IR 05000317/1989027
| ML20006E296 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 02/07/1990 |
| From: | Cowgill C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20006E288 | List: |
| References | |
| 50-317-89-27, 50-318-89-28, GL-88-14, NUDOCS 9002220545 | |
| Download: ML20006E296 (21) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
50-317/89-27 j
Report Nos.:
50-318/89-28
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License Nos.:
DPR-69 l
t Licensee:
Baltimore Gas and Electric Company
Post Office Box 1475 Baltimore, Maryland 21203 Facility:
Calvert Cliffs Nuclear Power Plant, Units 1 and 2 Inspection at: Lusby, Maryland I
t-Inspection conducted: November 13 - December 31, 1989
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Inspectors:
James E. Beall, Senior Resident Inspector Andra A. Asars, Resident Inspector, Haddam Neck i
Lyn M. Kolonauski, Project Engineer, DRP
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Approved by:
I J 7 90 CuFtis J. CowgYll, Chief Date
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Reactor Projects Section No. lA
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Division of Reactor Projects Inspection Summary:
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Areas Inspected: This was a routine safety _ inspection by the resident inspec-tion staff. Areas reviewed included outage acti_vities; events occurring during
the inspection period; radiological controls; maintenance activities on the emergency diesel generators; outage surveillance activities; Fitness for Duty
Program training; testing of instrument air system required by Generic Letter
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- 88-14; deficiencies in electrical cable separation; system engineer training; Plant Operations and Safety Review Committee meetings; written reports submit-ted to NRC; equipment preservation during extended outages; and corrective
. actions for previous NRC concerns and findings in UFSAR revisions, Low Temper-
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ature Overpressure Protection, Emergency Procedure Guidelines, and emergency
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diesel generator fuel oil sampling and analysis program.
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t 9002220545 900207 PDR ADOCK 05000317
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Inspection Summary (Continued)
Results:
Two Violations were identified.
The first violation involved the identification of several examples of inadequate separation of safety related electrical cable (Section 6.2). This is indicative of a programmatic weakness in this area.
The seconc violation involved inadequate management attention in resolving protracted periods of out of specification steam generator chem-istry (Section 7.3).
Three Unresolved Items were identified.
The first involved the apparent absence of periodic testing of safety related instrument air accumulator check valves (Section 6.1).
The apparent lack of administra-tive cont.'ols for UFSAR revisions is also an Unresolved Item (Section 7.4.1).
The third item involved the apparent failure to review CEN-152 for applica-bility to licensee procedures (Section 7.4.3).
The increases in operations staffing in 1989 were noted and should strengthen operations programs (Section 2.1).
Improvements in diesel fuel oil sampling techniques resulted from effective corrective actions for an unrelated NRC Deviation (Section 8.0). The improved sampling techniques led to the identifi-cation and correction of sediment contamination in the fuel oil storage tanks (Section 4.1).
Ongoing investigation of an emergency diesel generator trip during a surveillance test was noted to be thorough (Section 4.2.1).
The pro-gram for training system engineers was determined to be a notable strength (Section 6.3). And the identification of a Unit 1 EQ problem during technical
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training was determined to be an example of competent, alert maintenance per-sonnel (Section 7.2).
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TABLE OF CONTENTS Page 1.
Summa ry of Facili ty Activi ti es (71707)*.....................
2.
Plant Operations (71707, 71710, 93702)......................
2.1 Op e ra t i o n a l S a f e ty.....................................
2,2 Engineered Safety Features System Walkdown.............
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2.3 Follow-up of Events Occurring During the Inspection Period...............................................
3.
Radiological Control s (71707)...............................
4.
Maintenance and Surveillance (61726, 62703, 71707)..........
4.1 Maintenance Observation................................
4.2 Surveillance Observation...............................
5.
Security (71707)............................................
5.1 Fitness for Duty Program Training (TI 2515/104).......
6.
Engineering and Technical Support (37700, 37828, 71707).....
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6.1 Instrument Air System Testing - Generic Letter 88-14...
6.2 Electrical Cable Separation Deficiencies...............
6.3 System Engineer Training...............................
7.
Safety Assessment and 'k111ty Verification (40500, 62703, 71707,90712,.92700)......................................
7.1 Plant Operations and Safety Review Committee...........
7.2 Review of Written Reports..............................
7.3 Equipment Preservation During Outages - Steam Generators...........................................
7.4 Review of Past Corrective Actions......................
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Follow-up of Previous Inspection Findings (61726, 92702)....
9.
Exit Meeting (30703),.......................................
- Each report section lists the NRC Inspection Manual procedure or temporary instruction that was used as inspection guidance, i
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DETAILS 1.
Summary of Facility 9.:tivities Unit I remained in cold shutdown for the duration of the inspection period
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for maintenance activities and resolution of management and safety issues.
Unit 2 remained defueled for the extended Cycle 8 refueling outage with the fuel in the spent fuel pool.
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Plant Operations
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2.1 Operational Safety The inspectors observed plant outage operations and verified that the plant was operated safely and in accordance with licensee procedures and regulatory requirements.
Regular tours were conducted of the
following plant areas.
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control room security access point
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auxiliary building protected area fence
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radiological control point intale structure
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electrical switchgear rooms diesel qe, nerator rooms
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auxiliary feedwater pump rooms turbine building
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Control room instruments and plant computer indications were observed for correlation between channels and for conformance with applicable technical specification (TS) requirements. Operability of necessary engineered safety features, other safety related systems and onsite and offsite power sources was verified.
The inspectors observed various alarm conditions and confirmed that operator response v;as in accordance with plant operating procedures.
Routine outage opera-tions surveillance testing was also observed. Compliance with TS and implementation of appropriate action statements for equipment out of service was verified.
Plant radiation monitoring system indications and plant stack traces were reviewed for unexpected changes.
Logs and records were reviewed to determine if entries were ac: urate and identified equipment status or deficiencies. These > ecords included operating logs, turnover checklists, system safety tags, and the lif ted lead and temporary nmper log.
Plant housekeeping controis-
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were monitored, including control and storage of flammable material and other potential safety hazards.
The inspector also examined the condition of various fire protection, meteorological, and seismic monitoring systems. Control room and shif t manning were compared to (
regulatory requirements and portions of shift turnovers were ob-
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served. The inspectors-found that control room access was properly I
controlled and a professional atmosphere was maintained.
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The inspectors reviewed the staffing level of the operations group and noted that substantial additional personnel had been hired during 1989.
Specifically, the number of plant operators increased from about 40 in December,1988 to 72 at the end of 1989. The licensee stated that the staffing increases were part of an effort to change from a five shif t rotation to a six shift rotation.
The operations
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procedures group has also been augmented, increasing from seven e
persons in December, 1988 to 16 at the end of 1989; the additional complement consists of contractors.
As noted in NRC Inspection Report 50-317/89-23; 50-318/89-23, a new position was established and staffed with an SRO-itcensed individual responsible for monitoring
and coordinating post-maintenance testing.
These - additional re-
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sources should help _to strengthen the operations programs.
In addition to normal utility working hours, the review of plant
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operations was routinely conducted during portions of backshifts (evening shifts) and deep backshifts (weekend and midnight shifts).
Extended coverage was provided for 50 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br /> during backshifts and 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> during deep backshif ts.
Operators were alert ano displayed no signs of inattention to duty or fatigue.
2.2 Engineered Safety Features System Walkdown
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In addition to routine observations made during regular plant tours, the inspectors conducted walkdowns of the accessible portions of
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selected safety related systems. The inspectors verified portions of the High Pressure Safety Injection system operability through reviews of valve lineups, control room system prints, equipent conditions, instrument calibrations, and control room indicatiord.
2.3 Follow-up of Events Occurring During Inspection Period During the inspection period, the inspectors provided onsite coverage and follow-up of unplanned events.
Plant parameters, performance of safety systems, and licensee actions were reviewed.
The inspectors confirmed that the required notifications were made to NRC. During event follow-up, the inspector reviewed the corresponding documenta-tion per Calvert Cliffs Instruction 118N, " Nuclear Operations Section Initiated Reporting Requirements", including event details, root cause analysis, and correctin actions taken to prevent recurrence.
The following events were reviewed.
2.3.1 Trailer Fire
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On November 14, 1989, at 8:25 p.m.,
security personnel notified the control room of smoke coming from the vicinity of temporary trailers located south of the intake struc-
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ture.
The fire brigade responded at 8:28 p.m.
and con-firmed the existence af a fire in a trailer used for train-ing sessions.
The tire was extinguished by 8:37 p.m.
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The inspectors verified that licensee response to the fire was in accordance with Emergency Response Plan Implementing L
Procedure 3.0, "Immediate Action."
Because-the fire was extinguished within ten minutes, it was not necessary for an Unusual Event to be declared.
Licensee investigation determined that the fire was caused by inappropriate disposal of smoking materials. Addition-ally, since keys for temporary buildings had not been pro-vided to Security for emergency use, the fire brigade was unable to easily gain access to the trailer.
In response to the event, the station smoking policy was reiterated during morning planning meetings and supervisors provided Security with heys to the temporary buildings.
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Inoperable Fire Hose Stations On December 11, 1989, the licensee identified that two valves which supply water to two fire hose stations were not included in the appropriate surveillance test procedure (STP). The flow paths to these hose sJations were declared inoperable in accordance with TS 3.7.11.1.c.
Notification was made to the NRC Operations Center on December 12, 1989.
Fire suppression valves FP-413 and FP-653 are manual, nor-l mally locked open, gate valves providing flow to hose sta-l tions 69-6 and 69-9.
Both were installed under Facility Change Evaluations. Following installation, however, these valves were not included in STP M-693-0, " Fire Suppression System Valve Cycling Test," which implements the annual fire suppression system valve cycling requira,'ent in accor-dance with TS 4.7.11.1.1.e.
The licensee identified the omission during routine performance of STP M-693.
Because these valves had not been verified as operable through an STP, the licensee declared the flow paths to be
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inoperable. Both valves were unlocked and stroked to ver-ify operability, thereby restoring the flow path. Noncon-formance Report 8932 was initiated for this event.
A special report was submitted to the NRC as required by TS action statement 3/4.7.11.b.2.b.
The inspectors discussed the system modification, flow path
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operability, and reporting requirements with Fire Protec-tion personnel.
No additional inadequacies were is s
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Radiological Controls I
During routine tours of the accessible plant areas, the inspectors ob-served the implementation of selected portions of the licensee's Radiolog-ical Controls Program. The utilization and compliance with special work permits (SWPs) were reviewed to ensure detailed descriptions of rdiolog-
ical conditions were provided and that personnel adhered to SWP require-
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ments. The inspectors observed controls of access to various radiolog-ically controlled areas and use of personnel monitors and frisking m thods E
L upon exit from these areas. Posting and control of radiation areas, con-taminated areas and hot spots, and labelling and control of containers holding radioactive materials were verified to be in accordance with licensee procedures.
4.
Maintenance and Surveillance
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4.1 Maintenance Observation The inspectors observed various maintenance and problem investigation activities for compliance with procedures, plant TS, and applicable codes and standards.
The inspector also verified the appropriate quality control (QC) personnel involvement, safety tags, equipment alignment and use of jumpers, radiological and fire prevention con-trols, personnel qualifications, post maintenance testing, and repor-tability.
The inspector witnessed and reviewed portions of the mais,
tenance activities associated with the drain down, cleaning and
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refilling of the Nos.11 and 21 Emergency Diesel Generator (EDG) Fuel Oil Storage Tanks (FOSTs). These activities were performed under the following Maintenance Orders (Mos):
M0 209-334-393C, "A&A 011 to Cleu Ne. 21 FOST"
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M0 209-334-394C, "A&A 011 to Clean No.11 FOST"
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M0 209-363-148, " Remove Top Manway from No. 11 FOST"
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No inadequacies were identified.
4.1.1 Emergency Diesel Generator Fuel Oil, Tank Contamination
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The licensee has changed techniques for sampling the FOSTs following an internal review of sampling commitments and requirements.
This review was conducted as part of the corrective actions associated with a Deviation identified in a previous NRC inspection (see Section 8.3). The cuar-terly samples under the new criteria (takea froni ASTM 0270-65) were first perfor.ned in August, 1989. This pro-
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cedure involves multi-level samples from each FOST rather than sampling from only the tank outlet as was done
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The August, 1989 sample results were determined to be
acceptable, however, the results from the November, 1989 samples identified sediment contamination.
The fuel oil delivery trucks had been sampled with acceptable results prior to filling the F0STs. The recent analysis concluded that the sediment was normal fuel oil breakdown products and dead biological products. The licensee has postulated
that a gradual buildup of these contaminants occurred. The i
FOSTs are cleaned every ten years and were last cleaned in
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1984.
The day tanks for the EDGs and the diesel driven fire pump were sampled and were found to be acceptable.
Based on required fuel inventcries, tht. EDGs were declared
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Although the day tank inventory for the fire pump met TS requirements for fire fighting duration, the fire pump was declared inoperable based on the FOST sample results.
I The multi-level sample identified that recirculation of the FOSTs or the addition of new fuel (via a tap low on the tank) stirred up the sediment which had built up on the bottom of each tank. As the sediment physically settled, the fuel oil did not meet ASTM requirqtments. After settle-ment was compiete, the oil would pass all mandated tests until the inventory was sgain disturbed. The presence of the contaminants would not be detectable during normal operation, but shculd the EDGs (or the fire pump) be required to draw on the FOST inventories during sediment t
settlement, then the contaminants would havn been trans-ported throgh the system thus potentially impacting oper-ction of the engines.
The licensee drained each FOST, shipped the oil of fsite,
cleaned the tanks and refilled with new oil.
When FOST
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were declared operable.
The inspector verified that, dur-L ing the period of EDG inoperability, the licensee took actions to maintain Unit 2 Containment integrity and sus-pended nuclear fuel handling at Unit 2 in accordance witi#
L TS requirements. The inspc-etor also reviewed the Spc.ial S
Report s/ubmitted by the licensee concerning the inoperable diesel driven fire pump (see Section 7.2 of this report).
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The inspectors noted that the licensee's enhanced FOST sampling techniques identified the buildup of sediment not detectable by previour methods.
The improvement in sam-
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pling technique resulted from a broad review of sampling coomitments and requirements following an unrelated NRC identifiet Deviation. This is considered by the inspector to be en example of effective corrective action.
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4.2 Surveillance Observation j
The inspectors witnessed selected surveillance tests to determine whether properly approved procedures were in c e; TS frequency and
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action statement requirements were satisfied; necessary equipment
. tagging was performed; test instrumentation was in calibration and properly used; testing was performed by qualified personnel; and test results satisfied acceptance criteria or were properly dispositioned.
Portions of the following activities were reviewed.
STP D-73D-1, " Charging Pump Performance Test," for No. 13 Charg-
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ing pump on December 13, 1989.
I STP 0-8-0,
" Diesel Generator Test,"
for No.
EDG on
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December 15, 1989.
During STP 0-8-0, the inspectors noted a QC hold tag on the jacket
water cooling pump. This tag identified the outstanding Nonconform-ance Report (NCR) 8812 concerning the pump motor leads and lugs. The hold tag provides a space for comments or disposition to permit equipment operation but none was provided. The inspectors reviewed
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the NCR and found that the deficiency had been corrected but the tag had not been removed. The inspector was also informed that Calvert
Cliffs Instruction _116G, " Control of Deficiencies and Nonconformanco Reports", is being revised to clarify the applicability of QC hqld.
and deficiency tags. There is a Plant Operations and Safety Review
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Committee open item tracking the completion of this procedure revis-
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ion.
The inspector found this acceptable and had no further i
Concerns.
4.2.1 Emergency ?iesel Generator Trip During Surveillance i
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On December 15, during performance of STP 0-8-0 the No.12
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EDG tripped on crank case overpressure. Because the No. 11
EDG was still inoperable, the licensee took the TS ree,uired
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actions for when no EDGs are available; containment integ-rity was established, and fuel movement was discontinued.
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At the end of this inspection period, the licensee was con-tinuing investigation into the root cause of the high crank
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case pressure and subsequent engine trip. A special Engi-l neering Test Procedure was developed for this investiga-
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tion.
The inspectors noted that this investigation has been thorough and critical in attempting to determining the failure mechanism.
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Secutiry
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Durtoj routine inspection tours, the inspectors observed implementation of
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portions of the security plan.
Areas observed included access point search equipment operation, condition of physical barriers, site access control, security force staffing, and response to system alarms and
degraded conditions.
These areas of program implementation were deter-mined to be adequate.
5.1 Fitness For Duty Program Training
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I On December 18, 1989, the inspectors attended a combined Fitness For Duty (FFD) Program training session for worker awareness and escort
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qualifications.
The two hour session was presented in a combined lecture and video format.
The inspectors found that the session addressed the broad training objectives of 10 CFR Part 26, " Fitness For Duty Program," including licensee policy and procedures, indi-vidual worker responsibilities, and the hazards and recognition techniques associated with drug use.
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In addition to the lectures and video presentations, drug equipment
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displays were used.
Details of the licensee's JFD Program not spec-ifically covered in the presentation were addressed in the handout,
"Calvert Cliffs Nuclear Power Plant Fitness For Duty Handbook." The
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inspectors concluded that the training was satisfactory.
6.
Engineering and Technical Supnort
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6.1 Instrument Air System Testing - Generic Letter 88-14 NRC Generic Letter (GL) 88-14, Instrument Air Supply System Problems Affecting Safety Related Equipment, requires licensees to perform a design and operations verification of the instrument air (IA) system.
To satisfy this GL, Calvert Cliffs developed Engineering Test Proced-ure (ETP) 89-57 which demonstrates the ability of all valves and dampers with safety related accumulators to meet their design stroke requirements with a loss of normal IA.
-During this testing, the licensee discovered that many safety related air operated control valves and piston operated ventilation dampers which utilize safety related air accumulators would not perform as
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expected after a loss of normal, nonsafety related IA. Specifically, the control valves failed to meet their design stroke requirements.
Further licensee evaluation determined that many of the accumulators
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would eventually depressurize to point where they would be unable to perform as expected.
On November 6,1989, the licensee determined that this condition could prevent certain systems from removing residual heat and control the release of radioactive material after a loss of Coolant Accident (LOCA).
The event is described in Licensee Event Report (LER) 89-1 _
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The following components failed to meet the minimum number of valve or damper strokes upon loss of normal IA.
ECCS pump room ventilation exhaust dampers,
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sptnt fuel pool ventilation exhaust dampers,
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salt water system normal supply and discharge path valves,
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salt water system alternate discharge path valves,
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auxiliary feedwater system control valves, and
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the emergency. diesel generator service water inlet and outlet
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valves.
With the exception of the normal salt water discharge path, LER 89-18
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stated that all of the above failures could result in the potential loss of system safety functions. The licensee has established a pro-ject team to address the root cause of these failures. The team will
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also consider the outstanding Facility Change Requests on the IA
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system. The licensee will provide a supplement,,to LER 89-18 when the root cause investigation is' complete.
The testing associated with GL 88-14 and the subsequent LER were reviewed.
The inspectors identified that the licensee does not cur-
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rently perform periodic testing or maintenance of safety related air accumulator check valves to ensure continued operability. This item is Unresolved (50-317/89-27-01; 50-318/89-28-01).
6.2 Electrical Cable Separation Deficiencies t
During walkdowns of selected Unit I systems, the inspe: tors identi-
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fied several instances of inadequate separation between different electrical cable groups. Cable separation is required to assure that
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a single failure or event could not impact more than one train of
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safety equipment.
This requirement is specified in the General Design Criteria (10 CFR 50 Appendix A), the emergency core cooling systems (ECCS) criteria (10 CFR 50 Appendix K), and the protection systems criteria [10 CFR 50.55a(h)].
Section 8.5 of the Calvert Cliffs Updated Final Safety Analysis Report (UFSAR) describes the design measures which satisfy these requirementr..
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The Calvert Cliffs design document E 406, " Design and Construction Standards for Cable and Raceway," describes six sets of cable called t'
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" separation groups." Each separation group is required to be routed
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with a certain minimum physical distance from other groups. When the
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facility layout prohibits the attainment of this minimum distance, i
the design allows for the use of installed barriers to achieve s
physical separation.
In general, minimum distances of three feet i
horizontally and five feet vertically are required.
Other require-
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ments cover cable tray crossover and control panel layout.
The inspector identified the following apparent deficiencies and for-warded them to the licensee:
Cables in tray ZA1AL11 (separation group 1) did not have three
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feet of horizontal separation f rom tray BIAE40 (separation group 2).
Cables in tray ZAIAE35 (separation group 1) did not have three
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feet of horizontal separation from tray BIAE40 (separation group 2).
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Cables in tray ZA1AL10 (separation group 1) did not have ade-
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quate separation from trays BIAE41 and B1AL14 (separation group 2) due to a damaged barrier.
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Cables in tray ZB1AE76 (separation group 2) were also routed 'in
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tray ZFIAE77 (separation group 3).
Cables in tray ZA1AE70 (separation group 1) were also routed in
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tray ZGIAE72 (separation group 3).
This is a violation of 10 CFR 50, Appendix B, Criterion V which requires that activities affecting quality be completed in accordance with instructions, procedures and drawings (50-317/89-27-05).
Licen-see corrective actions were in progress at the close of the inspec-tion; they include additional system walkdowns to identify other cable separation deficiencies.
The cable separation rewirements of E 406 are con *ained in Section 0, " Separation Criteria", and are referenced elsewhere in this design document.
The E 406 construction details used during installation do not adequately reflect the separation criteria.
These details were used during original construction and are currently used for facility-i modifications. The first two deficiencks appear to be original con-struction while the last two are apparent modifications.
These deficiencies, together with the damaged and uncorrected barrier, are indicative of a programmatic weakness in the assurance of adequate separation of safety related cabl y
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l 6.3 System Engineer Training The. inspectors reviewed the licensee's program for training system engineers. The inspectors found the program to be thorough, compre-
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hensive, and highly structured. The engineers are issued qualifica-
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tion manuals which address component functions, flow paths, operating
parameters, design requirements, and applicable regulatory require-
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ments.
Each portion requires the signature by an evaluator certify-ing that the candidate successfully demonstrated the required know-ledge.
An additional evaluation area is sytem history including
preventive maintenance, LERs, modifications, and industry events. An extensive list of required practical factors was also listed includ-ing starting system components, system alignments, testing, and pre-ventive maintenance.
The inspector concluded that the program was a notable strength which, if personnel turnover was not excessive,
would result in highly skilled and knowledgeable system engineers.
7.
Safety Assessment and Quality Verification
7.1 Plant Operations and Safety Review Committee The inspectors attended several Plant Operations and Safety Review Committee (POSRC) meetings.
TS 6.5 requirements for required member
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attendance were verified.
The meeting agendas included procedural changes, proposed changes to the TS, Facility Change Requests, and minutes from previous meetings, items for which adequate review time was not available were postponed to allow committee members time for further review and comment. The inspectors observed that some indi-viduals presenting agenda items to POSRC were not well prepared and in some cases unable to answer committee questions concerning the material. The inspectors also noted that it is common for procedure
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change summary sheets to be distributed for committee review and approval based on oral deposition rather than consideration of the
procedure itself.
Overall, the level of review and member partici-
pation was adequate in fulfilling the POSRC responsibilities.
7.2 Review of Written Reports Periodic, Special, and Licensee Event Reports (LERs) were reviewed for clarity, validity, accuracy of the root cause and safety signif-icance description, and adequacy of corrective action. The inspector also determined whether further information was required.
The inspector verified that the reporting requirements of 10 CFR 50.73, j
Station Administrative and Operating Procedures, and TS 6.9 had been met. The following reports were reviewe,
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Special Report concerning Inoperable Fire Suppression Hose Stations, dated December 12, 1989.
Calvert Cliffs Unit 1 Report of Steam Generator Tube Plugging, dated December 13, 1989.
Special Report concerning an Inoperable Dier,el Driven Fire Pump, dated December 27, 1989.
LER 89-13. " Missing Steps in Surveillance Test Procedure."
LER 89-14
" Salt Water Header Not Seismically Qualified Due to Spool-Tack Welds."
LER 89-15
" Iodine Filter Dousing System Not Environmentally Qualified."
LER 89-16,
" RIDS Not Environmentally Qualified Due to Uns,ealed Housing."
LER 89-17, " Incorrect Surve:11ance Test Criteria."
LER 89-18. " Failure of Safety Related Air Accumulators to Perform As Required Results in a Condition That Could Have Prevented Certain Systems to Perform Their Intended Safety Functions."
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LER 89-19
"Unimplemented Requirement to Lock the HPSI Discharge Header Isolation Valves Shut Results in Operation Outside the Low Temperature Overpressure Protection Design Basis."
LER 89-20. "Nonseismic Solenoid Valves and Solenoid Valve Power Sup-plies on Class I System results in a Condition &mide the Plant Design Basis."
The inspectors noted the following items. These were discussed with the appropriate licensee representative as necessary.
The Special Report, dated December 12, 1989, concerning the diesel fire pump states that the pump was declared inoperable due to the FOST contamination, but also states that sufficient fuel was avail-able to meet pump TS performance requirements.
These different TS statements are both intended to require sufficient fuel for fire pump operation, but do not appear to be consistent.
The inspector iden-f tified the potential inconsistency; the licensee has committed to review the matter for a possible TS amendment to clarify the require-ments. The events associated with the diesel fire pump inoperability are discussed in Section 4.1.1 of this report.
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The inspector identified two apparent contradictions between LER 89-18 and the associated TS Bases, TS 3/4.7.7 concerning the Emerg-i ency Core Cooling System (ECCS) pump room. ventilation system's pur-pose and credit in the UFSAR Chapter 14 Accident Analysis.
The LER states that 'this ventilation system was installed to improve habita-
bility of the pump rooms following a loss of Coolant Accident (LOCA)
and that the system is not credited in the accident analysis. How-ever, the bases for TS 3/4.7.7 state that the ECCS pump room ventila-tion system ensures that radioactive materials leaking from ECCS equipment following a LOCA are filtered prior to reaching the environment and that the operation of this system is credited in the accident analysis.
The inspectors discussed this item with the licensee. The licensee has been aware of this conflict since March,
1984. LER 50-318/84-01, Isolation of Instrument Air to Fan Discharge Damper, stated that the basis for TS 3/4.7.7 is incorrect in this
case. This is another example of the licensee's inability to manage
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and resolve a commitment made to the NRC (LER 318/84-01) in a timely manner (see Section 7.4 of this report).
Additionally, the licensee is aware of many inconsistencies among the TS, the FSAR, and operating procedures. These inconsistencies were discussed in NRC Special Inspection Report 50-31]/89-31; 50-318/89-32 and at the associated Enforcement Conference held after the inspec-
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tion period on January 18, 1990.
- The deficiency described in LER 89-16 was identified by maintenance
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personnel during technical training.
The training involved the equipment qualification requirements of safety related resistance temperature detectors (RTDs). Maintenance technicians noted that the RTD configuration described during the training differed from the actual plant configuration.
Subsequent inspection verified that the Unit 1 reactor coolant system hot and cold leg RTDs were installed incorrectly.
The identification of this deficiency is an illustra-tion of competency and alertness of maintenance personnel.
No significant deficiencies were identified in the reports reviewed.
The inspectors noted that four of the LERs (89-15,18,19, and 20)
committed to future submittals of supplements following substantial additional analysis and review.
7.3 Equipment Preservation Durin>;.?ntages - Steam Generators Both units have been shutdown for extended periods - Unit 1 since May 1989, and Unit 2 since March 1989.
During equipment outages. it is necessary to place components and systems in lay-up to preserve equipment integrity and ultimately, operability. During this inspec-tion period, the inspectors reviewed the licensee's lay up practices as applied to both units' steam generators (SGs).
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Currently, Calvert Cliffs does not have a formal Equipment Preserva-tion Program. A program is being developed by the Chemistry Depart-ment and is scheduled for implementation early in 1990.
Histori-cally, plant management has determined when it was necessary to place the SGs in lay-up.
Chemistry Procedure (CP) 217
" Specifications and Surveillance -
Steam Generators," contains specifications for the SG lay-up condi-tion. Table 3 of CP-217 applies to cold shutdown and refueling con-ditions and specifies that SG pH should be maintained between 9.8 and 10.5, and hydrazine concentration should be maintained between 70 and 200 ppm.
CP-217 states that if a parameter degrades beyond the specified limits, the plant must be placed in a mode of operation which minimizes the potential for corrosion to the SGs; the para-meters should then be returned to within specifications.
If these parameters remain outside the specifications, Action Level 1 is entered.
CP-217 defines Action Level 1 as "out-of-normal water chemistry which is inconsistent with maintaining long term SG integrity."
Additionally, 10 CFR 50, Appendix B, Criterion XIII, " Handling, Stor-age, and Shipping," states that measures shall b,p established to con-trol the storage and preservation of equipment in accordance with
work and inspection instructions to prevent damage or deterioration.
The inspector reviewed the pH and hydrazine histories for all four SGs for the period May 1,1989 to December 15, 1989.
A summary of this data is provided in Attachment 1 to this report. The pH levels and hydrazine concentrations for SG Nos. 11, 12, and 22 were con-
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sistently below the specifications of CP-217.
This is a Violation of the above procedure and 10 CFR 50, Appendix B, Criterion XIII requirements-(50-317/89-27-02 and 50-318/89-28-02).
The circumstances surrounding this condition and its protracted
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nature are of particular concern. Ouring review of this issue, the inspector was made aware of several complications which prohibited and delayed adequate lay-up of the SGs.. These difficulties involved
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auxiliary feedwater and auxiliary boiler availability, demineralized water transfer ability, insufficient SG water recirculation equip-ment, SG manway bolt suitability, and extended maintenance work.
While personnel from several departments were aware of the difficul-ties in es'.ab11shing adequate SG chemistry, licensee management apparently failed to give appropriate attention to correcting the
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degraded SG water chemistry.
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7.4 Review of Past Corrective Actions The inspector conducted an evaluation of the licensee's processes for tracking, implementing, and evaluating the effectiveness of correc-
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tive actions taken for identified deficiencies.
The inspector reviewed licensee actions associated with deficiencies or commitments documented in the following and NRC Inspection Reports (irs):
IR 50-317/87-22; 50-318/87-24, dated September 21, 1987 1)
Revise Updated Final Safety Analysis Report (UFSAR) to reflect proper containment cooling system operation.
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IR 50-317/88-05; 50-318/88-06, dated May 11, 1988 2)
Low Temperature Overpressure Protection (LTOP) concerns, 3)
Review revision to emergency procedure guidelines to ensure significant changes are incorporated in emergency operating procedures.
The inspector determined that no formal, integrated tracking system was in place for commitments and corrective actions. ~ Actions asso-e ciated with LERs were reviewed by the POSRC and a POSRC Open Items i
List (OIL) was maintained. The POSRC OIL was found to be governed by.
procedure but items other than LERs were generally not addressed.
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Informal tracking systems were found to include some but not all of
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the items identified above.
7.4.1 UFSAR Revision for Containment Cooling System Operation The inspector reviewed the status of the licensee's commit-ment to revise the UFSAR to indicate the need for operation of four containment coolers during the summer months and the use of an eight inch valve as necessary. The inspector
found that the UFSAR had been revised (Revision 8)~ to indi-cate the use the coolers but that the valve use had not been included. The inspector requested to review the docu-mentation associated with this action and found that none existed and that this UFSAR change was apparently made without procedural controls.
Furthermore, Calvert Cliffs
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Instruction (CCI) 126H, " Administrative Control of Facility Change Request," states that revisions to the UFSAR are controlled and processed by CCI-143F,
"Calvert Cliffs Administrative Control of License Amendments".
However, CCI-143F does not address UFSAR revisions.
The apparent
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lack of administrative controls for UFSAR changes is an Unresolved Item (50-317/89-27-03; 50-318/89-28-03).
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7.4.2 Low Temperature Overpressure Protection (LTOP) Concerns The inspector reviewed licensee actions taken to resolve concerns pertaining to Pressure - Temperature (P-T) limits i
and LTOP systems.
The inspector identified several
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instances where licensee commitments were apparently not
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met. These issues are addressed in NRC Special Inspection
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Report 50-317/89-31; 50-318/89-32.
7.4.3 Emergency Procedures Guidelines Review
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Guidance for the development for emergency ocedures is
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provided in CEN-152, " Combustion Engineering Emergency Pro-F cedure Guidelines".
During the NRC staff review process, several revisions to CEN-152 were submitted to resolve identified deficiencies.
Consequently, the staff evalua-
- tion of CEN-152 has been an ongoing process. The original NRC safety evaluation (SE) and SE revisions and supplements i
were issued between May, 1983 and November, 1986.
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Previously, the inspectors found that the licensee had
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deferred revising plant E0Ps and AOPs to incorporate the L
procedural guidelines of CEN-152, Revision 3" until CEN-152 was approved in its entirety.
The licensee felt that repeated revisions to E0Ps and AOPs could pose a detriment.
to safety because licensed operators might not be able to
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maintain an appropriate level of familiarity with these procedures.
However, in response to inspector concerns
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regarding potential E0P and AOP deviations from CEN-152, the licensee committed to reviewing the NRC approved revis-ions and supplements to CEN-152 to determine if any of the changes to the E0P guidelines were significant.
Any
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changes found to be significant would then be incorporated into the E0Ps and AOPs.
Minor changes would be deferred until.the NRC completed its review of CEN-152.
During this inspection period, the corrective actions taken to ensure procedural adequacy with significant change. to CEN-152 were reviewed. The inspector found that the licen-see apparently had not reviewed the NRC-approved revisions
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to CEN-152 to discern and implement the significant changes from the original E0P guidelines.
In addition, this com-
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mitment was apparently not included on any tracking system.
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commitments (see Section 7.4.2 of this report). Failure to address deficient void control requirements in emergency l
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procedures based on guidance in CEN-152 was the subject of a Violation in NRC Inspection Report 50-317/89-23; 50-138/
i 89-23. The broader issue of the apparent failure to review CEN-152 for applicability to licensee procedures will be tracked separately as an Unresolved Item (50-317/89-27-04;
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50-318/89-28-04).
7.5 Summary
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Sections 7.2, 7.3, and 7.4 of the report discuss instances where
the inspectors identified inadequate commitement followup.
Incon-sistencies among the TS, the FSAR, and operating procedures have been known to the licensee but not resolved potentially indicating accept-ance by licensee management of these conditions.
Failure to resolve
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problems spanning several different organization groups led to a pro-longed period of degraded SG chemistry, niso, a weakness was identi-fied in the licensee's ability to track, manage, and resolve com-mitments made to the NRC.
These examples are indicative of a programmatic weakn'ess in the licensee's ability to track, manage, and resolve commitments. This concern was also addressed in NRC Special Inspection Report 50-317/89-31; 50-318/89-32 and r
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at the subsequent Enforcement Conference held in the Region I Office following this inspection period, January 18, 1990.
Subsequently, the licensee committed in a January 25, 1990 letter confirmed by CAL 89-00, Supplement 1, dated February 1,1990 to review tracking and resolving I
commitments prior to startup of either unit.
8.
Follow-up of previous Inspection Findings Licensee actions taken in response to open items and findings from pre-vious inspections were reviewed.
The inspectors determined if corrective actions were appropriate and thorough and previous concerns were resolved.
Items were closed where the inspector determined that corrective actions
would prevent recurrence.
Those items for which additional licensee
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action is warranted remain open.
The following item was reviewed.
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Quarterly Diesel Fuel Oil Sampling (Closed) Deviation (50-317/89-17-01; 50-318/89-18-01) This item involved the identification by and NRC inspector that certain quarterly diesel fuel oil samples committed to in the UFSAR were not being performed.
In addi-tion, some samples which were being performed were not being analyzed for all the parameters specified in the UFSAR.
During this period, the
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inspector reviewed the licensee's chemistry procedure involving oil sam-pling, CP-226, " Oil Specifications", and noted that the required samples i
and analyses had been incorporated.
The inspector reviewed the sample l
results and confirmed that the required parameters had been analyzed.
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Exit Meetino During this inspection, periodic. meetings were held with station manage-c ment to discuss inspection observations and findings. At the close of the
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inspection period, an exit meeting was held to sumrearize the conclusions
'of the inspection. No written material was given to the licensee and no
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proprietary information related to this inspection was identified.
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i ATTACHMENT 1 Steam Generator Chemistry May 1, 1989 to December 15, 1989
SG11 SG12 SG21 SG22 Date pH N2H4 pH N2H4 pH N2H4 pH N2H4
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5/1
- 8.6
- 8.6
- 9.3
- 75
- 9.2
- 16
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5/8
- 9.0
- 16
- 8.8
- 10
- 8.9
- 41
- 9.2
- 15 5/15
'9.5
'9.4 190
- 8.6
- 31
- 9.0
- 13 5/22
- 9.6 141
- 9.2 162
'8.7
- 27 9.5 151 5/29
- 9.7 124
'9.3 149
'9.5
- 9.6
6/5 9.9 165
'9.4 135 9.8 176 9.8 177 6/12 9.8 182
- 9.4 155 9.8 200
- 9.7 185 6/19 9.9 155
- 9.4 140 9.8 167
'9.5 195 6/26 9.9 165
'9.4 131 9.8 194
'9.2 194 7/3 9.8-179
'9.4 128
- 9.7 198
- 9.0 125 7/10 9.9 149
- 9.4 119 9.8 195
- 8.8 129 7/17 9.8 167 9.8 200 8.8 129
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7/20
- 9.5 123
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7/24 9.8 164
'9.4 131 9.8
- 202
- 8.6 111 7/31 9.9 150
- 9.4-104 9.8 183
- 8.6
8/7 9.8 135
'9.4
9.8 180
- 8.5"
8/14 9.8 141
'9.5
9.8 189
- 8.6
8/21 9.8 134
- 9.4
9.8 176
- 8.5
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8/28
- 9.7 105
- 9.4
9.8 179
- 8.4
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9/5
- 9.7
'9.2 119 9.8 179
- 8.3 104 9/11
- 9.4
- 9.3
- 65 9.8 175
- 8.2
- 59 9/18
- 9.4
- 9.3
9.8 177
- 9.0 183 9/25
- 9.5
- 9.3
- 58 9.8 178
- 9.4
- 422 10/2
- 9.4
"9.3
- 65 9.9
- 208
- 9.0
- 446
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10/9
- 9.4 123
- 9.4
9.8 163
- 9.3 191 10/16
- 9.3
- 9.3
9.8 188
- 8.9
10/23
- 8.6
- 46
- 9.4
9.9 191
- 8.9
10/30
- 8.7
- 9.4
9.8 176
- 8.9
11/6
- 8.6
- 61
- 9.2
- 9.7 146
- 8.9
11/13
- 8.9
- 51
'8.9
- 48 9.9 126
- 8.9
11/20
- 8.9
- 48
'8.8
- 37 9.9 179
- 9.2 161 11/27
- 8.8
- 47
- 8.6
- 33
- 9.6 126
- 9.0
12/4
- 8.7
- 51
- 8.6
- 64 9.9 192
- 9.0
- 70 12/11 8.7
- 38
'8.6
- 24 9.9 174
- 9.0
- 61 12/15
- 9.1 110
- 9.0 119 9.8 180
- 9.4
- 204
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Note:
Chemistry Procedure 217 specifies that during cold shutdown and refueling conditions SG pH should be maintained as follows:
pH: between 9.8 and 10.5 N2H4: between 70 ppm and 200 ppm
- Indicates parameters which are out of specification.