IR 05000338/1991003
| ML20029C034 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 03/06/1991 |
| From: | Frederickson P, Lesser M, Menning J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20029C032 | List: |
| References | |
| 50-338-91-03, 50-338-91-3, 50-339-91-03, 50-339-91-3, NUDOCS 9103250144 | |
| Download: ML20029C034 (13) | |
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UNITED STATES
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NUCLEAR REGULATORY COMMIS$10N
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REo!ON11 101 M ARIETTA STREET, N.W.
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t ATLANT A, GEORGI A 30323
%,.....,o Report Nos.:
50-338/91-03 and 50-339/91-03 Licensee: Virginia Electric & Power Company 5000 Dominion Boulevard Glen Allen, VA 23060 Docket Nos.: 50-338 and 50-339-License Nos.:
NPF-4 and NPF-7 Facility Name: North Anna 1 and 2 Inspection Conducted:
January 20 - February 16, 1991 Inspectors: MId b-3/I'/#/
M.S. L6ss,er/ Senior Resident Inspector fat 6 Signed kWW hv W WG/
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~fE. MenniT1))/ P,4sident Inspector Dhte'Si~gned Accompanying In ector:
A. B. Ruff
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Approved by:
P.E. Fredrickson, Section Chief Efate Signed Division of Reactor Projects SUMMARY Scope:
This routine inspection by the resident inspectors involved the following areas:
operations, maintenance, surveillances, evaluation of licensee self assessment, licensee event report followup, and action on previous inspection findings.
Inspections of licensee backshift activities were conducted on the following days:
January 20, February 6 and 10,1991.
Results:
In the area of operations an effective management tool was identified involving condition while in modes 5 or 6 (parameters and the margin to an unacceptable a graphical display of critical paragraph 3.c.).
In the area of operations one non-cited violation was identified involving inadequate controls to ensure all containment penetrations through the equipment hatch are properly isolated during core alterations. One rubber hose was found to be open on both ends and a second rubber hose was found to be isolated with an inadequate check valve (paragraph 3.b.).
In the area of quality verification / safety s,ssessment one non-cited violation was identified involving the failure to maintain portions of the UFSAR updated.
A large backlog of items not yet incorporated exists and the licensee is now devoting management attention to resolve the issue (paragraph 6).
9103250144 910308 PDR ADOCK 05000338 Q
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REPORT DETAILS
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1.
'Persnns-Contacted-
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Licensee Employees
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. *L._Edmonds. Superintendent, Nuclear Training R. Enfinger,-Assistant Station Manager
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M. Gettleri Superintendent.. Site Services
- J. Hayes, Superintendent, Operations
- D. Heacock, Superintendent, Engineering l
G. Kat.e, Station Manager
- P. Kemp, Supervisor, Licensing _
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.W. Matthews,-Superintendent, Maintenance.
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O.: Roberts, : Supervisor, Nuclear Safety Engineering
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R. Shears.: Superintendent, Outage Management
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- J. Smith, Manager, Quality Assurance
- A. Stafford, Superintendent,. Health Physics
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(*J. Stall.. Assistant Station Manager
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Other licensee employees contacted, included engineers, technicians, i
operators, mechanics,= security force membert,.and office personnel..
NRC Resident Inspectors
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l *M.:Elesser, Senior Resident Inspector:
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'*J. Menning,< Resident Inspector-
- Attended exit interview
-Acronyms and initialisms used throughout this report are listed'in the'
last7 paragraph, 2.-
. Plant; Status
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Unit 'l sstarted the inspection period in mode' 6, refueling.- Fuel offload-
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commenced on January 27.
Fuel movement was suspended when the fuel.
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transfer ' cart drive train failed.
Othercproblems were: encountered with the cart waich delayed fuel offload until February 1. - The licens* made sprompt nutification to the NRC after determining that all three eteam generators were classified as "C-3" pursuant to Technical Specification ~
4.4.5.0.
- Category "C-3"- means: greater than 1: percent of the inspected i
L tubes are. defective and requires NRC approval for restart (Unit 1 only).
I The licensee's original eddy current inspection plan included:
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Bobbin inspection of -100 percent hot and cold leg tubes (full length).
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Rotating Pancake Coil of 100 percent hot leg tubes at -the top of 'the
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18X1 probe inspection of 600 tubes in the hot legs
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As a result of indications fourd, the scope of the program was expanded to include additional 8X1 inspection up to the fourth support plate in the hot leg of all tubes. The expanded scope added approximately five days of
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critical work' activity to the refueling schedule.
The decision was also made to pull three tubes for further analysis.
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Core reload started on February 7 and was completed February 9.
Following-completion of fuel movement the licensee identified a breached penetration to the-containment required to be isolated.
This issue is further discussed in paragraph 3.b.
The unit ended the inspection period in mode 5, day '35 of the outage.
Unit ~ 2 operated the entire inspection period at 100 percent power completing day 106 of continuous operation.
3.
Operational Safety Verification (71707)
The inspectors conducted frequent visits to the control room to verify
_ proper staffing, operator attentiveness and adherence to approved procedures.
The inspectors attended plant status meetings and reviewed operator logs on a daily basis to verify operational safety and compliance
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-with TS: and to maintain awareness of the overall operation of the facility.
Instrumentation and ECCS lineups were periodically reviewed
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from control room indicaticns to assess operability.
Frequent plant tours were conducted to observe equipment status, fire protection programs, radiological work practius, plant security programs and housekeeping.
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Deviation reports were reviewed to assure that potential safety concerns were. properly addressed and reported.
Selected reports were followed to
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ensure that appropriate management attention and corrective action was E
applied.
-a.
Control Rod Drive Shaft Coupling:
The inspectors observed control ' rod drive shaf t coupling activities on tinit 1.
Procedure 1-0P-4.4, Control Rod Drive 3haf t Handling Tool Operating Instructions, was used 'to control-and document activities.
The evaluation was conducted in.a controlled manner and the operators were knowledgeable of the hardware and the procedure.
In order to couple a drive shaf t to a control rod, the -prc:edure requires positioning the handling tool over the drive shaf t until the spring scale-reads zero pounds, indicating the weight of tool is supported by the drive shaft.
Procedural steps direct the operator to engage the tool with the drive shaf t.
Verification of engagement is done by lifting one-half to three inches while observing the spring scale to indicate "approximately 350 pounds" (weight of handling tool and drive shafts).
The procedure then directs the operator to lower the
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handling tool and couple the drive shaf t to the centrol rod.
Proper coupling is verified by raising the hanCing tool three inches and observing the load on the spring scale.
The inspectors noted the following problems with the procedure:
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An acceptance criteria for the combined weight of the tool,
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drive shaf t and control rod-was not specified.
A review of the recorded data showed these values to range between 380-440-
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pounds.
Step 4.3.6 'of the procedure requires the operator to observe the
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spring-scale indicating "approximately 350 pounds" as the Height of the tool and drive shaft.
Step 4.3.7 lists this acceptar.ce
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criteria as "approximately 330 to 350 pounds."
The inspector noted.that this weight actually ranged from 260 to 280 pounds.
The inspector. questioned the results and was later told that an alternate handling tool had been used which weighed 50 pounds less that' the primary tool, for which the procedure was written.
It appears -that the operators broadly interpreted the criteria and should have -initiated a procedure enange to mcre clearly specify the acceptance criteria.
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Drawings of the control rod drive shaf t and henoling tool in
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attachments to the. procedure were not legible.
Spring scale calibration information (calibration date and
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serial. number) was'not recorded in the' procedure.
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The licensee was informed of these discrepancies for dispbsition.
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b.
Containment Penetrations.During Core Alterations.
On February 9,1991 the licensee identified a breach of containment '
penetration following completion of core onicao. Formal notification to the NRC was made in accordance with 10 CFR 50.72.
In preparation for refueling activities, the lic9nsee removed the escape hatch from the containment equipment hatch and replaced the hatch with a' plate.
The plate has several penetrations through which numerous electrical
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cables. and hoses were. run to support the outage.
TS 3.9.4 requires
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that.during core alterations these penetrations be sealed in order to j
restrict radioactive material' release from a postulated fuel element rupture (Containment pressurization is not assumed).
The licensee implemented the requirement with. procedure 1-PT-91, hntainment Penetrations, which among other things, requires all mechanical penetrations through the equipment hatch. to have che::k-valves installed or some other method to prevent outleakage from containment.
Due to the number of hoses and cables penetrating. the -
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equipment hatch, the Refueling SRO, on February 9, had concerns regarding the accountability of hoses.
A walkdown ider,tified a 3/4 inch black hydro hose open at both ends.
The hose was entangled and mixed with numerous electrical cables. The black hose ar>parently
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was mistaken for an electrical cable and missed during previous performances of the TS surveillance, which requires the penetrations to be verified isolated within 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> prior to core alterations and once per seven days during core alterations.
A red 3/4 inch air hose was also discovered with a check valve installed that contained a small equalizing hole in the disc.
The improper use of this type check valve resulted in the red air hose being unisolable.
The inspectors reviewed the licensee's program for ensuring integrity of the equipment hatch pt ietrations and reached the following conclusions:
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Cables and hoses enterkg the pe.etrations are not labelled or adequately ecccunted for.
For axample, on one day,1-PT-91 listed the following five raechanical penetrations through the equipment t!atch door:
" sludge lance, sludge lance, breathing air, service air, service air."
No description of the hose, accounting nurter or attempt to distinguish between similar hoses was done.
In this case it was not clear whether the 3/4 inch red rubber air hose was accounted for.
Procedures for bringing new hoses and cables through
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penetrations were inadequate in that requirements to document them in 1-PT-91 or the 1-PT-91 Breuh Log (a log to account for open penetrations during periods whee core alterations have been temporarily suspended) did not exist.
The program inappropriately required operations personnel to identify all hoses and account for them in an after-the-fact method.
The licensee agread with the inspectors' findings and identified rral corrective actions to prevent recurrence, including a root
.cause evaluation (at-the end of the inspection this had not yet been determined), a Human Perfc7mance Enhancement System evaluation, additional requirements and guidelines for ensuring proper instal-lation and use of check valves, and the implementation of a penetra-tion accountability document that includes labelling hoses, cables, and other criteria. The licensee additionally reviewed the event for safety significance following a postulated fuel handling even. A conservative evaluation yielded a release of 0.04 per cent of the release assumed in Chapter 15 of the UFSAR.
The inspectors identified other areas in the procedure wher e improvement is needed but did not directly effect this avent.
It is not clear from the procedure on how check valves in piping
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systems may be used to form the boundary, in some cases the check valve is used as an isolation valve, preventing reurse flow and in other cases, the body of the check valve provides piping integrity.
In the case of service water supply and return lines to the recirculation spray heat exd angers, check valves are not leak tested.
The licensee's intent is to maintain integrity by ensuring the body of the check valve is
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intact and - thus maintaining a closed piping system inside -
containment, in order to do this, the supply and. return.
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penetrations for a particular loop must be addressed together
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and not independently as the procedure might suggest.
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case of one ' service water penetration,' the licensee was fortuitous in that the closed piping system, with a check valve s,
for isolation purposes, was not breached.
If the piping system had been breeched, the check valve,1-SW-150, would have been ineffective as an isolation device because it was discovered to be stuck open,
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Normally a valve identified to be closed is initialled by the-t
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Shift Supervisor, however, in - some cases one initial inappropriately applied to two valves (penetration 2, -10, 45, s
62,114).
It appears in' this event that procedures were inadequate to ensure-
- all containment penetrations were-isolated.- This licensee identified.'
violation, NCV 50-338/91-03-01, Inadequate:-Procedures to Ensure Isolation of Containment Penetrations,._is not being cited because criteria-specified in Section V.G.1 of -the NRC Enforcement Policy were satisfiG. The inspector will review the full implementation of
. the licensee's corrective action when it.is complete.
c.
Mode 5 and 6 Critical Parameters:
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The licensee.has recognized a need for _ increased sensitivity regard--
c ing the-management of operable equipment while in modes 5 or 6 a:d has-implemented a graphic tool to maintain awareness of the sta*;.s of critical - parameters.-
Typical. = parameters monitored are the operability of emergency diesel generators, RHR pumps, service water l
pumps, Tboration flow paths, - shutdown margin - ana offsite power-sources. The margin to-an unacceptable condition is graphically
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displayed for each critical: parameter and available for management review each morning A projection for the next day is also prepared.
the display is intended to be used by management for planning
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purposes and _not by operators who will stil1 rely on Technical P
Specifications and station procedures.
The : critical parameters graphical' display _ appears -to - be_ usefuli and 'is an example of
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management's comitment to safe operations while shutdown.
One non-cited violation was identified.
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MaintenanceObservation-(62703)
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Station maintenance activities were observed / reviewed to ascertain that the activities were conducted in accordance with-approved procedures, j
regulatory guides and industry codes or standards, and-in conformance with
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L TS requirements.
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lhe following maintenance activities were reviewed:
DCP 87-30-1 CRDR Auxiliary Feedwater Flow Indicetion DCP 89-43-3 Service Water Expansion Joint Replacement No violations or deviations were identified.
5.
Surveillance Observation (61726)
The inspectors observed / reviewed TS required testing and verified that testing was performed in accordance with procedures, that test instrumen-tation was calibrated, that LCOs were met and that any deficiencies identified were properly reviewed and resolved.
The following survei' lance activity was observed.
ICP-1-ER-2 Instrument Calibration for Triaxial Peak Shock Recorder T'
'echnicians were observed to be knowledgeable of the equipment and
ii sration procedure.
No violations or deviations were identified.
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6.
Evalur. tion of Licensee Self Assessment (40500)
The inspectors reviewed licensee actions taken to resolve Quality Assurance Department audi t findings of UFSAR discrepancies.
(Audit findings N-88-16 B and N-88-19-06),
in 1988 numerous examples of UFSAR inconsistencies we:c identified by Quality Assurance, in addition to correcting the identified discrepancies, long term actions included a UFSAR Validation Project, completed in January 1990, which identified approximately 61 needed changes. The inspectors became aware of a backlog totaling approximately 110 changes wafting to be incorporated.
Discounting the 61 from the 1990 Validation Project, the remaining changes consisted generally of design modifications made to the facility.
While the majority of the modifications were implemented in 1989 and 199C. an excessive number involved older changes including 10 examples from 1987, 2 from 1986 and 1 each from 1984 and 1982.
The inspectors determintd that programatic weaknesses Existed with the licensee's ability to maintain the UFSAR as required by 10 CFR 50.71(e) and efforts to improve have been ineffective.
An accurate and dependable UFSAR has particular importance for safety evaluations required by 10 CFR 50.59 and future efforts to I-___
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relocate some of the requirements in Technical Specifications.
Discussions with licensee personnel revealed sevetal problems including burdensome administrative controls, inefficient processing of the proposed text changes, and a lack of accountability regarding attention and promptness.
The licensee recognizes the weakness and is proposing a plan to improve the process and eliminate the excessive backlog.
It appeared to the inspectors that after raising this issue, appropriate management
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attrntion will be given.
10 CFR 50.71(e) iequires that annual UFSAR rev sions reflect all changes to the f acility up to a maximum of 6 months pri.'r to the date of filing the revision to assure that the infonnation incluood in the UFSAR contains the latest material develuped.
This NRC identified violation is not being cited because the criteria specified in Section V. A.
of the NRC Enforcement Policy were satisfied.
NCV 50-338/91-03-02:
Failure to Maintain UFSAR updated.
One non-cited violation was identified.
7.
LERFollowup(92700)
The folio.ing LER was reviewed and closed, the int. tor verified that reporting raquirements had been met, that causes had been identified, that corrective actions appeared appropriate and that gtneric applicability had been considered.
Additionally, the inspectors confirmed that no unreviewed safety questions were involved and that violations of regulations or TS conditions had been identified.
(Closed) LER 338/89-02:
Voluntary LER on Instrument Air Events and UFSAR Discrepancies.
The LER reported various operational events involving the instrument air system.
The licensee completed major modifications to the system as corrective action including installation of oil free compressors and dryers. UGR update has not been completed and will be followed up under licensee cm4Ictive actions to NCV 50-338/91-03-02:
Failure to Maintain UFSAR updated.
C.
Action on Previous inspection items (92701, 92702)
a.
(Closed) P2189-01:
Brown Boveri K-Line Circuit Breakers, Model K-225 through K-2000, Delivered Prior to 1974 Need Rebound Springs Added to the Slow-Close Lever.
This Part 21 report also caused the issuance of NRC IN 89-29, Potential Failure of ASEA Brown Boveri Circuit Breakers During a Seismic Event. The manufacturer indicated that the slow-close lever, without the rebound spring, could be repositioned by a seismic event so that the breaker may not close, however, if the breaker was closed, it would open or trip normally during the seismic event. The installation of the rebound spring would maintain the slow-clerie lever in its normal position. The manufacturer notified all nuclear generating stations that purchased :.afety-related K-Line circuit breakers, model numbers K-225 through X-2000, prior to 1974 of this problem and they requested that all users add the rebound springs to the slow-close lever to ensure that the lever does not reposition itself during a seismic event.
The licensee completed the installation of the rebound springs for the applicable bretkers during the last Unit 2 outage in late 1990.
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Unit 1 is presently in an outage.
WRs and W0s have been issued for the installation of rebound springs to the the applicable Unit 1 circuit breakers.
Installation of rebound springs is in process and the licensee states Unit 1 circuit breaker modifications should be
complete before the unit is restarted, b.
(Closed)P2189-12: Limitorque Corporation Pre-1980 Model SMB-000 and Pre-1976 Model SMB-00 Cam-Type Torque Switches Can Fail as a Result of Stationary Contact Screws Loosening on Torque Switch Assemblies That Use Fiber Spacers.
l The above described potential problem was reported in a Part 21
Notification by Limitorque Corporation in September 1989. Limitorque
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installed fiber spacers under the contact bridge for these style torque switches to provide equal spring pack compression in both the open and closed directions.
The problem with the fiber spacor is that it can take a compression set and lose its resiliency.
This action could allow the stationary contact screws to lo7sen and tnus affect torque switch operation.
Any replacement torque switches which may have been purchased for SMB-000s after 1980 or SMB-00s after 1976.would not included fiber spacers and therefore do not fall within this Part 21 Notification. Limitorque recommended replacement of the cam-type torque switch that uses fiber spacers.
North Anna identified approximately 112 Unit 1 and Unit 2, safety-related MOVs which could possibly contain fiber spacers as l
part of the cam-type torque. switch assembly.
To date about 90 percent of MOV actuators in Unit 2 have been inspected and, where t
applicable, replacements have been made.. Most of this wor ( was done during the last Unit 2 outage in the fall of 1990.
Unit 1 is presently in an outage.
The licensee stated work in the area-of actuator / cam-type _ switch inspection and switch replacement is in process and a significant amount of the work will be completed before the unit is restarted.
Several w(. i orders for switch replacement were reviewed and found to be acceptable. Also a partial review was made-using the licensee's computer system on switch inspections l
and/or switch replacement work orders. _ The licensee has a program to perform these modifications and a tracking system to ensure
completion of this project.
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c.
(0 pen) IFl 338,339/88-06-03:
Calibration of Control Room Instrumentation.
Partial followup to this item was conducted in Inspection Report 338,339/88-31.
The licensee agreed to reevaluate the calibration program to incorporate control room indicators beyond those listed in Regulatory Guide 1.33, Appendix A. Section 8.
Both engineering and operations participated in the evaluatsion and a list of indicators was identified.
Indicators used to safely operate or shutdown the l
plant were included in the list. The calibration periodicity will be once every two years. The annunicators, recorders and computer points l
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associated with those instruments will be checked.
The current schedule is that the identified indicators be included in-the calibration program by June 1, 1991.
d.
(0 pen).URI 338/90-18-03:
Gas Stripper Inoperability and Potential for Unmonitored Release.
The licensee performed a safety evaluation and determined that no
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unreviewed safety questions exist when the gas stripper is. operated-without steam during normal at-power operat'ons.
The basis for the
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conclusion 1s that a potential rupture of the boron recovery-tank is bounded by the WGDT rupture analysis and the boron recovery tank is constantly vented to the process vent system.
The Haalth Physics and Chemistry Services Department in the corporate
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office-conducted a radiological evaluation for operating without use of the gas stripper.
Three scenarios were evaluated; A synopsis of.
t the evaluation and associated assumptions are described below:
-(1) The fission-product gases from the reactor. coolant in the VCT are stripped by the gas stripper, and directed to the.WGDT for
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further decay before releasing to the atmosphere via the process vent. The total curies released are calculated based on:
(a) _ Waste gas feed cycle:
30 days of feed 20 days of decay,
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and-two days of bleed for a typical gaseous waste processing mode.
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(b) Seventeen gpm of total letdown flow rate. to the gas stripper for both ~ units; f This is based on the. average
annual letdcwn flow rate and' size of_WGDT. A 1:gpm letdown
flow rate is also evaluated in the calculation.-
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lodine activities are not considered in. the evaluation
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since iodine removal rate is -less than.0.1 percent in gas stripper.
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(2). Fission product gases from the reactor coolant _in the CVCS and
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primary coolant' drain transfer tank are directed to the boron t
I recovery system _ without operation of the gas stripper.
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percent of the noble gas activities are assumed to be entrained in the boron recovery system for various time-intervals (i.e. 10 days Ltwo huurs and no decay) before venting via the process vent.
The other-50-percent of noble gases are vented without-any decay credit. North Anna';. experience with the degassing of reactor. coolant sampics indicated that 50 percent noble gas entrainment-is a reasonable assumption.
I-(3) Fission pro' duct gases from the reactor coolant in the CVCS and primary coolant drain transfer tank are directed to the boron recovery system without operation of the gas stripper.
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hundred percent of the noble gas activities are assumed to be i
entrained in the boron recovery system for various time intervals (i.e. 10 days, two hours, and no decay) before venting via the process vent.
The evaluation concluded tha. the site boundary whole body doses resulting from operating the GRTS without the gas stripper are generally a factor of four to seven higher than the cases with the gas stripper operating.
This is based on the assumption that the GRTS is operating continuously for one waste gas feed cycle and is
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dependent on the following design parameters and boron recovery system modes of operation:
(1) The percent of failed fuel in the primary coolant.
(2) Letdown flow rate to be processed in the gas stripper.
(3) Percent of noble gases entrained in the boron recovery system.
(4) Decay credit for noble gases entrained in the boron recovery system.
The difference in site boundary whole body doses for both cases (with or without the gas stripper) is minimal for low gas stripper flow rate. Yet, the difference can be substantial when the high flow rate is required for the degassing process.
The evaluation also noted that the overall maintenance activity on the gas stripper has not been above what should be expeci.ed for this system. Therefore, a thorough review of the gas stripper maintenance program may be needed before the gas stripper bypass option is contemplated.
A strong preventive maintenance program may eliminate some of the problems associated with the gas stripper operation.
The evaluation recommended that the gas stripper be maintained and operated as designed to provide maximum radiogas decay, if the gas stripper is to remain out-of-service as the normal mode of operation, a 10 CFR 50.59 review should be performed (completed) and the 31-day dose projection criteria for the operation of the GRTS in effect becomes the gaseous radwaste effluent release limits.
The-station to date is only using the gas stripper when degassing the primary plant during cooldown and depressurization.
The station has questioned some of the assumptions used in the evaluation, for example, the percentage of noble gases which come out of solution.
They are requesting further engineering evaluation in this area.
This item will remain open and will be followed up by regional inspectors to evaluate licensee actions and the acceptability of higher offsite doses during routine plant operation.
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(Closed) Apparent Violations 338,339/90-29-02:
Apparent Failure to e.
Perform a Safety Evaluation in Accordance with 10 CFR 50.59 on UFSAR CC System Change and 338,339/90-29-03; Apparent failure to Take Adequate Corrective Action to a Previous Enforcement Action.
An enforcement conference was held on January 8,1991 to discuss the above concerns.
The enforcement conference resulted in the determination that enforcement action would not be taken in these two cases, however, a Notice of Violation was issued on February 1,1991 involvin9 inadequate procedures which resulted in a failure to adequately control operations of the service water system.
This violation is closely related to apparent violation 338,339/90-29-01, and is now administratively assigned that number for tracking purposes and followup of licensee's corrective action, f.
(Closed) Unresolved item 338,339/90-27-01, Employees and Contractors Right to Access Their Fitness for Duty Records.
By NRC Region ll's letter of February 13, 1991 the licensee was informed of the NRC's position relative to the individual's right to have access to their Fitness for Duty records.
The licensee has informed the NRC that it has revised its procedure on this topic to be consistent with the NRC's position and is in compliance with Part 26, Appendix A. Subpart C, Section 3.2.
The licensee's corrective action closes both the Region 11 allegation Rll 90-A-0152 and the unresolved item.
9.
Exit (30703)
The inspection scope and findings were sumarized on February 19, 1991, with those persons indicated in paragraph 1.
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 not received from the licensee, item, Number Description and Reference NCV 338/91-03-01 Inadequate Procedures to Ensure isolation of Containment Penetrations, paragraph 3.b.
NCV 338/91-03-02 Failure to Maintain UFSAR Updated, paragraph 6
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12 10. Acronyms and initialisms
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CC Component Cooling CFR Codes of Federal Regulations
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CRDR Control Room Design Review CVCS Chemical Volume and Control System ECCS Emergency Corc Cooling System GPM Gallons per Minute GRTS Gaseous Radwaste Treatment System IFl Ir.spection Followup Item IN Information Notice LC0 Limiting Condition for Operation LER Licensee Event Aeport MOV Motor Operated Valve NCV Non-cited Violation NRC Nuclear Regulatory Commission RHR Residual Heat Removal SR0 Senior Reactor Operator TS Technical Specification UFSAR Updated final Sa?ety Analysis Report URI Unresolved item VCT Volume Control Tank WGDT Waste Gas Decay Tank
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WR Work Request WO Work Order-1
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