IR 05000333/1989003
| ML20247J965 | |
| Person / Time | |
|---|---|
| Site: | FitzPatrick  |
| Issue date: | 05/19/1989 |
| From: | Jerrica Johnson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20247J936 | List: |
| References | |
| 50-333-89-03, 50-333-89-3, IEB-84-02, IEB-84-2, IEC-79-02, IEC-79-2, NUDOCS 8906010171 | |
| Download: ML20247J965 (19) | |
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U.S. NUCLEAR REGULATORY COMMISSION Region I Report No.
89-03 Docket No.
50-333 License No.
DPR59 Licensee:
New York Power Authority P.O. Box 41 Lycoming, New York 13093 Facility:
James A. FitzPatrick Nuclear Power Plant Location:
Scriba, New York Dates:
March 5 to April 18, 1989 Inspectors:
W. Schmidt, Senior Resident Inspector R. Plasse, Jr., Resident Inspector Approved by:
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'J. Johnson, Chief, Reactor Date Projects Section 2C, DRP INSPECTION SUMMARY This inspection report discusses routine and reactive inspections during day and backshift hours of plant activities including; plant management changes, normal steady state and reduced power plant operations, reportable operational events, previously identified open items, quality assurance, surveillance, mai.ntenance, security, radiation protection and emergency preparedness activi-ties. This report period encompassed a total of 222' hours of direct inspection effort. Of that total, 34 were backshift hours while 14 were deep backshift hours conducted on 3/5, 3/11, 3/19, 3/25.
INSPECTION RESULTS Previously open items are closed in sections 2, 5, and 7.
A violation is identified in section 2.b, dealing with the licensee's failure to make a 10CFR50.72 report. A deviation, with which the licensee disagreed, dealing with the continuous monitoring of the emergency 115 KV off site power supplies remains open and is discussed in section 2.f.
A violation, for which 8906010171 890522 ADOCK 0500 g FDR O
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no notice of violation is being issued is discussed in section 4.a regarding positive control of vehicles in the protected area. The licensee's failure to perform two surveillance tests on HPCI, one required to demonstrate system operability based on ECCS analysis and one based on TS are identified in section 5.c.
An unresolved item which deals with the safety significance of exceeding an ECCS analysis parameter for HPCI is discussed in section 5.c.
An unresolved item which deals with the installation of an incorrect component in the HPCI speed control system which caused a HPCI high steam flow isolation is discussed in section Se. A licensee identified violation of TS dealing with the control of locked high radiation areas is addressed in section 9.
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The inspector will track the following issues in a subsequent inspection report:
1) Human factor improvements to the SRV/ ADS panels (section 2.a). 2) Heat load analysis on electric bay unit coolers (section 2.b).
3) Licensee corrective actions regarding the spill of diesel fuel from an underground storage tank (section 2.c).
4) The completed evaluation of components purchased from PMS (section 3.c).
5) Testing of the UPS MG set AC-DC drive undervoltage relay (section 5.b).
6) Incorporation of +he 25 second surveillance for HPCI (section 5.c).
7). Licensee's action to limit the number of HPCI system starts during startup (section 5.c).
8) Licensee's action on tagged valve hand wheel removal (section 5.f).
9) The licensee's new modification planning and coor-dination system and commitment to upgrade the nitrogen system that supplies ADS /SRV. (section 7.b)
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DETAILS 1.
. Plant Management Change (71707)
On April 1, the licensee announced that the Operations Superintendent, D. Lindsey was appointed as the Superinter -nt of Planning. Mr. Lindsey.
was succeeded by R. Locy who had been tN s.ssi stant - 0perations Superintendent. Mr. Locy was succeeded by D. Johnson, who had been the operations department radioactive waste supervisor and is licensed-. senior reactor operator..The inspector determined that the above personnel met qualification requirements for their positions.
2.
Operations (40500, 71707, 92700, 93702)
During this reporting period the unit operated at 100% of rated power except for reductions on March 15 to 45% and on March 29 to 65%. The first reduction was.to allow single loop operation while worn recircula-tion MG set brushes'were replaced and to investigate a possible condenser tube leak. The brushes were replaced satisfactorily but the condenser leak could not be identified.
The second reduction was needed to decrease radiation levels to support repair of a valve body-to-bonnet steam leak on an extraction steam line to the #6B feedwater heater.
The inspector reviewed the operability of the following systems during the inspection period:
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crescent room unit coolers
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high pressure core spray automatic dep assurization
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a.
On March 6, one main steam safety re,.'ef valve (SRV) was inadver-tently opened for approximately 5 seconds due to a personnel error.
The operator was in the process of performing an automatic depressurization system (ADS) logic system functional test which is required by Technical Specifications (TS) when the high pressure coolant injection (HPCI) system is inoperable. The operator inadvertetitly turned the wrong switch.
This event was an unplanned manual actuation of an Engineered Safety Feature, and was reported via ENS, as such.
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This event is discussed in LER 89-03, The licensee. counseled the operators to be more careful when operating switches and is including this event'in operator requalification training. The licensee.also committed to complete a modification to. correct human
' factor concerns on this panel during the next refueling outage. The inspector had no further questions.
The modification will be reviewed.
in a subsequent inspection report.
b.
On March 9, the licensee discovered that.the water supply temperature control valves for the east and west electric bay unit coolers will fail shut on a loss of air. The air supply'is the non-safety instru-ment air system. This would affect the safety related electrical-loads for:both emergency divisions, as air temperature increased to the design limitaof 104 F.
The licensee believes that this tempera-ture increase would be slow and would be noticed during operator tours.
'This event is described'in LER 89-04. The licensee tag'ged the temperature control bypass valves open so that flow will be
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available even with a loss of air. The deficiency appears to have been. caused by the installation of a fail closed rather than the designed fail open valve'during initial plant construction.
The
. licensee has committed to completing a heat load analysis' of the electric bays. This will be reviewed in a subsequent inspection repo rt'.
The shift supervisor who initiated the occurrence report' determined that this event was not reportable. The NRC resident inspector was made aware of'the valve problem by the Plant Operating Review Committee (PORC) secretary (on March 13 or 14) prior to PORC evaluation.
PORC subsequently reviewed the occurrence report and event details on March 15 and determined that the event was reportable under 50.73(a)2(v). At that time PORC assigned an action item to initiate an LER.
The rerident inspector was not informed of the licensee's determination that the event was of a safety significance requiring reporting to the NRC.
During a subsequent review of outstanding PORC action items two weeks later, the resident inspector noted the action item for the LER.
He questioned the licensee to determine the details of this issue and why an NRC notification had not been made as required by.
50.72(b)2(iii) which would also be applicable as it contains the same criteria as 50.73(a)2(v). The licensee's position was that they believed 50.72 was not applicable because the determination was l_
after the fact and they believe that a 50.73 report was adequate.
l This indcates a possible lack of understanding of NRC notification
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requirements.
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A 50.72: prompt notification allows for a timely multidisciplinary and management review of events by several NRC organizations and personnel responsible for emergency response and generic applicability to other facilities.
It is therefore from this
.important perspective that licensees not only issue LER's where appropriate but make required notifications per 50.72.
Failure to notify the NRC per 50.72 when the PORC determines that both safety-divisions of 4160 VAC and 600 VAC switchgear, the uninterruptable power supply, and reactor protection system motor generators could be adversely affected (and potentially more than one emergency core cooling system) is an. apparent violation (89-03-01).
c.
On March 21, approximately 2,000 gallons of #6 Fuel Oil overflowed the below ground fuel oil tank.
The spill was due to the tank fill valve being inadvertently left partially open allowing an uncontrol-led transfer of fuel oil from the above ground storage tank. An undetermined amount of spillage contaminated the site storr. sewer drain system,'which discharges directly to the lake.
Lic nsee's visual estimate of the amount of oil that leaked into the lake was approximately 50 gallons, before the storm sewer drain s.$ stem could be isolated. The licensee notified the New York State. Department of Environmental Conservation and the US Coast Guard of the spill. A contractor assisted in the cleanup operations. A press release informing the public of the oil spill was issued.
The event was reported via ENS because of the environmental impact and issuance of the press release. The licensee has not determined how the tank fill valve was left open. The inspector will continue to follow the licensee corrective action in this area.
d.
On April 12, the HPCI system was declared inoperable due to a ground on the "B" DC emergency bus, which was isolated to the HPCI speed control circuit.
The licensee entered a Technical Specification (TS) Limiting Condition for Operation (LCO) which allows the plant to continue to operate for seven days as long as the low pressure coolant injection (LPCI), core spray (CS), reactor core isolation cooling (RCIC), and automatic depressurization (ADS) systems are operable. This event'was reported via ENS.
This event is further discussed in section 6.e.
The inspector reviewed A0P 23, the "B" DC system ground isolation procedure and determined that the actions taken by the operators were proper, e.
On April 12, the licensee was performing HPCI operability testing after completion of repairs correcting the DC ground discussed above.
A spurious high steam flow isolation signal was received in the HPCI steam line which resulted in an automatic isolation of the HPCI turbine and a turbine trip. This event was reported via ENS. The actions taken by the operators to verify that a steam leak did not exist were reviewed and found to be satisfactory.
The licensee determined that the high steam flow was due to a malfunction of the turbine control valve actuator.
This event is discussed in section 6.e.
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f.
(0 pen) DEVIATION 88-23-02: On January 20, the licensee submitted their response (JAFP89-0056) to this deviation, dealing with the on site capability to monitor the availability of the emergency 115 KV
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power supplies. In this response, the licensee disagrees with the deviation stating that the monitoring provided on site for the
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licensee controlled portion of the Nine Mile Point Unit 1 (NMP1) and
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FitzPatrick 115. KV power supplies is adequate.
Niagara Mohawk Power Corporation (NMPC) controls the transmission lines and breakers that supply both sources of power to FitzPatrick. NYPA controls the (10013,10017 and 10022) breakers at FitzPatrick that supply one source from Lighthouse Hill to NMP1. The licensee states that the.
operation of breakers which supply FitzPatrick and the breakers that supply NMP1 are controlled by the power centers of each utility and that the coordination of these breaker operations is controlled so as not to jeopardize the operation of either unit.
In their response, the licensee did not discuss the coordination problems which lead to the. identification of.this deviation.
In this previous event, FitzPatrick and NMP1 were both shutdown and had no TS requirements for offsite power. NMPC operators deenergized the South Oswego line to NMP1 for repairs, without notifying NYPA or the FitzPatrick control room.
This left both NMP1 and FitzPatrick with only one off site power source from Lighthouse Hill. The Lighthouse Hill line was lost due to a. fault causing a total loss of off site 115 KV power at FitzPatrick.
The inspector discussed the lack of coordination between NMP1 and NYPA with the Resident Manager at the time of the event. He stated that he was taking action to preclude a future-instance were NYPA was not notified of a change in position of breakers affecting the supply of power to FitzPatrick.
On March 13, at 1:36 p.m., the FitzPatrick control room (CR) was notified by NMPC that the Lighthouse Hill line supplying FitzPatrick has been deenergized (due to operator error) on that day at 12:46 p.m.
The Shift Supervisor immediately began to perform ST 9-D for an inoperable 115 KV line with the reactor critical. TS 4.9.8.5 and 4.9.B.6 require, within one hour of the time that incoming power is only available from one 115 KV source, that the availability of the diesel generators be demonstrated by manual starting and force paralleling and, that the availability of the other off site power source shall be determined.
NMPC had restored the line to service by 1:41 p.m. but the FitzPatrick CR was not notified of this until 2:12 p.m. Test no. ST9D, which was to be completed within one hour of the loss, was not able to be completed until 1:47 p.m.
It now appears that thL loss of power was actually for a much shorter period of time.
Because of the return of the line to service within one hour, there was no violation of TS.
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Continuous monitoring of power available can be provided by other than site personnel, but the licensee has not taken adequate and timely action to provide the control room with adequate status of the 115 KV power supplies, either by breaker position indication or proper coordination with NMPC.
This deviation remains open pending licensee action to provide adequate power monitoring capabilities.
g.
(Closed) Violation 88-17-01:
This item identified various weaknesses in procedural adherence, one of.which led to an inadvertent control rod insertion during refueling operations.
In response to this violation the licensee committed to various short term and long term corrective actions.
The short term corrective actions were completed and reviewed by the inspector prior to recommencement of refueling operations and were documented in Inspection Report 88-17.
Long term commitments were made to update the spiral offload procedure (RAP 7.1.24) to clarify the steps used for recharging hydraulic control units, and install special condition tags to caution the operators to prevent reoccurrence.
The inspector reviewed this procedure change, and had no further questions.
This item is closed.
2.1 Safety Assessment The unit continues to be operated safely by the licensee's staff who
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are knowledgeable of ongoing evolutions and able to answer inspector questions fully.
The licensed operators have been observed to be alert during back shift inspection hours.
Licensee management needs to stress the need to make required 10 CFR 50.72 notifications, even if the determination that a reportable condition exists is made after the condition is known (reference report paragraph 2.b).
The licensee has not taken effective action to resolve the concern regarding continuous monitoring of 115 KV emergency off site power supplies.
3.
Quality Assurance (35502, 40500, 92702)
a.
In Inspection Report 88-29, section 11.b, it was noted that the inspector would review the licensee's actions based on a 10CFR21 report made by Niagara Mohawk Power Corporation (NMPC).
NMPC made this report because they believed that the process used by a diesel parts vendor Morrison/Knudsen (MK) to dedicate commercial grade parts for safety related use, was flawed. Based on this the licensee sent a QC inspection team to MK to review their dedication process.
This team found that MK had used two procedures for dedicating components. One procedure ensured that a proper dedication was
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'8 completed prior to shipping, while the other allowed. parts to be shipped to a customer without the. dedication being completed.
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the latter case the ~ dedications were done after-shipping, and potential installation of the parts.
The licensee verified that MK L
'was no longer using this latter procedure. MK provided the licensee E
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commercial grade dedication. performed on them.. The licensee stated that none of-these parts have been installed and that they have been;
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placed on-QC hold until the dedications are received from MK. These
actions were deemed acceptable.
b.
On. April 11, the inspector met with the QA Superintendent to discuss the licensee's -self assessment plans..Several initiatives were discussed..The inspector informed the licensee that'the collection and assessment.of data by the NRC staff was underway to complete NRC inspection module 35502, concerning self' assessments. AsLpart of.
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this effort the licensee should plan to.make a prese:itation to NRC management at the Region I office during May. The, inspector informed r:
the licensee that this inspection was meant to identify any problem areas that need licensee attention and convey these to the licensee.
c.
On December 2, 1988, the licensee was sent a letter from the NRC staff stating that there had been cases of incomplete documentation
'of components sold by PMS, Inc. This was also the sub.iect of NRC'
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The licensee reviewed purchase orders for L
ccmponents received through PMS. On March 13, 1989,the site engineer-ing organization issued an. internal memo to-the site QA~ Superintendent outlining where the subject components were installed.
The components are switches and relays that appear to have been manufactured by GE.
These components were installed in safety related app.lications during the 1987 refueling outage. None of the parts are required to have
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environmental qualification documentation since they are located in the control or relay rooms.
The licensee determined that they had-a certificate of compliance from PMS but had never received certified test reports, required by the purchase. order.' Since the test reports are not available the licensee can not confirm seismic qualification.
The itcensee has issued a QC Request to determine how these parts had been installed with.out the purchase order being fully satisfied.
The parts were installed in the circuits of the following primary containment isolation valves: (Note that each of these valves has a backup check valve.)
12MOV69, RWCU Outboard Isolation valve - control switch and
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PCIS relay.
02-2-SOV001 and O02, CRD supply to recirculation pump seals -
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control and test switches, and PCIS relays.
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9-27S0V141 and 145, N2 isolation valve'to drywell instrument
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' header - control switches.
'Other uses for these components were in the N2 supply and TIP purge system and as a control switch to the plant' computer feeder breaker.
The licensee..is in 'the process of developing a Failure Effects Evaluation, which will take into accounc testing that has been done.
on similar components.
In addition, a table. showing the effects of any' failures of these components, and operator actions that might be required. This. evaluation and the resolution of the QC request will be reviewed in a subsequent inspection report.
3.1 Safety Assessment The parts corrective actions issues discussed above dealing with'
diesel components and switches and relays purchased from PMS have been well handled by the licensee.
4.
Security (71707, 92702, 40500)
a.
On March 23, the inspector noted an unattended and idling licensee vehicle in the protected area. 'The inspector maintained positive'
control of the vehicle and immediately informed a security. guard.
The inspector noted that the vehicle was unattended for approximately.
two minutes. Operations Department personnel were responsible for the vehicle while performing cleanup efforts for' the oil spill,
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discussed in section 2.c.
10 CFR Part 73.55, section D.4, requires'
the licensee to exercise positive control over vehicles to assure that they are used only by authorized personnel.
Failure to maintain positive control is a violation. As allowed by NRC enforcement policy, 10 CFR Part 2, Appendix C, section V.A. no Notice of Violation is being issued due to the minor safety significance of the event and the immediate and long term corrective actions taken to prevent reoccurrence of this event.
Vehicle control requirements'in the protected area have been added to the security section of General Employee Training. The plant staff was informed of this requirement by memorandum on March 23. The Security Department has initiated a purchase requisition for operator aids to be applied to all authorized vehicle dashboards reminding vehicle operators of this requirement.
Until the operator aids are received, the licensee has placed a copy of the March 23 memorandum in each vehicle.
These corrective actdens appear to be adequate.
In addition this is an isolated case. An open item number is assigned to this issue solely for tracking purposes NCV(89-03-02)
b.
Based on the need to cut the seal welds on a manway in the site storm sewer system the licensee established a posted guard to verify that
. unauthorized access to the protected area was not gained through the manway.
During a night walkdown of the perimeter, the inspector observed this watch person to be fully alert and able to describe fully his reason for being posted.
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Surveillance and Maintenance (40500, 61726, 62703, 92700, 92702, 93702)
a.
(Closed)Bulletin 84-02,(84-00-02) Failure of GE Type HFA Relays
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.in Class IE Systems. The licensee responded to the bulletin by i
letter dated July 6, 1984 (JAFP84-0666). : Commitments were made to
replace relay coils made'of Nylon or Lexon by installing new relays
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r or replacing old coils with coils made of Fetzel.
It was stated that there were 285 relays that need to be replaced or recoiled, and that this would be completed by' January 31, 1986.
In an' additional response, dated February 20,1986(JAFP86-0154), the licensee stated that 26 of. the 285 total relays had not-been upgraded as of the
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initial commitment date, but that the upgrades would be completed by-March 14, 1986.
The licensee completed the upgrades and documented 12 additional HFA relays above the original 285 that now have new Fetzel coils.
This item is closed, b.
(Closed) Circular 79-02(79-00-02), Failure of 120 Volt Vital Power Supplies:.Although.there was no specific written response required by this Circular, NRC Bulletin 79-27, Loss of Instrumentation and Control. Power During Operation, required that this circular be addressed.
In response to this' bulletin the licensee submitted a letter,' dated March 4, 1980, which. stated that the licensee only needed.to address the time delay devices on the Uninterruptable' Power Supply (UPS) MG set.
The inspector reviewed the licensee's documen-tation in this area and found that the undervoltage relay for the transfer from the AC drive to the DC drive (IUVR) has not been fully tested. The reason for this is that the relay requires a 600 V test source to actuate and test the time delay setting. At present the licensee'does not have the capability to test a relay at this voltage.
The licensee has tested this relay by deenergizing the bus and verifying that the relay operates. The licensee is currently developing additional test equipment to test this relay, and plans to conduct further tests during the September 1989 outage.
NRC review documented in Inspection Report 81-06 noted that the licensee needed to review the operating procedures for the LPCI MOV inverters.
The licensee has developed instrument Maintenance procedure 71.20, LPCI UPS trip function test and calibration, which incorporates the required testing on these units per the manufacturers instructions.
Based on the above actions this item is closed. The testing of the UPS MG set undervoltage relay will be followed in a subsequent inspection.
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High Pressure Coolant Injection (HPCI) System W,lkdown (71710)
j HPCI is required to be operable at reactor pressures greater than 150 psig and to provide 4250 gpm to the reactor vessel at pressures
from 150 to 1120 psig.
FSAR section 6.4 states that HPCI will be at j
the designed flow rate within 25 seconds of an initiation signal.
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The present ECCS LOCA analysis states that the maximum allowable time delay from initiating signal to rated flow with the injection valve wide open is 30 seconds.
As discussed in.section 6.e of Inspection Report 89-02 the licensee's action to evaluate the significance of limit switch wiring deficiencies
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on the HPCI turbine stop valve were reviewed.
This event and the actions taken by the licensee are described in LER 89-02. The inspector
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noted that this limit switch (by design) controls a relay (K13) which i
operates a contact in the turbine speed control circuit, placing the turbine governor ramp generator in service.
In LER 89-02 the licensee concluded that the 25 second time discussed above had been violated, but that the 30 second time had not been violated. Because of this the licensee believed the event to be of low safety significance.
The licensee also noted that testing to verify that the system could come to rated flow was intermittently performed.
The licensee has committed to proceduralize this test. This will be reviewed in a subsequent report.
The inspector reviewed the electrical elementary diagrams for HPCI and determined that there were other functions of the K13 relay. One is (along with an injection signal and an open position signal from the steam admissic: valve (MOV14)) to allow the injection valve to the feedwater lines (MOV19) to open. As stated above the ECCS analysis assumes that the pump is at rated flow and that MOV-19 is wide open within 30 seconds.
The inspector reviewed the logic system functional testing and determined that this logic was tested in ST4F, HPCI Actuation Logic Functional Testing, but that the time between an initiation signal and MOV-19 wide open had never been measured. The inspector determined that there was no surveillance testing performed that adequately demonstrated that the HPCI system could function to meet the design requirements outlined in the ECCS analysis.
This is a violation.
The HPCI Flow Rate and Inservice Test (STUN) tests whether the HPCI system will provide a discharge pressure equal to 100 psig greater than reactor pressure. Thus if the test was being performed at 150 psig steam pressure the throttle valve in the discharge to the condensate storage tank would be throttled to give a pump discharge pressure of 250 psig. At 980 psig the valve would be throttled to achieve 1080 psig. This is done in an effort to simulate the head loss in the system piping that would be seen if actually injecting to the reactor vessel.
The inspector reviewed initial startup tests and verified that during actual vessel injection the pump discharge
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pressure was approximately 40 psig higher than any given vessel pressure.
Since HPCI is-a constant flow system, set at 4250 gpm, this 40 psig represents the head loss between the HPCI pump and the l
reactor vessel. This is also conservative since the HPCI injection test was run with feedwater flow also being supplied to the vessel.
The use of 100 psig is thus conservative. TS 4.5.C.1 requires that HPCI be tested to deliver at least 4,250 gpm against a system head corresponding to a reactor vessel pressure of 1120 to 150 psig. The inspector found that the licensee does not test to achieve a discharge pressure of 1120 psig plus the head loss assumed when injecting to the vessel.
The licensee has committed to upgrading their surveillance testing to include the 30 second requirement for MOV-19 to be open and the requirement to test at 1120 psig plus the head losses at rated system pressure.
These two examples constitute a violation of T.S. 4.5.c.1 (89-03-03).
After discussions with the inspector, the licensee management decided to perforni testing to determine the time from actuation until full flow was achieved and MOV-19 was full open prior to declaring the system operable after the ground and high steam flow isolations.
On April 13 the inspector observed the performance of ST-4N, which contained a temporary change to allow these determinations. The times from when the auxiliary oil pump was started until the red open indication for HOV1 lighted and until the flow indicator reached 4250 gpm were measured.
The HOV1 red light timing gave the time until K13 sent a signal to MOV-19 to open, since the red position light is operated from K13. This time was taken during actual operation of the system with MOV-19 shut.
The MOV-19 stroke time was then determined with the pump secured, and then added to the H0V1 time.
This test method was acceptable. The test results were that HPCI came up to full flow within 18 seconds and MOV-19 would have opened within 28 seconds.
The inspector determined that the licensee had been operating outside of their ECCS analysis. With relay K-13 wired to the HOV1 full open limit switch the combined time of opening H0V-1, and of MOV-19, would have allowed for the total time to exceed 30 seconds.
By reviewing recent valve IST testing results the timing limit was exceeded. The licensee is pursuing the reasoning for GE including this requirement in the ECCS analysis and has committed to updating LER 89-02, when the determination of safety significance is complete. This item is unresolved pending this review.
(89-03-04)
The licensee performs two STs during reactor startup prior to exceeding 150 psig and again at rated pressure.
Both tests recirculate water from the CST.
ST-4A, Simulated Automatic Initiation Test, performed once per cycle, " quick starts" the HPCI system by tripping either reactor vessel low level or drywell high pressure instruments.
ST-4N, HPCI Flow Rate and Inservice Test
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(IST), performed once per quarter, starts che turbine by lining up-
.the steam supply and discharge flow path and starting the auxiliary oil pump. While the use of two STs to meet this TS requirement is not prohibited, the HPCI turbine must be: started at least five times during a startup (once for the turbine overspeed test ST 4K, and
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twice each for 4A and 4N). The inspector is not aware of; any reason why 4A cannot meet-the requirements of the cyclic and quarterly
' surveillance as well as IST requirements.
This would prevent two runs.of the system during startup. The licensee-has committed to reviewing this situation. Their actions will be reviewed in a-
-subsequent report.
d.
(0 pen). UNRESOLVED 88-29-02: Monthly system pump and valve operability
is determined'by ST-4B. As-documented in Inspection Report 88-29, the licensee is not taking' data which would allow the determination ofcoperability of the pump to perform its design function. The licensee commented on this_ statement in their March 20 response.
The licensee stated'that the taking of this data was over and above what was required at other nuclear plants, although they said that they would incorporate the testing.
This item-remains unresolved pending the licensee incorporation of the data recording and evaluation.
into the.ECCS monthly pump operability tests or revision of the T,S.
e, While performing HPCI operability testing (ST-4N) on April 12, a-HPCI high steam flow isolation was received.
The testing was required after. maintenance performed to correct the DC. ground identified in-the HPCI governor actuator. The governor actuator was. replaced with
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a new one. During performance of ST-4N, the turbine governor valve did not throttle back'when required, which resulted in the HPCI high steam flow isolation.
Further review by the licensee determined that the replaced actuator was an incorrect component.
The actuator was designed for the RCIC system. This item will remain unresolved pending-inspector review of the causes which allowed the installation of an incorrect component in a safety system (89-03-05),
f.
On April 17 the inspector monitored the preparations for authorized-valve maintenance on FPC31, the Fuel Pool Cooling Discharge Blocking Valve.from RHR. Maintenance and radiological personnel were in the process of completing installation of a radiological containment, scaffolding-and radiological boundaries to support the valve repair.
The inspector noted the handwheel to FPC26, Fuel Pool Cooling Blocking Valve from the fuel pool filter demineralizers, was removed and on the floor with a protective tag attached to it.
The inspector determined
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FPC-31 maintenance.
During the period that the inspector monitored these operations maintenance personnel removed the installed. staging and began to place the (FPC26) handwheel back on the valve. The inspector informed the Shift Supervisor and NC0 of his concern L
regarding the administrative control of valve FPC 26, and was told L
that no authorization was given to remove that part'icular handwheel.
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The licensee is determining the events which led to the unauthorized removal of the handwheel and plans to take corrective actions to prevent recurrence.
Licensee's action to prevent any further deficiencies of this kind will be reviewed in a subsequent inspection.
5.1 Safety Assessment The licensee's actions to complete their evaluations of IE Circular 79-02 was adequate, but not timely and did not apparently receive attention until the inspector followed up on the issue.
Review of HPCI system testing and maintenance shows that the licensee's review of ECCS analysis and Technical Specifications has been inadequate to ensure that systems are being tested such that their operability is fully demonstrated.
6.
Emergency Preparedness (71707)
a.
On April 12, the licensee identified a major loss of offsite notifi-cation system capability. During a weekly test of the Tone Alert System it was determined that all the tone alert receivers did not activate. The Tone Alert System is activated by the National Oceanographic Atmospheric Administration weather transmitter. A similar event occurred on November 18,.1988.
Since the November 18 event the Tone Alert System Test has been performed on a weekly basis. The November 18 event was causea by a low modulation signal preventing the tone alerts to activate. Troubleshooting the April 12 event, however, did not identify any problems.
The. test of the Tone Alert System was reperformed April 13 satisfactorily. The system was declared operable and will continue to be tested on a weekly frequency.
This event was reported via ENS.
b.
Between March 20 and 23 the licensee remodeled their Technical Support Center. The licensee designated the Alternate OSC (the work control center) and the EOF as providing the compensatory functions.
The inspector reviewed the licensee's Emergency plan and found this to be acceptable and agrees with the licensee that this did not degrade the emergency rest nse capabilities.
No concerns were identified.
Licensee actions were acceptable.
7.
Engineering and Technical Support (92702)
a.
(Closed) VIOLATIONS 89-02-04, 86-04-02, 86-13-02: EQ violations
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The licensee responded to the violations described in Enforcement
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Action 88-239, in a letter dated March 10, 1989. The specifics of each are discussed below.
1.
'The licensee did not establish environmental qualification of four Limitorque valve actuatorsLin the. Reactor Recirculation System in that the insulation material on the torque-and. limit switches was Durez (red), notl Fibrite (brown), which was not
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qualified for_ its application. This item was originally unresolved and was later determined to be_an EQ Category C violation.
This item was also the subject of Licensee Event-Report (LER)86-007.
In their response the licensee agreed with'the violation.
The response:also stated that following determination onl March 24,-
1986 that the actuators were:not qualified for in-containment use,.they were replaced with environmentally. qualified actuators on March. 31, 1986. All other EQ actuators in the-containment'were immediately inspected and verified to be environmentally qualified for their application.
This action was completed prior to restart of the. facility.
Subsequently, the EQ files' for Limitorque actuators were completely ~ revised.~
.The traceability of each actuator to the appropriate test report was established and the qualification of.each actuator was reverified.
- The licensee's response further stated that in order to improve the consistency and completeness of their review, verification, and acceptance'of'EQ files generated by outside consultants, a new procedure titled Review of Plant Specific Qualification
' Reports (EDP28), was written and implemented on September 27, 1987.
This procedure requires written documentation of. the review, verification, and acceptance of these EQ files in accordance with a checklist which documents the details of the file review and verification.
The checklist -includes verification that acceptance criteria, similarity, installation interfaces, and all other pertinent qualification attributes are specified and adequately addressed.
2.
Environmental Qualification of Rosemount Model 1153 Pressure Transmitters without conduit sealant was indeterminate.
This violation was classified as a Severity Level IV based on the licensee's failure to establish environmental qualification of sixty-four Rosemount pressure transmitters installed in the analog transmitter trip system.
Specifically, the transmitters were installed without the use of the required thread sealant at the instrument conduit connection as required by procedure;
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no. record was placed in the environmental qualification file to
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verify that these transmitters, as installed, would function properly in a post accident condition.
The licensee's response to the violation stated that the violation did occur and that the transmitter conduit connections were sealed during the maintenance' outage which commenced on September 27, 1986.
To er. ure that future installation and maintenance activities are performed in accordance.with the environmental qualification requirements, Instrument Maintenance Procedure IMP 77, Replacement of Rosemount Pressure Transmitters Model 1153,-Series B, Code R, with Conduit Sealant 353C was. prepared and approved. However, the licensee performed a Nuclear Environmental Qualification (NEQ) Assessment Report on the Rosemount transmitters and confirmed that the as-installed configuration of the transmitter conduit without the thread sealant was capable of performing its-environmental qualification function for its application. The inspector reviewed NEQ report 48627-01 dealing with this issue and had no_further questions.
Based on'the review documented above this violation is closed.
b.
On March 20, 1989 the licensee submitted their response, requested in the cover letter forwarding Inspection Report 88-29..One section of this response deals with inadequacies-in the nitrogen supply system to the automatic depressurization (ADS) and safety / relief valves (SRV). The licensee broke down corrective-action for these specific deficiencies into short and long term actions.
(Closed) UNRESOLVED 88-29-04. This is a short term action to upgrade.the operating procedure for the containment air dilution (CAD) system to include specific action to be taken for high and low nitrogen header pressure. Although the licensee does not have specific alarm response procedures for computer point alarms, it is felt that the operators have adequate knowledge of the operating procedures so that remedial actions can be found and taken, dased on this, this item is closed.
(Closed) UNRESOLVED ITEMS 87-19-01 and 88-29-03.
These are the long term actions.
The licensee plans to make a modification during the 1990 refueling outage to correct the location of the pressure sensing device so that it is downstream of the two supply lines and to provide an annunciated alarm for high/ low nitrogen pressure to the ADS /SRV valves to provide an alternate scheme to correct these deficiencies.
The licensee further committed to develop an applicable alarm response procedure for any newly installed annunciated alarms.
Based on this, these items are closed.
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In this portion of the response the licensee further pointed out that.
I-their systems for planning and coordinating modifications have changed and that a modification being planned in the future will not negate'any previous modifications. This process will.be
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(Closed) Violations'88-23-01 and 88-23-04: On March 13, the NRC.
staff. issued a violation and proposed civil penalty as discussed in
Enforcement Action 88-304. 'This action was taken based on Violations 88-23-01 and 88-23-04. These violations have been grouped together and another unresolved item (UNR 88-29-10) is _ tracking the licensee's corrective actions. outlined at the Enforcement Conference for these violations. Eecause of this these items are closed, and the violation response will be tracked with unresolved item 88-29-10.
d.
(0 pen) UNRESOLVED ITEM 88-29-10: On April 12, the' licensee issued their response to Enforcement Action 88-304, discussed above. The licensee agreed with the subject violaticns and remitted the propos'd civil penalty under separate cover.
The licensee documents e
in the. response the commitments outlined in Inspection Report 88-29 section 12, which are the subject of this open item. The licensee.
does not discuss the commitment to review the need to test the safety-related components that would be cooled by emergency service
. water, during a loss of service water, with the actual emergency service water. This was discussed with the Resident Manager who agreed that this was still a licensee commitment.
e.
(Closed) Temporary Instruction (TI) 2515/95:
During his site familiarization trip to the FitzPatrick Nuclear Power Plant the week of January 16, 1989, the NRR Project Manager, David LaBarge, inspected the Recirculation Pump Trip implementation as required by Temporary Instru: tion (TI) 2515/95. The purpose of this inspection was verification that the signals indicative of an ATWS event (reactor vessel low water level and reactor vessel high pressure)
would cause the recirculation pumps to trip. This verification was accomplished using the Recirculation System Operating Procedure F0B27, the Recirculation System Description and Training document, the General Electric 'Serie: Wiring Drawings 730E1978A, and Technical Specification Sections 3.2.G and 4.2.G However, because of a desire to do further review on the implementation method (which trips the recirc MG motor supply breaker rather than the pump motor field breaker), the TI was not closed out at this time. A subsequent check with the Instrumentation and Control Systems Branch at NRR Headquarters has shown that the implementation method is satisfactory.
Research also showed that since these trips were in effect prior to the Salem ATWS event, no modificat;ons were necessary. Therefore, the requirements of TI 2515/95 are satisfied and the TI is considered closed.
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8.. Fo110wup of Written Reports of Nonroutine Events (92700)
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The inspector reviewed the following nonroutine reports to determine whether the licensee has taken proper corrective actions and whether' the response was adequate and met regulatory requirements.
The inspector reviewed the following item:
LER 89-01 - ECCS pumps potentially made inoperable due to loose motor.
lead terminal boxes. This event occured on February 28 and was described-
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in Inspection Report 89-02.
Based on the review of this LER the-inspector had no further questions.
9. Radiological Protection (71707, 93702)
a.
On April 6, while, performing a daily surveillance, a radiological technician discovered a high radiation gate (#T272-7) leading.to the condenser bay, unlocked. This'same door was founa open March 17 and a radiological' incident report was issued.
Dose rates in the general area by the steam jet air-ejector platform are 1.5 rem / hour. Through licensee investigation the cause of the problem has been determined to be with the latching mechanism. On April 6'the gate appeared secured and a reasonable person would have believed the gate to be locked by pulling lightly on the gate. The technician,.however,.
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discovered that a hard pull would allow the gate to be forced open.
A work request was initiated to inspect the locking mechanism.
A-screw was found missing and the gate was properly repaired. Technical Specification 6.11.A.2 requires areas greater than 1 rem / hour to be
' locked.to prevent unauthorized entry.' This is a violation. As allowed by NRC enforcement' policy, 10 CFR part 2, Appendix C, section V.G.1, no Notice of Violation is being issued since this was identified by the licensee, would be a severity level IV or V violation and prompt and effective corrective actions have been taken. An open item number is assigned to this licensee identified non-cited-violation solely for tracking purposes NCV (89-03-07)
10. Licensing On. March 20, 1989 the licensee submitted their response requested in the cover letter forwarding inspection report 88-29. One section of this response deals with the TS revisions that are needed due to differences of current plant configurations and to provide clarification.
The specifics of these changes are discussed below.
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D (0 pen) UNRESOLVED ITEM 88-29-01. The licensee discussed the sequence ~of.
events leading to the. failure to correct deficiencies with the TS for low pressure coolant _ injection (LPCI). The licensee committed to having the submittal to correct the LPCI TS deficiencies to the NRC by May 31, 1989.
This item remains unresolved pending submittal and review of these changes.
i The licensee also included eleven other TS amendments that.they committed to submit between May 31, 1989 and July 19,1989. The inspector reviewed o
these items and the expected submittal dates and had no further questions.
!The commitments to submit these amendments will be tracked using Unresolved Item 88-29-01, 11. Exit Interview (30703)
At periodic intervals during the course of this inspection, meetings were held with senior facility. management to discuss inspection. scope and findings.
In addition, at the end of-the period, the inspector met with licensee representatives and summarized the scope and findings of the inspection as they are described in this report-
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Based on the NRC Region I review of this report and discussions held with NYPA representatives during the exit' meeting, it was determined that this report does not contain information subject to 10 CFR 2.790 restrictions.
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