long term vigilance is necessary.
b.
Demonstrated Expectation of Adherence to Procedures STATUSt COMPLETE: After extensive NRC involvement and subsequent enforcement action, the licensee developed regulatory compliant procedure adherence program and procedure change program. Licensee management has expressed its i
expectations on procedural adherence. All plant staff received extensive training on the new requirements. Improved performance in this area has been documented in routine NRC resident inspection reports.
c.
Management involvement in Self-Assessment and independent Self-Assessment Capability STATUS:
COMPLETE: Third party (Institute of Nuclear Power Operations, contractors) assessments have been good.
Internal management assessment in one case was not well documented regarding findings and recommendations.
d.
Effectiveness of Management Review Committees STATUS:
COMPLETE: In general, improvements in critical assessment of CPS activities have been noted in areas where continued improvements were necessary.
e.
Management's Demonstrated Awareness of Day-to-Day Operational Concerns STATUS:
COMPLETE: Acceptable communication, in geheral, between plant managers and directors. Through observation of the engineering and 8:15 a.m. licensee m,eetings, individuals appear knowledgeable of current operationalissues.
f.
Management's Ability to identify and Prioritize Significant issues STATUS:
COMPLETE: Performance in this area is adequate. The licensee has had success in this area where improvements l
were needed. For example, a supervisor's involvement with l
an employee's failure to follow procedures while exiting the site through a radiation monitor on March 9,1997, was I
B-14
o handled effectively; on the ott.er hand, the significance of the March 9,1997 situation was not appreciated until NRC was involved. The February plant wide " stand-downs" are another example where appropriate actions were taken in response to continuing performance errors.
g.
Management's Ability to Coordinate Resolution of Significant issues STATUS:
COMPLETE: Licensee implemented the Recovery Team to monitor and assess effectiveness of corrective actions required for plant restart, h.
Management's Ability to implement Effective Corrective Actions STATUS:
COMPLETE: There are indications that corrective actions have improved.
C.2.2 Management Support a.
Impact of Any Management Reorganization STAT.t)JJ COMPLETE: Management changes immediately after the September 5,1996 event and additional changes based on performance in various areas were taken by IP. Most recently, a new senior level management position was created to ensure appropriate focus on assessment and to maintain corrective actions in the long term. Human performance has improved in the last three months.
b Adequate Engineering Support as Demonstrated by Timely Resolution of issues STATUS:
COMPLETE: A significant issue had been identified in the September 5,1996 event with additional findings by the OSTl.
More recent observations indicate improved support.
Engineering identification of surveillance acceptance criteria deficiencies and additional voltage issues indicate improved engineering support. Current issues associated with Strategic Performance improvement Plan for system assessments has produced positive results.
I c.
Adequate Plant Administrative Procedures j
s STATUS:
COMPLETE: The revised Operability Assessment document was considered good. The new 10 CFR 50.59 implementation j
document was considered adequate. Further, the revised upper tier procedure adherence document and procedure B-15 i
I
a change document removed policy disconnect between expectations and written guidance and were considered to be adequate.
C.3 ASSESSMENT OF PLANT AND CORPORATE STAFF EFFECTIVENESS The licensee's staff must be capable of recognizing and carrying out their responsibilities to ensure public health and safety. Plant and corporate staff effectiveness should be assessed on the basis of the results achieved by the licensee. A proactive attitude toward safety issues should be demonstrated in all aspects of operations. In this regard, the licensee's staff should display attentiveness to duty, fitness for duty, a disciplined approach to activities, a sensitivity for trends in the plant, security awareness, and openness of communications, and a desire for teamwork that supports effective relations between different groups (e.g., management, operations, health physics, maintenance, engineering, security, and contractors).
C.3.1 Assessment of the Licensee's Staff a.
Demonstrated Commitment to Achieving Improved Performance STATUS:
COMPLETE: Improved performance indicates the licensee's staff is more attuned to performance issues. There is still skepticism about long term management commitment on the part of licensee staff. DET scheduled for shortly after unit restart.
b.
Demonstrated Safety Consciousness STATUS:
COMPLETE: Examples indicate improvement in this area; however, there are events continuing which indicates not everyone in the staff is thinking along these lines. DET scheduled for shortly after unit restart.
c.
Understanding of Management's Expectations and Goals STATUS:
COMPLETE: Generally, personnel seem to understand expectations and goals. February "sta. d downs" provided another opportunity for management,to present its expectations. The licensee's staff participate in the discussions. Indications are that staff willimplement management expectations and goals when the expectations are clearly and consistently defined.
d.
Understanding of Plant Issues and Corrective Actions STATUS:
COMPLETE: The licensee's staff understand the issues and corrective actions for the September 5,1996 event.
B-16
Indications are that staff understands the need for additional corrective actions as well, but some examples of resistance to change have been observed by inspectors.
e.
Qualifications and Training of the Licensee's Staff STATUS:
COMPLETE: Training observed by the NRC team was appropriate. No significant qualification or training issues were identified in the Operations Department. Examples of inadequate training of the Maintenance Department staff were noted and cited. Immediate corrective actions were implemented in each case. DET scheduled for shortly after unit restart.
f.
Level of Attention to Detail STATUS:
COMPLETE: Improvements were observed in procedure content and usage. However, some errors were still being made, but not at a level or frequency which created a clear safety concern.
g.
Licensee Staff's Overtime sage STATUS:
COMPLETE: Overtime usage, while high, is within NRC guidelines.
h.
Procedure Usage / Adherence STATUS:
COMPLETE: While there are notable examples of continued problems in this area, there was significant improvement following implementation of new procedural use guidance and a new temporary change procedure at the beginning of April 1997. Current performance is considered adequate.
C.3.2 Assessment of " Corporate" Support (THIS ITEM WAS REMOVED BECAUSE THERE IS NO ' CORPORA TE" SUPPORT ORGANIZA TION. ALL SUPPORT FUNCTIONS ARE ON SITE.)
a.
Corporate Staff Understanding of Plant issues b.
Corporate Staff Site Specific Knowledge c.
Effectiveness of the Corporate / Plant Interface Meetings d.
Corporate involvement with Plant Activities l
e.
Effectiveness of Licensing Support B-17
C.3.3 Operator issues a.
Level of Formality in the Control Room - Crew Consistency STATUS:
COMPLETE: Substantialimprovement observed by the NRC team. While problems of consistency continue to be noted, overall performance is adequate. Performance will be monitored during startup as documented in attachment C of the cover memorandum for this document.
b.
Effectiveness of Control Room Simulator Training STATUS:
COMPLETE: Observed training is effective and addressed NRC concerns.
c.
Control Room / Plant Operator Awareness of Equipment Status STATUS:
COMPLETE: Observations and discussions with operating crews indicates improved awareness of equipment status and examples indicate a more questioning attitude by the operators. A few examples continue to exist where individuals are not fully aware of equipment conditions. Follow-up will be performed as described in Attachment C.
d.
Adequacy of Plant Operating Procedures STATUS:
COMPLETE: Recent reviews by operators have identified a number of procedural corrections and enhancements. Changes are being prioritized based on significance to unit startup.
Additional review were conducted to ensure procedures could be processed under the new guidance on procedure adherence, CPS Procedure 1005.15.
e.
Procedure Usage / Adherence STATUS:
COMPLETE: General procedure adherence in operations has improved. Operators indicate that the old philosophy that procedures provided guidance and could be interpreted loosely has been replaced with a philosophy that procedures are to be performed as written or changed.
f.
Log Keeping Practices STATUS:
COMPLETE: Licensee control room log keeping practices are consistent with the licensee's expectations.
l B-18 l
i C.4 ASSESSMENT OF PHYSICAL READINESS OF THE PLANT The licensee should identify the causes of significant equipment problems and take appropriate corrective actions. Operational testing should verify that each significant equipment problem has been resolved. Testing may need to be expanded to cover complex type problems.
The licensee must be able to demonstrate that all needed safety equipment is operational before restart. Systems and equipment need to be available and aligned. Surveillance tests should be up to date. Maintenance backlogs should be managed at controllable levels and should be evaluated for impact on safe operation. Maintenance personnel must also be capable of responding to equipment failures during startup and operation and should not be hindered by unresolved chronic problems with equipment. Procedures should be adequate and current.
a.
Operability of Technical Specification Systems STATUS:
COMPLETE: Verified through augmented resident staff inspection activities. See also Attachment C.
b.
Operability of Required Secondary and Support Systems STATUS:
COMPLETE: Verified through augmented resident staff inspection activities. See also Attachment C.
c.
Results of Startup Testing STATUS _1 COMPLETE: Verified through augmented resident staff inspection activities. See also Attachment C.
d.
Adequacy of System Lineups STATUS:
COMPLETE: Verified through augmented resident staff inspection activities. See also Attachment C.
e.
Adequacy of Surveillance Tests / Test Program STATUS:
COMPLETE: Being verified through a,ugmented resident staff inspection activities. See also Attachment C.
f.
Significant Hardware issues Resolved (i.e., damaged equipment, equipment ageing, modifications)
STATUS:
COMPLETE: 1. Reactor Recirculation Pump Seal has been replaced; 2. Safety related breakers have been inspected, tested, and/or refurbished; 3. Degraded containment coatings have been removed, re-coated, and pull tested; 4. Main B-19
o control room neon bulb sockets have been replaced: 5.
Licensee requested a TS exemption from NRR for degraded 345 kV line: 6. Licensee was in the process of verifying components in the EDG room qualified to 140*F, equivalent to 112*F outside temp. Licensee answered questions to requests for additionalinformation from NRC.
g.
Effectiveness of the Plant Maintenance Program STATUS:
COMPLETE: Licensee is continuing to assess work practices and control. Initial NRC assessment did not identify any restart issues. However, a recent issue was identified by the NRC on exceeding deadlines for completing safety and non-safety related equipment PMs. A computer program error caused 1,464 PMs deadlines to be exceeded.
h.
Maintenance Backlogs Managed and impact on Operations Assessed STMUS:
COMPLETE: Initial review of maintenance work requests to remain open after plant restart did not identify any significant safety issues. The licensee will address the 1,464 PM backlogs by performing the necessary PMs and/or conducting an engineering evaluation to justify not completing the PMs before plant restart.
i.
Discrepancies Between As-Built Facility and Updated USAR Evaluated STATUS:
COMPLETE: IP compiled list of known USAR discrepancies.
Actions have been taken to change USAR, change facility, or evaluated to ensure no unreviewed safety question exists.
NRC reviewed a sample and did not identify any start up issues.
J.
Degraded But Operable Equipment Evaiuated STATUS:
COMPLETE: IP identified degraded but operable equipment and developed safety evaluations for each cass. Mode restraints were applied for the appropriate equipment. NRC did review a sample of these items, b,efore the electricalissues arose, and did not ldontify any start up issues.
C.5 ASSESSMENT OF COMPLIANCE WITH REGULATORY REQUIREMENTS a.
Applicable License Amendments Have Been issued STATUS:
COMPLETE: licensee requested a License amendment for availability of 345 kV offsite power source and exemption for General Design Criteria 1~7.
B-20
2 b.
Imposed Orders Have Been Modified or Rescinded STATUS:
COMPLETE: No Orders were written.
c.
CAL Conditions Have Been Satisfied STATUS:
COMPLETE: CALs No. Rlli-96-013,97-001, and 97-006 will be closed via a letter from A. Bill Beach, Rlli Regional Administrator to John Cook of IP.
d.
Significant Enforcement issues Have Been Resolved STATUS:
COMPLETE: Enforcement actions associated with September 5,1996 event, radiation protection, feedwater check valves, HPCS, EDG operability, and safety related breaker reliability were issued. Additional examples of apparent violations associated with the administrative l
procedure on procedure usage have not been dispositioned; however, corrective actions have been taken and have been verified to be effective, e.
Allegations Have Been Appropriately Addressed STATUS:
COMPLETE: Special review of outstanding allegations did not identify any startup issues.
l C.6 COORDINATION WITH INTERESTED AGENCIES AND PARTIES a.
Department of Justice: Investigation into Wrongdoing During Unit Shutdown by Office of Investigation (01)
STATUS:
COMPLETE: Two 01 investigations were complete. Letters issued to two individuals for September 5,1996 event, and a determination of no violation due to procedural issues in another event. No further 01 involvement anticipated, and no open actions left.
b.
Appropriate State and Local Officials STATUS:
COMPLETE: IDNS onsite inspector participated in evaluating the completion of the licensee's SRAP ltem.
B 21
l e
ITEM DESCRIPTION LICENSEE NRC ACTION CLOSEOUT NUMBER ACTION STATUS LETTER STATUS 8.1 initial NRC ?::;:= -
N/A Complete N/A B.2 Notifications N/A Complete N/A B.3 Estabheh and Organise NRC review procese N/A Complete N/A B.4.1 Root Causes and Corrective Actione N/A Complete N/A B.4.2 Equipment Demage Aseeeement N/A Complete N/A B.4.3 Determine Reetert leeues and Resolution
- e.
Review / evaluate licensee generated restart issues N/A Complete N/A b.
Independent NRC identification of restart issues N/A Complete N/A c.
NRCAicensee agreement on restart issues N/A Complete N/A d.
Evaluate licensee's restert issues implementation N/A Complete N/A process e.
Evaluate licensee's implementation verification process N/A Complete N/A f.
Obtain NRR Projects input for Action Plan N/A Complete N/A g.
Division Director's approval of Restart Action Plan N/A Complete N/A h.
Implement Action Plan N/A Complete N/A 1.
Modify CAL es necessary N/A Complete N/A B.4.4 Obtain comments on Plan N/A Complete N/A B.4.5 CLO6EOUT ACTIONS K W 5
' 46 e.
Evaluate licensee's restert readiness self-essessment N/A Complete N/A b.
NRC evaluation of applicable items from Section C N/A Comnlete N/A "lSSUES*
c.
Restert issues closed N/A Complete N/A d.
Conduct NRC restert readiness team inspection N/A N/A N/A e.
leave augmented restert coverage inspection plan N/A Complete N/A f.
Comment from other parties considered N/A Complete N/A g.
Determine that all conditions of the CAL have been N/A Coniplete N/A satisfied
- h.
Re-review Generic Restart Checklist N/A Complete N/A n@
B.5 RESTART ACCEPTANCE a.
Prepare Restart Readiness Review and beeis document N/A Complete N/A b.
NRC Restart Panel approves restart readiness review N/A Complete N/A l
B-22
. -. ~..
.. -... ~. - -.. ~.
- - -. - -... _ - -...... ~.
. ~........ - -. -
~
ITEM DESCRIPTION LICENSEE NRC ACTION CLOSEOUT NUMBER ACTION STATUS LETTER STATUS c.
No restert objectione from other applicable HQ offices N/A Complete N/A (NRR, AEOD, etc.)
d.
Regional Adrninistrator Approves Restert Readinees N/A Complete N/A Review S.6 RESTART AUTHORIZATION NOTIFICATION 5?@
a.
Public Affaire (Region)
N/A Cornplete N/A b.
IDNS (Region)
N/A Complete N/A c.
Additional Notification to be considered l
1.
Commission (NRR)
N/A NOT REQUIRED N/A 2.
N/A Complete N/A 3.
Congressional Affaire (NRR)
N/A NOT REQUIRED N/A 4.
N/A NOT REQUIRED N/A l.
i-l l
l l
l 1
l l
l I
j B-23 t
i e
s e
a
i j
1 2
1 1
ITEM DESCRif' TION LICENSEE NRC ACTION CLOSEOUT i
NUMBER ACTION STATUS LETTER l
STATUS i
l C
ISSUES x
4 4
l C.1 ASSESSMENT OF ROOT CAUSE IDENTIFICAT10N AND 9.-$W l
CORRECTION i
C.1.1 Root Cause Assessment 4
1 j
e.
Condition requiring the shutdown are cleerty N/A Complete N/A understood b.
Root Causes of conditions requiring shutdown are N/A Complete N/A i
clearly understood j
c.
Root causes of other significant prot,lerne clearly N/A Complete N/A
{
understood d.
Effectiveness of root cause enelysis program N/A Complete N/A C.1.2 Damage Assessment
/M
+
e.
Damage essessment was thorough and comprehensive N/A Complete N/A b.
Corrective actions cleerty restored system and N/A Complete N/A equipment C.1.3 Corrective Actions Ml '
Mi s.
Thoroughness of the corrective action plan N/A Complete N/A b.
Completeness of corrective action programs for specific N/A Complete N/A root causes c.
Control of corrective action item tracking N/A Complete N/A d.
Effective corrective actions for the conditions requiring N/A Complete N/A the shutdown implemented e.
Effective corrective actions for other problems N/A Complete N/A implement.ed f.
Control of long-term corrective actions N/A Complete N/A g.
Effectiveness of the corrective action verification N/A Complete N/A process i
pr
^
C.1.4 Self. Assessment C;d"::y e.
Effectiveness of Quality Assurance Program N/A Complete N/A b.
Effectiveness of licensee's Independent Review Groups N/A Complete N/A c.
Effectiveness of deficiency reporting system N/A Complete N/A d.
Staff willingness to raise concerne N/A Complete N/A e.
Effectiveness of PRA usage N/A Complete N/A C.2 ASSESSMENT OF LICENSEE MANAGEMENT s
EFFECTIVENESS B-24 m.-
r v-m
-,-,-, n -.,--
n w
s ITEM DESCRIPTION LICENSEE NRC ACTION CLOSEOUT NUMBER ACTION STATUS LETTER STATUS C.2.1 Management Oversight & Effectivenese M
4
<4 e.
Goele and expectatione communicated to the staff N/A Complete N/A 1
b.
Demonstrated expectations of adherence to procedures N/A Complete N/A c.
Management involvement in self ensessment & Indep.
N/A Complete N/A self assessment capabilities d.
Effectivenes.e of management review committee N/A Complete N/A e.
Menegement awareness of day to-day operatiotal N/A Complete N/A concerne f.
Managemente ability to identify and prioritize significant N/A Complete N/A issuee g.
Management's ability to coordinate resolution of N/A Complete N/A significant issues h.
Management's ability to implement effective corrective N/A Complete N/A actione C.2.2 Management support W
r.9m g3 e.
Impact of any management reorganization N/A Complete N/A b.
Adequate engineering support; demonstrated by timely N/A Complete N/A issue resolution c.
Adequate plant administrative procedures N/A Complete N/A C.3 ASSESSMENT OF PLANT AND CORPORATE STAFF A
gp 4
EFFECTNENESS Ti W
4 4
C.3.1 Assessment of Staff
!Ni
,M 4 4QdE5 inn e.
Demonstrated commitment to achieving Improved N/A Complete N/A performance b.
Demonstrated esfety consciousnese N/A Complete N/A c.
Underetending of management's expectatione and N/A Complete N/A goele j
d.
Understanding of plant issues and corrective actione N/A Complete N/A e.
Qualification and training of the staff N/A Complete N/A f.
Level of attention to detail N/A Complete N/A g.
Staff overtime usage N/A Complete N/A h.
Procedure usage /edherence N/A Complete N/A C.3.2 Aseeeement of
- Corporate" support N/A NOT N/A APPLICABLE e.
corporate staff understanding of plant issues N/A NOT N/A APPLICABLE B-25
a ITEM DESCRIPTION UCENSEE NRC ACTION CLOSEOUT NUMBER ACTION STATUS LETTER STATUS b.
Corporate staff site specific knowledge N/A NOT N/A APPUCABLE c.
Effectiveness of corporate / plant interface meetings N/A NOT N/A APPUCABLE d.
Corporate involvement with plant activities N/A NOT N/A APPUCABLE e.
Effectiveness of licensing support N/A NOT N/A APPUCABLE C.3.3 Operator leeues a.
Level of formality in the control room - crew N/A Complete N/A consistency b.
Effectiveness of control room simulator training N/A Complete N/A c.
Control room / plant operator awareness of equipment N/A Complete N/A status d.
Adequacy of plant operating procedures N/A Complete N/A e.
Procedure usage / adherence N/A Complete N/A f.
Log keeping practices N/A Complete N/A
^'
C.4 ASSESSMENT OF PHYSICAL READINESS OF THE
^
PLANT a.
Operability of technical specification systems N/A Complete N/A b.
Operability of required secondary and support systems N/A Complete N/A c.
Results of pre-startup testing N/A Complete N/A l
d.
Adequacy of system lineups N/A Complete N/A e.
Adequacy of surveillance tests / test program N/A Complete N/A f.
Significant hardware issues resolved N/A Complete N/A g.
Effectiveness of the plant maintenance program N/A Complete N/A h.
Maintenance backlog rranaged and impact on N/A Complete N/A operations assessed l
I 1.
USAR discrepancies evaluated N/A Complete N/A j
j, Degraded but operable equipment evaluated N/A Complete N/A C.S ASSESSMENT OF COMPUANCE WITH REGULATORY n
g
)
REQUIREMENTS a.
Applicable license amendments have been issues N/A Complete N/A l
(Offsite power availability & GDC 17 partial exemption) i b.
Imposed Orders have been modified or rescinded N/A Not Applicable N/A B-26
j 1
ITEM DESCRIPTION UCENSEE NRC ACTION CLOSEOUT l
NUMBER ACTION STATUS LETTER STATUS c.
Confirmatory Action Letter (s) conditions have been N/A Complete N/A satisfied d.
Significant enforcement issues have been resolved N/A Complete N/A e.
Allegatione have been opproprietely addressed N/A Complete N/A C.6 COORDINATION WITH INTERESTED AGENCIES AND PARTIES s.
Department of Justice Olinvestigations into wrong N/A Complete N/A doing during unit shutdown b.
Appropriate State sad Local officials: IDNS N/A Complete N/A 1
l i
i B-27 i
i
- - ~ _ ~. -...
e l
i ITEM DESCRIPTION LICENSEE NRC ACTION CLOSEOUT NUMBER ACTION STATUS LETTER STATUS l.1 Adequacy of policy statemente and general procedures Verified dosed by panel IR 50-regarding conduct of operations and procedure
- complete, 5/8 461/97012 compliance considered effective 1.2 Seminer on procedure compliance Verified Closed by panel IR 50
- complete, S/8 461/97012 considered effective 1.3 Special procedure review for selected topics Verified Closed by panel IR 50-Complete 4/28 461/9701,2 1.4 Simulator practice for operating crews Verified Closed by penel IR 50-Complete 4/28 461/97012 1.5 Revised Critique process Verified Qosed by panel IR 50-Complete 6/3 461/97012 1.6 Procedure compliance seminers Verified Closed by panel IR 50-
- complete, 6/3 461/97012 considered effective 1.7 New fuel procedures Verified Closed by panel IR 50-Complete 4/28 461/97012 1.8 Monitor Procedure compliance Verified Closed by penel IR 50-
- complete, 5/22 461/97012 considered effective 1.9 Evoluete procedure process Verified Closed by panel IR 50-
- complete, 5/14 461/97012 considered effective 1.10 Review sys ops procedures -
Verified Closed by panel IR 50-Complete 5/14 461/97012 1.11 Review Surv. procedures Verified Closed by panel IR 50-
- complete, 5/14 461/97012 considered effective 1.12 Review rendom semple Verified Closed by panel IR 50-Complete 4/28 461/97012 1,13 Review comment control fme Verified Closed by panel IR 50-Complete 4/28 461/97012 1.14 Assess personnel qualifications Verified Closed by panel IR 50-Complete 5/14 461/97012 1.15 Review temp proc. changes Verified Closed by panel IR 50-Complete 4/28 461/97012 1.16 Obsorve surv. proc. usage Verified Closed by panel IR 50-Complete 4/28 461/97012 B-28
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ITEM DESCRIPTION LICENSEE NRC ACTION Ct.OSEOUT NUMBER ACTION STATUS LETTER STATUS l.17 10 CFR 50.59 training Actions Closed by panel IR 50-
- verified, 5/22 461/97012 l
considered complete l.18 Review all Standing Orders against the 10 CFR 50.59 Verified Closed by panel IR 50-l screening process. (new item added by licensee Complete 5/22 461/97012 4/1/97) l.19 Review Surveillance Procedures for fidelity with Verified Closed by panel IR 50-Technical Specifications and USAR, Complete 6/3 461/97012 l
- 11. 1 Define & doo. conservative decision expectations Verified Closed by panol IR 50-Complete 4/28 461/97012
- 11. 2 Conservative decision maidng serninar Verified Closed by panel IR 50-Complete 4/28 461/97012
!!.3 Plant & equip condition limits Verified Closed by panel IR 50-Complete 4/28 461/97012 ft.4 Recognition & Acceptance of errors by 9.5.96 crew Verified Closed by panel IR 50-Complete 6/3 461/97012 l1.5 Plant Manager will meet with each crew Verified Closed by panel IR 50-Complete 6/3 461/97012
- 11. 6 Additional plant / equipment condition limits Verified Closed by panel IR 50-Complete 5/8 461/97012 1
- 11. 7 Review April 1996 incident Verified Closed by panet IR 50-
- complete, 5/22 461/97012 i
considered effective
- 11. 8 Review SOER 9210 Reducing event through H.P Actions Closed by panel IR 50-verified 5/22 461/97012
- complete, but not ready ll.9 Simulator Restart Training Verification Closed by panel IR 50-Complete 4/28 461/97012 111. 1 Review of oversight personnel roles, duties, &
Verification Closed by panel IR 50-expectations Complete 4/28 461/97012 111. 2 Oversight personnel roles, duties, & expectations Verification Closed by panel IR 50-briefing Complete 4/28 461/97012 111. 3 Control room monitoring during startup Verification Partial Closure IR 50-in progress 5/22, review 461/97012 through during startup startup 111. 4 Startup hold points Verification Closed by panel IR 50-j Complete 5/22 461/97012 l
l lli.5 Monitor operational decision making Verification Closed by panel IR 50-Complete 5/22 461/97012 B-29 l
o ITEM DESCRIPTION LICENSEE NRC ACTION CLOSEOUT NUMBER ACTION STATUS LETTER STATUS 111. 6 Oversight responsibility briefings Verification Closed by panel IR 50-Cornplete 4/28 461/97012 til.7 Senior Management Team self-critique Verification Closed by panel IR 50-Complete 4/28 461/97012 ll1.8 Lower threshold to initiate assessments Verification Closed by panel IR 50-Complete 5/22 461/97012 111. 9 Monitor Effectiveness of Corrective Actions Verification Closed by panel IR 50-Complete 6/3 461/97012 111. 1 0 Corrective Actions for the Work Control Program Verification Closed by panel IR 50-Complete 6/3 461/97012 IV.1 Recirc. B. seal replacement Considered Partial Closure IR. 50-
- complete, 5/14, pending 461/97012 but will PMT during remain open Startup pending PMT during startup IV.2 Drywell floor drain monitor Verification Closed by panel IR 50-Complete 4/28 461/97012 IV.3 Drywell equipment drain monitor Verification Closed by panel IR 50-Complete 4/28 461/97012 IV.4 Review outstanding MWRs Verification Closed by panel IR 50-
- complete, 5/22 461/97012 considered effective IV.5 RF leakage detection systems Verification Closed by panel IR 50-Complete 6/3 461/97012 IV.6 Leak detection added to process computer Verification Closed by panel IR 50-In Progress 5/22 461/97012 IV.7 Quarterly monitoring of material deficiencies by senior Verified Closed by panel IR 50-mors.
- complete, 5/8 461/97012 considered effective IV.8 Review 95 & 96 NRC reports on material condition Actions Closed by panel IR 50-verified 5/22 461/97012
- complete, but not ready IV.9 Operability / Generic Letter 91 18 Verification Closed by panel IR 50-Complete 5/22 461/97012 IV.10 Action plan reviews Verification Closed by panel IR 50-Complete 4/28 461/97012 IV.11 Butterfly valve seismic concerns Verification Closed by panel IR 50-Complete 5/8 461/97012 B-30 i
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ITEM DESCRIPTION LICENSEE NRC ACTION CLOSEOUT NUMBER ACTION STATUS LETTER STATUS IV.12 Review MWRs older than 6 months Verification Closed by panel IR 50-
- Complete, 5/22 461/97012 considered offactive IV.13 Feedwater check valves Will remain Partial Closure IR 50-open until 5/14, pending 461/97012 after startup Post Startup Review IV.14 GL. 96.06 Verification Closed by panel IR 50-In Progress 5/22 461/97012 IV.15 AR/PR system as an effective tool Verification Closed by panel IR 50-Complete 5/22 461/97012 l
IV.16 Operator workaround review Verification Closed by panel IR 50-Complete 6/3 461/97012 IV.17 Main control room deficiencies Verification Closed by panel IR 50-Complete 6/3 461/97012 1
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Attachment C Startuo inspection Plan Docket No. 50-461 Inspection Report 97016 A.
Puroose of Insoection Provide 24-hour coverage of start-up activities in order to evaluate the effectiveness of licensee corrective actions involving procedure adherence, communications, compliance with Technical Specifications, maintenance work practices, operability determinations, temporary modifications, and radiological work practices.
B.
Insoection Team Membershio The lead inspector is Troy Pruett. There will be 2 inspectors per 8-hour shift.
7AM-3:45 Pruett and Collins /C. Brown 3PM-11:45 Stasek and Ray /F. Brown 11 PM-7:45 AM Campbell and Stoedter Team members should understand that anticipated coverage is seven days a week for up to two weeks. Replacement inspectors will need to be identified for any individual breaks in coverage C.
General Information Inspectors are expected to provide written comments, at least once per shift, in a common log regarding the activities observed and areas where additional inspection effort should be directed. The shift lead is expected to assess the activities in progress and adjust plant observations to best utilize inspection resources (e.g.,
continuous control room observations need not be performed if it is more beneficial to observe maintenance / surveillance activities). Daily input of inspection observations to Region til management is expected.
Report input in Manual Chapter (MC) 0610 format is due within 1 week following the end of start-up observations. Round-the-clock startup coverage will be provided generally in the period from prior to rod pull to full power.
Inspection MCs 71715,71707,71750,61726,62707, and 37551 will be used to perform inspection activities. Inspection hours are to be charged to regional initiative.
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l D.
Functional Area Insoection Activities The following elements within each functional area represent the minimum activities that should be evaluated. Additional items described in the inspection Manual Chapters should be performed at the discretion of the shift lead.
1.
Ooerations a.
Assess ability of personnel to implement procedural requirements.
b.
Evaluate the effectiveness of communications and control room formality.
c.
Verify compliance with Technical Specifications, d.
Assess implementation of operability determination program.
j e.
Verify mode restraints are completed prior to changing operational modes.
f.
Evaluate the ability of personnel to evaluate the condition of plant equipment on operability.
g.
Independently verify the adequacy of selected valve and breaker lineups.
h.
Assess log keeping practices of Reactor Operator, Senior Reactor Operator, and Non-Licensed Operator, l.
Observe recirculation pump shifts, and pump seal performanco in general.
J.
Observe performance of drywellleakage detection systems.
k.
Assess operator knowledge of system modifications installed during Refueling Outage 6.
l.
Assess procedure adequacy for routine operating evolutions.
m.
Determine Operations' ability to make appropriate procedure changes in a timely manner when procedures cannot be performed as written.
2.
Maintenance a.
Evaluate the effectiveness of maintenance work practices.
b.
Determine if equipment is preconditioned prior to the performance of testing.
c.
Assess ability of personnel to implement procedural requirements.
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.a s
e-e d.
Monitor the extent of on-line maintenance.
Verify surveillance testing fulfills the Technical Specification requirements e.
and is in accordance with design basis information from the Updated Safety Analysis Report.
3.
Enaineerina Assess the impact of temporary modifications on the licensing and design a.
basis of the facility.
b.
Evaluate engineering input provided to operations (especially operability determinations) and maintenance (especially root cause and trending of degraded equipment) departments.
Observe interaction between nuclear engineering and operations during start-c.
up.
4.
Plant suooqrt Determine effectiveness of postings as radiological conditions change.
a.
b.
Ensure radiation work permit requirements ere understood and followed by radiation workers and enforced by health physics technicians and first line supervisors.
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