IR 05000213/1986027
| ML20214U410 | |
| Person / Time | |
|---|---|
| Site: | Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png |
| Issue date: | 11/25/1986 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20214U327 | List: |
| References | |
| TASK-2.F.2, TASK-TM 50-213-86-27, IEB-79-11, IEB-79-13, IEB-79-17, IEB-79-18, IEB-79-21, IEB-79-23, IEB-85-002, IEB-85-2, IEB-86-002, IEB-86-008, IEB-86-2, IEB-86-8, IEIN-86-073, IEIN-86-73, NUDOCS 8612090262 | |
| Download: ML20214U410 (23) | |
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m U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-213/86-27 DCS Nos. 50-213/86-10-08 50-213/86-10-09 Docket No.
50-213 50-213/86-10-16 License No.
DPR-61 Licensee:
Connecticut Yankee Atomic Power Company P. O. Box 270 Hartford, CT 06101 Facility:
Haddam Neck Plant, Haddam, Connecticut Inspection at: Haddam Neck Plant Inspection conducted: October 1 through November 17, 1986 Inspectors:
Paul D. Swetland, Senior Resident Inspector Stephen M. Pindale, Resident Inspector E. L. Conner, Project Engineer Approved by:
u2S/fC E. C. McCabe, Chief, Reactor Projects Section 3B Date Summary:
Areas Inspected: This was a routine resident inspection (261 hours0.00302 days <br />0.0725 hours <br />4.315476e-4 weeks <br />9.93105e-5 months <br />) of plant operations, radiation protection, physical security, fire protection, maintenance, surveillance testing, open items, licensee events, IE Bulletins and TMI Action Plan
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Followup.
Results: Four violations were identified involving improper valve lineups (Detail 3.1), out-of-calibration test gauges (Detail 3.2), inadequate post-maintenance testing (Detail 3.3), and a recurrent breach of containment integrity (Detail 4.3).
Two previous NRC findings regarding containment leak rate testing and procedural compliance were closed.
New NRC inspection findings were opened to review licensee implementation of inadequate core cooling instrumentation surveillance and operator training for independent verification of system lineups.
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TABLE OF CONTENTS P.afLe 1.
Summary of Facility Activities........................................
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Reviewlof Plant Operations............................................
- 2.1 Plant Operations Review Committee Meeting........................
2.2 Demineralized Water Storage Tank Design Error....................
3.
Observation of Maintenance and Surveillance Testing...................
3.1 -Violation Involving Improperly Positioned Valves.................
3. 2 Violation Involving Gauge Calibration............................
3.3 Violation Involving Leak Rate Testing After Valve Replacement....
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Followup on Previous Inspection Findings..............................
4.1 Procedural Compliance Verification...............................
4.2 Containment Leak Rate Tests......................................
4.3 Containment Integrity Violations.................................
4.4 Computer Room Fire Wall Deficiencies............................
5.
IE Bulletins (IEBs), Information Notices (IENs), and Region I Guidance 11 5.1.a IEB.79-11, DB-50 and DB-75 Circuit Breaker Overcurrent Tri IEB 79-13, Feedwater Pipe Cracking........................ps..
5.1. b
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5.1.c IEB 79-17, Pipe Cracks in Stagnant Borated Systems............
5.1. d IEB 79-18, Audibility of Alarms and Evacuation Announcements..
5.1.e IEB 79-21, Temperature Effects on Level Indication............
5.1.f IEB 79-23, Emergency Diesel Generator Excitation Transformers., 14 5.1. g IEB 80-08, Containment, Liner Penetration Weld Examination.....
5.1.h IEB 85-02, DB-5 Circuit Breaker Undervoltage Trips............
5.1.1 IEB 86-07, Static "0" Ring Differential Pressure Switches.....
5.1. j IEN 86-73, Emergency Diesel Generator Problems................
5. 3 GE Type AK-F-2-25 Circui t Breaker Inspection....................
5.4 Standby Gas Treatment System Single Failure.....................
6.
Followup on Events Occurring During the Inspection...................
6.1 PORV Setpoint...................................................
6.2 Potential Strike................................................
6.3 Unlocked Isolation Valve....................
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6.4 Security Access Control Degradation.............................
6.5 Fire in Radilogical Controlled Area.............................
6.6 ENS Service Interruption........................................
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Followup on Implementation of Inadequate Core Cooling Instrumentation. 19 8.
Review of Periodic and Special Reports...............................
9.
Unresolved Items.....................................................
10.
Exit Interview.......................................................
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-9 DETAILS 1.
Summary of Facility Activities At the beginning of the inspection on October 1,.1986, the plant was at 100%
power.
On October 25, load was reduced to 50% to repair an oil leak on a reactor coolant pump motor.
Full power operation resumed on October 25 and continued until November 1, when a second load reduction to 50% power was-initiated to repair a cooling water intake structure. traveling water screen and to inspect the reactor coolant pumps.
Full power was reached on November 2 and continued through the end of the inspection.
2.
Review of Plant Operations The inspector observed plant operation during regular tours of the following plant areas:
Control Room Security Building
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Primary Auxiliary Building Fence Line (Protected Area)
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Vital Switchgear Room Yard Areas
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Diesel Generator Rooms Turbine Building
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Control Point Intake Structure and Pump
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Building Control room instruments were observed for. correlation between channels and conformance with Technical Specification requirements.
The inspector observed various alarm conditions which had been received and acknowledged. Operator awareness of and response to these conditions were reviewed.
Control room l
and shift manning were compared to regulatory requirements.
General control room atmosphere was noted, including no physical distractions such as tele-visions, radios or extraneous reading materials.
Posting and control of radiation and high radiation areas was inspected.
Compliance with Radiation Work Permits and use of appropriate personnel monitoring devices were checked.
Plant housekeeping was observed, including control and. storage of flammables and other potential hazards.
The inspector also examined various fire pro-tection systems.
Logs and records were reviewed to determine if entries were properly made and communicated equipment status / deficiencies.
These records-included operating logs, turnover sheets, tagout and jumper logs, process computer printouts, and Plant Information Reports.
The inspector observed aspects of plant security including access control, physical barriers, and personnel monitoring.
Except as noted below, the inspector had no questions on these items.
2.1 Plant Operations Review Committee (PORC)
The inspector attended a Plant Operations Review Committee (PORC) meeting on November 7, 1986.
Technical specification 6.5 requirements for mem-bership were verified.
The meeting agenda included a review of potential main feedwater system design problems.
The main feedwater pump discharge
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piping is class 601 carbon steel piping. The corresponding maximum de-sign operating pressure is 1305 psig at a maximum temperature of 450*
F.
The licensee identified that, during feed system startup, the feed-water pump discharge pressure reaches 1500 psig.
The PORC reviewed engineering evaluations of the potential problem.
It was noted that the plant design code (ASME B31.1, 1955) allows for variations from normal operating pressures and indicates that piping systems are safe for oc-casional operatiori greater than design pressure.
115 percent of design pressure is allowed for operating conditions occurring during 10 percent of the operating period, and 120 percent of design pressure is allowed for conditions occurring during one percent of the operating period.
Since 1500 psig is approximately 11 percent above the 1305 psig design pressure, and since this condition occurs during only a small fraction of the system operating period, the PORC concluded that the feedwater system is adequately designed.
The meeting was characterized by frank discussions and questioning of the potential prob 1 cms.
Items for which additional information was required were postponed to allow committee members time to obtain and review the necessary information.
The in-spector had no further comments.
2.2 Demineralized Water Storage Tank Design Error On October 8, 1986, the licensee notified the inspector that a risk assessment evaluation of an ongoing modification to the demineralized water storage tank (DWST) revealed that the potential common mode failure susceptibility of the new DWST design would increase the plant core melt risk.
The DWST modification would maintain a nitrogen gas blanket on top of the water stored in this tank to maintain the de-aerated quality of the water.
The water is used for secondary system makeup and for the water supply to the auxiliary feedwater (AFW) system.
The eight-inch gooseneck vent on the DWST was to be replaced by two redundant breather valves for tank over pressure and vacuum protection.
The increased risk resulted from the increased probability of loss of the DWST as a water supply for AFW during an accident.
Although the redundant full capacity l
breather valves should provide adequate overpressure and vacuum protec-tion, the risk of their common mode failure based on the frequent cycling of the system was found unacceptable.
The DWST modifications had been approved and in progress since early 1986, however, the new system had not been placed in service because of problems in the nitrogen gas system.
During this period the DWST remained vented through a drained eight inch loop seal which had been attached to the original gooseneck vent.
Upon identification of this problem, the licensee issued a stop work order on the DWST modifications and verified that the loop seal drain remained tagged open to assure the DWST is adequately vented.
Since the DWST has been vented continuously, the operability of AFW was not affected.
The inspector discussed the following two aspects of this occurrence with licensee management.
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l a)
The licensee's commitment to risk assessment has shown positive results regarding maintenance of plant safety.
Continued licensee support for upgrading of plant risk evaluations is reflective of the licensee's overall commitment to nuclear safety.
b)
The replacement of the passive gooseneck vent on the DWST with ac-tive breather valves requires redundant, reliable active compon-ents and support systems in order to conclude that no new accident or malfunction is created by the new design.
In this case, the modification safety evaluation written pursuant to 10 CFR 50.59 relied upon a single non-safety grade heat trace system to prevent common mode freezing of both breather valves, and the continued reliability of these valves would have been untested since no sur-veillance of valve operability was specified in the design.
The inspector stated that, within the context of 10 CFR 50.59, this DWST modification would constitute an unreviewed safety question unless these two weaknesses are corrected.
The licensee indicated that a new safety evaluation would be written prior to any further im-plementation of this design.
Licensee identification of this prob-lem through risk assessment reflects a cafety benefit from the lic-ensee's initiative in applying risk assessment technology.
On the other hand, the circumstances also point out a weakness in the effectiveness of the licensee's design change review and approval process.
The inspector will review the results of licensee follow-up on this event during additional NRC review of previous design change problems (UNR 213/85-15-02).
I 3.
Observation of Maintenance and Surveillance Testing The inspector observed various maintenance and problem investigation activi-ties for compliance with requirements and applicable codes and standards, QA/QC involvement, safety tags, equipment alignment and use of jumpers, per-sonnel qualifications, radiological controls, fire protection, retest, and reportability.
Also, the inspector witnessed selected surveillance tests to determine whether properly approved procedures were in use, test instrumenta-tion was properly calibrated and used, technical specifications were satis-fied, testing was performed by qualified personnel, procedure details were adequate, and test results satisfied acceptance criteria or were properly dispositioned.
The following activities were reviewed:
Hot Functional Test (SUR 5.1-4)
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Auxiliary Feed Pump Monthly Functional Test (SUR 5.1-13)
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Inservice Inspection Pump Surveillance (SUR 5.7-19)
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Inservice Inspection of Power-Operated Relief Valves (SUR 5.7-88)
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Leak Sealing Reinjection (CMP 8.5-150)
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Replacement of Check Valve CC-CV-885 (Work Order 86-06479)
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3.1 Violation Involving Improperly Positioned Valves On November 3,1986, while reviewing the results of the core cooling system monthly surveillance test (SUR 5.1-4, Hot Operational Test) con-ducted on October 2, 1986, the inspector noted that the same operator performed both the final valve lineup check and the second operator valve check.
Further review of procedure SUR 5.1-4 indicated that the in-structions were misleading.
The prerequisites section of SUR 5.1-4 instructs the operator to complete an initial pretest valve lineup check.
When the procedure is completed, the operator is instructed to complete
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a final valve lineup check.
Selected valves require independent verifi-cation of their position using a second operator valve check list.
When the operator is instructed to complete this second operator valve check list, the procedure notes that it is to be performed by an operator who did not perform the initial valve lineup check.
The intent of the note is to assure that the final and second valve check lists are performed by different operators.
In this case, the operator reasoned that, since he had not conducted the initial pretest lineup, he could perform the second valve lineup check.
The inspector reviewed additional completed packages of SUR 5.1-4.
In those cases, proper independent operator valve position verifications were conducted.
Upon notification of this problem, the licensee implemented Temporary Procedure Change (TPC) No.86-528 to procedure SUR 5.1-4 to clarify the instructions for second operator verification.
The licensee also reviewed other applicable procedures for similar problems.
No other deficiencies were identified.
On November 4,1986, an NRC Examiner noted an open chain and padlock hanging from a manual valve (SI-V-865) in the primary auxiliary building.
NRC follow-up found SI-V-865 was open.
The licensee was informed of this finding and the valve was promptly closed.
SI-V-865 is the high pressure safety injection (HPSI) combined loop recirculation stop valve.
Four separate HPSI loop recirculation lines join in a common single header on which the combined loop recirculation stop valve is loc.ated.
The valve is downstream of the outermost containment isolation valve for each of the HPSI system loop recirculation lines.
These upstream containment isolation valves are locked closed using chain and padlocks in accordance with the plant Locked Valve Checklist (SUR 5. b 126).
Because its post-tion is not critical during normal operations, SI-V-865 is not on the Locked Valve Checklist.
This valve is locked closed during cold shutdown conditions, and normally remains closed with the lock in place during most plant operations.
SUR 5.1-4 direros the operators to open SI-V-865 to perform a portion of that surveill ace test.
Following the completion of that portion of the test, the va Ne should be reclosed.
The initial, final and independent valve lineups in SUR 5.1-4 close SI-V-865 or verify that SI-V-865 is closed.
The ins';ector questioned whether the valve may have been reopened since the last performance of SUR 5.1-4 on October 2, 1986.
No other manipulations of SI-V-865 could be identified.
Therefore, it was concluded that the valve had not been reclosed when
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procedure SUR 5.1-4 was completed on October 2, 1986.
The licensee interviewed the operator who performed both the final and second operator verifications for the October 2 test..The operator stated that the valve was checked and thought to be closed based upon encountering resistance to his attempts to turn the handwheel.
The licensee counselled this operator on the importance of carefully checking valve position.
Addi-tionally, a training request was submitted to enhance operator training by including lessons on the purpose of independent verification and the proper method for its conduct.
Technical Specification (TS) 6.8 requires that written procedures be established, implemented and maintained.
The failure to close and verify the closed position of valve SI-V-865 violates TS 6.8 and procedure SUR 5.1-4.
Based on the licensee corrective actions noted above, the in-spector concluded that no further actions are necessary in this area.
The implementation and effectiveness of these corrective actions will be reviewed in a subsequent inspection (VIO 213/86-27-01).
3.2 Violation Involving Gauge Calibration On November 5, 1986, during observation of the Auxiliary Feed Pump Monthly functional Test (SUR 5.1-13) and Inservice Inspection Pump Sur-veillance Test (SUR 5.7-19), the inspector noted that the auxiliary feedwar.er (AFW) pumps' suction and discharge pressure gauges were overdue i
for their quarterly calibration.
The quarterly calibration schedule is consistent with the Inservice Testing (IST) Program.
The latest cali-bration of the four gauges was performed on May 12, 1986, and the cali-bration due date was August 12, 1986.
SUR 5.7-19 requires that all as-scciated pressure gauges be calibrated quarterly, and the calibration data sheets are to be attached to the procedure. The quarterly calibra-tion requirement is intended to ensure that the calibration is performed prior to the surveillance test to prevent invalidation of the test be-cause. the data was taken with out-of-calibration gauges.
The calibration requirements of SUR 5.7-19 are implemented through the performance of procedure PMP 9.2-19, Calibration of ISI Gauges.
The Instrument and Controls (I&C) Department is responsible for this calibration, which is scheduled quarterly by the Production Maintenance Management System (PMMS) data base.
PHP 9.2-19 is normally performed approximately two weeks prior to SUR 5.7-19.
However, PHP 9.2-19 had not been performed on AFW pressure gauges since May 12, 1986.
The last two SUR 5.7-19 quarterly tests were completed on August 5 and November 5, 1986.
The August 5 surveillance test was within the quarterly calibration require-ment by seven days (May 12 to August 5).
However, the use of the May 12 calibration data for the August 1986 surveillance test compromised the intent of the control of measuring and test equipment program.
The November 5 surveillance test was performed with AFW pressure gauges that had not been calibrated since May 12, 1986.
Additionally, the latest l
calibration sheets for the AFW pressure gauges were not attached to
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either the August 5 or November 5 procedures, as required by procedure SUR 5.7-19.
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Upon inspector identification of these problems, the IST Engineering group initiated a nonconformance report, documenting the discrepancies.
The I&C Department performed the required calibrations on November 13, 1986, and the data sheets were attached to the appropriate procedures.
The pressure gauges were found to be within specification.
Additionally, the IST Engineering Department committed to initiate procedure changes to include appropriate references, instructions and procedure check-offs to assure that PMP 9.2-19 is performed prior to the performance of SUR 5.7-19 and that the pressure gauge calibration data sheets are attached to the procedure.
IST Engineering also committed to review other applic-able surveillance procedures for similar deficiencies.
Failure to follow procedure SUR 5.7-19 violates Technical Specification 6.8.
Based on the licensee's corrective actions noted above, the inspector determined that no further action is necessary at this time.
The implementation of these actions will be reviewed in a subsequent inspection (VIO 213/86-27-02).
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3. 3 Violation Involving Leak Rate Testing After Valve Replacement On May 2, 1986, the licensee replaced the containment isolation check valve (CC-CV-885) in the component cooling water supply to the neutron i
shield tank (NST) cooler.
The valve is located inside containment on
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this non-safety-related piping system.
It is the only containment isolation valve for this penetration and had failed several local leak
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rate tests.
The inspector reviewed the work package (CY 86-06479) for this job.
Several discrepancies were identified.
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a)
The work scope identified in the work order included the replacement of check valve CC-CV-885.
The actual work performed included re-j moval of about two feet of piping within the containment penetration j
boundary.
This pipe section included two check valves and was re-
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placed by a single check valve and a pipe coupling.
b)
The work package included no quality assurance material control documentation (MIS form) for the newly installed check valve, c)
The work package did not require an adequate retest of three new welds inside the containment penetration boundary.
No 10 CFR 50 Appendix J leak rate test was performed on this new pipe section.
i The inspector met with licensee representatives on November 3, 1986 to l
discuss these problems.
The following information was received, a)
There were two check valves in this line because a previous, un-
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approved modification had been performed, adding the second check valve to the line because structural interference with the first leaking check valve precluded maintenance of that valve.
The lic-ensee could not determine when the modification occurred.
Since all work packages after 1978 have been reviewed by the licensee for unapproved modifications, it was concluded that this arrangement has existed for several years.
One other containment penetration
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for the NST fill piping is known to be similarly altered.
This line, however, has a norrrally closed manual containment isolation valve outside containment.
The work scope actually performed on CC-CV-885 returned the system to the original design condition.
The licensee issued a non-conformance report (NCR 86-449) for the NST fill pene-tration.
An engineering evaluation concluded that the system design criteria had not been compromised by these modifications.
The lic-L ensee has implemented a supplemental work order review check list designed to improve documentation of replacement and repair work order reviews and prevent unapproved modifications in the future.
This area will be reviewed during supplementary NRC followup on licensee implementation of design change program improvements re-sponding to a December 1984 NRC Order.
b)
Quality Assurance documentation for the new check valve CC-CV-885 was located with a separate work order used to bench test the new valve.
This information was duplicated in work package CY 86-06479.
This inspector had no further questions on this item.
c)
No leak rate test was performed on three of four new welds in this containment penetration because the licensee had not identified the extent to which the containment boundary had been affected.
The local leak rate test, which was specified and conducted satisfac-torily, tested only one of the four new welds installed.
However, i
the licensee noted that, since normal component cooling system pres-sure exceeds containment design pressure (40 psig) and no evidence of leakage at these joints has been noted, there is adequate evi-dence of satisfactory leak tightness of these joints.
On November l
13, 1986, a visual inspection of these joints under normal system l
pressure identified no leakage.
The licensee's failure to perform post-maintenance leak rate testing of three out of four containment
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boundary welds violates 10 CFR 50 Appendix J.
The licensee stated
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that the recently implemented replacement and repair work order review check list provides for inter-disciplinary reviews of this type of job and should prevent recurrence of this problem.
The inspector concluded that, based on the satisfactory operational leak check of the N R tooling supply line and the implementation of the replacement anc repair work order review checklist, no further cor-rective actions are required at this time.
Effectiveness of the licensee's corrective actions will be assessed incident to follow up NRC review of this violation (VIO 213/86-27-03).
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Followup on Previous Inspection Findings i
During the inspection, four NRC open items were reviewed.
The inspector found licensee actions on two of these to be sufficient to close the items.
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4.1 (Closed) Violation (213/85-21-03) NRC cited procedural non-compliances by different licensee organizations and asked the licensee to address programmatic and quality assurance aspects of these occurrences.
The licensee acknowledged the procedure compliance problems in his written response dated February 28, 1986.
The licensee committed to improve procedure compliance through enhanced personnel awareness of the import-ance of following procedures and reemphasis to supervisors of the dis-ciplinary policies regarding procedural non-compliance.
The licensee also noted that the site quality assurance organization has increased its effort to monitor continued procedural compliance.
The inspector verified licensee actions to periodically reemphasize procedural com-pliance by regular distribution of policy memoranda and management direction to apply appropriate disciplinary action as necessary. Inspec-tor discussions with licensee personnel have indicated a renewed sensi-tivity to procedural compliance.
Also, an increased number of temporary procedure changes have been generated to resolve procedure inadequacies.
In addition, the inspector reviewed the implementation of the quality assurance activities surveillance program.
The level of effort in this area was expanded during 1986 and the pre planning of surveillance acti-vities was formalized.
The inspector noted the positive contribution of this program to the overall assurance of quality on site.
This item is closed.
4.2 (Closed) Unresolved Item (213/86-06-01) Certain containment boundary isolation valves failed several previous leak rate tests.
Supplemental tests of these valves in July 1986 were successful.
The licensee revised Licensee Event Report (LER) 86-06 to include the results of the current test data.
A follow-on test has been scheduled for the next cold shut-down period.
This test will be reviewed during routine NRC inspections.
The inspector also reviewed the licensee guidance on event reportability contained in station policy CYSP-75.
The inspector noted that further NRC guidance comparing the reporting requirements of 10 CFR 50.72 and 50.73 is included in NUREG 1022, Supplement 1, LER System.
The licensee is evaluating the merit of incorporating this guidance in station docu-ments.
This item is closed.
4.3 (0 pen) Violation (213/86-20-03) The licensee reported a technical viola-tion of containment integrity which resulted from opening manual con-tainment isolation valves during routine operational evolutions.
The licensee was cited for the violation because the corrective actions re-sulting from two similar NRC identified occurrences should have prevented this problem.
On October 14, 1986, the licensee responded to the viola-tion.
The licensee referred to the Final Description and Safety Analysis (FDSA) document addressal of the cited operational evolutions as justi-fication for not meeting the more conservative containment integrity requirements cited in the Technical Specifications.
During a discussion of this issue between NRC and licensee management on October 30, 1986, NRC emphasized that when discrepancies exist between license documents
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the appropriate action is compliance with the most conservative require-t l
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ment plus prompt NRC notification and submittal of proposed licease changes to ectify the discrepancy.
The NRC also noted that FDSA de-scriptions do not supersede current TS requirements.
In response, the licensee conducted a more comprehensive review of manual containment boundary valves.
That review identified other containment isolation valves which may need to be opened during plant operation.
On October 2,.1986, the Operations Department Head notified the Opera-tions Shift Supervisors in writing that, in order to maintain compliance with the containment integrity TS (3.11), valves SS-V-971-A & B (RHR sample line), SS-V-999-A (neutron shield tank (NST) sample line), CC-V-884 (NST fill line) and WG-V-984-A (pressure relief tank vent sample line) should not be opened until further notice.
By letter to NRC Region I dated October 24, 1986, the licensee described the result of their manual containment isolation valve review and an October 8, 1986 incident in which manual containment isolation valve CC-V-884 was opened to fill the neutron shield tank (NST).
The licensee stated the position that certain valves need to be operated during power operation and present little safety significance when operated for short periods under administrative control.
The licensee also stated that three valves would continue to be opened as necessary pending licensee submittal and NRC approval of appropriate TS changes.
Further, the licensee stated that no Licensee Event Reports would be submitted for these technical violations of TS 3.11 because, in their view, the intent of the TS was being maintained.
The inspector discussed these matters with Region I managers and the NRC Licensing Project Manager.
It was concluded that, although the manipulation of these manual containment isolation valves appears justifiable from a safety viewpoint, that does i
not justify exceeding Technical Specification requirements in a non-emergency situation.
Licensee submittal of proposed TS changes and NRC granting of a waiver / relief from compliance, if necessary for interim use of these valves, was judged to be the appropriate method to address this problem.
This is the method used in response to the previous vio-lation cited in NRC Inspection Report 50-213/86-20 involving safety in-jection recirculation line isolation valves.
The inspector presented the NRC position to the Station Superintendent on November 10, 1986.
Since the licensee had already removed the operator prohibition oa open-ing manual containment isolation valves based on their October 24 letter, the inspector cautioned that further restrictions on these operations were appropriate until NRC concurs in a waiver / relief from compliance.
On November 10, 1986, the licensee re-implemented the guidance to shift operators prohibiting the opening of manual containment isolation valves.
With regard to the licensee identified opening of CC-V-884 on October 8, 1986, the inspector noted that corrective actions resulting from the previous violation cited had identified this manipulation as an activity prohibited by TS 3.11.
This information was disseminated to all shift supervisors six days prior to the event, however, all operators had not
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been made aware of this guidance prior to opening CC-V-884 to fill the NST. When the shift supervisor was appraised of the neutron shield tank fill, he recognized the problem and notified plant management.
NRC was notified of the occurrence by the Emergency Notification System on Octo-ber 9 and by licensee letter on October 24, 1986.
Since the corrective actions in progress for the July 1986 violation should have prevented this occurrence, this item is considered a repetitive violation of TS , 3.11.
(VIO 213/86-27-04)
The inspector also noted that 10 CFR 50.73 requires an LER to be sub-mitted for each condition / operation prohibited by TS.
Since no waiver was granted for opening valve CC-V-884 on October 8, 1986, a condition prohibited by TS existed as reported on October 9 and an LER is required.
The inspector determined that, based on the submittal of the licensee's October 24, 1986 letter describing the October 8 event, this item would remain unresolved pending licensee submittal of an LER (UNR 213/86-27-05).
4.4 (0 pen) Unresolved Item (213/86-24-01) Licensee identified discrepancies in the fire rating of the computer room / control room wr.11 resulte:d in implementation of a roving fire patrol pending resolution of the dis-crepancies. On September 30, 1986, the licensee identified that the fire watch had been removed on September 26.
The one-hour rodng fire patrol was promptly reinitiated and the occurrence was documented in Plant In-formation Report (PIR)86-185.
The inspector verified that, although
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the degraded fire barrier was not specifically inspected during the
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period September 26-30, 1986, the control room was continuously manned
and the wall could oe observed during routine operator rounds behind the main control board.
In addition, fire detection systems remained opor-able on both sides of the wall throughout this period. The licensee was unable to identify the individual who directed removal of the committed fire watch.
The inspector reconfirmed with the station superintendent the licensee's commitment to maintain the roving fire watch in place until the computer room wall discrepancies are resolved.
The inspector i
also noted that the computer room wall was incorporated in the plant design basis by a licensee condition in Amendment 28 to the Operating Licensea dated October 3, 1978.
However, the licensee's position re-mained that the computer room wall was not a fire barrier subject to the requirements of Technical Specification 3.22.F from which the one-hour roving patrol requirement was derived.
The inspector confirmed, with
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the NRC Licensing Project Manager, the NRC's position that the control room to computer room wall must be a one-hour fire barrier and is subject to TS 3.22.F.
This position is significant because the failure to treat this fire barrier as a TS 3.22.F barrier reduced the emphasis on the importance of this barrier and may have contributed to the removal of the fire watch on September 26.
Further, if the required action of TS 3.22 F were not applicable to the computer room wall, then the degrada-tion of this wall would represent plant operation outside the license condition defined in Amendment 28.
The inspector discussed this issue with licensee management and with NRC Licensing.
It was determined that.
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based on the licensee's maintenance of the one-hour roving fire patrol and the continued operability of fire detection systems on both sides of the computer room wall, this item will remain unresolved pending timely disposition of the material and regulatory issues related to the computer room wall.
5.
Followup on IE Bulletins (IEBs), Information Notices (IENs), and Region I Guidance 5.1 Licensee actions on the following IEBs and IENs were reviewed for licen-see review for applicability, response timeliness, response appropriate-ness, response accuracy, corrective action commitments, and corrective action completion.
a.
IEB 79-11, DB-50 and D8-75 Circuit Breaker Overcurrent Trips This bulletin addressed Westinghouse Type DB-50 and 08-75 circuit breaker delay dashpots defects which result in a reduced time delay for overcurrent protection.
The July 6 and August 8, 1979 licensee responses document the testing of all overcurrent trip devices on 08-50 and DB-75 breakers, the revision of test procedures to incor-porate new manufacturer recommended acceptance criteria, and the finding that no cracked or defective end caps were found.
The in-spector found that all DB breakers using an electro-mechanical tripping device (about 50 plus those in spare parts) were converted to a solid stste tripping device in 1984.
This work was engineered under plant design change request (PDCR) No. 616 and completed under work order 84-05886 in August, 1984.
The inspector also reviewed Preventive Maintenance Procedures (PHP) 9.5-37 and 9.5-38 for DB-50 and 08-75, respectively.
A sample of PHP 9.5-37/38 maintenance conducted during the last outage was also reviewed.
No discrepan-cies were identified.
The inspector had no further questions on this issue.
b.
IEB 79-13, Feedwater Pipe Cracking This bulletin summarizes industry experience with feedwater piping weld failures and specified the required inspections to be performed.
The licensee performed inspections of the steam generator feedwater nozzle to elbow welds and the feedwater system piping supports and snubbers inside containment in the fall of 1979.
By letter dated November 5, 1979, the licensee provided the Haddam Neck inspection data, the analyses of this data, and the conclusion that no cracking similar to that observed at other facilities was detected at Haddam Neck.
An NRC Generic Safety Analysis of this issue, dated January 4, 1980, concluded that nondestructive and visual inspections per-formed by the licensees and the inherent toughness of the piping materials are adequate to ensure that the feedwater piping integrity will be maintained.
The inspector questioned the licensee regarding l
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any past waterhammer events and any cases of feedwater piping leak-age.
No such events have occurred at Haddam Neck since issuance of Bulletin 79-13.
The inspector had no further questions.
c.
IEB 79-17, Pipe Cracks in Stagnant Borated Systems This bulletin concerns cracking in safety related stainless steel piping systems in portions of systems which contain oxygenated, stagnant or essentially stagnant borated water.
One of the events of concern occurred at Haddam Neck on April 13, 1977.
This event was reported to the NRC by licensee letters (LER 77-4) dated April 14 and 21, 1977 and March 26, 1979.
The licensee's August 24, 1979 response to this bulletin addresses inservice inspection (ISI) pro-gram hydrostatic tests, visual and volumetric examinations, water chemistry control including periodic flushing to maintain required water chemistry, pre-service weld nondestructive examination (NDE),
and the history of previously experienced cracking.
The inspector reviewed the results of the first 10 year ISI program testing per-formed during the 1980 refueling outage.
No leakage was found in the subject piping systems.
A generic NRC review of IEB 79-17 (NRC memo dated April 1, 1981) states that no further evidence of stress corrosion cracking problems beyond those previously identified was observed in pressurized water reactor plants.
During NRC review of the cheinistry control program that provides justification for reduced NDE, the inspector noted a reduction in the scope of the committed program.
The licensee's August 24, 1979 bulletin response encloses procedure SUR 5.4-26, Inservice Inspec-tion Chemical Sampling Program, specifying 15 sample points and eight cation analyses in addition to a chloride analysis.
The cur-rent Inservice Inspection Water Chemistry Program under Preventive Maintenance Procedure (PHP) 9.7-11 became effective on February 26, 1986, and specifies nine sample points and no cation analyses.
In addition, PMP 9.7-11 references IE Circular NO. 76-06 (same general subject) but does not reference IEB 79-17.
The licensee produced a March 8, 1982 internal analysis of the Inservice Inspection Water Chemistry Program, justifying the * eduction of sample points and the elimination of cation analyses.
The reduction to nine sample points results from eliminating redundant sample points and a find-ing that one line is not stagnant.
Although the inspector had no disagreement with the above described reduction in the chemical sampling program, he questioned the licensee's commitment tracking system that failed to detect reductions in plant programs committed to in NRC correspondence.
The licensee stated that the current commitment tracking system is greatly improved over the system in effect in 1982.
This issue will continue to be addressed during routine NRC inspections.
The licensee initiated a temporary change to include the IEB 79-17 reference in PMP 9.7-11.
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d.
IEB 79-18, Audibility of Alarms and Evacuation Announcements This bulletin concerns a condition where the evacuation announcement, made over the public address (PA) system, was not heard by personnel in high-noise areas.
Licensees were asked to determine whether current alarm systems and evacuation announcement systems are clearly audible or visible throughout all plant areas, with emphasis on high-noise areas.
The licensee's September 21, 1979 response provides the corrective actions to be taken including contracting an outside consultant for a system review.
The inspector reviewed internal licensee correspondence showing the following.
1)
Problems with hearing the paging system in some plant locations was identified by the licensee two months prior to issuance of the bulletin.
2)
All bulletin corrective actions for accessible areas were not completed within 120 days of the date of this bulletin.
3)
The outside consultant (Gaf-Tronics Corporation) report re-garding this bulletin was not received until December 27, 1982.
4)
Minor paging equipment adjustments were performed during the fall of 1979 and during subsequent years.
5)
In 1983, INPO found that the plant paging system could not be understood or heard in some areas of the plant.
6)
In response to the INPO finding, a Construction Program Speci-fic Project was initiated in August 1983 but was not approved due to budget /high cost.
7)
In October 1985, an alternate plan was deferred from the 1986 refueling outage due to high containment work load.
8)
Equipment needed for the paging system upgrade is now available and the work is to begin early in 1987.
Containment work is to be completed during the outage scheduled to start in July 1987.
The licensee's action on this bulletin has not been responsive.
Seven years have passed since issuance of the bulletin and the paging i
system remains inaudible in several plant locations.
This bulletin remains open pending licensee submittal of written schedular com-mitments for implementation of appropriate paging system modifica-tions, and pending timely licensee completion of these commitments.
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IEB 79-21, Temperature Effects on Level Indication This issue concerns the effect of increased containment temperature on the reference leg water column and the resultant effect on the indicated steam generator (SG) water level.
The licensee's response, dated September 17, 1979, provides information on the narrow and wide range level instrumentation.
The inspector reviewed the licensee's response and the emergency response procedures, and talked to instrumentation and operations personnel.
The narrow range low level trip setpoint of 10% would effectively be reduced to 4% if the containment temperature in-
creased to 200 F following a steam release accident.
This includes
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a 4% reduction due to the containment temperature increase and a 2% reduction for instrument error.
The narrow range instrumentation system is not environmentally qualified and its availability after l
an accident is not taken credit for.
(The wide range steam genera-
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tor level system is environmentally qualified.) For a high energy
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line break, the reactor trip is actuated before the adverse environ-
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ment occurs, and is backed up by a high containment pressure trip.
i The new symptom oriented emergency operating procedures include SG level and pressurizer level and pressure corrections for an adverse containment environment.
The inspector had no further questions, f.
IEB 79-23. Emergency Diesel Generator Excitation Transformers This bulletin concerns the possibility of circulating currents in l
an emergency diesel generator exciter transformer due to a direct
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connection between the generator and control power transformer neutrals, or due to common grounding.
The licensee's response, dated November 1, 1979, states that this configuration was altered
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in 1974 by removing the grounding connection from the excitation
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transformers and from the control transformers on the 4 Kv windings.
The high side of the transformers is now an ungrounded wye con-figuration.
The inspector verified the completion of the 1974
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modifications under PDCR-176.
In addition, the control room indi-cated voltage and amperage readings with the EDG fully loaded were
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verified to be as stated in the licensee's response.
The inspector l
had no further questions on this issue.
g.
IEB 86-08 Containment Liner Penetration Weld Examination l
This bulletin addressed nondestructive examination (NDE) performed
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on containment penetration welds at a plant under construction.
The NDE did not satisfy ASME Boiler and Pressure Vessel (B&PV) Code requirements.
The welds in question were the primary piping con-tainment penetration flued head (integral fitting) to outer sleeve welds which form a part of the containment pressure boundary.
The June 19, 1980 licensee response to this bulletin provided identifi-cation of shop and field welds that were randomly radiographed in l
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accordance with Paragraph UW-52 of the ASME B&PV Code,Section VIII.
The inspector confirmed that the testing reported in the licensees response was completed during construction of the plant.
No in-spections have been performed on the containment liner penetration welds since that time.
No other supporting data was available for review.
This bulletin will be evaluated further during a subsequent inspection.
h.
IEB 85-02, D8-50 Circuit Breaker Undervoltage Trips The bulletin directed licensees of Westinghouse plants that had not incorporated automatic shunt trips in the reactor trip breakers to accelerate that modification and report their current status.
Since Haddam Neck has always had both shunt and undervoltage trips on the reactor trip breakers, this bulletin was not applicable to this facility.
This item is closed.
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IEB 86-02, Static "0" Ring Differential Pressure Switches The bulletin requested that licensces submit a report containing information concerning Model 102 or 103 differential pressure switches manufactured by SOR (Static "0" Ring).
The licensee re-sponded to the bulletin stating that SOR Model 102 or 103 differen-tial switches were not installed at the Haddam Neck Plant and that no further action was required.
The inspector reviewed the Produc-tion Maintenance Management System (PMMS) data base to verify the licensee's submittal.
No discrepancies were observed.
The inspec-tor had no further questions in this area.
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IEN 86-73, Emergency Diesel Generator Problems This 1E Notice notified licensees of potential problems in Emergency Diesel Generator (EDG) systems.
In particular, the starting circuit design on some General Motors EDGs precludes flashing the generator field if an emergency start signal is received dt. ring the engine cooldown cycle of operation. With no field flash, the EDG may not assume emergency electrical loads as required.
The inspector veri-fled, through checks with licensee maintenance pcrsonnel and refer-ence to the EDG technical manual, that the gene"ator field will be flashed on each emergency start.
The inspector tao no further
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questions in this area.
5.2 GE Type AK-F-2-25 Circuit Breaker Inspection Recent failures of General Electric (GE) type AK-F-2-25 breakers prompted
NRC Region I to provide inspection guidance to resident inspectors for reviewing the failure history of these breakers at their assigned plants.
The inspector reviewed the potential for similar problems at Haddam Neck and determined that GE type AK-F-2-25 breakers are not used at this plant.
The inspector had no further questions.
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5.3 Standby Gas Treatment System Single Failure
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Recent problems identified in nuclear plant standby gas treatment systems (SGTS) prompted NRC review of the SGTS at Region I plants.
In particular, single component failures have been identified at some plants which would render the SGTS inoperable.
The inspector reviewed the potential for a similar problem in accident gas treatment systems at Haddam Neck.
There is no SGTS at Haddam Neck.
Post-accident containment gases would be vented through non-safety grade ventilation systems.
The inspector determined that this concern was not applicable to this facility.
6.
Followup on Events Occurring During the Inspection 6.1 PORV Setpoint In July 1986, the licensee identified a problem with the reactor coolant system power operated relief valve (PORV) setpoint of ?270 psig.
Due to previous PORV modifications, it was recognized that the PORV setpoints needed to be raised.
The licensee postponed the PORV setpoint change so that an adequate review and approval of the change could be conducted after plant startup.
A Justification for Continued Operation (JCO) was approved by the Plant Operations Review Committee (PORC) and discussed with NRC.
The JC0 was approved provided that the reactor core moderator temperature coefficient (MTC) remained below specified negative values and the PORV block valves remained closed (in standby for auto-actuation).
The PORV setpoint change was planned to be performed approximately two weeks following plant startup, however, several problems have delayed the change.
The PORV block valves are scheduled to be stroke tested quarterly, and were due for testing on October 26, 1986.
Since the JC0 did not address opening the PORV block valves for testing, and the setpoint change had not yet been implemented, the JC0 required revision.
The revised JC0 addressed the opening of the PORV block valves for small time intervals to allow for stroke testing.
This revision was also reviewed and ap-proved by PORC.
The inspector observed the PORV stroke test SUR 5.7-88, Inservice Inspection of PORV Block Valves.
No discrepancies were noted.
The implementation of the setpoint change will be reviewed through the routine resident inspection program.
6.2 Potential Strike On October 10, 1986, the inspector received a letter from the United Plant Guard Workers of America (UPGWA) representing contractor security guards at the site.
The letter stated that a vote on a final contract offer by the licensee's security force contractor would be conducted on October 26, 1986, and that a rejection by union members could result in a work stoppage (strike) at 1:00 a.m. on October 27, 1986.
The licensee also received a copy of this letter.
The inspector verified that the licensee had taken appropriate measures to assure that, should a strike
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take place, no degradation of plant security would occur.
These prepara-tions included designation of watch schedules, verification of training and qualification, and prepositioning of replacement guards to facilitate watch turnover.
The inspector found no discrepancies in the licensee's contingency plans.
On October 26, 1986, the UPGWA decided not to take the proposed contract to a vote and scheduled new negotiations to begin early in 1987.
Based on the union's certification that no labor action would be initiated without 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> notice, the licensee removed the contingency plans on October 27.
The inspector had no further questions in this area.
6.3 Unlocked Isolation Valve On October 16, 1986 the licensee discovered that safety injection valve MOV-24 was not locked open as required by Technical Specification (TS) 3.6, Core Cooling.
MOV-24 is the single isolation valve between the refueling water storage tank (RWST) and the suction side of the high pressure safety injection (HPSI) pumps.
TS 3.6 requires M0V-24 be locked in the open position, with the circuit breaker locked out whenever the reactor is critical.
This provides assurance that a hot short condition in the valve operator will not compromise HPSI flow.
The lock for MOV-24 was found opened and the locking chain was lying over the top of the valve (not through the handwheel).
The valve was open and its breaker remained locked open.
The licensee's immediate corrective action was to verify that the valve was open and properly lock the valve.
Several auxiliary operators (A0s) were questioned about the lock for MOV-24.
The A0s stated that the lock was very hard to close and could have dropped open if it had not been properly latched.
Additional checks were performed on all other TS locked valves.
No additional discrepancies were identified.
The licensee also performed selected checks on various valves from the Locked Valve Checklist (Surveillance Procedure SUR 5.1-126).
During these checks, some discrepancies were noted with the locks and/or valve handwheels, however, the valves were found in their proper positions.
Corrective actions were initiated and completed.
MOV-24 is unlocked and cycled monthly during surveillance test SUR 5.1-4, Hot Operational Test.
There is a double operator verification on the step which directs the operator to relock the valve open.
SUR 5.1-4 was last performed on October 2, 1986.
Also, M0V-24 is verified open each shift by the auxiliary operator (A0).
Hcwever, when questioned, the A0s could not recall whether the chain and lock were in place during these checks.
The failure to maintain MOV-24 locked closed constitutes a licensee identified violation of TS 3.6.
Subsequent additional licensee actions included 1) issuing instructions to operators to emphasize the importance of insuring that locks and chains are intact on locked com-ponents; 2) filing a training request to add locked valve training to
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operator training programs; and 3) changing procedure SUR 5.1-126 to l
address the proper method for verifying locked component status.
After consultation with NRC Region I, the inspector determined that this un-locked valve would be considered a licensee identified violation for l
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which adequate corrective actions have been taken.
The safety signifi-cance is minor because no equipment was mispositioned.
Implementation of licensee corrective action will be reviewed in a subsequent inspection (VIO 213/86-27-06).
6.4 Security Access Control Degradation On October 16, 1986, the licensee reported to NRC a moderate loss of security access control for which immediate compensatory measures had been implemented.
During a review of NRC Information Notice No. 86-83, Underground Pathways Into Protected Areas, Vital Areas, Material Access Areas, and Controlled Access Areas, the licensee's security organization identified a potential unmonitored access point between a protected and vital area inside the plant radiological controlled area.
Access through this pathway was controlled by the licensee's locked high radiation area program and would require traversing a constricted and highly contaminated area.
No record of actual access via this pathway was identified.
The licensee implemented immediate corrective actions to compensate for this pathway and the event was promptly reported to NRC.
Subsequently, the licensee secured access to this pathway and rescinded the compensatory measures.
The resident inspector verified the adequacy of the licensee's actions.
No further problems were noted.
Because there were locks on this potential access, the significance of this problem was minor.
After consultation with NRC Region I security specialists, the inspector de-termined that the existence of this problem would be considered a licen-see identified violation for which adequate corrective actions have been taken and no further action is necessary.
6.5 Fires in Radiological Controlled Area On October 22, 1986, there was a small grass fire within the radiological controlled area (RCA).
The fire started when work was being performed on the outside overhead yard crane. Workers were flame-cutting on the yard crane walkway when sparks dropped on the grass outside an inner RCA fence.
A fire watch was on the job site throughout the job as required.
The fire watch observed the sparks falling to the grass but could not see if a fire had started.
The fire watch subsequently determined from the workers above that a fire had started.
The fire was immediately reported to the control room, who called for the fire brigade.
The fire was extinguished by two fire brigade members who were in the area before the rest of the fire brigade reached the scene.
The shift supervisor ordered that the area be hosed down to prevent another fire.
On October 23, a similar fire occurred.
This fire was also promptly extinguished by plant personnel.
When the fire was extinguished, the Operations Shift Supervisor stopped work on the crane until provisions were established for periodic wetting of the area under the yard crane.
No additional problems were encountered during the remainder of the job.
The inspector had no further questions in this area.
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6.6 ENS Service Interruption On October 9, 1986, the licensee declared the emergency notification system (ENS) out of service.
The necessary notifications and subsequent daily phone checks to the NRC Operations Center were made via commercial telephone service.
The local telephone company was contacted to repair the ENS.
The ENS was returned to service on October 24, 1986.
The in-spector had no further questions.
7.
Instrumentation for Inadequate Core Cooling (ICC) NUREG 0737-II.F.2 On September 18, 1986, the licensee reported completion of the installation and testing of instrumentation systems required by licensee commitment to TMI Action Plan Item II.F.2.
The NRC asked what provisions the licensee had made for ongoing surveillance of this system and for administrative controls to assure continued operability of this equipment.
Such provisions were neces-sary to justify the licensee position that appropriate Technical Specification (TS) changes for this system would be submitted at a later date.
The inspec-tor identified that no surveillance or administrative control had been imple-mented except for routine plant logs.
During this review, the inspector also identified that the routine operator logs do not adequately document the per-formance of inter-channel comparisons for appropriate TS instrumentation.
Inspector discussions with licensed operators confirmed that those required TS channel checks are routinely performed.
The inspector discussed these problems with licensee management on November 3, 1986.
The licensee stated that control routing (CR) 86-1799 had been previously issued to address test-ing requirements for ICC instrumentation and that this CR would be amended to include administrative controls (ATS) for the system.
CR 86-1799 is scheduled to be completed December 1, 1986.
With regard to TS channel checks, the licensee committed to revise the guidance and documentation of qualitative channel checks by January 1987.
Further evaluation of quantitative acceptance criteria for some channel checks will also be performed.
The inspector will review the implementation of these actions in a subsequent inspection (UNR 213/86-27-07).
8.
Review of periodic and Special Reports Upon receipt, periodic and special reports submitted pursuant to Technical Specification 6.9 were reviewed.
This review assessed whether the reported information was valid and included the NRC required data; whether test results and supporting information were consistent with design predictions and per-formance specifications; and whether planned corrective actions were adequate for resolution of the problem.
The inspector also ascertained whether any reported information should be classified es an abnormal occurrence.
The following periodic reports were reviewed:
Monthly Operating Reports 86-09 and 10, plant operations from September
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No discrepancies were identified.
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9.
Unresolved Items Unresolved items are matters about which more information is required in order to determine whether they are acceptable. items or violations.
Unresolved items identified during this inspection are discussed in Paragraph 4.3, 4.4, and 7.
10.
Exit Interview During this inspection, meetings were~ held with plant management to discuss the findings.
No proprietary information related to this inspection was identified.