IR 05000289/1987005
| ML20205S540 | |
| Person / Time | |
|---|---|
| Site: | Three Mile Island  |
| Issue date: | 03/27/1987 |
| From: | Blough A, Conte R, Dante Johnson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20205S503 | List: |
| References | |
| 50-289-87-05, 50-289-87-5, IEIN-87-008, IEIN-87-8, NUDOCS 8704070051 | |
| Download: ML20205S540 (23) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report N /87-05 Docket N >
, License N 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
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Inspection Conducted: February 6 to March 6, 1987 Inspectors: R. Conte, Senior Resident Inspector (TMI-1) D. Johnson, Resident Inspector (TMI-1) J. Rogers, Resident Inspector (TMI-1) F. Young, Resident Inspector (TMI-1) ReportingInspector[: q 0. Johnson,MsidentI JNW , Inspector (TMI-1) -Date Reviewed By: g [ [[ R. Conte, Mnior Resident Inspector (TMI-1).
M':P7 Date " Approved By: I A. BloughfChief 3 Date Reactor Projects Section No. 1A Division of Reactor Projects Inspection Summary: The NRC resident staff conducted safety inspections (169 hours) of outage activities, focusing on plant and personnel performance. .Specifically, items reviewed in detail in the operation, maintenance, and surveillance areas were:
. emergency diesel' generator (EDG) "1B" "run-in" testing; loss of "1E" ' vital bus, reactor trip breaker wiring errors; and, the tripping of the auxiliary trans-former "1A". Other items included followup on NRC Information Notice 87-08, EDG "1A" overhaul, fire protection system upgrades, and ' licensee action on previous inspection finding l
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Inspection Summary (Continued) 2 i , Inspection Results: i Licensee personnel exercised reasonable control over shutdown and test activi-
- tie In general, technical problems were effectively resolved, 'such as 'for the post-overhaul damage to the emergency diesel generator (EDG) "1A". How-ever, continuing signs of weak technical support appeared as evidenced by wir-
ing errors in modifications for the EDG "1B" and reactor protection system
- breakers. These presented unnecessary challenges to operating and test per -
sonnel during appa.rently premature testing. Licensee self-evaluation of these
- events . properly noted that, when challenged, operating and test personnel did not take timely and conservative actions in certain instances. For example, 4 there were six attempts to start a diesel generator for troubleshooting during tests. No adversity to safety resulte Weak technical support also appears to be a contributing factor in delays on licensee submittals for exemptions to fire protection rule Further, the above noted challenges seem to be centered around fire protection upgrade wor However, a significant amount of fire protection upgrade work was completed during this outage to assure compliance with regulatory requirements. This area will be further reviewed by NRC staff in a future inspection. Operator training for complex modifications, such as the heat sink protection and remote shutdown systems, appear to be well thought out and substantia During this inspection, the licensee identified an error in NRC Inspection
, Report No. 50-289/86-22 regarding the licensee's reactor coolant pump seal !
evaluation A clarification is provided in paragraph 5.6 of this repor No violations of regulatory requirements were identifie ,
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DETAILS
! Introduction and Overview *
1.1 NRC Staff Activities The overall purpose of this inspection was to assess licensee activ-ities during the cold shutdown mode as they related to reactor safety
, ' and radiation protection. Within each area, the inspectors documen-ted'the specific purpose of the area under review, scope of inspec-tions, 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, measurement of radiation levels, or independent calcula-tion and selective review of listed applicable document The NRC resident office inspectors supported and participated in the
- Readiness Assessment Team Inspection conducted February 17 to March 3, 1987 (see NRC Inspection Report No. 50-289/87-06).
n 1.2 Licensee Activities
- During this period, the licensee maintained the plant in cold shut-
- down. Preparations for plant startup began with the completion of
outage-related work leading to system valve lineups and repressuriza- . tion of the reactor coolant syste . Plant Operations 2.1 Scope of Review The NRC resident inspectors periodically- inspected the facility to determine the licensee's compliance with the general operating re-quirements of Section 6 of the Technical Specifications (TS) in the following areas:
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review of selected plant parameters for abnormal trends; '
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plant status from a maintenance / modification viewpoint;
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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;
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implementation of radiological controls; }
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implementation of - the security plan, including access control, boundary integrity, and badging practices; and,
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implementation of the fire protection plan, including fire barrier integrity, extinguisher checks, and housekeepin Because of additio.nal resident office coverage at this facility, more detailed and frequent reviews of operating personnel performance were conducted to determine that:
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operators are attentive and responsive to plant parameters and
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plant procedures are used and followed as required by plant policy;
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equipment and status changes are appropriately documented and communicated to appropriate shift personnel;
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the operating conditions of the 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 appropriate when normal instrumentation is found to be defective 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 conservative operating practices in conducting plant operations; and,
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operator actions are consistent with performance-oriented trainin Specifically, the inspectors focused attention on the areas listed belo General / Operations
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Control Room operations during regular and backshif t hours, including frequent observation of activities in progress, and ) periodic review of selected sections of the shift foreman's log and Control Room operator's log and other Control Room daily logs
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Areas outside the Control Room, including important-to-safety buildings
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Selected licensee planning meetings l
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Maintenance
-- . EFW turbine steam supply line check valve, MS-V-9A/B, reassembly i
! -- EG-Y-1A and 1B emergency diesel generator yearly maintenance
Surveillance
- - EG-y-1B - diesel generator post-maintenance testing i
The inspectors' findings and conclusions are described belo .2 Findings / Conclusions , , 2. Followup to IE Information Notice 87-08 The NRC Information Notice No. 87-08 was issued on February 4,1987, and identified a problem with certain d.c. motors on limitorque motor operators. The wiring in some of these motors, which were manufactured .by H. K. Porter (now Peerless-Winsmith), contained Nomex-Kapton insulated leads that are susceptible to insulation degradation and short
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circuit failure. The inspector requested that the licensee j determine if any such motors existed or were in use at j TMI- The licensee responded that only two valves at TMI-1 had d.c. motor operators. These valves were, MS-V-10A/B, which supply low pressure steam to the emergency feed pump turbine. The inspector verified that both motors were d.c. motors manufactured by the Reliance Corporatio , The inspector concluded that the concerns described in IE i Information Notice 87-08 were not applicable at TMI-1. The inspector had no other comments relating to this matte . Rewiring of Reactor Protection Trip Breakers
On February 24, 1987, during instrument calibration checks of the electro-hydraulic system, licensee' Instrument and - Control (I&C) technicians discovered that the control rod drive mechanism (CRLM) a.c. breakers (Nos.10 and 11) tur-
- bine trip on reactor trip circuitry was wired in series and not parallel as required for proper plant operatio The
' wiring change was made during the current outage for fire protection upgrading with "Rockbestos" cable replacemen With the CRDM trip breaker auxiliary contacts wired in
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series, if either a.c. breaker is opened, the turbine trip circuit will energiz .. O
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Surveillance -Procedure (SP) 1303-4.1, " Reactor Protection System (RPS)", required that during normal operations each breaker be opened twice each month during reactor protec-
- tion systea (RPS) channel - testing. If the plant was on-
' line, the first RPS channel surveillance would have opened one of the a.c. breakers, would have tripped the turbine , probably resulting in a reactor trip on high reactor cool-ant system pressure.
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The licensee initiated a Field Change Request (FCR) No.
l 50817 to rewire the a.c. breaker contacts in parallel. In
- preliminary discussions with licensee and vendor personnel,
- the inspector noted that the - underlying causes of the wir-
ing design change were unclear. The licensee stated that
- the wiring change should have been a direct exchange of
] "Rockbestos" fire-rated cable for non-fire-rated cable and
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not a circuitry wiring design chang At the end of the inspection period, the licensee was investigating the cause of the event in order to formulate appropriate corrective action This item indicated that the licensee's engineering design review process was weak to allow this design modification to be installe An
- additional concern for a similar problem was addressed in I paragraph 4.3 (re: 289/87-05-01). The NRC staff followup in this area is included in that unresolved ite ,
, 2.2.3 Partial loss of Off-Site Power On March 3,1987, the licensee experienced a partial loss i of off-site power requiring an automatic start and loading of the emergency diesel generator "1B" due to loss of power
, to the "1E" 4160-volt emergency service (ES) switchgea ' The plant was in cold shutdown on the "A" train . decay heat
- removal (DHR) system. The "A" train DHR is powered from
! the ID 4160-volt ES switchgear, which did not de-energize during the even During maintenance on the "A" auxiliary transformer, an ' electrician accidentally bumped the sudden pressure fault relay which stripped the "A" auxiliary transformer of its
< loads. The trip of that auxiliary transformer caused one of two 230 kilowatt buses to trip ("B" bus). All affected 6900-volt and 4160-volt buses (except the vital 4160 volt buses) automatically transferred to the "B" auxiliary transformer as designed. Loss of voltage on the "1E" 4160 volt bus caused the diesel generator to start.
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' The inspector's review of this event included. discussions with cognizant licensee personnel and review of applicable documents. All equipment responded as required and opera-
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l tor action was correct. Since the plant was in cold shut- ' down, the safety significance of this event was minimal.
' The inspector verified that the licensee made the proper
- notifications to the NRC under 10 CFR 50.72. The licensee
" l will issue a Licensee Event Report (LER) within thirty days detailing the corrective actions to be taken to prevent reoccurrence of this event. The LER will be reviewed for accuracy in a future inspection repor .3 Plant Operations Summary Overall, personnel and management exhibited reasonable control over shutdown activities. Personnel attentiveness and the test program < appear to be identifying design and/or installation errors. However, , when symptoms of problems occurred, personnel actions were inappro-priate or not conservative in some instances as detailed in Section 4 of this repor Personnel need to be more careful while working in switchgear panels;
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but, because of space limitations, such events can be expected to
- occur at time Licensee personnel response actions were appropri-
, ate, along with post event critique corrective action The NRC i staff will review the applicable licensee event report in a future
- inspectio . Fire Protection Modifications 3.1 Background The 10 CFR 50.48 requires the licensee to adhere to the requirements of 10 CFR 50, Appendix R, Fire Protection, prior to plant startu Appendix R requires that each licensee complete a fire hazards
- analysis report to ensure that one train of redundant safety-related
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equipment be available for safe shutdown of the plant in the event of a fire in any area of the plant and that certain modifications be performed depending on the outcome of the analysis. The 10 CFR 50.12 and 50.48 allow the licensees to submit a request for exemption from the provisions of Appendix R if such required modifications would not enhance fire protection safety or such modifications are detrimental to the overall facility safety. The Office Nuclear Reactor Regula-1 tion (NRR) must evaluate these exemptions for validity, i
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On March 3, 1987, the resident inspectors had discussions with re-spect to Cycle 6 startup with licensee personnel and management con-cerning the status of the licensee's fire protection upgrade The below-listed topics were discussed concerning the status of each item and its impact on Cycle 6 startu !
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3.2 Associated Circuits The 10 CFR 50, Appendix R, Criterion III.G requires that protection be provided for associated circuits that could prevent ope' ration or mal-operation of redundant trains of systems necessary for safe shut-dow Inspection Report (IR) No. 50-289/86-23 reviewed the common bus con-cern, spurious signals concern, and the common enclosure concer The first two items were considered satisfactory. The common enclos-ure concern (electrical or fire barrier protections) was found inade-quate due to the small sample size of the revie The IR 86-23 stated that the issue must be resolved with NRR prior to startu Licensee's letter, dated December 23, 1986, stated that an interrupt-ing device coordination study and a fault study would be performed i for Appendix R adherence. The licensee informed the resident inspec-
tor that both studies were complete and were available for review.
- The NRR told the licensee that a letter on Appendix R associated
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circuits compliance was required prior to startup. NRR will review this matter at a later date. This situation was acceptable to the inspector.
- 3.3 Emergency Safeguards Actuation System (ESAS) Room (CB-FA-3C) Inspection Report No. 289/86-23 lef t this item open since the licen-see had not yet determined their actions for a fire in this area. A fire in this area could cause reactor building isolation [ isolation of Intermediate Closed Cooling Water (ICCW) to reactor coolant pump (RCP) thermal barriers]. This area also contains the "A" remote shutdown transfer switch (RSDTS) panel for "A" train components.
" The revised response to Generic Letter 81-12, dated February 10, 1987, (5211-87-2028), stated that if a fire occurs in the ESAS room, a senior reactor operator (SRO) would remain in the control room to , monitor parameters and operate components that are independent of the , ESAS room. The control room SR0 would control the cooldown by uti-
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11 zing the remote shutdown (RSD) panels, since the RSD panels cir-cuitry are independent of the ESAS, control, and relay rooms. The revised response to Generic Letter 81-12 is to be reviewed by NRR.
' At the end of the inspection period, no procedures existed for a fire l in the ESAS room concerning the control room SR0 and RSD panel oper- i ator actions and responsibilities. The licensee stated that the pro-cedures for a fire in the ESAS room will be incorporated in Emergency Procedure (EP) 1202-37, "Cooldown from Outside the Control Room," and EP 1202-31, " Fire," prior to startup. The resident inspectors will-review these procedure changes in a later inspection.
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- 3.4 Exemption Requests 3.4 1 Exemption Request, Dated February 2, 1987 (5211-87-2021)
l This exemption requested approval for manual valve actions in lieu of circuit protection for approximately twenty-three valves and one pump. This request was a resubmittal
- of an exemption request that was denied in NRR's Safety 3 -
Evaluation Report (SER), dated December 30, 1986. This.
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request lacked necessary information for NRR to decide on the matter. The licensee agreed that a resubmittal was
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needed prior to startup for NRR to evaluate the exemption
- request for the ventilation syste The NRR intends to i
take action on these exemptions prior to startup.
l 3. Ventilation Exemption Request, Dated February 11, 1987 (5211-87-2033) This exemption requested approval to not protect ventila-tion circuits and equipment in various locations of the plan This submittal supersedes all previous request The NRR informed the licensee verbally that there was not enough time available to evaluate this request prior to startup. The licensee will install a fire watch program
to observe those areas of the plant every twenty minutes that have ventilation cables and components not protected in accordance with Appendix R. The licensee was informed that this exemption request must be withdrawn and a letter
- sent to NRR detailing the specifics of the fire watch pro-gram prior to startu .5 Reactor Coolant Pump 011 (RCP) Collection System The NRC Appendix R inspection determined that the licensee could not produce documentation on the seismic qualification of RCP copper
- instrumentation tubing (289/86-23-04). The licensee stated that a 1 modification concerning seismic upgrade will be completed prior to startup and documentation will be available for inspection prior to startu .6 Air Operated Valves
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, In the licensee's Fire Hazards Analysis Report (FHAR), Revision 7, t '. the licensee committed to perform an evaluation of the potential effects of a fire on air-operated valves required for safe shutdown as required by Appendix R. The licensee's letter, dated January 29, 1987,(5211-87-2022), stated all such valves have redundant operating ,
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methods or redundant valves or systems, except WDL-V-1, 2, 3, 4, and - 5. Emergency procedures will be developed to connect an external air or nitrogen supply for WDL-V-1 or WDL-V-3, 4, or 5 for . fire compen-sation. The licensee stated that the modifications required for this item will be complete and EP 1202-31, " Fire," will be revised prior to startup. This item is subject to NRR revie .7 Review of Emergency Procedure for Remote Shutdown Panel Cooldown
' During review of EP 1202-37, Revision 20, dated January 20, 1987, "Cooldown From Outside the Control Room," the inspector noted the following inconsistencies: --
ESAS room fire procedures had yet to be incorporated;
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the procedure did not include cooldown rates;
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Enclosure 3 for sustained loss of control building ventilation had yet to be written; and,
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corrective measures for component failures were not included in the procedur The licensee stated that the above concerns will be reviewed for incorporation in the next revision to EP 1202-3 .8 Emergency Lighting The 10 CFR 50 Appendix R, Criterion III.J requires that emergency lighting units with at least an eight-hour battery power supply shall be provided in all areas needed for operation of safe shutdown equip-ment and in access and egress routes thereto, unless an exemption from this requirement was approve The Appendix R inspection (IR 289/86-23) found that the licensee did not instail emergency lights in the control room as required by Appendix The licensee stated that the control room lighting will be protected and other plant areas required for safe shutdown will have emergency lighting installed prior to startu The licensee also stated that most of the installation work is complete and ready for inspectio .9 High Impedance Faults Although not directly discussed within the Appendix R rule, this issue developed from an NRC concern that a fire could damage unpro-tected component feeder cables to the extent of increasing the total switchgear current loading to its trip setpoin In this condition, a vital bus could not be restored until the non-essential loads are stripped from the bu .
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In licensee letters, dated January 13, 1987, (5211-87-2008) and-October 22, 1986, (5211-86-2177), the licensee stated that procedures to strip the non-Appendix R protected components from an affected switchgear or motor-control center and bus re-energization' would be incorporated into plant procedures. The inspector verified that EP 1202-37, Revision 8, dated January 20,1987, "Cooldown From Outside the Control Room," incorporated procedures for high impedance faults.
, Licensee was told that NRR will need to evaluate the licensee's program for high impedance fault .10 Issuance of Maintenance Procedure The licensee revised response to Generic Letter 81-12, dated February 10, 1987, stated that repair procedure 1420-Y-30, " Repair of Appendix R Cold Shutdown Circuits," will b'e available for NRC revie This new procedure will incorporate those ::ut and jumper actions required to achieve cold shutdown within seventy-two hours after a fire. The licensee acknowledged that the procedure will be available for NRC review prior to startu ' 3.11 Technical Specification Chance Request (TSCR) Nos. 163 and 169 These two technical specification changes concern the remote shutdown instrumentation and controls operability and testing (TSCR No. 163) and fire detector operability (TSCR No. 169). The licensee stated that neither one of these TSCR's needs to be approved by NRR prior to startup since each component or instrument will have been tested ar:d operable prior to startup. NRR has indicated that neither would be issued before startu Without a technical specification change, the licensee's newly in-stalled automatic sprinkler system at the auxiliary building contain-ment penetration area (elevation 281 feet) will not be accurately described in current Technical Specification (TS) 3.18.3. Deluge sprinkler system TS 3.18.3.2 states that the " manual" sprinkler sys- , tem at the auxiliary building containment penetration area shall be '
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operable or a continuous fire watch will be established within one hour and the system restored to operable status within fourteen days or submit a special report to the Commission within the next thirty days. Since the sprinkler system is now an automatic system, the inspector considered the system operable despite the above-noted con-tradiction in TS. The licensee and the inspector agreed that the closing of a valve to defeat the automatic function (i.e., to convert the system back to manual operation) or establishing a fire watch and issuance of an LER on an operable automatic sprinkler system is in-appropriate. Since an automatic sprinkler system provides greater fire protection for this area and therefore greater overall plant safety, the inspector concluded the TS contradiction is insignificant and the automatic sprinkler system should be in operation while the new and clarifying TS are being reviewed by NR ..
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3.12 Appendix R Operator Training The .iaspector reviewed for completeness and accuracy the licensee's program for training the senior reactor operators (SR0's) and cont ~rol room operators (CR0's) on Appendix R modifications and procedure The inspector reviewed the following documents:
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Training Handout - Remote Shutdown System, Memorandum 3210-87-
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0007, dated January 8, 1987; ) -- Lesson Plan 11.2.01.262, Revision 2, Remote Shutdown Panel; and,
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Lesson Plan 11.2.01.299, Revision 0, EP-1202-37, Cooldown Out-side the Control Roo : The licensee's operator training program consists of four phases:
(1) plant system lecture on the new remote shutdown system; (2) lec-ture on the revised "Cooldown Outside the Control Room" Emergency Procedure; (3) in plant walkdown of the new remote shutdown system; and, (4) evaluation of a plant drill for cooldown using the remote shutdown syste The inspector attended an Appendix R classroom lecture for one opera-tor shift and observed various walkdowns and drills in the plan All personnel contacted were knowledgeable concerning the require-ments of Appendix R, the functional use of the remote shutdown sys-tem, operator actions required for remote shutdown, and the need for cooldown procedure adherenc The inspector noted that the lecture portion of the training did not include the actions required for a fire in the ESAS room (see Section 3.2.2). This training was given during plant walkdowns; and, when procedure EP 1202-37 is revised to include actions required for an ESAS room fire, the licer see will instruct the operators formally on this issu The inspe:: tor will verify ESAS room fire training in a future inspection repor Overall, the licensee's Appendix R operator training program appears adequate to ensure that the operators are knowledgeable enough to safely shut down the plant following an Appendix R fir .13 Fire Protection Summary The licensee management has recognized, even before the current out-age, that the fire protection system upgrades would be a critical path for Cycle 6 startup. Planning started sufficiently earlier but ;
poor technical support (untimely engineering work / incomplete or . inadequate initial reviews) appears to be a contributing factor on
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:- .last minute exemption 7 requests that were not yet submitted to NRC
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' staff at the close of the inspection period. However, a substantial amount of work was completed to assure compliance with 10 CFR 50 Appendix Licensee provided training for operators in this area appears to be well thought out and substantia . Emergency Diesel Generator Maintenance, Modification, Test Control 4.1 Background The NRC Inspection Report No. 50-289/87-02 discussed the maintenance problems that the licensee experienced with the yearly overhaul of the EDG "A." The licensee was in the process of evaluating the fail-ure of the cylinder liners for EDG "1A" with the assistance of the vendor, Fairbanks-Morse. The EDG's at TMI-1 are Fairbanks-Morse Model 3800-TD 81/8 with a 3000 kw 100% load 2000 hour rating. This inspection details the results of the licensee / vendor interface and clarifies the resolution of the problems experienced during the over-haul of the EDG "1A". Also, this inspection followed up on testing problems identified during the post-overhaul testing of EDG "18."
4.2 EDG "A" Post-Maintenance Damage ] The licensee had requested the vendor to provide additional guidance, in the form of revised Service 'Information Letters (SIL's), to con-firm proper engine adjustments and to provide a failure analysis of components that were found in a worn or degraded condition dunt,g initial inspection or had failed during initial post-maintenance 4 testin One problem dealt with the adjustment and modifications made to the EDG based on vendor guidance through various SIL's. Upon initial vendor guidance, the licensee installed an additional oil drain ring i on the lower piston to reduce oil consumption. This drain ring was i removed after the engine damage occurred, also at the recommendation ' of the vendor. The licensee requested the vendor to formally docu- ) i ment the proper ring configuration in a SIL. The vendor stated that i i this second oil drain ring was standard on diesel engines of this type; but, for this application, one oil drain ring was sufficient.
' Also, the engine timing was reset, based on vendor guidance, to 43 degrees advanced from the previous 38 degrees. Subsequently, the vendor recommended that a 40-degree setting be used for initial l l "run-in" testing and then returned to 43 degrees for normal full load ) operation. This adjustment (to 40 degrees) was made to reduce cylin- ! der temperatures during low load conditions, which were experienced when the diesel was run at gradually increasing loads after overhual to eliminate excessive wear during run-in.
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The vendor recommended a new, more gradual "run-in" sequence after the initial engine damage occurred. The licensee requested that the vendor document this new sequence by a formal change to the appli-cable SIL. The vendor indicated to the licensee that he will m'ake this change. This change will require a lower "run-in" sequence at low loads and smaller load increase Further, the licensee used flow control orifices in the cooling water system to obtain a 16-20 degree F delta temperature across the engine. The vendor notified the licensee that this was incorrect and that 10 degrees was the maximum delta T to be used and that flow control orifices should be used to obtain this delta-T regardless of the condition of the cylinder liners (e.g. , used or new).
The licensee also requested the vendor evaluate the other component wear and failures that were evident upon initial inspection of the diesel engine, such as cracked timing chain rollers, vertical drive thrust bearing wear, an upper main and rod bearing that were wiped, and distress on several upper piston pin bushing The vendor's reply stated that these problems had no common cause and that these types of failures can be expected for the conditions experienced , resulting in engine damage. The vendor also recommended that yearly or on refueling outage basis, inspections be conducted to identi fy ' any significant wearing or degradation of components before a serious failure occur The inspector concluded that the licensee and vendor evaluation of the problems associated with the EDG "1A" inspection and overhaul were made in a timely and proper manne This was further evidenced by the successful performance test for the EDG "1A" after its over-haul. The inspector had no other comments in this are .3 Post-Overhaul Testing of EDG "18" The licensee completed the annual inspection and overhaul of the EDG ;
"1B" in accordance with Surveillance Procedure (SP) 1301-8.1,
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Revision 29, during the week of February 8-14, 198 Problems asso-ciated with the EDG "1A" overhaul and licensee resolution of these problems with the vendor were addressed above and implemented for the
"1B" overhaul . The overhaul consisted of the replacement of the ,
cylinder liners but included the modifications, setpoint adjustments,
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and "run-in" test sequence that were accomplished for the EDG "1A" following its inspection / overhaul . Preparation for and testing of the EDG commenced on February 16, 198 I J l l
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.In addition to the normal diesel engine and generator maintenance performed during this outage, EDG control circuit modifications were made to allow operation of the EDG "1B" from the "1E" 4160-volt bus control panel at the 338-foot level of the control' building (remote shutdown system). These modifications were made as part of the overall plant upgrade for fire protection in accordance with 10 <
CFR 50 Appendix R. The licensee tested the diesel and the electrical modifications in accordance with STP 1-87-0010 and TP 422/ Several problems were experienced during the test and "run-in" evolution On initial start, the' EDG voltage indication was not responding.
" During licensee troubleshooting, it was realized that the EDG exciter trip circuit had tripped, then cleared. No operator or startup and test (SUT) engineer evaluation was apparently mad The diesel was restarted; but, again, no voltage indication was presen The fre-
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quency meter was also observed to be inoperable. Subsequently, the EDG exciter was observed to trip about one minute after engine star This was reset but tripped again approximately fifteen seconds late The engine was again shutdown for troubleshooting.
, Incomplete wiring was observed for the potential transformer circuit i used for generator monitoring. The wiring was repaired and the engine started again. This time the startup and test (SU&T) engineer observed EDG volts to peg high upscale (more than 4550 volts) on his
; temporary voltage monitoring equipment that was connected specif-ically for this tes The EDG was secured again and it was surmised that the EDG voltage-indicating circuit had been wired backwards. This was repaired and
, the diesel started again, except the megawatt (MW) meter was erratic when-the diesel was being loaded to 0.9 MW. Shortly, thereafter, the diesel tripped on reverse power. Subsequent troubleshooting revealed . that the manual voltage control circuit was mis-wire This was ,
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corrected and the diesel was restarted but the frequency meter failed to respond. The EDG was manually shutdown. An anti-static spray was I used to restore frequency meter indication and the diesel was re- ! ' starte After the sixth start, with the generator loaded, the generator breaker tripped again on reverse powe The EDG was started again but an alternate MW meter at the 4160-volt vital bus control cabinet was used for load purposes and the testing success-
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fully completed.
i The licensee critiqued the above sequence of events to determine the cause of the wiring problems and evaluate the consequences of the EDG test / troubleshooting sequenc The inspector reviewed the related internal plant incident report (PIR) on this matte It appeared
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l that the construction drawings were confusing, which resulted in the incomplete and inaccurate wiring. Also, SU&T did not completely j check out modifications prior to turnover to operations for testin !
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3 Maintenance construction and facilities (MC&F) division did not
' properly document the completion of specific wiring tasks by high-lighting the drawings to show completion. This is normally done in the course of completing wiring jobs. Also, the relay tes't depart-ment (Lebanon Relay) tested the overexcitation and reverse . power relays but were not aware of modifications that affected these circuit The PIR recommended that MC&F and the SU&T organizations strengthen .
their programs for ensuring that wiring modifications were completed and verified accordingly. The SU&T organization needed to specify proper testing and ensure that it is completed prior to system operation ' Most significantly, the PIR noted' that the shift personnel were non-conservative in their failure to recognize the severity of the wiring
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problems while continuing to operate the EDG with uncertain indica-
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tion and, apparently, unreliable control systems existing. The PIR states: "It is unacceptable to start components this number of times for troubleshooting." Consequently, all shift crews were to be ' briefed on this event with a confirmation that each shift supervisor specifically review this inciden The inspectors noted that more ef fort in the front end processes, i .e. design, design review, and accurate drawings, could have pre-cluded these problems. The inspector shared licensee management con-cern on the repeated attempts to restart the EDG. The inspector con-cluded that the licensee .self-evaluation of this problem was suffic-tent to identify the cause and that corrective action being taken 4 appeared to be adequat Licensee management also acknowledged that this problem, as well as the wiring design / drawing problems discussed in Sections 2.2.2 and 5.7, is not acceptable; but they also pointed out that the problems were self-identifie Licensee management
stated that their testing program, which will be accomplished through
the performance of preoperational and surveillance testing along with j operational system and component checkouts prior to criticality, will i be sufficient to capture any future wiring problems prior to plant operatio The inspector expressed concern that the events did occur. This area < is unresolved pending NRC:RI review of licensee action concerning strengthening of the MC&F and SU&T interface for the completion and testing of electrical circuit modifications (289/87-05-01).
< The NRC staff will closely monitor licensee preoperational and sur-veillance testing prior to plant startup to ensure that any future ' problems of this nature are properly identified and correcte l l
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i ! :. 4.4 Diesel Generator Activity Summary ' The technical problems associated with the EDG "1A" overhaul were l effectively resolved and lessons learned were factored int'o the EDG
"1B" overhaul . Licensee representatives remained in close communi-cations with vendor representatives to resolve the problem, but poor communication and unclear work instructions between the licensee and vendor seem to be contributing factors to the EDG "1A" damag The design and/or installation errors identified during testing of the EDG "1B" and other _ test problems appear to be centered around fire protection upgrade modification Construction and/or test personnel failed to recognize that the EDG was not ready for testin Further, operator and test engineer actions were poor (not timely and not conservative) in response to the continuing symptoms of the fundamental wiring error problem Underlying causes remain to be determined by the license NRC staff will further review this area for insight into the imple-mentation of the licensee's modification control program. Licensee corrective actions appear to be appropriate but continued care is needed to assure that testing is not relied upon as the last resort for identifying design and/or installation technical problems. Both EDG's are operable to support Cycle 6 startup.
! 5. Licensee Action on Previous Inspection Findings 5.1 (Closed) Inspector Follow Item (289/86-13-03): Licensee to evaluate noble gas build-up in the auxiliary building due to suspected leaks in the waste gas vent heade The licensee conducted a helium test of the waste gas vent header during this outage per Surveillance Procedure 1303-11.29. The re-suits of that testing were inconclusive and it appears that the vent header was not the source of the problem. Several components were repaired as a result of the testing and the licensee' concludes that these repairs, along with the various repairs made to other systems, should eliminate any other noble gas leakage. Also, this item also was opened to identify the fact that the underlying problem with noble gas release to the auxiliary building, which will occur due to leaks from some systems regardless of how many repairs are made, should be properly ventilated through a monitored release point if the ventilation system was functioning properly. This is the subject , of another inspector follow item (289/84-16-01) addressed in Section l 5.2. The licensee effort's to detect leakage in the vent header was i concluded by the inspector to be satisfactory and this item is close I l l I I ! l !
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5.2 (0 pen) Inspector Follow Item (289/84-16-01): Licensee comolete flow balancing and air distribution test for the auxiliary building / fuel handling building ventilation syste . The licensee has attempted over the past eighteen, months of operation to adjust the ventilation from various areas of';he auxiliary build-ing to ensure that radioactive gaseous releases from certain areas do not spread throughout un-monitored areas but are collected and exhausted through the normal filtered or designated release pathways,
'The licensee has not yet been fully successful in achieving the desired goal. Events, as documented in Inspection Report No. 50-289/
86-13 (addressed above) continued to occur during the last operations cycle. The licensee is presently making arrangements with a private contractor to develop a flow balancing procedure and conduct the required testing and adjustments of the auxiliary building ventila-tion system in order to prevent radioactive gaseous releases through-out the auxiliary buildin This is tentatively planned to be accomplished during May and June of 198 .3 (Closed) Inspector Follow Item (289/86-13-01): "C" Reactor Coolant Pump Seal Leakage This item concerned the cause determination, removal and inspection, and replacement during the 6R outage of the excessive No. I seal leakoff of "C" reactor coolant pump (RCP). During the current out-age, the seal packages of the "A," "C," and "0" RCP's were removed and inspected and the results are documents in Inspection Report N /86-22 and this report. The licensee is completing and docu- ' menting their review and evaluation of the indications found and this
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item is now part of unresolved item 289/86-22-0 Based on the , above, this item is closed.
. . 5.4 (Closed) Unresolved Item (289/86-09-05): Inclusion of MU-V-10 in the Inservice Testing Program During review of boric acid make-up operability, the inspector noted that valve MU-V-10 was not included in the licensee's proposed per-todic inservice testing (IST) program. The MU-V-10 is the isolation valve for the alternate discharge flow path for normal boration of the reactor. If the norra.i flow path (fiu-V-51) is not available, the licensee would be required to depend on MU-V-10 to supply borated water to the reactor coolant system (RCS) to obtain a one percent sub-critical shutdown margin. The MU-V-51 and two valves upstream of MU-V-10 are part of the IST program to ensure valve operabilit The inspector reviewed the IST program as submitted by letter (5211-86-2201), dated December 24, 1986, and noted that MU-V-10 has been included for quarterly full stroke testing to assure valve opera-bility. Based on the above, this item is close *
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5.5 (Closed) Unresolved Item (289/86-01-01): Repair of Leaking Decay Heat Check Valves (DH-V-14A/B) , When placing the decay heat removal (DHR) system into operation dur-ing January 1986, a relief valve (DH-V-578) lifted due to leakage past check valve DH-V-14B. The lifting of the relief valve spilled water on the auxiliary building floor. The licensee provided appro-priate procedure cautions to prevent challenging the decay heat sys-tem- reli.ef valves when placing the DHR system into operation until the check valves (DH-V-14A/B) could be inspected and repaired. The DH-V-14A/B are downstream of the decay heat pump suction valves (DH-V-5A/B) from the borated water storage tank (BWST).
During the current outage, both DH-V-14A and B valves have been dis-assembled, repaired with a modified seat ring, inspected, reassem-bled, and hydrostatically tested. The inspector reviewed all or part ' of the following documents for completeness and accuracy: Job Ticket (JT) No. CC-494 for inspection and repair of DH-V-14A;
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JT No. CJ-303 for inspection and repair of DH-V-14B;
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GPUN letter 3310-83-202, dated July 28, 1983;
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JT No. CL-683 for the repair of a valve bonnet leak on DH-V-14A;
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Surveillance Procedure (SP) 1300-5C, Revision 1, dated January 23, 1987, "DH Hydrortatic Test for IST."
Both DH-V-14 A and B han had a history of leakage. Both valves are Walworth 14-inch, 300 psig, Model Ho, 5344WE swing check valves. . The vendor recommended that the stainless steel (31655) seat rings be re-l placed by a modified " soft-seat" stainless steel seat ring containing two 0-rings; one 0-ring for the disk seating surface and the other ring for the seal ring to valve body threaded surfac After 6he modified seat ring replacement, the initial hydrostatic test for DH-V-14B failed due to excess seat leakage. On inspection, , the licensee discovered that the check valve disk arm bushing had ! excessive wear, allowing the arm to move in the lateral direction and prevent proper valve seating. After replacement of the bushing, DH-V-148 passed the hydrostatic test. During the DH-V-14A hydro-static test, a bonnet gasket leak was observed. After repair of the leak, DH-V-14A passed its hydrostatic test. Based on the modifica-tions made and satisfactory hydrostatic test results, the ability of these valves to prevent decay heat system leakage has been improved and this item is close .
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5.6 (0 pen) Unresolved Item (289/86-22-02) Reactor Coolant Pump Seal Inspection and Replacement
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During the current. outage, the licensee has removed, inspected and/or repaired the seal packages for the "A," "C " and "D" RCP's. The "B" RCP seal package was inspected during 1983 and no problems were found. The review of the "A" and "C" RCP seal package removal, inspection, and new seal package installation were reviewed in Inspection Report No. 50-289/86-2 . In this inspection, the inspector reviewed the maintenance conducted on the "D" RCP seals. The following documents were reviewed:
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JT CK-317 for "D" RCP maintenance;
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Maintenance Procedure (MP) 1401-1.1, Revision 13, dated November 17, 1986, " Reactor Coolant Pump Seal Inspection and Repair;"
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MP 1401-1.4, Revision-4, dated August 16, 1985, " Reactor Coolant Pumps and Motor Alignment;"
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Electrical Corrective Maintenance Procedure 1420-RCP-6, Revision 0, dated April 2,1985, " Removal and Adjustment of RCP Bentley Nevada Probes;" and, !
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l Change Modification Request (CMR) CM No. 0723M for upgrade of
RCP No. 2 seal per Westinghouse Technical Bulletin NSID-TB-85- These documents were reviewed.for:
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completeness and required administrative approvals;
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verification that QA hold points were identified and completed or in the process of being completed;
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verification that qualified replacement parts and tools were recorded and identiffed;
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verification that data sheets were properly completed; {
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verification that acceptance criteria was defined and verified; and,
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verification that records were assembled, stored, and retriev-able as part of the maintenance histor . G
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; 21 The following items were found during the "
D" RCP seal package ; , inspection and replacement.
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The No. I seal runner and No. I seal ring faces were found covered with a red, rusty materia The aluminum oxide faces were cleaned, inspected, and reinstalle f j -- The No. I seal insert showed no signs of erosion and was rein-i
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-- -The No. 2 seal runner and seal ring aluminum oxide surfaces showed signs of uneven wear; both were replace ! --
The No. 3 seal runner and seal ring aluminum oxide surfaces had
indications of uneven wear; both were replace ' -- No indication of- electrophoresis was observed on the seal sur-faces of the "D" RC In accordance with Westinghouse Instructions (Technical Bulletin
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NSID-TB-85-5), the licensee has replaced the No. 2 seal upper housing metal insert piece with a two piece assembly for the "A," C," and "D" RCP's. This field modification was performed to alleviate a poten-tial problem concerning intermittent " hang up" of the No. 2 seal due to excessive friction between the 0-ring and the retainer (housing) i balance diameter, which could cause fluctuations in No. I seal leak-off. A two piece No. 2 seal upper housing metal insert should pre- ' vent 0-ring " hang up" from effecting No. I seal leakoff.
' The inspection of the "D" RCP' No. 2 seal did not indicate the exten- ' sive wear to the No. 2 seal ring graphitar nose that was observed on ! the "A" and "C" seal rings (both noses appeared to have been worn away). The graphitar nose is designed to wear away. as an -indication of No. 2 seal degradation. When the nose height is less than .065 3 - inches, the No. 2 seal ring must be replaced. Even though both "A" and "C" RCP No. 2 seals showed signs of wear, it appears that they ' would have been able to withstand full system pressure.
I The licensee is in-the process of documenting their review and evalu-
! ation of the indications found on all- three RCP seal packages. The l NRC Ir.spection Report No. 50-289/86-22 erroneously reported that the seals would be sent off site for evaluation by the vendor. A licen-see representative, clarified that this evaluation will be conducted by the licensee in consultation with the vendo ,
This item remains unresolved pending inspector review of this docu-mentation in a future - inspection repor The inspector concluded that licensee corrective actions to date to correct the RCP seal j leakage problems are adequate for startu !
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5.7 (Closed) Unresolved Item (289/86-22-01): Licensee Evaluate Loss of 1E 4 kv Bus On January 9,1987, the plant experienced the loss of the'"1E" 4 KV vital electrical bu This was due to electricians doing work for Appendix R modifications in the IE 4 KV switchgea The electrician lifted a lead to the neutral overcurrent relay, 51BN/IE, causing an overcurrent relay actuation that tripped the feed breaker to the bu The cause was incorrect work instructions that allowed lifting of the lead while energized. The work was stopped and the bus re energize Instructions were provided to accomplish the work with the bus in an energized condition. It appeared to the inspector that this problem was similar to the events documented in this report concerning the EDG "1B" testing (incorrect or incomplete wiring diagrams for Appendix R work). Therefore, corrective action will be tracked under 289/87-05-01 a'nd this item is closed. The inspector concluded that i licensee's short-term review and corrective actions for this event were adequate and complete, i j 5.8 Past Inspection Findings Summary i j In summary, the licensee's response to issues and unresolved items 7 during this inspection period appeared to ba timely and generally adequate for the circumstances addresse . Exit Interview The inspectors discussed the inspection scope and findings with the licensee management at a final exit interview conducted March 6, 198 Senior licensee personnel attending the final exit meeting included the following: I J. Colitz, Plant Engineering Director, TMI-1 D. DeSantis, Public Affairs, GPUN H. Hukill, Director, TMI-1 S. Otto, TMI-1 Licensing D. Shovlin, Manager, Plant Maintenance R. Toole, Operations and Maintenance Director, TMI-1 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 contained proprietary or safeguards information.
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At the exit meeting, the NRC staff acknowledged the receipt of the licen- - - see's letter, dated February 3,1987, which responded to the Notice of Violation in Inspection Report No. 50-289/86-19. The corrective actions taken and which will be taken to correct the violation are acceptabl The violation dealt with the licensee's failure to address doses to
" individuals inside the site boundary" in the semi-annual release repor l The staff suggested that the licensee clarify the technical specifications (TS) terminology (TS 6.9.5.2) since the licensee now associates the standard- TS definition of " members of the public" with the current TS terminology on " individuals" Piide the site boundar Unresolved Items are matters about which more information is required in order to ascertain whether they are acceptable, violations, or deviation Unresolved items discussed during the exit meeting are addressed ~ in paragraphs 4.3 and 5.4, 5.5, 5.6, and Inspector Follow Items are significant open issues warranting followup by the inspector at a later time to determine if it is acceptable, unre-solved, a violation, or a deviation. Inspector follow items discussed during the exit meeting are addressed in paragraph 5.1, 5.2, and 5 ~. Prior to issuance of this report, the inspector read a portion of Section 5.6 to the Plant Engineering Director (PED). The - sole purpose was to assure that the NRC staff had the proper understanding of planned licensee 7 actions with respect to the RCP seal damage evaluation, in view of their plans having been erroneously reported in NRC Inspection Report N /86-2 Based on the conversation with the PED on March 21, 1987, the PED verified that NRC understanding is now accurate regarding the licensee's planned actions with . respect to the RCP seals. No other portion of the report was read or shown to the license I f
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