IR 05000317/1989023
| ML20005G966 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 01/10/1990 |
| From: | Limroth D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20005G959 | List: |
| References | |
| 50-317-89-23, 50-318-89-23, NUDOCS 9001230325 | |
| Download: ML20005G966 (34) | |
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U. S. NUCLEAR REGULATORY COMMISSION Region I 50-317 DPR-53 Docket Nos.:
50-318 License Nos.:
50-317/89-23 Report Nos.:
50-328/89-23
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. Licensee:
Baltimore Gas and Electric Company Post Office Box 1475
Baltimore, Maryland 21203 I
Facility:
Calvert Cliffs Nuclear Power Plant, Units 1 and 2 i
l-Inspection at: Lusby, Maryland
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Inspection Conducted:
August 29 - October 2, 1989
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Inspectors:
D. Limroth, Acting Senior Resident Inspector V. Pritchttt, Resident Inspector s
J. G la, Acting Re ident Inspector Approved By:
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DaHd F. LimroOf/ Acting Chief
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Reactor Projects Section No. lA.
Summary: August 29 - October 2, 1989 Inspection Report Nos. 50-317/89-23 and 50-318/89-23
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D Areas Inspected:
Facility activities, licensee action on previous inspection findings, operational safety, physcial security, plant operations, maintenance,
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surveillance, engineering support, Licensee Event Reports, licensee response to
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' NRC initiatives, review of periodic and special reports, events requiring notification to the NRC, and followup of restart issues.
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t Results: One violation of regulations was cited related to failure to assure that conditions adverse to facility were promptly identified and corrected.
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9001230325 900110 gDR ADOCK0500g7
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TABLE OF CONTENTS t
Page 1.
Persons Contacted.........................................
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2.
Summary of Facility Activities............................
3.
Status of Previous Inspection Firdings (IP 71707, 92702, 92701)..................................................
4.
Operational Safety (IP 71707,71710)......................
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4.1 Daily Inspection....................................
4.2 System Alignment Inspection..........................
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4.3 Biweekly and Other Inspections.......................
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5.
S e c u ri ty ( I P 71707 )......................................
5.1 Observation of Physical Security.....................
'6.
Plant Operations (IP 71707,93702,40500).................
- 6.1 Possible Unevaluated Problem With Unit 1 and 2 Excore Nuclear Instrument Control Channel Y...............
6.2 Typographical Error in Technical Specification Table 2.2-1 for Thermal Margin / Low Pressure Trip Setpoint...........................................
6.3 Two Non-Radioactive Systems Operated While Contaminated Without a Prior 10 CFR 50.59 Safety Evaluation.........................................
6.4 RTDs Not Environmentally Qualified Due to Unsealed Housing............................................
6.5 Corrective Actions - Generic Letter No.
81-21........
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Maintenance / Surveillance (IP 71707,61726,62703,70313)..
7.1 Maintenance..........................................
7.2 Surve111ance.........................................
8.- Engineering Support (IP 71707,37828).....................
8.1 Pressurizer Cracking.................................
9.
Licensee Event Reporting (LER) (IP 93702,90712)..........
10.
Review of Licensee Response to NRC Initiatives L
(IP 71707)..............................................
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Table of Contents (Continued)
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-11.
Review of Periodic and Special Reports (IP 71707).........
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Events Requiring Telephone Notification to the NRC (IP.93702)..............................................
13.
Followup of Restart Issues (IP 92702).....................
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14. Unresolved Items (IP.93702)...............................
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15. Management' Meetings (IP 30703)...........................
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- The NRC Inspection Manual inspection procedure (IP) or the Region I temporary
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instruction (RTI) that was used as inspection guidance is listed for each applicable report section.
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DETAILS
1.
Persons Contacted
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Within this report period, interviews and discussions were conducted with various licensee personnel, including reactor operators, maintenance and t
surveillance technicians and the licensee's management staff. Night shift g
inspections were conducted on September 7, 8, 11, 12, 20 and 21,1989.
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2.
Summary of Facility Activities Unit 1
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The unit remained shut down in accordance with Confirmatory Action Letter
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(CAL) 89-08 pending the results of the Unit 2 pressurizer examinations and correction of numerous management issues associated with the CAL.
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Unit 2
.The unit remained defueled for the entire period for a combination of the
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8th cycle scheduled refueling outage and the ongoing investigation and repairs of pressurizer heater sleeve leakage.
The unit is expected to remain shut down through March 1990.
General i
The licensee met with NRC management on August 29, 1989, at USNRC Region I, Kin the licensee'g of Prussia, in a public meeting to present the results of s self-assessment.
From September 13 through 15, 1989, Region I specialists conducted a rou-tine announced emergency preparedness inspection which included observa-tion of the licensee's full participation annual emergency preparedness exercise conducted September 14, 1989.
A Region I specialist conducted an inspection during the week of
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September 25, 1989, related to the licensee's Radiological Environmental Monitoring Pr: gram.
3.
Licensee Action on Previous Inspection Findings (Closed) Violation 50-317/88-17-02 Failure to perform a calorimetric calculation per Operating Instruction (01-30) before making adjustments to nuclear instrumentation and Delta T l.
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power (50-317/88-17-02).
Violation of Technical Specification 2.2.1 regarding Limiting Safety System Settings, Reactor Protective Instrumen-tation Trip Setpoint Limits (50-318/88-17-03).
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The licensee has made the following corrective actions regarding these violations:
the Escalation to Power Test Procedure (PSTP-3) has been revised to include steps to check six indications of core power at 5%
power increments from turbine parallel, approximately 15% power, to 85%
power.
Procedure PSTP-3 requires that the six indications be discussed with the Control Room Supervisor (CRS) and agreement reached that core spower is accurately known, prior to another 5% increase in power. Addi-
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tional indications of power, such as megawatts-electric and feedwater flow, are also monitored to check for consistency with the power indica-tors.
A further check of core power is now required to be made at 30%
indicated power. The indicated power is to be compared with the computer calculated calorimetric power.
If the computer point is not available,
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the calorimetric calculation is performed using 01-30.
Power escalation may not proceed until the power level is verified at 30%
power.
Also, the Escalation to Power Test Procedure now requires that, prior to escalation to power, a pre-shift briefing be given to the oper-ators by Nuclear Engineering Unit engineers.
The Shift Supervisor, Senior Reactor Operator (SRO), and Reactor Operator (RO) licensed individuals that were nvolved in this event have been counseled in requirements regarding procedure adherence and control. These individuals have also reviewed the appropriate controls and procedures used to ensure these requirements.
Instruction is now given during operator requalification training on the accuracy and reliability of power indications at various power levels and the use of special test exceptions.
An evaluation has been conducted to determine how accurate the Delta T power calibration potentiometer setpoints are below 90% power. Notes were then added to the Units 1 and 2 setpoint sheets which indicate what the setpoint tolerances are for various power levels. This was done to pre-vent the recurrence of a significant potentiometer setpoint change by
providing additional guidance to the operators.
Corrective steps taken to avoid further violations include the instruction given to operators at requalification training discussed above, the evalu-ation and inclusion of notes on the Units 1 and 2 setpoint sheets also discussed above, and the counseling of all personnel regarding procedure adherence and control.
The inspector's review of the licensee's corrective measures taken, including those intended to preclude a recurrence of these violations, determined that the licensee appears to have adequately addressed the violations including root causes and corrective and preventive measures.
This item is closed.
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j (0 pen) Violation 50-318/88-17-01 Failure to meet Technical Specification 3.8.1.1 with respect to the mini-mum number of AC power sources demonstrated to be operable. A synopsis of the issue'is as follows: while the Unit 2 reactor was in Mode 1 and oper-
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ating at 100% power, Emergency Diesel Generator (EDG) No. 21, one of the two required - diesel generators, was inoperable.
During that time, L
Technical Specification Surveillance Requirements 4.8.1.1.1.a and L
4.8.1.1.1.a.4 were not performed. The EDG was inoperable during that time
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period in that its voltage regulatoa was in the manual mode. With the
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voltage regulator in this mode, the EDG would not successfully power essential loads as required during a loss of coolant accident concurrent
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i with a loss of offsite power.
l-Corrective actions taken by the licensee are as follows:
Operating Instruction (01)-27 has been modified to specifically state that the EDG is inoperable whenever the voltage regulator is not in the AUTO mode, and
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to eliminate the test of the voltage regulator in MAN mode. The Shift Supervisor (SS), SR0 and R0 licensed individuals that were involved in this-event have been counseled regarding requirements for procedure adherence and control.
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Actions 'taken to avoid further violations include the following: Operator training for SRO and R0 licensed individuals has been changed to incor-porate training on the function and operation of the EDG voltage regulator in both MAN and AUTO modes. The SS is now required to review the control room operator log during shift turnover.
Also, the switch position for each EDG voltage regulator will be verified by' control room operators to be in the AUTO mode, unless otherwise authorized, at least once during each shift.
Furthermore, the licensee has committed to install an alarm function on the voltage regulator mode selector switches on Control room panels IC18, IC19, and IC20.
The alarm will occur in the control room whenever the mode selector switch is not in automatic.
The operator switch position verification at each shift, mentioned above, will be deleted once the alarm function is operable.
The inspectors'
review and assessment of the licensee's corrective measur9s and those taken to preclude further violations has determined that the licensee has adequately addressed this issue.
This item will remain open, however, pending the hardware installation (voltage regulator mode alarm function) in the control room.
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Operational Safety 4.1 Daily Inspection During routine. facility tours, the following were checked: manning, access control, adherence to procedures and LCO's, instrumentation,
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recorder traces, protective systems, control rod positions, contain-
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ment temperature and pressure, control room annunciators, radiation monitors, effluent monitoring, emergency power source operability, control room logs, shift supervisor logs, and operating orders,
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No unacceptable conditions were noted.
4.2 System Alignment Inspection i
Operating _ confirmation was made of selected piping system trains.
Accessible valve positions and status were examined. Visual inspec-tion of major components was performed.
Operability of instruments essential to system performance was assessed. The following systems were checked during plant tours and control room panel status observations.
Low Pressure Safety Injection (Shutdown Cooling)
High Pressure Safety Injection
Breaker Lineup
Boration Flowpath Lineup
No unacceptable conditions were noted.
4.3 Biweekly and Other Inspections During plant tours, the inspector observed shift turnovers; boric acid tank samples and tank levels were compared to the Technical Specifications; the use of radiation work permits and Health Physics procedures was reviewed.
Plant housekeeping and cleanliness were evaluated.
No unacceptable conditions were noted.
5.
Security 5.1 Observation of physical Security Checks were made to determine whether security conditions met regu-latory requirements, the physical security plan, and approved proced-l ures.
Those checks included security staffing, protected and vital l
area barriers, vehicle searches and personnel identification, access I
control, badging, and compensatory measures when required.
No unacceptable conditions were note "o
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6.
Plant Operations 6.1 Possible Unevaluated Problem With Unit I and 2 Excore Nuclear Instrument Control Channel Y During the April 22, 1989 Unit 1 startup and ensuing power ascension, the licensee collected data for calculating an appropriate shape annealing factor for the power ratio calculator. Upon evaluating the collected data, the licensee noted that the Channel Y and lower seg-ments had values that were the reverse of Channel X value. The power ratio calculator (PRC) is used to monitor linear heat rate (LHR) and Departure from Nucleate Boiling during a loss' of the plant computer when the Better Axial Selection Shape System (BASSS) is inoperable.
The PRC is classified as non-safety related. The function of the PRC and the BASSS calculation of Axial Shape Index (ASI), is required by the Combustion ' Engineering Statistical Combination of Uncertainties
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(SCU), document. number CEN-124, Appendix A.
Operation of either device, PRC or BASSS, satisfies the requirement.
Operation of the BASSS has been highly reliable, and historically, the use of the PRC has been minimal. ' Resolution of this issue, therefore,. is not con-sidered a startup issue. However, if neither device is available for ASI calculation, based upon assumptions of the SCU, the unit could
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not be started up or would have to be shut down if operating.
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The licensee is currently reviewing STP M-213-1, " Calibration of Power Range Nuclear Instrumentation by Comparison with Incore Nuclear Instrumentation" to determine if any deficiencies or differences exist in the calibration of excore power range channels X and Y.
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Also, the licensee has performed a review of the applicable design drawings and has not found any reversal of the detector cables within the design. To verify the proper connection of the detector cables to the power ratio calculator, Calvert Cliffs Maintenance Order num-bers 209-244-651A and 209-234-166A, for Units 1 and 2, respectively, have been issued to troubleshoot the detector cable connections. The findings of this verification will determine if this is an installa-tion problem or if further study of the operation of the PRC is required. If the problem is in the installation or calibration, cor-rective action will be initiated and a root cause evaluation will be performed. The completion of the verification of detector cable con-nections and subsequent evaluations may include collecting further data during Unit I startup.
6.2 _ Typographical Error in Technical Specification Table 2.2-1 for Thermal Margin / Low Pressure Trip Setpoint On September 5,1989, the licensee discovered a probable typograph-ical error in Technical Specification Table 2.2-1 for Thermal Margin /
Low Pressure trip setpoint. The Thermal Margin / Low Pressure trip is provided to prevent operation when the Departure from Nucleate Boil-ing Ratio (DNBR) is less than 1.2 e -,
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The typographical error, which appears ir. Technical Specification Table 2.2-1 and FSAR Table 7.1, lists the allowable value of Thermal
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Margin / Low Pressure trip setpoint to be not less than the larger of a calculated value and 1875 psig. The licensee has reviewed this value and determined that the 1875 psig is a typographical error and should be 1875 psia. This determination is based on the following:
The safety analysis uses a value of 1728 psia for the TM/LT
trip.
The plant Technical Specification psig units are incon-sistent with this.
The Standard Technical Specification Ba3es for the TM/LP trip
uses a value of 1875 psia for TM/Lp trip.
The Units' psig are inconsistent with the process loop units and
the units of the setpoint values of other similar process loops, i.e., SG Pressure Low 685 psia; Pressurizer Pressure High (2400 psia).
A TM/LP p-min setpoint is well above the safety analysis value
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of 1728 psia.
It was also determined by the licensee that the typographical error
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occurred when the 1875 psig value was added to Technical Specifica-tion Table 2.2-1 per Amendment No. 71 to Unit 1 Technical Specifica-tions and Amendment No. 61 to Unit 2 Technical Specifications.
The safety evaluation for each of these changes indicated that the licen-see was going to replace certain Fisher pressure transmitters located
inside containment with EQ transmitters manufactured by Barton.
The above noted Technical Specifiestion change was made to maintain the validity of the safety analysis which assumed installation of a lower uncertainty value of the Fisher transmitters then in place. The low pressure for the TM/LP trip setpoint was changed from 1750 psia to 1875 psig to reflect the increased uncertainty associated with the Barton Pressure transmitters.
The transmitters were changed to Barton in 1982/83 and were more recently changed to Rosemounts. The Bartons' had a calculated uncertainty of about 140 psi while the new Rosemounts have an uncertainty of about 60 psi. Thus, installation of the Rosemounts have added about 80 psi (140-60) of conservatism to the 1875 psig setpoint value in Technical Specifications.
The licensee has concluded that the 1875 psig value in Unit 1 and Unit 2 Technical Specification Table 2.2-1 and FSAR Table 7.1 is in all probability a typographical error and that the actual setpoint called for in the setpoint file allows enough conservatism to assure that the design basis described in the FSAR is not exceeded.
The inspector concurred with this assessment. The licensee is planning to correct this typographical error in their next fuel load Technical Specification change submittal for each uni y
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l 6.3 Two bn-Radioactive Systems Operated While Contaminated Without a
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Prior 10 CFR 50.59 Safety Evaluation
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On September 27, 1989, the licensee reported that two non-radioactive j
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systems, the auxiliary steam boiler and nitrogen systems, were dis-j
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covered to have been operated while contaminated without a prior L,
10 CFR 50.59 safety evaluation.
Routine surveys for contamination L
disclosed minor amounts of contamination in the plant's nitrogen sys-
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tem on August 25, 1987, and auxiliary boiler systems ABW 11 on
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t March 29, 1989 and ABW 12 on May 10, 1989.
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L Since this discovery, the licensee has written a draft assessment l
h which indicates that these systems have been operated with low levels of. radioactive contamination but without safety significance.
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Assessments of onsite and offsite consequences of operation in this condition were shown to be either inconsequential or quantified at levels below the MPC of 10 CFR 20, Appendix B, Table II for the isotopes. identified, Cs-137 and Xe-133.
The licensee has been performing routine surveys of non-radioactive systems since 1980 as a result of NRC IE Bulletin No. 80-10
" Contamination on Non-radioactive System and Resulting Potential for Unmonitored, Uncontrolled Release to Environment."
This Bulletin requires that a 10 CFR 50.59 safety evaluation be performed for con-tinued operation of a known non-radioactive system which becomes contaminated. Since contamination was detected in the nitrogen sys-tem in August 1987, new liquid nitrogen bottles have replaced the old bottles.
The new bottles are maintained at a pressure which is greater than that of the source of contamination to the system, the volume control tank-(VCT) of the the chemical and volume control sys-tem.
Also, the auxiliary steam boilers are presently drained down for maintenance and being decontaminated.
The licensee is in the process of formalizing its safety assessment of this event into a formal 10 CFR 50.59 safety evaluation.
This issue will remain open
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as an unresolved item No. 50-317/89-23-01 and 50-318/89-23-01 pending review of the licensee's 10 CFR 50.59 safety evaluation.
Also, the issue of continuing to operate contaminated non-radioactive systems without a 10 CFR 50.59 safety review per IE Bulletin No. 80-10 will be addressed as part of this unresolved item.
6.4 RTDs Not Environmentally Qualified Due to Unsealed Housing On September 8, 1989, with Unit 1 in cold shutdown and Unit 2 defueled, it was determined by the licensee that the as-found condi-tion of the resistance temperature detectors (RTDs) installed on the the RCS hot and cold legs of Units 1 and 2, did not match the environmentally tested configuration. This condition invalidated the environmental qualification of the RTDs. The RTDs provide input to the post-accident monitoring instrumentation (Subcooled Margin Monitor) and are governed by Technical Specification 3.3.3.6.
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Technical Specification requires that a certain minimum number of post-accident monitoring instrumentation channels be operable in modes 1, 2 and 3.
Because the condition existed during Mode 1 oper-ation, the assumed inability of these instruments to function under post-accident conditions, constitutes a
Technical Specification violation.
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Discovery of this condition by the licensee was as follows:
during the present Unit 2 shutdown, RTDs were removed from the primary cool-ant system for routine maintenance.
Technical training was provided to the maintenance personnel to familiarize them with the environ-mental qualification requirements of the RTDs.
Personnel attending the training noted several discrepancies between the guidance offered
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Engineering personnel were notified and walked down the installed RTDs on Unit 1 approximately three weeks later during the next Unit I shutdown.
The walkdown disclosed the fact that the RTDs were not installed as environmentally tested.
The nipple-to-base interface in the upper housing was not sealed as the environmental qualification tests required.
The presumption which violates Technical Specification i
3.3.3.6 is that moisture intrusion could have occurred as a result
of the post-accident environment, thereby affecting the RTD inter-nals.
Design engineering personnel evaluated either unit.
Thi s event has been reported to the NRC in accordance with the require-ments of 10 CFR 50.73, " Licensee Event Report System." A supple-mental LER will be submitted to discuss the root cause of the event
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and any additional corrective actions.
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The Subcooled Margin Monitor would have been rendered inoperable by
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the loss of the RTDs.
This situation constitutes a violation of
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Technical Specification 3.3.3.6.
However, due to the fact that it
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was self identified, and given the prudent observation of the licen-see's maintenance department personnel, this will not be cited as a violation.
Based on potential safety significance, this will be followed as an unresolved item pending the licensee's determination l
of the root cause of the event, any further corrective actions, and review by the NRC (50-317/89-23-02 and 50-318/89-23-02).
6.5 Corrective Actions - Generic Letter No. 81-21 Natural Circulation Cooldown The NRC issued Generic Letter 81-21, " Natural Circulation Cooldown,"
on May 5,1981, to require pressurized water reactor (PWR) licensees
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to implement procedures and training programs to ensure the capabil-
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ity to control upper head voids during natural circulation cooldown.
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The NRC staff had subsequently determined that controlled voiding
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in the reactor vessel upper head is acceptable provided: (1) that it can be done using all safety grade equipment with procedures developed in accordance with NRC-approved generic emergency procedure guidelines and with licensed operators trained in the use of these
procedures; and (2) that void formation must not be allowed to threaten natural circulation cooldown.
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t Guidance for the development of emergency procedures at Calvert Cliffs is provided in CEN-152, " Combustion Engineering Emergency
- Procedure Guidelines," in Supplement 3 to the Safety Evaluation for CEN-152, dated November 5,1986, the NRC staff found that Supplement 2 of Revision 3 to CEN-152, is acceptable for implementation and will provide improved guidance for emergency operating procedure develop-ment.
Included therein was clarifying guidance for voiding elimina-tion, directing PWR licensees to eliminate voiding any time voids may
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jeopardize or threaten reactor coolant system (RCS) heat removal via natural circulation.
During the period from February 13 to March 31, 1988, the NRC Senior Resident Inspector at Calvert Cliffs performed Temporary Instruction 2515/86, " Inspection of Licensee's Actions Taken to Implement Generic Letter No. 81-21, Natural Circulation Cooldown." As documented in
Inspection Report Nos.
50-317/88-05 and 50-318/88-06, dated May 9, 1988, the inspector found.that: (1) the licensee's procedures did not conform to the approved guidance on void control and (2) the licensee had deferred incorporation of NRC approved guidelines included in CEN-152 until CEN-152 was approved in its entirety.
- At that time, the licensee stated that they would modify their pro-cedures to reflect the approved CEN-152, Revision 3 guidance regard-
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ing actions required to be taken when void formation jeopardizes or threatens RCS heat removal via natural circulation cooldown.
In addition, the licensee committed to reviewing all NRC approved
CEN-152 guidance for significant issues and to determine how best to incorporate those changes.
During a July 1989 review of the licensee's completion of actions associated with this generic activity, the inspector found that the licensee's emergency operating procedures (EOPs) and abnormal opera-ting procedure (A0P) 3F, " Natural Circulation Cooldown," had not been revised to incorporate the voiding guidance provided in CEN-152, Revision 3.
Rather, these procedures continued to state "If RCS voiding inhibits heat removal, then reduce or eliminate voided area."
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Upon being notified of this apparent continuing discrepancy, the
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licensee committed, on July 25, 1989, to incorporating the CEN-152,
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voiding-guidance in all applicable procedures by September 1, 1989. The licensee stated that it had failed to correct this deficiency following the issuance of Inspection Report Nos.
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50-317/88-05 and 50-318/88-06 because:
(1) resolution of this deficiency was not being followed through any tracking system and (2) between May 1988 and July 1989, a personnel shift had occurred in the plant's Procedural Development Unit resulting in a change in personnel responsible for developing E0Ps.
Subsequently, on September 12, 1989, when asked by the inspector to provide copies of the procedures revised to incorporate the proper void control requirements, the licensee determined that the Calvert Cliffs E0Ps had again not been revised. The licensee stated that the Procedural Development Unit was tasked with too many " Priority 1" actions to permit completion of the necessary corrective actions by the September 1, 1989, commitment date. In addition, this deficiency apparently was still not carried on any management corrective action or commitment tracking system.
The inspector did note that the licensee, however, had modified AOP-3F on August ^9,1989, to incor-porate void control requirements.
- Following ' his notification of this continuing deficiency, the Vice President - Nuclear Energy directed that corrective actions be taken immediately.
Consequently, the applicable E0Ps were modified on September 19, 1989.
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The inspector reviewed the following procedures that were modified to incorporate void control requirements to evaluate the adequacy
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of the licensee's corrective actions:
E0P-3 (Units 1 and 2), " Total Loss of All Feedwater" E0P-4 (Units 1 and 2), " Excess Steam Demand" E0P-5 (Units 1 and 2), " Loss of Coolant Accident" E0P-6 (Units 1 and 2), " Steam Generator Tube Rupture" E0P-7 (Units 1 and 2), " Station Blackout" AOP-3F (Units 1 and 2), " Natural Circulation Cooldown" The inspector found that the corrective actions taken consisted of:
(1) the modification of a common procedural action, previously requiring reduction or elimination of the voided area if voiding inhibited heat removal, to now require voided area reduction /
elimination if voiding threatens or jeopardizes heat removal, and (2) the addition of a precaution to the above E0Ps stating that
"... Steps to eliminate voiding should be taken anytime voiding causes heat removal or inventory control to be threatened. Void elimination should be started soon enough to ensure heat removal and inventory control are not lost."
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These corrective actions appear to be inadequate as:
(1) no pro-
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cedural guidance is provided to licensed operators on how they should i
determine that voiding has progressed to the point where heat
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removal and inventory control will be effected unless void elimina-tion actions are initiated, and (2) no additional training of
licensed operators on these void control requirements has been pro-
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vided other than routing of the modified A0P-3F procedure through operator required reading. The adequacy of these corrective actions i
p has been discussed with the licensee.
j The licensee's repetitive f ailure to correct the deficient void con-j i
trol requirements in emergency procedures at Calvert Cliffs Units 1
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and 2 constitutes a violation of NRC requirements (50-317/89-23-03 J
and50-318/89-23-03),
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7.
Maintenance / Surveillance
7.1 Maintenance i
At 1:05 a.m on September 19, 1989, the licensee notified the NRC via the Emergency Netification Systen. (ENS) line that a pipe crack was discovered downstream of No.11 Spent Fuel Pool (SFP) heat exchanger outlet valve 0-SFP-115 at a location where a hanger was welded to the
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pipe.
The system was being realigned to recirculate 11 Refueling
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Water Tank (RWT) with Il SFP cooling pump and to recirculate and cool
c the SFPs using the 12 SFP and 12 SFP heat exchanger.
The 11 SFP
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cooling pump and 11 SFP heat exchanger were aligned for recirculating and cooling the SFPs prior to this.
During the realignment opera-tions, a plant operator entered the SFP heat exchanger room to throttle open the discharge of 11 SFP cooling pump upon starting.
When the control room started the pump, the operator in the SFP heat exchanger room noted water spraying from the crack.
The leak was i
then isolated and the system subsequently returned to operation through an alternate alignment.
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The licensee's review of the reporting requirements of 10 CFR 50.73 determined that no report is required at this time.
The inspector concurred with this assessment.
During the licensee's reportability review, two similar events were noted to have occurred.
On April 30, 1989, a weld leak was discovered at the discharge side of the 12 SFP cooling pump, and on May 17, 1989, another weld leak was discovered at the 11 SFP cooling heat exchanger outlet valve 0-SFP-118.
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~ The apparent cause of the failures was determined by the licensee to
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be fatigue cracking due to highly stressed piping configuration.
Repairs to this most recent failure have been made and the system l-returned to service.
The inspector witnessed weld repairs to the pipe on September 26, 1989.
An enlarged " saddle" arrangement has been installed at the pipe hanger where the crack was located to provide additional support.
Based on the potential significance of
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a generic concern with the pipe configuration and stress levels in the Spent Fuel Pool Cooling system, the licensee is further investi-gating this problem.
The results of their determination will be reviewed by them for additional reportability concerns.
7.2 Snrve111ance
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The inspector observed portions of tests to assess performance in
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accordance with approved procedures and LCOs, test results (if com-
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I pleted), removal and restoration of equipment, and deficiency review and resolution.
The following tests were reviewed:
01-21, Emergency Diesel Generators, Revision 24, "Non-Emergency
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Start of Diesel Generator" ETP No.
0-8-0, Revision 26,
"11, 12 and 21 Diesel Generator
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Test"~
No unacceptable conditions were identified.
8.-
Engineering Support 8.1 Pressurizer Cracking
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On September 25, 1989, in a public meeting at Bethesda, Maryland, BG&E presented their response to Confirmatory Action Letter (CAL)
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89-08, regarding the safety issues involving the restart of Unit 1 as it might relate to the leaking pressurizer penetrations in Unit 2.
Thus far, no leakage has been found in the pressurizer penetrations of Unit 1.
The Unit 1 pressurizer has operated longer than Unit 2 pressurizer,(92,449 hours0.0052 days <br />0.125 hours <br />7.423942e-4 weeks <br />1.708445e-4 months <br /> vs. 86,228 hours0.00264 days <br />0.0633 hours <br />3.769841e-4 weeks <br />8.6754e-5 months <br /> under essentially the same conditions).
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In their response, the licensee initially presented the results of i
f their investigation of leaking penetrations in Unit 2.
These pene-trations were of two types:
(2) Inconel 600 heater sleeves (HS) and
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(2) an Inconel 600 instrumentation nozzle (IN).
In both types, the penetrations were welded to the vessel with partial penetration ("J" groove) weld joints.with the former sized to accommodate the in-
stalled heaters. Leakage was detected by the presence of boric acid crystals on the surface of the vessel around the penetrations.
In
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the case of the heater sleeves (HS), 20 HSs out of a total of 120 were definitely known to have leaked.
In the case of the instrumen-
tation nozzles, one of seven was found to have leaked.
A more detailed inspection of the HSs by liquid penetrant inspection
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and eddy current inspection disclosed that the leakage originated in longitudinally oriented defects on the ID surface of Inconel sleeves.
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No circumferential defects were observed. Portions of three of these
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defective sleeves were removed for metallurgical examination. One of the three sleeves included the Attachment "J" weld joining the sleeve to the ferritic (SA-533-GR-B Mn-Mo) head. Metallurgical examination of the sleeve sections, which were made from tubing, revealed axially oriented cracks on the ID (wetted) surface of the sleeves. The maxi-mum length of the cracks was Ih" long.
The major portion of the defects as observed in the core bore samples as located in the area just found to be clearly intergranualr in nature. Of major impor-tance was the fact that the examination showed evidence of heavy cold work on the ID surface, the apparent origin of cracking, to a depth of.006".
This condition was attributed to a reaming operation that was employed to remove surface irregularities on the ID surface caused by the weld penetration effects of the
"J" weld.
The reaming operation resulted in an ID of 0.895" and a maximum surface hardness of Knoop 450 (~ RC-45) in the cold work area as compared to an ID of 0.905" prior to reaming with a Knoop hardness of 245 (~ RC-22). The licensee also reported that after removal of the sleeves, visual
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examination of the ferritic (vessel penetration) surfaces showed no evidence of steam cutting and minimal corrosion attack (<.030). Also noted was that the yield strength of the sleeves as reported in the mill test report was higher than generally found in fully annealed tubing (63,500 psi vs. ~40,000 psi).
The licensee concluded that the cracking in the Unit 2 pressurizer heater sleeves was due to primary water stress corrosion cracking in a crevice environment resulting from a combination of factors includ-ing excessive tensile stresses from cold working (reaming), residual
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welding stresses and a susceptible metallurgical structure attendant l
with a material of relatively high yield strength.
The latter is determined by various processing variables such as, chemistry, melt-ing practices, tube forming operation and heat treatment.
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With regard to the isolated leak in the instrumentation nozzle, the licensee attributed the failure to primary water stress corrosion cracking that resulted frort a unique set of metallurgical and resi-dual stress effects from welding and/or machining that were generated
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during a major weld repair of the "J" groove during fabrication. A
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review of fabrication records did not indicate that significant ream-ing was employed in the fabrication or repair of the instrumentation
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nozzle although machining or grinding may have been required.
From
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the standpoint of metallurgical factors, the nozzle would not have
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been expected to fail based on its pre-weld repair yield strergth reported to be 36,000 psi, considerably less than the 60,000 psi reported for the Calvert Cliffs heater sleeve material and for two instrumentation nozzles in a San Onofre pressurizer that failed in 1986.
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In providing justification for the safe operation of Unit 1 pressur-izer, the licensee made these salient points in comparing Unit 1 penetrations with those of the leaking penetrations in Unit 2, even though the same heats of Inconel 600 materials were used for both Units (except for one sleeve on Unit 1).
In addition to not detec-ting any leakage in Unit 1, the heater sleeves were considered to be less susceptible to stress corrosion cracking than Unit 2 primarily because the amount of reaming, and attendant residual stress, was
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signifNantly less for Unit I than reported for Unit 2 (locally up to
.005" ruaoved in Unit I vs.013" removed in Unit 2). With regard to the instrumentation nozzles in Unit 1, failure is considered to be less likely than the heater sleeves in Unit 2 because, as previously stated, of its reduced susceptibility to stress corrosion cracking as related to its lower yield strength, and the reported absence of reaming in fabrication.
In addition, the licensee performed a frac-ture mechanics analysis which concluded that unstable growth of axial cracks lh" to 2" long in the sleeves was not expected, although con-tinued stable crack growth could occur by stress corrosion cracking.
Also, the possibility of a sudden cross-sectional failure was
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unlikely since no circumferential cracks were found.
A leak rate analysis indicated that leakage from the size of flaws observed would be small and would not result in significant corrosion of the press-urizer wall.
In addition, the licensee reported that a visual inspection of all heaters and instrumentation sleeves was performed in Unit I with no evidence of leakage observed. Also, approximately 150 similar Inconel partial penetration ("J" groove) joints in the primary side of Unit 2 and seven (7) joints in Unit I were visually
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inspected with no evidence of leakage observed.
The licensee in their letter dated October 2,1989, stated that since they cannot be
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completely assured that leakage of pressurizer penetrations will not occur, they have committed to visually inspecting pressurizer sleeves and nozzles in the next fuel cycle during each reactor shutdown where i
a hot standby and/or a cold shutdown (when a duration of 7 days or more is anticipated) is reached.
In the hot standby, the insulation
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will not be removed, whereas in the cold shutdown, the inspection U
will be performed on bare metal. The bare metal inspection will be
performed at least once per eighteen months.
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On the basis of the licensee's investigation and their commitment to
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inspect the penetrations during the next fuel cycle, NRC concluded that the licensee has provided reasonable assurance that restart of Unit I with the pressurizer penetrations in their current configura-tion is not a safety concern.
This issue, which was an element of the May 25, 1989 CAL issued to the licensee is considered resolved.
No unacceptable conditions were noted.
9.
Licensee Event Reports (LERs)
LERs submitted to NRC:RI were reviewed to vu ify that the details were clearly reported, including accuracy of the description of cause and ade-quacy of corrective action.
The inspector determined whether further
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information was required from the licensee, whether generic implications were indicated, and whether the event warranted on site follow up.
The
.following LER's were reviewed:
LER No.
Event Date Report Date Subject Unit-1 89-13*
07/31/89 08/28/89 Inadequate procedure to fully comply with Technical Specif-ication 4.9.12.a for spent fusi pool exhaust fans 89-14*
07/23/89 10/03/89 Determination that the No. 12 saltwater header was not capable of withstanding a
seismic event intact
- Detailed examination of these events are documented in Inspection Report Nos. 50-317/89-18 and 50-318/89-19.
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LER No.
Event Date Report Date Subject Unit 1 e
89-15 08/22/89 09/02/89 Determination that calcula-tions used to determine that F
the dousing system for the containment iodine filters
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are not required to be environmentally qualified are in error 10.
Review of Licensee Response to NRC Initiatives No unacceptable conditions were noted.
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11.
Review of periodic and Special Reports
Periodic and special reports submitted to the NRC pursuant to Technical Specification 6.9.1 and 6.9.2 were reviewed.
The review ascertained:
inclusion of infoimation required by the NRC; test results and/or suppor-ting information; consistency with design predictions and performance specif.ications; adequacy of planned corrective action for resolution of problems; determination whether any information should be classified as an i
abnormal occurrence; and validity of reported information. The following i
periodic reports were reviewed:
August 28, 1989, Semi-Annual Effluent Release Report
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September 5, 1989, Special Reports Concerning Two Inoperable Penetra-
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tion Fire Barriers September 18, 1989, Operating Data Reports for Calvert Cliffs Unit
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Nos. I and 2 for August 1989 No unacceptable conditions were identified.
12.
Events Requiring NRC Notification The circumstances surrounding the following events, which required NRC notification via the dedicated ENS line, were reviewed. A summary of the
~ inspector's review findings follow or is documented elsewhere as noted below:
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At 12:14 p.m. on September 7,1989, the NRC was notified in accord-
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ance with 10 CFR 50.72(b)(1)(vi) that a small weld leak was dis-covered on the outside of the 21 RWT (Unit 2 Refueling Water Tank).
The unit was defueled at the time.
The leak was discovered by Rad Con personnel while performing a routine weekly survey around the outside of 21 RWT. Previous weekly surveys did not reveal any leak-o I
age. The leakage was evidenced by the presence of a dried boric acid buildup on an approximate 6 inch by 6 inch area located at the bottom northeast area of the tank. The indicated tank level was 34 feet and no water was present at the seam weld.
The licensee declared a
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i Radiological Event due to the unplanned contaminatior..
Activity levels in the water were measured to be 5.88 x 10 ' micro curies /cc at 10:17 a.m.
The licensee is currently in the process of draining the RWT and processing it using the Miscellaneous Waste Processing System for release.
As of this inspection, the tank was at the 6 foot level with drain-L ing, processing and release operations temporarily halted.
The
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licensee had been draining to the RWT to tne Miscellaneous Waste Pro-cessing System through manual stop valve 2-SI-4163 and check valve 2-51-4:54.
Given the present level in the tank (6 feet) and the relative elevation heads in the systems, 2-SI-4164 will no longer open to allow fM out of the tank. The licensee had planned to per-
form a temporary modification to remove the valve internals, which would allow draining of the remainder of the tank.
This would require a 10 CFR 50.59 safety evaluation.
In lieu of this, the Operations Department devised an alternate path-way to drain the remainder of the tank to the Miscellaneous Waste Processing System.
At the present time, a pathway is being con-sidered through check valve 2-SI-4146 in the Safety Injection System to drain valve 2-SI-472 at the suction side of the No. 21 High Pressure Safety Injection (HPSI) pump.
This will transfer the water to the No. 21 ECCS room sump from which a path will be established to transfer the liquid to the Miscellaneous Waste Processing System,
The leak is through a butt joint at the base of the tank which con-sists of an internal and an external fillet weld. The leak location through the externD fillet is evident by the boric acid deposits.
The leak location nrough the internal fillet will be investigated upon emptying the tank.
Repairs to the tank can then be made, j
At 1:27 p.m. on September 8, 1989, the NRC was notified in accordance
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with 10 CFR 50.;2(b)(2)(iii)(A), that an investigation of a degraded condition found on the RCS RTDs determined that the nipple-to-base interfaces were not sealed.
This event is discussed in Section y
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j At 9:47 a.m. on September 14, 1989, the NRC was notified in accord-j
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nL ance with 10 CFR 50.72(b)(1)(v), that the Emergency Offsite Facility
(EOF) was without power.
Also, during this time, the emergency diesel generator did not start. Availability and adequacy of emerg-
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ency power to the EOF is being tracked as an unresolved item No.
50-317/89-23-05 and 50-318/89-23-05).
At 1:05 a.m. on September 19, 1989, the NRC was notified in accord-
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ance with 10 CFR 50.72(b)(2)(1), that a pipe crack was discovered downstream of No. 11 spent fuel pool heat exchanger outlet valve 0-SFP-115. This event is discussed in Section 7.1.
At 2:00 p.m. on September 28, 1989, the NRC was notified in accor-
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dance with 10 CFR 50.72(1)(b)(v), that the dedicated emergency notif-ication system (ENS) telephone line was out of service.
This was discovered by the licensee upon the illumination of the failure lights on the control room phone.
The system was restored at
- 2:10 p.m. on the same day.
During this time period, other means of communication were available if needed.
The probable cause of the
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event was determined to be a lightning strike on the system.
No unacceptable conditions were noted.
- 13.
Followup of Restart Issues In May 1989, following discovery of indications of leakage in the vicinity of heater sleeves in the Unit 2 pressurizer, the licensee elected to shut down Unit I until it could be established that the cause of leakage in Unit I was either not applicable to Unit 1 or, if applicable, the issue had been resolved such that the unit could be safely operated.
In its letter of May 23, 1989, the licensee also committed to resolve several management concerns prior to returning either unit to service.
These specific commitments were summarized in NRC Confirmatory Action Letter (CAL) No. 89-03 of May 25,1989 as determining and correcting the root cause(s) of the problems which have been manifested as weaknesses in con-trol of system status; control of work activities; and procedure use and control of procedure changes.
In a letter of June 21, 1989, in response to unresolved items and other issues stemming from the Special Team Inspection (STI) conducted February-March 1989, the licensee committed to certain shcrt-term corrective actions prior to startup of either uni y o
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The licensee documented its corrective actions in packages which were presented to the resident inspection staff for review.
(These items have been identified as CAL-(No.) or STI-(No.) to correspond to identification numbers utilized by the licensee staff for tracking).
Results of review
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of those packages submitted thus far are as follows:
i 13.1 CAL-2, ~3,
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-5,
-6,
-7,
-8, -10, and -13 (OPEN)
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These commitments were related to the general i ssue of control of systems.
Specifically:
l-CAL-2:
Improve the process for identifying equipment out-of-
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service and tagout status to ensure that shift supervision is cognizant of the information they need to safely supervise oper-ational activities.
CAL-3:
Display tagout boundaries on laminated drawings for
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shift supervision review and use.
CAL-4: Require an independent review by two licensed operators
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of all tagouts for adequacy and appropriateness relative to
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plant conditions.
- CAL-5:
Improve the controls of supplementary tagout clearanca.
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CAL-6:
Require physical walkdowns of tagging boundaries. The
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job supervisor will conduct these walkdowns independently or with Tagging Authority when required.
(Limited exceptions are permitted).
CAL-7:
Reorganizing Safety Tagging such that the position of
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Tagging Supervisor is elevated to report directly to the Super-visor-0perations Maintenance Coordination (OMC).
CAL-8:
Prohibits all unscheduled tagouts from being initiated
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except those which are permitted by the Shif t Supervisor or Supervisor-0MC due to the critical nature of the job.
CAL-10:
Schedule jobs involving more than one work group or the
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Tagging Authority a minimum of three days in advance with limited exceptions as authorized by the Supervisor-0MC or Shif t Supervisor. All missed work will be brought to the OMC Unit for evaluation of impact on other work and rescheduling.
CAL-13:
Implement and train on Calvert Cliffs Instruction
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(CCI)-112, " Safety Tagging".
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The licensee has _ implemented these various commitments through addi-tions to-its procedure, Safety Tagging, CCI-112. This procedure was
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i reviewed by resident inspectors and regional staff in conjunction
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with the closeout process.
First and foremost, the procedure has l
been subjected to many narrowly-focused changes and has therefore
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become extremely complex and replete with exceptions.
The procedure l'
appears to warrant a programmatically-oriented revision.
A specific concern which has been discussed with the licensete include the option to perform' work on energized low voltage (<400 volts) cir-cuits on instrument loops and high energy systems with the approval of the job supervisor and shift supervisor. This practice does not l
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appear to provide protection to technicians nor to provide positive control of system / component status.
L Further, while the procedure permits the use of supplementary clear-ances for multiple tasks within one boundary, there is no requirement i
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that all clearances be signed off before the main clearance is lifted.
Paragraph VIII.F.4 permits testing before all clearances are lifted through use of a tagout modification, whereas paragraph j
VIII.F.5 requires all clearances to be signed off and returned prior to testing.
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These items remain open pending satisfactory resolution of the_ above three concerns and verification through inspection of implementation.
13.2 CAL-9 Control of Work Activities (CLOSED)
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This commitment resulted from a series of events which occarred in Spring 1989 which led the licensee to conclude that control of work
activities, particularly those associated with the Unit 2 outage, was
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inadequate. The licensee committed to a reduction of level of site i
activities and craft contractors by approximately one-third to facil-
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itate more effective control of work.
The inspector has reviewed several weekly reports of contractor manning levels and is satisfied that this has been done.
The inspector questioned what long-term corrective actions are planned to permit increase of craft labor to levels normally encountered during a typical refueling outage.
The licensee's response was that an Outage Management Department has been created and headed by an experienced plant manager ar.d a Superintend-ont cf Maintenance has been installed to strengthen maintenance activities.
These are in addition to other initiatives taken per above.
This item is closed.
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j 13.3 CAL-11 Communications (OPEN)
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This commitment, also related to the control of work activities,
L addressed weaknesses in communications among Operations shift person-
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nel, Tagging Authority personnel, and Operations and Maintenance L
Coordination (OMC) personnel.
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In its response, the licensee stated, "The formation of new work
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groups led to a. segregation of work activities and to a deterioration in communications between Operations Shift personnel, the Outage Coordination Group, and the Tagging Authority as the goals of the groups became less tightly bonded.
Each work group felt its primary responsibility was for its own special work activity and did not function to ensure nuclear safety." The root cause cited for this condition was, "(T) hat roles, interfaces and responsibilities were unclear. Management failed to recognize this condition and to imple-ment corrective actions."
Short-term corrective action has been the issuing of General Super-
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visor-Nuclear Operations (GS-NO) Standing Instruction 89-9, Communi-cations Betwe n Operations Shift Pecsonnel, Tagging Authority and the OMC Unit, is: sed August 16, 1989.
- Review of that document indicates that it addresses matter and pre-scribes-action related to activities important to safety such as shift and relief turnover matters which. should be addressed in pro-cedures reviewed by the POSRC and approved by the Plant Manager in accordance with Technical Specification 6.8.2.
This is a further example of the improper use of GS-N0 Instructions for properly approved procedures.as identified in Special Team Inspection Report 89-200, Unresolved Item 89-200-03.
Long-term corrective action is reportedly addressed under Section 3.0 of the Performance Improvement Plan Implementation Program. Neither the GS-NO Instruction 89-9 nor the PIP address the issues identified by the licensee as the associated root cause. This item remains open pending the licensee's demonstration that the authority and duties of the persons in these organizations are clearly established and delineated in writing in compliance with the requirements of 10 CFR 50, Appendix B,
Criterion I (50-317/89-23-04; 50-318/89-23-04).
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13.4' CAL-12 Human Performance Evaluation of Procedure Violations (CLOSED)
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In an effort to reduce the numerous past procedure-noncompliance vio-lations, the' licensee identified th lack of a consistent, systematic
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mechanism for evaluating human error associated with such violations s
and the failure to conduct detailed investigations to establish root
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cause(s).
This particular item dealt with implementing a system to evaluate. human error such that root causes of violations /noncompli-
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.ances are identified and corrected.
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if The licensee has established an Engineering Root Cause Analysis pro-
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gram ' under the purview of the Independent. Safety Evaluation Unit (ISEU) under which human performance aspects of events are evaluated.
Pro s aral changes. have been initiated requiring forwarding of the
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"C. w list for Timely Notification" to the Supervisor-ISEU (Nuclear Operations Section Initiated Reporting Requirements, CCI-118N);
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notifying the ISEU 'for possible initiation of a human performance review as determined by the HPES Coordinator (Calvert Cliffs Event Reports,- CCI-1270); requiring the QC/PQ Supervisor to perform trend-
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ing -to ' analyze the nonconforming condition / deficiency for repeti-tions, hardware failure or human error, distribute the NCR ' to ISEU,
. review NCR records semi-annually for any trends...to analyze...for human error (Control of Deficiencies and Nonconformance Reports,
CCI-116G).
The inspector exp essed concern to licensee management regarding the lack of a programmatic approach to the resolution of a deficient corrective action program, the diffuse requirements incor-porated in many diverse procedures, and the probability of inadver-tent noncompliance with the recent initiatives.
While. the letter of the commitment regarding this issue has been satisfied, and on thst. basis, this item has been closed, an HPES-discipline approach to the entire subject of corrective action pro-
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grams as implemented at Calvert Cliffs would appear appropriate.
Also - reviewed during the closeout of this issue was a proposed Nuclear Energy Department Control Procedure (NEDCP) which would
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establish the Human Performance Evaluation System at Calvert Cliffs.
Since the inspector was not familiar with this type of procedure and it was not defined within the licensee's Quality Assurance program, the inspector questioned the cognizant program manager regarding the matter. The manager explained that these NEDCPs were procedures out-side the scope of P0SRC review and the QA audit program. The inspec-tor explained that administrative controls directing the operating organization in the conduct of activities important to safety regardless of their title are subject to POSRC review and QA program audit.
The licensee agreed to reexamine the review process for NEDCPs.
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13.5 STI-1 Control of Measuring and Test Equipment (OPEN)
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Special. Team Inspection (STI)89-200 identified this item as an unre-solved item - (89-200-01).
The issue was that CCI-120D, " Calibration
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Program for Measuring and Test Equipment," Change 2, required the supervisor of each group responsible for measuring and testing equip-ment to ensure that approved calibration procedures for test equip-ment were available -and used.
Further, the STI found that licensee personnel used instruments to perform surveillance test procedures that had not been controlled and calibrated in accordance with approved calibration procedures.
In addition, the NRC inspector
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determined that the licensee had a number of pressure gauges which, when needed, were calibrated against "more accurate" gauges then used to perform surveillance tests, however, no record was made of where they were used tnd no checks were made to verify that the gauges were still1 indicating properly after use. This area was further inspected during inspection 50-317/89-15; 50-318/89-16 and has been subject to enforcement action resulting from that inspection.
'The licensee's immediate corrective action has been limited to issu-ing Shop Lab Memo I-89-1 (Revision 1) which informs Instrument Main-tenance (IM) technicians that, when requested to install calibrated test 1 equipment for support of maintenance, the (T)est (E)quipment
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(G)roup shall supply the calibrated test equipment.
Long-term cor-rcetive action consists of plans to audit to verify adequacy and effectiveness of the onsite calibration program.
The inspector - expressed concern to licensee management that the appropriate administrative controls which would implement this aspect of the QA program have not been revised to incorporate the otherwise non permanent 1 initiative promulgated by the Shop Lab Memo.
This issue remains open pending incorporation of the revised measuring and test equipment controls into permanent, reviewed, administrative procedures.
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13.6 STI-3,
-4,
-5, and -6 Use of General Supervisor-Nuclear Operations (GS-NO)' Standing Instructions (OPEN)
The Special Team Inspection 89-200 identified concerns that the use of GS-N0 Standing Instructions were used as a means of providing directions for operator actions rather than including those direc-tions in an approved procedure.
(See Unresolved Item 50-317/
89-200-03).
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The licensee reviewed these standing instructions and has incorpor-
- ated identified operator actions into appropriate procedures.
Per-manent corrective action included insertion of a-statement in CCI-114, Plant Logs, to the effect that GS-N0 notes and instructions shall not be a substitute for procedures and a requirement that the GS-N0 review all current standing instructions semi-annually to verify.that they are not substituting for procedures.
lThe inspector noted that, while the immediate corrective action has-incorporated operational steps into appropriate procedures, other matters which affect activities ~important-to-safey have since been
. incorporated into GS-N0 instructions. An example of such incorrect usage is GS-N0 Standing Instruction Guidelines 89-9 regarding.commun-ications among operations shift personnel, Tagging Authority person-nel and the OMC Unit.
These'. items remain open pending the implementation of more effective corrective action to prevent recurrence of earlier problems.
13.7 STI-7 Lack of Detailed Work Instructions (OPEN)
This item was identified in the Special Team Inspection as unresolved item 89-200-05.. Specifically, work instructions used for performing maintenance activities did not contain adequate details to ensure that the activities were being performed correctly or to provide
. meaningful acceptance criteria and holdpoints for Quality Control inspectors.- (The corrective action related to acceptance criteria is discussed'below under STI-27.)
Licensee corrective action included revising CCI-200, Calvert Cliffs Nuclear Maintenance System, allocation of additional personnel to procedure writing and maintenance planning, and training of affected personnel in the revised maintenance system requirements.
Specif-ically, CCI-200 was revised to require that maintenance planners pro-vide detailed steps necessary to complete maintenance work.
Al so included was a requirement that QC review maintenance order (MO)
packages to determine if their involvement, including holdpoints, is required.
Additionally, CCI-101 which prescribes requirements for implementing procedures, had been revised to include a Procedure Writers Guide which required procedure writers to incorporate a level of detail in procedures to provide adequate instructions to the least experienced qualified procedure user.
The maintenance system procedural rev1sions, when fully implemented, would appear to provide the improvements necessary to resolve and close this unresolved item; however, the current data base is inade-quate to assess the effectiveness of the system changes.
Addition-ally, a licensee surveillance (Surveillance 89-16) was conducted in late August 1989 which concluded that improvements had been imple-mented; however, recurrent problems were still noted.
This item
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remains open pending future review of maintenance orders / procedures i
to be produced under the system.
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13.8 STI-15 AOP-9 (Alternate Safe Shutdown Procedure) Revision and Validation (OPEN)
During the Special Team Inspection, the team walked through abnormal operating procedure AOP-9, " Alternate Safe Shutdown Control Room
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Evacuation Procedure." Performance of A0P-9 required extensive oper-ator actions throughout the plant, and required participation from most of the operators on shift.
The licensed and non-licensed plant operator training for A0P-9 consisted of independent classroom train-
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ing and procedure walkthrough to locate equipment.
The independent
procedure walkthrough appeared inadequate because the operating shift
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would have 'to' perform complex required actions as a team.
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appeared to the team that the procedure walkthrough training would have been more effective if licensed and non-licensed personnel had been trained.together.
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In its June 21, 1989 response, the licensee committed to revising AOP-9; to provide. necessary training following. that revision; and, as. long-term corrective action, to train licensed and non-licensed operators together on AOP-9-at least once each training cycle.
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A special licensee project team inspection of this procedure deter-mined that in the event of a control room fire, the measures con-tained in AOP-9 to achieve cold shutdown within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, as required by 10 CFR 50, Appendix R, could not be performed.
The two major weaknesses identified with A0P-9 were insufficient shift manning levels and design features in the plant which would not permit required local operations.
The licensee committed to revise A0P-9 to account for design modifi-cati.ons made to the plant and to. correct procedural inadequacies.
A. review of the revised procedure identified the following concerns; a.
A0P-9A is specific to Unit 1.
It is not clear how this proced-ure interfaces with Unit 2 in the event of a control room fire since Units 1 and 2 have a common control room.
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AOP-9A requires responses from seven different individuals:
a RO, CRO, SS, STA, OSO, TB0 and a AB0. Assuming a similar pro-cedure exists for Unit 2, would an additional seven individuals be required? Would there be any responses which would be common to both Units? Would off-shift manning be sufficient to support both Units?
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To $1p clarify the A0Ps, it is recommended that the licensee develop e
a Writers Guide,- similar to that used for writing E0Ps,. to provide consistency and 'a clear understanding of what is required.
For example, on page 61 of AOP-9A, step 1 would be clearer if an "0R" was placed'between each of the three substeps and step 3 would be clearer if an "AND" was placed between the two substeps.
'This item remains open pending completion of 'the plant modifications necessitated by the licensee project team inspection and correction of technical deficiencies in nine additional. Abnormal Operating Pro-cedures (AOP-3B, 3G, 6D, 7B, 7C, 70, 7G, 3F and 7I) identified by the licensee.
13.9 STI-18 Post-Maintenance Testing Process (CLOSED)
The Special Team Inspection identified a concern that the responsi-bility for-the determination of post-maintenance testing rested almost exclusively with the shift supervisor. This imposed a signif-icant burden on shift operating personnel, particularly during an outage with its' attendant large number of maintenance orders pending closeout.
The shift supervisor was forced to rely on his " good judgement"
~to' identify post-maintenance testing requirements and related acceptance criteria as well as determining the. level of docu-mentation required.
Part of _the recent revision to CCI-200, Calvert Cliffs Nuclear Main-tenance System, specifies inclusion of post-maintenance testing requirements in each maintenance order. The revised procedure iden-tifies organizational responsibilities, when post-maintenance testing is required and the organizational responsibility for performance, and specifies requisite documentation.
A new position has been established within the maintenance organization, Post-Maintenance Testing Coordinator, who is responsible for monitoring and coordina-ting the program.
(This position is currently filled by an SRO-licensed individual within the Operations and Maintenance Coordina-tion Unit). The inspector reviewed Post-Maintenance Testing guides which have been developed to assess the practical direction given to maintenance planners regarding requisite post-maintenance testing for maintenance orders. Licensee short-term corrective action appears to have provided requisite direction for the correction of this concern; however, need for continued management attention to the assessment of the effectiveness of corrective action remains.
Based on licensee action to date, this item is closed.
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.13.10 STI-20 Communication of Management Expectations and Priorities (CLOSED)'
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The Special: Team Inspection determined that:
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-The second tier of~ management, the General Supervisor (GS), was l
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effectively separated from the managers above and the workers
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below.
Rather than translating management's strategic goals and
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pol.icies into work practices and expectations, the GS group was found to be the enforcers of an operating style that emphasized
't production over safety.
Rather than focusing management's stated goals and policies, the GS group tended to act as a filter.
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Very little of the stated goals and policies has filtered.down
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to the workers, leaving a. frustrated desire for guidance and
. direction.
To paraphrase several persons, workers "wish they (management) would just tell'us what they want."
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r The terms and conditions under which work was accomplished in.
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the organization were being developed by default at lower levels of the organization.
Persons at those levels were developing their own performance standards and expectations based.on their perception of an operating philosophy which stressed production, O
and, relative to the climate in which work was performed,- that with the production orientation found throughout the organiza-t o
tion, that teamwork was considered by the plant staff to be
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L doing that which was necessary to support operations rather than
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working together toward a.
shared safety or performance obj ective.
The licensee characterized these findings as a significant number of complex activities competing for a limited amount of. time and
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resources and further, that despite management efforts to communicate to the work force that Performance Improvement Plan (PIP) items were top priority, past performance indicated that outage work and restart commitments would receive all the priority and attention at the expense of PIP. items.
Daily meetings began to reflect the priority for returning the units to service without unnecessary delay and a i
preference for dealing with shorter-term, more concrete issues in lieu of the softer, longer-term programmatic issues.
Licensee management expressed the concern that unless clear, focused and pri-oritized goals were communicated by management (from the VP and man-
agers through the general supervisors to the workforce), the licen-see's history of focusing primarily on production would be repeated.
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Licensee.short-term corrective action has included:
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Extending Unit 2 outage in order to allow better allocation of personnel towards near-term goals.
Conducting " focus" meetings with all employees to provide better
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Meetings between VP and employees to provide VP's personal
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expectations regarding quality and safety.
Development of an integrated activity schedule.
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Integration of PIP and restart commitment items with outage work
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activities.
.The inspectors attended representative meetings in which licensee management addressed the staff and have interviewed operators and technicians in order to attempt to assess the effectiveness of these.
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meetings.
Activity schedules have been reviewed in normal daily inspection' activities.
Based. on these activities, it was concluded that licensee efforts in the short-time have been adequate in con-
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veying. the intent of longer-range goals and expectations to the
Calvert Cliffs operating organization, therefore this item is closed.
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However, the inspector.noted that these initiatives are short-time solutions in -transmitting only the "what" of long-term expectations.
The "who" and "how" remain to be implemented through the establish-ment and clear delineation in writing of the authority and duties of-persons and organizations performing activities important to safety and the documentation of management's direction for the accomplishing of.these-activities through an effective administrative controls pro-gram, the essential elements of a quality assurance program.
13.11 STI-21 Equipment Status Log (CLOSED)
The Special Team Inspection identified that current status of equip-ment out-of-service was not readily available to control room per-sonnel.
While limiting conditions for operation were listed in the control room operator's log and on a video screen and a computer printout was available for those systems / components tagged out, sys-Y tems or components could be placed out-of-service without entry into an LC0 or without requiring a danger tagout.
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F In response: to this identified weakness, the licensee revised pro-cedure CCI-307, Nuclear Operations Shift Turnover,. which now incor-porates an Equipment Status Sheet which reflects deranged equipment, its-problem and the associated maintenance request number.
The inspector verified that this document was being utilized and that appropriate onsite operating organization personnel had been trained in the revised procedure.
This item is closed. -
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-13.12 STI-27 Incomplete Documentation of Completed Maintenance (CLOSED)
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The Special Team Inspection identified that numerous maintenance pH
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records were incomplete in that required information had not been included and concluded that these omissions were an indication of
carelessness.
The team was concerned that the noted examples of-incomplete equipment history could be a generic issue which could inhibit licensee efforts to use this equipment history es a tool to conduct meaningful root cause analyses. This item was identified as unresolved-item 89-200-06.
In ;its analysis of this issue, the licensee determined that a root cause was management's failure to insist on attention to detail -and to communicate that missing documentation constituted procedural noncompliance.
Licensee corrective action has focused primarily on reiteration of management expectations with respect to procedural compliance. Meet-ings have been held with operators and technicians during which the requirement for procedural compliance has been stated.
Letters have been issued by the Plant Manager and the Vice President stating pro-cedural compliance expectations. These. also emphasized the account-ability, of personnel-including disciplinary action in the case of violations.
Some initiatives have been taken in changes to the basic instruction regarding implementing procedures, CCI-101, in an effort to assist in the development of accurate and human-factored maintenance pro-L cedures. The governing document for the maintenance system, CCI-200, has been changed to facilitate incorporating action taken in mainten-
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ance orders.
Inspector interviews with site operating organization personnel indi-cated that there is a understanding of procedural compliance policy.
Based on the short-term corrective actions taken to date, this item is closed.
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30 In its close out documentation, the licensee identified the generic concern that additional incomplete maintenance records exist in other areas.
While the licensee has not formally committed to a prompt review of such documentation in order to provide reasonable assurance of its completeness, such action would appear appropriate.
The licensee acknowledged this point.
13.13 STI-22 Complete the Revision and Approval of CCI-104 (Surveillance Test Program) (CLOSED)
The inspector reviewed the licensee's actions taken with respect to the findings of the Special Team Inspection 89-200 in the area of the surveillance test program (STP).
During the team inspection, it was noted that the responsibility for implementation of the STP was divided among the various work groups at the plant.
The STP admin-istrative procedure, CCI-1041, specified that a single individual be responsible for the overall administration of the program. The var-ious work groups, however, independently scheduled, coordinated, and were responsible for their own surveillance testing activities.
CCI-104I appeared to be a very detailed and complex document for the administrative task it was suppossd to perform. A lower tier docu-ment or a more centralized program was needed to ensure consistency and program responsibility.
Following the inspection, the STP was revised and CCI-104J was issued.
CCI-104J appears to be as complex and detailed as the pre-vious revision but is more centrally oriented to the SSTPM and the FSTC.
The program calls for the establishment of a Site Surveillance Test Program Manager (SSTPM).
The SSTPM has the responsibility and the authority to administer the STP.
Reporting to this position are seven Functional Surveillance Test Coordinators (FSTC) in the area of operations, mechanical maintenance, electrical and control s, fire protection, nuclear materials engineering, snubbers, and integrated leak rate testing.
CCI-104J lists the responsibilities for the STP.
Some of che FSTC responsibilities include scheduling, maki ng test changes and reviewing tests in their areas.
Program control might be increased if the licensee were to computer-ize test scheduling rather than scheduling manually as is done pre-sently.
The licensee does have a plan for computerizing in the future.
Additional concerns noted by the licensee with respect to training, qualification, and certification have been adequately addressed.
Based on licensee action, this item is closed. The effectiveness of correction actions will continue to be monitored in future inspections.
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14.' Unresolved Items Unresolved items require more information :.o determine their acceptability and are-discussed in Details 15. Management Meetings.
Meetings were periodically held with senior facility management to discuss '
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the' inspection ~ scope and findings. A summary-of findings was presented to the-licensee at' the end of the inspection.
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