ML20246J923
| ML20246J923 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 06/27/1989 |
| From: | Caldwell J, Fredrickson P, King L, Munro J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20246J897 | List: |
| References | |
| 50-338-89-14, 50-339-89-14, NUDOCS 8907170481 | |
| Download: ML20246J923 (26) | |
See also: IR 05000338/1989014
Text
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. , " UNITED STATES .
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' NUCLEAR REGULATORY COMMISSION
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REGION U "
' ' 101 MARIETTA STREET,N.W,'
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l Report lNos.: -50-338/89-14 and 50-339/89-14-
Licensee: .VltginiaElectric&PowerCompany.
Richmond, VA 23261.
Docket Nos.: 50-338 and 50-339 License Nos.: NPF-4.and NPF-7
Facility Name: North Anna 1 and 2,
i Inspection Conducted: April 8, 1989 through May 31, 1989-
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Inspect 0rs: .
J.
Y $l OpA
L.. Caldwell', SRI
Je &lMlM
Date Signed.
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- L. P. King, RI
& Jn 6/27/s9
Dhte Figned
% s. w,.n Un/89
. J. f o, RI~ .g) ' D6te Signed
Approved by: b,
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4/27/D
Cate Signed
P.T. Fredrickson. Section Chief
Division of Reactor Projects
SUMMARY
Scope: _
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'This routine inspection by the resident inspectors involved the following
areas: plant ~ status, maintenance, surveillance, ESF walkdown, operational 1
safety verification, operating reactor events, licensee event report followup, j
licensee action on previous enforcement matters,. review of inspector follow-up
items, plant procedures, plant .startup from refueling, preparation for
refueling, and evaluation of licensee self-assessment capability. During the
i. . performance of this inspection, the resident inspectors conducted reviews of
the licensee's backshift operations on the following days: April 18, 25, 27,
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28, 29, 30,-May 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 16, 23, and 26, 1989.
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Results:
ESeveral weaknesses 'were identified associated .with corporate related
activities. . The corporate independent review committee was not performing all
of the TS required reviews, the formal check valve PM program was not develop ~ed
as committed, the . corporate FAI group failed to issue an accurate spent fuel
pool map;to the station, and corporate licensing failed to issue a TS required I
special report .within the required 30 days. With respect to the indepenar.t
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review committee, the inspector raised a concern about the licensee management's f
past attitudes toward this committee's regulatory performance, and over the '
ability of management to ensure future improved performance.
A strength was identified associated with the station's newly developed
self-assessment program including the recent Unit E rastart assessment. An
additional strength was the successful restart of Unst 2 following the j
refueling outage. The unit was restarted without experiencing any power i
reduction.
Within the areas inspected, there were three violations, one additional. example
of an apparent violation, and one non-cited violation.
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Violation: Failure of the licensee's independent review group.to perform
all of the reviews required by Technical Specifications (paragraph 14).
Violation: Failure to adequately control the locatior of fuel assemblies
during fuel movement operations (paragraph 9).
Violation: Failure to adequately control maintenance operations with two
examples (paragraphs 7 cnd 9):
1. Failure to follow procedcres resulting in work being conducted
on an unisolated charging ;ystem filter.
2. Failure to have adequate calibration procedures to prevent
unexpected reactor trip signal generation.
Apparent Violation: Additional example of failure to provide design SW
flow to the RSHX for Unit 2 (paragraph 5).
l Non-Cited Violation: Failure to comply with TS 3.11.1.3 and submit a
I special report within the 30 days as required (paragraph 7).
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REPORT DETAILS
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1. Persons Contacted
Licensee Employees
- M. Bowling, Assistant Station' Manager
- G. Clark, Quality Assurance:
J. Downs, Superintendent, Administrative Services
R. Driscoll, Quality Control Manager
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. *R. Enfinger, Assistant Station Manager-
G. Gordon,' Electrical' Supervisor
- D. Heacock, Superintendent Engineering
G. Kane, Station Manager .
L *P. Kemp, Licensing Coordinator
- J. Leberstien, Licensing E;mineer
- J. Mosticone, Operations Administration Coordinator
T. Porter, NSE Supervisor 1
- D. Quave, Licensing Engineer
- C. Snow, Chemistry Supervisor '
J.-Stall. Superintendent, Operations
A. Stafford, Superintendent, Health Physics
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F. Terminella,-Quality Assurance Supervisor
D. Thomas, Mechanical Maintenance Supervisor
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- W. Matthews, Superintendent, Maintenance
G. Flowers, Configuration Management Supervisor
Other licensee employees ' contacted included engineers, technicians,
operators, mechanics, security force. members, and office personnel.
- Attended exit interview
NRC Regional Site Management Visit: S. D. Ebneter visited the North Anna
Power Station on May 4 to interface with the Resident Inspectors and
perform a tour of the station.
On May 31, the Hungarian-Vice Minister of Industry and two of his
associates visited the North Anna Stat. .ri at the invitation of the
licensee. The minister and his group were given a presentation and a tour
of the station. .
2. -Plant Status
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On April 18, the beginning of the inspection period, Unit I was in Mode 5
day 51 of an outage. On April 26 and 27, with a reactor vessel head purge
in progress and the resultant inaccurate vessel standpipe level
indication, vessel level was inadvertently reduced by 546 and 860 gallons,
respectively. However, vessel level remained above the reduced RCS
l inventory le/el as' defined in Generic Letter 88-17 (see paragraph 6.d of
NRC'Inspec', ton Report 338,339/89-08 fordetails).
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On April 27, an attempt was made to place a new fuel assembly into a spbnt
fuel pool location where another fuel assembly was currently stored. This
occurred due to an incorrect fuel handling data sheet submitted by the
corporate. fuel audit and inspection 9 oup. Subsequent inspection showed
no damage to either assembly (see paragraph 9 for details). Core offload
was commenced on May 8 and completed on May 11.
On April 18, the beginning of the inspection period, Unit 2 was in Mode 5,
day 57 of the refueling outage. Also on April 18, the " Flow Test of
Inside Recirc Spray Pumps" was satisfactorily completed (see paragraph 5
for details). On April 21, containment pressurization in accordance with
the Type "8'? test procedure commenced. The Type "A" test was
satisfactorily completed on April 23 with the containment depressurized
and returned to atmospheric pressure on April 24. On April 24, the ,
" Service Water System Flow Balance" for the RSHXs was completed. The
results of the test revealed that one of the four Unit 2 RSHXs was not
receiving the design SW flow (see paragraph 5 for details). On
April 29, while increasing RCS pressure to start RCPs, PORV 2-RC-PCV-2455C
lifted at approximately 350 psig. The valve, with a setpoint of 370 psig,
lifted early due to an out-of-calibration pressure channel. On May 2, a
Train "A" reactor trip signal, low steam g'enerator level coincident with
steam flow greater than feedwater flow mismatch, was inadvertently
generated during the performance of the steam flow instrument channel
calibration.- A four-hour report was made in accordance with 10 CFR 50.72
(b)(2)(11) (see paragraph 9 for details). On May 4, the Unit 2 heat-up
commenced and Mode 4 was entered. On May 7, reactor startup commenced
with criticality being achieved in approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. On May 8,
the turbine generator was placed on line and core physics testing was
satisfactorily completed. The unit achieved 100 percent power on Maf 16.
During the startup, erratic feedwater flow to the "A" SG was periodically
encountered. This problem was corrected on May 18, by replacement of the
pilot valve associated with the MFRV positioner. On May 20, the CVCS
letdown filter replacement maintenance was inadvertently commenced on the
in-service RCS filter. Work was imediately stopped and filter cover
bolts re-tightened when water began spraying during disassembly (see
paragraph 7 for details), On May 30, entry into TS Action 3.7.12.la was
made on total settlement between the Unit 2 containment and Unit 2 MSVH
being greater than 75 percent of allowable.
3. Maintenance (62703)
Station maintenance activities affecting safety-related systems and
components were observed / reviewed, to ascertain that the activities were
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industry codes or standards, and in conformance with TS.
l As documented in NRC Inspection Report 338,339/88-11, the licensee
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committed to develop a formal check valve PM program prior to the present
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Unit 1 and Unit 2 refualing outages. The failure to have a formal check
valve PM program was also discussed as a weakness that needed management
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attention in the last sal.P report. Consequently, VEPC0 tasked corporate
management with the development of this program. At present, this program
has not been completely developed and is not scheduled to be fully
approved until August 1989.
The inspector discussed the need for the program and the NRC ccmmitment,
with station management at the beginning of the Unit 2 outage. The
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inspector was later informed that the maintenance superintendent had
obtained a draft check valve maintenance procedure .which had been
developed by Stone and Webster. This procedure established a list-of 174
critical check valves. For various reasons, the maintenance department
inspected 56' check valves during the Unit 2 outage of which 48, or
approximately 30%, were from the critical check valve list. The
maintenance superintendent intended .to work approximately 30% of the
critical check valves each outage for the next three outages unless
otherwise directed by a formal PM program. The inspector was also
informed that another 20% of the critical check valves were tested during
the IST program. Therefore, approximately 50% of the Stone and Webster
Unit.2 critical check valve list was either tested or inspected during the
Unit. 2 outage. Even though the department of the corporate office
respons'ible for the development of the check valve PM program failed to
comply with the NRC commitment, the inspector will not identify this as a
deviation because of the effort put forth by the station maintenance
department to_ address the check valve concern. This does, however,
demonstrate a weakness in the licensee's corporate response to NRC
commitments. The inspector will follow the check valve PM program for
Unit 1. ,
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On April 19 the inspector, accompanied by the licensee, conducted a
walkdown of_ the Unit 1 and Unit 2 condenser air ejector _ piping. This
walkdown was conducted to understand the licensee's determination of the
failure mode of the Unit 1 air ejector radiation moniteLr during the last
two SG tube leak events. The Unit 2 air ejector drain piping was observed
to contain a loop seal, with check valves installed upstream to prevent
reverse flow and subsequent loss of the' loop seal. However, the Unit 1
drain piping loop seal did not contain the same check valves.
Consequently, each time the Unit 1 air ejector would divert to
containment, it placed the containment pressure' (a vacuum) on the loop '
seal, drawing water up into the radiation monitor and, after the loop seal
has been removed, drawing a high flow rate of dilution air from the drain
line vent past the detector. The detector wou.1d fail low due to either
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the moisture or the dilution air.
The licensee was unable to explain why the check valves had been omitted
from the Unit 1 design or added to the Unit 2 air ejector drain piping.
This design difference could explain the fact that past operation of the
Unit 2 air ejector radiation monitor had not demonstrated the same
failures as the Unit I radiation monitor. The licensee has also observed
a faster reduction in containment vacuum when the Unit 1 air ejector is
diverted to containment than that of the Unit 2 air ejector. This
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reduction rate would be a result of the high dilution air flow into
containment from the Unit I air ejector drain line vent after the loop
seal had been removed. The licensee intends to install the check valves .
upstream of the Unit 1 air ejector drain line loop seal prior to the
completion of the Unit I refueling outage.
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No violations were identified. l
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4. Plant Procedures (42700)
Procedures were reviewed by the inspectors to verify that:
a. Procedure changes were made to reflect revis d TS. A review was made
of changes to technical specifications for ta88 and 1989, and the-
applicable procedures were checked to ensure the new requirements had
been incorporated.
b. The 10 CFR 50.59 submittals were reviewed to ensure procedures had
been changed according to requirements.
c. Temporary procedures and deviations written during the past year did
not conflict with TS requirements.
d. The method of incorporating temporary procedure changes into
procedures for emergencies and other significant events did not j
preclude proper and timely operator action during abnormal plant
conditions.
e. Overall procedure content was consistent with TS requirements.
Stepwise construction was compatible with checklist information and
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there wc e provisions for signoff on the checklist and appropriate TS
limits were incorporated.
L f. The procedures accomplished the evaluation within the design
characteristics and applicable safety review considerations.
g. Precautions were taken to ensure safety-related operations are within
appliccole regulatory requirements.
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! h. Procedures, including checklists and related forms in plant working
files..were current with respect to revision and temporary change.
The following is a list of the procedures reviewed:
2-0P-1.5 Unit Startup from Mode 3 to ?
2-0P-2.1 Unit Startup From Mode 2 to Mode 1 1
1-0P-7.1 Recirc of RWST Using Low Head Safety Injection Pumps
1-0P-7.1A Valve Checkoff - Low Head Safety Injection System !
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1-0P-16.0 Fuel Pit Cooling and Refueling Purification
1-0P-16.1 Spent Fuel Pit Cooling and Purification System
1-0P-16.1A Valve Checkoff - Spent Fuel Pit Cooling
1-0P-16.2A Valve Checkoff - Refueling Purification
1-0P-21.7 Main Control and Relay Room Ventilation
1-0P-21.6 Main Control Room and Relay Room Air Conditioning
1-0P-51 Compomnt Cooling Water Systems
1-0P-46.1 Instrument Air Compressor
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2-AP-4.3 Malfunction of Nuclear Instrumentation (Power Range)
2-AP-22.1 Loss of 2-FW-P-2 Turbine Driven Aux Feedwater Pump
1-AP-27.2 Loss of Spent Fuel Pool System ~
1-AP-27.1 Loss of Spent Fuel Pool Level
1-AP-28 Loss of Instrument Air
1-AP-55 Loss of Control Room / Emergency Switchgear Room Air
Conditioning
1-M0P-7.01 Low Head Safety Injection Pump (1-SI-P-1A) <
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1-M0P-16.02 Refueling Purification Pump - 1-RP-P-1B
1-M0P-16.2 Refueling Purification Filter 1-RP-FL-1A j
1-PT-30.2.1 NIS Power Range Channel I (N-41) Functional Test l
T-PT-30.2.2 NIS Power Range Channel II (N-42) Functional Test
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2-PT-30.2.3 NIS Power Range Channel III (N-43) Functional Test {
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1-PT-57.1A ECCS Subsystem - Low Head SI Pump (1-SI-P-1A) i
1-PT-74.2A Component Cooling Pump (1-CC-P-1A) Test
2-PT-888 D.C. Distribution Capacity Test for Train B Battery
2-PT-85 D.C. Dis tribution Systems
2-PT-87 D.C. Distribution Systems Service Test
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2-PT-86A D.C. Distribution Systems - H Bus.
2-PT-86B D.C. Distribution Systems - J Bus.
1-ES-1.3 Transfer to Cold Leg Recirculation
j. 1-ES-1.4 Transfer to Hot Leg Recirculation
.ADM 5.3 Review of Procedures
ADM 5.4 Processing New and Revised Procedures and Deletion of
Procedures
The inspector determined that, overall, the procedures reviewed were
technically adequate and would accomplish their intended purpose.
However, several deficiencies were observed as described below:
Administrative and/or typographical errors were identified in 2-PT-30.2.2,
2-PT-30.2.3, 2-AP-4.3 and 2-AP-22.1. None of these errors would preclude
proper completion of these procedures. The licensee has been informed of
these errors and has indicated that appropriate co'rrections will be made.
Certain reviewed procedures, although adequate to control the stated
purpose and/or evolution, omitted several checks and/or verifications.
Procedure 1-0P-7.1A did not align valves 1-51-282 and 1-SI-283 (see
Procedural Reference 1, Drawing Number 11715-FM-96A, SH 1 of 3).
Procedure 1-M0P-7.01 removes pump 1-SI-P-1A from service for maintenance,
however, the procedure does not verify that the recirculation spray cross
tie valve,1-SI-315 is shut (see Procedural Reference 2. Drawing Number
11715-FM-96A, SH. 2 of 3).
The inspector reviewed a signed-off copy of 1-0P-21.7 dated May 4, 1989.
The present system lineup was unclear, in that both. procedure step 4.3,
which places the main control and relay room ventilation ' system in
operation, and step 4.4, which removes it from operation, were marked as
completed for the same procedure. Because times are not indicated on this
multi-purpose procedure, the order in which the steps were performed is
unclear. 1-0P-21.7 also makes several references to the " Control Room
Isolation" switch. The s5titch is actually labeled " Control Room Exhaust
Damper."
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f The inspector also reviewed the licensee's process for revising and
deviating procedures. Administrative procedures that control this process
are ADM-5.4, Processing New and Revised Procedures and Deletion of
, Procedures, and ADM-5.8, Procedure Deviations. Changes to procedures
require SNSOC approval and review, and these approvals are documented on
ADM-5.4, Attachment 2, block 15 and ADM-5.8, Attachment 1, block 12. The
inspector determined that the actual signatures of approval are not always
filled in. In lieu of the actual signature, the chairman's name is
printed with the SN50C secretary's initials. This methodology is not !
addressed by the administrative procedures and occurs approximately 25% of
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the time. A sampling of these instances were reviewed against the SNSOC
meeting minutes. The SNSOC meeting minutes supported SNSOC review in each
of these instances. This situation has been discussed with the licensee.
Two instances were noted in which documentation was not complete. The
questions of Block 10 in Attachment 3, ADM-5.4 dated June 23, 1988, for
i procedure 2-AP-4.3, were not checked either yes or no. The Safety
Evaluation /10 CFR 50.59 Review performed in accordance with ADM-3.9 on
August 23, 1988, for 2-PI 71.3 was not annotated as " Approved,"
" Disapproved" or " Return for further Evalu& tion." SNSOC meeting minutes
support review of these procedures.
The original " Evaluation for Potential Unreviewed Safety Question"
( ADM-3.9, Attachment 1) for 1-PT-68.1.1. 1-PT-68.1.2, 1-PT-68.2.1, and ,
1-PT-68.2.2 was not available in Station Records. However, a copy was-
obtained from the STA's files and the licensee is taking action to address
this recordkeeping omission.
No violations or deviations were identified.
5. Surveillance (61726)
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The inspectors observed / reviewed TS required testing and verified that
testing was performed in accordance with adequate procedures, that test
instrumentation was calibrated, that LCOs were met, and that any l
deficiencies identified were properly reviewed and resolved.
On April 18, 1989, the inspector observed the performance of the periodic ,
test 2-PT-64.8, for the Unit 2 Inside Recirculation Spray Pumps. Both
"A" and "B" pumps tested satisfactorily. The inspector attended the-
licensee's meetings prior to the performance of the test and discussed the
test procedure and set-up with the test engineer. Operational, i
radiological, and safety aspects of the test were discussed by the test
engineer with those performing the procedure in a professional and
thorough manner. Interaction between the control room operator and test
persor.nel during the test was acceptable. Procedure 2-PT-64.8 requires
that temperatures of the recirculation system sump water be recorded from
control room indications 30 that temperatures are maintained below 150
degrees F for personnel protection. The inspector also noted that sump
water temperatures could be monitored near the pump suction location to
give a more timel,y and accurate reading for the safety of the test
performers. The inspector believes that this additional local indication
should be useful for future test monitoring.
During the "A" recirculation pump testing, the rotation light failed to
indicate in the control room. The indication light had been checked prior
to performing the test and was determined to be operational. A work
request was written to correct the problem. At the end of the tests, the
inspector compared the recirculation pump head curve data to the last test
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performed in October 1988, and also to the manufacturer's stated pump head
curves. By these indications, neither the "A" or "B" pump has suffered
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any significant degradation. All test acceptance criteria were met.
On April 24, the inspector witnessed the performance of 1-PT-62.2.1, RSHX
SW Leakage, Surveillance Test. This test is conducted to verify that the
RSHXs are maintained in a dry condition. During the performance of the ,
test, the operator opens a low point drain on both the supply and return
SW headers to and from the RSHXs and measures .the amount of SW removed
from the header. Based on the amount measured, the licensee can' verify if
any SW has reached the RSHXs. The acceptance criterion is less than 100-
gallons, even though the piping to some of the RSHXs would require
approximately 1000 gallons to reach the actual heat exchanger tube sheet.
On April 24, the measured leakage was approximately 5 gallons in the
supply header and 0.20 gallons in the return header. ,
Also, on April 24 the inspector witnessed the performance of 2-PT-75.6
Service Water System Flow Balance, for the Unit 2 RSHXs. The Unit 1 RSHXs
were tested on April 14' as discussed in NRC Inspection Report 338,339/
89-08. The rest1 ;s of the Unit 2. test indicated that three of the four SW
throttle valves were adjusted such that greater than the design flow 'of
4500 gpm was achieved through the respective RSHXs. The fourth throttle
valve, 2-SW-203D, had been adjusted improperly, limiting the SW flow
through the 'D' RSHX to approximately 3600 gpm. The licensee subsequently
adjusted all four of the SW throttle valves to establish a flow of greater
than 4500 gpm through each RSHX. Failure to provide the design basis SW
flow to the 'D' RSHX on Unit 2 is identified as an additional example of
apparent violation 338,339/89-08-03. The licensee also determined the
maximum allowed flow through the Unit 1 CCW heat exchangers and still be
able to maintain the 4500 gpm : through each Unit 2 RSHX. This was
performed using the same method described in NRC Inspection Report
. 338,339/89-08.
During the performance of the test, the inspector was informed that one of
the throttle valves did not have the mechanical stop installed. After
further discussions, the inspector determir.ed that the mechanical stops on
all four Unit 1 RSHX SW throttle valves had been discovered to be missing
during the April 14 test.- Also, based on the test data from both tests
and a review of the Setpoint Document, the licensee determined that the
as-found throttle valve settings did not agree with the setpoint document.
Both of these findings indicate that problems exist with the maintenance
activities that have been conducted on these valves in the past, either
i due to improper performance or inadequate procedural guidance.
On April 30, the inspector reviewed the completed surveillance procedure
2-pT-10 Determination of Shutdown Margin. The minimum shutdown margin of
2203 pcm was determined by the surveillance test to comply with the TS 3.1.1.1 limit of greater that equal to 1.77% delta K/K. The actual
shutdown margin was calculated to be 4286 pcm. The inspector had a
licensed SR0 step through the procedure to determine acceptability of the
results. No problems were identified.
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The inspector witnessed several additional tests which were completed {
satisfactorily. On May 1, 1989, the inspector witnessed the start of
2-PT-83.4, Blackout of Emergency Bus for Shutdown Loads for the 2J EDG.
The diesel was operated for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, two of which were at 2950 KW and the
remaining 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> were at 2500 to 2600 KW. Following the completion of
the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> test, the diesel was secured for approximately 5 minutes,
then the normal power supply to the J bus was removed and the J diesel
auto started and picked up the loads within the allowable times. No
problems were identified. On. May 2,1989, the inspector witnessed
performance of Appendix G. of 2-PT-61.4, RCS Pressure Isolation Valves -
Leakage Test. The licensee experienced a problem with the alternate
charging header remaining pressurized. This required the procedure to be
deviated to bleed the pressure off through several drain valves. Once the
alternate charging header was depressurized, the leakage test was
satisfactorily completed. On May 7, 1989, the inspector witnessed
2-PT-30.2.2 and 2-PT-30.2.3, NIS Power Range Channel II (N-42) and III
(N-43) Functional Tests. The tests were satisfactorily conducted in
accordance with the procedure. On May 8, 1989, the inspector witnessed ,.!
2-PT-212.6, Valve Inservice Inspection, for three accumulator motor
operated valves. Position indication was verified inside the containment.
'All three valves completed the str6ke test time satisfactorily.
6. ESF System Walkdown (71710)
On May 24 and 25, the inspectors walked down the auxiliary feedwater
system on Unit 2 using valve checkoff list 2-0P-31.A and drawing number
12050-FM-074A Rev. 24. The inspector noted that the check valves in the
lube oil cooler line installed by EWR 88-178A were not reflected in the
drawing. The inspector checked the control room drawings an'd found that
they had been redlined to reflect these valves. The inspector also noted
that the cooler outlet isolation valves 2-FW-600, 601 and 602 were not
shown on the drawing or redlined on the control room drawing. However, .
the valves were correctly listed on the valve checkoff list. The licensee
is investigating the drawing discrepancy and will be updating the control
room drawings to reflect these valves.
No violations or deviations were identified.
7. Operational Safety Verification (71707)
By observations during the inspection period, the inspectors verified that
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the control room manning requirements were being met. In addition, the
inspectors observed shift turnover to verify that continuity of system
status was maintained. The inspectors periodically questioned shift
personnel relative to their awareness of plant conditions. Through log
review and plant tours, the inspectors verified compliance with selected '
TS and LCOs. )
In the course of the monthly activities, the resident inspectors included
a review of the licensee's physical security program. The performance of
various chifts of the security force was observed in the conduct of daily
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activities to include: protected and vital areas access controls;
searching of personnel, packages and vehicles; badge issuance and
retrieval; escorting of visitors; patrols; and compensatory posts. On a
regular basis, RWPs were reviewed and the specific work activity was
monitored to assure the activities were being conducted per the RWPs. The
inspectors kept informed, on a daily basis, of overall status of both
units and of any significant safety matter related to plant operations.
Discussions were held with plant management and various members of the
operations staff on a regular basis. Selected portions of operating logs
and data sheets were reviewed daily. The inspectors conducted various
plant tours and made frequent visits to the Control Room. Observations
included: witnessing work activities in progress; verifying the status of
operating and standby safety systems and equipment; confirming valve
positions, instrument and recorder readings, and annunciator alarms; and ,
observing housekeeping.
The inspector reviewed a special report dated April 7,1989, which was
submitted by the licensee in accordance with TS 3i11.1.2 and TS 3.11.1.3.
These TS require a special report be submitted to the Commission within 30
days any time the release or discharge limits for the associated TS LC0
are exceeded. The non-compliance with TS 3.11.1.3 involved the discharge
of effluents without going through the final demineralized when the actual
dose projections were in excess of the TS limit. This non-compliance
began on February 20 and continued until March 2, when the dose projection
error was discovered. However, as stated above, the special report was
not issued by the corporate office until April 7, in excess of the 30 days
required by TS 3.11.1.3. Since this violation of TS meets the criteria of
10 CFR Part 2, Appendix C for licensee identification, it will be
identified as NCV 338,339/89-14-04.
On May 12, preparations were commenced to replace the filter elements in
the Unit 2 letdown filter 2-CH-FL-5. A team of 2 mechanics and I health
physics technician proceeded to the job location to perform the radiation
surveys required to complete the RWP. There are two unlabeled filter
access plugs in the same area, one for 2-CH-FL-5 and one for 2-CH-FL-2.
The team used an informally marked up radiological survey map and record
form as the reference to determine ~ the access plug to be removed. On
May 16, the SNSOC approveti RWP 89-2256 to remove and replace the filter
element for 2-CH-FL-5. The associated RWP was posted on the wall south of
filter 2-CH-FL-2 instead of 2-CH-FL-5. On May 20, the licensee commenced
procedure MMP-C-FL-5 to replace filter .2-CH-FL-5. The area established by
RWP 89-2256 was covered by herculite except for one access plug. This
access plug, assumed to be the plug for 2-CH-FL-5, was removed. As the
fourth bolt on the filter cover was removed, water begon spraying from the
filter cover. The cover bolts were immediately tightened and the spray of
water stopped. The job was stopped and supervision informed. A shift
operator was dispatched and the determination made that the wrong filter
had been worked, 2-CH-FL-2 versus 2-CH-FL-5.
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TS 6.8.1.a requires written procedures be established, implemented and
maintained covering maintenance activities. The failure of the licensee
to follow MMP-C-FL-5, the associated work order and RWP resulted in
maintenance being conducted on an unisolated charging system' filter and
will be identified as the first example of Violation 338,339/89-14-02.
8. Plant Startup From Refueling (71711)
During the previous SALP period, the licensee received a category 3 rating i
for the outage functional area. The primary reason for the category 3
rating was the licensee's inattention to detail during unit shutdown,
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startup and outage situations, which resulted in plant events.
Consequently, the inspectors closely observed the Unit 2 refueling outage.
As discussed in NRC Inspection Report 338,339/89-08, the inspectors
observed the Unit 2 shutdown for the refueling and determined that
evolutions were well controlled and conducted in a safe manner.
During the recent recovery of Unit 2 from the refueling outage, the
inspectors observed the licensee's startup activities around-the-clock.
The Unit 2 mode change from Mode 5 to Mode 4 occurred on May 7 with the
reactor achbving criticality at 2234, control bank D at step 128. Unit 2
was placed on line on May 9 and, after secondary chemistry holds and
correction of soce vibration problems on the main turbine, achieved 100%
power on May 16. i.5e inspectors observed the startup to be deliberate and
controlled, and the oprator's full attention was placed on the unit's
performance. There were no major perturbations associated with the
startup, as were common for startups from the refueling outages in the
past. The inspectors believe that the successful startup of Unit 2 was a
result of many licensee initiated activities. The licensee provided
startup training for the operations staff on the simulator. Attention to
detail was emphasized by all levels of management. The station manager
set a goal .for the station to start up the unit, achieve 100% power and
maintain operations for at least 30 days without any major power
reductions. Station management established a startup assessment program
for which the presentation was conducted on May 3 with the Station
Managers. As discussed further in paragraph 14, this program involved the
superintendents of each department making presentations to the station
oversight board on how their responsibilities were accomplished to allow
the unit to restart. This provided station management with r list of
items left to be completed prior to restart and objective evidence that
the unit was in f.act ready for the restart. The resident inspector
attended portions of the Unit 2 restart assessment.
The successful startup, as well as the low number of equipment problems
following the startup and the low identified and unidentified leakage
rates, also reflected an adequately conducted outage. The actual time the
unit was in the outage exceeded the original scheduled time. However,
much of this could be attributed to the unplanned February outage for
Unit 1, and the fact that the Unit 2 outage was driven more by
satisfactory completion of the necessary maintenance versus strictly
meeting the schedule.
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Prior to the Unit 2 restart, the inspectors conducted the. following
inspections:
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On April 26,.the inspector made a Unit 2 containment entry to check (
the lineup of the low head safety injection system. The leakage {
monitoring valve for penetrations 60, 61 and 62 were verified closed
and capped. No problems were found.
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On May 1 and 2, the inspectors made containment entries into Unit 2
with licensee representatives. A walkdown was made of the first, j
second and third levels of the containment using 2-0P-1B, Containment j
- Checklist. Areas inside the A, B and C cubicles on the shrouo cooler {
level needed vacuuming. There were pieces of red tape on various j
walls and floors throughout containment. Several welding rods, rags I
and other small material were picked up during the course of the
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checkout. The licensee noted all discrepancies to be closed out
before final heatup. The inspectors did not notice any major items
or equipment which were left in containment. However, the material
found and removed should have been removed by the maintenance and/or
contractor groups as they completed their activities, to prevent
unnecessary exposure at the end of the outage.*
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On May 6, the inspectors witnessed portions of 2-PT-17.2, Rod Drop
Time. The procedure was completed satisfactorily with the rod drop
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times meeting the TS criteria. The inspector did observe a couple of
problems associated with the performance of the test procedure.
Steps 2.2.2 and 4.2.5.4, related steps, were signed off even though
the steps were not actually performed. The function required by the
steps was stated to be optional, therefore, the steps were not
required to be performed, and could have been annotated to indicate
that the option was not taken. Step 4.2.5 was not going to be
performed until the inspector questioned how the reactor engineer
could sign the step and not perform it. The engineer informed the
inspector that because they were using a new calibrated recorder to
record the rod drop traces, the step was no longer required. Based
on the inspector's discussions regarding the deviation process, the
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engineer chose to perform step 4.2. 5 rather than deviate the
procedure. The signing off of steps that are not performed is !
inconsistent with the attention-to-detail / follow-procedure philosophy
supported by station personnel. The inspector has discussed this
with the licensee.
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On May 6, the inspector witnessed portions of the following
procedures:
a. ICP-RP-2-RPI-1, Rod Position Indication
b. 2-PT-714, Auxiliary feedwater Pump Time Response and Logic Test
c. 2-PT-71.1 Auxiliary Feedwater Pump (2-FW-P-2) and Valve Test
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d. ST-81, Auxiliary Feedwater Pump Head Curve Verification
No problems were observed.
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On May 7 and 8, during the Unit 2 start-up, the inspectors observed
the performance of sections of the following procedures:
a. Unit 2 startup from Mode 4 to Mode 3 per 2-0P-1.4, Withdrawal of-.
the Shutdown Banks. This evolution was performed in a
deliberate and controlled fashion to ensure that TS regarding to
rod position indication were being complied with,
b. Nuclear Design Check per PT-94.0, for the determination of the
reactivity worth of Shutdown Bank B. The inspectors also ,
observed parts of the procedure for boron end point determina-
tion, isothermal transfer coefficient testing and B group rod
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worth. The control manipulations were performed in a controlled
and deliberate manner, and in accordance with PT-94.0. -
c. Estimated . Critical Position per 2-0P-1C, to determine the bank
and' range of control rod position expected to achieve
criticality. This procedure was designed to be performed
following a routine reactor trip. Consequently, several steps
had to be _NA'd, and the operators and STA needed the reactor
engineer to explain what'information was required to be placed
in several of the steps. The estimated critical position was
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adequately determined. The inspector discussed the confusing
nature of the procedure with the licensee. The licensee stated
that they intend to make the procedure applicable to a startup
following a refueling outage.
No violations or deviations were identified. .
9. Operating Reactor Events (93702)
The inspectors reviewed activities associated with the below listed
reactor events. The review included determination of cause, safety
significance, performance of personnel and systems, and corrective action.
The inspectors examined instrument recordings, computer printouts,
operations journal entries, scram reports and had discussions with
operations, maintenance and engineering support personnel as appropriate.
.
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On April 27, new fuel movement to the spent fuel pool was in progress in
accordance with procedures for Receipt and Storage of New Fuel,1-0P-4.2, i
and Fuel Building Bridge and Trolley Crane,1-0P-4.10. The controlling
document for the fuel assembly location was the Fuel Handling Data Sheet
generated by the corporate FAI group. While attempting to place a new
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fuel assembly, K65, in fuel pool location V30, a 200 lb. slow load loss
was noted as fuel assembly K65 entered the storage cell. In accordance
with 1-0P-4.10, fuel movement was stopped immediately and fuel assembly
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K65 was raised to inspect the storage cell. The inspection showed a fuel
assembly already stored in fuel pool location V30. A review of local
records indicated this assembly to- be N47. This conclusion was later
confirmed by a video inspection. Facility records, Form VNF-7,
Number NA-1-01-89, indicated that fuel assembly N47 had been placed in I
pool location V30 on January 26, 1989. A copy of this VNF-7 form had
been forwarded to FAI group by company mail for entry into the tracking
system, which is used to update the FHDS. However, this VNF-7 was not
entered into the FHDS by the corporate group, resulting in the official
FHDS being in error. Subsequent to the occurrence, local facility records
and the magnetic tag board utilized to track fuel movement were verified
to be correct and up to date. This board was then used to check the
official FHDS issued by FAI prior to further fuel movement. In the past,
station personnel were not required to review the accuracy of the FHDS
with respect to the magnetic tag. board or other station records prior to
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fuel movement. A video inspection of assembly N47 showed no damage. A
visual (out of pool) inspection of assembly K65 showed no damage.
As further corrective actions, the licensee made the following changes to
1-0P-4.10 on April 28.
a. Prior to all fuel movement, the VNF-7 covering the moves to be
performed will be verified by the fuel handling supervisor in charge
against the magnetic board in the station refueling office.
b. The fuel handling supervisor will ensure that lighting in the fuel
pool will permit visual verification of all moves. If lighting is
not adequate, auxiliary lights will be used as required to assure
' proper visibility.
Also, the method for transmission of fuel movement information, i.e.,
completed VNF-7 or FHDS forms, to the FAI group has been revised to ensure
receipt. The completed forms will be telexed to the FAI group, as well as
mailed, with a response required from FAI indicating that the fuel
movement data has been received and recorded. During discussions with
FAI, the inspector determined that FAI personnel feel it is not necessary
to be on site 'during fuel movements for first-hand verification of the
fuel assembly locations. -
TS 6.8.1.b requires written procedures to be established, implemented and
maintained covering refueling activities. The failure of the corporate
FAI group to provide an accurate FHDS will be identified as a Violation
338,339/89-14-03.
On May 2, with Unit 2 in Mode 5 and all rods fully inserted, an unexpected
automatic RPS reactor trip signal was generated during the performance of
procedure ICP-FW-2-F-2486, SG B Feed Flow Protecion Channel IV.
1
The "A"
train reactor trip breakers were closed for the performance of 2-PT-36.1B,
Reactor Protection and ESF Logic Test Train B. SG "B" was being flushed
and drained below 25% narrow range level. During the performance of
ICP-FW-2-F-2486, the "B" S/G channel IV Steam Flow /Feedwater Flow is
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placed in trip and a SF/FF mismatch signal generated on channel IV of the
"B" SG. Since an actuel low SG 1evel existed on the "B" SG, the placing
of the "B" SG channel lY SF/FF mismatch bistable in trip completed the ;
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logic (less than 25% level on any SG coincident with a SF/FF mismatch on
the same SG) and generated a reactor trip signal. The reactor trip
breakers opened as designed. Since a reactor trip signal was not
expected, the event is reportable pursuant to 10 CFR 50.73(a)(2)(iv). A
four-hour report was made in accordance with 10 CFR 50.72(b)(2)(ii). The
licensee addressed the procedural inadequacy by the issuance of a
memorandum requiring a review of current plant conditions against
procedural coincident logic requirements ' prior to proceeding with the
procedure.
TS 6.8.1.a requires written procedures to be established, implemented and
maintained covering maintenance activities. Procedure ICP-FW-2-F-2486 was
inadequate in that the procedure's initial conditions stated that there i
were no coincidence requirements during modes 3, 4, 5 or 6 which could
result in an inadvertent reactor trip signal. The inadequate procedure
will be identified as the second example of Violation 338,339/89-14-02.
10. Licensee Event Report Follow-up (90712)
The following LERs were reviewed and closed. The inspector verified that
reporting requirements had been h.at, that causes had been identified, that
corrective actions appeared appropriate, .that generic applicability had
been considered, and that the LER forms were complete. Additionally, the
inspectors confirmed that no unreviewed safety questions were involved and
that violations of regulations or TS conditions had been identified.
(Closed) LER 338/88-03, failure to Test Containment Personnel Airlock
Equalizing Valves. The inspector reviewed the LER closcout package. The
licensee satisfactorily leak-tested the emergency equalizing valves as an !
immediate corrective action. In addition, the containment surveillance
procedure,1/2-PT-62.1, was revised to delete the requirement that the
emergency equalizing valves be blank flanged during testing. These
corrective actions should preclude recurrence of the event.
(Closed) LER 338/87-010, Steam Generator Defects. The inspector reviewed
the supplemental LER, which detailed the tube examination results.
Because of the tubesheet indications, two tubes were removed from the "A" :
SG for further nondestructive and destructive examination. Preliminary !
results of the examinations performed revealed circumferential pressurized a
water stress erosion cracking in the expansion transition region of both ;
tubes at the tube sheet top location. Also identified was minor outside
diameter intergranular corrosion within the first support plate region of
one tube and just above the top of the tube sheet region of both tubes.
The licensee has plans to implement a them! si.ress relief program for
Unit 2 during the next refueling outage. The program is not being
implemented for Unit 1.
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(Closed) LER 338,339/88-010, Kaman Vent Stack "B" Radiation Monitor
Exceeded T. S. Action Statement. .The licensee issued supplemental LER
88-010-01 on March 3, 1989. A root cause investigation of the erroneously
high radiation level being displayed for RI-VG-180 revealed that the CPU
~ board had malfunctioned. The most probable cause was the ground
configuration of the CPU. The licensee's corrective actions included
replacing the failed CPU board and as a continuation of the reliability
upgrade project (initially mentioned in LER 338,339/88-006), the licensee
initiated a field change to improve the reliability of the monitor. This
modification included ground configuration improvements. This event was
unrelated to a previous failure of the Kaman Process Vent Radiation
Monitor which failed on November 24, 1967, due to intermittent continuity
problem on the CPU card on the card edge connectors. The inspector
reviewed the TS applicability and the LER closeout package. ,
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11. Licensee Action on Previous Enforcement Matters (92702) l
(Closed) Violation 338,339/86-28-01, Failure to take prompt corrective
action to ensure compliance with 10 CFR 50.49. This violation was as a
result of licensee engineering not taking prompt action to establish
environmental qualification for equipment in the MSVH. The criteria for '
initiating Deviation Reports covering the identification of potential and
actual conditions adverse to quality was clarified to the engineering
organization. The Engineering Department procedure for evaluating NRC
Information Notices, vendor notifications, .and other pertinent operating
information has been revised.
12. Review of Inspector Follow-up Items (92701)
(Closed) Unresolved Item 338,339/88-11-02, Potential for the recirculation
spray heat exchangers to have been inoperable during plant operations with
the service water supplied by lake water at a temperature greater than 83 .
degrees F. This item is being closed based on the licensee's evaluation
of the previous condition of the RSHXs, the chemical cleaning of the
RSHXs, and the leakage monitoring program initiated to ensure that the
RSHXs are maintained in a clean, dry condition. The licensee's original
analysis of the operability of the RSHXs assumed a SW flow rate of 4500
gpm. During a management ~ meeting (June 8,1988) in Atlanta, the licensee
reported that they had 4500 gpm SW flow through the RSHXs during the
chemical flushing of the heat exchangers. Based on the testing that has
been performed during this outage (See NRC Inspection Report
338,339/89-08, paragraph 4), it is clear that the SW flow rate through
several of the RSHXs was not 4500 gpm. The question of operability of the
RS system will continue to be tracked by the apparent violation discussed
in paragraph 4 of NRC Inspection Report 338,339/89-08. Therefore, this
unresolved item is considered closed.
(0 pen) IFI 339/89-03-05, Determine cause for failure of 2-CH-2115E to
close and cause for the reset sticking of relay K-604 during safety
inspection functional test and take corrective action. The failure of
2-CH-2115E to close was determined by the licensee to be a limit switch
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adjustment problem. The limit switch was readjusted and the valve was
retested satisfactorily. This IFI will remain open pending the licensee's
resolution of K-600 relay sticking problems.
(Closed) Item 338, P2186-01, Power supply failures of SLV relays. The
licensee has indicated that all applicable in-service SLY ratings have had
their power supply circuitry modified to prevent power supply " hang-up" on
relay energization. Documentation for this modificati^r. is not presently
available for review. This item is closed and re-opened as IFI
338,339/89-14-05 pending licensee submittal of the referenced
documentation.
13. Preparation for Refueling (60705, 60710)
On April 30, the inspector reviewed the completed refueling master
procedure 2-0P-4.1, Controlling Procedure for Refueling. No problems were
identified. This review was conducted to close out the completed Unit 2
refueling evolutions and facilitate the preparations for the Unit I
refueling.
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On May 5, the inspector attended a briefing conducted by the Westinghouse
Supervisor in charge of refueling activities concerning the impending
vessel head lift and subsequent fuel movement. During the briefing, the
refueling shift supervisor provided some additional comments, including an
explanation that he was the final authority on stopping and starting the
refueling evolutions. Refueling activities actually commenced on May 8
and the core off-load was completed on May 11. The inspectors witnessed
several fuel assemblies being off loaded. Also, prior to the core
off-load, the inspec^or observed the performance of 1-0P-41.5, Manipulator
Crane, and the resulting setting of the crane limit switches. The core
on-load did not recommence during the inspection period due to the ISI
activities being conducted on the vessel. These inspections did identify
several indications in the vessel and nozzle welds which will be reviewed
by a regional inspector. The information concerning these vessel indica-
tions will be provided in NRC Inspection Report 338,339/89-20.
The licensee will be conducting UT inspections of the fuel assemblies
removed from the vessel to locate any leaking assemblies. The RCS
activity on Unit I was elevated prior to the refueling outage indicating
problems of leaking fuel assemblies. The licensee had experienced some
baffle jetting in.the past and is installing additional grid straps on
susceptible fuel assemblies until long-term corrective action can take
place. The inspectors will continue to follow the refueling activities.
14. Evaluation of Licensee Self-Assessment Capability (40500)
The inspectors conducted a review of the licensee's self-assessment
capabilities during this inspection period. The review involved the
attendance at several of the licensee's off-site and on-site independent
and safety committee review meetings, a review of previous committee
meeting minutes, a determination of the licensee's compliance with TS and
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the overall effectiveness of the review comittee. Based on these
reviews, the inspectors concluded that the corporate independent review
group was not in full compliance with TS. Corporate management, though, ,
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is in the process of significantly upgrading the independent oversight
functions. The inspector did identify a strength in the licensee's
self-assessment capabilities. This strength involved North Anna station
management's implementation of the self-assessment program and the recent
startup assessments performed prior to the unit restart from the refueling
outage. Both of these items have provided station management with more
objective tools to be able to make informed decisions and to provide
management attention where it is most needed.
On May 17, the inspector attended a MSRC meeting conducted in the
licensee's corporate office. The MSRC, a recently developed management
oversite committee, was established by the licensee to provid9 a broad '
management overview of all nuclear related activities and to act in an
oversight role for other groups performing review functions. The
comittee chairman will be the Vice President of Nuclear Operations, with
the Vice Chairman being the Assistant Vice President of Nuclear
Operations. The committee members will include both of the station
managers, the corporate managers associated with nuclear support, and at
least one consultant. The meeting attended by the inspector was the
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committee's second meeting. In that the charter had just been developed,
the committee will function for several months before a TS amendment would
be submitted to establish the comittee as a TS independent review group.
The information provided in the meeting was very well presented and the
questions raised by the committee showed both an interest and cc..;ern for
the topics being presented. However, sinca this was the second meeting,
the committee has not developed a method for addressing their concerns and
tracking these items to ensure that they are properly resolved. This
particular problem was identified during the meeting to be resolved by the
next meeting. The inspector believes that this comittee, if properly
implemented and maintained, will be an effective method for corporate
management to maintain an up-to-date understanding of the issues reviewed
and ensure that the proper management oversight is being provided. The
inspector plans to attend several comittee meetings in the future to
determine the actual effectiveness of the process.
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Also on May 17 and 18, the inspector conducted a review of the licensee's
TS required independent review committee. This review involved attendance
of a review committee monthly meeting on May 18, a review of previous
committee meeting minutes, a review of the group's implementing
procedures, discussions with several of the staff specialists and a
determination of the committee's compliance with TS. TS 6.5.2.7 requires
the following subjects to be reviewed by the corporate independent review '
committee:
a. Written safety evaluations of changes in the stations as described in
the Safety Analysis Peport, changes in procedures as described in the
Safety Analysis Report and tests or experiments not described in the
, Safety Analysis Report which are completed without prior NRC approval
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under the provisions of 10 CFR 50.59(a)(1). This review is to verify
that such changes, tests or experiments did not involve a change in
the technical specifications or an unreviewed safety question as
defined in 10 CFR 50.59(a)(2) and is accomplished by review of
minutes of the Station Nuclear Safety and Operating Committee and the
design change program.
b. Proposed changes in procedures, proposed changes in the station, or
proposed tests or experiments, any of which may involve a change in
the technical specifications or an unreviewed safety question as
defined in 10 CFR 50.59(a)(2). Matters of this kind shall be
referred to the Director-Safety Evaluation and Control by the Station
Nucitar Safety and Operating Comittee following its review prior to
implementation.
.
c. Changes in the technical specifications or license amendments
relating to nuclear safety prior to implementation except in those
cases where the change is identical to a previously reviewed proposed
change,
d. Violations, REPORTABLE EVENTS and Special Reports such as:
(1) Violations of applicable codes, resultations, orders. Technical
Specifications, license requirements or internal procedures or
instructions having safety significance;
(2) Significant operating abnormalities or deviations from normal or
expected performance of station safety-related structures,
systems, or components; and
(3) ALL REPORTABLE EVENTS submitted in accordance with Section 50.73
to 10 CFR Part 50 and Special Reports required by Specification
6.9.2.
Review of events covered under this paragraph shall include the
results of any investigations made and recommendations resulting
from such investigations to prevent or reduce the probability of
recurrence of the event.
e. The Quality Assurance Department audit program at least once per 12
months and au.dit reports.
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f. Any other matter involving safe operation of the nuclear power
stations which is referred to the Director-Safety Evaluation and
Control.
g. Reports and meeting minutes of the Station Nuclear Safety and
Operating Comittee.
The review of the independent review committee's meeting minutes revealed
very little about the effectiveness of the comittee, since only the
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agenda and any supporting handouts supplied by the presenters were
maintained in the minutes. There was no mention of questions or_ concerns
raised by the comittee, how the committee tracked these concerns if any
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or whether or not the committee was able to raise concerns and effectively
resolve them. Also, the meeting attended by the inspectors on May 18 did
not shed any further light on the committee's effectiveness. During the
meeting, there were several good presentations made by the licensee, but
these presentations for the most part generated no in-depth questions or
concerns. The inspectors were later informed that the meeting was not ;
typical and that the inspector's presence had inhibited the committee's !
staff specialists. I
The inspectors determined, based on discussions with licensee personnel-
and reviews of the committee's procedures, meeting minutes and reports, ;
that the major problem was not the qualifications of the specific
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committee members, but rather a lack of resources dedicated to the i
committee functions. The TS requirements for a Director and three staff l
specialists were being complied with. However, the work load established i
by the TS could not be maintained effectively by a staff that size and to
complicate the matter, the licensee assigned collateral duties for the
Director'and the specialists such that only a portion of their time was
devoted to independent review. The inspectors were informed though, that j
the licensee was revising the entire program by increasing the committee's
size from a Director and three staff-specialists to a Director and j
approximately 22 personnel located at both the sites and the corporate '
office, and by providing the requisite management attention to ensure
proper implementation. This change in the program was based on a
management consultant's review which informed licensee management that
their independent review functions 'were not consistent with the rest of
the industry. i
Based on the above review, the inspectors determined that the corporate .
independent review group was not in full compliance with TS. For example, I
the committee does not conduct the required reviews as described in TS i
6.5.2.7.a for safety evaluatioris relating to; a) changes to the plant
through the EWR system, b) changes to procedures, and c) special tests,
4
In addition, the committee does not review all SNSOC repsts and meeting
minutes as required by TS 6.5.2.7.g. and described in TS 6.5.2.7.a. l
Finally, the inspector determined that the corporate independent review
group does not review all reportable events, violations, and special
reports required by TS 6.5.2.7.d. Failure of the independent review group ,
to conduct the required TS reviews will be identified as violation 338, i
339/89-14-01. i
In addition to the inadequate TS required review activities, the inspector
also perceived a management attitude which possibly affected the poor
performance of the review committee. There was the appearance that
management either did not understand the TS requirements for the ;
independent review group or was not beino informed that the group was not
properly performing its intended function. This perception was reinforced "
through discussions with several licensee personnel involved in the
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committee activities. Specifically, the Manager of Licensing stated that
although the intent of the TS review may not have been met, the letter of
the TS was being achieved. During this review, neither intent nor letter
was noted to be achieved. The superficial committee review, as noted in
the above violation, and the apparent compliance attitude observed during
the inspection, raises a concern with the inspector over the licensee's
management's past attitudes toward. this committee's regulatory
performance, and also the commitment of management to provide the support '
necessary to ensure the satisfactory implementation of the independent
review function.
The inspector also attended several of the station's safety review
committee (SNSOC) meetings and reviewed 14 committee meeting minutes for
meetings conducted during 1988. Based on these reviews, the inspector
concluded that the station safety committee was in compliance with TS.
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The only problems noted were a backlog of several months of the typed
versions of the SNSOC meeting minutes and the volume of work placed on the
safety committee. The inajority of the items reviewed are procedure
changes, indicating that the procedure upgrade process has not had the
time to become effective in reducing the number of procedure changes
required. The safety committee meets almost daily, fully complying with
the TS required monthly meeting. The inspector has determined that the
SNSOC has been effective in identifying problems and concerns, as
evidenced by adequate deportability determinations for plant deviations,
satisfactory 10 CFR 50.59 reviews, and properly evaluated JCDs.
The inspectors reviewed the station's nuclear safety engineering group's
functions and effectiveness. This group, which works for the Assistant
' station Manager for Safety and Licensing, provides an independent safety
engineering function, the shift technical advisor function, the human
performance evaluation function, the nuclear plant reliability data system <
function, deviation report tracking and trending, and operating experience
review. This group performs independent evaluations at the station, which
compensates to some extent for the incomplete reviews performed by the
corporate independent review group. The inspector has observed an
increase in the licensee's effectiveness in reviewing operating experience i
such as IEINs, 10 CFR 50.73 reports, station deviations and other 1
activities. This group is also responsible for performing safety
evaluations for EWRs, special tests, jumpers, JCOs, TS and UFSAR changes, ;
and prior-to-use procedure deviations as well as independent review of '
safety related procedures and tests, design changes and changes to TS, at
the discretion of the SNSOC chairman. The only problem identified by the .
inspector is that the resources devoted to the nuclear safety engineering !
group appear to be strained. The group's effectiveness could be increased
by an increase in resources.
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- Along with the above assessment capabilities at the station, the station j
management has established a self assessment program. This program
involves compiling, in one report, all of the information available at the
station which would provide some insight on their performance. This -
report provides management with a tool to objectively assess the station's
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performance and determine where additional management attention is needed.
The most recent self-assessment was performed in a SALP format.
Not only has the station management developed self-assessment capability j
for the station, but the recent restart of Unit 2 was preceded by'a
startup assessment. This assessment involved the superinter. dents of each
department providing station management with a presentation and report
concerning their areas of responsibility. These presentations and reports.
not only described the accomplishments of the groups, but focused on the
items which were not completed and/or problems that had not been resolved. ,
The presenter had to demonstrate why these items would not affect the i'
restart of the unit or explain how they would be resolved prior to
restart. The Unit 2 startup assessment provided station management with
an objective tool to ensure all items, prob 1 cms or concerns were ,
addressed, properly reviewed, corrected or accepted prior to restart. The
startup assessment is new, but the inspector was impressed with the
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program, the candidness of the presentations, and the desire by station
management to be fully informed of all problems and concerns e that a
well informed decision to restart the unit could be made.
15. Exit -
The inspection scope and findings were summarized on May 31, 1989, with
those persons indicated in paragraph 1. Violation 338,339/P9-14-01 was
also discussed with the Manager of Licensing on May 18, 1989. The
inspectors described the areas inspected and discussed in detail the
inspection results listed below. The licensee did not identify as
proprietary any of the material provided to or reviewed by the inspectors
during this inspection. Dissenting comments were received from the
licensee at the May 18, 1989 exit as discussed in paragraph 14.
.
Violation 338,339/89-14-01, Failure of the licensee's independent review
group to perform all of the reviews required by Technical Specifications
(paragraph 14).
Violation 338,339/89-14-02, Failure of procedures to control maintenance
operations with two examples (paragraphs 7 and 9).
Violation 338,339/89-14-03, Failure of the procedures to adequately
control the location of fuel assemblies during fuel movement operations
(paragraph 9). .
Apparent Violation 338,339/89-08-03, An additional example of failure to
provide design basis SW flow to the safety-related RSHX (paragraph 5).
Non-Cited Violation 338,339/89-14-04, Failure to comply with TS 3.11.1.3
and issue the special report in the required 30 day period (paragraph 7).
Inspector Follow-up Item 338,339/89-14-05, Review documentation to support
power supply modification of SLV Relays (paragraph 12).
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16. Acronyms and Initialisms
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AP Abnormal Procedure
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CAD Computer Assisted Drawing
l CAE Condenser Air Ejector
CDA Containment Depressurization Actuation
CPU Central Processing Unit
CR0 Control Room Operator
CVCS Chemical Volume'and Control System
DCP Design Change Package
DHR- Decay Heat Removal
DUR Drawing Update Request
EDG Emergency Diesel Generator
EP Emergency Procedure .
ESF Engineered Safety Feature
EWR Engineering Work Requests
FAI Fuel Audit and Inspection
FHDS Fuel Handling Data Sheet ~
GPM Gallons Per Minute
HP Health Physics
IFI Inspector Follo*-up Item
IST Inservice Testing
-JC0 Justification for Continued Operations
LC0 Limiting Condition for Operation
LER Licensee Event Report
MCC Motor Control Center
MFRV Main Feedwater Regulatory Valve
MOV Motor Operated Valve
MPC Maximum Permissible Concentration
MREM Millirem
MSRC Management Safety Review Committee
MSVH Main Steam Valve House
NA Not Applicable
NCV Non-Cited Violation
NIS Nuclear Instrumentation System
'NRC Nuclear Regulatory Commission
NSE Nuclear Safety E'ngineering
PDTT Primary Drain Transfer Tank
PES Plant Engineering Services
PM Preventative Maintenance
PORV Power Operated Relief Valve
PROM Programmable Read Only Memory
PSIG Pounds Per Square Inch Gauge
PTS $ Periodic Test Scheduling System
RMS Radiation Monitoring System
RSHX Recirculation Spray Heat Exchanger
RTD Resistance Temperature Detector
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RWP Radiation Work Permit
SALP Systematic Assessment of Licensee Performance
SF/FF Steam Flow /Feedwater Flow
SI- Safety Injection
SNSOC Station Nuclear Safety and Operating Committee
SRO Senior Reactor Operator
STA . Shift Technical Advisor
SW Servi'e
. Water.
TS Tp;nnical Specification
UE Unusual Event ;
UFSAR Updated Final Safety Analysis Report "
URI Unresolved Item
UT Ultrasonic Testing '
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VCT Volume Control Tank
WOG Westinghouse Owners Group
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