IR 05000289/1987011: Difference between revisions

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{{Adams
{{Adams
| number = ML20237H879
| number = ML20247P275
| issue date = 08/10/1987
| issue date = 05/25/1989
| title = Insp Rept 50-289/87-11 on 870529-0709.No Violations & Five Unresolved Items Noted.Major Areas Inspected:Power Operations & Transition Into & Out of Letdown Cooler Replacement Outage,Focusing on Operator Performance
| title = Errata to Insp Rept 50-289/87-11,correcting Unresolved Item Number on Page 18
| author name = Baunack W, Conte R, Johnson D
| author name =  
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
| addressee name =  
| addressee name =  
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| license number =  
| license number =  
| contact person =  
| contact person =  
| document report number = 50-289-87-11, NUDOCS 8708170394
| document report number = 50-289-87-11, NUDOCS 8906060144
| package number = ML20237H859
| package number = ML20247H557
| document type = INSPECTION REPORT, NRC-GENERATED, INSPECTION REPORT, UTILITY, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
| document type = INSPECTION REPORT, NRC-GENERATED, INSPECTION REPORT, UTILITY, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
| page count = 33
| page count = 1
}}
}}


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=Text=
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U. S. NUCLEAR REGULATORY COMMISSION k
 
==REGION I==
l -Docket / Report No. 50-289/87-11  License: DRP-50
. Licensee: GPU Nuclear Corporation    ,
P. O. Box 480 Middletown, Pennsylvania 17057    ..
Facility: Three Mile. Island Nuclear Station, Unit 1 Location: Middletown, Pennsylvania Dates: May 29 - July 9, 1987 Inspectors: D. Coe, License Examiner, Region I (RI)
R. Conte, Senior Resident Inspector (TMI-1)
D. Johnson, Resident Inspector (TMI-1)
S. Peleschak, Reactor Engineer, RI Reporting jj j Inspector: Mft .MV    g,7
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D.~ Johns n, Re ident Inspector Reviewed by  v>v- -
1/7/J7 R. Conte // enior Resident Inspector    Date Approvedbh: ), u (L4ws-    /8/O W. Baunack,- Acting Chief    Da'te Reactor Section No. 1A
 
Division of Reactor Projects Inspection Summary:
The NRC resident staff conducted safety inspections (210 hours) of power operations and the transition into and out of the letdown cooler replace-ment outage, focusing on operator performance, including-event respons The following events were reviewed: letdown pre-filter noble gas release; reactor trip of June 12, 1987; and, reactor protection system (RPS) actuation during reactor startup. Items reviewed in the plant operations area were: reactor coolant system leak rate, reactor shutdown for letdown heat exchanger replacement, letdown heat exchanger problems, and plant shutdown and startup. With respect to system operability, the following items were reviewed: nuclear service river pump 1A overhaul and spurious actuations of the control building chlorine detection system. Licensee action on past inspection findings was also reviewe A review of the implementation of the fire protection program was also conducte PDR 0 ADOCK 05000289
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la Inspection Results:
No violations were identified; five. items reviewed in the course of the inspection remain unresolved. One item concerned problems associated with the high chloride levels in the reactor coolant system (RCS) identified during the outage. This will require NRC staff review of licensee's evaluation of addi-tional chemistry samples. The second item concerns the review and approval of Technical Specifications Change Request (TSCR) No.172 for the reorganization of the licensee corporate organization. The third item concerns the repeated spurious actuations of the new chlorine detection system which actuates pro-tective actions for the control building ventilation system. A licensee-identified violation discussed during review of the fire hazards analysis will require additional lice.isee action to get the appropriate Fire Hazards Analysis Report (FHAR) exemption The last item concerns the operability of NI-9, a source range detector for the remote shutdown pane Corrective actions to repair this detector and establish requirements for its operability are yet to be determine The transitions into and out of the letdown cooler replacement outage went relatively smoothly with no major equipment problems. Operator performance problems appear to be isolated cases and are being dealt with by licensee managemen !
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_ TABLE OF CONTENTS Page 1. Introduction and Overview. . . . . . . ........... 2 2. Plant Operations . . . . . . . . . . . . . . . . . . . . . . 2 3. Maintenance / Surveillance - Operability Review. . . . . . . 10 4. Event Review . . . . . . . . . . . . . . . . . . . . . . . 13 5. Fire Protection Annual Review. ..............19 6. Licensee Action on Previous Inspection Findings. . . . . . 24 7. Exit' Interview . . . . . . . . . . . . . . . . . .. . . . . 27 8. Attachment 1 - Activities Reviewed
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DETAILS 1.0 Introduction and Overview 1.1 NRC Staff Activities The overall purpose of this inspection was to assess licensee activities during the power operations and cold shutdown modes as they related to reactor safety and radiation protection. Within each area, the inspectors documented the specific purpose of the area ~under review, acceptance criteria and scope of inspections, along with appropriate findings / con-clusions. 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 calculation and selective review of listed applicable docu-ment On June 19, 1987, a resident inspector also participated in a licensee meeting with NRC: Region I staff to discuss licensee's tentative plans to shift to a site emergency plan instead of one for each uni The licensee explained that plant conditions at TMI-2 do not warrant a specific pla For an event at TMI-2, the combined (site) plan would be oriented toward technical problems being resolved by TMI-2 personnel, while TMI-1 would be responsible for overall emergency plan implementation such as off-site notification or recall of plant personnel. A separate meeting summary will be documented by NRC staf .2 Licensee Activities During this period, the licensee operated the plant at full power, except for a two-week shutdown to replace the letdown heat exchangers. The reactor was shut down on Friday, June 11, 1987; and, during the shutdown at approximately 11 percent power, the reactor tripped due to reactor coolant system (RCS) high pressure (see section 4). The plant was restarted on Friday, June 26, 1987, and ended the period at full powe The problem with Once-Through Steam Generator (OTSG) tube fouling was not as evident as prior to the shutdow OTSG 1evels wer- somewhat lower after startup, especially in the "B" 0TSG. Details concerning the letdown heat exchanger leaks are discussed in paragraph 2. .0 Plant Operations 2.1 Criteria / Scope of Review The 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:
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review of selected plant parameters for abnormal trends;  '
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plant status from a maintenance / modification viewpoint, includ-ing plant housekeeping and fire protection measures;
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control of ongoing and special evolutions, including control      i room personnel awareness of these evolutions;
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control of documents, including logkeeping practices;
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implementation of radiological controls; and,
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implementation of the security plan, including access control, boundary integrity, and badging practice The inspectors focused on the specific areas listed in Attachment As a result of this review, the inspectors reviewed specific evolu-tions in more detail as noted belo .2 Findings / Conclusions 2. Letdown Heat Exchanger Leakage On June 3, 1987, the licensee was operating at full power with letdown through the "1B" letdown heat exchanger (HX) MU-C-18. The
"A" letdown heat exchanger MU-C-1A was isolated due to the identifi-cation of a leak on May 14, 1987. This leak (in the "A" HX) had been of sufficient magnitude (estimated at 0.5 gpm) to render the intermediate closed cooling (ICC) system radiation monitor RM-L-9 inoperable due to the meter reading being at full scale (10 E6 counts per minute (cpm)). On June 1,1987, the licensee again experienced a leak of similar magnitude from the "B" HX, which also produced a RM-L-9 reading of greater than 10 E6 cpm. The leak increased during the next two days to approximately 3.3 gpm. Then, on June 3, 1987, the leak rate abruptly increased to an estimated 30 gr Technical specifications prohibit operation for more than 24 hours with known (identified) RCS leakage greater than 10 gpm. The licensee shifted letdown flow back to the "A" HX and considered a plant shutdown if the "A" HX did not show a significantly lower leak rate. The "A" HX leak rate was subsequently measured at approxi-mately 0.4 gpm and remained that way until June 12, 1987, when leakage abruptly increased to 0.8 gpm. At this time, the decision was made to shut down the plant to accomplish repair During the period of time that the "B" letdown HX was in service and leaking to the ICC system, the excess level generated in the ICC system surge tank was being drained to the auxiliary building sump (at approximately 3 hour intervals) via vent valves on the ICC system cooler in the 265 foot elevation of the auxiliary buildin A vent on the surge tank located in the fuel handling building was temporarily directed to an opening in the ventilation system, which
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  . 4 exhausts through carbon.and particulate filters and is monitored by RM-A-8. The RM-A-8 gas' channel indicated a slight increase during
  .the time frame June 1-3, 1987, and it was-estimated that approximately 101 l
curies, mostly Xenon 133 and Xenon 135, were released during this two-day period. This release was coming mostly from the ICC system surge tank
. vent as'the,RCS was partially degassing through the leak into the surg tan I
  ,The in'spector_ conducted independent radiation surveys of the areas of-.the auxiliary building which contain ICC piping to confirm licensee information. These surveys showed some readings (e.g., ICC surge tank) to be garoximately 80 mrem /hr. Maximum readings were 30 mrem / hour on some. portions of the ICC system piping. This piping would normally be reading less than'1.0 mrem / hour. Licensee sam-pling of:the ICC system indicated.that total gamma activity was-approximately 0.25 micro curies per millimeter (micro-Ci/ml). The RCS activity was approximately 2.8 micro-Ci/ml during this perio The inspectors discussed these changing radiological prameters for the ICC system and the release that was occurring from the ICC system surge tank with appropriate radiological control personne Licensee radiological control personnel had evaluated these condi-tions and concluded that they did not present a significant problem as long-as leakage did not increase substantially. The noble gas .
release was'a small percentage of technical specification quarterly limits. The increase in general area radiation levels in the affected auxiliary building and fuel handling building areas was not in areas normally traversed by personnel, except'for routine auxil-iary operator-(AO) tours and surveys and, therefore, ALARA (as low as' reasonably achievable) principles were not a concern. The inspector concluded that, although this leak' rate (approximately ,
gpm during June- 1-3,1987) was not desirable, the licensee was not violating technical specifications and no substantial exposures would likely result from the release or increased radiation level Subsequent to the shifting of heat exchangers from the "B" to the
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  "A'! on June 3,1987, the total release indicated on RM-A-8 and the radiation levels and activity levels in the ICC system all showed marked decreases. Although only one heat exchanger was available, the licensee continued to operate while making contingency plans to shutdow The licensee issued Special Temporery Procedure (STP) 1-87-029,
  " Guidelines for Shutdown /Cooldown with Letdown Isolated," on June 5, 1987. This procedure provided guidance to the operators in the event that leakage from the "1A" letdown heat exchanger became unmanageable (a limit of 2 gpm was set) and both heat exchangers were required to be isolated. The inspector reviewed this procedure and discussed its implications with operations personnel. Although
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ENCLOSURE 2 ERRATA TO IR 50-289/87-11 1. Page 18, second paragraph before section 4.4, unresolved item N "50-289/85-26-05" should be "50-289/85-25-05".
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!  shutdown without letdown is not desirable, a simulation of this event was done on the plant simulator and showed that pressurizer
  'evel would not reach high level limits during a rapid controlled      !
shutdown, followed by plant cooldow The inspector concluded again I that even though this was not a desirable condition, it could be managed by licensee personne . heactor Shutdown /Cooldown for Heat Exchangers Replacement On June 12, 1987, the decision was made by licensee personnel to shut down the plant to cold shutdown conditions to replace both letdown heat exchangers, MU-C-1A/18. Leakage had increased abruptly on the morning of June 12, 1987. The licensee evaluated the situa-tion and concluded that the leak could be expected to get larger. There-fore, since shutdown without the availability of the letdown system was not advisable, plant shutdown for repair was the conservative optio The licensee employed an extra shift of personnel to assist normal plant operations staff in conducting the shutdown. This has been standard practice for major evolutions conducted at TMI-1. Plant power reduction was commenced at approximately 9:15 The inspector verified that the shutdown was being conducted in accor-dance with Operating Procedure (0P) 1102-10, Revision 39, dated March 20, 1987. A reactor building purge was ia progress at the time and the inspector verified consistent and acceptable radiation monitor reading on RM-A-2, reactor building monitor, and RM-A-9, reactor building purge exhaust stack monitor. QA monitoring person-nel were also present for the shutdown. The reactor shutdown was controlled properly with no problems until just after the turbine generator was tripped. At this time, reactor power was approximate-ly 10-12 percent and was being controlled by the turbine bypass valves. The feed pumps were being controlled in manual and the operator did not maintain the proper flow to the OTSG's. The resultant lowering of OTSG levels resulted in a high RCS pressure condition and subsequent reactor trip (see section 4).
 
Overall, the cooldown was properly controlled. Based on a sampling review, the cooloown procedure was properly followed. Operators were particularly plotting reactor coolant system (RCS) pressure (P)
and temperature (T) within the P-T curve limits and cooldown rate (temperature vs. time) was also plotted. The inspector noted that the cooldown curve used was not that specified in the licensee's
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cooldown procedure, but it was a suitable equivalen . Plant Heatup/ Reactor Startup On Ju'e 25,1987, the licensee commenced plant heatup to 525 F, after the completion of the letdown cooler replacement. The inspec-tor witnessed portions of the plant heatup over a two-shift period on June 25, 1987. Initial heat up operations with three RCP's in
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.'  6 service were conducted smoothly with few problems. The inspector verified proper licensee tracking-of RCS heatup rates as plant heatup is limited to 100 F/hr. During:the heatup, the licensee identified a high chloride (C1) concentration. in the RCS. The chloride sample indicated approximately 0.45 ppm (p' arts per million).
 
The technical specification limit for critical operation is
'0.15 ppm. ' The heatup was stopped at approximately 375 F in order to
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. clean up the RCS. Maximum letdown flow of 120 gpm was established and, 'using the installed. letdown demineralized and filtering sys-tems, chloride concentration was lowered to approximately 0.129 ppm I' by 5:00 a.m. on' June 26, 1987.. Plant heatup was recommenced and hot shutdown was reached at 9:00 Licensee representatives could not positively identify the chloride source. One plausible explanation was related to the fact that, earlier in the outage, high chloride concentration was detected in the "A" decay heat (DH) loop when the plant was in cold shutdown. Residual chlorides that remained in the system could have leached-out of RCS metal crevices during the heatup. The licensee established some data which'showed that lithium eJditions for pH control would temporarily cause the chloride concentration to increase. The source of the chloride
. intrusion.into the decay. heat system was also unknow The leaching-out process is'a plausible explanation for the chloride increases when heatup commenced and proper chemistry was being established. Final chloride concentration was reduced to less than ppm. The licensee chemistry department is still studying the problem and has sent several RCS samples off site to an independent lab for analysis. The licensee intends to report the results of the inves-tigation when completed. The inspectors will review the results of that investigation in future inspection This item is unresolved
.(289/87-11-01).
 
Just prior to heatup, the licensee conducted a special test, Special Temporary Procedure, STP 1-87-033, to adjust the intermediate closed j cooling system flow in preparation for changing to a parallel cooler '
arrangement for the letdown heat exchangers. Parallel cooler operation, in addition to modifications in the control circuitry for ,
the cooler outlet isolation valves, MU-V-2A/B, were the changes made j in an effort'to reduce the failures that were observed in the letdown coolers. MU-V-2A/B now will only close approximately 10 percent during Engineering Safeguards Actuation System (ESAS)
testing and during the testing of the interlock for radiation monitor RM-L- Previously, these valves would shut during the quarterly testing of these valves. MU-V-2A/B function as the inside containment isola-tion valves for the letdown line. The inspector reviewed the changes to OP 1104-8, Revision 27, dated January 26, 1987, "Interme-diate Cooling System," and OP 1104-2, Revision 61, dated January 6, 1987, " Makeup and Purification System," to verify that proper safety evaluations were mad _ _ - _ _ _ _ - _ _ _ _ - _ _ __
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l The inspector reviewed the modification package, Safety Evaluation (SE) No. 128965-001, to verify that proper consideration was given to technical specification and Final Safety Analysis Report (FSAR)
requirements concerning the operation of MU-V-2A/B. This modifica-tion was similar to the controls provided for other containment isolation valves such as IC-V-2 and NS-V-35. The inspector verified that the licensee was granted an exemption from the quarterly cycling requirements of Section XI of the ASME (American Society of Mechnical Engineers), B&PV (Boiler and Pressure Vessel) Code, for MU-V-2A/B. This was a previously granted exemption as a result of NRR evaluation of the licensee's submittal of their second ten year inservice testing (IST) progra The inspector also reviewed the completed test procedures TP 455-1 and 455-2 that verified propar operability of the modification. The valves will still close on a valid ESAS signal as long as the new test switches are in the normal positio The position of the switches is administrative 1y controlled by procedur Also, during the heatup, an RPS actuation occurred when in shutdown bypass conditions and the event is detailed in paragraph Overall, the licensee appears to have taken proper corrective action to correct the problem with the leak development in the letdown heat exchanger . Early Criticality At 4:35 a.m. on June 24, 1987, the licensee identified that the reactor was critical below the specified range for estimated critical rod posi-tion. The reactor was declared critical with Group 6 at 31 percent with the maximum estimated critical position (ECP) at 65 percent on Group 7 and minimum position at 54 percent on Croup 6. In accordance with facility procedures, operators immediately inserted control rods to assure the reactor was sufficiently shut down (1% delta K/K). Apparently, " excess fuel reactivity" was underestimated due to depletion of lumped burnable poison in the reactor core. Nuclear engineers processed a procedure change to the applicable reactivity curve and reevaluated the ECP. Then reactor startup continued without similar inciden With the new calculation of ECP at 58 percent withdrawn on Group 6, the minimum rod position for criticality was calculated to be 14 percent withdrawn on Group 6 and maximum was 30 percent on Group The actual critical rod position was 31 percent on Group '
The resident inspectors first learned of the problem from a log review during backshift inspections later that weeken Initial inspector review of the Temporary Change Notice (TCN) (N ) on June 28, 1987, generated additional questions. The TCN safety evaluation (on file in the control room) was very brief
 
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. 8 (handwritten with one of four lines illegible due to copying of the original TCN) and it provided little obvious technical basis for correcting the fuel excess reactivity term by 0.25 percent delta K/K. During later discussions with the licensee's nuclear engineer, it became clearer as to the basis for the above-noted change. These discussions occurred through the week of June 27, 1987, and in a conference call between NRR staff, Region I staff, and the licensee on July 6, 1987. A summary of these discussions is presented belo The licensee has been tracking the all rods out (AR0) boron concen-tration as being consistently high above target since the beginning of reactor core life for this cycle of operatio For the startup on June 27, 1987, core life was seventy effective full power days (EFPD) and the ARO boron concentration was approximately 920 ppm (parts per million) with the target at 870 pp The ARO boron concentration is a measure of the excess fuel reactivity, since the measurement is made essentially with all rods cut o' the core and with compensation for other reactivity terms such is " power doppler defect" and equilibrium xenon. Surveillance Procedure (SP)
1301-9.5, Revision 22, effective March 11, 1987, " Reactivity Anomaly,"
makes the measurement and, on a sampling basis, the inspector determined it to be technically adequate to meet TS 4.10. Similarly, the inspector determined the technical adequacy of the ECP Procedure 1103-15B, Revision 6, effective March 13, 1987, " Estimated Critical Conditions."
 
These results indicated that the core is more reactive than that reflected by the target ARO boron concentration. The target curve is provided by the Nuclear Steam Supplier (Babcock and Wilcox (B&W))
with a target band. The above-noted results were within that band (for 70 EFPD the band is 750 ppm to 970 ppm). Licensee representa-tives provided two reasons for the ARO boron concentration being off targe There appears to be a modeling problem with lumped burnable poison (LBP) burnout rate. The LBP is placed in a fuel assembly designed to " burn out" during reactor operation to provide extended core life (12 to 18 months). It has been determined at other B&W plants with extended core life that, la % in core life, the ARO boron concentra-tion approaches the target s ave, thus the reason for not adding a correction factor to all tFe appropriate reactivity curve The  j other reason provided by the licensee representatives is the buildup  ;
of Plutonium (Pu-239), which adds fuel reactivity of approximately    l
.26 percent delta K/K, which is not factored into the reactivity    !
curves for this cycle of operation. The licensee representatives    i pointed out that incorporating this factor into the ECP would have    I resulted in achieving criticality in the calculated target ban The inspector noted that a brief explanation of this phenomenon was    l provided on a one page SE written by the lead nuclear engineer and    J attached to a copy of the ECP calculation. The forms provided by l the licensee's technical and safety review process procedure were
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. 9 not.directly used in this instance, but the SE appeared to be technically sound. The inspector expressed concern that the infor-mation was not consolidated into clear and concise presentation, using appropriate administrative control forms, as justification to proceed with startup. The licensee acknowledged this commen During the confe*ence call of July 6,1987, the licensee committed to sending a letter to NRC staff within two weeks of that date explaining the above in a clear and concise manner for NRR staff review, along with appropriate corrective actions. The inspector had no additional comments on this matte . Licensee Reorganization Dn Friday, May 29, 1987, licensee representatives announced a reorgani::ation of GPU Nuclear, effective June 1,1987. Nine divi-sions under the Office of the President remain; but, five of the six corporate-based divisions changed functional responsibilitie No changes were made to the Communications Division or the site operat-ing divisions: TMI-1, Oyster Creek, and TMI- The divisions with new functional responsibilities are as described below. (1) A new Division of Planning and Nuclear Sefety is headed by Dr. Robert Long, formerly Director of Nuclear Assurance Division (NAD), a disbanded division. This new division also has the Licens-ing Department, .formerly under the Division of Technical Function (2) The Division of Administration is headed by Mr. F. Manganaro, formerly Director of the Division of Maintenance, Construction and Facilities. This division picks up, in part, the Training and Educaticn Department, formerly under NA (3) The Division of Maintenance, Construction and Facilities is headed by Mr. R. Heward, formerly Director of Radiological and Environmental Control (4)
Another new division is the Division of Quality and Radiological Controls and it is headed by Mr. M. Roche. This division picks up the Quality Control function, formerly under NA (5) The Division of Technical Functions (remains under Mr. R. Wilson), which essen-tially remains in tact, except for the removal of its licensing responsibilities as noted abov The inspector noted that the reorganization was inconsistent with that specified in Technical Specifications (TS) Section 6, Figure 6-1. L;censee representatives acknowledged that fact and indicated that this change was not substantial in that the responsibilities did not change management level positions and the operating divisions were unaffected. Apparently no 10 CFR 50.59 safety eveluation was conducted for this change prior to June 1, 1987, to assess whether or not a tech-nical specification clarification was needed on a pre-implementation basis. However, both GPUN licensing management and the GPUN President discussed these changes with NRC Region I management on May 29. The licensee committed to submitting a Technical Specification change by June 19. To clarify the technical specification, on June 19, 1987, the i
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licensee submitted Technical Specification Change Request (TSCR) No.172  ]
to make the TS Figure 6-1 more in line with the current reorganization  j
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and the question on significant safety hazard is addressed by that lette This area is unresolved pending NRC staff review and approval of-TSCR No. 172(289/87-11-02).
 
2.3 Plant Operations Summary Licensee management and the quality assurance department continued their detailed attention to and involvement in plant operation Generally, operations were carried out formally and in accordance with licensee procedures. The errors made by personnel resulting in the reactor trip on June 12, 1987, and the RPS actuation on June 23, 1987, were isolated incidents of individuals not using appropriate judgement in the conduct of their particular function at the tim Operator action to recover from these incidents was performed adequatel Activities requiring safety review could have beer, enhanced with the better use of the consolide:ed corporate policy in this are . Maintenance / Surveillance - Operability Review 3.1 General Criteria / Scope of Review The inspector reviewed activities to verify proper implementation of the applicable portions of the maintenance and surveillance pro-grams. This was a spontaneous review to capture ongoing activities in the plant spaces as they occurred. The inspector used the general criteria listed under the plant operations section of this report. Specific areas of review are listed in Attachment A more detailed review of equipment operability was also addressed belo .2 Selected Equipment Operability Review The inspector reviewed licensee maintenance (preventive and corrective)
and surveillance activities to assure nuclear service river water pump operability. Specifically, the inspector was to verify that:
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equipment was appropriately tagged out of service;
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procedures were being followed by maintenance personnel and the procedures were current;
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test equipment was calibrated;
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replacement parts were appropriately noted and certified; and, l
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  -the maintenance history for the nuclear river water system indicated no. major problem The inspector reviewed the maintenance and surveillance that was conducted on the "1A" nuclear services river water pump (NR-P-1A). The pump was observed by.the licensee' to.have brass filings emitting from the' packing-
- gland and this indicated ~ some problem with the bearings on the pump :, haft and housing. The pump motor also indicated high vibration reading ~
NR-P-1A'is a' deep shaft-type pump used to supply river water to the nuclear service closed cooling system heat exchangers. The licensee replaced the majority of pump components during this maintenance, inclu-ding the submersible bowl, impeller, shaft, shaft to support column
. bearings,- and packin The inspector reviewed the conduct of the work as it was being accompl-
'ished, discussed the -various aspects of the repair with licensee personnel, anrl< reviewed the following documentation associated with the repair and testin Job. Ticket (JT) CM-855.for NR-P-1A overhaul
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Corrective Maintenance'(CM) Procedure 1410-P-14, deep' shaft pump (RR, NR, SR, RB) yearly overhau SP 1300-3I A/B, Revision 25, completed June 13, 1987,'"NSRW Pump Functional Test and Valve Operability Test."
 
3.3 Findings / Conclusions, 3.3.1 Nuclear Service River Water pump Generally, maintenance personnel involved in the repair evolution were knowledgeable of the equipment that was being repaired.- The-inspector observed portions of the pump impeller-t bowl clearance adjustment. This involved applying a pre-load to the shaft using a
"dillon load cell" and chain fall arrangement. The amount of pre-load force that the maintenance personnel used was as specified in CM Procedure 1410-P14. The inspector observed initial pump operation and packing adjustment after the repair was complete Maintenance personnel used appropriate caution to ensure that the packing was well lubricated-and that sufficient water flow was available to prevent the packing from overheating. The evolution
.was coordinated well with operations personnel. The pump was allowed to run for several shifts to ensure proper operation prior to performance of the surveillance tes .The inspector also observed the post-overhaul inservice inspection (ISI) of the pump impeller that was replaced. Some portions of the impeller were worn substantially and portions of the shaft'also exhibited evidence of some wear. The post-overhaul ISI examination of the worn parts is a licensee initiative in addition to the normal
 
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corrective maintenance program review. This is, intended to ensure that adverse or unexpected pump degradation'due to the harsh conditions to which this pump is subjected will be appropriately identified and tracked for corrective actio Post-maintenance surveillance test results were reviewed by~the inspector and data was verified to be within acceptable tolerance The inspector concluded that this maintenance evolution was conduct-ed in accordance with appropriate maintenance and surveillance procedures. Persennel involved were knowledgeable of the work being done. The inspector had no safety concerns with this evolutio ~
3.3.2 Core Flooding System Valve Operability The inspector witnessed the performance of SP 1303-11.21, Revision 7, dated December'23,1983, " Core Flooding System sives Operability Test." Subsequently, the inspector reviewed.the i ucedure for technical adequacy to meet the requirements of TS 4.5.2.3 for check valve CF-V4A/B and isolation valve operability. This test also satisfies ASME inservice testing for these valves (partial stroke testing) as required by TS 4. On a sampling basis, the inspector verified that the operators properly implemented the procedure during the cooldown sequenc . Appropriate data was recorded and it was within test acceptance criteri Subsequent to the test, the inspector reviewed the procedure for technical adequacy. The procedure met the intent of the applicable T . Control Building Ventilation Chlorine Detector For Cycle 6 startup, the licensee installed safety grade chlorine (C1) detectors at the river water screenhouse (channels CE 776-1 and 777-1) and the air intake tunnel (channels CE 776-2 and 777-2). At 5 ppm (parts per million), they actuate to place the control building (which includes the control room) ventilation system (CRVS)
into a recirculation mode to prohibit outside C1 from entering the control room environment. Since that startup, there has been periodic actuation of the CRVS into the recirculation mode due to spurious high Cl detector respons Licensee representatives similarly noticed the problem and requested a solution from plant engineering. Cognizant plant engineers explained that the detector is sensitive to certain environmental conditions. Direct sunlight and heavy rainfall apparently promote drying and saturation conditions on the probe. Chlorine detection
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is based on a conductivity measurement based on how much chlorine is absorbed into the probe. Currently plant engineering is working on a solution under Change Modification Request (CMR) No. 0820 During the above discussion, the inspector determined that the licensee had instituted weekly preventive maintenance for these problems, 10-145, " Intake Chlorine Monitor Probe Maintenance." This is apparently ineffective in keeping up with the changing environ-mental condition The inspector did not question the operability of the syste ~
In fact, it appears to be too sensitive to changing environmental conditions. He expressed concern for the reliability of the system under such circumstances and when spurious actuations on a real chlorine leak event have occurred. He also questioned operator conditioning to the spurious actuations. This area is unresolved pending NRC: Region I review of the licensee solution for CMR N M (289/87-11-03).
 
3.4 Operability Summary Licensee maintenance management and the quality assurance department were also involved in this are In general, safety-related equip-ment was operable and kept in good working order. However, the licensee needs to resolve the problem with the Cl detection probe . Event Review Introduction and General Scope of NRC Staff Review During this inspection period, there were several events that the NRC staff reviewed in Lore detail. They were: the letdown pre-filter noble gas release of May 28, 1987; the reactor trip of June 12, 1987; and, reactor protection system actuation of June 24, 1987. 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 licensee 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;
      ,
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verification that plant and system performance are within the limits of analyses described in the Final Safety Analysis Report (FSAR); and, l
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proper notification of the NRC was made in accordance with 10 CFR 50.7 For each of these events, the inspector provided a chronological /
factual summary and a specific scope of NRC staff review, licensee findings and NRC staff findings. An overall conclusion on licensee l
, performance is also provide .2 Letdown Pre-filter Noble Gas Release At the close of the' previous inspection period, the licensee experi-enced a small release of noble gas from the auxiliary building during the changeout of a letdown pre-filter cartridge. This occurred on May 29,-1987, and was noted in Inspection Report N /87-10, but details ~ were not available at the time to allow a proper discussion in that repor Subsequent' investigation by the licensee'and the inspectors revealed that a drain valve for the filter housing was left open and this allowed water to drain to the auxiliary building sump during the
: filter changeout. Since the water was coming from the reactor coolant system (RCS),. noble gas was released to the auxiliary
  -
building and to the atmosphere via-the monitored filtered building exhaust fan RM-A-8 showed a-slight increase which was calculated to be 0.0994 curie This represents a very small fraction of the quarterly release limits for noble ga The drain valve'is operated via a reach rod through the shield wall that protects personnel from the high radiation levels present at the filter housings. Binding in the reach rod mechanism allowed the valve to remain partially'open when it was supposed to be shu This condition was corrected by licensee maintenance personnel and the valve subsequently tested satisfactorily. The licensee has
. subsequently completed several filter changeouts with no recurrent problem The inspector concluded that licensee corrective action for this problem was adequate. The inspector had no safety concerns for this item. The licensee is presently in the process of evaluating ventilation flow paths and flow rates from the auxiliary building in
'an attempt to prevent any noble gas releases from spreading through the auxiliary building when they occu _ _ _ _ - _ - _ _ _ _ - _ _ - _ _ -
 
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4.3 Reactor Trip 4. Event Chronology At 9:20 p.m. on June 12, 1987, the licensee started a normal plant shutdown for the letdown cooler replacement outage. At 9:42 p.m.,
operators experienced minor feedwater oscillations. At 9:51 p.m.,
the low steam level emergency feedwater (EFW) initiation function was defeated as permitted by technical specification for this cycle of operation when reactor power is less than 30 percent for a normal shutdown. At 9:56 p.m., operators manually tripped the main tur-bine. Between 9:51 p.m. and 9:57 p.m., while in manual operator control, main feedwater flow started large oscillations and it was eventually lost with reactor power at 10-12 percent. This resulted in RCS high pressure and a reactor trip occurred at 9:57 p.m. when only two-of-four reactor protection system (RPS) channels for RCS pressure reached 2300 psi Once-through Steam Generator (OTSG) levels reached approximately 11 inches on the "A" 0TSG and 2 inches on the "B" OTSG. The EFW pump start occurs at 10 inches, normally; but, since the initiation system was in defeat, no EFW actuation occurred. Operators restored levels in the OTSG to low level limits of 30 inches using the main feedwater syste Because of operator response to the low level in the OTSG's, the startup regulating valves were opened excessively and a large amount of feedwater was injected into the steam generators. The operato'
quickly responded to prevent an excessive cooldown rate in the RL Since the reactor was already shutdown by the trip, the licensee decided to proceed with the plant cooldown for outage preparations and they conducted a post-trip review on June 13, 198 The inspectors attended that post-trip review in addition to wit-  {
nessing the reactor trip, since they were on backshift coverage  1 during that weeken )
4. Specific Scope of NRC Staff Review for the R, ;ctor Trip  J Specific to the reactor trip event noted above, the inspector verified the below-listed items:
  --
initial proper response of the plant to the post-trip window on the pressure-temperature (P-T) plot; l
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personnel properly implemented ATOG procedures and prudently  '
acted o, unusual conditions;
 
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identification of the sequential proximate causes for the trip l
along with a reasonable determination of the root cause;
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post-trip review was conducted in accordance with Administra-tive Procedure (AP) 1063, " Reactor Review Process;" and,
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no unreviewed safety issues identified in post-trip review dat In addition to discussions with cognizant licensee personnel, the inspector:
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made an independent assessment of post-trip parameter response based on visible strip charts and indicators in the control room shortly after the events;
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attended the licensee's post-trip review;
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reviewed the complete post-trip review package ( O . 87-03);
and,
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reviewed AP 1063, " Reactor Trip Review Process" for adequac . Licensee Findings / Conclusions For the reactor trip, listed below is a summary of the licensee-identified problems / findings along with licensee resolutions:
(1) The cause of the trip was operator inattention to differential pressure indicator in the main feedwater system while operating a main feedwater pump in manual speed control. This differen-tial pressure assures enough driving head for water to be    ;
injected into the OTSG. This cause was also noted for a trip    ;
in 198 >
At the post-trip review, operations department decided to re-review operator training for the period of low power opera-tion with main feedwater in manual contro The licensee operations department also issued a memorandum to all shift supervisors stressing the need for closer cooperation among all shif t operations personnel during these types of plant transients to assist in preventing abnormal occurrence (2) One channel of source range instrumentation (NI-1) acted erratically and sometimes faile Based on past trips, the problem had been traced to a faulty cabl The outage list had replacement of new cables for both NI-1 and NI-2. This was accomplished during the letdown cooler outag _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _
 
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(3) Minimum pressure in a steam generator went below 925 psig (at 815 psis). By the licensee's post-trip administrative control, this abnormality was to be independently reviewe The post-trip group concluded that the minimum pressure-was due to overfeeding the 0TSG's because of operator response to the low. level situation. It was also concluded that operator response was good to take control of the overfeed situation and prevent an excessive cooldown. rate'on the'RC The independent review was conducted June 16, 1987, by the Plant Review Group (PRG), which concluded that no unreviewed safety question existe (4) Other minur. equipment problems were noted and they were placed on the outage work list for corrective actio '4. NU Findings / Conclusions The inspector independently confirmed the licensee findings /conclu-sions as noted above. Plant response was essentially as expected with minor problems noted. The licensee adequately identified these problems _and planned appropriate and reasonable action for immediate correction and to prevent racurrence. The AP 1063 was adequate to identify / confirm the root cause of the reactor trip and the post-trip review was. reasonably thorough to identify appropriate corrective actions before:startu Operator response to the trip and off-normal. conditions were essen-tially consistent with facility operating and emergency procedure It appeared that they were conscious of and they oriented' their
" actions toward. confirming reactor shutdown. conditions and adequate decay heat removal. Licensee action-to recover from the reactor trip'was adequate. The memorandum noted above to enhance shift awareness of the feedwater pump control at lower power level was adequate. The Plant Operations Director (POD) indicated.that sufficient  ,
training and procedure guidance existed to have precluded the even '
The inspector also reviewed the procedural guidance for this evolu-tion. The feedwater system startup procedure addresses the problem explicitly with cautionary notes, et However,'the shutdown section provides little guidance in this regar Nonetheless, the operators do train on this evolution frequently and they should know what is expected of them during such evolutions. The POD acknowl-r- edged that the feedwater pump procedure may be enhanced in the next periodic review of that procedur Cont'rol of the feed pumps in manual is a somewhat difficult evolu-tion that demands attentiveness on the part of the operator. This
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type of control problem has resulted in a previous reactor tri The inspector. concluded that this type of problem can occur based on-the variation in individual operator skill level and it is not considered a serious training deficienc The inspector pursued another apparent problem not specifically identified as such by the license The post-trip review identified that one or two OTSG safety valves lifted.' The inspector initially thought that to be unexpected since the initial plant power.just prior to the reactor trip was 10-12 percent, well within the capacity of the turbine bypass valves and the atmospheric dun'p valve On a reactor trip, the turbine bypss valves open at 1010 psig while the atmospheric dump valves start opening at'1026 psig and the first set of safety valves open at 1030-1050 psig. For this trip, the turbine bypass valves (initially open with turbine header pressure at approximately 875 psig) went closed on reactor trip with the automatic change in setpoint to 1010 psig. In response to the trip, OTSG pressure rapidly increased to the 1010 psig turbine bypass valve setting (for trip condition). The' licensee representative stated that actual valve response was apparently too slow to turn
  ~
the OTSG pressure increase and prevent overshoot into the range of safety valve'setpoint The licensee representative indicated that the licensee was re-reviewing the coordination of the valve setpoints in conjunction with the B&W Owners Group Reassessment on OTSG safety valve chal.-
1enges (previous unresolved item No. 289/85-26-05). The inspector had no additional' comments on this matte The' pre-startup RPS calibration checks showed that the two high pressure ' channels that did not trip were in proper calibratio Licensee representatives explained that the plant was almost recov-ered from the feedwater oscillation that occurred just prior to the trip. The inspector had no additional comments on the matte )
 
i 4.4 Reactor Protection System (RPS)-Actuation    i During the heatup, as pressure was being increased to 1700 psig, the operators were procedurally required to drive four safety rod groups to the bottom of the core during shifting of the reactor protection system-(RPS) out of the shutdown bypass condition. In this condition, the RPS has reduced high pressure trip setpoints of 1720 psig vice the normal 2300 psig setpoin In order to prevent a reactor trip, the rods must be inserted prior to reaching this reduced setpoint, then the shift made tg.
 
., .
. ... - . g) .RP3 "'setpoint~s. ' The' safet~ ' groups y ~can' then be re-withdrawn af ter pressure is increased above 1800 psig. The low pressure trip setpoint is  !
bypassed when the RPS is in the shutdown bypass mod '
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, ,  19 The. operators were in the process of ' driving the last group of safety rods (Group -1) to the bottom of ~ the core when pressure was allowed to: increase close to the 1720 psig setpoint. As result,.the reactor tripped on the reduced RCS high pressure trip setpoin Operators had been monitoring RCS pressure using the digital pressure indication, which is not the instrument used to generate the RPS. trip setpoints. This instrument indicated approximately-1685 psig at the time of the trip. The relatively large disparity between pressure indications was due to the uneven reactor coolant pump combination
-- one pump in one loop with two pumps in the other loop. It appears that the operators had allowed pressure to increase close to the: lower tolerance-band of the RPS pressure instrument while-monitoring another instrumen The licensee made the required NRC notifications-for RPS actuations per 10 CFR 50, Part 73, and the inspector will review the resultant Licensee Event' Report (LER) when it is submitted by the license The inspectors concluded that no particular safety concern was generated by this RPS actuation. The licensee did not conduct a post-trip review as their Administrative Procedure (AP).1038 only requires a review if the reactor trip occurred at power. It appears-that more operator attention to detail is required when conducting this evolution. No previous startups have resulted in this type of problem and the inspectors. concluded that this was' apparent 1,v an isolated inciden .5 Event Summary Overall, operator response to off-normal events were oriented toward safety and in accordance with facility' procedure Licensee management and quality assurance department provided substantial attention and involvement in the reactor trip and post-trip revie Post-event reviews were reasonably thorough wit corrective action appropriately identified, documented, and evaluat-ed for impact on plant operation Plant response was as' expected. When required, safety systems functioned appropriately. There were no challenges to the emergency core cooling system .0 Fire Protection 5.1 Fire Protection Annua'l Review The inspector conducted a review of the licensee's fire protection program to verify that proper measures have been established and are
.being maintained to prevent, detect, and control fires at the sit The. licensee's fire protection program is described in AP 1038, Revision 13, dated January 12,1987, " Fire Protectica Program."
 
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. 20 Also, the requirements for operability / surveillance of fire detec-tion and control equipment are delineated in Technical Specifica-tions (TS) Section 3.18 and 4.18. The requirements for fire protec-tion audits are contained in Section 6.5.3.1g and 6.5.3.2a/b. The inspector reviewed these procedures and requirements to verify proper licensee implementation of the fire protection progra .1.1 Audits The inspector reviewed audits completed during the period since the last annual review. The bi-annual audit of the fire protection program and implementing procedure, S-TMI-86-03, required by TS 6.5.3.lg was completed on April 24, 1986. No major problems were noted, except that the local fire company did not participate in an on-site drill during 1985, The inspector questioned the lead fire protection engineer as to the cause of the problem and if a problem existed in gaining support of the local fire company. The licensee responded that scheduling of local fire company personnel, who are all volunteers, was difficult that yea Since that time, the local company has participated in on-site drills. It was also noted that the local company personnel do use the on-site facilities for their own training and are, therefore, familiar with site practices and configurations. This was not a concern to the inspector as on-site participation has taken plac The inspector reviewed the latest annual fire protection audit 0-TMI-86-09 completed October 27, 1986, which is required by TS 6.5.3.2a. Several minor discrepancies were noted but were satisfac-torily resolved by on-site licensee personnel and documented in a memorandum to file from the lead fire protection engineer. The inspector had no other concerns on the completion of these audit .1.2 Fire protection System Walkdowns The inspector examined visible portions of the fire protection water system to verify that valves were lined up in accordance with approved system lineup procedures. Surveillance Procedure (SP)
3301-M1, Revision 28, dated April 24, 1987, " Fire System Valve Lineup Verification," was used as a guide. No discrepancies were noted, except that FS-V-399, the shutoff valve for the auxiliary building 281 foot area deluge system was noted as closed when the valve is open as the deluge station is now automatically actuate It was previously a manual station. An Exception and Deficiency (E&D) sheet was properly noted and dispositioned. A Procedure Change Request (PCR) is required to update the procedur The fire pump rooms were examined, along with selected post-Indicator valves, hydrants, deluge stations, and sprinkler station No problems were note The inspector also observed proper installation of fire
 
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. 21 barrier penetration seals, fire detection systems, and alarms and fire
; doors. Fire extinguishers that were checked all had proper inspection tags that indicated monthly checks were complete The inspector questioned the lead fire protection engineer on an apparent discrepancy in the fire barrier penetration seal design. A large area containing several pipes and electrical conduits was visible in the ceiling of the 281 foot elevation of the fuel han-dling building or the " chiller room." It appeared that this area should have been sealed to separate the two levels of the fuel handling building 281 foot and 305 foot areas. The licensee re-sponded that the Fire Hazards Analysis Report (FHAR) considered these two' locations as one fire zone and that they were protected accordingly as described in the FHA The inspector reviewed the completed surveillance file for surveillance required by TS 4.18. The E&D sheets that were generated for the surveil-lances were limited in number and were resolved satisfactorily. No discrepancies in the surveillance program were note The 5spector did question the licensee maintenance personnel concerning ongoing evaluation of fire pump discharge check valves that are being considered for inclusion in some type of preventive maintenance progra This is a residual concern following the damage done to the FS-P-3 building when check valve FS-V-27 failed open (previous inspection finding 289/86-10-02).
 
The licensee personnel stated that they are currently evaluating several commercially available non-destructive examination systems that will allow check valve performance / operability determination without disassembly. A decision on the implementation of this type of system would probably be made within the next three to four month The inspector will continue to track licensee effort in this area (289/86-10-02).
 
Fire brigade training and performance was not evaluated (normally a yearly review) as extensive review of this area was accomplished during closecut of residual items from the previous fire protection program inspection (see NRC Inspection Report No. 50-289/87-06).
 
Further, a 10 CFR 50, Appendix R review was conducted by NRC staff as documented in NRC Inspection Report No. 50-289/86-23. Accordingly, these areas were not revisited, except as noted belo .2 Protection of Equipment Within the last three months, the licensee identified certain apparent failures to meet the technical requirements of 10 CFR 50 Appendix R for which an NRC staff exemption was not granted. The 10 CFR 50 Appendix R, Section III.G.2 requires, in part, that the equipment (cables, pumps, valves, etc.) necessary to achieve hot
 
.
 
shutdown conditions be protected and remain free of fire damage by several options specified in III.G.2 a through f (except as provided in III.G.3). The staf f's safety evaluation, dated March 19, 1987, for the licensee' exemption request to these. requirements, specifically exempted certain equipment (which was not adequately protected) with specific compensatory measures to achieve the same level of safety. For equipment that needed to be operated manually in less than thirty minutes, a roving fire watch was to assure timely identification and response to a fire in areas that had unprotected equipmen In particular, one group of exempted components was to assure RCP seal integrity (seal injection / cooling). Normal action for fires in CB-FA-28 and 2F) includes tripping of the RCP. An additional commitment for this function on fire in CB-FA-2B and 2F was the upgrading of the fire emergency procedure to dispatch an operator to the RSP to restore seal injection or trip the RCP's locally in the ,
turbine building. On April 24 and May 1, 1987, and in a letter dated May 7, 1987, to NRC staff, the licensee identified that unprotected cables (as defined by III.G.2) for RCP seal injec-tion / cooling were also in CB-FA-1 and that area was not under a roving patrol, nor did the fire emergency procedure for a fire in CB-FA-1 specifically address the additional commitments on operator action. The licensee pointed out that other emergency procedures would require those actions for RCP seal integrity anyway. The letter noted that the RSP provides an alternative capability for restoration of RCP seal cooling independent of CB-FA-1, including fire protection and detection capability and that the requirement of III.G 3 is met. Therefore, no exemption was require However, the letter requested that fire area CB-FA-1 be included in the NRC staff's updated safety evaluation to ensure compliance with 10 CFR 50 Appendix R. The NRC staff will review the licensee's (final) Fire Hazards Analysis Report, Revision 9, to be submitted October 31, 1987. The NRC staff will review this matter for techni-cal adequac On June 25, 1987, the licensee identified to the NRC staff that certain equipment for safe shutdown was unprotected for which no exemption was granted by NRC staff. The equipment was in area FB-FZ-1 (281 foot elevation, Fuel Handling Building) and it was cabling for a local ventilation fan AH-E-ISB, which services the nuclear services pump area in the auxiliary building (AB-FZ-7). The licensee identified that the problem was noted during re-review of a need for modification to adequately protect equipment associated with the RCP seal injection / cooling issu The NRR staff informed the licensee a letter was needed to describe I the technical solution or provide an exemption request to 10 CFR 50 Appendix !
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The licensee added the FH-FZ-1 area to the roving fire watch patro The licensee will be sending letter by July 27, 1987, to address this item. The inspector expressed concern that the technical shortcomings noted above poorly reflects on the licensee Appendix R review as a whole unless they are indeed isolated case It was noteworthy that these items were being identified by the licensee / vendor and are being reported to NRC staff. The licensee acknowledged the above and stated that their letter of July 1987 may address whether or not these problems are indeed isolated case The above items are unresolved pending completion of licensee action as noted above and subsequent NRC staff review for technical adequacy and/or appropriate enforcement action (289/87-11-04).
 
5.3 Remote Shutdown Panel Source Range Indication For the startup after the letdown cooler outage, the licensee decided that it was safe to proceed with the source range channel  -__
    (NI-9) at the remote shutdown panel (RSP) inoperable. There are no technical specifications for the system and proposed technical specification indicated that while the RSP is inoperable or any portion thereof, a written report would be made to NRC to identify the problem along with taken/ planned actio On July 8, 1987, the inspector determined that the licensee could not immediately repair NI-9 because of a faulty detector. The plant would have to be shutdown for such repair Further discussions revealed that the control building roving fire watch was instructed to pay attention to the cables for NI-1/2 (other source range channels indicated in the control room) cable on tours. The inspector questioned if that was an equivalent fire protection measur Further, the 'icensee plans to submit a letter outlining corrective actions by July 31, 1987. Tentatively, it appears that, if a shutdown in excess of 24 hours were to occur, the licensee would plan to replace the ill-9 detecto The operability of NI-9 is unresolved pending NRC staff review of the above noted letter to the NRC staff (289/87-11-05).
 
5.4 Fire Protection Summary Generally, the fire protection program at TMI-1 continues to be properly implemented. Housekeeping is acceptable and control of transient combustibles is generally not a proble The inspector reviewed several recently completed fire protection engineer weekly walkdowns of the plant spaces. These walkdowns identified some minor discrepancies but they were promptly corrected. The inspector noted sufficient evidence of the proper implementation of this program. This inspector had no other safety concerns on the fire protection progra _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _    . _ . _ _ _ _ _ _ _ _ _ _
 
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. 24 The problems being identified for Appendix R work show signs of weak technical support. Further review by the licensee and NRC staff is neede . Licensee Actions on Previous Inspection Findings 6.1 (Closed) Unresolved Item (25-00-16): NRC Temporary Instruc tion, " Seismic Interaction for Incore Nuclear Instrumentation" The NRC staff's Temporary Instruction (TI) 2500/16 was issued to provide inspection guidance concerning IE Information Notice 85-45,
  " Potential Seismic Interaction Involving the Moveable Incore Flux Mapping System at Westinghouse (W) Plants."
 
The configuration that exists at TMI-1 on Babcock and Wilcox (B&W)-
designed plants is not similar to the W-designed plants in that the incore flux detectors are permanently installed in the core at B& The inspector considered the issue of TI 2500/16 applicable to TM1-1; namely, the adequacy of non-seismic equipment over seismically-installed equipment. The seal table exists on the operating floor of the reactor building, but no equipment or machin-ery for detector movement is required. The flux detectors are removed from the core during refueling evolutions by using an overhead jib crane mounted on the wall of tLe "D-ring" adjacent to the incore seal table. During plant operati3n, this jib crane is not located over the seal table and is secured in position on the D-ring by cables and turn buckles to prevent it from falling onto the seal table during a seismic even General Maintenance Procedure (MP) 1401-18, Revision 2, " Equipment Storage in Class I buildings," was reviewed by the inspector. This procedure specifies the requirements and methods to secure this crane to prevent its movement during normal plant operations. The inspector also verified after the latest outage that the jib crane was properly secured and store The licensee was aware of the concerns in Information Notice 85-45 and had evaluated the situation as not being applicable to TMI- The reason was that TMI-1 is not a W-designed plan The inspector concluded that, based on the type of arrangement used  .
for the incore instrumentation at TMI-1, no concern of the type  '
identified in IN 85-45 exists at TMI-1. Adequate actions have been taken to prevent damage to the incore seal table so as to preclude any damage during a seismic event at TMI- The inspector had no other concerns and this temporary instruction is considered closed for TMI-1. Additional work on seismic interaction throughout the plant will occur related to Generic Letter 87-02.
 
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,    25 6.2- (Closed) Unresolved Item (289/85-24-01. Training Feedback An Atomic Safety and Licensing Board (ASLB) Partial Initial Decision
'(PID), dated May 3, 1985, required the licensee-to develop a method to provide supervisors with a means to.give feedback to training    ,
programs by licensed operators directly evaluating the effect of training on the actual job performance of trainees under their supervision (performance based training evaluation). At the time of    i
'NRC Inspection No. 50-289/85-24, a licensee-developed procedure to    ;
accomplish this objective.had not been implemented for licensed operators and the item was-left unresolve . Subsequent review of this item was reported in NRC Inspection Report No.'50-289/87-09 during which the inspector identified one remaining concern. The method by which the licensee was documenting the supervisors feedback allowed for the use of this process'by the operators themselves to voice concerns or suggest improvements in
      ~
trainin However, separate mechanisms existed for operator / trainee feedback,' which were intended to be distinct from-that for supervi-sors. The supervisors own evaluation was not directly require 'The inspector reviewed the licensee's memora'nda and the supervisor feedback forms for the evaluations which covered the one year period ending in March 1987. Licensee training staff. representatives met one-on-one with each supervisor to' explain the objective of the evaluation and to ensure the proper level of analysis and suggested improvement were taking place. Based on this and the previous review, the inspector. concluded that the licensee's procedure now adequately addresses the original concer Furthermore, the inspector noted that this feedback input is only one of several that the licensee uses for improving training. Other inputs ~ include requalification. examination results, simulator evaluations, TMI and industry operational events, operations depart-ment inputs, NRC/INP0/ internal audits. These changes are comprehen-sive, well documented, and exceed minimum regulatory requirement .3 (Closed) Inspector Follow Item (289/86-03-15): Licensee Review / Modify Maintenance Procedure for Limitorque Motor-Operated Valves Two maintenance procedures, Corrective Maintenance Procedure    l
        '
1420-LTQ-2, Revision 8, and Preventive Maintenance Procedure E-131, Revision 12, for Limitorque motor-operated valves were identified as    l having various weaknesses concerning adjustments to the limit    '
switches 'or in specifying valve operation. The inspector reviewed current revisions to the subject procedures, Revision 10 to 1420-LTQ-2 and revision 13 to E-13 and he verified that the previous concerns had been addresse . - _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _
 
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Procedure 1420-LTQ-2 now specifies that a more precise valve open position (6 percent of total handwheel turn) be maintained when setting the open limit switc Previous guidance was that the valve be open "a slight amount." This change was considered satisfactory by the inspector to correct any doubt as to what valve position is required to set the open limit switc The second concern was that the torque bypass switch could have been set such that unseating forces would not be overcome before torque switch trip at the previously specified 3-10 percent open positio The procedure now specifies that 10 percent (+4 - 2) of valve stroke time be attained for setting the opening of the torque bypass switch. The inspector concluded that this was acceptable. Previous guidance has determined that 8-14 percent of valve travel be allowed prior to bypass switch actuatio Procedure E-13 was modified to delete reference to " jogging" the valve to verify proper motor rotation. The procedure now correctly specifies how to operate the valve to check correct motor rotatio The inspector concluded that the above-noted procedure enhancements were adequate to address the previously-noted concerns and this item is close .4 [0 pen)UnresolvedItem(289/85-25-05): Steam Generator Safety Valve Performance Additional information on this item was obtained during a post-trip review (see paragraph 4.3.4).
 
6.5 (0 pen) Unresolved Item (289/87-02-01):  NRC to Review Licensee Investigation of Drug Abuse During this inspection period, the licensee concluded another investigation of drug abuse by its employees and/or contractor personne Since May 19, 1987, the licensee has frequently briefed NRC staff on their investigation. On June 15, 1987, the licensee concluded their review and issued a press release on their investigation. The l
licensee confirmed positive drug test results have been received on ten employees. Of the ten employees, one has resigned, one was fired for failing to cooperate with the investigation, and eight have been suspended without pay. One additional employee refused to undergo testing and was discharge There are no positive test results (or test refusals) involving licensed operators or manage-ment personne _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ - - __
 
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The eight suspended employees were given the opportunity to regain their jobs after thirty days if they successfulD completed a rehabilitation program and subsequent evaluation by a GPU Nuclear psychologist. A licensee representative reported that all eight employees accepted the licensee's offer and terms which included periodic and random testing for drug misus The licensee indicated that, similar to a previous investigation, an internal investigation report would be issued. This area continues to be unresolved pending NRC staff specialist review of the licensee's internal reports on these matter .6 {0 pen)InspectorFollowItem(289/87-07-01): Individual Documentation of Operator Performance during Simulator Evaluations The licensee committed to document individual performance, as well as team performance during simulator evaluations. This area will be reviewed again by NRC staff after the licensee's next annual simala-tor examinations in March 198 .7 (0 pen) Inspector Follow Item (289/87-07-02): Senior Licensed Operators Not Evaluated During Simulator and Oral Examinations at the Senior License Level The licensee has added a statement to a proposed revision to their corporate requalification program description clearly specifying that senior reactor operators (SR0's) will be evaluated in SRO positions during simulator examinations. Two senior operators who did not' receive this type of evaluation (apparently because they normally stand reactor operator watch) during the licensee's March 1937 simulator examinations will be given additional simulator evaluations by the licensee during July 1987. This item can be closed out following notification by the licensee that the requalification program description is approved as drafted and the additional simulator examinations scheduled for July 1987 are complet .8 Past Inspection Findings Summary Overall, the licensee was responsive to address previous inspection issues / concern . Exit Interview I
The inspectors discussed the inspection scope and findings with  )
licensee management at a final exit interview conducted July 9,  4 1987. Senior licensee personnel attending the final exit meeting  l included the following:
C. Incorvati, Audits Supervisor, TMI-1 M. Ross, Director, Plant Operations, TMI-1 C. Smyth, Licensing Manager, TMI-1    ;
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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 informatio Unresolved Items are matters about which more information is re-quired in order to ascertain whether they are acceptable, viola-tions, or deviations. Unresolved items discussed during the exit-meeting are addressed in paragraphs 2.2.3, 2.2.5, 3.3.3, 5.2, 5.3, and Section Inspector Follow Items are significant open issues warranting follow-up by the inspector at a later time to determine if it i's acceptable, unresolved, a violation, or a deviation. An inspector follow item discussed during the exit meeting is addressed in paragraph 6.3 of this repor l
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NRC INSPECTION REPORT i
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NO. 50-289/87-11 ATTACHMENT'l ACTIVITIES REVIEWE0 Plant Operations
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Control room operations during regular and backshift hours, including frequent observation of activities in process'and periodic reviews of selected sections of the shift foreman's log and control room. operator's,
~1og and selected sections of'other control room daily logs
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Areas outside the control room
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Letdown' cooler shift due to high leak rate from "1B" heat exchanger on June 3, 1987-
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Unplanned reactor trip, Emergency Procedure 1210-1 on June 12,'1987
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Operating Procedure (OP) 1102-11,- Revision 68, dated March 15, 1987,
" Plant Cooldown," on June 12-13, 1987
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OP'-1102-2, Revision 80, dated May 15, 1987, " Plant Startup," includ-ing the license heatup/startup prerequisite list and related activi-ties on June 25-26,L1987      1
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OP 1104-8, Revision 27, dated January 26,.1987, "ICCS System Operation,"
(TCN 1-87-138) on June 24, 1987 During this inspection period, the inspectors conducted direct inspections during the following backshift hours:
  '6/01/87 8:00 p.m. to 10:30 /02/87 6:00 a.m. to 7:00 :00 p.m. to 5:00 /06/87- 9:00 a.m. to 10:30 /12/87- 7:00 p.m. to 10:30 /13/87 9:00 a.m. to 1:00 /24/87 5:00 p.m. to 8:00 /25/87 4:00 p.m. to 8:30 /27/87 8:00 a.m. to 10:00 /18/87 8:45 p.m. to 10:15 /09/87 5:00 a.m. to 7:00 Maintenance
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NR-P-1A Overhaul per Job Ticket (JT) CM-855
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Corrective Maintenance Procedure 1410-P-14
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Surveillance
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Surveillance Procedure (SP) 11.21, Revision 7, dated December 3, 193, " Core Flood Valve Operability Test," on June 13, 1987
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SP 1303-4.16, Revision 29, dated June 23, 1987, " Emergency Power
' System for Diesel Generator B," on June 24, 1987
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SP 1303-5.1, Revision 22, dated March 4, 1987, " Reactor Building Cooling and Isolation System Logic Channel and Component Test," week of July 6-9, 1987
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SP 1303-5.2, Revision 24, dated March 10, 1987, " Load Sequence and Component Test," week of July 6-9, 1987
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SP 1300-3I, NR-P-1A Post-Maintenance Test (records review)
Reactor Coolant System (RCS) Leak Rat The inspector selectively reviewed RCS leak rate data for the past inspection period. The inspector independently calculated certain RCS leak rate data reviewed using licensee input data and a generic NRC " BASIC" computer program
"RCSLK9" as specified in NUREG 110 Licensee (L) and NRC (N) data are tabulated belo TABLE RCS LEAK RATE DATA (All Values GpM)
DATE/ TIME  (NUREG 1107) CORRECTED DURATION Lg Ng Ng Ng L U
6/1/87 2.1863 2.19 0.12 0.22 0.2236 3:41 Hours 6/2/87 3.2235 3.23 -0.04 0.06 0.0401 10:34 Hours 6/2/87 3.5089 3.50 0.13 0.23 0.2435 8:27 Hours
 
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l DATE/ TIME  (NUREG 1107) CORRECTED DURATION Lg Ng N g Ng L U
7/8/87 0.0924' O.09 0.12 -0.02 -0.0127 11:49 Hours G = Identified gross leakage U = Unidentified leakage L = Licensee calculated N = NRC calculated Columns 2 and 3; 5 and 6 correlate 1 0.2 gpm in accordance with NUREG 1107. (N is corrected by adding 0.1044 gpm to the NUREG 1101 N due to u    u l total purge flow through the No. 3 seal from RCP's.


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Revision as of 22:23, 9 February 2021

Errata to Insp Rept 50-289/87-11,correcting Unresolved Item Number on Page 18
ML20247P275
Person / Time
Site: Three Mile Island Constellation icon.png
Issue date: 05/25/1989
From:
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20247H557 List:
References
50-289-87-11, NUDOCS 8906060144
Download: ML20247P275 (1)
v • d • e


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ENCLOSURE 2 ERRATA TO IR 50-289/87-11 1. Page 18, second paragraph before section 4.4, unresolved item N "50-289/85-26-05" should be "50-289/85-25-05".

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0FFICIAL RECORD COPY TMI-1 ERRATA SHEETS - 0004. /03/89 8906060144 890525 PDR ADOCK0500g9 ,

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