IR 05000397/1991035
| ML17286B175 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 11/21/1991 |
| From: | Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17286B173 | List: |
| References | |
| 50-397-91-35, NUDOCS 9112100074 | |
| Download: ML17286B175 (34) | |
Text
U.
S.
NUCLEAR REGULATORY COHYISSION REGION V
Report No:
Docket No:
Licensee:
Facility Name:
Inspection at:
50-397/91-35 50-397 Mashington Public Power Supply System P. 0.
Box 968 Richland, hA 99352 h'ashington Nuclear Project No.
2 (h'NP-2)
h'NP-2 site near Richland, Washington Inspection Conducted; September 18 - October 22, 1991 Inspectors:
R.
C. Sorensen, Senior Resident Inspector D. L. Proulx, Resident Inspector R.
C. Barr, Senior Resident Inspector (Trojan)
(October 15 - 18, 1991)
Approved by:
o nson, ie Reactor Projects Section
g d
Summary:
Ins ection on Se tember 18 - October 22, 1991 50-397/91-35
~AI:
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h room operations, reactor startup, licensee action on previous inspection findings, operational safety verification, surveillance program, maintenance program, licensee event reports, special inspection topics, procedural adherence, and review of periodic reports.
During this inspection, Inspection Procedures 61702, 61705, 61706, 61707, 61715, 61726, 62703, 71707; 71711, 90712, 90713, 92700, 92701, and 93702 were utilized.
Safet Issues Mana ement S stem
{SINS Items; None.
Results:
General Conclusions and S ecific Findin s
Si nificant Safet Matters:
None.
Summar of Yiolations and Deviations:
One violation was identified, involving failure to follow the plant startup procedure.
Two non-cited violations (one licensee-identified and one NRC-identified) were also noted, as discussed ir paragraph 9.
These violations are not being cited because the criteria in Sections V.A and Y.G of the Enforcement Policy were satisfied.
9112100074 9lgi2l PDR ADOCl( 05000397 G
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Two unresolved items were identified.
One involves inspection observations reoardina the containment atmospheric control (CAC) system (paragraph 7.c).
The second item involves the procedure used to normalize the traversing in-core probe (paragraph 11).
0~en Items Summer One followup item and three LERs were closed.
Three new items were opene kj j f
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,
Persons Contacted DETAILS
- L. Oxsen, Deputy Managing Director
- D. Bouchey, Director, Licensing and Assurance
- J. Baker, Plant Manager
- L. Harrold, Assistant Plant Manager
- R. Graybeal, Health Physics and Chemistry Manager
- R. Webring, Plant Technical Manager J.
Harmon, Maintenance Manager A. Hosier, Licensing Manager
- S. Davison, Ouality Assurance Manager R. Koenigs, Generation Engineering Manager S. McKay, Operations Nianager J. Peters, Administrative Manager G. Gelhaus, Assistant Technical Manager W. Shaeffer, Assistant Operations Manager
- D. Feldman, Assistant Maintenance Manager
- J. Schnell, Supervisor, Administrative Procedures
- N. Reis, Supervisor, Compliance The inspectors also interviewed various control room operators, shift supervisors and shift managers, and maintenance, engineering, quality assurance, and management personnel:
- Attended the Exit Meeting on October 22, 1991.
2.
Plant Status 3.
At the start of the inspection period, the plant was still in cold shutdown while completing retraining and reexamining of licensed operators.
The reactor was restarted on September 26.
Node 1 was achieved on September 30, but the plant was again shut down on October
to repair a number of steam leaks.
The reacto~
was restarted on October 3, and the plant achieved 100% power on October 11.
At the end of the inspection period, the plant was at 100K power.
Previousl Identified NRC Ins ection Items 92701 92702)
The inspectors reviewed records, interviewed personnel, and inspected plant conditions relative to licensee actions on previously identified inspection findings, as follows:
~(Closed Followu Item 50-397/90-09-0I
- Procedures to Siitioate a Slow Reactor Pressure Vessel De ressurization Event During an NRC administered requalification examination for licensed operators, NRC examiners noted an absence of a procedure for mitigating a
slow reactor depressurization initiated by malfunction of a balance-of-plant system, During the restart assessment conducted from August 22 to September 25, NRC examiners reviewed objective evidence that the licensee had
0
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impl.emented procedure PPY 4.2. I. 14, "Inadvertent Reactor Depressuriza-tion," to mitigate this event.
This procedure appeared to adequately mitigate a turbine generator hydraulic control system failure, or the failure of a steam bypass valve.
This item is closed'otential Problems Identified k'ith Scram Pilot Valves Scram pilot valves (SPVs) for hydraulic control units (HCUs) are solenoid valves, supplied by the Automatic Switch Company (ASCO).
ASCO also provides kits for refurbishing these SPVs, Two such kits were supplied to the Yiillstone Station with oversized core assembly needle hole diameters.
This caused two control rods to fai 1 the Technical Specification scram time limit and six others to have slow scram times.
The inspector questioned cognizant members of the Plant Technical staff as to the possibility of such an occurrence at WNP-2.
This problem was first identified at the Vermont Yankee plant in 1986.
General Electric had issued a service information letter (SIL) at that time to document the existence of this problem, as well as others, with the ASCO rebuild kits.
The SIL also alerted other licensees to these problems and provided a
number of recommendations for identifying them in the rebuild kits on the shelf.
However, the SIL noted that the only truly effective way of determining proper valve operation is to conduct scram time testing while the reactor is at power.
WNP-2 has implemented the recommendations of the SIL.
All rebuild kits on the shelf were examined in accordance with the recommendations of the SIL and a number of discrepancies were identified.
All rebuild kits that are received from ASCO are still examined per the recommendations of the SIL.
All 370 SPVs were refurbished during the 1990 refueling outage.
All were bench tested prior to reinstallation and single rod scram tests were conducted with the reactor in cold shutdown.
In addition, all control rods successfully passed their scram time tests with the reactor at power.
The inspector revipwed the most recent scram time test data, compiled from tests conducted on October 6, 1991, and noted that all scram times were less than three seconds, well within the Technical Specification acceptance criterion of seven seconds.
No violations or deviations were identified.
Review of Maintenance Personnel Oualifications 62703 The inspector reviewed the licensee's program for training and qualification of maintenance personnel as described i,n the licensee's Technical Training Nanual.
The inspector also observed the licensee's implementation of the training and qualification program.
The inspector noted that the maintenance training program, a licensee initiative encouraged by the training accreditation process, is a three-phase program that is tailored to each maintenance discipline.
Phase I
of the program is initial training designed to train personnel on funda-mental skills and knowledge necessary to perform general maintenance
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tasks.
Phase 11 is continuing training, used as a periodic refresher or to keep the maintenance staff apprised of procedure changes or lessons learned from operating events.
Phase III is specialized training, designed to ensure that adequate numbers of maintenance personnel are trained to work on equipment requiring specialized skills and knowledge.
For each discipline, a list of equipment had been developed that requi res Phase III qualification for work to be performed on it.
The Phase 111 training i's either in the form of classroom lectures or supervised on-the-job training.
Each Maintenance Work Request (MWR) contains a step.
for indicating if a particular job requi res specific training (i.e.,
Phase III training) for that activity to be performed.
A tracking mechanism is utilized by the maintenance training department to track the Phase I, II, and III qualification of each person in the maintenance department.
A formal waiver process was in place to allow waiving these requirements for persons found knowledgeable and experienced in certain areas.
The inspector selected for review the Phase III list of equipment for electricians.
ITT Hydromotors, a type of valve operator, were selected from the Phase III list to determine whether the licensee was utilizing qualified individuals to perform maintenance activities.
This type of valve operator is located on.many valves in the Containment Atmospheric Control (CAC) system.
The inspector reviewed the qualification list for ITT Hydromotors and determined that according to the list, which was current per the maintenance training staff, no one in the electric shop was qual.ified to work on ITT Hydromotors.
Further, the inspector noted that work was in progress, or had recently been completed, on several valve operators of this type.
The work involved on these valve operators was substantial, and would indicate that qualified individuals were important to conduct it.
However, the applicable MWR blocks had been checked off to indicate that no specific training was required for these jobs, even though the Phase III listing of equipment indicated that it was.
No class had yet been developed and, apparently, no waiver process had been undertaken for the individuals conducting the work.
The inspector did determine that the individuals were qualified in accordance with the licensee's Technical Specification committment to ANSI N18. 1-1971 "Selection and Training of Nuclear Power Plant Personnel".
While the maintenance training program was recognized to be a licensee initiative, this issue was brought to the attention of maintenance management.
The Maintenance Manager agreed with the inspector that the specific trainino block of the MWR should have been checked
"yes," and that only qualified persons should be working on equipment indicated by the licensee's program to require Phase III training.
In addition, the inspector discussed with maintenance management the practice of aliowinq supervisors to siqn off work completion steps of Yk'Rs.
Specifically, maintenance management indicated that it was not inappropriate for a supervisor to sign off for completed work steps on an MWR that required Phase 111 qualification, even if the supervisor was net Phase III qualified in that area.
However, this was not well established as being appropriate in PPM 1.3.7,
"Maintenance Work Request."
Maintenance management stated that they would consider enhancino the
guidance in PPYi 1.3.7 to specifically allow such a practice, to document their expectations regarding when this'practice is appropriate and the proper methodology for accomplishing it.
No violations or deviations were identified.
6.
0 erational Safet Verification {71707 a.
Plant Tours The following plant areas were toured by the inspectors during the course of the inspection:
Reactor Building Control Room Diesel Generator Building Radwaste Building Service Mater Buildings Technical Support Center Turbine Generator Building Yard Area and Perimeter b.
The following items were observed during the tours:
( 1)
0 eratinq Lo s and Records.
Records were reviewed against
= Technical Specification and administrative control procedure requirements.
(2)
Yonitorin Instrumentation.
Process instruments were observed for correlation between channels and for conformance with Technical Specification requirements.
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for conformance with 10 CFR 50.54(k), Technical Specifications, and administrative procedures.
The attentiveness, of the operators was observed in the execution of their duties, and the control room was observed to be free of distractions such as non-work related radios and reading materials.
{4)
E ui ment Lineu s.
Valves and electrical breakers were veri ied to e in the position or condition required by Technical Specifications and administrative procedures for the applicable plant mode.
This verification included routine control board indication reviews and conduct of partial system lineups.
Technical Specification limiting conditions for operation were verified by direct observation.
(5)
E ui ment Taqoinq.
Selected equipment, for which tagging requests a
een initiated, was observed to verify that tags were in place and that the equipment was in the condition specified.
P ~E.
observed for indications of system leakage, improper
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lubrication, or other conditions that could prevent the system from fulfillingits functional requirements.
Annunciators were observed to ascertain their status and operability.
(7)
Fire Protection, Fi refighting equipment and controls were
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Plant Chemistr
.
Chemical analyses and trend results were reviewe or conformance with Technical Specifications and administrative control procedures.
(9)
Radiation Protection Controls, The inspectors periodically o served rad>o og)ca protect>on practices to determine whether the licensee's program was being implemented in conformance with facility policies and procedures and in compliance with regulatory requirements.
The inspectors also observed compliance with Radiatiors Mork Permits, proper wearing of protective equipment and personnel monitoring devices, and personnel frisking practices.
Radiation monitoring equipment was frequently monitored to verify operability and adherence to calibration frequency.
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111 storage were observed to determine the general state of clean-liness and housekeeping.
Housekeeping in the radiologically controlled area was evaluated with respect to controlling the spread of surface and airborne contamination.
(11) ~Securit
.
The inspectors periodically observed security practices to ascertain that the licensee's implementation of the security plan was in accordance with site procedures, that the search equipment at the access control points was opera-tional, that the vital area portals were kept locked and alarmed, and that personnel allowed access to the protected area were badged and monitored and the monitoring equipment was functional.
En ineered Safet Feature Malkdown Selected engineered safety features (and systems important to safety)
were walked down by the inspectors to confirm that the systems were aligned in accordance with plant procedures.
During walkdown of the systems, items such as hangers, supports, electrical power supplies, cabinets, and cables were inspected to determine that they were operable and in a condition to perform their required functions.
Proper lubrication and cooling of major components were observed for adequacy.
The inspectors also verified that certain system valves were in the required position by both local and remote position indication, as applicable.
Accessible portions of the following systems were walked dowr on the indicated date lj H
~Ss tern Diesel Generator Systems, Divisions 1, 2, and 3.
Hydrogen. Recombiners Low Pressure Coolant Iniection (LPCI)
Trains "A", "B", and "C" Low Pressure Core Spray (LPCS)
High Pressure Core Spray (HPCS)
Reactor Core Isolation Cooling (RCIC)
Residual Heat. Removal (RHR), Trains II All a nd IIB II Scram Discharoe Volume System Standby Liquid Control (SLC) System Standby Service Pater System 125Y DC Electrical Distribution,'ivisions
and
250V DC Electrical'istribution'
Dates October 2, 9,
October 3, 10,
October 2,
October 2,
October 2,
October 2,
October 2,
October 2, 9,
October
October
October
October
No violations or deviations were identified.
7.
Surveillance Testin (61726
'a
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Surveillance tests requi red to be performed by the Technical Specifications (TS) were reviewed on a sampling basis to verify that:
( 1)
a technically adequate procedure existed for performance of the surveillance tests; (2) the surveillance tests had been per-formed at the frequency specified in the TS and in accordance with the TS surveillance requi rements; and (3) test results satisfied acceptance criteria or were properly dispositioned.
b.
Portionls of the following surveillance tests were observed by the inspectors on the dates shown:
Procedure 7.4.4.2.1.2 7.4.6.4.1.2 Oesc~ri tion Safety/Pelief Valve (SRV)
Acoustic Monitor Channel Check and SRV Operability Suppression Pool/Drywell Vacuum Breaker Operability Dates Performed October
October
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7.4.6.6.1.1 Containment Atmospheric Control September
(CAC) System Operability {Oper-ability Check of CAC-TCY-4A)
7.4. 1.4. 1. 1 Rod Worth Minimizer (RWN)
Precritical Check September
7.4. 1.4.2.
{RSCS) Operability September
C.
During performance of the September 26 surveillance on CAC-TCV-4A, just prior to plant startup, the inspector noted a 3/4 inch hex nut on the floor of the "A" CAC skid near CAC-TCY-4A. It was part of CAC piping restraint PS-5, which the inspector noted was not installed properly.
This restraint was apparently disassembled for work on CAC-TCV-4A, although the NWR that authorized work on this valve did not authorize removal of PS-5.
The inspector informed the equipment operator who was performing the surveillance, and the Shift Manager, who indicated that mechanical maintenance would restore PS-5 to its proper configuration.
Reexamination of PS-5 on October 2 and 9 indicated that the observed discrepancy had not been corrected.
During further inspection, the inspector identified seven other deficiencies in CAC supports, and licensee inspections prompted by these findings identified nine others.
This issue is unresolved, and will be addressed further during a future NRC inspection (Unresolved Item 397/91-35-01).
8.
Plant Maintenance 62703 During the inspection period, the inspector observed and reviewed documentation associated with maintenance and problem investigation activities to verify compliance with regulatory requirements and with administrative and maintenance procedures, required QA/QC involvement, proper use of clearance tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspector verified that reportabi lity for these activities was correct.
The inspector witnessed portions of the following maintenance activities:
Descri tion Dates Performed Lift Bearinq and Realign DO-P-2 (AR-4999)
Troubleshoot CAC-EHO-TCV/4A (AP-58O1)
Ho violations or deviations were identified.
September
September
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9.
Plant Startu from Refuel in 71711 The inspectors monitored activitie s associated with startup of the reactor for operating cycle 7, to ensure that the licensee was in compliance with the Technical Specifications arid other applicable t~RC requirements.
This included reviews of procedures, interviews with personnel, plant tours, and sustained observations of personriel perform-ance in the control room.
The inspector determined the licensee's performanc'e to be generally good, conservative, and directed toward safe operation, althouoh deficiencies were also noted.
The inspector reviewed procedures PPM 3. 1. 1 (IIaster Startup Checklist),
and PPY 3. 1.2 (Plant Startup from Refueling) for technical adequacy, and monitored the licensee's performance of these procedures.
The inspector performed an independent verification of a 25K sampling of the items signed off as complete on the master startup checklist.
No deficiencies were noted.
During performance of the RSCS and RVM checks listed in paragraph 7.b above (just prior to taking the reactor critical) the inspector noted that Technical Specifications Section 3.4. 1.1 states, in part:
"Two reactor coolant system recirculation loops shall be in operation."
Applicability':
Operational Conditions
and 2.
Action:
a.
With one reactor coolant system recirculation loop not in operation:
1.
Verify that the requirements of LCO 3.2.6 and LCO 3.2
are met, or comply with the associated action statements.
2.
Verify that Thermal Power'/core flow conditions lay outside of Region B of Figure 3.4. 1. 1-1."
The licensee entered into Operational Mode 2 (Startup)
and withdrew control rods for the above survei llances with one reactor coolant recirculation loop in operation, but did not verify the required actions as stated in the above action statements.
The inspector further noted that despite the extensive 'oversight presence in the control room during the occurrence, no Supply System personnel questioned the startup procedure or the operators'ctions.
The inspector pointed out this deficiency to the licensee, who was unaware that this action constituted entry into Operational Condition 2.
Furthermore, since plant admini-strative procedures allow operators to perform certain procedure steps out of sequence if plant condi tions permit, the operators apparently believed that they had the latitude to start the second recirculation pump any time prior to pulling control rods for the purpose of attaining
. criticality.
This was noteworthy because if the procedure steps had been followed in the order stated in PPM 3. 1.2, this problem would not have occurred'.
Althouoh the operators did not take credit for, nor.verify, the action statements listed above, the actual plant conditions met the criteria described in the applicable action statements.
Subsequent to notifica-tion of this problem, the licensee promptly amended the Plant Startup procedure to specify the conditions that constitute entry into Mode 2, and to require two recirculation loops to be in operation for entry into Mode 2.
Because nf the minimal safety significance of this apparent Severity Level V violation, and because the licensee took prompt corrective actions, this violation meets the criteria in 10 CFR
Appendix C,Section V.A for a non-cited violation, and will not be cited
'NCV 397/91-,35-02).
After achieving criticality, heating up, and performing walkdowns of the drywell, the licensee was.requi red by the Technical Specifications and
.PPM 3. 1.2 to perform a containment air lock test within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of closing the drywell.
Despite the procedural guidance, the licensee did not perform the airlock test until approximately 95 hours0.0011 days <br />0.0264 hours <br />1.570767e-4 weeks <br />3.61475e-5 months <br /> had elapsed after closing of the drywell, exceeding the allowable TS surveillance interval by more than 25K.
This was determined by the licensee to be an operator error.
Plant procedures were modified to emphasize the import-ance of ensuring that the airlock test is performed within the required time period.
The licensee's review initially concluded that the event, a
late surveillance test, was not reportable to the NRC pursuant to 10 CFR 50.73.
The inspector noted that NUREG 1622,
"Licensee Event Reporting System,"
and the Bases section for TS 4.0.2 clearly stated that technical specification surveillance tests not performed within their allowable time constraints are reportable.
The licensee subsequently reported this event to the NRC as an LER.
The inspector noted that failure to perform the airlock test within the time required constituted a violation of Section 4.6.1.3 of the Technical Specifications.
However, this licensee-identified violation is not being cited because the criteria,in Section V.G of the Enforcement Policy, including licensee corrective actions, were satisfied (Non-cited violation 91-35-03).
One other issue arose during the plant startup process.
PPM 3. 1.2, paragraph 4.21 stated:
"MS-V-16, MS-V-19, and YS-V-67A, B, C, D shall be closed whenever reactor power is GE I greater than or equal to] 55 to prevent potential iodine release during accident conditions.
These valves shall remain closed until the reactor is in Mode 4, unless either of the following exceptions are in effect:
Directed otherwise by Emergency Operating Procedures, or these valves are required to be opened to equalize pressure across the MSIV's following a scram."
The intent of the requirement to not reopen these valves until after Mode 4 entry stemmed from engineering calculations which determined that the main steam line drains could only endure a finite number of thermal
However on September 29, ]99}, MS-V-16 and MS-V-19 were reopened at 3.7X power, prior to entering Mode 4 (Cold Shutdo
).
valves had been previously closed before reactor power was increased to greater than 5N.
This is an apparent violation of the Technical Specifications, Section 6.8. 1.
(Violation 397/91-35-04)
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The inspector informed the licensee of this discrepancy.
A Problem Evaluation Request'PER)
was generated to document this occurrence and to determine the intent of the procedure requirement.
Subsequently, a
procedure deviation was issued to allow these main steam line drains to be reopened below 5~ power, as long as each of these reopenings with the reactor at normal operating conditions is documented on a
PER to keep track of the number of thermal cycles on the main steam line drain
'iping; The plant was shut down on October 1,
1991 to make minor repairs, and was subsequently restarted on October 3, 1991.
Startup and power ascension were otherwise uneventful after that time.
Other inspection activities performed during startup and power ascension are discussed below.
Determination of Reactor Shutdown Nar in 61707 The inspector reviewed licensee procedures for determination of reactor shutdown margin and reactivity anomaly (PPNs'7.4. 1. 1 and 7.4. 1.2 respec-tively).
The inspector determined that these procedures complied with the recommendations of the vendor manuals and were performed at intervals required by the Technical Specifications.
The inspector also performed independent calculations of shutdown margin and reactivity anomaly after the'eactor achieved criticality.
The inspector's results agreed with those of the licensee.
PPN 7.4.1.1 depended largely on reactivity values at various control rod positions, as provided by the vendor's
"Startup and Operations Letter Report."
This document provided reactivity values based on reactor coolant temperatures of 60F or 180F.
However, PPM 7.4.1. 1 provided no directions on how to determine the shutdown margin at temperatures between these two values.
The shift technical advisor (STA) was initially unsure of which value to use since the reactor coolant temperature was 129F when PPM 7.4. 1. 1 was performed.
The STA decided to interpolate the reactivity values based on the values in the vendor document and the existing reactor coolant temperature.
This appeared to be an appropriate course of action.
However the inspector informed licensee management of this observation, and the licensee committed to revise PPN 7.4. 1. 1 to provide direction on interpolating vendor data.
No violations or deviations were identified.
Incore/Excore Detector Calibration 61705 The inspector evaluated the licensee's process for calibrating the Local Power Range Monitors (LPRNs) using the Traversing Incore Probe (TIP) to ascertain if the licensee's program for this evolution was in compliance with the Technical Specifications and followed the re'commendations of vendor manuals.
This evaluation consisted of procedure review, inter-views with personnel, and witnessing of control room activities.
On October 7, 1991 the inspector noted that an apparently inexperienced member of the Plant Technical staff was operating the TIP machine without a copy of the procedure present.
This staff member had been given verbal direction on operation of the TIP machine by the STA.
However, when
questioned by the inspector, he could not identify the proper procedure for operation of the TIP, nor could he recall any of the precautions or prerequisites for TIP operation.
This condition was reported to the Shift Yanager, who requested to the Technical Staff that inexperienced personnel use PPN 2. 1.3 (TIP Operation),
or he under the direct supervision of an STA.
Upon review of PPN 9.3.3 (LPRN Calibration), the inspector determined that the 1'icensee's procedure was substantially in agreement with the vendor recommendations and the technical specifications.
However, one apparent discrepancy existed between PPN 9.3.3 and Technical Specifica-tion (TS) 4.3.7.7.
TS 4.3.7.7 states,
"The traversing in-core probe shall be demonstrated operable by normalizing each of the above required detector outputs within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> ~rior to use for the above applicable monitoring or calibration functions.
The action statement for TS 3.3.7.7 states, in part,
"With the traversing in-core probe system inoperable, suspend use of the system...."
PPN 9.3.3, paragraph 5.5, stated, in part,
"PPN 7.4.3.7.7 [the TIP normalization procedure]
is only required once as the final step of this procedure,"
Furthermore',
step 6.1.11 of the procedure directed the user to perform this surveillance after use of the TIP for data acquisition, apparently conflicting with the above TS requirement.
Discussions with Plant Technical personnel revealed that the licensee interprets this TS to mean that as long as they do not consider the LPPNs calibrated until 7.4.3.7.7 is performed, they are meeting the intent of the TS.
They stated that the hardwar'e and software for accomplishino TIP normalization and LPRN calibration were changed several years ago.
They also conceded that it may have been appropriate to amend the TS at the time the new computer code was implemented, to clarify how the TIP normalization would actually be accomplished.
The inspector noted that
CFR 50.59 requires prior NRC approval of such design changes if they entail a TS amendment.
This issue remains unresolved (Unresolved Item 397/91-35-05).
Surveillance of Core Power Distribution Limits 61702 The inspector examined the licensee's program for monitoring core power di stribution limits to ascertain whether the licensee was in compliance with TS requirements and the recommendations of vendor manuals.
The inspector determined that the power distribution limits were properly analyzed, and are monitored with a frequency commensurate with the TS.
In addition, the inspector veri fied that the licensee's procedure provided di rection for the user to ensure that the Leading Fuel Assemblies (LFAs) did not contain the highest nodal power in the core.
The inspector also reviewed three daily process computer printouts and verified that the power distri bution parameters were within the TS limits.
On October 6, 1991 with the reactor at 30~ power, the licensee obtained a
thermal limits printout that indicated that several of the power distribution parameters were above their TS limits.
The operators took conservative action, and reduced reactor power to below 251. (thermal limits do not apply below 25% power) until the problem was resolved.
The licensee found errors in their implementa'tion of a new computer code, vihich were corrected.
Reactor power was subsequently increased and the
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thermal limits were verified to be within the Technical Specifications limits.
No violations or deviations were identified'.
Core Thermal Power Evaluation (61706 The inspector reviewed the licensee's process for determining core ther-mal power.
The inspector verified that licensee procedure PPM 9.3.1,
"Manual Core Heat Balance,"
was developed according to the guidelines of the vendor manuals.
The inspector noted that three processes are available for determining core thermal power.
The plant process computer (PPCRS)
continuously calculates reactor power via direct signals from detectors that monitor the various parameters.
In the event th'at the PPCRS is not available, the STA can calculate core thermal power by manually inputting the required parameters (obtained from control room indications) into a personal computer.
The third option available involves hand calculation of 'core thermal power using PPN 9.3. 1 and a set of steam tables.
The STAs demonstrated strong technical knowledge of all of these methods.
The inspector performed a manual calculation of core thermal power using the licensee's procedure.
The inspector's calculated results agreed with the thermal power calculated by the PPCRS, In the process, the inspector noted a minor procedure error in PPM 9.3. 1.
This error was pointed out to licensee representatives who indicated that the procedure would be corrected accordingly.
To verify the accuracy of the core thermal power calculation, the inspector reviewed the Scheduled Maintenance System (SMS) printout for calibration frequencies for the instruments that provide input to the thermal power code.
All of these instruments were noted to have specific calibration frequencies, and were in calibration.
No violations or deviations were identified.
Verification of Containment Inteqrit 61715 During the inspection period, the inspector observed and examined activities to verify the licensee had established containment integrity when required.
The insp'ection included selected examination of contain-ment integrity surveillance procedures and tests, design documents, and walkdowns of a primary and secondary containment support system, To check containment integrity, the inspector observed the position of 20 separate containment penetration mechanical barriers or isolation valves.
The inspector found that all the barriers and isolation valves were correctly positioned.
The inspector verified that the barriers and isolation valves for the 20 containment penetrations observed met
CFR Pzrt 50, Appendix A, General Design Criteria (GDC) 55, 56 and 57.
The inspector verified that the licensee performed a monthly aligrment check of each penetration that is required to be closed for a design basis accident and is not capable of heing closed by automatic isolatio II
l
The inspector also verified these checks were performed each 92 days when the facility was in cold shutdown.
The inspector reviewed the results of licensee-conducted surveillance testing for all containment penetrations that require Type B and Type C
leak tests.
The inspector found the testing had been performed in accordance with licensee procedures and that the combined Type B and C
leakages were.within the requirements of technical specifications.
The inspector identified tv o weaknesses and one strength in the licensee's performance and evaluation of these tests.
The inspector found that the responsible licensee system engineer had developed a data base of the previous Type B and C test results.
The system engineer evaluated the data after each test performance to identify trends of increasing leakage rates or recurring failures.
The inspector considered this practice a strength.
The inspector found that the licensee performed Type B and C leak rate tests using one of two methods:
the pressure decay method or the constant flow method.
The constant flow method determined leak rate by measuring the equilibrium value of a supplied fluid, either nitrogen or air, that was necessary to maintain a constant pressure.
The inspector noted that approximately six of these Type C tests resulted in negative leakage rates, an apparently invalid result.
One of these negative leak rates was also apparently in error by greater than the accuracy of the leak measuring equipment.
Through discussions with the syst'm engineer, the inspector learned that when licensee'personnel expected isolation valves to have small leak rates, a known leak was imposed in the air supply.
The licensee would then calculate the leakage by subtracting known leakage from the total makeup flow. It was necessary for the licensee to impose a
known leak due to the leakage measuring equipment's difficulty in accurately measuring leakages of between 0 and 20 cc/min..
Because the total Type B and C leakage was less than one-half of the technical specification limit, the potential errors created by these inaccurate leak rate measurements appeared not to be safety significant.
However, the inspector questioned whether the licensee should have a
lower limit for acceptance leak rate test results (e.g.,
no negative leak rates).
The inspector discussed this weakness with the system engineer and licensee management.
Licensee management committed to change procedures and establish lower-limit acceptance criteria for Type B and C
test results.
During the review of Type B and C leak rate data, the inspector evaluated the results of the licensee's calculation for secondary containment bypass leakage.
The licensee's safety analysis (FSAR section 6.2.3.3.2)
assumed maximum secondary containment bypass leakage of 349.2 standard cubic centimeters per minute (sccm).
The inspector found that the licensee calculated secondary containment bypass leakage by assuming a
single failure of the containment isolation valve with the greatest leakage, concurrent with inoperability of one train of containment isolation valves due to the loss of an emergency diesel generator.
Although the licensee considered this calculation method conservative, the method was different from the maximum pathway leakage method called out by Appendix
~~ of 10 CFR 50.
Discussions the inspector had with the
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cognizant Nuclear Reactor Regulation engineer led'to the conclusion that the licensee's approach was satisfactory.
However, to provide additional clarity, the licensee committed to change surveillance procedure 7.4.6. 1.2.4,
"Containment Isolation Valve and Penetration Leak Test Program," to clearly define the criteria for calculating secondary bypass leakage.
'
The inspector, reviewed the results of the most recent licensee surveil-lance of the primary containment personnel airlock seals.
The inspector found that the surveillance test met Technical Specifications require-ments; however, the licensee did not perform the surveillance within the time limits required by, the Technical Specifications.
The licensee had previously identified and documented this as a deficiency in their prob-lem reporting program.
The licenske's evaluation of the reportability of this event is discussed in paragraph 9 of this inspection report.
The inspector conducted a walkdown of the Standby Gas Treatment System (SGTS),
and found all SGTS valves to be correctly positioned.
The inspector identified three potential deficiencies:
an inoperable supply air temperature indicator on the A train of SGTS, a long-standing technical evaluation request (TER),
and lack of verification of drain line flow.
The supply temperature instrument, located in the control room, for the 8 train of SGTS was pegged low (50 degrees F).
The inspector noted that this condition had existed for several weeks.
Licensee investigation found that the circuit card for this instrument was not fully engaged.
The inspector reviewed licensee electrical diagrams and found that the indicator provided no control function for the SGTS; therefore, the inoperability of the instrument had no safety significance.
The A train of the SGTS had two deficiencies, documented in TER 87-106, which were identified in 1987 and had not yet been corrected.
The deficiencies dealt with operation of SGTS heaters and alarms.
In discussion with the licensee's cognizant system engineer, the inspector found that during the 1991 refueling outage one of the deficiencies, had been corrected and the deficiency tag had not been removed.
The system engineer was not aware of the other deficiency and committed to research its status.
Upon initial evaluation, the outstanding deficiency did not appear to impact the ability of the SGTS to perform its safety function.
In reviewing SGTS design documents and surveillance procedures, the inspector noted that drain lines which remove condensed moisture from the SGTS moisture separators had not been verified to flow freely.
Clogging of these drain lines could cause a backup of water and possibly result in SGTS inoperability.
At the exit meeting, the licensee committed to determine whether the drain lines had been previously verified free-flowing and to change procedures to conduct periodic verification of drain line status.
As a result of this inspection, the inspector concluded that the licensee met Technical Specifications requirements for containment integrit,
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Generally, the licensee's program for assuring containment integrity was adequate.
However, inspection findings indicated a need for improved operator attention to instrument status and. more thorough licensee review of leak rate testing results.
ho violations or deviations were identified.
15.
Licensee Event Re ort LER Followu (90712, 92700 The following LERs associated with operating events were reviewed by the inspector.
Based on the information provided in the report, it was concluded that reporting requirements had been met, root causes had been identified, and corrective actions were appropriate.
The below LERs are considered closed.
LER NUYiBER DESCR'IPTION Control Room Emergency Filtration and SGTS Carbon Adsorbers not in Compliance with Technical Specifications 91-23 91-26 HPCS Pump Suction Valve Switchover Actuation During Testing Reactor Mater Cleanup (RMCU) 'System Isolation Due to Failed Component In Leakage Detection System
~ No violations or deviations were identified, 16.
Review of Periodic and S ecial Re orts 90713 Periodic and special reports submitted by the licensee pursuant to Technical Specifications 6.9. 1 and 6.9.2 were reviewed by the inspector.
This review included the following considerations:
the report contained the information required to be reported, and the reported.information appeared valid.
Mithin the scope of the above, the following reports were reviewed by the inspectors.
Monthly Operating Report for August, 1991.
No violations or deviations were identified.
17.
Unresolved Item Unresolved items are matters about which the NRC plans further inspection or requires additional information to determine whether they are viola-tions, deviations, or acceptable i tems.
Two unresolved items identified during this inspection are discussed in paragraphs 7.c and 1 i, t
"
Exit Yieetino The inspectors met with licensee management representatives periodically during the report period to discuss inspection findings and status, and an exit meeting was conducted with the indicated personnel (refer to paragraph 1) on October 22, 1991.
The scope of the inspection anc'he inspectors'indings, as noted in this report, were discussed with and acknowledged by the licensee representatives.
The licensee did not identify as proprietary any of the information reviewed by or discussed with the inspectors during the inspectio f
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