IR 05000302/1994007
| ML20029E266 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 04/19/1994 |
| From: | Butcher R, Cooper T, Landis K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20029E258 | List: |
| References | |
| 50-302-94-07, 50-302-94-7, NUDOCS 9405180068 | |
| Download: ML20029E266 (17) | |
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UNITED STATES
[p* Rfouq'o&
NUCLEAR REGULATORY COMMISSION
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REGloN 11
$
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101 MARIETTA STREET, N.W., SUITE 2900 3g,
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4j ATLANTA, GEORGIA 30323 0199
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Report No.:
50-302/94-07 Licensee:
Florida Power Corporation 3201 34th Street,-South St. Petersburg, FL 33733 Docket No.:
50-302 License No.: DPR-72
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Facility Name:
Crystal River 3
Inspection Conducted: March 5 tirough April 1, 1994 Inspector:
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4- / 7 ~4 R. Butcher, Senior Resident Inspector Date Signed Inspector:
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- - /9 - 9M T. Cooper, Resident Inspector Date Signed l
Approved by: I
%-/9M K. Landis, Section Chief Date Signed Division of Reactor Projects SUMMARY Scope:
This routine inspection was conducted by the resident inspectors in the areas of plant operations, radiological controls, security, surveillance observations, maintenance observations, preparation for refueling, and self assessment. Numerous facility tours were conducted and facility operations e,oserved.
Backshift inspections were conducted on March 8, 12, 15, 16, 19, 20, 21, 22, 23, 24, 30. and April 1.
Results:
Within the scope of this inspection, the inspectors determined that the licensee continued to demonstrate satisfactory performance to ensure safe plant operations. One violation was identified concerning three examples of failure to follow procedures resulting in mispositioned valves. One Inspection Followup Item was identified.
50-302/94-07-01, Violation.
Three examples of failure to follow procedures resulting in misposit.ioned valves. (paragraph 3.a, 5.a, and 5.b)
50-302/94-07-02, Inspection Followup Item. Operators entered Technical Specification 3.0.3 to perform a surveillance. (paragraph 3.a)
9405180068 940421 PDR ADOCK 05000302 O
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During this inspection period, the inspectors had comments in the following Systematic' Assessment of Licensee Performance functional areas-H Plant Operations.
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The removal of the A train decay heat pump to perform non-critical maintenance while the B train of the nuclear services closed cycle cooling system was in a scheduled system outage is considered undesirable and poor practice. (paragraph 5.a)
The comprehensive pretest briefing in the control room and the conduct of simulator runs prior to main steam safety valve testing to determine expected plant response were considered good practices. (paragraph 4)
Fuel receipt was conducted in a professional manner and was well controlled. (paragraph 7)
Maintenance / Surveillance:
Testing of the main steam safety valves was conducted in a professional and controlled manner.
Communications with the control room were very good. (paragraph 4)
Other Comments:
The Nuclear General Review Committee subcommittee reports were very thorough and questioned events in great detail.
This is considered a strength.
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REPORT DETAILS 1.
Persons Contacted Licensee Employees G. Boldt, Vice President Nuclear Production R. Davis, Manager, Nuclear Plant Maintenance G. Halnon, Manager, Nuclear Plant Operations
- B. Hickle, Director, Nuclear Plant Operations W. Marshall, Nuclear Shift Manager
- P. McKee, Director, Quality Programs
- R. McLaughlin, Nuclear Regulatory Specialist B. Moore, Manager, Nuclear Integrated Scheduling
- W. Rossfeld, Manager, Site Nuclear Services
- H. Walker, Manager, Nuclear I&C Shop
- R. Widell, Director, Nuclear Operations Site Support
- K. Wilson, Manager, Nuclear Licensing Other licensee employees contacted included office, operations, engineering, maintenance, chemistry / radiation, and corporate personnel.
NRC Resident Inspectors
- R. Butcher, Senior Resident Inspector T. Cooper, Resident Inspector Other NRC Personnel on Site
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I. Selin, Chairman, Office of the Commission K. Landis, Section Chief, Branch 2B, Region II H. Berkow, Director,-Project Directorate II-2, NRR H. Silver, Senior Project Manager, Project Directorate 11-2-2, NRR L. Raghavan, Project Manager, Project Directorate 11-2-2, NRR T. Cerovski, Technical Reviewer, NRR/ECGB
- Attended exit interview
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Acronyms and initialisms used throughout this report are listed in the last paragraph.
2.
Plant Status At the beginning of this reporting period, Unit 3 was operating at 100%
power and had been on line since September 20, 1993. The following evolutions occurred during this assessment period:
On March 28, 1994, at 2:00 a.m. a power reduction to approximately 77%
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Reactor power was reduced in preparation for retubing of the C and U waterboxes.
The D waterbox and CWP-D were j
removed from service.
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After plant stabilization was achieved, on March 28, 1994 day shift,
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reactor power was increased to approximately 87% power.
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The D waterbox was returned to service and the C waterbox was removed
for outage preparation.
Reactor power was reduced to approximately 77%-
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Plant Operations (71707 & 93702)
Throughout the inspection period, facility tours were conducted to observe operations and maintenhnce activities in progress.
The tours
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included entries into the protected areas and the radiologically controlled areas of the plant.
During these inspections, discussions were held with operators, health physics and instrument and controls
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technicians, mechanics, security personnel, engineers, supervisors, and plant management.
Some operations and maintenance activity observations were conducted during backshifts.
Licensee meetings were attended by the inspector to observe planning and management activities. The inspections confirmed FPC's compliance with 10 CFR, Technical Specifications, License Conditions, and Administrative Procedures.
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Operations
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The MVP-lC was taken out of service at 12:38 a.m. on March 8, l
1994. The main objective for the MUP-lC on-line system outage was to reduce pump vibration to within the normal range.
Pre-outage vibration readings were in the observation range indicating possible misalignment.
In addition to the alignment concerns, past maintenance had identified what may be excessive bearing clearance on the high speed gear drive output shaft. Also, based on recent MVP-1C gear drive oil analysis, an increase in large and small direct reading ferrography levels, although not to a point of concern further supported the need to perform the proposed internal gear drive inspections. Other maintenance and MAR work will be accomplished during this outage.
TS 3.1.2.4.1 requires in modes 1, 2 and 3 that two make-up pumps be operable.
Since MUPs IA and IB were operable, no LC0 was applicable for taking the MVP-lC out of service.
For accessible equipment, the inspectors verified the inplant tagging order (94-03-039) was properly hung and verified.
MVP-lC was returned to service March 10, 1994.
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At 3:30 p.m. on March 11, 1994, the control room received Inverter
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Trouble and Inverter Bypassed alarms. A visual inspection indicated that inverter VBIT-1A was dead with no output.
VBIT-1A supplies 120 VAC vital power for vital instrumentation and control l
functions powered from 120 VAC vital bus A.
The loss of inverter
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VBIT-1A resulted in the automatic transfer of the A bus to I
transformer VBTR-4A. Apparently the transfer switch did not I
transfer quickly enough to prevent some ES relays from actuating but no ES bistables tripped. The operators reset the ES relays.
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The operators entered TS action statement 3.8.2.1.b which states that with transformers, supplied from a single ES train, powering one or two vital busses, operation may continue provided the remaining vital busses are powered from inverters.
At 12:00 a.m. on March 12, 1994, the ITS were implemented.
ITS action statement 3.8.7.A states that in modes 1, 2, 3 or 4, with one or two inverters on one train inoperable, restore the inverter to operable status within seven days.
Parts were obtained from the non-vital inverter VBIT-1E and VBIT-1A was returned to service at 1:00 p.m. on March 16, 1994.
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On March 12, 1994, when operations attempted to start BSP-1A, following maintenance on BSV-28, no flow was observed and low running amperage for the pump motor was identified. The pump was shut down after approximately one minute of attempted operation.
Upon investigation, DHV-18 was found closed, isolating the pump recirculation flow to the BWST.
It was discovered that this valve had been closed for approximately one day. The clearance which released the building spray pump to Operations for testing left valve DHV-18 in the closed position instead of the required open position. This valve was not listed in the BS system procedure and the operations personnel developing the clearance request did not review the DH system procedure, OP-404, Decay Heat Removal i
System, which required the valve to be open.
This failure to follow procedures in properly aligning safety-related valves will j
be tracked as the first example of violation 50-302/94-07-01:
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Failure to Follow Procedure Resulting in Mispositioned Valves.
As corrective actions, the licensee has included DHV-18 in the BS system procedure and has placed copies of the system operations procedures at the desk of the operator responsible for filling out the clearances. These occurrences are being cited, due to recurring problems with mispositioned valves, further examples of which are discussed in paragraphs 5.a and 5.b.
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At 10:05 p.m. on March 15, 1994, the operators entered ITS 3.0.3 during the performance of SP-340F, MVP-1C and Valve Surveillance.
The plant was operating at 100% reactor power with MVP-1A and MVP-1B designated the ES MVPs. MVP-1A was powered from the A 4160V ES bus and MVP-1B was powered from the B 4160V ES bus. A system outage on MVP-1C was completed and performance of SP-340F was required to return MVP-1C to operable status. While performing SP-340F for MVP-1C, the licensee was also performing a quarterly stroke test of MUV-25 and MUV-26.
MUV-25 is the HPI isolation valve to RCS loop B1 and MUV-26 is the HPI isolation valve to RCS loop B2.
SP-340F, dated April 1, 1993, step 4.1.2 requires MUV-3, MUP-1C to MVP-1B discharge cross connect, be closed.
This action placed the HPI System in a configuration where three independent
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injection paths into the RCS were not available, j
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ITS 3.5.2, ECCS - Operating, requires in modes 1, 2 and 3 that two ECCS trains be operable. The basis for ITS 3.5.2'further defined what comprised an HPI train.
Not all portions of the HPI System satisfy the required independence criteria.
Specifically, the HPI System downstream of the HPI/ Makeup pumps is not separable into
two distinct trains, and is therefore, not independent. This conclusion was based upon analysis which shows injection flow is required through a~ minimum of three (3) injection legs in the event of a postulated break in the HPI piping. When considering the impact of inoperabilities in this portion of the system, the o
same concept of maintaining single active failure protection must be applied.
When components become inoperable, an assessment of the HPI system's ability to perform its safety function must be
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performed.
If the system can continue to perform its safety
function, without assuming a single active failure, then the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> loss of redundancy Action Statement is appropriate.
If the
inoperability renders the system, as is, incapable of performing
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its safety function, without postulating a single active failure, then the plant is in a condition outside the safety analysis and must enter LC0 3.0.3 immediately.
The flow path for each train must maintain its designed degree of independence to ensure that
no single active failure can disable both ECCS trains.
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does not caution the operators that shutting MUV-3 while in modes
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I, 2 and 3 would place the HPI System in an LC0. lhe operators recognized that they had entered ITS 3.0.3 and did not violate ITS..The total time the plant was in this condition was twenty
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minutes and the operator was. aware that MUV-3 could be opened if necessary to restore the required flow path.
The cover letter for NRC IR 50-302/92-27 requested additional information regarding violation 50-302/92-27-02 which involved the failure to comply with a TS action statement when equipment required by TS was rendered inoperable by surveillance activities.
The practice of not complying with TS action statement requirements when performing surveillance activities is not-consistent with the guidelines of'GL 91-18. The licensee's reply to this issue was included as attachment 2 to their letter and stated, in part, the following:
The NRC, in GL 91-18, communicated to licensees two chapters of the Inspection Manual that deal with operability assessments and several related topics.
The positions contained in the guidance, including the requirement to enter ACTION statements during the performance of TS required surveillance activities, were expressly recognized to potentially raise backfitting issues for certain licensees.
FPC is one of those licensees.
FPC requests that this issue be deferred until after implementation of the CR-3 ITS later this year. At that
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time, FPC is willing to voluntarily change its practice to require entry except where the TS specifically acknowl~ edge
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the impracticality of doing so.
The reason for suggesting this course of action is that the existing surveillance procedures are not written to facilitate determining which portions render specific TS controlled structures, systems, and components inoperable.
While this could be accomplished, the methodology for accomplishing many surveillances would need to be changed to accommodate the arbitrary time limits imposed by current STS based'TS.
These same procedures will be undergoing significant revisions as part of ITS implementation and, thus, would need to be significantly changed twice over a very short period of time.
Doing so is inconsistent with high quality procedure content.
Further, many A0T have been expressly modified to accommodate this new NRC position in the generic ITS development process and others will be appropriately modified in the ongoing lead plant efforts.
The SP had not been updated to facilitate the impact of the ITS.
The licensee is reviewing their reply to violation 50-302/92-27-02 in that their intent was not to revise every surveillance procedure to specifically caution the operators when they might need to enter ITS action statements. The operators are expected to be_ aware of actions that will place them in LCOs. The licensee is preparing an LER in regard to this event and the inspectors will follow the licensees corrective actions when the LER is issued.
This will be tracked as IFI 50-302/94-07-02, Operators Entered TS 3.0.3 to Perform a Surveillance.
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At 1:35 p.m. on March 16, 1994, SWP-1B was removed from service for a system outage.
The primary reason for this' outage was to replace degrading expansion joints and repair various system
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leaks. AI-255, System Outage Scheduling and Implementation, requires the system manager make a determination of a safety benefit for an on-line system outage and provide written justification.
The Manager, Nuclear Plant Operations must concur
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in the proposed system outage and final approval by the Director,
Nuclear Plant Operations is required.
The inspectors reviewed the i
determination of a safety benefit where the licensee determined a system outage was justified.
ITS 3.7.7, Nuclear Services Closed Cycle Cooling Water (SW)
System, action A states that in modes 1, 2, 3, and 4 with one emergency SW pump inoperable, restore the SW sys;.em to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The SWP-1B was returned to service at
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3:00 a.m. on March 18, 1994.
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At 1:35 p.m. on March 16, 1994, SWP-18 was removed from service for a system outage.
SWP-1B was returned to service at 3:00 a.m.
on March 18, 1994.
During the time SWP-1B was out of service, the DHP-1A was removed from service.
DHP-1A was removed from service at 2:00 p.m. on March 17, 1994, and. returned to service at 4:45 p.m. on March 17, 1994.
DHP-1A was removed from service to j.
support installation of replacement temperature control circuitry l
(DC-17-TT) and subsequent testing. The replacement of the
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temperature control circuitry was not a critical maintenance task that needed to be performed immediately.
It is considered poor practice to remove a safety system from service to perform non-emergency maintenance while another opposite train safety system i
is out of service for planned maintenance.
The inspectors l
discussed this concern with the shift manager and the NSS, and although the NSS was well aware of all aspects of the maintenance and readily knew what manual actions would be required to recover the DHP system, it is not considered a desirable plant condition.
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On March 22, 1994, at 6:40 a.m. the EFP-2 was removed from service
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to accomplish PMs.
Oil analysis results indicated a need to change oil in both the turbine and the pump.
Calibration of EF-198-TI was scheduled concurrently. Action B.1 of ITS 3.7.5 was entered at that time.
Action B.1 of ITS 3.7.5 states that in modes 1, 2 and 3 with one EFW train inoperable (for reasons other l
than one steam supply to the turbine driven EFW pump being inoperable), restore the EFW train to operable status with;. 72
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hours. The plant was in mode 1 at 100% power.
The inspectors reviewed the licensees documentation of determination of a safety benefit for performing an on-line system
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outage.
This determination is required by AI-255, System Outage Scheduling and Implementation.
As noted above, the lubrication L
analysis report for EFP-2 dated January 14, 1994, indicated the
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turbine and pump bearing oils should be replaced.
On March 22, 1994, at 5:40 p.m. the EFP-2 was returned to service and ITS 3.7.5, Action B.1 was exited.
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On March 23, 1994, at 1:00 a.m. the licensee removed the B ECCS train from service for a system outage. The A ECCS train was verified operable prior to removal of the B ECCS train.
The main reason for this system outage was to repair leaks, implement a linkage modification for DHV-7, and shoot and clean DCHE-18.
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following ITS action items were entered:.
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Comoonent ITS &
Date Date Returned Condition 00S to Service DHP-1B 3.5.?
3/23/94 3/25/94 Cond. A 1:00 a.m.
6:00 p.m.
BSP-1B 3.6.6 3/23/94 3/25/94 Cond. A 1:00 a.m.
6:00 p.m.
DCP-1B 3.7.8 3/23/94 3/25/94 Cond. A 1:00 a.m.
7:30 a.m.
RWP-38 3.7.10 3/23/94 3/25/94 Cond. A 1:00 a.m.
7:30 a.m.
Each of the above action statements put the plant in a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> time constraint for modes 1, 2, 3, and 4.
The plant was at 100%
power in mode 1.
The inspectors reviewed the B ECCS train system outage justification letter to the Manager, Plant Operations and verified the licensee made a safety benefit determination as required by AI-255, System Outage Scheduling and Implementation.
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The inspectors reviewed the licensee's process for controlling the use of excessive amounts of overtime.
Generic communications; including NRC Information Notice 91-36, Nuclear Plant Staff
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Working Hours, NRC GL 82-12, Nuclear Power Plant Staff Working Hours, NRC GL 82-16, NUREG-0737 Technical Specifications, NRC GL 83-02, NUREG-0737 Technical Specifications, and NRC GL 83-14, Definition of ' Key Maintenance Personnel', were reviewed and compared to licensee requirements.
No requirements for overtime control had been incorporated into the original CR-3 Technical Specification requirements.
Licensee procedures, AI-100, Facility Administrative Policies, and AI-500, Conduct of Operations, both address control and restrictions on overtime.
Both procedures contain limitations in line with the requirements discussed in the NRC generic communications. Al-500 includes an enclosure which documents approval for personnel working overtime in excess of the limits. AI-100 requires that permission be granted by the appropriate levels of management, but does not require that the documentation of the approval be retained.
Therefore, even though some approval memorandums have been located, detailed records have not been maintained, outside of the operations department.
The introduction of the ITS included (in paragraph 5.2.2.e) a requirement to establish and adhere to a program to control overtime. At present, the licensee is working to develop forms which will provide documentation of approvals.
Licensee QA has planned to include overtime reviews in various departmental audits in the futur _
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b.
Radiological Protection Program Radiation protection control activities were observed to verify that these activities were in conformance with the facility policies and procedures, and in compliance with regulatory requirements.
These observations included:
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Entry to and exit from contaminated areas, including step-off pad conditions and disposal of contaminated clothing;
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Area postings and controls;
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Work activity within radiation, high radiation, and contaminated areas;
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RCA exiting practices; and
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Proper wearing of personnel monitoring equipment, protective clothing, and respiratory equipment.
The implementation of radiological controls observed during this inspection period were proper and conservative.
c.
Security Control In the course of the monthl: activities, the inspector included a review of the licensee's physica; security program. The performance of various shifts of the security force was observed in the conduct of daily activities to include:
protected and vital areas access controls; searching of personnel, packages, and
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vehicles; badge issuance and retrieval; escorting of visitors; patrols; and compensatory posts.
In addition, the inspector observed the operational status of protected area lighting, protected and vital areas barrier integrity, and the security organization interface with operations and maintenance.
No performance discrepancies were identified by the inspectors.
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Fire Protection Fire protection activities, staffing, and equipment were observed to verify that fire brigade staffing was appropriate and that fire alarms, extinguishing equipment, actuating controls, fire fighting equipment, emergency equipment, and fire barriers were operable.
One violation (first example) was identified.
4.
Surveillance Observations (61726)
The inspectors observed TS required surveillance testing and verified that the test procedures conformed to the requirements of the TSs; testing was performed in accordance with adequate procedures;. test instrumentation was calibrated; limiting conditions for operation were met; test results met acceptance criteria requirements and were reviewed by personnel other than the individual directing the test; deficiencies were identified, as appropriate, and were properly reviewed and resolved by management personnel; and system restoration was adequate.
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completed tests, the inspectors verified testing frequencies were met and tests were performed by qualified individuals.
The inspectors witnessed / reviewed portions of the following test activities:
- SP-ll3, Power Range Nuclear Instrumentation Calibration;
- SP-130, Engineered Safeguards Monthly Functional Test;
- SP-353, Control Room Emergency Ventilation System and RM-A5 Monthly
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Test;
- SP-650, ASME Code Safety Valves Test; and
- FP-302, New Fuel Assembly Unloading, Inspection, Storage, and
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Container Reclosing.
The following item was considered noteworthy.
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On March 29, 1994, the licensee initiated lift setpoint testing of nine of the main steam safety valves per SP-650, ASME Code Safety Valves Test.
CR-3 uses Dresser Industries main steam safety valves.
The main steam safety relief valves are in a series of i
four with four valves per MS line.
Each valve in the series will open at the valves increasing pressure setpoint as follows:
1050 psig, 1070 psig, 1090 psig, and 1100 psig. By accomplishing the setpoint tests with the valves in place and at normal operating temperature and pressure, the effects of temperature induced variations in setpoints is minimized. The plant was at approximately 87% reactor power during this testing.
Prior to the testing, on March 28, 1994, the licensee conducted simulator runs to determine the effects to be expected if a main steam safety valve were to fail open (for any reason) during setpoint testing.
Simulator results indicated an expected 6% pcwer increase and no unusual transients. The inspectors attended a pre-test briefing that was held in the control room. The NSS discussed test objectives, required communications, possible problems and responsibilities with operations and maintenance personnel.
The comprehensive pre-test briefing and the use of the simulator to determine if there were any unusual consequences if a main steam safety valve were to inadvertently stick open during testing were considered a strength. During MSV testing, the tests were conducted in a professional and controlled manner with close communications maintained with the control room.
The inspectors determined that the above testing activities were performed in a satisfactory manner and met the requirements of the TSs.
Violations or deviations were not identifie..
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5.
Maintenance Observations (62703)
Station maintenance activities of safety-related systems and components were observed and reviewed to ascertain they were conducted in accordance with approved procedures, regulatory guides, industry codes and standards, and in conformance with the TSs.
The following items were considered during this review, as appropriate:
LCOs were met while components or systems were removed from service; approvals were obtained prior to initiating work; activities were accomplished using approved procedures and were inspected as applicable; procedures used were adequate to control the activity; troubleshooting activities were controlled and repair records accurately reflected the maintenance performed; functional testing and/or calibrations were performed prior to returning components or systems to service; QC records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were properly implemented; QC hold points were established and observed where required; fire prevention controls were implemented; outside contractor force activities were controlled in accordance with the approved QA program; and housekeeping was actively pursued.
The inspectors witnessed /revicwed portions of the following maintenance activities in progress:
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WR NU 0317216, Pump Aligament Checks on SWP-1B; and
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WR NU 0273949, Repair Body to Bonnet Leak on DHV-7.
The following items were considered noteworthy.
a.
Wnile making a routine tour of the diesel generator room, on March 17, 1994, the auxiliary building operator observed that DFV-2, the drain line isolation valve for EDG-A fuel. day tank, was open.
After conferring with the plant chief operator, it was determined that this valve should be in the closed position as noted in proce ure OP-707, Operation of the ES Emergency Diesel d
Generators.
The operator closed the valve and verified that all the other valves for both day tanks were in their proper positions.
The valve DFV-2 is the safety-related isolation valve on the fuel oil day tank, but there are two, parallel, non-safety related isolation valves down stream of this valve.
The auxiliary building operator verifieu ihat both of these valves were in the closed position and that the day tank level was normal.
Investigation determined that the I&C shop had been performing trouble-shooting of the DF-2-LS level switch, per WR 0317684, by opening DFV-2 and allowing the tank level to decrease. The licensee surmises that the valve was left open following the
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maintenance on this component, which was performed March 14, 1994.
The EDG was not determined to be inoperable, by the licensee, since they stated the two valves downstream were both in the closed position.
However, seismic qualification of EDG fuel oil piping ended at the DFV-2 valve.
The two downstream valves are neither safety-related or seismic qualified valves.
This is the second example of violation 50-302/94-07-01, Failure to Follow Procedures Resulting in Mispositioned Valves.
b.
On March 17, 1994, while troubleshooting a starting problem with control complex chiller lA (CHHE-1A), it was identified that the isolation valve (no valve number) to CH-378-PT, was isolated.
This pressure transmitter controls the position for the CHV-68 valve, the control valve for nuclear services closed cycle cooling water to the chiller.
Investigation determined that the valve had baen closed on March 15, 1994, during the performance of SP-169F, Miscellaneous Switch Interlock with Tech Spec Equipment.
The procedure required that the valve be closed for the calibration, but reopened as part of the restoration.
Failure to do so
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rendered the CHHE-1A chiller inoperable.
The requirement that the control room ventilation system control temperature of the control l
room was deleted from TS upon issuance of the ITS. This is the third example of violation 50-302/94-07-01, failure to Follow Procedures Resulting in Mispositioned Valves.
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For those maintenance activities observed, and except for the two examples of the noted violation, the inspectors determined that the activities were conducted in a satisfactory manner and that the work was properly performed in accordance with approved maintenance work orders.
Two examples of a violation were identified.
6.
Self Assessment (40500)
The licensee routinely performs Quality Program audits of plant activities as required under its QA program or as requested by management.
To assess the effectiveness of these licensee audits, the inspectors examined the status, scope, findings and recommendations of the following audit report:
REPORT N0.
TITLE NO. OF NO. OF FINDINGS RECOMMENDATIONS 93-12-CAP Corrective Action
13 Programs
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No additional NRC followup will be taken on the findings referenced above because they were identified by the licensee's audit program and corrective actions have either been completed or are currently underway.
Problem Reports were initiated on the findings and plant management is aware of the findings.
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The inspector attended an NGRC meeting on March 9, 1994. The plant status report was presented by the Director, Nuclear Plant Operations. The actual performance for 1993 versus the CR-3 performance indicator goals was presented with only two goals not having been met.
One of these goals was exceeded based on a management decision at the time.
The thermal performance goal of
>99.2% was not met, but a 99.1% thermal performance was achieved.
This presentation was followed by each Subcommittee Report.
The subcommittee reports were very thorough and questioned events in great detail.
In general, it was stated that prs were not stated in a positive manner in that responses would indicate a less aggressive attitude than that actually taken.
It was suggested that future PR language be revised to more accurately reflect the extensive corrective actions taken. There was a presentation on i
the status of NCR (NCR 02856) wnich was generated in response to a PR (PR 93-0132) regarding problems with the PR system.
The PR I
system improvements were discussed. See comments below for more information on prs.
Presentations on other current plant concerns and plans were covered. The inspector determined that the NGRC was operating in a manner that met the FSAR commitments and promoted plant safety.
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On March 12, 1994, the ITS replaced the older TS.
Paragraph 6.5.2, Nuclear General Review Committee (NGRC), of the older TS has been relocated to section 12.8.2 of the FSAR. The inspectors reviewed the proposed section 12.8.2 of the FSAR and noted no
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changes to the NGRC had been made from that described in the older TS.
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The results of the following audit were considered noteworthy. The Corrective Action Frograms audit was significant in that this area was considered a challenge in the SALP report for the time period April 28, 1991, through August 22, 1992.
Previously, prs lacked event details, safety consequence evaluations, and root cause analysis.
Subsequently, Quality Programs performed an investigation into the identified deficiencies and issued NCR 02855, Inadequate Controls to Promptly Correct Problems.
The response to the noted NCR had, as a final corrective action, a
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plan to _ establish an automated problem reporting system to
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streamline the process; establish a method to asxign
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accountability for each identified problem, reduce / consolidate the number of process steps which are fragmented or unnecessary; and to identify responsibilities for each process step.
The responsibility for problem report tracking was transferred to NQA in February, 1993.
CP-lll, Documenting, Reporting and Reviewing Problem Reports, was revised to reflect the updated process.
As noted above, the status of the PR sy !em was discussed at the-NGRC meeting on March 9, 1994.
The development of the current improved PR system since 1992, when the licensee received criticism of the PR system from the NRC, INP0 and an internal audit, was discussed.
The audit concluded that the Corrective Action Program as implemented by CP-lll provided sufficient detail to support implementation of a nonconformance control and corrective action program that met the requirements of 10 CFR 50, Appendix B. Also, NRC IR 50-302/93-25 addressed the current PR system and concluded that it was functioning well.
Violations or deviations were not identified.
7.
Preparation for Refueling (60705)
Receipt of fuel shipments began this inspection period, after a delay caused by chemical contamination of some of the low enriched fuel pellets.
The fuel producer uses Dow Cleaner to clean the hoods of the shipping trays used to transport the fuel to the assembly fabricators.
At the assembly site, a worker noted discoloration on some of the fuel pellets.
Investigation revealed that the discoloration was caused by the Dow Cleaner, which had not been removed from some of the hoods prior to being placed over loaded fuel trays. The licensee sent QC and fuel design personnel to the fabricator to review their corrective actions.
The fuel manufacturer stated the material had no deleterious effects and met the contract specifications.
The licensee agreed with the manufacturer and released the fuel.
The inspectors observed the receipt of a shipment of the new fuel for the upcoming refueling outage.
The inspector observed the verification of the accelerometers, which are used to indicate shifts or sharp blows to the load during transport and the lifts to the refueling floor.
The inspector also observed the performance of the fuel receipt inspection on several assemblies. All the requirements of FP-302, New Fuel Assembly Unloading Inspection, Storage, and Container Reclosing, were verified to have been met and the inspectors noted that several bundles had been rejected by the licensee inspectors and that a manufacturer representative was brought to the site to disposition those assemblies.
All of the assemblies were accepted as is by the manufacturer representative and the licensee.
The fuel receipt was conducted in a professional manner and was well controlled.
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m.
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i Violations or deviations were not identified.
8.
Exit Interview The inspection scope and findings were summarized on March 31, 1994 with those persons indicated in paragraph 1.
The inspectors described the areas inspected and discussed in detail the inspection results listed
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below.
Proprietary information is not contained in this report.
Dissenting comments were not received from the licensee.
Item Number Status Description and Reference
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VIO 50-302/94-07-01 Open Failure to Follow Procedure Resulting in Mispositioned Valves.
(3 examples, paragraphs 3.a, 5.a, and 5.b)
IFI 50-302/94-07-02 Open Operators Entered TS 3.0.3 to Perform a Surveillance. (paragraph 3.a)
l 9.
Acronyms and Abbreviations AI
- Administrative Instruction ANSI
- American National Standards Institute
a.m.
- ante meridiem i
A0T
- Allowed Outage Times ASME - American Society of Mechanical Engineers BS
- Building Spray I
BSP
- Building Spray Pump BSV
- Building Spray Valve BWST - Borated Water Storage Tank B&W
- Babcock & Wilcox CCTV - Closed Circuit Television CFR
- Code of Federal Regulations CH
- Chilled Water CHHE - Chilled Water Heat Exchanger CHP
- Chilled Water Pump CHV
- Chilled Water Valve CP
- Compliance Procedure DC
- Decay Heat Closed Cycle Cooling DCHE - Decay Heat Cooling Heat Exchanger DCP
- Decay Heat Closed Cycle Cooling Pnmp DF
- Diesel Fuel DFV
- Diesel Fuel Valve DH
- Decay Heat DHP
- Decay Heat Pump
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DHV
- Decay Heat Valve ECCS - Emergency Core Cooling System (s)-
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ECGB - Civil Engineering and Geosciences Branch
.I EDG
.I EF
- Emergency Feedwater
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EFP Emergency feedwater Pump EFW
- Emergency Feedwater System ES
- Engineered Safeguards
- Refueling Procedure FPC
- Florida Power Corporation FSAR - Final Safety Analysis Report GL
- Generic Letter HPI
- High Pressure Injection System I&C
- Instrumentation and Control IFI
- Inspection Followup Item INP0 - Institute for Nuclear Power Operation IR
- Inspection Report ITS
- Improved Technical Specifications LC0
- Limiting Condition for Operation LER
- Licensee Event Report MAR
- Modification Approval Record MS
- Hakeup Pump
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MUV
- Makeup Valve NCR
- Non-conformance Report NGRC - Nuclear General Review Committee NQA
- Nuclear Quality Assurance NRC
- Nuclear Regulatory Commission
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- Office of Nuclear Reactor Regulation NSS
- Nuclear Shift Supervisor NUREG - NRC technical report designation OP
- Operating Procedure p.m.
- post meridiem PM
- Preventive Maintenance
>
PR
- Problem Report psig - pounds per square inch gauge QC
- Quality Control
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- Quality Assurance RCA
- Radiation Control Area RCS
- Raw Water Pump SALP - Systematic Assessment of Licensee Performance SP
- Surveillance Procedure STS
- Standard Technical Specification SW
- Nuclear Services Closed Cycle Cooling System SWP
- Nuclear Serviced Closed Cycle Cooling Pump TS
- Technical Specification V
- Volt VAC
- Volts Alternating Current VIO
- Violation j
- Work Request
i I