IR 05000289/1986006
| ML20207E668 | |
| Person / Time | |
|---|---|
| Site: | Crane  |
| Issue date: | 07/08/1986 |
| From: | Blough A, Conte R, Young F NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20207E566 | List: |
| References | |
| 50-289-86-06, 50-289-86-6, IEB-79-19, IEB-85-003, IEB-85-3, NUDOCS 8607220397 | |
| Download: ML20207E668 (50) | |
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U.S. NUCLEAR REGULATORY COMMISSION,
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REGION I
Report No.
50-289/86-06 Docket No.
50-289 License No.
DPR-50 Priority --
Category C Licensee:
GPU Nuclear Corporation Post Office Box 480 Middletown, Pennsylvania 17057 Facility At:
Three Mile Island Nuclear Station, Unit 1 Inspection At:
Middletown, Pennsylvania Inspection Conducted:
April 11, 1986 - May 16, 1986 Inspectors:
W. Baunack, Project Engineer, Region I P. Clemens, Radiation Specialist, Region 1 R. Conte, Senior Resident Inspector (THI-1)
D. Johnson, Resident Inspector (TMI-1)
J. Golla, Reactor Engineer, Region I J. Rogers, Resident Inspector (TMI-1)
F. Young, Resident Inspector (TMI-1)
Reporting Inspector:
[
7-8-8(,
f o,s F. Toungf Resident Inspector (TMI-1)
Date Reviewed By:
7-8-8f=
h R. Con (e, S'enior Resident Inspector (TMI-1)
Date Approved By:
7f%
A.
loffgh, Chief Date Reactor Projects Section No. lA Division of Reactor Projects Inspection Summan:
Resident and region-based NRC staff conducted routine safety inspections (374 hours0.00433 days <br />0.104 hours <br />6.183862e-4 weeks <br />1.42307e-4 months <br />) of shutdown outage activities, startup, and power operations, focusing on plant and personnel parformance. Heatup and startup activities were monitored by 24-hour NRC shift coverage.
Specifically, items reviewed in detail in the operation area were:
radiological releases; Performance Ap-praisal Team startup issues; shift manning; waste gas tank releases; reactor coolant cleanup evolution; startup activity records; source range detector out of service.
Special focus occurred on licensee actions for a partial loss of off-site power and reactor trip during startup, surveillance of motor-operated valves, containment leak rate test / report, station battery surveillance, steam generator eddy current inspection, and transportation of radioactive material.
Also, followup on an allegation associated with various restart and cycle 6 modification is addressed in this report.
Further, during the period, an NRC meeting with the licensee was held to discuss environmental qualification of specific equipment and is summarized within this report.
8607220397 860711 PDR ADOCK 05000289 PDR.
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Inspection Results:
Licensee personnel continue to exhibit overall_ good control of activities during plant shutdown and power operations. Operators response to two events, reactor trip and partial loss of off-site power, was correct and operators properly implemented station procedures.
In general, for major startup activities, procedures were used and implemented.
However, three examples were noted in which important-to-safety procedures were not properly 'imple-mented; and, collectively, these examples represent an apparent violation of TS 6.8.1 (see paragraphs 2.2.3, 2.2.4, and 2.2.5).
For routine activities, other examples were noted in which procedure implementation was poor or it represented minimal compliance with related administrative controls.
A review of transportation of radioactive waste determined that one individual was not receiving periodic retraining, which was a deviation from commitments (see paragraph 4).
This area, in general, was considered adequate; however, proper oversight or verification of activities in this area are considered weak.
Maintenance / outage-related work was planned and administered in a safe and efficient manner.
Review of station battery surveillance noted a need for additional NRC review of the adequacy of current technical specifications.
Licensee's eddy current inspection fulfilled the applicable license condition.
The meeting held on EQ uncovered problems in the licensee's program that will require additional NRC review to properly disposition these issues.
In addition, the allegations on certain design issues were essentially not sub-stantiated, but NRC review identified an unresolved item (to define a thermal transient for cold water to hot water injection nozzles).
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DETAILS 1.
Introduction and Overview 1.1 NRC Staff Activities.
The overall purpose of this inspection was to assess licensee activities during cold shutdown outage activities and the transition to power operations as they related to reactor safety. Within each area the inspectors documented the specific purpose of the area under review, scope of inspection activities and findings, along with appropriate conclusions. The inspector made this assessment by reviewing information on a sampling basis through actual observation of licensee activities, interviews with licensee personnel, measure-ment of radiation levels,or independent calculation and selective review of listed applicable documents.
1.2 Licensee Activities At the beginning of the inspection period, TMI-1 was in a cold shutdown condition with reactor vessel water level maintained at the reactor vessel nozzles and the primary side of the steam generators drained for eddy current testing (ECT).
The decay heat system was maintaining reactor vessel water temperature at approximately 80-100F.
Between April 19-20, 1986, the licensee filled and vented the reactor coolant system (RCS) and then pressurized the RCS to normal operating pressure as part of the heatup process.
Heatup.of the RCS to normal operating temperature was accomplished using heat generated by operating reactor coolant pumps.
By April 21, 1986, the plant was in hot standby condition.
Startup was delayed for environmental equipment qualification (EQ) repairs to reactor building recirculation fans. The NRC staff met with the licensee on April 18, 1986, to resolve this issue (seE pa*agraph 10).
Resolutions and repairs were completed to the fans by April 22, 1986.
Gn April 22, 1986, while in hot shutdown, the licensee experienced a
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partial loss of site power due to a failed bretket (see paragraph 3).
Reoairs to the breaker were completed the same day.
On Wednesday, April 23, 1986, the licensee made the reactor critical at 4:05 a.m.; but a reactor trip occurred at 5:10 a.m. due to personnel error in operating the feedwater system (see paragraph 3).
Subsequent to the i'cansee's post-trip review, the licensee made the reactor critical again by 10:34 a.m. on April 23, 1986, and they continued the power escalation process up to 55-60 percent power. As a result of two secondary plant problems, reactor power was decreased and the main turbine generator was taken off the
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regional grid for repairs on April 24, 1986.
The reactor remained in operation below 10 percent power with main steam bypassing the main turbine generator to the main condenser.
Following the completion of the repair at approximately 10:00 a.m. on April 25, 1986, a power escalation began.
Full power was achieved at 9:50 p.m. on April 26.
The plant was maintained at full power during the remainder of the report period.
2.
Plant Operations 2.1 Scope of Review
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The NRC resident inspectors periodically inspected the facility to determine the licensee's compliance with the general operating requirements of Section 6 of the Technical Specifications (TS) in the following areas:
review of selected plant parameters for abnormal trends;
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plant status from a maintenance / modification viewpoint, including plant housekeeping and fire protection measures;
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control of ongoing and special evolutions, including control room personnel awareness of these evolutions;
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control of documents, including logkeeping practices; implementation of radiological controls; and,
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implementation of the security plan, including access control,
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boundary integrity, and badging practices.
With additional resident coverage at this facility, the inspectors addressed the adequacy and effectiveness of operating personnel performance in operating activities to determine that; operators are attentive and responsive to plant parameters and
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conditions; plant evolutions and testing are planned and properly
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authorized; procedures are used and followed as required by plant policy;
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equipment status changes are appropriately documented and
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communicated to appropriate shift personnel;
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the operating conditions of plant equipment are effectively monitored and appropriate corrective action is initiated when required;
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backup instrumentation, measurement, and readings are used as
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appropriate when normal instrumentation is found to be defec-tive or out of tolerance;
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logkeeping is timely, accurate, and adequately reflects plant activities and status;
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operators follow good operating practices in conducting plant operations; and,
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operator actions are consistent with performance-oriented training.
The inspectors fccused their attention on the areas listed below.
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Control room operations which included twenty-four hour resi-
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dent coverage from 11:00 p.m. on April 20, 1986, to 7:00 p.m.
on April 27, 1986. During other periods, regular and limited backshift coverage was performed to observe activities in progress and periodically review selected sections of the shift foreman's log and control room operator's log and other control
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room daily logs.
-l Followup items on activities that could affect plant safety or
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impact on plant operations
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Areas outside the control room
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Selected licensee planning meetings
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Plant heatup and startup of April 19-27, 1986
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Reactor Building Local Leakrate Testing (LLT) during ECT outage OTSG tube repair April 14-18, 1986
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Motor-operated valve testing during the ECT outage Station battery surveillance testing
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2.2 Findings 2.2.1 Airborne Activity in Non-Radiologically Controlled Areas During a review of the health physics narrative log, the inspector identified that on April 6-7, 1986, licensee representatives detected airborne radioactivity in the Turbine Building (TB) and Intermediate Building (IB)
non-radiologically controlled areas. The levels of activity were in the order of 1.0 E-7 uCi/ml, Xe-133; 2.0 i
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5-E-11 uCi/ml, I-131; and 1.0 E-10 uCi/ml, Tritium (H-3) in these areas. Although detectable, these activity levels were near or less than the maximum permissible concentra-tions for unrestricted areas specified in 10 CFR 20.
The activity was coming from open Reactor Building (RB)
penetrations used _ to access cables for outage work in the RB. The RB purge was secured at 12:43 a.m. en April 6, 1986, for maintenance work. With a heat load in the RB and with limited penetrations open to outside atmospheric pressure, a light pressure buildup occurred causing a flow of airborne activity out of containment into the TB and IB.
Licensee representatives anticipated this by the initia-tion of smoke tests at the open penetrations. When flow out of RB conditions existed, grab sampling of TB and IB air occurred yielding the above-noted analytical results.
No TS release limits were exceeded. The licensee contin-ued monitoring these release paths by grab samples until the RB purge was restored on April 8, 1986, at 6:25 p.m.
For the future, in order to minimize these low level re-leases, radiological controls department recommended to plant ope ations department that they have continuous RB purges during outages and seal penetrations in use during the outage.
The operations department is currently review-ing this recommendation.
The inspector had no further question on this area.
2.2.2 Performance Appraisal Team Significant Findings The NRC Inspection Report 50-289/86-05 identified a number
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of NRC Performance Appraisal Team (PAT) (NRC Inspection Report 50-289/86-03) findings that the NRC staff consid-ered to be significant. More information from the licensee would be needed in order to determine any adverse conditions on safety-related equipment uperability for startup and subsequent power operations. During this inspection period and as described be'ov, the inspectors reviewed licensee actions to assure no conditions adverse to safety existed as potentially indicated by those adverse PAT findings.
2.2.2.1 Environmental Qualification The PAT found that apparently there was a lack of documen-tation on the environmental equipment qualification for the KERITE FR cable used in the EFW system and potentially other safety-related systems.
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This area was reviewed extensively as documented in paragraph 10.
The subject cable was found to be environ-mentally qualified and there were no outstanding issues that would preclude safe startup of the facility.
2.2.2.2 Safety Evaluation for the Installation of Lead Shielding The PAT found that apparently 10 CFR 50.59 safety evalua-
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tions were not performed for lead shielding on certain piping, and technical evaluations did not consider the additional stress on piping during dynamic conditions.
Due to the above concerns, the inspector reviewed the l
licensee's 10 CFR 50.59 safety engineering evaluation (No.
86-051-E) for the temporary installation of lead shielding around the 12-inch decay heat (DH) removal pump suction valve DH-V3. During heatup (April 20,1986) and after securing decay heat removal, a high radioactive " hot spot" was detected in the disc seating area of valve DH-V3 (10 Rem per hour at one foot).
Since the " hot spot" cannot be flushed without placing the der.ay heat removal system in service, temporary shielding is required. The licensee performed an engineering and safety evaluation and then cradled the valve body with lead blankets supported by 3/8-inch polypropylene rope secured to a permanent platform located above the valve body.
The engineering and safety evaluation considered the following items:
total weight of shielding compared to the strength of
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the rope and the platform floor and structure loading restrictions in static and dynamic loading situa-tions;
lead to stainless steel contact possibility;
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seismic requirements of the DH system and missile
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effects with the shielding attached to the platform; and,
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the effects of elevated DH system temperatures on shielding and materials used to hold it in place.
The inspector agreed with the safety analysis conclusion that no unreviewed safety question was raised.
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No other lead shielding was identified to be installed in the plant. Within the scope of this review, the inspector had no additional comments.
2.2.2.3 Electrical Isolation of the Remote Shutdown Panel The PAT found that apparently the remote shutdown panel
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(RSDP) was not electrically isolated from control room panels. Accordingly, a fire in the CR could adversely affect the RSDP.
In an internal memorandum (Serial No. 3330-86-003, dated April 17,1986) electrical engineering clarified the finding. The lack of isolation was for 22 Cabinet, a signal conditioning cabinet to be used in the Cycle 6
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design for the RSDP. The report confirmed the 120 V DC
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power circuits to the control room are common to the DC power of the B2 Cabinet and, therefore, not electrically isclated.
It reiterated that the loss of DC power would not impair display at RSDP. Accordingly, the RSDP was electrically isolsted from the control room.
J The long-term electrical isolation issue will be followed as a result of the PAT firding as documented in NRC
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Inspection Report 50-289/86-03, 2.2.2.4 BatterL apacity Versus Temperature C
i The PAT found, that with the battery room temperature kept
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below miniaun design temperature during certain tima periods, the effect on battery capacity was apparently not fully evaluated by the licensee. The licensee performed an evaluation of battery capacity at an ambient room temperature of C5 F.
The effect was to reduce battery capacity by an additional 5.4 percent. The result was to
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reduce the "A" battery expected life time from 20 to 10-15 years.
The load on the "B" battery is significantly less and, therefore, available capacity is adequate.
The inspector reviewed the licensee's evaluation and had no other concerns. Also, the battery operability was reviewed in paragraph 6.
2.2.2.5 Motor-Operated Valve (MOV) Testing The PAT found that a weakness existed i1 the program for MOV limit switch settings.
The inspector reviewed the results of the licensee's latest MOV testing with "MOVATS" (a vendor) equipment (see paragraph 5). The licensee made adjustments to various MOV limit switches as deficiencies were revealed by MOVATS equipment.
These changes were
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reviewed by the licensee's Plant Review Group (PRG).
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licensee is maintaining a valve history of these changes
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and valve operating characteristics. Changes to limit switches, deemed necessary by testing, received proper
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review and evaluation by the licensee.
2.2.2.6 Other Issues Prior to the outage startup, the NRC resident offica staff
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L followed up on the belos-listed additional PAT findings for which the licensee was in the p*ocess of taking
corrective action during outage work.
Licensee was to assure that the quality of the compressed air purchased for emergency feedwater two-hour backup air
system met design specifications.
Licensee
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representatives wrote Quality Deficiency Report (QDR) No.
DLL-030-86, dated March 21, 1986, on this issue.
Preliminary information attached to tha QDR indicated that
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the purchased air was of a quality that exceeded (conser-vatively) design specifications.
Plant operations re-sponded to the QDR, but it remains open by the QA department pending a review for adequacy of the plant operations department response.
Based on the information provided by the licensee, the inspector concluded no adverse safety condition existed for the startup.
The long-term aspects of these and all other PAT findings will be documented in detail in NRC Inspection Report No.
50-289/86-03.
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Based on the above review of all of the PAT significar,t findings, no conditicns adverse tc a safe stat tup were identified by the inspector.
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2.2.3 Radioactive Waste Disposal Gas Tank Relene
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During the 3:00 p.m. to 11:00 p.m. shift on April 19, 1986, tha inspector noted that a waste disposal system gas release was in progress and RM-A7, the flow path noble gas monitor was in a first alarm (alert) condition (2.0 E4
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cpm).
The steady-state indication was just over the first l
alarm setpcint at approximately 2.5 E4 cpm. Operators started the release at approximately 12:45 p.m. on the
previous shift, and they secured the release by 8:30 p.m.
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9 Based on a review of the chart recorder for RM-A7, the monitor was in the first alarm condition during the entire release.
Subsequent to operators securing the release, the inspec-tor reviewed various licensee documents applicable to the release. The applicaole radiological release permit G86-04042, datea April 19, 1986, estimated the maximum RM-A7 reading as 1.777 E4 cpm, which was relatively close to the first alarm setpoint of 2.0 E4 cpm; but it was not expected to exceed that setpoint.
Further, the alarm response procedure recaired that if
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RM-A7 reached the first alarm condition, tne gas release was to be secured with subsequent action for radiological controls department to sample the gas end evaluate conditions.
The release was not secured despite the alarming condition throughout the release period.
The failure to follow tne alarm response procedure (C-2-1, Revision 15, dated February 24,1986), represents an
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example of failure to adhere to aporoved procedures as required by TS6.8.1 (289/86-06-01). Additional examples
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are noted below.
2.2.4 Shift Manning Curing the mid-shift (11:00 p.m. to 7:00 a.m.) en April 20-21, 1986, the inspector conoucted observations in the control room for proper control room manning in accordance with 10 CFR 50.54(m)(2)(iii) with the plant in a hot shut-down mode above 200 F.
Shortly after shif t turnover, one of the qualified and on-duty shift senior reactor operators, the shift foreman, left the controi room to facilitate work in the Reactor Building.
There apparently was an acknow-ledgement and understar. ding by the remaining qualified and cn-duty senior reactor operator (SRO), the shift supervisor, that the shift foreman was to be in the Reactor Building.
At the time, the off-duty shift foreman (also a qualified SRO) was periodically in and out of the control room clear-ing up some left over shift matters. At approximately 12:15 e.-.m. on April 21, 1986, the shift supervisor left the control room to facilitate work outside the control room leaving only the off-duty SRO. The shift supervisor return-ed at approximately 12:35 a.m. and remained in the control room for the remainder of the shift.
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During the time of the shift supervisor's and foreman's
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absence from the control room, the off-duty SR0 was in the control room, except for a short time period (approxi-mately two minutes) in which he left to go into the
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Instrument and Control (I&C) shop area or SS office adja-
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cent to the control room.
However, it was not apparent
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that the shift supervisor (SS) conducted a formal turnover
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to the off-duty SR0 and he did not make an announcement to the control room identifying that turnover before leaving
the control room,
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e The inspector concluded that at least one on-shift SRO was not in the control room for approximately 15 minutes while the plant was above 200 F.
Further, the non-shift remaining SR0 was not in the control room for
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approximately 2 minutes during the absence of on-shift SR0s.
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The matter was discussed with the SS when he attempted to
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leave the control room at a time later in the shift. He caught himself when a reactor operator was going over the heatup prerequisite list and that jogged the SS's memory
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of the requirement for at least ona SR0 to be in the
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control rcom with the plant above 200 F.
The SS
acknowledged that no formal turnover occurred but also i
indicated that the SRO, being just relieved, was i
knowledgeable in plant conditions. The SS was unaware of the off-duty SRO absence from the control room until the inspector brought it to his attention.
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The matter was also discussed with licensee management who
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acknowledged the finding and became concerned over the incident.
Tney felt that all SRO's have a good under-I standing of the requirement and that procedures are in
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place to assure the requirement is met.
They became more
concerned that all the information as related by the (
inspector was not brought to their attention by their own personnel.
Considering other communication problem i
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incidents.during the outage and during startup, licensee
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issued an internal memorandum on this and other prcblems
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and, subsequently, met with all SS to discuss this inci-dent and to reenforce overall command responsibilities.
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Based on subsequent discussions with licensee management,
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the inspector determined the below listed aspects.
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The shift supervisor's office (adjacent to the
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control room but not within the " operator at the controls" definition in accordance with AP 1028) was a permissible area when the on-shift SR0 had to be present (restart condition 1.j).
Licensee management indicated that the AP 1028
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applied only to on-duty reactor operators but acknowledged that the AP should be updated for consistent guidance to SR0s.
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The SS office has a window for sighting of alarms, but it remained questionable as to whether or not individual auditable alarms could be heard.
The whereabouts of the off-duty SRO during his two minute absence from the control room was either in the SS office or adiacent I&C shop area.
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To implement the intent of 10 CFR 50.54(m)(2) (iii),
AP 1029, " Conduct of Operations," paragraph 5.7.b, requires that "a minimum of 1 SRO and 1 RO must be in the contral room at all times when the RCS is greater than 200 F."
The inspector concluded that, during the above-noted time period, AP 1029 paragraph 5.7.b was not implemented in that one SRO was not in the control at all times with the RCS above 200 F.
This represents another example of failure to adhere to approved procedures (289/86-06-01).
2.2.5 Reactor Coolant System Feed and Bleed Operation Shortly after shift turnover on the 11:00 p.m. to 7:00 a.m. shift for April 22, 1986, the operators commenced a valve lineup change for reactor coolant system (RCS) feed and bleed evolution.
The previous system lineup was for RCS cleanup processing using the "B" reactor coolant bleed
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tank (RCBT) as a source of makeup water to RCS and the "C" RCBT as a bleed tank for storage of water being drau.ed from the RCS. The "A" RCET contained oiluted borated water for RC5 deboration to criticality. The governing operating procedure (0?) was OP 1104-29E, Revision 34, dated April 14, 1986, " Bleed and Feed Process." For the cleanup process of the procedure required that WDL-V-164
"A" RCBT isolation valve be closed to prevent inadvertent
coron dilution in the RCS.
Paragraph 12.2.5.h of the procedure also properly reautred a restoration to normal
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which included reopening WDL-V-164 when the cleanup process was completed. This valve would need te be reopened for the deboration process.
Upon shift turnover, operators got ahead of themselves and started the deboration lineup before completing the restoration to normal lineup from the RCS cleanup process.
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Because WDL-V-164 was closed, the "A" RCBT pump tripped on low suction pressure when attempts to start the deborstion was repeated several times.
Further, review by shift personnel identified that the auxiliary operator (AO)
assigned to restoring the lineup to normal had not completed this task and, WDL-V-164 was still closed; thus, explaining why the transfer pump tripped.
The inspector also noted that shif t personnel mace no log entires on this event.
The failure to properly adhere to OP 1104-29E represents another example of not properly implementing procedures.
j In reference to paragrapFs 2.2.3 and 2.2.4 and to the above paragraph, these examples of failure to properly implement important-to-safety procedures collectively represent an apparent violation of TS 6.8.1 (289/S6-06-01).
2.2.6 Post-Startup Activities Records Review As a result of the above-noted procedure nonadherences, the inspector reviewed records / logs of startup activities to identify any aoditional examples of poor procedure implementation; and what, if any, was found by the licensee's 24-hour QA monitors in this area.
2.2.6.1 Startup Procedures Completion The inspector reviewed the signed startup operating pro--
cedures (OP) listed in Attachment I for completeness in signatures, adherence to administrative procedures, li-censee procedure, " Enclosure 1 - system lineup instructions and documentation, and procedure sequential oroer."
Many of these documents were in the process of being reviewed by operations personnel subsequent to reaching full power operations.
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In at least eight instances covering five procedures,
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step sign-off initials were missing or NA ("Not
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Applicable") was not indicated.
In five instances covering five procedures, SRO
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initials were not on the completed valve lineup
"o'eviation/ discrepancy list" or SR0 initials
introduced confusion as to whether or not it was an initial for an "NA" step or initials for a completed
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step.
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One procedure step erroneously referenced as ocnexistent appendix.
Ff fty-eight valve lineup deviations were listed for a
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. secondary plant procedure (1106-12, " Extraction-Steam, lie &ter Vent and Drains).
l Indiv1duatly these documentation discrepancies did not adversely impact plant startup or introduce a safety coacern. Cc'lectively, they represent poor implementation of existing administrative controls, apparently due to a lick of attentfon t; detail on the part of individuals and
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their supervit ars apparently compcunded by the pace of startup activities.
Licenses representatives acknowledged
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the coeve findings and initiated corrective action to correct the zbove-noted discrepancies. This area will coctinue to be rout?nely rev10'ed by the NRC resident
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cffice.
2.2.6.2 garrative Loo Revie.'
Throughout the-period 2nd, ir, particular, during NRC shift
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coverage, the inspector reviewed the contral rnoa logs and shift fo emen's (SF) logs for shift rei'ef accuracy, completeness, and adhb ence to a.i :nistrative procedures.
m No tog entries were,noted on '.he f3110 wing iters:
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"A" RCBT transfer pump trf,3s ch low suction pressure due to v:)ve W9L-V-164 being shut (see Section
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2.2.5):
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usectr.' cal distribution lireup just bafore and after
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the fai;ure of the "D" (vital) ous supply D ecker j.
(see Section 3.2); and,
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change in pasftion of Axial Power Snap qg Reds
(APSRs) sGmetime b? tween April 21 af.c 23, 1986,
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Administrative Procedure (AP) 1029, Revision 21, dated April 22, 1986, requires that logkeeping be done in a timely, accurate, and complete manner. AP 1012, Revision 26, dated September 11, 1984, requires that the control room log list any equipment malfunction or abnormal operations.
The failures to note in the control room log the problems with WDL-V-164 and the electrical distribution lineup appears to be inconsistent with AP 1012 and AP 1029.
AP 1012 requires that the control room log will contain
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information concerning reactivity changes. The movement
of APSRs is considered by the inspector as a change in reactivity and not logging that event appears to be inconsistent with AP 1012.
AP 1012 requires that the SF log contain a summary of the station operation and major events. Also AP 1012 requires that significant abnormatities be explained in greater detail than in the shift foremen log.
Starting "A" RCBT transfer pump several times with WDL-V-164 shut could have damaged the pump. Not logging the problems with WDL-V-164 in the SF log appears to be inconsistent with AP 1012.
As in past inspections, the inspector noted many instances where the right hand pages of the SF log appeared to be a
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condensed version of the control room log (left hand pages of the SF's log are reserved for LCOs and major plant events).
The inspector noted numerous entries for various facility activities in the logs reviewed and he acknowledged that there was a judgment call by operators on which events / evolutions are significant enough to warrant narrative recording supplemental to other documentation; such as, the alarm printer and complete precedure signuff.
The inspector reviewed the guidance provided by licensee mansgement in related AP's and independently assessed narrative logkeeping practices with respect to observed
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events or events of which the inspector was knowledgeable.
The inspector concluded the operator minimally complied with existing AP's in this crea. At the oxit interview licensee management acknowledged the inspector's comments and agreed to review this rattee.
This area will continue to be routinely reviewed by the NRC resident office.
2.2.6.3 QA Monitoring On a sampling basis, the inspector reviewed quality
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assurance (QA) monitoring attirities to assess the extent of their involverent in monitoring licensee activities
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during the "5M" outage and during the startup process.
Particular focus occurred on QA review of procedure adherence.
In addition to observing QA monitors in the plant, the inspector reviewed a sampling of QA monitoring reports for the ECT outage period.
The licensee provided 24-hour coverage of monitoring per-sonnel. The focus of these monitoring reports was in as-suring procedure adherence. Monitors identified no proce-dure nonadherences.
This contrasts with the NRC findings
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of several nonadherences during the same period. This may be due to differences in the samples of activities observed, or it could reflect on the depth and effectiveness of QA monitoring.
Previous NRC inspections have found QA monitoring to be generally thorough and probing. Thus, no conclusion can be drawn regarding the contrast of NRC findings with QA monitoring findings in this case. The effectiveness
of QA monitoring will continue to be routinely evaluated in NRC resident inspections.
i 2.2.7 Inoperable Source Range Instrumentation During the shift (11:00 p.m. to 7:00 a.m.) on April 22, 1986, subsequent to the start of deboration of the RCS, the inspector noted a discrepancy between NI-1 and 2, reactor source range neutron monitors.
Concurrently, operators noted the same problem. The NI-1 read about 1/4 i
of a decade below N1-2.
It appeared as though only NI-2 was trending upward as expected for the deboration to critical process. When questioned by the inspector, the
shift supervisor notified Instrument and Control (I&C)
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technicians of the problem. Apparently, they also suspected a problem with NI-1 or 2 based on I&C shift turnover report about cables being switched at RB Penetration No. 202 E.
Further review by shift personnel revealed that the high i
voltage power supply for NI-1 had been inadvertently
disconnected because an I&C technician switched the NI-1
.
power cable with a spare cable in Penetration 202 E at I
about 10:00 p.m. on the shift before.
This action was in accordance with the controlled copy of Drawing B224-336 Sheet 52, Revision 8, dated November 1, 1986, " Electrical
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The technicier,was re-storing the penetration to normal since it had been used for temporary,sacicP vessel water level indication.
By 3:15 a.m.
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- toi 4aclared NI-1 inoperable and restored it te fict T/ 4:15 a.m.
The deboration
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process continue;; tirc *hout the NI-1 inoperability period.
In accorarqce ',ith technical specifications, only one source range was nt>ded for startup. However, the inspector concluded tt<. sf'ft personnel may not have been sufficiently ing';isitive or prudent to assure opera-bility of both NI-1 atd 2 before starting deboration.
Licensee management ackncwledged the inspector's concern that the deboration process proceeded with certain members of shift compliment not fully appraising the problem and bringing it to the attention of the shift supervisor.
The inspector subsequently learned that the modification which outdated Drawing B224-336, Sheet 52, Revision 8, was accomplished during Jab T'cket (JT) No. CE-223, " Trouble-shooting of NI-1 Erratic iailures." The inspector reviewed licensee records for that JT and found no details on the modification let alone al approved safety evaluation.
Records indicated that personnel did work at Penetration No. 202 E.
The PAT inspection also identified an issue of making modifications without a properly approved safety evaluation and not having updated drawings. Accordingly, this area is unresolved pending furtner review of both issues (289/86-06-02).
2.3 Conclusion The licensee took prompt corrective action for various unexpected events and for the startup issues identified in the most significant PAT findings.
In general, procedures were used and implemented, especially for major startup activities.
However, three examples were noted in which procedures were not properly implemented and numerous other examples were noted in which proper procedure implementation was poor or it represented minimal compliance with i
related administrative controls. These problems resulted despite supervisory attention and various licensee oversight activities,
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3.
Event Review 3.1 Introduction and General Scope of NRC Staff Review During this inspection period, there were two events that the NRC staff reviewed in detail. They were:
the partial loss of off-site power on April 22, 1986, and the reactor trip of April 23,'1986.
In general, the following aspects were considered for each of these events:
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details regarding the cause of the event and event chronology;
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functioning of safety systems as required by plant conditions;
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consistency of licensee actions with license requirements, approved procedures, and the nature of the event;
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radiological consequences (on-site or off-site) and personnel exposure, if any;
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proposed licensee actions to correct the causes of the event;
--. verification that plant and system performance are within the limits of analyses described in the Final Safety Analysis Report (FSAR); and, I
proper notification of the NRC was made in accordance with
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For each of these events, the inspector provided a chronologi-cal / factual summary; specific scope of NRC staff review; licensee-findings, and NRC staff findings. An overall conclusion on licensee performance is provided in paragraph 3.4.
3.2 Emergency Electrical Power Breaker Failure 3.2.1 Sequence of Events During startup preparations at 9:40 a.m.,
April 21, 1986, the plant experienced a loss of one (of two) 4160-volt vital buses and all three 4160-volt non-vital buses.
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Operators were in the process of unloading "A" startup transformer for routine adjustment of transformer 16ad ta p s'.
During transfer of loads, the "D" (vital) but supply breaker apparently faulted and tripped. The fault was also sensed briefly in the switch yard, causing both 6900 volt reactor coolant pump (RCP) buses to deenergize.
This resulted in reactor coolant pumps tripping. Also a reactor trip occurred, but the reactor had not been critical, since only four safety rod groups had been withdraw %:
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Operators promptly diagnosed the problem, restored power to the r.on-vital buses, and restarted reactor coolant pumps. Operators manually initiated emergency-feedwater for decay heat removal cooling since the RCP initiation circuit (for EFW) was in " defeat" for plant conditions.at the time of the event.
The switch gear was checked for damage and the breaker was replaced on the same day. The plant electrical system was j
then returned to standard. lineup.
3.2.2 Scope of NRC Review The inspector reviewed the details and circumstances associated with partial loss of power that occurred on April 21, 1986, to determine:
the cause of the event and the event's chronology;
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licensee's actions in response to the event; and,
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significance of the event to plant operations and
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impact on plant operations and/or plant equipment.
The inspector review of this event included discussion with cognizant licensee personnel and review of the following documents:
applicable system drawings;
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applicable switching and tagging orders; and,
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station emergency procedures and applicable operating procedures.
3.2.3 Licensee Findings
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Investigatioti of "D" bus supply breaker determined that the closure mechanism of one of three main contacts failed.
Failure of the closure mechanism is still under evaluation.
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Review of the operating procedure determined that u.a procedure should be revised with respect to when a load-
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center feeder is placed in pull-to-lock (de-energized).
" Pull-to-lock" defeats the automatic closure of the individual breaker.
If the breakers were not placed in
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pull-to-lock until after all required load center transfers, this would reduce the amount of time the buses are susceptible to being de-energized upon failure of a single supply. The licensee is reviewing the procedure.
Review of plant response indicated all equipment responded as required. Operator action was correct. Since the plant was in hot shutdown, the reactor safety control rods were fully withdrawn. The loss of power caused a reactor trip which caused the safety control rods to be inserted as designed. No equipment malfunctions were identified other than that for the breaker.
3.2.4 NRC Findings The inspector confirmed and concurred with the licensee's findings. Based on visual inspection of the failed breaker, the inspector also concluded that the closure mechanism was the cause of breaker malfunction.
The licensee may not be able to positively identify the root cause of the failure of the mechanism.
The final licensee corrective action and evaluation will be reviewed in a subsequent inspection after receipt of the Licensee Event Report (289/86-LO-08).
3.3 Reactor Trip 3.3.1 Event Chronology and Background Information At 5:10 a.m., April 23, 1986, during startup from the steam generator tube inspection outage, a reactor trip occurred from 8 percent power due to high reactor coolant system (RCS) pressure.
The high pressure resulted from a main feedwater transient in which a turbine-driven pump decreased speed during the transfer of steam supply from the auxiliary system to the main steam system.
The RCS relief and safety valves were not challenged.
Emergency feedwater was not needed.
The licensee made the required report to the NRC Headquar-ter Duty Officer.
The NRC resident staff had been in 24-hour coverage of startup activities since April 20, 1986.
Accordingly, the senior resident inspector (SRI)
was in the control room monitoring licensee activities at the time of the trip, and he monitored the licensee post-trip response actions.
The plant wss restarted later that da s
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3.3.2 Specific Scope of NRC Staff Review for the Reactor Trip Relative to the reactor trip event noted above, the inspector verified the below listed items:
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initial proper response of the plant to the post-trip window on the pressure-temperature (P-T) plot;
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personnel properly implemented AT0G procedures and prudently acted on unusual conditions; identification of the sequential approximate causes
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for the trip along with a reasonable determination of the root cause;
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post-trip review was conducted in accordance with AP-1063, Revision 6, " Reactor Trip Review Process;" and,
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no unreviewed safety issues identified in post-trip review data.
In addition to discussion with cognizant licensee person-nel, the inspector:
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made an independent assessment of post-trip parameter response based on visible strip chart and indicators in the control room shortly after the event;
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attended the licensee's post-trip review;
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attended the independent safety review of abnormal response of the feedwater system; and,
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reviewed the complete post-trip review package (No.
86-4).
3.3.3 Licensee Findings Plant response was normal. The licensee's post-trip review identified the root cause as personnel error.
The individual who was shifting steam supply for the main feedwater turbine should have been mora attentive to feed pump control to prevent the trip.
Licensee corrective action was to increase shift manning for selected portions of the startup process.
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1 3.3.4 NRC Staff Findings Licensee findings were confirmed by the inspector.
Procedures were properly impleiaented for the post-trip emergency response and for the post-trip review. The inspector independently assessed that no safety issues were identified. The inspector has no additional comments on this area and he will review the licensee's event report (LER) when it is issued (289/86-LO-10).
3.4 Conclusion In general, operating personnel responded in a competent manner during both events. Actions by the operators quickly placed the plant in safe and stable condition.
Station procedures were avail-able, adequate, and used to place the plant in a stable condition.
Operators previous training was conducive in quick and proper operator action.
Reactor post-trip review determined that the plant response was as expected. All plant equipment functioned as required and/or as designed. Review by inspector concurred with the licensee's characterization of the cause of the trip and the plant's response. With respect to the creaker failure, the inspector also concurred with the licensee's findings and resolutions. No adverse safety conditions or concerns were noted.
4.
Transportation Inspection 4.1 Management Control Section 2.8 of TMI-1 Procedure No. 1009 states that "the Radwaste Operations Manger, TMI-1, is responsible for ensuring that Unit I radioactive waste is processed, packaged, and shipped in accordance with all applicable NRC and Department of Transportation (DOT)
regulations." While Unit I personnel are responsible for processing and packaging waste in liners, boxes, drum, etc., they are not involved and have no responsibility for the actual shipping of waste.
Unit 2 personnel do the shipping of radioactive waste. They order NRC approved packages from vendors, and they perform all final packaging requirements. The licensee apparently does not have administrative procedures which clearly define the responsibility and authority between the two units for Unit 1 radioactive waste shipments.
4.2 Shipments of Licensed Material During 1986, the licensee has utilized package Model No.14-290M, Certificate of Compliance (C of C) No. 9159 to make several ship-ments of licensed material to a burial site.
The shipments were reviewed against the criteria contained in 10 CFR 71.12, " General License:
NRC Approved Package."
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The licensee's performance relative to these criteria was determined from discussions with Units 1 and 2 Radwaste personnel and review of appropriate documents. Within the scope of this review, the follow-ing problem was identified.
10 CFR 71.12(a) states, "A general license is hereby issued to any licensee of the Commission to transport, or to deliver to a carrier for transport, licensed material in a pack for which a... certifi-cate of compliance... has been issued by the NRC."
10 CFR 71.12(c)(1) states, "This general license applies only to a licensee who has a copy of the... certificate of compliance... and has the drawings and other documents referenced in the approval..."
The inspector determined that the C of C No. 9159 referenced Drawing No. X-20-204D, Sheets 1 and 2, Revision No. E and that the licensee did not have the required drawing.
The licensee was informed by the inspector that the referenced drawing should be available for use by radwaste personnel.
The licensee subsequently obtained a copy of Revision E of the subject drawing.
4.3 Part 61 The licensee's quality control program for waste characterization was reviewed against criteria contained in 10 CFR 20.311(d)(3),
" Transfer for Disposal and Manifests."
The licensee's performance relative to these criteria was determined by discussions with the Operations Quality Assurance Manager, an Operations Quality Assurance Monitor, and by reviewing appropriate documents. Within the scope of this review, the following was r
identified.
10 CFR 20.311(d)(3), " Transfer for Disposal and Manifests," requires a licensee who transfers radioactive waste to a land disposal facility to conduct a quality control program to assure compliance with 10 CFR 61.55 and 10 CFR 61.56.
The inspector determined that the licensee made several shipments of dewatered radioactive resins to the burial site at Barnwell, South Carolina, during the period April-June 1985.
The quality control program for waste characterization had not been implemented because there were no documents to verify that the dewatering process had been observed as required by 10 CFR 20.311(d)(3).
Licensee radwaste personnel stated that they did not observe dewatering operations.
Documentation was provided to the inspector to verify that the solidification process had been observed.
At the Exit Meeting on April 18, 1986, licensee personnel stated that they would be provided the audition checklist used with the Audit S-TMI-85-03 that was performed during the period March-April 1985 and
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i that the checklist would demonstrate that quality control had been performed on the dewatering process.
The checklist provided did not include a cover page that would verify that the checklist was associ-ated with Audit Report S-TMI-85-03.
Page 20 of the checklist stated,
" Spent resin dewatered in HIC's 85-PR-1 (on 4/10/85)."
The auditor performing the audit did not reference the appropriate procedure so that one could determine what was required. The documentation appeared to be inadequate to verify that a quality control program had been conducted to assure compliance with 10 CFR 61.56. There was no other documentation available to verify that the numerous parameters associated with the dewatering process had been observed.
On May 1, 1986, in a telephone conversation with the licensee repre-sentatives the inspector was informed that NRR had approved the licensee's " graded approach" philosophy which incorporates operations quality assurance, inspections, and audits.
It was also stated by the licensee representative that minimal documentation is acceptable in the audit program. The Region I Quality Assurance Section Chief asked if the licensee had performed similar operations at TMI-2. The licensee representative stated that the Operations Quality Assurance Monitors had performed the quality control requirement at TMI-2, and agreed to send a copy of the report to the inspector.
This item will remain unresolved until such time as other documents are reviewed (289/86-06-03).
4.4 Training The licensee's program for training and retraining of personnel involved in solid radioactive waste preparation, packaging, and shipping operations was reviewed relative to the criteria contained in IE Bulletin 79-19.
The licensee's performance relative to these criteria was determined by discussion with the Unit 2 Radwaste Support Manager, Training Department personnel, and by reviewing appropriate documents.
Within the scope of this review, the following apparent deviation was identified.
IE Bulletin No. 79-19 required licensees to provide training and periodic retraining in D0T and NRC regulatory requirements, waste burial site license requirements, and licensee's procedures governing these activities for all personnel involved in the transfer, pack-
aging, and transport of radioactive material.
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On October 8,1979, the licensee responded to IE Bulletin No. 79-19 and stated... "A training / retraining program in the DOT and NRC regu-latory requirements, the waste burial license requirements and opera-ting procedures for supervisory personnel involved in the transfer packaging and transport of radioactive material is expected to begin classes on November 19, 1979.
Previous training was conducted on DOT regulation on June 12, 1979.
Records of training dates, attendees, and subject material will be maintained on file."
!
Licensee Procedure No. 6210-ADM-2622.01, " Radioactive Waste Supervi-sor Training Program Units 1 and 2," requires retraining every two years for Radioactive Waste Supervisors.
As of April 28, 1986, the inspector determined that a radioactive waste supervisor who is involved in the transfer, packaging, and-transport of radioactive material was last trained on January 26, 1982.
It must be noted that there were significant changes to the DOT and NRC regulations that occurred in July and September 1983, respec-tively; and, according to a licensee representative, it is apparent
that this supervisor did not receive any training in these regulato-ry revisions.
The failure to retrain supervisory personnel repre-sents a deviation from a licensee commitment to the NRC (289/86-06-04).
4.5 Procedures The adequacy and effectiveness of certain of the licensee's proce-dures were reviewed against the criteria contained in TS 6.8,
" Procedures."
The licensee's performance relative to these criteria was determined by discussions with the TMI-1 Radwaste Operations Manger, the TMI-1 Radwaste Operations Engineer, the TMI-1 Radiological Engineering Manager, the TMI-1 Radiological Engineer, and by reviewing proce-dures.
Within the scope of this review, no violations were identified.
4.6 Audits The licensee's program for the auditing of transport packages was reviewed against the criteria contained in Criterion II, " Quality Assurance Program," and Criterion XVIII, " Audits," of the licensee's 1.
quality assurance program.
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The licensee's performance relative to these criteria was determined
,
by discussion with the TMI-1 audit supervisor, and by reviewing appropriate documents.
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Within the scope of this review, no violations were identified.
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4.7 Package Selection The licensee's program for selection of packages was reviewed against the requirement of 10 CFR 71.12 and the 00T requirements of 49 CFR 173.
The licensee's performance relative to these criteria was determined by discussion with the Units' Radwaste Support Manager, other licensee personnel, and by reviewing appropriate documents.
Within the scope of this review, no violation were identified..
5.
Motor-Operated Valve Testing (MOVATS)
5.1 Introduction During the SM outage, the licensee conducted tests and evaluations of motor operated valve (MOV) actuators. The valves tested were those that were (a) specified in NRC Bulletin 85-03, "MOV Common Mode Failures During Plant Transients Due to Improper Switch Settings" and (b) additional valves identified by the licensee. The NRC bulletin was issued to require licensees to institute a program to test MOVs in the Emergency Feedwater (EFW) ard high pressure injection (MU)
systems to ensure that MOV limit switches were set correctly and that the valves would be able to operate under postulated differential pressure conditions that could exist during an accident. The li-censee contracted with MOVATS Corporation to use their method of testing MOVs.
The "MOVATS" system employs a device called the thrust measuring device (TMD) that senses a deflection in the movement of the MOV drive or worm gear. This deflection can be translated to a measure of stem thrust for various valve operating conditions.
A load cell is connected to the stem of the valve to measure actual stem thrust which can be corre ated to valve seat differential pressure.
The licensee obtained data from Torrey Pines Corporation, which gave target stem thrust values which correlated to differential pressures actually seen by the valves under accident conditions. These values were used in conjunction with the M0 VATS test setup to test various valves in the makeup (MU), sampling (CA), emergency feedwater (EFW),
main steam (MS) systems, and also the motor-operated containment purge isolation valves.
5.2 Scope of Review The inspector reviewed the following documentation a.sociated with MOV testing and conducted interviews with various licensee
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engineering and maintenance personnel who were involved with the test evaluations.
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NUREG/CR-4234, " Aging and Service Wear of MOVs in ESF Systems"
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Maintenance Procedure 1420-LTQ-7, " Testing Various Motor-
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Operated Valves Using M0 VATS 2100 System" Test results from M0 VATS Corporation for the twenty-five valves
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tested during the SM outage 5.3 Licensee Findings The licensee was in the process of formulating the initial response due to IE Bulletin 85-03, which was due on May 30, 1986.
This response will be evaluated in a future inspection report. The licensee submitted the results of the tests and adjustments made to various MOVs during the recent outage to the Plant Review Group (PRG). Meeting No. 86-35 on April 16, 1986, reviewed each deficient condition that was observed during recent testing. All problems which consisted of high thrust values, backseating, and limit switch mis-adjustments were determined not to be operability concerns.
In each case, the valve was judged capable of performing its intended safety function. Adjustments were made to some valves to correct problems and, in other cases, adjustments were to reduce the margin of calculated operational parameters such as operating thrust.
5.4 NRC Findings The inspector reviewed the PRG response and the results of the data obtained during M0V testing. Although many minor problems were identified and corrected, the licensee's program for testing MOVs appears to be complete as far as the scope of Bulletin 85-03 is concerned.
Bulletin 85-03 is limited to a selected number of MOVs in the HPI (MU) and EFW Systems.
This bulletin remains open pending receipt of applicable licensee required responses and subsequent NRC staff review (289/85-BU-03).
In addition and based on a previous inspection, the issue of MOV op-erabi'ity during design basis accident conditions was raised by NRC staff (re: NRC Inspection 50-289/85-08 - unresolved item 289/85-08-01).
Remaining licensee action associated with this unresolved item was to assure the operability of all " safety-related" MOVs during design basis accident conditions.
This item will be further reviewed inde-pendent of licensee action associated with NRC Bulletin 85-03.
The inspector had no further comments in this area.
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6.
Station Battery Operability 6.1 Introduction
Station batteries are provided in the emergency power supply system in order to provide a source of power through uninterruptable power supplies (UPS) for vital (AC) instrumentation and breaker opening /
closing control power.
These batteries are designed to function
'
when all AC power is lost. The licensee maintains two,
"A" and "B",
separate redundant battery banks for this purpose.
During the SM outage, the "A" station battery was replaced since its capacity had degraded to the point that the licensee suspected that it may not have lasted for its full expected lifetime.
The licensee expects to replace the "B" station vital battery during the next refueling outage, although, at this point, the "B" battery meets all TS acceptance criteria for operability.
6.2 Scope of Review
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The inspector reviewed licensee records and conducted interviews with licensee personnel concerning the replacement of the "A" battery and reviewed surveillance records for the "B" battery.
Specifically the following records were reviewed:
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Surveillance Procedure (SP) 1303-11.11, " Station Battery Load Test;"
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SP 1301-4.6, " Battery Weekly Surveillance;"
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SP 1301-5.8, " Battery Monthly Surveillance;"
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TS 4.6.2, " Station Batteries;"
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Battery Test Report for LC-21 Station Batteries, dated March
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27, 1986, from C&D Power Systems; and, GPUN TS for Station Battery Procurement, SP 1101-11-221.
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The inspector also conducted interviews with various licensee personnel concerning battery testing, technical specification re-quirements, and the results of battery surveillance testing.
6.3 Findings
During the review of test specifications for the new "A" battery and
'
results of test procedures, the inspector noted that the licensee had conducted, in conjunction with the battery replacement, an extensive test program to ensure that the new battery was accept-
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j able. One of the tests conducted was a battery load duty cycle test
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where the battery is subjected to a load based on assumptions and calculations. This test was performed in conjunction with a.
capacity test and various other tests and measurements of battery voltage and specific gravity. The inspector concluded that the licensee had conducted an acceptable test program to verify the acceptability and operability of the new "A" battery.
Upon review of +he TS, it was noted, however, that the load duty
'
cycle test is not required for the batteries once they are in service. Only the 8-hour capacity test is performed every refueling outage.
The inspector discussed this with the licensee plant engineering personnel and expressed concern that this is a potential problem area.
(Typical station vital batteries have shown. the ability to pass a capacity test; but, after long periods of service, could not pass the more rigorous load duty cycle test.) Licensee engineering personnel expressed a shortsighted view of considering
,
the present TS adequate. This item will be referred to the office of NRR for resolution and will remain an unresolved area (289/86-06-05).
The inspector also observed that the tronthly and weekly surveillanc-es for the new "A" battery contained an exception in that the acid level of the battery was not being recorded on the data sheets. The inspector was informed by the licensee that new acid was on order to fill the batteries to the top level mark in order to obtain a reference specific gravity.
Licensee maintenance personnel thought that with battery level off of the top mark, a correction to specific gravity was needed but no procedural guidance was given to perform the correction, that the battery cell levels would be recorded and the specific gravity corrected for level as required by procedure.
The inspector noted that all battery levels were within the high/ low level marks and that all specific gravity and voltage readings were within specification and there was no concern on the operability of the batteries.
Subsequent to the end of the report period, the licensee modified the monthly surveillance procedure to require recording of actual battery level, but they ommitted the specific gravity correction completion of battery testing as discussed above.
The inspector reviewed the procedure changes and verified that operators were recording battery level in the monthly surveillance procedure as required by technical specification.
In review, the exception should have been classified as a deficiency because the lack of documentation of a corrected specific gravity value precluded the surveillance test from being formally completed.
Since the level correction of specific gravity was not needed in determining operability of the system, the event did point out a need for enhanced and, perhaps, more formal communications between
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maintenance and engineering personnel.
This area will continue to
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be routinely reviewed by the NRC resident office.
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7.
Containment Leak Rate Testing 7.1 Introduction The licensee conducted containment integrated leak rate testing (ILRT) in April of 1984 and containment local leak rate testing (LLRT) during the recent outage.
This testing was accomplished to satis'y the requirements of the TS 4.4.1.1, 4.4.1.2, and 10 CFR 50.50, Appendix J.
The LLRT was not accomplished on a schedule as specified in the TS, but a scheduler exemption was granted by NRR in a letter to the licensee, dated February 20, 1986. This examption was a one-time exemption to allow the licensee to accomplish the LLRT during the SM outage (March / April 1986) instead of the due date of February 23, 1986.
7.2 Scope of Review The inspector reviewed the results of the LLRT and ILRT by examining the following documentation:
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Surveillance Procedure (SP) 1303-11.8, "RB Local Leak Rate Testing" (completed data);
Summary Technical Report submitted to the NRC by the licensee
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" Reactor Containment Building Integrated Leak Rate Test," dated July 19, 1984; and, The inspector conducted discussions with licensee personnel on the results of the local leak rate testing.
7.3 Findings (ILRT)
During an inspection conducted in April of 1984, the inspectors reviewed and observed the licensee's conduct of the ILRT. The results of this inspection were documented in NRC Inspection Report 50-289/84-10. The test results appeared to be satisfactory at that time pending receipt of the licensee's final report.
The licensee submitted their report on the ILRT on July 19, 1984.
The report confirmed that the preliminary data was satisfactory.
The inspector reviewed these calculations and independently confirmed the results.
The data in the final report were the same values as initially reported.
7.4 Findings (LLRT)
The results of the local leak rate testing were satisfactory.
In accordance with technical specifications, the allowable leakage is limited to 104,846 standard cubic centimeters per minute (SCCM).
Both the as-found and as-left leak rates were less than this amount.
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As-found leakage was approximately 98,000 SCCM. This leakage was due mainly to two valves IC-V3 and RB-V7, which were both repaired and retested satisfactorily.
IC-V3, which has been a problem in the past, will be replaced with a different type of valve during the 6R outage.
The inspector discussed the results of the data with licensee per-sonnel.
The affect of motor-operated valve testing (discussed in paragraph 5) on some containment isolation valves was also evaluated.
Adjustments of valve actuators seemed to have little or no affect on the results of the irdividual LLRTs. As-left leakage of 32,261 SCCM was substantially below the allowable leakage.
Also, the results of the "as-found" data on RB-V7 was initially recorded as 30,000 SCCM.
This was attributable to packing leakage and, after repairs, another set of data would be obtained. This packing leakage was from valves inside the RB and it was determined by the licensee that this leakage could be corrected and be sub-tracted from the "as-found" data prior to confirming actual "as-found" data recorded in the " total" as-found data. This resulted in total
"as-found" leakage which was less than the allowable of.6 L,.
( L, is the allowable leakage at peak containment pressure or 50.6 psig.)
The inspector had no further comments on the RB leak rate testing.
8.
Nuclear Services Closed Cycle Cooling Water Hydrostatic Test On April 11, 1986, the licensee performed a hydrostatic test of the nuclear service closed cycle cooling water system (NS) to adhere to the 10 year testing cycle required by 10 CFR 50.
The licensee identified that a section of piping of the NS system was not pressurized to the ASME code required pressure. The licensee notified the NRC resident insoector of the hydrostatic test problem on April 28, 1986.
It was not poss!ble to remove the NS pumps from service since NS cooling water is required for fan motor coolers, sample coolers, make-up and purification pumps, spent fuel pump room coolers, etc.
Despite a special lineup to maximum system operating pressure, some sections of piping achieved only 118 psig; whereas, the required test pressure per the ASME Code is 165 psig.
Thus, the NS hydrostatic test performed on April 11, 1986, appears not to qualify as a successful part of the inservice inspection plan.
There appears to be no immediate or regulatory safety concern since (1) the test pressure was approximately twice the normal operating pressure of 60 psig and (2) the plant, having operated only thirteen months before the 1979 extended shutdown, is still early in its first ten year ISI cycle.
Pending resolution of the NS hydrostatic test deficiency, this item is unresolved (50-289/86-06-06).
The inspector also noted that the completed procedure included thirty-six exceptions.
This high number of exceptions reflects poorly on the li-censee independent technical and safety review progra Y
9.
Steam Generator Inservice Inspection 9.1 Background Technical Specification Amendment No. 103 permits the return of the steam generators to operation after repair of the steam generators by any method other than plugging (i.e., kinetic expansion), provided that the repair method was approved by the NRC.
In order to confirm the continued leak tight integrity of the RCS after this repair, a license condition (No. 2.C.8) requires, in part, the performance of a special steam generator inservice inspection. GPU Nuclear Corporation was to conduct eddy current examinations, consistent with the extended inservice inspection plan defined in Table 3.3-1 of NUREG-1019 (NRC staff safety evaluation report for the kinetic expansion process).
This inspection was to be performed either 90 calendar days after re-aching full power or 120 calendar days after exceeding 50 percent power operation, which ever comes first.
On March 24, 1986, the licensee shut down the plant to perform the required testing.
9.2 Scope of Reviaw In order to verify that the licensee met the intent of the license condition, a review was performed to verify that:
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the licensee eddy current program met the requirements as stated in NUREG 1019 and performed at the prescribed time;
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data collection and analysis techniques were sufficient to record pertinent information; and,
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testing was performed by qualified and knowledgeable personnel.
In addition, the inspector reviewed and witnessed portions of field work to remove twenty-five tubes from service to ensure the evolution was performed per applicable procedures.
9.3 Licensee Findings In the required 3 percent random sample inspected, the licensee did not find any tubes with indications greater than 50 percent throughwall (TS 4.19.4.a.6, License Amendment No. 116).
Thus, no tubes in the random sample were removed from service.
In the population of tubes classified as degraded which require inspection every time eddy current inspection is performed, twenty-five tubes were required to be removed from service.
From a statistical review of the data collected, the licensee determined no significant degradation of the tubes was occurring.
From drip and bubble tests performed independently of ECT, no indication of primary to secondary leakage was observe.4 NRC Findings The inspector determined that the licensee's inservice inspection fully met the requirements of the license condition.
The program, as described and conducted by the licensee, was in accordance with NUREG 1019. The test was performed within the prescribed time interval.
Personnel performing the test were qualified and knowledgeable. With the assistance of NRR and region-based inspec-tors, the inspector independently confirmed licensee's interim re-sults of the inservice inspection.
In addition, the inspector reviewed, witnessed portions, and discussed the subsequent removal of twenty-five tubes from service due to eddy current analysis.
Inspector review of maintenance record determined that licensee had properly removed the required tubes from service.
10.
Environmental Qualification of Electrical Equipment 10.1 Background In their March 1986 inspection, the NRC Performance Appraisal Team (PAT) identified that emergency feedwater (EFW) system valves EF-V 2A and 2B power supply cables had not been evaluated for environmental qualification (EQ) at TMI-1.
Specifically, the cables were Kerite Company Flame Retardant Insulation / Flame Retardant Jacket (KERITE FR);
whereas, the only Kerite Company cable type evaluated for TMI-1 EQ was KERITE HTK.
The licensee had, however, evaluated the KERITE FR cable for Oyster Creek plant.
Subsequent to the PAT inspection, the resident inspectors ard Region I management, in conjunction with representatives of the NRC headquarters office of NRR and IE, reviewed this matter to determine whether there were broader EQ concerns relative to restart of TMI-1 from the eddy current outage.
10.2 Followup Telephone Conference Calls The NRC held several conference calls with licensee managers to discuss status of licensee investigation and resolution of EQ issues.
Participants are listed in Attachment 2.
Each call is summarized below.
April 1, 1986 - During this call, the licensee confirmed that
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the Oyster Creek System Component Evaluation Worksheet (SCEW)
for KERITE FR cable's qualification also bounded TMI-1 environ-mental profiles.
The licensee was not ready to address at that time how the EQ evaluation for KERITE FR was originally over-looked or whether additional cases of unevaluated equipment might exist.
April 3, 1986 - The licensee indicated that an extensive review
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had been initiated to determine if additional EQ cable problems exist. Other types of " common equipment" (i.e., equipment used commonly in the plant, which does not have an individual
component identifier) would also be addressed.
The KERITE FR problem apparently resulted from an error made in the original scope of the reviews for the EQ prcgram several years ago.
The licensee reported that identifying all types of common equipment was complex and various methods had to be used.
For example, for cable, the initial review included review of (1)
installation records for cables installed after 1980 and (2)
procurement records for cables installed earlier.
The KERITE FR was installed before 1980 and it was shown in procurement records; but, for reasons the licensee has not determined, it was not entered into the EQ program.
April 11, 1986 - The licensee provided a progress update. A
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contractor was reviewing all cable installation records back to (and including) initial plant construction. This work was projected to be completed by April 16, 1986.
Evaluation of other common EQ was in progress.
10.3 Management Meeting and Followup A meeting between NRC and licensee managers and technical personnel was held on site on April 18, 1986. Attendees a-e listed in Attach-ment 2.
This meeting had been confirmed by letter from S. D. Ebneter (NRC Region I) to H. D. Hukill (GPU Nuclear Corporation), dated April 15, 1986.
This letter listed the specific items to be dis-cussed related to the licensee's EQ program and reverification pro-gram. The licensee's presentations were responsive to the NRC's requests.
The licensee discussed his original EQ methodology, his recent reverification program for common equipment, and reverifica-tion program results The key points are summarized below.
Cables - The licensee's original EQ review was as described in the April 3,1986, conference call.
The reverification program involved a review of all cable installation records. Walkdowns had been attempted, but cables were not identifiable as to manufacturers and types.
Results of the NRC PAT team finding regarding KERITE FR were confirmed.
KERITE FR was found to be used extensively in other applications requiring EQ.
One additional cable type, BIW Silicone Rubber, installed after 1980, had not been evaluated for EQ.
The cable is used for high range Reactor Building (RB) sump level transmitters.
The licensee had obtained a test report and additional information, had preliminarily concluded the cable was "qualifiable," and was developing an EQ file and "SCEW" sheet, l
Terminal Blocks - The original program involved review of procure-ment records and sampling walkdowns.
In the Reactor Building all terminal blocks requiring EQ had been replaced with Raychem splices.
The reverification program involved 100 percent walkdowns in the Reactor and Intermediate Buildings and a sampling walkdown in the Auxiliary Building.
The reverification program resulted in reactivation of a file for Stanwick blocks. The licensee had originally developed a file but had subsequently deactivated it and removed Stanwick from his EQ roster, based on belief that there were no Stanwick blocks in EQ applications. The reverification walkdowns identified Stanwick blocks. The licensee stated that the master EQ list would also be corrected.
The NRC staff asked various questions about the verification walkdowns; and, based on the responses, the staff questioned whether the walkdowns provided confidence regarding terminal block model numbers.
(NOTE: Most terminal blocks are stamped with the manufacturer's name but no model number.) The licensee agreed to readdress this item before taking the reactor critical.
Splices - The original program involved sampling walkdowns and modification closeout reviews.
The splices were reverified by walkdowns as installation document reviews.
No problems were identified.
_ Equipment Seals - The original program involved sampling walkdowns.
The reverification was done through walkdowns or document reviews.
No problems were identified.
On April 21, 1986, the licensee provided information regarding additional review of terminal blocks to verify they were qualified models.
Each manufacturer had been contacted.
For States and Stanwick blocks each manufacturer had indicated that their blocks were similar and were qualified under a single test report. Also, the licensee had directly compared a sample States block to the in plant States blocks.
For GE blocks, an unused in plant block was removed and its mold number traced back through the vendor who (1)
confirmed that the blocks are the EB-5 and 6 type and (2) identified that the blocks of similar materials to the EB-25 for which GPUN had a qualification file.
The licensee was in the process of augmenting his EQ file with additional information from the manufacturer. Also during the terminal block review, the licensee found short links (about 5 feet long) of cable at the three Reactor Building air hand-ling units (in the Reactor Building emergency cooling system) that were dissimilar from any qualified cable at TMI-1.
The licensee indicated that these cables would be replaced with qualified cables and splices to meet technical specification requirements (i.e., two of the three coolers required to be operable) for startup.
Repairs to the third cooler, which was needed in service during repair of the other two, would follo T
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The licensee summarized the April 18, 1986, meeting and followup activities in a letter to NRC Region I, dated April 25, 1986.
In a followup phone call on May 16, the licensee indicated that he had evaluated the unidentified fan cooler cables, which were neoprene jacketed, standard wire. This review, based on test data of other neoprene jacketed cables, concluded (1) that the cables had been
" operable;"
i.e., able to perform their intended function; but, (2)
the cables could not be considered EQ qualified, since there was no vendor specific test report.
10.4 Findings Based on the licensee's EQ methodology and previous NRC reviews of the licensee's program, the NRC's EQ concerns involve only " common equipment." The licensee's original basic approach to identifying these items appeared reasonable; however, significant errors were made that resulted in failure to meet requirements of the NRC's rule on environmental qualification. These failures are detailed below.
Compounding this problem was the licensee's lack of independent verification of design input to the EQ tile development.
Subsequent to the NRC PAT team identification of unevaluated cable, the licensee conductec a reasonable reverification program to identify and resolve additional similar problems prior to restart from the eddy current cutage.
The NRC rule on Environmental Qualificatior, of Electrical Equipment Importart to 5,afety for Nuclear Power Plants, 10 CFR 50.49, required licensees to establish a program for qualifying electrical equip-ment, including safety related equipment, non-safety-related equip-ment whose failure could prevent accomplishment of critical safety functions, and certain post-accident monitcring equipment (per Regulatory Guide 1.97, Revision 2).
Licensees were required to develop lists of alectrical equipment covered by this rule.
Each item of equipment was to be Qualified to performance specifications under conditions existing during and following design basic acci-dents by tiarch 31, 1985, unless specific extension (to no later than November 30, 1985) was obtained from NRC;NRR.
Licensees are re-quired to maintain records of qualification in an auditable form.
The licensee's EQ program did not meet 10 CFR 50.49; in that, the following equipment (1) was not identified or, the list of equipment covered by the rule; (2) were not evaluated for qualification to plant-specific performance specifications; and (3) were not reflected in plant E0 records.
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l (1) KERITE FR cable, which is used extensively in circuits requir-l ing environmental qualificaticn; (2) BIW Silcone Ruober cable, used in circuits for post-accident monitoring of Reactor Building sump level; and, (3) Unidentified cable segments on safety-related Reactor Duilding air handling units As a result of itcm (3) above, the ability of the air handling units to function in a harsh envircnmert was urdeterminable and the units were, therefore, not operable as reauired by Technical Specification 3.3 during varfeus periods of reactor operaticn bet een October 3, 1985, and March 21, 1986.
The above-listed e nmples of failuro to meet 10 CFR SC.49 are a apparent violation (289/86-06-07).
10.5 Inspection Followup NRC review during t5is intpection focused or, ensuring that the licensee took adecuate short-term actions, prier to startup, relative to the EQ concerns evolvirg from tne NRC PAT inspecticn.
Long-term and programmatic correctiva actions will be reviewed as part of NRC followup to the violatitn cited above.
NRC followup will elso include a sarapling verification of short-term items discussed in the license? s April 25, 1986, letter; such as the BlW cable file, the GE teritinal eleck file, corrections tc the master EQ list, and operabliity c.aluation for R9 fan cables.
This is an inspector followup item (289/85-Gf]-C3).
10.6 Conclusion As discussed in dctati in 1C.3 cbove, the licensee's EQ master lists and files apparently were net entirely correct relative to the manufacturers and nadel numbers of terminal biccks.
Based on the currently available informaticn, these inaccuracies do ret appear individually safety significant and are corsidered additional examples of not adequately i'rplemeriting 10 CFR 50.49.
11.
Licensee Event Reoorts (LERs) In-Of fite Review The inspector reviewed the LERs listed below, which were submitted to the NRC Region I office pursuant to 10 CFR 50.73.
Based on resident office review of the LERs, the inspector determined that corrective action discussed in the licensee's report was appropriate, th&t tFe information satisfied reporting requirements, ana that there were no generic issues.
In addition, the inspecter deterrined that th3 event is not appropriate either for classification as an Abvreral Occurrence or for Licensing Board, Appear Board, or Cnmrission notificaticn.
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l For events that warranted on-site folle,vup, an on-site review was performed at the time of the event.
NRC inspection report containing the on-site review is stated in the description of the event if the review was required.
LER 86-001 on January 3, 19S6, dated February 1986.
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Snuober RC-18 was most probably due to failure to complete proper restoration of the component fcilewing maintenance.
The snubber had found unpinned and disconnected at one end during a routine visual inspection. The snubber was repaired within seventy-two hours of discovery.
-- LER 86-002 on January 04, 1986, dated January 29, 1986. An anticipatory trip occurred at 22 percent power due to a turbine trip, which resulted from high moisture separator level.
The reactor protection system responded as expected to the anticipatory trip signal and plant response was normal. The moisture separator level control valve HD-V-4 was replaced and power escalation re-commenced.
(This event was reviewed in NRC Inspection Report No.
50-289/85-30.)
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LER 86-003 on January 14, 1986, dated February 14, 1986. An undervoltage relay associated with the shunt trip feature of the control rod drive trip breaker f ailed to function during monthly surveillance.
The cause was due to the incorrect positioning of a jumper, internal to the relay. The jumper was repositioned from the 48 VDC position to the 125 VDE position.
(This event was reviewed in NRC Inspection Report No. 50-289/86-01.)
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LER 86-004 cn February 27, 1986, dated March 27, 1986. The isolation of condenser offgas radiation monitor RM-A-SL during 100 percent power operations was due to personnel error. When RM-A-5L was out of service, RM-A-13 was not continuously watched as required by TS 3.12-2, Item 4.
(This event was reviewed in NRC Inspection Report No. 50-289/86-05.)
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LER 86-005 on March 11, 1986, dated April 9, 1986.
Inoperable fire door C310 was due to excessive clearance between the bottom of the coor and the floor, a violation of TS 3.18.7 and NFPA Code 80, Section 3-6.1.
A section of angle iron was installed full distance between tne door frame and anchored to the floor, eliminating the door-to-floor clearance.
(This event was revicwed in NRC Inspection Report No. 50-289/86-05.)
LER 86-006 on March 15, 1986, dated April 11, 1986.
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reactor trio from 100 percent pcwer caused by a low pressure spike in the turbine lube oil system was due to transfer valve operation during operations surveillance.
The root cause was personnel error and procedure inadequacy, which resulted in valving in a standby lube oil coole" that was r.ot full pressurized.
(This event was reviewed in NRC Inspection Report No. 50-289/86-05.)
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LER 86-007 on March 26, 1986, dated April 25, 1986.
As a result of a safety system functional inspection by PAT, installed emergency feedwater two-hour backup air supply system was found not to meet the single failure criteria.
During a seismic event and either one of two check valves IA-V-1451 and IA-V-1460 failed, both air banks of the backup system would be discharged to the environment.
(This event was identified in NRC Inspection No. 50-289/86-03 and reviewed in this report.)
Excepc as noted below, these LERs were closed based on satisfactory in-office review and additional on-site event review.
For LER 86-006 two other post-startup items were identified for review by the licensee's Technical Functions Division.
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At the time of the trip, the saturation margin monitor (SMM)
instruments responded by indicating 25-30 F subcooling margin. One computer channel alarmed (indicating lass than 25 F).
Redundant subcooling instrumentation and the post-trip P-T plot indicated that saturation margin was above 50 F.
Licensee personnel believe that the response of the SMMs was due to resistance temperature detector (RTO) response.
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The plant did not get to the post-trip P-T window until about twelve minutes; whereas, the procedural guideline is ten minutes.
The post-trip review determined that the cause of the problem was feedwater flow going to zero or the regulating valves going shut.
This was unanticipated for proper Integrated Control System (ICS)
Once-Through Steam Generator (OTSG) level control.
I&C personnel were tu work on the applicable controllers during the eddy current outage.
Accordingly, this area is unresolved pending Region I review of Technical Functions disposition of the post-startup items noted above (289/86-06-09).
12.
Followup to Former GPUN Employee Concerns A former GPUN employee contacted Region I on January 21, 1986, to express certain general concerns. A followup call, initiated by Region I, to the same former GPUN employee was held on January 22, 1986.
During these phone conversations, the contact discussed a number of areas in which he felt certain safety concerns existed.
It was initially anticipated that a meeting would be held with the former employee to discuss these matters in detail. However, Region I was not able to recontact the individual.
The general concerns were in the following areas:
(1) operations with a new large capacity makeup valve MU-V217; (2) an engineered safety feature (ESF) ventilation system; and (3) the offgas radiation monitor RM-AS.
These matters were stated to have been identified to the licensee also.
During this inspection, a followup was conducted to determine the details associated with the general safety concerns expressed.
The concerns and related findings were as follow._
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12.1 MU-V217 Design Concerns Several concerns were expressed to the NRC associated with a large capacity makeup valve (FU-V217), which was installed in 1981. These, as well as additional concerns related to operation with this valve, had been brought to the attention of the licensee and, in response to these concerns, the licensee performed a detailed evaluation, which was completed on January 22, 1986.
One concern expressed was related to higher flow rate than designed being measured through MU-V-217.
This valve was installed in con-junction with a modification which mechanically interconnected the high pressure injection (HPI) legs in order to mitigate the effects of a small break occurring in a HPI line at or near its connection to the reactor coolant system (RCS).
The valve was installed as a means of quickly restoring pressurizer level, following a rapid cooling of the RCS, without thermal shocking a RCS HPI nozzle.
The system design description (SDD 211A, Revision 3) stated opening high flow capacity makeup valve MU-V-217 rrakes a maximum of 425 gpm available through HPI "B" leg at a RCS pressure of 1800 psig.
This is using one makeup pump.
Facility Abnormal Transient Procedure 1210-1, "
Reactor / Turbine Trip," specifies the use of this valve requires start-ing a second makeup pump prior to opening MU-V-217.
The licensee's evaluation with two pumps operating and the RCS at 1600 psig identi-fies a flow of 575 gpm.
Prior to the installation of MU-V-217, the method by which increased makeup was established was by opening the
"B" leg HPI valve MU-V-16B and ficw through this path under the same condition was 620 gpm.
Consequently, the overall plant makeup flow has not been increased by the addition of MU-V-217.
Also, the valve is intended to be throttled in response to pressurizer level.
The thermal transient on the "B" HPl nozzle, due to the increased flow, was also evaluated by the licensee; and it was determined that the transient associated with a HPI, a condition for which the system has been evaluated, is more severe than the makeup transient with the higher flows permitted by MU-V-217.
A second concern expressed was that the SDD specified MU-V-217 be used with one makeup pump while procedures specified the use of two pumps in conjunction with the use of MU-V-217.
Revision 3 of SDD 211A in Table 7 describes makeup flow rates through MU-V-217 with both one and two pumps in operation.
Licensee reviewed and approved procedures do specify starting a second makeup prior to opening MU-V-217.
This is consistent with the intent of providing maximum makeup when the use of MU-V-217 is required.
A third concern was that operations personnel do not understand what constitutes a thermal cycle and are recording cycles improperly.
Discussions with personnel and a review of the transient cycle log book for the high pressure injection nozzles shows that there is L
validity to this concern.
This had been recognized by the licensee and a technical functions work request had been prepared on April 12, 1985, which requested that the exact criteria which defines a thermal cycle be specified.
The licensee's identification of what constitutes a thermal cycle and the establishment of the logging requirements is considered to be an unresolved item (289/86-06-10).
The transient cycle log indicated, to date, thermal cycles have been experienced as follows:
"A" nozzle, 27; "B" nozzle, 21; "C" nozzle, 23; and "D" nozzle, 22.
The current limit is 40 cycles.
The fourth and final concern associated with the operation of MU-V-217 was that the guidance provided the operators as to when to use the valve was unclear.
The criteria for initiation of HPI is stated in Abnormal Transient Procedure 1210-10.
This criteria is (1) 1600 psig ESAS has auto initiated; (2) subcooling margin is 25 F or (3) neither OTSG is available as a heat sink. Also step 2.6 of the procedure, which specifies when to open MU-V-217, states that if unable to maintain pressurizer level greater than 20 inches, initiate HPI.
The inspector concluded that this procedural guidance is sufficiently clear.
12.2 Fuel Handling Building _ Ventilation Design Conceras
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Certain concerns were expressed in regard to the fuel handling area engineered safety feature (ESF) ventilation system. GPUN is cur-rently in the engineering design stage to modify the fuel handling building ventilation system.
The new ESF ventilation syste:a is being installed to mitigate the consequences of a Unit 1 fuel handling ac-cident.
By letter dated March 27, 1986, the licensee provided to NRR a description cf the ESF ventilation system, which is scheduled to be operational prior to moving fuel during the cycle 6 refueling outage.
In general, the concerns expressed by the former employee are address-ed in this submittal to NRR.
This document was probably not available to him when the concerns were raised.
The first concern dealt with the design basis of the ESF ventilation system for the fuel drop accident, in that the analysis assumed less damaged fuel rods than indicated in applicable regulatory guidance.
The licensee's submittal to NRC:NRR identifies the design requirement of the ESF ventilation system to mitigate the consequences of the effluent resulting from a 208 damaged rod accident. Although the FSAR fuel handling design basis accident consists of damaging 56 rods, the licensee's subnittal describes the new ESF ventilation system design capable of mitigating the consequences of the effluent resulting from a 208 rod accident.
Tables included in the submittal identify the source terms for 56 and 208 danaged rods.
This is indicated to be within the guidelines of Regulatory Guide 1.25, " Assumptions Used for Evaluatino the Potential Radiological Consequences of a Fuel Handling Accident in the Fuel Handling and Storage Facility for Boiling and Pressurized Water Reactors."
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A second concern expressed re:ated to the system classiffcation The licensee's submittal identif ies tne system classifications.
Tne motor cantrol centers are classified as nutiear saf ety related (FSR), tiie work related to the new penetrations ;n the ful bandling/auxiliarj building are also NSR.
Worr. assaciati.d with the ESF nntilation systen enclosure heating ana ventilation s;ystem, the enclosure light-f ng and the combustible gas detecters assoc ated with the fire c'ampers i
are classified as "not important to safety." All other work necessary te implement the E5F ventilation system is clas*,ified as " imp;rtant to safety." The system design tie;criptioa SDD-T1-845A, Revision 4 specifies these classifications. Also, a review of drawings associ-ated with the modification showed them to be corrbetly classified as important to safety.
A third concern related to system dampers not being redundant ard the dampers and fan house not being of seismic design.
The licensee's submittal identifies the system es cofisistitig of two 100 percent capacity filtration units; consequently, total redunciancy is provided. Additionally, the submittal Jescribes certain dampers and the associated ductwork and provides a point-cy point comparison of the requirements of the ESF ventilation system and Res.Jiatory Guide 1.52, " Design, Testing, and Maintenance Criteria for Post-Accident Engineered-Safety Feature Atmosphere Cleanup System Air Filtration and Adsorption Units of Light-Water-Ccoler Nuclear Power Plants,"
and the Standard Review Plan, Sections 6.5.1, 9.4.2, and 15.7.4.
Also, specific design features are as contained in ANSI /ASMC N 509.
With regard to seismic considerations, the submittal notes the Auxiliary Building structure, on which the new ESF vertilation system will be located, has been evaluated for the additional loadings under seismic Class I conditions; and no 2.dditional structural supports are required.
The submittal also notes the components of the ESF ventilation system and their enclosures are not required to be seismically qualified, since their failure daring a design basis seismic event would resJlt in on-site hPd off Site doses below 25 percent of 20 CFR 100 limits.
The fourth and last concern dealt with operating procedures allowing excessive continued operation (50 minutes) of the TMI-2 ventilation in the fuel handling building following a TMI-1 fuel drop accident.
At present, no operating procedures for the system have been prepared which address the time required to secure the Unit 2 fuel handling accident. Neither the Safety Evaluation SE No. 912336-C31, Revision 1, or the Systein Design Description 500-7I845, Revisicn 4, discuss any time requirement associated with the required manual trip of the Unit 2 normal fuel handling building ventilation fans af ter being notified by TMI-1 of a fuel handling acci(ient.
Discus-sions with personnel indicated that at some time during the conception of the modification, 50 minutes was assumed as the time allowed in the evaluation to secure the Unit 2 ventilation system.
The licensee's submittal addressed this matter by stating, "Should a TMI-1 spent fuel accident occur in the FHB, the TMI-2 operator will
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manually trip the TMI-2 normal FriB ventilation fans after being notified by TMI-1 operator about the accident." Also, "The manual isolatioa of the TMI-2 FFB ventilation system is solely to provide capability to discrir.1lnate between effluents resulting from Unit I and Unit 2 oceraticns. Operatio-of the TMI-2 FH3 ventiliticr.
system is not necessary for the proper functionirg of the TMI-2 FHS E3F ventilation system.
Since the Unit 2 ventilation system will include iodine filtration capatil1ty, its operation during a fuel handling acc7 dent will mitigate the effects cf the accident if it is operating at the time of the fuel handling accident and therefore its isolation need not be Smediata." The licensee's submittal is subject to NRR review and final acceptance of the r.1odification is based un the ret,ults of this review.
12.3 Condenser Offeas R;alation Monito,r Design Conceras A concern vis expressed that the cffgas radiattar: monitor /RMA-5)
would not work if the condanser vacuum is low ar.d t. Sat represent 4tisa grab camples cannot t,e obtained due to a poor fesign.
During plant conditions, where steam flows to che main co1 denser via the main turbice or bypass vahes, the main conderser vacuum punps are used to maintain tha main condenter at a sub atmosp*eric pressure.
The RNA-5 monitor cbtains a sample f om the main condenser vecuum pymps dt schargu header and rett.tn3 the sample to the main condenser vatuum pumps suction line.
T le RW-5 sartpli,g system uses the differ 6.itici pressurc between the vacuum pamps di.scharge ar.d sucticn header s to riave the sample fluid thsaugh the sariple system.
ine salmiing system enturas ttv.t condtnser vacuum pump releases are sampled and anal.vzea in accordance with technical sp?cification requirements.
The sampling ano analysis requirements s.re applicable only wFen condenser vacuum is established During conditicos of low or no vacuum, the mtin turbine steam va Ses and the bW :,ss valves are trevented from opening; cor;equently, release through the condenser vacuum pump exhaust is prGvented.
fhe rsanitor is also used to detect lackago between the primary and serendary system.
The sample taps on the main cord,nse v:.cuum pum suction and
<lischarge lines provide the flow path to the RAA-5 low and t.igh range sepler, to RNA-13 radiation tronitor, a backup to RMA-5, and to 4 manual sa7plc station. Also, exterded ranges for pest-accident monitcring are providod.
This extended range mc11tsrin, uses the scme sample chambar as RMA-5.
In addition, by letter, dated Nove nber 2% 1985, the licenseo provided NRR sith desinn '..ife-mat. ion for a me'iification snicF. will provide ; means fo-cbtclninga representati.e sample of the ;orderser Offgas througf. a sa rpla chamber +. hat can e.ollect both par ciculates and iteine'. for analysis.
~.
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Y
During this inspection, the physical installation of the sampling system and the condenser vacuum pump release sampling Procedure 1301-5.9 were reviewed.
RMA-5 is normally operated continuously, the flow rate is manually established, and the sample line blown down once each shift.
Procedure 1301-5.9 provides detailed instructions for manually obtaining tritium, radiciodine/ particulate and means for analysis for principal gamma emitters.
The procedure provides instructions for correcting the observed flow rate for low vacuum conditions.
12.4 Conclusion Overall results of this review show that many of the former employ-eus concerns, which related to the large capacity makeup valve M' -V-219, had been made known to the licensee. A detailed review J
acc evaluation of these concerns was performed by the licensee to resolve these matters.
One unresolved item relating to HPI cozzle thernal cycles resulted from these issues.
The concerns related to the E3C ventilation system appear to have been resolved in the licensce's submittal, " Fuel Handling Area ESF Ventilation S/ stem,"
to NRR for licensing review, dated March 27, 1986.
This information probably w:s not available to the former employee when he contacted Regior I.
Condenser cffgas monitoring, although requiring frequent blowing down of sample lines and manual ' low adjustment, meets regu-latorj requirements.
Design improvements for condenser offgas monitoring are scheduled for the next refueling outage.
13.
Licensee Action on Previous Inspection Findings The insDector reviewed licensee action on previous inspection findings to enture that the iicensee took appropriate action in respoase to the findings or by self-initiative and that the licensee's action was timely.
13.1 { Closed) Inspector Follow Item (50-289/85-20-04):
Safety Evaluation for EF-V3.
During the NRR review of the licensee's inservice
~
testing (IST) program, a discrepancy was noted in that the emergency river water suction source check valve EF-V3 is only partially stroke tested in AF 1300-3G A/G, " Turbine-Driven EFW Pump Functional icst and Valve Operability Test" (Letter of October 23, 1984, J. F.
Stolz to H. D. Hukill). ASME Code,Section XI, Subsection IWV, states that check valves can be partially stroke tested during plant j
operations if full stroke testing is not practical, but the valves I
rust be fully st.roke tested during periods of cold shutdo.m in three months has elansed since the last full stroke functional test.
Since the full stroke testing of valve EF-V3 woult! introduce river water, Silt, and CorrQsives into the suction piping of the EFW pumps and OTSGs, the licensee requested from the NRC IST relief to conduct p utial strop testing of EF-V3 in lieu of full stroke testing.
The request was denie.
.
The open item concerned the evaluation of the safety impact of the licensee's plan to remove the internals of the check valve so that inservice testing of EF-V3 is not required. The valve internals were removed during the last shutdown outage (5M).
The inspector reviewed the 10 CFR 50.59 nuclear safety / environmental impact evaluation (SE No. 000424-003).
Tne functjon of EF-V3 is to prevent reverse flow from the suttion side of the EFW pumps to the RB emergency cooling water system and nuclear service closed cooling water system.
The operating pressure for both cooling water systems is higher than the suction pressure of the EFW pumps. The conden-sate storage tanks (CSTs) will not drain back to the river water system.
In addition, two normally locked closed motor-cperated valves (EF-V4 and 5), located upstream of that check valve, can perform the isolation function between the two cooling water systems and the EFW system.
These two valves (EF-V4 and 5) can be opened to supply the EFW pumps with emergency backup river water only in the unlikely event that the water inventory from both CSTs, condenser hotwell, and the demineralized water storage tank is exhausted.
Therefore, the inspector agreed that there is no need for check valve EF-V3 in the EFW system.
The inspector confirted that EF-V3 will t'e deleted from the next revisions to the following documents:
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FSAR Figure 10.6-1;
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SP 1300-3G A/B, " Functional Test and Valve Operability Test;"
and, SP 1300-3R, "IST of Valves During Shutdown and Remove Indica-
--
tion Check."
The inspector has no further questions and this item is closed.,
13.2{ Closed)InspectorFollowItem(50-289/85-25-02):
Repair of 1Furmanited" Valves During a tour of the RB for a post-trip inspection on October 21, 1985, two leaks were identified.
One leak was on a flange on the EFW spray ring header and the other a body-to-bcnnet leak on FW-V-1093, an unisolatable steam generator IA level detector root valve. The licenses repaired the valves using the "Furmanite" process and committed to making permanent repairs during the next outage. During the SM outage, all of the EFW spray ring header and riser flanges were removed for inspection of the rpray nozzles.
The furmanite repaired flenge was permanently repaired at this time.
FW-V-1093 was also permanently repaired during the outage.
The inspector witnessed various portion of the (EFW) flange repair.
Since the repairs have been made, no leaks have been observed from these system l 13.3 (Clos _ed) Inspector Follow Item (289/85-28-02):
Surveillance _ Testing for Makeup Pump 1A A review of the quarterly surveillance tests for MU-P-1A,18, and 1C had revealed that on two occasions during 1985 the delta-P reading for MU-P-1A had been in the alert range.
The licensee had increased test frequency to six weeks as required by technical specifications.
Subsequently, the licensee calculated a new referenced value for the delta-P data in November of 1985 and returned the test frequency to the quarterly time period.
Subsequent testing on February 5,1986, and May 7, 1986, revealed that the delta-P values were in the normal range for the-new referenced value.
The inspector had no further concerns in this area.
14.
Exit Interview The inspector conducted an interim exit interview on April 18, 1986, in the area of transportation of radioactive materials. The inspectors discussed the inspection scope and findings for the entire period with the licensee management at a final exit interview conducted May 16, 1986.
The following key licensee management personnel attended the final exit meeting:
R. Barley, Manager, Plant Engineering, TMI-1 J. P'itz, Plant Engineering Director, TMI-1 H. Hukill, Director, TMI-1 C. Incorvati, TMI-1 Quality Assurance Audit Supervisor, Nuclear Assurance M. Ross, Operations Director, TM1-1 C. Smyth, TMI-1 Licensing Manager, Technical Functions R. Toole, Operations and Maintenance Director, TMI-1 A representative from the Commonwealth of Pennsylvania, Mr. Ajit Bhattacharyya, also 4,ttended the final exit meeting.
The inspection results, as discussed at the meeting, are summarized in the cover page of the inspection report.
Licensee representatives indicated that none of the subjects discussed contairted proprictary or safeguards irformation.
Unresolved Ite.ns are matters about woich information is rcquired in order to ascertain whether they are acceptable ite:ns, violations, or devia-tions.
Unresolved iter (s) discussed during the exit meeting are docu-mented in paragraphs 2, 4, 6, 8, 11, and 1 ATTACHMENT 1 PROCEDURES REVIEWED OP 1101-3, " Containment Integrity and Access Limits," Revision 39, completed April 20, 1986 OP 1102-1, " Plant Heatup to 525 Degrees F," Revision 83, completed April 23, 1986 OP 1102-2, " Plant Startup," Revision 29, completed March 25, 1986 OP 1102-12, " Hydrogen Addition and Degassification," Revision 8, completed April 19, 1986 0F 1103-2, " Fill and Vent of the Reactor Coolant System," Revision 53, com-pleted March 20, 1986 OP 1103-4, " Soluble Poison Concentration Control," Revision 24, completed April 21, 1986 OP 1103-5, " Pressurizer Operation," Revision 33, completed April 21, 1986 OP 1103-6, " Reactor Coolant Pump Operation," Revision 33, completed April 21, 1986 OP 1103-8, Approach to Criticality," Revision 24, completed April 24, 1986 OP 1104-1, " Core Flooding System," Revision 11, completed April 21, 1986 OP 1104-2, " Makeup and Purification System," Revision 57, completed April 22, 1986 OP 1104-4, " Decay Heat Removal System," Revision 58, completed April 22, 1986
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OP 1104-5, " Reactor Building Spray System," Revision 25, completed April 16, 1986 l
OP 1104-8, " Intermediate Cooling System," Revision 28, completed April 16, 1986
OP 1104-9, " Circulating Water," Revision 25, partial completion April 8, 1986 OP 1104-29E, " Bleed and Feed Processes," Revision 19, completed Anril 21, 1986 OP 1105-2, " Reactor Protection System," Revision 20, completed April 20, 1986 OP 1105-4, " Integrated Control System," Revision 19, completed April 23, 1986 l
OP 1105-9, " Control Rod Drive System," Revision 31, completed April 21, 1986 OP 1106-1, " Turbine Generator," Revision 41, completed April 16, 1986 OP 1106-2, " Condensate System," Revision 36, partial completion April 18, 1986 OP 1106-3, "Feedwater System," Revision 34, partial t#cpletion April 17, 1986 OP 1106-10, " Turbine Gland Steam Supply System," Revision 6, comp!eted April 21, 1986 OP 1106-12, " Extraction System, Heater Vent and Drains," Revision 30, complet-ed April 20, 1986 OP 1106-14, " Main Steam System," Revision 34, completed April 21, 1986 OP 1106-16, "0TSG Secondary Fill, Drain and Lay Up," Revision 33, completed March 28, 1986 SP 1300-3F, " Motor-Driven Emergency Feedwater Pump Functional Test and Valve Lineup Verification," Revision 16, completed April 20, 1986 SP 1300-3G A/B, " Turbine-Driven Emergency Feedwater Pump Functional Test and Valve Operability Test,: Revision 22, partial completion April 8, 1986 SP 1303-11.39, " Emergency Feedwater Pump Automatic Start," Rev.ision 7, com-pleted February 27, 1986 SP 1303-11.42, " Emergency Feedwater Flow Test from Condensate Storage Tank,"
Revision 4, completed April 20, 1986 SP 1303-11.53, " Emergency Feedwater Flow, Revision 5, completed April 2,1986
ATTACHMENT 2 PRINCIPAL PARTICIPANTS IN EQ MANAGEMENT MEETING AND CONFERENCE CALLS I. April 1 Conference Call A.
GPUN J. Mancinelli, Manager, EQ and Fire Protection R. McGoey, Manager, PWR Licensing B.
N_RC R
R. Blough, Chief, Reactor Projects Section 1A, Region I J. Thoma, Licensing Project Manager, NRR II. April 3 Conference Call A.
GPUN J. Mancinelli, Manager, EQ and Fire Protection R. McGoey, Manager, PWR Licensing B.
NRC C. Anderson, Chief Plant Systems Section, Region I R. Blough, Chief, Reactor Projects Section IA, Region I W. Johnston, Deputy Director, Division of Reactor Safety, Region I R. LaGrange, Technical Reviewer, NRR J. Thoma, Licensing Project Manager, NRR R. Weller, Section Leader, PWR Licensing Directorate No. 6, NRR III. April 11 Conference Call A.
GPJN J. Mancinelli, Manager, EQ and Fire Protection R. McGoey, Manager, PWR Licensing J. Thorpe, Director, Licensing and Regulatory Affairs B.
N_RC C. Anderson, Chief, Plant Systems Section, Region I R. Blough, Chief, Reactor Projects Section 1A, Region I J. Durr, Chief, Engineering Branch, Region I S. Ebneter, Director, Division of Reactor Safety, Region I J. Thoma, Licensing Project Manager, NRR G. Zech, Chief, Vendor Program Branch, IE
T
IV. NRC/GPUN Meeting on Equipment Qualification - April 18, 1986 A.
GPUN P. Boucher, Equipment Qualification R. Chisholm, Manager, Electrical Power & Instrumentation J. Colitz, Director, Plant Engineering L. Harding, Manager, Qual. Class. & Eng. Configuration C. Hartman, Manager, Plant Engineering H. Hukill, Director, TMI-1 L. Lanese, Safety Analysis & Plant Control G. Lehmann, Engineering & Design R. Liscom, QA Engineer J. Mancinelli, Manger, EQ and Fire Protection J. Marsden, Manager, QA Engineering R. McGoey, Manager, PWR Licensing K. Meyer, NSCC E. Pagan, Manager, Equipment Qualification L. Robinson, Media Representative P. Smith, Safety Analysis & Plant Control C. Smyth, Manager, TMI-1 Licensing R. Toole, Operations & Maintenance Director C. Tracy, Director, Engineering Assurance R. Wilson, Director, Technical Functions B.
NRC R. Blough, Chief, Reactor Projects Section 1A, Region I R. Conte, Senior Resident Inspector, TMI-1 J. Durr, Chief, Engineering Branch, Region I H. Garg, NRR/DPL-B/P/PEICSB W. Kane, Deputy Directory, Reactor Projects, IE R. LaGrange, NRR/ DBL /E0 Section Leader J. Miller, Deputy Director, QAVT U. Potapovs, Chief, EQ Section J. Thoma, Licensing Project Manager, NRR G. Zech, Chief, Vendor Program Branch, IE C.
Commonwealth of Pennsylvania A. Bhattacharyya, Nuclear Engineer, Pennsylvania Department of Environmental Resources