IR 05000220/1988019
| ML17055E392 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 12/15/1988 |
| From: | Jerrica Johnson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17055E391 | List: |
| References | |
| 50-220-88-19, 50-410-88-19, NUDOCS 8812270162 | |
| Download: ML17055E392 (44) | |
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
Docket No.
License No.
Licensee:
88-19/88-19 50-220/50-410 DPR-63/NPF-69 Niagara Mohawk Power Corporation 301 Plainfield Road Syracuse, New York 13212 Faci 1 ity:
Location:
Dates:
Inspectors:
Nine Mile Point, Units 1 and
Scriba, New York October 4, 1988 through November 17, 1988 W.A. Cook, Senior Resident Inspector W.L. Schmidt, Resident Inspector R.R.
Temps, Resident Inspect'or R.A. Plasse, Resident Inspector, FitzPatrick M. Banerjee, Project Engineer R.A. Laura, Reactor Engineer H. I. Gregg, Senior Reactor Engineer A.G. Krasopoulos, Reactor Engineer Approved by:
.R. Jo son, Chief, Reactor Projects Section 2C, DRP Date INSPECTION SUMMARY Areas
~Ins ected:
Routine inspection by the resident inspectors of station activities including Unit 1 and 2 operations, licensee action on previously identified items, plant tour s, safety system walkdowns, surveillance testing reviews, maintenance reviews, LER reviews, modification review, Part 21 Report re'view, allegation followup, and TI 2515/98 review.
This inspection involved 497 hours0.00575 days <br />0.138 hours <br />8.217593e-4 weeks <br />1.891085e-4 months <br /> by the inspectors which included 33 hours3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br /> of backshift inspection and weekend inspection coverage.
Results:
A concern regarding monitoring capability for the 115 KV offsite power sources is described in section 1. l.b.
Several examples of personnel errors and procedure adherence issues are discussed in section 1.2.
Three licensee identified violations are discussed in sections 1.2.c, 1.2.f and 1.2.g.
A review of licensee progress in resolving weaknesses in the control of activities at Unit 1 is discussed in section 2. l.a.
Withdrawal of Violation 50-220/88-17-02 is discussed in section 2. l.d.
Inspector review of a Unit 2 motor operated valve repair is discussed in section 5. 1.
An unresolved item concerning the need for licensee evaluation of elevated temperatures in the drywell of Unit 1 is discussed in section 13.
88i2270~i.2 Ssi2~~
PDl~
ADOCf'
0<)0220 I~i PIC
DETAILS Review of Plant Events (71707,71710,'93702,90712,71881,71709)
UNIT 1 The unit remains in Cold Shutdown with the core offloaded.
The licensee is currently targeting the middle of December or early January to present their Restart Plan to the NRC staff.
The following events occurred during this inspection period:
On October 24, the licensee announced the selection of Lawrence Burkhardt to the position of Executive Vice President - Nuclear Operations.
Mr.
Burkhardt was also elected a director on the company board.
Mr.
Burkhardt, will be responsible, in this new position, for oversight of the entire Nuclear Division which includes the operation and engineering support of Nine Mile Point Unit 1 and 2.
He will report directly to the company President, John Endries.
On October 31, the unit experienced a momentary loss of 115 KV power due to an offsite fault.
The interruption in 115 KV power lasted approximately two seconds and caused no adverse impact on the uni't.
Both emergency diesel generators remained in standby because their undervoltage emergency start relays were tagged out for preventive maintenance.
The licensee declared an Unusual Event in accordance with their Emergency Plan event classification requirements and then immediately secured from the event.
The inspector reviewed the offsite electrical power distribution with licensee Operations personnel and determined that because of the 115 KV distribution scheme, the potential exists for either the Nine Mile Point Unit 1 or the FitzPatrick station interrupting their common 115 KV power feed without the other station being aware of it.
Based on this review, the licensee is revising their electrical operating procedures to caution
"against this potential problem and will include a.notification to FitzPatrick should their 115 KV power be impacted and vice versa.
The inspector had no further questions.
At 2: 15 p.m.
on November 15, the licensee notified the Headquarters Duty Officer that five of the installed accident monitoring instruments at Unit 1 did not meet the environmental qualifications specified by Regulatory Guide 1.97.
The five instruments identified by the licensee are: drywell temperatures; torus water level; torus water temperatures; Electromatic Relief Valve tailpipe temperature monitors; and High Pressure Core Injection flow instrumentation.
This determination was made by an engineering group put together to prepare for and support an NRC team inspection.
This region based inspection team was on site the week of November 14 to review Regulatory Guide 1.97 compliance and will followup on this item.
(Reference Inspection Report No. 50-220/88-34).
UNIT 2 The unit remained in Cold Shutdown during this inspection period for the scheduled mid-cycle surveillance and maintenance outage.
The following events occurred dur'ing this time period:
On October 8, the unit experienced a high 'pressure core spray (HPCS)
system automatic initiation with a concurrent Division III emergency diesel generator (EDG) start due to the inadvertent energization of a reactor vessel low low water level relay.
The 'reactor was in Cold
.
Shutdown (Mode 4) at 104 degrees F and 35 psig pressure at the time 'of the event.
No water was injected into the vessel.
Upon identification of the cause of automatic initiation and verification of stable plant,,
parameters, the HPCS pump and Division III EDG were secured.
The inadvertent initiati'on signal was caused by technician error.
Details of this event are documented in Licensee Event Report No. 88-43.
On October 11, the unit experienced an automatic reactor building ventilation system isolation'on a high radiation signal from the digital radiation monitoring system (ORMS).
The cause of the high radiation signal was an equipment malfunction involving a faulty'test box switch:
The ventilation system was restored,to normal after verification that no actual high radiation conditions existed.
This event is discussed in detail in Licensee Event Report No. 88-56.
The inspector had no further questions.
Qn October 13, the licensee determined that due to an error of omission in the feedwater flow transmitter calibration, any time that Unit 2 was operated greater than 3306.4 MWt indicated power, actual reactor power exceeded the rated thermal power limit of 3323 MWt.
This condition existed for several days in April, July and August 1988'he licensee was alerted to this problem via General Electric Rapid Information Communication Services Information Letter (RICSIL) No. 030, dated Oc';
,!r 4,
1988.
This letter notified licensees of the omission of a materia'.
expansion factor in the feedwater-flow element flow transmitter calibration calculation.
The omission of this expansion factor results in feedwater flow indicating approximately 0.5% lower than actual flow at full power.
The licensee corrected the calculation error and recalibrated the flow transmitters.
Exceeding 3323 MWt is a violation of the operating license; however, this violation is considered licensee identified.
No Notice of Violation is.-being issued in accordance with 10 CFR 2, Appendix C.
(50-410/88-19-01).
On October 19, Inservice Inspection Program examination results identified an ASME Code,Section XI, IWB-3514-1 rejectable ultrasonic testing (UT) indication on the B main steam line, upstream of main steam isolation valve 6B on a pipe to pipe weld.
The weld indication was
L
r previously identified during the Preservice UT examination, but was acceptable at that time.
Resolution of this weld indication was still pending at the conclusion of the inspection period.
The inspectors will review this item in the subsequent inspection period prior to Unit 2 restart from the mid-cycle outage.
On October 30, the unit experienced a Group 9 containme'nt isolation (containment ventilation and purge valves) while troubleshooting the standby gas treatment
.system exhaust radiation monitor (2GTS-RE105).
All systems responded properly to the isolation signal, and were subsequently restored to normal.
The licensee notified the Headquarters Duty Officer of this engineered safety feature actuation, as required.
The inspector will review the Licensee Event Report for the root cause determination'nd corrective action in a subsequent inspection period.
On November 2, the licensee determined that 'the valve position indication for the suppression
'pool air operated purge and vent valves had been swapped with their respective solenoid operated air supply valves.
The valve position indications are physically located on a control room back panel, one above the other.
A control switch is located below the indicating lights which either energizes or deenergizes the solenoid operated valves which control air to their respective 12-inch air operated vent or purge valve.
Both valves and valve position indication lights operate together and the wiring error was discovered while, conducting.indep'endent local leak rate testing of the valves because of their containment isolation function.
The inspector determined that this wiring error was apparently overlooked in the system preoperational testing phase; however, this error did not impact the function of the valves and both valves'troke times were within the acceptance criteria.
The licensee is investigating the cause of,this error.
In that the valve position indication for these containment isolation valves was not accurate, the licensee considered this condition to be in violation of the operability requirements of TS 3.6.3 for primary containment isolation valves.
This event.is considered a licensee identified violation.
In accordance with 10 CFR 2, Appendix C, no Notice of Violation is being issued.
=(50-410/88-19-02).
On November 4, 1988, the licensee determined that the primary containment penetration conductor protective devices for the 1A and 1B recirculation pump motor heaters were improperly sized for electrical overcurrent protection.
Instead of two 30 amp trip coil breakers in series, the licensee found a
100 amp and a 30 amp trip coil breaker in series for both motor heaters.
This resulted in potentially inadequate selective tripping in the event of an electrical fault inside containment.
The licensee determined that this condition existed during unit operation in Modes 1, 2, and 3, and, therefore was in violation of Technical Specification (TS) 3.8.4.2.
The inspector determined that the licensee took prompt action to correct this deficiency and that the identification
L
of this problem is the direct result of followup to another concern for proper'urveillance monitoring of TS systems and components.
(reference 50-410/88-18-03).
This is considered a licensee identified violation.
In accordance with
CFR 2, Appendix C,
no Notice of Violation is being issued.
(50"410/88-19-01).
-The inspector verified that the licensee made the appropriate
CFR 50.72 notifications via the Emergency Notification System for the events discussed above.
~Followu on'revious.Identified Items (71707,93702,30702,92700)
Unit
On April 29, 1987, the NRC issued a Notice of Violation and imposed a
Civil Penalty on the licensee as a result of findings from three separate inspections which collectively indicated significant weaknesses in the control of licensed activities at Unit 1.
By letter dated May 19, 1987, the licens'ee responded to the Notice of Violation and addressed both the specific items of noncompliance and the four broad areas of concern:
root cause analysis; material controls; procedures; and management effectiven'ess.
These four areas of concern were addressed by individual task forces which presented recommendations for improvement to senior management.
The inspectors have monitored progress in these four major areas since issuance of the civil penalty.
In general, the inspectors have noted significant improvement in the areas of root cause analysis, material controls and procedures.
The licensee's root cause evaluations have been formalized by procedure and continue to be improved upon'vidence of this improvement is reflected in the more recent Licensee Event Reports (10 CFR 50.73 reports).
Licensee material control measures and procedures have also improved.
Significant manpower contributions were expended to restructure and enhance the material purchasing and storage and material issue controls at both units.
No'ignificant problems have been recently identified in this area.
Procedural enhancements and compliance have shown some improvement.
Programs are ongoing to streamline the station administrative procedures.
In the area of management effectiveness, significant progress has been less evident.
Supervisory skills training has been given to only a few levels of supervision and management with additional training tentatively scheduled for early 1989.
The team work concept of problem resolution has met with success in the areas of licensed operator requalification training and Health Physics (frisking).
Discussion with licensee representatives indicate, by their own admission, that progress in addressing this "soft issue" of management effectiveness has been slow.
This assessment was discussed with licensee senior management on October 18, 1988, in the NRC Region I office.
At this meeting, the licensee summarized reasons for their lack of progress in the area of
i
management effectiveness and what action they have taken or plan to take to improve.
A summary of the October 18, 1988 meeting is documented in a
meeting report dated October 27, 1988, The inspectors will continue to monitor licensee progress in these areas with particular interest in the area of management effectiveness'ecent personnel changes and reorganization of the Nuclear Division will be assessed in the months to come by both the resident and specialist inspectors during routine site inspections.
(Closed)
UNRESOLVED ITEM (50-220/84-14-11):
An internal memorandum generated by the licensee during installation of the post accident sampling system (PASS) stated that type 304 stainless steel tubing was installed when the drawing called for type 316 stainless steel.
Justification and authorization for the material change was not available for NRC review during the 1984 inspection.
Subsequent to the 1984 NRC inspection the licensee prepared an analysis in February 1985 which provided justification for using type 304 stainless steel in the PASS.
The licensee indicated that their field walkdown of the system identified type 304 stainless steel in 3/8" and smaller size tubing.
After reviewing the modification package and related paperwork, the licensee concluded that the safety related portion of the system contains type 316 stainless steel, as specified.
This includes the sample piping inside the containment and piping outside the containment up to the second isolation valve.
The licensee also indicated that the current modification procedure, AP 6,0, contains steps to prevent recurrence of such an incidence.
The procedure assigns responsibilities for identification and resolution of material changes via the Document Change Request (DCR) process.
The inspector reviewed the licensee's analysis; the file on Major Order No.
1850 which contained modification related paperwork including material issue sheets; AP-7.0,
"Procedure for Control of Materials and Services",
Rev 4; and AP 6.0,
"Procedure for Modification", Rev 5.
The inspector performed field walkdowns, reviewed piping specifications for systems I22 and 122. 1, and questioned the licensee about the use and accuracy of the piping specification.
The inspector noted that the piping specification prepared in 1987 indicated use of type 316L stainless steel only.
The licensee agreed to review the piping specification for necessary changes.
The inspector did not have any further questions concerning this item.
The adequacy and effectiveness of licensee's DCR process to control material changes and installation deviations during modifications will be the subject of a future inspection.
This item is resolved.
(Open)
UNRESOLVED ITEM (50-220/88-18-02):
Review of licensee corrective actions following the lifting of licensee Stop Work Order (SWO)88-004.
Following the lifting of SWO 88-004 on September 14, site guality Control (gC) inspectors identified another ISI Plan implementation concern on October 5, 1988.
Specifically, the gC inspector. identified that a
nondestructive examination was being prepared for, on the wrong wel Following this discovery, NMPC Engineering. issued a verbal Stop Work to their ISI contractor until appropriate corrective action was taken and reviewed.
d.
The inspector determined that the root cause for this problem was personnel. error coupled with the lack of a formalized component identification system.
Licensee corrective action includes retraining of examiners and independent location verification of all components and welds to be examined in the future.
No other problems were identified.
This item remains open for detailed technical review by specialist inspectors of the ISI Program implementation and examination results.
(Closed)
VIOLATION (50-220/88-17-02):
Failure to comply with T.S.
3.6.10.1 for a degraded fire barrier penetration
~
During an earlier inspection period, the inspector identified what appeared to be the failure to.establish a fire watch for a Breach Permit issued on Fire Door 234.
A Notice of Violation was issued for this apparent Technical Specification 3.6. 10. 1 violation in Inspection Report 50-220/88-17, dated September 15, 1988.
By letter dated October 17, 1988, the licensee responded to this violation.
The licensee does not agree with the violation, as stated.
The licensee states that, although the Breach Permit was issued for Door 234 and the fire detectors were inoperable, the door was never opened or held open.
In addition, licensee personnel responsible for removing the detectors from service first verified verbally with the Breach Permit holder that the door would not be breached during the time period that the detectors were out of service.
Therefoi e, the fire door was always closed and functionally operable.
The NRC agrees with the licensee's position that the fire door was not breached and always functional and,.therefore, T.S 3.6. 10. 1 was never violated.
This violation is withdrawn.
2.2 However, the NRC still maintains that the administrative controls over the Breach Permit Program require strengthening to ensure positive control over breached or potentially breached fire barriers.
This will be reviewed during future inspections.
Unit 2 a.
(Closed)
INSPECTOR FOLLOWUP ITEM (50-410/86-56-06):
While observing a
surveillance test, the inspector observed what appeared to be the overranging of a flow meter during the venting of a differential pressure flow transmitter.
Subsequent review and evaluation by the licensee determined the flow meter (2RHS"FI14A, a
was not overranged and was designed for 120 percent overcurrent conditions for up to eight hours and momentary overloading of 10 times rated current.
Inspection of the meter found it to still function properly over its range of operation.
Similarly, the Rosemount 1153DB5 flow transmitter was designed to withstand overpressure conditions on either side of the transmitter up to 2000 psid without damage.
The proper operation of both
the transmitter and flow meter were subsequently demonstrated on February 11, 1987 during a periodic loop calibration,.
In addition, the inspector determined that augmented training was provided to Instrumentation and Controls technicians on this event (reference Training Modification Request No. 186.27)
and proper techniques for venting detectors and transmitters were incorporated in the lesson.
This item is closed.
Plant
~Ins ection Tours (71707, 71710)
=-During this reporting period, the inspectors made tours of the Unit 1 and 2 control rooms and accessible plant areas to monitor station activities and to make an independent. assessment of equipment status, radiological conditions, safety and adherence to regulatory requirements.
The following were observed:
3.1 Unit
The inspectors made tours of the drywell, main steam line tunnel, control room, and other plant areas to monitor station activities.
No discrepancies were noted.
3.2 Unit 2 Theinspector reviewed Temporary Modification 88-192 on the diesel'enerator control circuit, described in section 9sa.
The temporary modification was handled properly.
The only comment that the inspector had was that the controlled copy of the circuit diagram onto which the modification was performed did not reflect the circuit change which was
'ade.
The inspector determined that the licensee plans to make a change to the temporary modification procedure requiring that modifications that are expected to be in place for greater than 30 days be properly annotated on the controlled drawing.
This will be reviewed in a subsequent report.
)s The inspector toured various plant spaces including the drywell to observe MOV-18B work activities.
No discrepancies were noted.
Surveillance Review (61726)
4.1 The inspectors observed portions of the surveillance testing listed below to verify that the test instrumentation was properly calibrated, approved procedures were used, the work was performed by qualified personnel, limiting conditions for operations were met, and the system was correctly restored following the testing.
Unit
During this inspection period, the inspector became aware of core spray piping nondestructive examination (NDE) results which were preliminarily classified as transgranular or surface "spider cracking".
These NDE indications were discovered coincident with Inservice Inspection Plan examinations of the core spray systems.
These spider cracks were found
on both the core spray piping and pipe supports.
The cracks found on the piping were located outside the weld heat affected zone and appear to propagate from the pipe'utside surface inward.
The inspector determined that the licensee has initiated action to map the identified cracks to track further propagation and has taken boat samples for analysis by an independent laboratory.
The licensee is waiting for official results of this laboratory analysis.
The identified pipe cracking is being tracked by gA nonconformance reports.
The inspector will monitor licensee action to resolve this cracking problem in a subsequent inspections 4.2 Unit
8
A recent event at the J. A.'itzPatrick Nuclear Power Station identified a potentially generic concern for the efficient operation of emergency core cooling systems'rea unit coolers.
FitzPatrick workers identified the partial obstruction of service water flow through their "crescent room" unit coolers.
These unit coolers provide area cooling for the emergency core cooling pump/motors located in the lower elevations of the reactor building.
Internal inspection of the service water side of the unit cooler heat exchangers identified a buildup of hard scale and soft sludge on the tubes which resulted in restricted flow.
The inspector alerted the licensee to this potential concern and reviewed the preventive measures taken by the Operations and Haintenance Departments to guard against this potential problem.
Unit 1'nd
managers indicated that they didn't currently have a formalized means to measure or trend unit cooler efficiency.
Assessment of unit cooler performance is left to operators as they perform routine shift walkthroughs of plant spaces.
The inspector determined that unit coolers at Unit 1 are not safety-related; however, the licensee is currently evaluating the impact of these components on safety system operability.
Several of the Unit 2 area unit coolers are safety-related and are directly associated with emergency core cooling system operability.
Unit 2 management informed the inspector that they are currently evaluating the need for a formalized unit cooler performance monitoring program because of their safety system impact.
Both un'its have preventive maintenance procedures which check for proper unit cooler operation, but do not include routine flushing or inspection of the service water side.
The inspector was informed that inspection and flushing of the service water side of the unit coolers would be incorporated into both the Unit 1 and 2 procedures.
The inspector determined that unit coolers do not typically have service water pressure or flow indication available on them and thus inhibit easy assessment of unit cooler performance.
The inspector will review licensee action to improve unit cooler performance monitoring in a subsequent inspection perio I S
5.
Maintenance Review (62703,71881;71709)
The inspector observed portions of various safety-related maintenance activities to determine that redundant components were operable, that these activities did not violate the limiting conditions for operation, that required administrative approvals and tagouts were obtained prior to initiating the work, that approved procedures were used or the activity was within the "skills of the trade", -that appropriate radiological controls were implemented, that ignition/fire prevention controls were properly implemented, and that equipment was properly tested prior to returning it to service.
. 5.1 Unit 2 Disassembl
/Reassembl of Recirculation
~Dischar e Valve 2RCS~MOV18B
'a.
~Back round Several attempts were made to open the B loop recirculation pump discharge valve 2RCS*MOV18B following an earlier reactor shutdown.
In each instance, by electrical operation and manual operation, the valve would not open more than approximately 30% stroke.
The valve was closed and a boroscope was inserted through the bonnet vent.
Galling of the valve stem was observed.
A safety evaluation was prepared and consideration was given to several options to provide positive isolations of the valve while performing its repair.
The option selected was to provide seating of the valve disc by fixturing hold-down mechanisms.
so that the bonnet could be removed and the stem could be repaired in place.
Experience gained from a somewhat similar valve repair at the LaSalle plant was factored into the selected repair-in-place option.
The safety evaluation reviewed the hypothetical scenarios that could occur and the worst case failure of the disc hold-down mechanism.
The evaluation concluded the repair is not an unreviewed safety question and that the scenarios are bounded by the licensing basis as documented in the Nine Mile Point Unit 2 FSAR.
A repair team consisting of NMPC, GE, and Anchor/Darling personnel was
"formed to review the procedural and fixturing aspects of the repair.
The repair also involved the replacement of the triple packing gland arrangement with a single packing box and gland arrangement.
Dedicated crews of maintenance personnel and gC personnel led by a
GE project manager for the repair, with guidance from the Anchor/Darling field service engineer, were trained on the valve disassembly utilizing an identical valve obtained from Perry Nuclear Power Plant.
The inspectors observed several mock-up drills.
The licensee prepared a repair plan presentation package that was provided to the NRC Senior Resident Inspector and the NRC Region I and NRR offices.
The package contained an overview, a safety evaluation,'alve repair questions and answers, Anchor/Darling certificate of design',
Operations support and Mechanical maintenance procedure drafts, and photographs and sketches in support of the maintenance procedures
L
The repair package was reviewed at the Region I office and some discussion was held with NRR regarding the proposed repair plan.
As a result of this review, a phone conversation between the NRC staff, the senior resident i'nspector, the GE -representative and the licensee's staff was held on November 2, 1988.
guestions were asked and several NRC concerns were expressed to the licensee.
These questions and concerns related to prerequisites to define the pumps to be used if the disc hold-down mechanism failed, establishing secondary containment and primary containment integrity, seismic review, safety evaluation review, several procedural discrepancies, and the use of a mock-up that didn'
reflect actual drywell conditions.
Subsequently, a question was asked concerning possible lateral motion while the bonnet was lifted.
Review of Finalized
~Re aic Documents During the week of November 7, 1988, the inspector reviewed the finalized valve repair procedures (N2-88-23, Revision 0, N2-NMP-RCS-246, Revision 0).
These procedures had been modified in response to the November 2, 1988 phone conversation.
The inspector also reviewed the GE letter of November 3, 1988, concerning seismic capability of the repair clamp.
This was also in response to the phone conversation questions.
This letter discussed seismic effects during different phases of the repair.
It concluded the only condition not covered by existing stress calculations was with the upper stem clamp in place and the bonnet supported by the chain fall.
Consequently, the GE letter stated the bonnet would be fully removed to minimize this condition.
This would also improve access for bonnet inspection"and stem repair work.
The inspector was in agreement with the procedural changes and the seismic discussion letter.
C.
During the week of November 14, 1988, the inspector monitored the valve repair effort.
Numerous daily discussions were held with the lead GE personnel, NMPC maintenance craft personnel, and the Anchor/Darling field representative.
The inspector observed the yoke and motor operator being removed, the in-place clamp arrangements, and the bonnet being hoisted.
d.
~Ins ection of Stem and Bonnet When the bonnet was removed, the inspector viewed the exposed stem and the bonnet I.O.
The stem was in good condition, had several faint vertical packing pull type surface markings, and one small area of several spots.
There was no evidence of any stem galling or other marking to indicate stem movement was prevented.
The bonnet I.D.'s were also observed and no rub marks were evident.
In subsequent discussions with the GE project manager and Anchor/Darling field representatives, they said there may have been some marking indications that a small amount of packing may have extruded approximately 1/16" between the stem and bonnet I.D. below the lower packing.box in one location.
However, this couldn't be authenticated.
gC personnel took numerous measurements of parts and noted that the stem was slightly ben e.
Undetermined Cause of Probl em From the inspectors observations of the exposed stem and bonnet, the inspector concluded that the reason the valve would not open was not yet determined.
Refurbishment of Stem and Bonnet The stem was cleaned and wiped and very lightly polished in several spots and the bonnet I.D.'s were flapped to clean slight residue.
Not much was done with either part since there was no evidence of damage and a
decision was made to reassemble the valve.
g ~
Monitorin Reassembl of Valve
'arious steps of the valve reassembly were monitored by the inspector.
When the bonnet was reinstalled, the stem was slightly off center in the bonnet bore and the split carbon bushing for the new single gland packing could not be properly installed.
This required a temporary change notice to the procedure, to allow the yoke to be installed prior to the packing insertion to enable centering of the stem.
With the y'oke in place, the packing insertion was performed and the remaining bonnet bolts were installed and torqued.
After the drain line is rewelded to the valve bonnet, an attempt will be made to manually stroke the valve.
~Fo1 1 owo As of November 18, 1988, the valve was fully reassembled and in a safe condition.
Stroking of the valve manually will be attempted to determine if the new packing arrangement may have affected the problem.
If stroking problems remain, another course of action must be taken.
The stroking capability of the valve and any problems or licensee corrective action will be followed and reported in a subsequent NRC inspection report.
Assessment The licensee's planning and carrying out the procedural aspects of the disassembly/reassembly were well thought out.
Personnel training for the disassembly, vendor on-site guidance and gC involvement was creditable.
Craft foreman and GE personnel were fully involved with all details.
This was a major undertaking, and even though 'several minor problems were encountered, the inspectors assessment was that the work effort was good.
An overall assessment of the entire effort, including the pre-planning and the remaining phases of completing the repair and the final testing, cannot be made until all the work is done.
A concern remains that the licensee has not yet determined the root cause of the binding.
As stated above, this will be reviewed during future inspection h
~fe ~ir f
rri 6.1 On a sample basis, the inspectors directly examined portions of selected safety system trains to verify that the systems were properly aligned.
The following systems were examined:
Unit
Service Water Normal and Emergency Ventilation No discrepancies were noted.
6.2 Unit 2 Emergency Diesel Generators Residual Heat Removal High Pressure Core Spray 7.1 No discrepancies were noted.
Review of Licensee Event
~Re orts ~LERs (90713)
The LERs submitted to the NRC were qeviewed to determine wheth'er the details were clearly reported, the cause(s)
properly identified and the corrective actions appropriate.
The inspectors also determined whether the assessment of potential safety consequences had been properly evaluated, whether generic implications were indicated, whether the event warranted on site follow-up, whether the reporting requirements of 10 CFR 50.72 were applicable, and whether the requirements of 10 CFR 50.73 had been properly met.
(Note: the dates indicated are the event dates)
The following Unit 2 LERs were reviewed and found to be satisfactory:
(event followup and licensee actions are described in several previously issued reports).
LER 88-44, September 12, 1988, Failure to Adequately Separate Category IE and Non-category IE Circuitry Resulting in Inoperable Division I and II Emergency Diesel Generators
- Inadequate Design Review.
LER 88-11, March 1, 1988, Engineered Safety Feature Actuation Caused by Spurious Isolation Signal due to Equipment Failure.
LER 88-40, September-1, 1988, Niagara Mohawk Management Deficiency Results in Missed Snubber Inspection in Violation of Technical Specifications.
LER 88-50, September 20, 1988,'ngineered Safety Feature, Results from Opening of a Feeder Breaker to an Emergency Switchgear - due to Personnel Error.,
LER 88-49, September 20, 1988, Engineered Safety Feature Initiation From a High Radiation Signal Due to Unknown Cause l
LER 88-19, June 21, 1988, High Reactor Vessel Water Level Caused by Failure of Feedwater Control Valve Feedback Linkage Results in Reactor Scram'.
LER 88-18, April 6, 1988, Two Technical Specification Violations Occur as a Result of a Missed Leak Rate Surveillance and Failure to Meet Primary Containment Sealing Requirements.
LER 88-24, June 5,
1988, Engineered Safety Feature Actuation Due to Resetting a Failed Radiation Monitor.
LER 88-23, June 15, 1988, Procedural Deficiency Results in a Design Deficiency in the Standby Gas Treatment System.
LER 88-38, August'2, 1988, Partial Primary Containment Isolation Due to an Equipment Failure/Design Deficiency.
LER 88-39', August 6, 1988, Revision 1, Reactor Scram Due to Loss of Electrohydraulic Control System Pressure Caused by Excessive Vibration.
LER 88-30, July 9, 1988, Technical Specification Violation Due to an Inoperable Radiation Monitor Caused by Personnel Error.
7.2 The following LERs were reviewed and the licensee was requested to'rovide further information in the
" Previous Similar Events
" section of the LERs.'ER 88-43, October 8, 1988, Inadvertant Initiation of the High Pressure Core Spray System due to Shorted Contacts-Personnel Error.
LER 88-54, September 29, 1988, Engineered Safety Feature Actuation (Residual Heat Removal Pump 1A) due to Shorting of Contacts on the Start Relay Caused by Personnel Error Following a Surveillance Test.
No violations were identified.
8.
a.
ATWS Alternate Rod Insertion Modification 80-72 (37700)
~Sco e
The licensee committed to complete the Alternate Rod Insertion (ARI)
modification prior to startup from the 1988 outage in order to comply with Anticipated Transient, Without Scram (ATWS) Rule
CFR 50.62.
CFR 50.62, paragraph (c) (3), requires that each BWR incorporate an (ARI)
system to reduce the risk of ATWS.
The purpose of this modification was to attain an ARI system that is diverse (from the reactor trip system)
from sensor output to the actuation device.
The ARI system must have redundant scram air header exhaust valves.
The ARI system must be designed to perform its function in a reliable manner and be independent (from the existing reactor trip system)
from sensor output to the final actuation devic The automatic signals that initiate ARI come from high reactor vessel pressure or low low reactor vessel water level.
Following initiation; the scram air header valves open to reduce air pressure allowing individual scram inlet and outlet valves to open the control rod drive units, then insert the control blades to shutdown the reactor.
b.
Review Details The inspector conducted reviews and specific observations of the following:
Reviewed conceptual engineering package and safety evaluation to verify that engineering work was technically sound.
Conducted system/equipment walkdown to confirm as-built information per installation drawings.
Reviewed portions of the modification work packages including installation, inspection, and testing.
Verified acceptance criteria of system pre-operational test was technically correct and that the test results met the acceptance criteria.
Verified proper level of QA/QC involvement in inspection activities.
Verified proper classification of work in accordance with ASME and IEEE requirements.
Verified onsite/offsite review committees performed modification reviews.
Verified that system training procedure for operators was updated to reflect the modification.
Verified existence of ATWS operating procedure (Nl-OP-57),
Rev.
0, issued 8/30/88, including verifying control room annunciators and procedures for correcting alarm conditions were included.
~Findin s
The inspector reviewed Modification Package 80-72, which incorporated the installation of two one-inch Valcor DC solenoid valves and associated supporting instrumentation and controls.
Also, due to the ARI modification effect on the existing system, the two backup scram valves were replaced with similar valves; however, they are energized with AC power.
The s'olenoid valves are environmentally qualified per IEEE 323-1974 and seismically qualified per IEEE 344-1975.
Procurement and installation of associated piping met the requirements of ANSI Code B
31.1, 1980 edition through the Winter 1982 addenda.
Although the ARI system is not safety related, it was installed such that the existing
e
~
5 protection system meets applicable safety requirements.
The ARI system was given a g Classification, this meets or exceeds the requirements of NRC Generic Letter 85-06 "gA Guidance for ATWS Equipment that is not Safety Related".
During review of the licensee's safety evaluation one minor discrepancy was noted.
The safety evaluation states that the safety related power supply for the ARI system is not independent from the Reactor Trip System power supply.
The ARI system channels are powered by the safety related RPS buses No.
11 and No.
12.
These two buses are normally fed from two divisional uninterruptable power supply motor generator sets 162 and 172.
Upon loss of AC power, the MG set is driven by the DC machine acting as a
motor supplied from the 125V DC batteries.
The reactor trip system is powered by buses No.
131 and 141, these buses are fed from AC motor generator sets 131 and 141 with no backup power.
The inspector concluded that the ARI power source is independent from the reactor trip system power source.
However, since the ARI power supply source is safety related, two Class 1E fuses had been installed for isolation to assure no degradation of the safety system.
This discrepancy was discussed with the licensee and th'e safety evaluation is planned to be revised.
The inspector physically verified the'ompleted work of the valve and instrumentation panels in the reactor building, electrical and instrumentation and control devices in the control room, and ATWS cabinets in the auxiliary control room.
The equipment was found to have been installed in accordance with the licensee's installation requirements and the NRC Safety Evaluation Report.
e No violations were identified.
9.
Part
~Re ert Review (90713)
During this inspection report period, the following 10 CFR 21 reports were initiated by the l icensee:
On September 30, 1988, the licensee notified Region I via a phone call of a
CFR Part 21 reportable condition in the control circuit of the Division I and II emergency diesel generators.
The required written notification was issued on October 5, 1988.
b.
This deficiency was identified by Stone and Webster while they were performing a review of the failure modes and effect analysis.
The nature of the deficiency is discussed in Inspection Report 88-18, section 1.2.b.
No discrepancies were noted in the, written Part 21 report.
During the week of October 31, the licensee notified the NRC Region I office of a potential
CFR Part 21 report concerning possible failure of safety relief valves due to the suspected fouling of internal operating mechanisms.
After obtaining additional information the week of November 7, the licensee withdrew the Part 21 repor The inspector determined that during initial lift setpoint testing of the nine spare safety relief valves (SRVs) at Wyle Laboratories, two of the spare SRVs failed the lifttest.
Examination of these valves identified that the protective coating sprayed on the valves for storage was not removed prior to testing.
Secondly, the protective coating was incorrectly applied to some operating portions of the valve which resulted in the unsatisfactory lifts.
Thirdly, the coating applied to the valves was the wrong type.
TECTYLE 890 preservative vice the specified TECTYLE 846 was applied to the valve.
Upon discovery of this protective coating problem, the licensee initiated a field inspection of the installed SRVs.
Inspection of the valves identified a small buildup of blackened residue on the outside of the valve bonnet ventilation ports.
The licensee initially thought this blackened residue was valve protective coating.
Further investigation identified the blackened substance to'be burnt/charred plastic vent port dust covers.
These dust covers were accidentally left in the 'vent ports after the valves were installed and insulated.
The inspector concurred with the licensee's determination that the charred dust covers should not adversely impact operation of the SRVs.
All installed SRVs have or will be inspected and the charred plastic removed prior to restart.
None of the installed SRVs had evidence of protective coating still installed.
The licensee and inspector concurred that this was not an operational concern.
The SRVs which failed the lift test were not properly cleaned after removal from the warehouse and prior to testing.
Both SRVs subsequently passed the lift test after complete disassembly and cleaning of the valves.
The inspector had no further questions.
. On October 21, the licensee notified the NRC Region I office of a Part
report involving unqualified relays in the Class 1E 'control circuits for five of the six service water pump discharge iso'lation valves.
The licensee determined that the circuits contained unqualified Agastat 7000 series relays instead of qualified E7000 series relays due to a design error.
This event was reviewed and discussed previously in Inspection Report 50-410/88-18.
On November 15, the licensee notified the NRC Region I Office that they had discovered an unqualified valve in the Division II emergency diesel generator lube oil system.
The diesel turbocharger post-lube pilot valve was determined to be unqualified.
Th'is valve functions to control the lubricating oil isolation valve to the turbocharger.
After the diesel is secured, the post-lube pilot valve delays the isolation of lube oil to the turbocharger until it stops rotating and subsequently prevents flooding of the turbocharger unit with lube oil while'the diesel is in standb I
4
The post-lube pilot valve had failed earlier and the internals of the valve were replaced with commercial grade components.
It was just recently discovered that these replacement parts should have been dedicated for use in this 'safety related application.
The diesel generator has been declared inoperable until the valve is replaced or properly dedicated.
The'inspector determined that the cause for this problem was the improper classification of the valve by the vendor (Cooper-Bessemer, Inc.).
The vendor categorized the valve as non-critical (non-safety related)
on their original system drawings.
Following discussion with the licensee, the vendor's Energy Services Group conceded the safety. significance of the post-lube pilot valve.
The inspector will review final resolution of this item and the licensee final assessment in a subsequent inspection.
C On-November 1, the licensee contacted the inspector to discuss the operability requirements of Technical Specification snubbers under Mode
(COLD SHUTDOWN) plant operating conditions.
The licensee had initially conducted an engineering evaluation and
CFR 50.59 evaluation to authorize the temporary removal of two snubbers in the residual heat removal system (RHS) and two snubbers in the feedwater system.
The snubbers were required to be removed to faci'litate the removal of safety relief valves (SRVs) for testing.
Subsequent review by Licensing Department personnel concluded that their earl,ier evaluation to permit temporary removal of snubbers may be in conflict with TS operability requirements in Modes 4 and 5.
The interpretation conflict was brought to the attention of the resident inspectors and Licensing Project Manager who concurred that the licensee'
plan to temporarily remove the snubbers was inappropriate.
The inspector informed the Operations Department of this potential problem and the on-shift operators verified that neither RHS snubber had been removed and therefore the temporary system modification was not implemented.
The inspector subsequently determined that the licensee will exercise the TS 3.7.5 action statement if the RHS snubbers need to be removed for removal of SRVs.
This permits the snubbers to be inoperable (removed)
for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> before the effected system must be declared inoperable.
The inspector also reviewed the licensee's Engineering staff evaluation for temporary removal of the snubbers and its overall impact on seismic qualification of the system.
The
CFR 50.59 evaluation was also reviewed.
The inspector considered the Engineering basis for removal of the snubbers to be acceptable.
However, Technical Specifications were and are considered clear with respect to snubber operability requirements.
The inspector had no further question I t
~Alla ation ~Fol1owu (71881)
During the inspection period, the inspectors conducted interviews and inspections in response to an allegation presented to the NRC.
The inspector and licensee actions resulting from this allegation are noted below:
Unit 1 A~lie ation No. RI-88-0095:
On September 29, 1988, the resident inspectors received an anonymous allegation in letter format, alleging a
chemistry technician.was one day not ANSI qualified and the next day was qualified for no apparent reason other. than to maintain minimum staffing levels.
Unit 1 Technical Specifications 6.3.1 commits the licensee to meet the minimum education and experience requirements for, selection and training of nuclear power plant personnel per ANSI N18. 1-1971.
The inspectors determined that a qualification evaluation of the technician in question was issued by the supervisor on July 16, 1987, and specified that 18 months of further experience was needed prior to qualification as a chemistry technician.
This evaluation was based on meeting the requirements of ANSI/ANS 3;1-1981 which is a revision of ANSI N18.1-1971.
ANSI/ANS 3.1-1981 contains more stringent qualification requirements than ANSI N18-1971 for a technician.
Subsequently, a second qualification evaluation was issued on September 7,
1988 (14 months.later),
and declared that the subject technician was qualified.
The methodology used by the licensee to make this determination was reviewed by the inspector, discussed with the licensee and was found to be satisfactory.
The inspector determined that the subject chemistry technician possessed the proper education and experience required by the ANSI standard.
The inspector reviewed the qualifications of three other chemistry technicians and identified no problems.
This allegation was not substantiated; however, the technical qualifications and abilities of chemistry technicians will be reviewed in future routine chemistry and radiation protection inspections.
E ui ment Classification In May of 1988, the licensee identified that motor generator sets 161 and 171 (battery chargers for station batteries)
were improperly classified as non-safety related (NSR) vice safety related (SR).
These battery chargers were originally classified as SR; however, they were later downgraded to NSR in 1983.
The inspector conducted a review of how Unit 1 and Unit 2 personnel determine the proper equipment classification (ie; SR, NSR, g, etc.),
and the licensee's commitment to NRC Generic Letter 83-28 item 2.2. 1 ( Salem ATWS-equipment classification issue).
c
~ I
Interviews with Quality Control (QC) work release personnel found that Unit 1 utilizes a Systems Book to determine equipment classification by listing different bound'aries in a system that contain SR equipment.
This Systems Book is supplemented by a controlled set of P&IDs in the control room.
These prints are color coded to show which parts of systems are SR mechanical, SR electrical or Q related.
The inspector concluded that this process determines the equipment classification on the sub-system level but not on the individual component level.= The inspector determined that a component Q-list did exist; however, he was informed by QC that the list was not validated for use.
If questions arise on the proper classification of a component, a "Determination of Appendix B Quality Requirements" request is issued and then answered by Niagara Mohawk Engineering.
Several of these evaluations were reviewed by the inspector and were found to contain sound judgement with respect to Appendix B
requirements.
13.
An interview with QC Procurement personnel found that the component Q-list is validated for use at Unit 1, and is being used for procurement of new items.
The inspector asked Quality Assurance (QA) management why different segments of QC were using different methodology to determine equipment classification.
Investigation by the QA management determined that the component Q-list was indeed validated and should be used by all Unit 1 personnel to determine equipment classification.
The licensee committed to uni.formly implement use of thi s Q-list.
In summary, the inspector found Unit 1 personnel were sensitive towards the equipment classification process.
The inspector determined that Unit 2 uses a master equipment list (MEL)
program to determine equipment classification.
This list provides information about components such as SR rating, EQ rating, ASME level, and other pertinent data.
The inspector witnessed operation of several examples of the MEL system, and found it to be accurate.
Similar to Unit 1, Appendix B evaluations are used when questions arise concerning
'quipment classification.
No concerns were identified by the inspector.
Profiles +92700 The objective of this Temporary Instruction (TI) is to review containment/
drywell temperatures for operating plants to determine whether high containment/drywell temperatures are a plant specific problem, or generic to all PWRs and BWRs.
The inspector reviewed Unit 1 and 2 temperature profiles for the summer months of June, July and August.
This data is used to determine its effect on the environmental qualification of equip-ment, particularly, electrical insulation.
UNIT 1 The drywell temperature detectors are located at three different elevations; 230 foot level, 250 foot level and the 330 foot level.
All three levels read out in the control room.
Additionally, the 230 and 330
foot drywell levels have redundant detectors that provide indication at Remote Shutdown Panels 11 and 12.
Procedure Nl-ST-DO records the 330 foot level read in the control room and at the remote shutdown panel, and the 230 foot level read at the remote shutdown panel.
The Operations staff provided the 'inspector with drywell temperatures from the summer months of 1987.
The data provided was extracted from daily surveillance checks recorded in Procedure Nl-ST-DO.
The inspector computed the average monthly temperatures and found them to be 145, 142 and 140 degrees F for June, July and August, respectively.
The inspector reviewed Unit 1 Technical Specifications and found there are no limi,ts on drywell ambient temperature; however, an administrative limit of 150 degrees F average temperature does exist.
Procedure Nl-OP-8 states; "if drywell average temperature exceeds 150 degrees F-, consult Nl-EOP-4 for proper operator actions."
Procedure Nl-EOP-4 provides guidance to operate'drywell cooling as required to maintain drywell average temperatures below 150 degrees F.
Further, the procedure states that if this limit is exceeded, prior to exceeding 300 degrees F and if below the containment spray initiation limit, scram the reactor, trip the recirculation pumps, trip the drywell cooling fans, and initiate containment spray.
The drywell cooling system is designed such that the lowest temperatures will be found in the lower drywell,and the highest temperatures will be in the upper portion of the drywell.
Review of Procedure NI-OP-8 indicates that the three drywell" temperature detectors that read-out in the control room alarm at 120 degrees, 150 degrees, and 175 degrees, respectively, from the bottom to top of the drywell.
Review of the data provided by the licensee showed that local temperature at the 330 foot level frequently exceeded the 175 degree F alarm.
The highest temperature during the subject period was 185 degrees F at the 330 foot elevation.
The highest average drywell temperature reached during the period was 150 degrees F on one day.
In summary, the inspector noted high temperatures in localized regions of the upper drywell during the summer months, and on one occasion the average drywell temperature did reach the 150 degree F, administrative limit.
The effect of high localized temperature on electrical components in the upper drywell with respect to aging needs further review.
High average drywell temperature is an entry condition to EOP-4; however, the daily surveillance checks do not compute the average temperature.
This item remains unresolved pending NRC review of the licensee's evaluation of high temperatures in the upper drywell with respect to the Eg aging factor on electrical equipment.
(50-220/88-19-01).
UNIT 2 The average drywell temperatures for June, July, and August of 1988 were retrieved by the inspector from the daily surveillance checks Procedure N2-OSP-LOG-0001.
This procedure requires that the average drywell
'4 4 I\\'
I
temperature be calculated at least daily.
The drywell average temperature for the June, July, and August were calculated to be 101, 110 and 111.5 degrees F, respectively.
These temperature, profiles were well within the 150 degrees F average drywell temperature limit contained fn Unit 2 Technical Specifications.
As there are 12 different elevations in the drywell that are monitored by temperature detectors, staggered between the 244 and 306 foot levels, the inspector concluded that drywell average temperature is representative of actual drywell temperatures, and that drywell temperatures during the summer were well below the TS limit.
No discrepancies were identified at Unit 2.
14.
Assurance of ~ualit
~Summer (30702,30703)
The licensee identified violations discussed in section 1.2 are indicative of thorough review by your staff; however, the increasing trend in personnel errors involving procedural compliance is of concern to the NRC staff.
Actions taken to turn this trend around will be closely monitored.
Licensee preparation and execution of repair to RCS*MOV18B was generally good.
Licensee response to the unit cooler concern at the FitzPatrick station appears to be prompt and thorough.
The careful review of elevated temperatures in the Unit 1 drywell and their potential impact on electrical cable insulation is strongly recommended and will be tracked by the NRC staff.
Execution of the Unit
ATWS Alternate Rod Insertion modification was good.
15.
Exit'Meetin s (30703)
At periodic intervals and at the conclusion of the inspection, meetings were held with senior station management to discuss the scope and findings of this inspection.
Based on the NRC Region I review of this report and discussions held with licensee representatives, it was determined that this report does not contain Safeguards or 10 CFR 2.790 informatio '~i
~ gi'
fa