IR 05000338/1993010
| ML20036A543 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 04/22/1993 |
| From: | Belisle G, Lesser M, Taylor D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20036A539 | List: |
| References | |
| 50-338-93-10, 50-339-93-10, NUDOCS 9305120055 | |
| Download: ML20036A543 (18) | |
Text
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UMITED STATES
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NUCLEAR REGULATORY COMNisSION u
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. REGION 11
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101 MARIETTA STREET, N.W.
- t ATLANTA, GEORGI A 30323
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Report Nos.:
50-338/93-10 and 50-339/93-10 Licensee:
Virginia Electric & Power Company 5000 Dominion Boulevard Glen Allen, VA 23060
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Docket Nos.: 50-338 and 50-339 License Nos.: NPF-4 and NPF-7 Facility Name: North Anna 1 and 2 Inspection Conducted:
February 21 - April 3, 1993 Inspectors:
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/e. 2/-f.3 M.S.4essef/S$11or Re'sident Inspector Date Signed h Kd/
k 9'- N-P3 D.R. Taylor,1/LfdentInspector Date Signed Accompanying Inspector: A. B. Ruff YL f2 -
(A MJ p
G. A.' Be' lisle,,ledisin Cliief Date Signed Division of Reactor Projects
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SUMMARY Scope:
This routine inspection by the resident inspectors involved the following areas: plant status, operational safety verification, maintenance observations, surveillance observation, licensee event _ report followup, and action on previous inspection items.
Inspections of licensee backshift activities were conducted on the following days:
February 21, 22, 23, 24, 28,
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March 3, 6, 7, 8, 10, 11, 12, 18, 21, 23, 28, 30 and April 3.
Results:
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In the' operations area, an inspector follow up item was opened c'oncerning a'
leak.which developed on a reactor coolant pump flange. The licensee is-currently monitoring the leak via a video camera and remote monitor (paragraph -
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3.g).
In the operations area,_ a non-cited violation was identified regarding _
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inoperable containment-purge and exhaust isolation radiation monitors
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(paragraph 7).
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9305120055 930422 PDR ADOCK 05000338 G
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In the maintenance / surveillance area, an unresolved item was identified when an inadequate independent verification resulted in signal cables to upper and lower Power Range Nuclear Instrument N-42 being swapped (paragraph 3.c).
In the maintenance / surveillance area, an: enhancement was noted regarding how supplemental work instructions are developed (paragraph 4.a).
In.the maintenance / surveillance area, an unresolved item was identified concerning the licensee's interpretation of Technical Specification 3.6.4.2 Surveillance requirements. A weakness was also noted with the licensee's procedure for testing the hydrogen recombiner (paragraph 5.a).
In the maintenance / surveillance area, a weakness was identified _ with the post maintenance test _ data sheet associated with containment purge and exhaust isolation valves. Containment type C leakage was low reflecting good-maintenance of type C valves (paragraph 5.b).
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In the engineering and technical support area, the controls that were in place to implement a pilot electronic procedure distribution program were considered
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a strength (paragraph 3.b).
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In the safety assessment / quality verification area, the licensee's evaluation for a Westinghouse Advisory Letter on check valve leakage during a LOCA did not consider valve failure. Once this was considered, the condition was determined reportable and compensatory actions were taken (paragraph 3.a).
In the safety assessment / quality verification area, the licensee requested enforcement discretion for an incomplete surveillance (paragraph 3.e).
In the safety assessment / qualification management area, actions to ensure containment penetrations were properly maintained during refueling were taken i
and appeared effective (paragraph 5.d).
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s REPORT DETAILS
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1.
Persons Contacted
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. Licensee Employees L. Edmonds, Superintendent, Nuclear Training
- R. Enfinger, Assistant Station Manager, Operations and Maintenance J. Hayes, Superintendent of Operations
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D. Heacock, Superintendent, Station Engineering
- G. Kane, Station Manager
- P. Kemp, Supervisor, Licensing
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W. Matthews, Superintendent, Maintenance
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J. O'Hanlon, Vice President, Nuclear Operations
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D. Roberts, Supervisor, Station Nuclear Safety
- R. Saunders, Assistant Vice President, Nuclear Operations -
D. Schappell,. Superintendent, Site Services R. Shears, Superintendent, Outage and Planning
- B. Shriver, Assistant Stat. ion Manager, Nuclear Safety and Licensing
- J. Smith, Manager, Quality Assurance
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A. Stafford, Superintendent, Radiological-Protection
- J. Stall, Acting Assistant Station Manager, Operations and Maintenance
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Other licensee employees contacted included engineers, technicians,.
i operators, mechanics,. security force members, and office personnel.
NRC Resident Inspectors
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- M. Lesser, Senior Resident Inspector
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- D. Taylor, Resident Inspector
- S. Lee, Resident Inspector
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- Attended exit interview Acronyms and initialisms used throughout this' report are' listed in the I
last paragraph.
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f 2.
Plant Status Unit I began the inspection period shutdown and defueled. A contractor
was performing SG work during the scheduled 51-day SGRP window. -The
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contractor finished. work on schedule. Core onload began on March'16, i
and the unit entered Mode 5 on March 22. At the end of the inspection i
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period, the unit was on day 89 of an originally scheduled 110-day'
outage.
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Unit 2 operated the entire inspection period at or near 100 percent l
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power.
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3.
Operational Safety Verification (71707) - Units 1 and 2 The inspectors conducted frequent visits to the control room to verify
proper staffing, operator attentivreness and adherence to approved procedures.
The inspectors attended plant status meetings and reviewed operator logs on a daily basis to verify operational safety and compliance with TS and to maintain awareness of the overall operation of the facility.
Instrumentation and ECCS lineups were periodically reviewed from control room indications to assess operability.
Frequent plant tours were conducted to observe equipment status, fire protection
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programs, radiological work practices, plant security programs and
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housekeeping. Deviation Reports were reviewed to assure that potential
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safety concerns were properly addressed and reported. Selected reports were followed to ensure that appropriate management attention and corrective action were applied.
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a.
Potential Offsite Leak Path The inspectors reviewed the licensee's actions for a Westinghouse Nuclear Safety Advisory Letter on check valve leakage during a LOCA. The licensee initiated DR N-93-ll3 following receipt of the letter on January 19, 1993.
The advisory pointed out the potential for a leakage path outside containment following a LOCA should the VCT outlet check valve,1-CH-215, fail.
If the plant
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is in the sump recirculation mode after an accident and the LHSI
pumps are supplying flow to the HHS1 pumps (low to medium size break LOCA) and if 1-CH-215 leaks, flow will be diverted through the seal water heat exchanger.
If the LHSI pumps discharge
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pressure exceeds relief valve 1-CH-RV-13828 set point pressure,
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the relief valve would lift.
This would relieve to the VCT and eventually to the Liquid Waste System resulting in an uncontrolled
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release to the auxiliary building.
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The licensee's evaluation determined the potential pressure from
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the LHSI pumps to be 145-150 psig.
Relief valve 1-CH-RV-13828 has a setpoint of 150 4.5 psig, therefore, the concern applied.. The licensee's initial actions included plans to leak test 1-CH-215
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(Unit I valve only), to consider placing the valve in a periodic
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test program, and to consider up-rating the seal water return line piping in order to increase the 1-CH-RV-13828 setpoint.
Leak testing, completed on February 15, measured 200-230 cc/ minute.
At this rate it would take 38 hours4.398148e-4 days <br />0.0106 hours <br />6.283069e-5 weeks <br />1.4459e-5 months <br /> to see a VCT level increase of 10 percent.
Based upon this, on February 19, the station turned
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further corrective action to Corporate Nuclear Safety for further
tracking.
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The inspectors questioned the evaluation since it did not consider the possibility of 1-CH-215 (and the corresponding Unit 2 valve)
failing fully open and whether this represented a credible single i
failure previously not analyzed.
If the valve failed open, the
leak rate through the lifted relief valve 1-CH-RV-1382B could be
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180 gpm and offsite doses could exceed limits.
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l The licensee considered the inspector's concerns and on
February 25 notified the NRC of the condition in accordance with 10 CFR 50.72.
The licensee prepared JC0 93-01 to address short term actions which was reviewed by the inspectors. The licensee briefed each operating shift on the potential condition and i
indications to watch for. The inspectors attended one session on i
March 3.
In the short term, the licensee will add a statement to their E0Ps to contact the TSC for technical guidance prior to
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initiating SI recirculation.
For an intermediate break LOCA, it is reasonable to assume that the TSC will be manned prior to swap-
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over.
The guidance in the JC0 will assess the possibility of
securing a LHSI pump, assess preemptively isolating the seal water
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return heat exchanger, check for VCT level or pressure increases
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and consider supplying HHSI pumps-from the alternate suction
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This compensatory action appears to be acceptable until long term corrective action is taken.
b.
Procedure Upgrades The inspectors reviewed and discussed with the licensee the use of f
electronic procedures. The licensee established a pilot project l
titled " PROMIS" to electronically store, distribute, view, and i
print technical procedures.
The pilot was initiated at the end of
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January 1993. The scope encompassed Unit 2 ops.
The inspectors reviewed the controls placed on the use of I
electronic procedures to verify applicable administrative requirements are adhered to. The system is-set up with several levels of security, such that only designated individuals can update revisions or PARS and prepare procedures for SNSOC
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approval.
Other users can view and print procedures. The process
takes into consideration the approval mechanism by SNSOC,.and
safeguards against using or printing an incorrect revision or PAR.
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The controls were demonstrated to the inspectors by the licensee.
l The inspectors also verified that operators and shift operation procedure writers were aware of the controls.
Procedures can be
printed from various locations but only_ the control room can print
" controlled" copies. A backup hard copy file was kept in the control room during the pilot demonstration period. Hard copies of E0Ps will be maintained in the control room.
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The inspectors considered the controls over implementing the pilot to be well thought out and a strength.
In addition, the program
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has various attributes which enhance the overall procedure quality i
and tracking.
Feedback from.the operating shifts is being
considered to further enhance the process.
The inspectors also noted considerable improvement over the last
year in procedure quality and the number of active PARS.
Dedicated procedure writers have been established for each operator shift, the I&C Department, and more recently, mechanical I
maintenance.
The licensee has also implemented on-the-spot
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electronic procedure PARS which has greatly increased the quality of procedure changes that are needed to support aperations. The backlog of procedure PARS, which was a weakness a year ago, has virtually been eliminated.
c.
Inoperable Power Range Nuclear Instrumentation The inspectors reviewed OR N-93-528 that documented power range NI'
detector N-42. delta flux indicating +0.5 percent while all other detectors were at -5 percent. The difference was identified on March 22 by an oncoming reactor operator.
Prior to the discovery, the N-42 detector had just been calibrated per instrument calibration procedure ICP-NI-2-N-42, Power Range Channel N-42,
Protection Channel II. Power Range NI N-43 was in the process of being calibrated. After completing the N-43 calibration, a calibration check was performed on N-42 and no discrepancies were found. When the detector was returned into service, the delta flux indication returned to normal.
Initial investigation suspected that the delta flux indicator was sticking from a possible static charge.
However, further review i
identified that computer point checks agreed with the questionable delta flux indication from the time that the initial calibration
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of N-42 was completed until the calibration check was performed.
Based on this, the licensee concluded that the upper and lower
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detector signal cables were incorrectly switched following' the initial calibration and then correctly reconnected during the calibration check. To verify this conclusion, on March 23, a special SNSOC approved procedure was performed that reversed the cables and obtained computer data. The test data supported the
conclusions. The licensee's investigation into this. event was thorough.
The inspectors reviewed the ICP and discussed this event with the licensee.
The procedure clearly identified connecting the signal cables to their appropriate instrumentation and the instrumentation and cables were clearly marked.
In addition,'the e
procedure requires per step 4.12.10.3 that a qualified individual independently verify that detector A and detector B signal cables
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have been reconnected.
Further, step 4.12.27 of the procedure requires a verification by the control room operator that all indications, alarms and printouts are normal for plant conditions.
The inspectors concluded that the procedure was adequate and had.
sufficient controls to preclude the condition from occurring. The i
apparent cause was inattentiveness on the part'of the technician and operator'and an inadequate independent verification. -The licensee initiated a HPES evaluation of the event.
The significance of reversing the cables with respect to TS was reviewed. Detector amplifier rescaling was performed during the calibration. The new currents used for the upper and lower detectors were so close to each other (within one milliamp) that i
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very little effect was noticed on the power range indication.
However, the delta flux portion of the indication was affected such that a changing delta flux would act opposite to what was expected for the N-42 power range channel.
Delta flux provides
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input to RPS for the OTAT setpoint and also provides input to the OTAT rod stop and turbine runbacks. This effectively rendered the OTAT setpoint and possibly the N-42 power range channel inoperable for a period of about three hours. While the N-42 channel was in this condition, testing of the N-43 channel proceeded. TS requires an inoperable NI and OTAT channel to be placed in trip within one hour. One inoperable NI channel may be bypassed for two hours while testing a redundant channel.
The licensee will report this event per an LER. The licensee is determining potential inoperability of the channel and specifically OTAT setpoint for the channel.
Until this review is completed, this item is identified as unresolved item 50-339/93-10-01:
Inoperable NI Channel.
d.
Equipment Hatch Platform Design On March 8, the licensee made a four hour report pursuant to 10 CFR 50.72 concerning an un-analyzed condition of the containment equipment hatch platform. The platform was modified, prior to Unit I shutdown, to support steam generator replacement.
The existing equipment hatch supports the missile shield in front of the equipment hatch and was evaluated for a 360 mph tornado
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wind load. When the temporary extension was erected, it was not designed for the tornado. The licensee determined that failure of
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the temporary structure due to a 360 mph tornado could transfer load to the existing tower, consequently causing the equipment
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hatch platform to collapse.
Follow up of this item will be performed during LER close out.
e.
Request for Enforcement Discretion P
On March 25, the licensee identified that testing required by TS
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4.3.1.1.1, table 4.3-1, item 19 had not been completely performed.
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The TS requires that the manual ESF function input to the reactor
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trip system instrumentation be verified operable every 18 months.
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A manual ESF actuation can be initiated by two manual SI-switches
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in the control room.
Each of the switches directly energizes the shunt trip coils of both trains of reactor trip breakers and
bypass breakers. During the licensee's programmatic review of TS surveillance requirements, it was determined that the output from one SI switch to one bypass breaker and the output from the I
redundant SI switch to both reactor trip breakers and one bypass breaker had not been functionally tested. As a result, on
March 25 at 3:26 p.m., the licensee invoked the requirements of TS 4.0.3 which allows delaying for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> the action statement requirements to permit the completion of the I
surveiliance.
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On March 26, the licensee requested enforcement discretion from NRC to allow for continued operation of Unit 2 until the next refueling outage.
Specifically, the licensee requested that the ESF functional test of the SI input to the reactor trip breakers be excluded from TS surveillance requirement 4.3.1.1.1, Table 4.3-1 for the remainder of the operating cycle. The licensee discussed this issue with NRC per telecon on March 26.
Verbal approval of the request was given by NRC the same day. The licensee committed to submit a TS changed to NRC by March 31. The functional test of the Unit I switches was satisfactorily
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performed on April 1.
f.
Unqualified Protective Coating Material on Primary Loop Piping
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The licensee applied an encapsulant coating to the old steam generators to minimize the potential for loose contamination during the removal of the old steam generators.
However, the licensee had dripped unqualified coating on the primary piping when applying the encapsulant. As discussed in NRC Inspection Report Nos. 50-338, 339/93-11, the dripped coating remained on the
B and C loop primary piping after licensee's attempts to remove
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it.
The licensee issued Non-conformance Reports Nos. 0060 and 0074 to address the presence of dripped coating. The licensee closed NCR
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Nos. 0060 and 0074 on March 17 and March 19, 1993, respectively, after completing corrective measures.
On March 22, 1993, the inspectors examined the primary loop piping and found that the piping had been cleaned. Subsequently, insulation was installed on the piping.
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g.
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On March 26, the licensee entered Unit 2 containment to assess and if possible make temporary repairs to a flange leak on %" line CH-935-1502-01. The line is a thermal barrier test line off of the IC RCP. The flange is not isolable from the RCS and is at RCS pressure of 2235 psig. The flange was covered with boric acid build up and was wisping steam. The personnel that entered
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containment cleaned off the boric acid and then determined that a temporary repair was not feasible due to the inability to exactly assess the flange bolting condition. The stainless steel flange is held in place by four 7/8" diameter chrome-moly threaded studs.
The studs have experienced some wastage due to the boric ccid corrosion.
To monitor the flange leakage, a temporary video camera was installed at the flange with a remote monitor located. in the Unit 2 control room. The licensee also performed an evaluation which concluded that the flange would be acceptable even if two opposite side bolts were judged non-effective, i.e., having degraded below 1" diameter. At that time no quantitative bolt degradation-
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assessment had been done. The inspectors noted that unidentified i
leakage had been increasing from about 0.16 gpm on March 30 to 0.25 gpm on April 2.
It was not known if the increased leakage l
was due to the flange leak.
On April 2 the licensee entered
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containment to assess the current condition of the flange. The threaded studs appeared to be degraded to less than }".
The licensee conducted a meeting to discuss possible corrective f
action. Design engineering was tasked to evaluate the current condition given the wastage that occurred. The licensee scheduled a shutdown of the unit on April 24 to_ perform the repair. The I
meeting was thorough and provided direction to engineering, maintenance and operations on resolving this problem. Until the inspectors can review the licensee's engineering evaluation when.
completed, this is identified as IFI 50-339/93-10-02:
One unresolved item was identified and is discussed in paragraph 3.c.
One inspection followup item was identified as discussed in paragraph
3.g.
4.
Maintenance Observation (62703) - Units 1 and 2 Station maintenance activities were observed / reviewed to ascertain that the activities were conducted in accordance with approved procedures,
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regulatory guides and industry codes or standards, and in conformance with TS requirements.
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EDG Maintenance
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On March 17, the inspectors observed maintenance on Unit 2 EDG.
The EDG was tagged out and entered a 72-hour action statement to-
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allow a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> window for various maintenance. The inspectors l
observed PM-M-20-D/Q-1, which performed maintenance procedures-MMP-P-EG-1, Mechanical Maintenance Procedures for-the EDG Engines.
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The procedure is performed quarterly to inspect such things as the fuel control system, fuel oil system, lube oil system and air filters.
The inspectors also observed the removal of 2-EG-P-4H, Standby tube Oil Pump. The pump was being removed because of a small _ leak from the pump seal. The maintenance was delayed about an hour because the tagout for the work did not isolate oil from the l'ube oil reservoir. ' The condition was caught by maintenance prior to the start of the job. The maintenance was further delayed following the tagout to obtain an oil collection drum to collect oil-drainage from the un-isolable piping-to the pump. The.
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inspector commented that although the delays were minimal, they
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did affect the time that a safety-related component was in a TS action statement.
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The inspectors reviewed the work documentation which was being performed using a generic pump repair procedure and MDAP-19, Maintenance Procedure Usage, Supplemental Work Instructions.
Supplemental work instructions are written to perform specific maintenance on a component when detailed procedures are not available. The written steps for those instructions were
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electronically generated and had been approved by SNSOC prior to use.
Per discussion with the craft performing the work, a designated maintenance procedure writer was established to provide assistance to the maintenance shop for the outage. The inspectors considered the SNSOC approved electronic supplemental work instructions to be an enhancement to the normally hand written instructions. The supplemental work instructions can be stored for future use.
b.
Freeze Seal on Quench Spray System On March 18, 1993, the inspectors observed the use of a freeze seal to isolate a portion of the Unit 1 quench spray system to
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permit valve maintenance. The freeze seal was to be established in the 6-inch diameter discharge line of the refueling water chemical addition tank.
This work was performed to support the repair of manual valve 1-QS-32. which had a body-to-bonnet leak (WO 159551).
Because a portion of the system would be isolated by the
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freeze seal, the licensee found it convenient to repack nearby manual valves 1-QS-31 (WO 153250) and 1-QS-35 (WO 153247) at the same time.
Manual valves 1-QS-29,1-QS-34, and 1-QS-37 had been closed for
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system isolation. Valves 1-QS-MOV-102A and 1-QS-M0V-102B were open. A liquid nitrogen chamber was attached to the CAT discharge piping to form the freeze seal. The CAT contains a 12-percent Na0H solution which freezes at 10 F.
However, to be conservative, the temperature of the pipe under the chamber was maintained at-
-320"F for about two hours before declaring the freeze seal intact.
Then, the isolated system was drained through manual valves 1-0S-33,1-QS-36, and 1-QS-118. Work activities were conducted in the yard adjacent to the CAT.
The inspectors reviewed Procedure No. MMP-C-FS-2, Rev. 2-P1,
" Freeze Seal Isolation Using Freeze Seal Engineering," which was.
used for establishing, maintaining, and removing the freeze seal.
The inspectors observed that Step 3.7.2 of the procedure had been signed off indicating that a cuntingency plan for freeze seal failure had been verified to be available for implementation.
The inspectors reviewed the contingency plan dated March 9, 1993,
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and found that the contingency plan addressed only valve i
repacking.
Specifically, a contractor (Furmanite) would be on standby to inject the packing with sealant should an uncontrollable packing leak develop. However, this contingency t
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plan did not address a freeze seal failure when the bonnet was off the 1-QS-32 valve to repair the body-to-bonnet leak.
The licensee indicated that the bonnet would be quickly reinstalled and Furmanite would inject sealant to control the leak.
However, Attachment 1 to the contingency plan indicated that Na0H is
" corrosive to all body tissues, causes deep burns and ulcerations." The inspectors noted that it may be difficult to reinstall the bonnet when the corrosive Na0H solution from the CAT is draining through the valve bonnet opening.
On March 22, 1993, the licensee indicated to the inspectors that the Na0H solution at the concentration of the CAT would cause chemical burns only after
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skin contact for an hour.
I The licensee has a favorable record in the application of freeze
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seals. The subject freeze seal for the CAT was completed without
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incident. However, the licensee indicated that procedures for performing freeze seals in the future would be enhanced to provide more extensive considerations for contingency plans addressing
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freeze seal failures and associated industrial safety issues.
No violations or deviations were identified.
5.
Surveillance Observation (61726) - Units 1 and 2 The inspectors observed / reviewed TS required testing and verified that
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testing was performed in accordance with adequate procedures, that test
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instrumentation was calibrated, that LCOs were met and that any
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deficiencies identified were properly reviewed and resolved.
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a.
Hydrogen Recombiner Test On March 5 the inspectors witnessed testing of Hydrogen Recombiner 2-HC-HC-1.
Procedure 0-PT-68.1.2, Hydrogen Recombiner 2-HC-HC-1 i
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Functional Test is performed to meet the 6-month surveillance
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requirement of TS 4.6.4.2.a.
The procedure initially lines up the recombiner to the operating unit (Unit 2) containment and verifies an adequate flow. The inspectors noted flow to be about 21
percent as indicated on flow instrument FI-1.
The procedure then realigns the recombiner to the non-operating unit if applicable (Unit 1) to check heater sheath temperature greater than 700*F for
at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
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The inspectors noted initial flow to Unit I was higher (30%) due
to the containment being at atmospheric pressure.
Step 6.9.29 has i
the operator adjust inlet flow valve V-1 to obtain a flow rate of i
16-26%. The operator must leave the shielded operating panel'and i
operate V-i locally at the recombiner skid.
The recombiner
tripped on low flow 3 times while the operator was attempting to
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lower the flow rate.
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The inspectors noted that the procedure does not reposition V-1 and questioned whether the flow could be sufficient to preclude
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tripping when the recombiner is lined up for post accident
hydrogen removal to a sub-atmospheric containment..If the
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recombiner tripped on low flow, due to excess thrcttling of V-1, it may be impracticable to open V-1 because it is unshielded.
The inspectors noted that the operating procedure for post accident conditions directs that flow rate be adjusted with 2-HC-2, a
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supply valve, in series with V-1 and operated with a remote reach rod from a shielded area.
The operators indicated they would submit a procedure change to return V-1 to the fully open position
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and to control flow for testing purposes with 2-HC-2.
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inspectors considered this a test procedure weakness.
The inspectors also identified a discrepancy in meeting the TS surveillance for the purge blowers.
Specifically the TS states:
Each hydrogen recombiner system shall be demonstrated operable. at least once per 6 months by verifying during a recombiner system functional test that the minimum heater sheath temperature
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increases to a 700*F within 90 minutes and is maintained for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and that each purge blower operates for 15 minutes.
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The licensee has interpreted the " purge blower" to be the blower-
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contained within the hydrogen recombiner.
However, section 6.2.5.2 of the UFSAR describes the containment atmosphere cleanup system as consisting of two skid mounted hydrogen recombiners, two
hydrogen analyzers, two purge blowers and associated piping. The
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purge blowers are two fans separate from the hydrogen recombiners which take suction off the same piping penetration as the hydrogen
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recombiners. They discharge to the process vent system through charcoal filters to atmosphere.
The licensee is not testing the purge blowers in the manner
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described in the TS because of its previously mentioned interpretation. The licensee stated that their interpretation is
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based upon the fact that a portion of the purge blower flow path consists of non-Q piping and components and that there are no
automatic containment isolation valves which would be available to function during the test.
(It should also be noted that there are l
no automatic containment isolation valves for the hydrogen
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recombiners). The licensee also pointed out that TS 3.6.4.2 -
refers to the hydrogen recombiner system as opposed to the containment atmosphere cleanup system. The UFSAR also indicates
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that the purge blowers are backup equipment to the redundant hydrogen recombiners.
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The inspectors questioned the adequacy of this' interpretation and the basis for the TS surveillance with NRR.
The NRR Project
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Manager indicated that the interpretation appears incorrect and the licensee should amend the TS. Until the licensee clarifies the intent of the TS, this is identified as Unresolved Item I
50-338/93-10-03:
Clarification of Purge Blower Test Requirements.
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I b.
Containment Purge Valve Test and Maintenance
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On March 3, the inspectors witnessed type C testing for valve penetration No. 91 using 1-PT-61.3.5, Containment Purge Valve Type
C Test.
The procedure pressurizes the 36 inch containment purge
lines to 45 psig and maintains pressure while leakage past
1-HV-M0V-100B and 1-HV-MOV-102 outside containment purge isolation
valves is measured.
Leakage is detected by the amount of makeup
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air flow necessary to maintain pressure.
The makeup air flow is
measured by connecting a rotometer in line with the supply. The penetration is considered acceptable if total penetration leakage
is less than or equal to 11.0 SCFH.
The measured leakage was
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observed to be 1 SCFH with leakage determined to be through the inside containment isolation valve,1-HV-MOV-100A, which was also being pres:urized but in the non-accident flow direction. When
this valve was subsequently tested in the accident direction, test
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pressure could not be reached due to excessive leakage.
Following the unsuccessful test, the inspectors observed the licensee try to repressurize the valve in the non-accident direction, however, excessive leakage past the seating surface was again noted. The
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licensee could not explain the reason for the leakage since_it i
held pressure earlier that day. The valve test'was subsequently i
declared a type C failure with a leak rate of greater than 257
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SCFH which was the maximum capable measurement using the i
rotometer. Minimum pathway leakage for the penetration was zero.
Following maintenance, the inspectors reviewed the work package, which replaced the T-rings. The inspectors noted that NRC Inspection Report Nos. 50-338,339/91-14 identified a weakness involving maintenance procedures for the containment purge valves.
Specifically, guidance recommended in NRC Information Notice 88-73 and its supplement, Direction Dependent Leak Characteristics of Containment Purge Valves, was not incorporated into the
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maintenance procedures. The inspectors verified that the
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procedure used for T-ring replacement included the guidance given in the NRC Information Notice. The valve was subsequently tested
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for as-left Type C criteria with no leakage.
On March 10 the inspectors observed setup for type C as-found testing on 1-HV-M0V-1000. The inspectors identified that the l
packing on 1-HV-MOV-1000 had been tightened prior to the type C
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test, and would invalidate the as-found condition. Valve i
1-HV-MOV-100D is the outside containment isolation valve for piping penetration 90.
In the discussion with the operators, the
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inspectors were informed that maintenance on 1-HV-MOV-100C, the inside containment isolation valve, was also performed prior to
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the as-found test.
10 CFR 50, Appendix J, requires for type "C" test that:
"Each valve to be tested shall be closed by normal
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operation and without any preliminary exercising or adjustments."
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The inspectors reviewed the maintenance work orders and discussed with system engineers the condition described.
System engineers P
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agreed that adjusting the packing invalidated the outside isolation as found test, but stated that the maintenance on the inside containment valve did not effect the as-found condition.
The maintenance involved replacing the torque switch.
The engineers based their conclusion on the fact that these valves are manually closed prior to establishing containment vacuum and
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remained closed throughout the entire cycle.
When they are closed
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for the last time, leakage is measured between the inside and outside isolation valves and the valves are tightened by hand if necessary. After establishing acceptable leakage, the valves are
de-energized and locked. The licensee concluded that tightening the valve by hand is the normal closing mechanism and does not
effect the as-found condition. Therefore, replacing the torque
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switch would also not affect the as-found test.
t The inspectors discussed this issue with regional inspectors and concluded that the licensee explanation was reasonable but also noted that performing any maintenance prior to the as-found was not a good practice.
The licensee took the maximum penalty for the outside isolation valve, however, total penetration leakage
" minimum path" was zero. The inspectors reviewed the
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circumstances which allowed the maintenance.
Each maintenance
work order had a PMT test data sheet which listed pre-maintenance l
action.
For these valves, the data sheet was inadequate in that it incorrectly listed a PT which leak tested between the two i
valves but did not obtain type C as-found data.
Based on the inspectors questioning, a DR 93-486 was initiated to document the
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discrepancy.
The inspectors noted continued total low leakage rates for the type C tests.
This is reflective of good
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maintenance on type C valves.
c.
Quench Spray Pump Test On March 2, 1993, the inspectors observed the operability test of
the Unit 2 'B' quench spray pump (2-QS-P-1B).
The periodic test was performed in accordance with procedure 2-PT-63.1B, " Quench Spray System 'B' Subsystem." This test is performed at least
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every 3 months or following pump maintenance. The surveillance i
requirement is provided in TS 4.6.2.1.b.
The pump was tested in the recirculation mode with suction and discharge into the refueling water storage tank. A small' quantity
of pump discharge into the RWST was passed through test nozzles that were identical to those used in the spray ring to simulate a containment spray.
After the pump had been running for 5 minutes, pump operating data
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was collected. Technical Specifications require a pump discharge i
pressure greater than or equal to 123 psig. The measured pump discharge pressure was 138 psig.
The difference between the I
discharge pressure and the inlet pressure was measured at 117 psig. The total recirculation flow was measured at 1,596 gpm with
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sufficient flow to the test nozzles.
Pump operation, including vibration level, was found acceptable according to the licensee's procedures. After the test, the system was re-aligned for normal
operation.
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d.
Containment Integrity During Core On-load On March 15, the inspectors performed a walkdown of the Unit 1 I
piping penetration areas inside and outside containment. The
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inspectors verified selected containment penetrations were in a condition to support fuel on-load and as required by 1-PT-91,_
Containment Penetrations. The PT is the governing procedure for verifying integrity required for core alterations. The licensee had shown weakness in this area during the core off-load for this outage and during previous refueling outages. The licensee had established a task team to evaluate vulnerabilities in this area.
No discrepancies were identified by the inspectors and management-attention in this area appeared effective.
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One unresolved item was identified and is discussed in paragraph 5.a.
6.
Licensee Event Report Followup (92700) - Units 1 and 2 The following LER was reviewed and closed. The inspector verified that reporting requirements had been n.et, that causes had' been identified,
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that corrective _ actions appeared appropriate and that generic applicability had been considered. Additionally, the inspectors confirmed that no unreviewed safety questions were involved and that violations of regulations or T3 conditions' had been identified.
(Closed) LER 50-339/92-16:
Failure to Reset Condenser Air Ejector Reset Switches Following Safety Injection causes Potential Unmonitored Release Path to Turbine Building Atmosphere Due to Personnel Error. On August 13, 1992, while performing a Valve Inservice Inspection Test, valve 2-SV-TV-202-1 (Condenser Air Ejector Discharge to Containment Isolation Valve) failed to stroke (open).
.An. investigation showed that during the recovery from an August 6th safety injection event, the air ejector divert capability was not reset. _ As a result, a seal-in condition existed in the control circuits for both the Condenser Air-Ejector Discharge to Containment Isolation Valves. (2-SV-TV-202-1 and f
2-SV-TV-203) that prevented them from opening automatically on A/E exhaust High-High radiation readings. The electrical (manual) operation for the valves was also defeated until the seal-in relay was reset.
This condition rendered the A/E discharge capabilities to containment inoperable, and if an A/E exhaust High-High radiation event occurred, a potential existed for an unmonitored. release path to the turbine building via the. A/E after-condenser loop seals (A/E' backpressure would increase.over time and-displace the aftercooler loop seal, thus creating the release path).
This event was the result of personnel error due to the failure to
properly reset the A/E divert capability, and a lack of specificity in
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f the safety' injection termination procedure (ES-1.1). No significant l
safety consequences resulted;from this event since no High-High
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radiation alarm from the A/E exhaust was received and the normal discharge-path.was.in service and being monitored.
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.i Upon discovery of this condition, the licensee reset SI reset switches,
-i train A'and train B condenser A/E divert to containment, and tested the j
valves satisfactorily.
Procedures (ES-1.1,. Safety Injection;. A/P 5,
Attachment 3, Condenser Air Ejector Radiation Monitor; and A/P 24, Steam
Generator Tube Leak) were changed to be'more specific in the required j
action step (For example from, " Reset Air Ejector Divert Valves"-to
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" Place both Train A and Train B CNDSR AIR EJECTOR DIVERT TO CONTMT SI
RESET switches to RESET").
In addition, the licensee also included the
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event in the Modification and Experience training section of the l
Licensed Operator /STA Requalification Program for cycle 93-1, and the
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LER was included as required reading #92-108 for operation personnel.
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No violations'or deviations were identified.
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7.
Action on Previous Inspection Items (92701, 92702) - Units 1-and 2
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(Closed) Unresolved Item 50-338/93-08'-03: Containment Gas'eous and
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Particulate Radiation Monitor Operability During Refueling.
NRC
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Inspection Report Nos. 50-338,339/93-08 documented that radiation j
monitors RM-RMS-159 (particulate)- and. RM-RMS-160 (gaseous) become
inoperable whenever a containment.. air recirculation fan is not running..
.l These' monitors provide a containment purge and exhaust isolation signal j
and are required to be operable during Mode 6 operation's'with the i
containment purge and exhaust system isolation valves open.. The
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licensee identified that containment recirculation fans were not running i
during Mode-6 refueling operations from January 16 through January 20.
-l Further, this condition was-believed to have existed during past
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refueling outages.
After the condition was identified, corrective action was initiated by
training and revising operations backboard logs and operating
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l procedures. The inspectors reviewed UFSAR chapter 15 accident analysis
for a fuel handling' accident inside containment. The analysis shows-j that even with the containment purge and exhaust valves failing to close sj during 'a fuel handling event, the radiation doses' at the site boundary
'j are well below the allowable limits set-forth in 10 CFR 100. The event
was reported to the NRC by:LER 50-338/93-004 and.is a. violation. This i
violation will not be subject to enforcement action because the
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licensee's efforts in identifying and correcting the violation meet'the criteria specified in Section VII.B of the Enforcement Policy.
Non.
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cited. violation 50-338/93-10-04: ' Inoperable Containment. Purge and-i Exhaust Radiation Detectors.
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One non-cited violation was identified.
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8.
Exit (30703)
The inspection scope and findings were summarized on April 5, 1993, with those persons indicated in paragraph 1.
The inspectors described the l
areas inspected and discussed in detail the inspection results listed bel ow. The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection.
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Dissenting comments were not received from the licensee.
Item N_pmber Description and Reference
50-339/93-10-01 (URI) Inoperable NI Channel (paragraph 3.c)
50-339/93-10-02 (IFI) RCP Flange Leak (paragraph 3.g)
50-338/93-10-03 (URI) Clarification of Purge Blower Test Requirements (paragraph 5.a)
50-338/93-10-04 (NCV) Inoperable Purge and Exhaust Radiation l
Detectors (paragraph 7)
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Acronyms and Initialisms A/E Air Ejector
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CAT Chemical Addition Tank
CFR Code of Federal Regulations
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DR Deviation Report.
ECCS Emergency Core Cooling System EDG Emergency Diesel Generator E0P Emergency Operatioq Procedure i
ESF Engineered Safety hature GPM Gallons Per Minute HHSI High-Head Safety Injection HPES Human Performance Evaluation System
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I&C Instrumentation and Control
ICP Instrument Calibration Procedure IFI Inspector Follow Up Item
JC0 Justification for Continued Operation LER Licensee Event Report
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LHSI Low Head Safety Injection LCO Limiting Conditions for Operation
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LOCA Loss of Coolant Accident
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MPH Miles Per Hour NCR Non-Conformance Report NI Nuclear Instrument
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NaOH Sodium Hydroxide NCV Non-Cited Violation
NRC Nuclear Regulatory Commission NRR Nuclear Reactor Regulation
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OP Operating Procedure i
OTAT Overtemperature Delta Temperature
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PAR Procedure Action Request
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PSIG Pounds per Square Inch Gage
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PT Periodic Test P
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i RCP Reactor Coolant Pump RPS Reactor Protection System RWST Refueling Water Storage Tank-SCFH Standard Cubic Feet per. Hour SGRP Steam Generator Replacement Project SI Safety Injection SNSOC Station Nuclear Safety and Operating Committee STA Shift Technical Advisor
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TS Technical Specification
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TSC Technical Support Center UFSAR Updated Final Safety Analysis Report URI Unresolved Item
VCT Volume Control Tank WO Work Order t
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