IR 05000289/1988017

Insp Rept 50-289/88-17 on 880808-19.Violations Noted.Major Areas Inspected:Licensee Preventive & Corrective Maint Activities,Design Changes & Mods,Including Reg Guide 1.97 Re Selected Plant & Environ Monitoring Instrumentation

ML20204J032
Person / Time
Site:	Three Mile Island
Issue date:	10/14/1988
From:	Blumberg N, Napuda G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20204H998	List: IR 05000289/1988017 ML20204H995 ML20204J023
References
RTR-REGGD-01.097, RTR-REGGD-1.097 50-289-88-17, NUDOCS 8810240522
Download: ML20204J032 (36)

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U.S. NUCLEAR REGULATORY' COMMISSION

REGION I

' Report N /88-17 Docket:N License N DPR-50 e Licensee: GPU Nuclear Corporation Post Office' Box 480 Middletown, Pennsylvania 17057-0191 Facility Name: Three Mile Island Nuclear Generating Station - Unit 1

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Inspection At: Middletown, Pennsylvania Inspection Dates: August 8 - 19, 1988 Inspectors: M. Dev, Reactor Engineer, OPS, 08, DRS L R. Hernan, NRR Project Manager, TMI-1 P. Drysdale, Reactor Engineer, OPS, OB, ORS A. Sidpara, Resident Inspector, iMI-1 R. W. Winters, Reactor Engineer, hPS, EB G. LAmpi , Consultant, NRC

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Team Leader: id  ! 7 G. N #uda, Lead Reactor Engineer, OPS, Dai.e /

08, DRS, Region I i

Approved by: ~! N N. Blumberg, 9hief, Operation # Programs Date Section, Operations Branch, DRS, RI

] Inspection Summary: S_p.ecial announced inspection on August 8-19, 1988 (Report No. 50-289/88-17)

Areas Inspected: Inspecti a v licensee's preventive and corrective i

' maintenance activities; desit changes and modifications, including Regulatory

Guide 1.97 related selected plant and environmental condition monitoring j instrumentation and non-nuclear instrumentation; inservice inspection; and

, plant surveillances conducted during the 7R refueling outag l l Results: Two violations were identified: (1) Inadequate procedures

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and T2] Failure to review temporary changes within the specified time required

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! by the plant Technical Specifications and the establishment of a procedure which permits this practice (see Appendix A to the letter forwarding this report and also paragraphs 2.2.8, 2.2.9, 2.3, and 4.1). Overall 7R refueling activities appeared adequate and were performed in accordance with established

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procedures by conscientious and knowledgeable personnel. Management support, Engineering Services, and QA/QC interfaces were found to have improved and were effective specifically in the areas of in-service inspection and plant i surveillances. The inspections also identified concerns relating to i inoperability of neutron flux monitor NI-12 during a criticality test (paragraph 3.1.1), and lack of planning and coordinstion of work performed by the Lebanon Relay Group (paragraph 3.3).

8810240522 801017 PDR ADOCK 050002A9 Q PDD L . . . _ _ .

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DETAILS 1.0' General r 1.1 Objectives of the Inspe_ction The objective of this inspection was to evaluate the licensee's program for controlling plant outage activitie Particular emphasis was placed on the licensee's systems for completion and closeout, including formal corrective actions, of activities to assure plant readiness for restar Inspection activities included the following functional areas which are discussed in the details of this report: [

- corrective and preventive maintenance .

- design changes and modifications  !

plant surveillances  !

- inservice inspection l

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plant restart ,

Ongoing outage activities such as post maintenanca and post modification testing, including those performed on backshifts, were

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observed to verify proper closeout of wor Support activities such  :

as procurement, QA/QC overview, engineering and housekeeping were also examined and are discussed in various paragraphs. Persons i contacted during this inspection are listed in Attachment .2 _S_ummary of Conclutions and Findings Trained and qualified licensee personnel generally comply with a well documented and administrative 1y controlled preventive maintenance i program. Examples of jobs that were well planned and implemented i were the Turbine Drain Valve repair and motor operated valve actuator  ;

testing (M0 VATS). However, contractor tradesmen who were used ,

extensively during this outage for corrective maintenance work were

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! allowed by procedure to make temporary changes in work instructions t

, without a review of the changes by higher level persons. Substantive i

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changes to procedures without prior review and approval, or without  ;

such review within 14 days of implementation of the change, was i contrary to the Technical Specifications (TS) and constituted a  !

i violation (paragraph 2.2). Failure to provide procedures that were  ;

adequate for tho intended work (paragraphs 2.2 and 4.1) constituted a  ;

separate violatio l l Design modification work by engineering personnel was found to be  !

> technically sound. The post-modification testing was done by know- L ledgeable test engineers and technicians. As-installed

configurations were in accordance with engineering documenti, i i

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One area of concern was the lengthy and complicated process of updating as-built drawings, and the use of out-of-date drawings for writing post-modification test procedures. The QA audit group had previously identified a similar concern, and the inspector found the ongoing corrective action to be adequate and timely. Overall, modification installation procedures were adequate and the work done was properly documente t Another concern was the method for scheduling work on relays by an offsite licensee group. This method circumvented the QA engineering review process that decided which tasks would be overviewed by QA/QC (Paragraph 4.3). This had also been previously identified as a

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deficiency by the QA organization and was scheduled for followup by

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QA when the corrective action became du .

The accomplishment of Inservice Inspection (ISI) was found to be J

ahead of schedule and all NDE personnel were well qualified. Also, there was evidence of ertensive QA involvement and corrective actions were adequate and timely. The erosion / corrosion inspections of piping were conducted in an acceptable fashion and the extent of

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engineering support in this area was adequate.

1 Overall, plant surveillances were being conductea in an acceptable fashion by competent technicians in accordance with adequate

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procedures. One concern was identified on a procedure that did not provide sufficient worksheets for necessary calculations. This was

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discussed with licensee representatives who took immediate action to i rectify the condition (paragraph 6.4). Other comments on i

potentiometer adjustment (paragraph 6.4), "pen and ink" changes to procedures (paragraph 6.6) and providing the Control Room with the weekly plant surveillance work schedule (paragraph 6.7) were i

discussed with licensee management.

! With the exception of the items discussed above, the licensee's

, performance during the outage in the functional areas reviewed j was acceptable and adequat .0 CorrectiveandProventiveMaintenancel627CO)

2.1 Scope of Review The status of outage maintenance work was reviewed and discussed I with the licensee's planning supervisor. All major and most minor

! tasks had been completed and only a small amount of non safety

. related work was still in progress during this inspectio The final i

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licensee review and approval sf document packages associated with completed work was ongoing by the Plant Materiel group which reviews and approves those documents upon the completion of the work. Twenty five (25) .orrective and ireventive maintenance tasks, completed i

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during the 1988 refueling outage (7R), were selected and the t

respective job document packages were reviewed for administrative controls; technical content; reporting of data and results; and, QA/QC involvement and overvie The licensee held daily morning and afternoon meetings during the outage to schedule, coordinate, and discus.) upcoming work and testing. Several of these meetings were attended by inspection team members who selected certain ongoing work to be observe Witnessing of maintenance activities in progress during this inspection is discussed in paragraph 2.2 belo t Site personnel involved in the performance of the selected  ;

maintenance work were interviewad and discussions were held with the Plant Materiel group staff with respect to the maintenance program. Also, GPUN Administrative Procedures (see Attachment A)

were reviewed to determine whether they w1re consistent with the-licensee's QA Program and FSAR commitment '

The following aspects of the maintenance program and implementation thereof were reviewed ano discussed with licensee staf Welding Control

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Measuring and Test Equipment Control

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Fire Protection

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Flood Protection

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Painting of Equipment and Piping

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Motor Operated Valve Actuator Testing (MOVATS)

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Maintenance History and Trending

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Root Cause Analysis of Equipment Problems

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Vibration Monitoring of Equipmer* '

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Sampling of Lubricating Oils 2.2 Review and Findings 2. Corrective maintenanca tasks (cms) CT 085 and CS 274, l (Attachment A) involving welding repairs to the seat and l seat rings of Main Steam Valve (MSV) 003A (a pressure L retaining boundary) were reviewed. The work package !

included approved welding procedures, weld rod  ;

traceability, drawings and welder qualification document i Also, the plant Qualified Welders List ..as readily '

accessible and contained the applicable up to date training i records and welder process useage data. The Plant Materiel ,

group welding supervisor was knowledgeable about ASME Code l requirements and had effective communications with the Site ;

Welding Engineering grou .

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2. The inspectors witnessed selected Limitorque MOVATS work conducted within the scope of cms CN 158 and CT 131 (Attachment A). They noted that the work was being per-formed by three member crews that consisted of one MOVATS company representative and two licensee plant electrician The testing was supervised by a Plant Materiel group fore-man and was closely coordinated by a plant test enginee The work packages included approved test procedures, drawings, and test data. Also noted was that (1) approved vendor manuals were readily available for review; (2) problems wer'e documented on Engineering Evaluation Requests (EER); and (3) the interdisciplinary Plant Review

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Group evaluated test data and EERs, and instituted necessary corrective action . The work scope of CM CS 292 was to pin the Main Steam

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piping hangers at the start of the outage and unpin them at the end. The work package included maintenance procedure 1410-Y-69 and data sheets, all of which were found to be cc3 ole + It was noted that the licensee found three hangers already unpinned during the work and performed a visual inspection which revealed no physical damage to either the hangers or piping. Appropriate engineering

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evaluations were being done and long term corrective action 4 was being planned. The NRC resident inspectors intend to i follow up on the actual corrective measures adopted by the license . Preventive maintenance task (PM) PA 970 involved testing a

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480 volt electrical circuit breake The work package included measuring and test equipment (M&TE) useage records, breaker inspection results and the completed

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preventive maintenance procedure (E 5). Also, it was verified that the control of calibrated M&TE was done in i accordance with administrative procedure AP 1022. All M&TE were determined to be properly co.1 trolled and calibrated.

j 2. Licensee inspection of fire fighting equipment and repairs to fire doors were conducted under PM PA 144 and CM CP 560 i

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respectively. Approximately 320 items of portable fire fighting equipment are maintained and inspected monthly by trained and qualified plant mechanics in accordance with approved procedure U 10. It was

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also verified that (1) Plant Materiel group personnel are given yearly training on fire fighting techniques and

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equipmen*.; (2) maintenance records are being kept for all

fire extinguishers and firo fighting equipment; and, (3)

i effective communications had been established between the

. Plant Materiels group and Fire Protection staff.

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2.2.6 The painting of plant piping was performed under cms CS 646, CS 742 and CS 743 in accordance with approved procedures and by qualified painters. It was also verified that quality control was provided by certified painting inspectors and effective communications were established between the site and the GPUN general offices paint specialis .2.7 Licensee inspection and repair of both non safety related auxiliary power transformers was addressed by CM CL 002 and performed by the Metropolitan Edison Company (Met Ed)

Electrical Construction and Maintenance group (EC&M) who are not under the direct supervision of plant management or the Plant Materiels group. It was noted that the work package for transformer IA included all appropriate records of work, but the IB work package lacked records of work performed on that transformer. This was brought to the attention of the Plant Materiels group foreman who obtained the appropriate records prior to the conclusion of this inspection. The retrieveability of the transformer B ,

maintenance documentation an'J the control of this documentation was considered inadeqett .2.8 The scope of cms CN 583, CP 769 and CS 028 was inspection '

of the seals on Reactor Coolant Pumps 1A, 1B IC and 10 and their replacement, as necessary. The performance of the work was assigned to the GPUN Maintenance Construction and-acilities (MC&F) group. The task was performed by con-

.eacted tradespersons and four Westinghouse technical representatives. Procedures 1401-1.4, Reactor Coolant Pump Seal Inspection and Repair, Rev 15; and 1401-1.1, General Maintenance Procedure, Rev 15 were two of several procedures used to accomplish the work. It.was noted that ,

eight steps in procedure 1401-1.1 were annotated "NA" ( '

not appropriate) with no higher level approval noted on the l four executed procedures (one procedure for each pump). A i technical evaluation of this and other applicable procedures ascertained that (1) the instructions and guidance included in five of these steps were adequate to enable the workers to determine when a work step did not need to be accomplished; and, (2) the remaining three steps were comparable to steps in Procedure 1401-1.4 where torque values and other required information had been documente The latter practice of annotating a procedure step as NA without an explanation when the omission of that step is not self evident within the given procedure and completion o.' the step is documented elsewhere is considered a weak-nes ,

However, it was identified that the incremented torquo ,

value in step 6.1.12.2 of 1401-1.4 was changed from 300 [

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foot pounds to 100 foot pounds in each of the four copies of the executed procedure by 1.ining out the 300 value and later writing in the 100 value. The changes were not dated, initialed or annotated in any fashion. Further review identified that (1) a permanent change to the procedure was submitted August 11, approximately one full month after the work had been conpleted; and, (2) procedure 1407-1, Corrective Maintenance, Rev 32 permits workers to make such changes and implement them without any prior authorization or subsequent review by a higher level person within the Technical Specifications time fram Implementing a change to a procedure without prior review and approval or approval of the implemented change within fourteen days; and establishment of an administrative procedure permitting such action is a violation of Technical _ Specifications Sections 6.8.2 and 6.0.3 require-ments(50-289/88-17-01).

2.2.9 The scope of CM CP 736 was a complete overhaul of Reactor Coolant Make-up Pump 1B, while CM CT 031 addressed repair of the newly installed inboard and outboard mechanical shaft seals. The work was performed by contracted trades-persons and the vendor technical representatives. The new mechanical seals had been obtained through Purchase Order (PG) TP-039051 from the manufacturer of the seal Certain specific instructions were included with the P0 required documentation that was forwarded to the license This vendor technical information required that the seal rings and inserts be checked for flatness prior to installation; that the perpendicularity of the installed seals to the shaft be held to certain tolerances; and, that the shaft concentricity runout be within a specified rang The seals were installed without being checked for flatness because these specific instructions were not incorporated into procedures used for the work (e.g.1410-P-7).

Water leakage past the seals was unacceptable when the pump was tested. The seals were then removed, found not to meet the flatness criteria, relapped by the licensee maintenance staff, and reinstalled. The pump then tested satisfactorily. Also, there was no objective evidence that the perpendicularity and runout measurements had been checked or a technical evalcation done on whether the measurements were necessary. A subsequent review by the inspectors of the GPUN instruction book for mechanical

, seals revealed that it did not contain the vendor technical l information (VTI) supplied by the vendor nor was there any objective evidence that a technical evaluation of this VTI had been done nor possible alternatives considere ,

This is an example of violation for failure to establish l technically adequate procedures. Another example of this i violation (50-298/88-17-02) is detailed in paragraph 4.1.

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2 '.10 Seat Leakage on Relief Valve RC-RV-1A On August 13, 1988, after the plant had been taken to hot standby conditions, seat leakage was noted on pressurizer code relief valve RC-RV-1A. The leakage was detected by an increase in differential temperature (delta T) between the valve downstream piping and reactor building ambient temperatur Normal delta T is less than 3(, In this case, it had risen to as high as 77 F and nominally varied between 20'F and 75* The inspector reviewed the history of work that had been done on the valve during the refueling outage. Wyle Laboratories Report No. 48250-0 dated June 20, 1986 documented inspections, repair, and testing performed on the valve. The valve had passed "as received" seht leakage testing on April 9, 1986 but lifted at a pressure slightly above the high end of the setpoint tolerance band. The valve was readjusted until it lifted at the proper pressure during 3 retests. The valve was then disassembled and the nozzle and disc seats were polished. The valve success-fully passed set pressure testing following reassembl The valve was then disassembled a second time and the disc and nozzle seats repo11shed. The valve was then re-assembled and a seat leakage test using gaseous nitrogen was conducted on April 16, 1986 at room temperature in lieu of a hot gaseous nitrogen seat leak test specified in the GPUN specification. During the seat leakage check, the leakage was observed to be 7-9 bubbles per .ninut Engineering declared this leakage to be "acceptable" and waived the hot gaseous test in a letter dated April 17, 1986. GPUN Mechanical Engineering also performed an engineering evaluation on the test results to assess the implications of the seat leakage on continuing with plant

! startup. The evaluation concluded that this condition did not present a safety concern, nor was 't an operational concern at the present leve This esaluation is documented in a GPU Nuclear internal nemorandum dated August 16, 1988, which also stated trat the condition of the. valve would to be monitored so tiat future

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replacement of the valve, if necessary, could be planned for an opportune time. In addition, the evaluation

! supported raising the delta T alarm etpoint from 30 F to 80'F. At the conclusion of this inspection, the delta T ( continued to vary between 20*F and 75' The NRC Resident l Inspectors will monitor future performance of this valv .3 C_onclusions Th performance of corrective and preventive maintenance activities and the maintenance program were found to be satisfactory. However, l

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the noncompliances and weaknesses discussed above were associated with work done by other than plant staff such as contract personne These other personnel were found not to be fully trained and indoctrinated in all of the maintenance administrative controls for work done during this refueling outage as exemplified in paragraphs 2.2.7.and 2.2.8. This area merits further review by licensee managemen :

3.0 Design Changes and Modifications (37701, 37702, 37828 and 72701)

3.1 Design Changes and Modifications Program Review The inspector reviewed the administrative procedures listed in Attachment A that have been established within the Technical Functions, Site Engineering, and Plant Operations groups for governing modifications and design changes to plant systems; and for cond olling their tie-in to existing systems and operation The reviewed procedures were found to be current, complete, properly approved, and consistent with stated policy objectives and regulatory requirements. Design change and modifications controls are well

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defined within the scope of the reviewed procedures. These procedures provided comprehensive and specific instructions defining design change program requirements. The organizational and individual responsibilities assigned to design changes; the methods required for

proving and approving the necessary engineering design specifications

and plans; and the methods and procedures for controlling the implementation and incorporation of design modifications into

applicable site and plant documents have been delineated by these procedures.

The inspector verified that Technical Functions administrative l procedures were properly implemented in the development of engineering work packages associated with the ICS/NNI modification described in paragraph 3.4. The inspector noted, however, that

several obvious inconsistencies and definitions exist within the i Technical Functions and Plant Administrative Procedures particularly t with respect to the definition of "test certification" and system

"Ready-for-Service." For example, Technical Functions Procedure EMP-017, "Project Ready for Service and Completion Reporting" did not agree in this case with Administratise Procedure AP-1043, "Control of Plant Modification." Test certification and system readiness for

, service were not clearly established ir this case. The inconsistent i use of "Ready-for-Service" termino 1cyy between Technical Functions I and Plant Administrative Proced' ires was discussed with the Startup

{ Test Engineering and Site 8.icensing Groups. The <sxisting practices allowed modification test certifications to be "person" dependent i rather than "system" or "procedure" dependent and as such uniformity was not maintained.

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The inspec a r noted that Technical Functions procedure EMP-017, defined and used "Turnover" differently than does Site Administrative Procedure AP-1043. The inspector further noted that

"responsibility for a project" af ter turnover is not explicitly defined in EMP-017, nor is the point of "completion of the test portion of a plant modification." Both phrases were inconsistent with the previous discussion on the use of "Ready-for-Service."

These inconsistencies in definition and use were also discussed with Startup and Test (SU&T) and Plant Licensing Groups who agreed to evaluate the need for procedure revision to clarify administrative controls over modification turnover to Operations and certification of system readiness for servic Implementation of several modifications were reviewed and are detailed in paragraphs 3.2, and 3.4 belo .2 Regulatory Guide 1.97 Related Plant System Modifications The licensee is required by NRC regulations 10 CFR 50, Appendix A, Criterion 13, !nstrument and Control; Criterion 19, Control Room; and Criterion 64, Monitoring Radioactivity Release to provide instrumentation to: (1) monitor variables and systems over their anticipated ranges for accident conditions as appropriate to ensure adequate safety; and (2) monitor the reactor containment atmosphere, spaces containing components for recirculation of loss of coolant accident (LOCA) fluid, effluent discharge paths, and the plant environs for radioactivity that may be released from postulated accidents. USNRC Regulatory Guide 1.97, "Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environmental Conditions During and Fo. lowing an Accident" provides guidance and recommendations for compiying with the regulation By letter to the NRC dated June 5, 1986, GPU-Nuclear Corporation updated their schedule for implementing plant modifications to the TMI Unit-1 to ensure compliance to Regulatory Guide 1.97. This inspection verified the adequacy and effectiveness of the following selected design changes and modifications implementated during the Cycle 7 refueling outag . Neutron Flux Monitoring _ System Description of Modification The upgraded Neutron Flux Monitoring Instrumentation consists of two new redundant instrument channels, including associated sensors in the containment and indicators in the control room. New fission chambers have been installed in existing out-of-core detector wells in the reactor builaing. Environmentally qualified cables connecting these fission chambers were laid through the containment electrical penetrations 202E and 201E for

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NI-11 (channel A) and NI-12 (channel B) respectively and routed to preamplifiers NI-YY-11 and NI-YY-12. The preamplifiers are connected to the signal processing unit which provides signals for wide range indicators NI-YI-11 and NI-YI-12 in the control room. It also provides an electrically isolated signal to the plant computer for wide range recording from channel A, and an isolated input to the remote shutdown panel for source range indication from channel The new Neutron Flux Instrumentation is capable of monitoring neutron flux from source range (IE-6) to 100%

power rang B. Find;.m The inspector reviewed the modification package A25B-30491, l Regulatory Guide 1.97 Neutron Flux Monitoring System, including the associated safety evaluation, installation procedures and startup test results. The modification is designated as safety related/important to safety and is installed as such. The device was evaluated to meet environmental qualification requirements (Ref.1.2, Attachment A). In addition, the vendor's equipment design and qualification supported the survivability of the equipment through a design basis seismic event following 40 years of operation under normal conditions, as delineated in the Vendor Manual (Ref. 1.6 Attachment A).

The inspector also reviewed the construction documents and verified that the installation was conducted in accordance with approved procedures by qualified and trained individuals. QA/QC interfaces for revi1 w of installation procedures, and verification of des :ed witness and holdpoints were adequate and properly uocumented. The result of the licensee QA audit 0-TMI-88-01, "Continued Engineering and Design Services" of Gilbert / Commonwealth's engineering documentation and design controls pertaining to the Neutron Flux Monitoring System Modification was also reviewed and determined to be adequat .

The inspector reviewed the startup test results of NI-11 and NI-12 Neutron Flux Monitoring Instrumentation and witnessed testing at 70% reactor power. The tests were conducted in accordance with approved test procedures by qualified individuals and the results met the acceptance criteria. However, during heatup and reactor criticality, the Neutron Flux Senso- NI-12 indication deviated some four decades from other Source Range indicators. This problem disappeared during power ascension. However, NI-12 was declared inoperable and the licensee instituted an investigation, including vendor contacts, to determine the root cause of the anomalies and to implement corrective action, o

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circuitry -owe , m i,.x d?termine.. At the comple >n et -

.censee .-i Pf vendor were ai' . - 3 t i ng t'. . c-- .n' lib of NI-12. The N msee': des'gn im process; tNr las . . I test; the ve - r recommended correw tb reportabil'

required under 10 a tu design inadeqt,- t could not be determ , this inspection because -'

i incomplete data. Tb i an :aresolved issue penunig further review of - ,ue sctions (50-289/88-17-03).

The inspector held discussions with cognizant individuals and verified that the Neutron Flux Monitoring Surveillance Procedure Weekly Check (DSP-1301-1) had been issued and that the Re/ueling Outage Calibration Procedure (SP-1302-1.2) was undergoing management review. Also, the licensee had identified changes a;fecting the plant Technical Specifications, the FSAR, and the training modules as a result of this modification. The cognizant groups are pursuing the necessary actions. The inspector verified the physical installation of preamplifiers, a signal processor, control circuitry and termination Channel separation and fire protection isolation were also verifie Configuration control and housekeeping were found to be adequate and acceptabl .2.2 Reactor Coolant Drain Tank Temperature Instrumentation Description of Modification Regulatory Guic'e 1.97 requires that the reactor coolant drain tank (RCOT) temperature instrumentation should be capable of mo'itoring the complete range of postulated RC3T temperatures. Accordingly, the new meter scales for RCDT temperature indicators TI-605A and TI-602B were installed; the associated existing 117.8 k-Ohm resistors were replaced with 99 k-Ohm resistors; and RCOT Temperature Instruments were recalibrated for a 50'F to 400*F range.

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The inspector reviewed the modification package A258-30491, including the associated safety evaluation and installation documentation.- The work was per-formed in accordance with approved installation'

procedure TMI-MM-412491-002, RCDT Temperature Range Extension. 'A commercial grade 99 k-Ohm resistor was procured with an approved QC inspection plan which verified adequacy of critical attributes, such as t insulation resistance, to meet its intended safety '

application. QA/QC interfaces for review of procedures and verification of witness and holdpoints !

for installation and post modification testing were !

found satisfactory. The licensee has also initiated a training hand-out to familiarize the operations personnel with the RCDT temperature instrumentation modification. The inspector verified the physical installation of the RCDT temperature instrumentation and reviewed the preventive maintenance and surveillance procedures. They appeared adequate.

l 3. Makeup and purification System Instrument loop Upgrade f Description of Modification i This modification upgraded the instrumentation which monitors process variables during and following an accident, to comply with the requirements of

Regulatory Guide 1.97. The upgraded Makeup and

, Purification System /HPI (High Pressure Injection) flow

! instrumentation consists of existing qualified transmitters, new qualified signal conditioning ,

! modules, and new indicating devices. The sensors l l providing signals for the upgraded loops are designed i i and manufactured to operate in post-accident

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environmental conditions, i f

i The cables used for Class 1E instrument connection t j were environmentally qualified per IEEE-383-1974, i l "Standards for Type Test of Class IE Electric Cables,

Field Splices and Connections for Nuclear Generating i Stations". Their field installation followed the ;

electrical cables separation requirements established ;

) in the licensee's system description, SDD-TI-772, Rey, i

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14 Findings The inspector reviewed the Makeup and Purification System Instrument Loop mcdification package A258-30491 including the associated safety evaluation, and installation and startup test procedures. The existing transmitters have been retagged to reflect the current configuration. The new class 1E circuits and new signal conditioning modules were installed in A3 and B3 cabinets. They provide electrically isolated outputs to existing control room annunciator and computer alarms for low and high flow set point All installation work was done in accordance with approved procedure TI-IS-412491-003, Revision 0 (Re .2, Attachment A) by qualified and properly trained individuals. QA/QC interfaces for review of installation and test procedures and verification of designated witness and holdpoints were adequate and properly documented. All post modification startup test results met the acceptance criteria and were properly reviewed by plant personnel and accepted prior to the system returning to service. 'No anomalies were identifie The inspector also verified the physical status of the installed equipment during a management verification of the system and valve lineup walkdown. Equipmen*.

configuration met the design criteria, and require-ments of Regulatory Guide 1.9 The licensee has issued a training handout of the modification to operations personnel, and initiated action to update the plant Technical Specifications and the Final Safety Analysis Report (FSAR).

3.3 10CFR50, Appendix R. Fire protection Program Related Modifications Remote Shutdown Transfer Switch _ panel B Repower and Rewire Remote Shutdown System for IC-V-3 and 1C-V-4 Description of Modifications Previous testing of the remote shutdown system identified that operation of associated transfer switches created a high frequency oscillation in the reactor coolant pump power monitor circuitr The possible momentary tripping of one of the reactor coolant pump power monitor channels, while the plant was operating, could result in a reactor trip if the reactor protection system or reactor coolant pump power monitors were being tested. This modification repowered the B channel relays in the remote shutdown transfer switch panel (RSTSP) B from 1B Engineered Safe-

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15 i guard (ES) motor control center. In addition, the previous ;

power supply configuration from the vital AC distribution i

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panel VBB was disconnected. This change provides a diesel generator backup source of. power to the B channel relays in RSTSP The licensee also analyzed that with the previous design

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configuration, the Intermediate Cooling. Isolation Valves 1 IC-V-3 and IC-V-4 could close on a spurious engineered safeguard actuation during a fire. In order to correct the situation,.these valves were rewired through the remote 1 shut-down transfer switch panels. This modification allows them to remain open during such an inciden Findings  !

The inspector reviewed modification packages A25G-30244 and A25H-30244 including the associated safety evaluations .

installation procedures, and test procedures. The work was performed and documented in accordance with approved procedures. All test results met the acceptance-criteria

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and were properly reviewed by cognizant personne Material procurement met the design requirements and was adequately documented. All material was properly receipt inspected. QA/QC interfaces for review of the

, installation and test procedures (Ref.1.2, Attachment A),

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and verification of designated witness and hold points were adequate and properly documente The inspector verified the physical configuration and

status of the installed devices and determined that the

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design requirements were me Housekeeping and cleanliness inside and around the panel were acceptable. The licensee i

has also provided a training hand-out for the IC-V-3/4 l RSTSP rewire to the operations personnel for

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familiarization of Appendix R related system modification The Operations Plant Manual, Section F-9 is currently l being revised and update .

3.4 ICS/NNI Enhanced Reliability Upgrade Modifications Description Modification

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Upgrade of the Integrated Control System /Non Nuclear Instrumentation (ICS/NNI) during the 7R outage is a system modification resulting from recommendations made under the Safety and Performance Improvement Program (SPIP) within the Babcock and Wilcox Owner's Group. The upgrade is

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designed to increase the reliability of ICS/NNI circuit functions and ICS/NNI instrument loops providing information to Control Room opera + ors.

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The licensee performed ICS/NNI modifications consisting of four ICS subsystem upgrades designed to make the "HAND" and

"AUT0" controls independent of each other. The setpoints and operating limits of the ICS were not changed by these modification Although the ICS system is not considered safety related, portions of the modification provide input signal enhance-ment to the ICS and have a QA classification of "Nv;1 ear Safety Related" because they interface with a Nuclear Safety Related (NSR) System. The applicable components comply with 10CFR50, Appendix A, Criterion 24 "Separation of Protection and Control Systems."

Some new equipment seismically mounted on the Control Room Console is seismically qualified to the methodology of IEEE-344, 1975, Recommended Practices for Seismic Qualification of Class IE Equipment for Nuclear Power Generating Stations," and has a QA classification of

"Regulatory Required."

8. Findings B.1 Per'formance of Test Tp-349/4. Functionally Test MS-V-4A/B and MS-V-3A-F The inspector witnessed the performance of TP-349/4 and observed the following:

a) All required preliminary work and prerequisite conditions were reviewed by the test director prior to starting the test. However, one prerequisite signoff (paragraph 8.3) was not made until well after the test had commenced. The test director entered his signature after the inspector noted it missing, b) The appropriate test equipment specified by the test procedure was in use and properly calibrated and controlle c) The procedure in use contained several typographical and editorial errors which required ex planation to avoid misinterpretation, d) The test was interrupted during performance of paragraph 9.1.16 due to a deficient condition. The Test Director, in conjunction with a Plant Materiels engineer and Plant Operations personnel, determined that ICS module IC 15.14 was "HAND" powered. This module should have been changed to "AUT0" power . . ." The module had not been

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properly rewi)ed during performance of a previous test (TP-300/0.1, Power Rewire of ICS/NNI). Discussion with the Test Director revealed that TP-300/0.1 had specified the ,

wrong location of module IC 15.14 and in fet, the module had not been properly rewired prior to performance of test

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TP-349/4. TP-300/0.1 referenced as-built drawings which also specified the incorrect module locatio Troubleshooting of the system involved some disagreement among test and plant personnel over current vs correct circuit configuration since construction drawings and other applicable documents containing current information were not physically present at the job site. These updated

. drawings were referred to by test personnel only after the I initial troubleshooting effort was ineffectiv Engineer-ing documents in use at the job site contained out-of-date and conflicting design information, and test personnel

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often had to rely on memory of modifications which had I

changed the original as-built plans. The inspector discussed this situation with Test and Plant Materiel personnel who expressed nn immediate concern. Further discussion with an Operations QC Senior Monitor revealed the existence of a closely related Quality Deficiency Report (GLO-015-88), which was written in April,1988 but was still outstanding. This QDR reports a particular lack of system configuration control, and the use of out-of-date and confileting plans and documents to perform work. The inspector discussed the status of this QOR with the site QA Manager, the site QC Monitor, and the Startup and Test Manager in light of the situation observed during functional testing of ICS/NNI modification e) The inspector noted from several discussions with Test and Plant personnel that performance of a system test was

"expected" to uncover and document conflicting and contradictory design information or unanticipated operational characteristics. This situation is exemplified by the purpose statement in TP-300/0.1, which clearly states that no drawing presently exists designating current, up-to-date circuit design, configuration, etc.,

for the ICS/HNI system. Since the site engineering groups do not compile all system modification details into final plan revisions until af ter the system has been "turned over" to P! ant Operations, no single set of ICS/NNI design documents are available to Control Room

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personnel for some time after the system becomes operationa This situation also reflects the fact that the test certification and turnover process is htavily "person" dependent and relies substantially upon the experience, knowledge and confidence of test personnel. Turnover occurs af ter satisfactory test performance and acceptance but without full and complete documentation prior to system operatio B.2. Performance of Test TP 349/5, Functional Testing i of ICS Control Loops on Loss of power at Cold Shutdown '

l The inspector witnessed the performance of Test TP-349/5 l and observed the following: l a) All required preliminary work and prerequisite conditions were reviewed by the test director and certified complete prior to initiating the tes l l

b) The appropriate test equipment specified by the I procedure was in use and properly controlled and calibrate l c) Several instances occurred where the test could not be i performed as written due to existing plant conditions being incompatible with test requirements, and/or plant components being tagged out of service. These situations i resulted in the temporary defeat of ICS/NNI interlocks; the ;

installation of temporary jumpers to bypass normal ICS/NNI l signals; and the deferral of major TP-349/5 sections to a '

later dat d) The inspector noted an apparent lack of communication I between Startup Test and Plant Operations personnel f concerning reqctred plant conditions for the ICS/NNI l functional testing. For example, during the daily l Plan-of-the-Day management meeting, the Plant Operations Manager had to be informed by the Startup and Test Manager ti,at the goals for achieving certain plant conditions could not be supported because certain outstanding testing had not yet been completed. This lack of communications I occurred on several occasions prior to plant criticalit Testing of a Feedwater Pump (FV-P-18) ICS/NNI control circuit was deferred until af ter the reactor was critical because the pump was tagged out of servic This deferral did not affect operational safety of the plant, however, it resulted from the apparent lack of close coordination between Startup Test and Plant Operations activities during plant restart. The inspector discussed these situations with the Plant O&M Director and the Startup and Test l

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Manager. The licensee agreed that there should be improvement in the coordination and scheduling of testing i to better coincide with pre-operational plant condition B.3 Review of Control Room Console Instrumentation Resulting from ICS/NNI Modifications The inspector noted that labeling on certain I S/NNI instruments (SP9A/B-FR and SP11A/B-PI) had changed as a !

result of system modifications. "Circle ICS" labels had 4 been installed on the control room console for approximately two weeks prior to this inspectio'n and one of the R0s questioned was not aware that the new labeling had been installed. Discussion with several control room personnel indicated that they were not aware of the new

"Circle ICS" labeling on the control room console. The

, inspector questioned CR operators on the extent of their

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training on ICS/NNI mcdifications and found that formal instruction had been given covering the design change l The simulator panels, however, had not yet been upgraded to

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reflect new labeling in the control room. A new Auto Bus Transfer (ABT) associated with "Circle ICS" instruments had been installed in the ICS system, and operator action was required to reset it in the event of an "AUT0" power los ,

Operators were not familiar with the location of the ABT in

the plant and were not certain as to what controls on the

ABT panel needed to be reset. The inspector noted that adequate information r= quired for correct operator action

was available in the control room, both in emergency

response procedures and in training hand-outs. It was

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apparent, however, that the level of misunderstanding among

. control room personnel over ICS/NNI equipment and labels i warrants additional review and/or instructio The inspector discussed lack of label familiarity with the site

! Training Manager and was informed that the simulator panels l would be upgraded by 10/1/88 to reflect actual control room instruments.

l 4.0 System Wal Qowns and Observations of Plant Startup Activities l 4.1 Emergency Diesel Generators The inspe. tor conducted a system lineup verification for the

! Diesel Generators A and B, with licensee managemen The system l lineup met the operational readiness requirements delineated in the

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operating procedure 1107-3, Rev 38. Housekeeping and cleanliness in the Diesel Generator Room was acceptable. However, the inspector identified that 1" globe valves EG-V-80 A/A and A/B; and EG-V-80 B/A and B/B were not listed in the operating procedure. These valves serve a safety function by providing e flow path for the turbo-charger jacket coolant. Their inadversant closure could impair operability of the diesel generators for lack of heat removal from the turbocharger. The licensee initiated a procedure change notice to revise the procedure. Omission of these valves in the operating procedure constitutes one example of a violation in which a procedure was not adequately established (50-289/88-17-02). Another example of this violation was discussed in paragraph 2. .2 Decay Heat Removal System / Makeup and Purification System Walkdown The inspector conducted a system / valve lineup verification for the Decay Heat Removal System and Makeup and Purification System with licensee management. The system / valve lineup met operational readiness as described in the Systems Management Independent Verification Checklists. Housekeeping and cleanliness along the system lineup and in the auxiliary building were satis-factor The individual conducting management verification appeared to be knowledgeable of the system During this walkdown, the inspector noted that the pressure indicator DH-PI-1223B on one of the Decay Heat Pump suctions had malfunctione The inspector investigated the surveillance history and noted that the equipment troubleshooting and calibration was performed during 1987. In order to correct this problem, the licensee promptly initiated a job ticket to replace the pressure indicato .3 Reactor Building Spray Pump B Relays Calibration During the Remote Shutdown Modification system walkdown, the inspector noted that the relays in the Reactor Building Spray Pump B Panel were not crimp sealed. Upon investigation, it was found that the relays were calibrated by the GPU-Nuclear Lebanon Relay Group on July 15, 1988, and inadvertently seals were not installe The licensee took immediate corrective action by verify ng the operating i

status of these relays and then installing tamper resistant seal Although the relay calibration and surveillance procedure does not call for this seal, it is an industry recognized good practice to provide seals on relays af ter calibratio The inspector became concerred that a quality control activity, such as relay calibration, was not witnessed by the station QA/QC personnel. Further investigation indicated that the relay calibration work was not coordinated with the plant scheduling grou QA/QC notification was therefore not carried out, eventhough it was required by the preventive maintenance procedur The QA group had

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identified, in their Quality Deficiency Report (QDR) HRH-039-88, dated August 2, 1988, a program discrepancy related to the lack of coordination and planning for the activities conducted by the Lebanon Relay Group. This item is unresolved pending verification of the adequancy and effectiveness of the licensee's planning and coordination of similar safety significant activities conducted by the Lebanon Relay Group at the site (50-289/38-17-04).

4.4 Witnessing of Reactor Heatup and Criticality In addition to system / valve lineup verificatiors for the plant restart (Paragraphs 4.1, 4.2 and 4.3), the inspectors witnessed the reactor heatup and criticality on August 14, 1988. These activities were well coordinated between the operations and nuclear engineering staffs which was evident from smooth reactor criticality progressio The individuals performing these activities were found experienced, properly trained and qualified, and provided adequate documented information to support the activities for this particular plant evolution. No major problems were identified except the inoperable Neutron Flux Monitor, NI-12 (discussed in paragraph 3.1.1). Further details of the inspection of licensee startup activities is documented in NRC Inspection Report 50-289/88-1 .0 Licensee Inservice Inspection Program (73051, 73/53, 73755)

5.1 Background Three Mile Island Nuclear Power Plant, Unit 1, was licensed on November 2, 197 The plant has a two loop Babcock and Wilcox designed reactor. September 2, 1974 was the commencement of the first ten year inservice inspection interva The first ten year inspection interval was interrupted due to the extended shutdown from

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February 17, 1979 to October 3, 1985. As a result of this shutdown the first ten year interval consisted of four distinct parts as shown

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belo FIRST TEN YEAR INTERVAL First Period: September 2, 1974 through January 1, 1978 Second Period:

First segment January 2, 1978 through February 17, 1979 Second Segment October 3, 1985 through December 7, 1987 Third Period: December 8, 1987 through April 19, 1991

! The plant is currently in the third period of the first ten year interval of the Inservice Inspection Progra The licensee is committed to the ASME Code,Section XI, 1974 edition through the i

Summer 1975 Addenda for the emainder of the first interval.

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5.2 Scope The licensee performed inservice inspection during this refueling outage to comply with the ASME Boiler and Pressure Vessel Code, and with their ISI schedule for the 7R (1988) outag The following areas were selected for inspection:

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ISI Program

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NDE personnel qualification and certification records

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Quality Assurance involvement in ISI activities

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Steam and Condentate Piping Erosion / Corrosion Inspection Program

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Engineering involvement in the ISI and erosion / corrosion programs 5.3 I_nservice Inspection Program 10 CFR 50.55a identifies the applicable ASME Boiler and Pressure Vessel Code (i.e. Code) year and addenda that must be used by the  !

licensee for inservice inspection (ISI). The actual Code year and addenda is based on the issue date of the operating license. The effective Code year and addenda during the first 10 year interval for Three Mile Island, Unit 1, is 1977 Code through Summer 1978 addenda for component supports, and 1974 through Summer of 1975 addenda for other components. These Code years and addenda have been approved by the NRC and will remain in effect until the end of the first interval in 1991. The licensee plans to take advantage of the  ;

allowable one year extension of the ten year interval to complete the inspection of the reactor vessel during the 9R outage in December

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Ouring the 6R (1986) refueling outage the licensee completed the second period of the first 10 year interval. At that time approximately 55% of the total ISI inspections -equired had been l per fortned. During outage 7R (1988) approximately half of the i remaining inspections were performe During outage 8R (1990) the

, licensee expects to complete the remaining inspections except for the

reactor vessel. The reactor vessel is scheduled for inservice  !

inspection in the 9R refueling outage in December, 199 From the above the inspector concluded that the licensee can complete the required inspections within the third period of the first inspection interval as required.

, 5.4 NDE personnel Qualification and Certification Records The inspector reviewed certification documents for selected individuals both in the licensee's and in the ISI contractor's

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organizations. All certification packages reviewed were found to contain the education, training and experience records required by SNT-TC-1A. In addition the contractor personnel had received site specific training in such subjects as safety and radiation, data collection and control, measuring and test equipment control, drawing and procedure use and control, and support of plant activities. The training on data collection and control was designed to provide consistency between ISI inspections during this outage and prior ISI inspections to aid in direct comparison of results from prior inspections. As a result of these reviews and discussions with licensee personnel the inspector concluded that the qualification program was effective, and the training to previde consistency was adequate to provide the necessary consistency in data reportin .5 Quality Assurance Involvement in ISI Activities The Quality Control organization is responsible for the performance of the inservice inspection Contractor personnel are used to perform inspections under the supervision of licensee personne During the 7R outage approximately 16 individuals were on site from the contractor (NES) for the ISI program. The contractor personnel are required to work in accordance with the licensee's NDE procedures. The licensee has three individuals in his on site organization certified in accordance with SNT-TC-1A to level III in all disciplines except eddy current testin The inspector reviewed selected data sheets that reported rejectable indications and followed the actions taken by the licensee to resolve the problem reported on the data sheet In all observed cases the licensee Special Processes and Programs (SPP) Group had generated a Request for Evaluation to request a disposition from the engineering group. When the engineering evaluation was completed and returned the SPP group prepared a Mater i Nonconformance Report (MNCR) to control the repair wurk in a' ' dance with the Quality Assurance Program. The dispositions mu.e by the engineering group were acceptable and met the requiremen'.s of the applicable ASME Code,Section X The inspector noted that one attachment weld for piping support CHH-108A was rejected for liquid penetrant examination due to the poor surface condition of the weld. In this case there was no prior examination required but in accordance with the ASME Code, 1977 Edition, Summer 1978 Addenda, this weld now was in Category C-E-1 and required examination. The licensee disposition on MNCR 880107 was to grind the weld smooth, reweld if necessary and perform the penetrant inspection. The work was scheduled to be completed after olant startu In preparation for the 8R (1991) outage the licensee performed multidiscipline walkdowns of plant areas that would not be accessible

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during power operations. The object of these walkdowns was to determine the equipment and preparations that will be required during the next inspection. Such things as scaffolding requirements, lagging to be removed, surface preparations to be performed, and interferences were determined. The result of the walkdown is a status document to assure all required inspections will be scheduled and performe The inspector reviewed audit S-TMI-88-05 performed by the independent onsite audit group. This audit of the Nondestructive Examination area included the organization, qualification of licensee and contractor NDE personnel, procurement and control of NDE material, procedures and their implementation, outage preparation, records, and corrective actions. Three procedural nonconformances were identified during this audit. Two of these nonconformances were related to the review of purchase orders by SPP and were determined not to impact on the quality of the hardwar The third noncompliance concerned the linearity check of contact thermometers u:ed during NDE. In this case the thermometers had been calibrated but not by using a three point verification. The inspector verified that the licensee had taken appropriate corrective action As a result of these observations and interviews the inspector concluded that the licensee's Quality Assurance organization was effective in controlling the ISI activitie The audit program was adequate to assure that the established program was being followe .6 Erosion / Corrosion Inspection As a result of NRC Bulletin 87-01 the licensee has developed an erosion / corrosion inspection program to determine to monitor wall thinning in selected piping systems. The inspector reviewed the results of the erosion / corrosion inspection program initiated by the licensee during the 6R (1986) refueling outage. The Technical Functions Organization (Corporate Engineering) Sad selected 63 components as candidates for degradation by erosion / corrosio During subsequent inspection of these 63 components, six components in the steam extraction system were rejected. Of these six, four components were replaced and two elbows were repaired by external overlay weldin Only the 450 elbow en the 6th stage extraction steam line from the moisture separator reheater to the feedwater heaters was subjected to two phase (steam / water) corrosion / erosion. The other five components were subjected to single phase (steam) corrosion / erosio During the 7R (1988) outage 66 components were selected for examination. Of these 66 components 16 were previously inspected during the 6R outage. One component was found rejectable. This component was a 90* elbow on the extraction steam line that had been

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P repaired in the 6R outage. As a result of this inspection the elbow was again repaired by expanding the size of the external overlay welding repai '

The above inspections were performed by contracted personr.el (Virginia corporation) and supervised by the licensee's QC

?cspectors. Prior to the inspection each component was marked < ah high temperature crayon in a grid pattern and photographed for positive identification of defect location The licensee C Aoned on leaving the grid markings in place for ease in locating the armas of thinning in future inspection Based on the mill tolerance of +/-12.5%, during the 6R outage all components found with wall thickness below the mill tole ance were evaluated by the Technical Functions organization. This approach led to a large number of evaluations required during that outage. For the 7R outage the Technical Functions provided the Special Processes and Programs (SPP) section with acceptable wall thickness for each component to be examined. If the wall thickness was found below this acceptance level SPP would then request an evaluation from the Technical Functions organization. SPP then prepared an HNCR for rejected components and processed the MNCP. through Plant Engineering to determine the resolutio From the above reviews and discussions the inspector determined that the licensee's erosion / corrosion control program was adequat ..

5.7 Engineering Involvement in ISI and Erosion / Corrosion Process ,

The inspector interviewed engineering personnel and reviewed selected <

requests for evaluation to determine the extent of engineering involvement in the ISI and Erosion / Corrosion programs. The licensee's engineering department reviews the data submitted by SPP to determine the effect of adverse conditions on the system, to evaluate the root cause of the problem, to determine the disposition ,

of the non-conforming item and if other components must also have corrective action, to determine the method to be used for repair, ,

and based on the design and requirements determines the acceptance

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standards for the repair. As a result of these interviews and reviews of selected Material Nonconformance Reports, the inspector '

determined that the plant engineering organization was providing adequate support for the plant and performing in accordance with the licensee's governing procedure .0 Plant Surveillances (61700)

6.1 Scope of the Inspection During this inspection, the inspector observed the performance of ,

various outage surveillance tests, reviawed Control Room

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Technical Specifications, changes to surveillance procedures, and the scheduling of test procedure performance. The inspector '1so ot terved the adequacy of management involvement and tne supervision of on going surveillance activitie Individual areas of the inspection are discussed in the following paragraph .2 Witnessing of Surveillance Tests The inspector witnessed the performance of surveillance tests SP 1303-12.4, "Decay Heat Pump Venting" and SP 1303-4.1, "Monthly Reactor Protection System (RPS) Surveillance." Operations were well controlled, procedures were followed, and appropriate log entries were made at the completion of the tests. The technicians were familiar with the procedures and the tests were cono'ucted in a formal manner. Supervisory overview was apparent on a frequent

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The inspector also witnessed the performance of SP 1303-11.42,

"Emergency Feedwater Flow (EFF) Verifications" on August 11, 198 The purpose of this test was to verify an EFW flow path from the condensate storage tank to both steam generators following an extended shutdown period. The operators followed the procedure with ver'stion compitance and were familiar with the procedur .3 Adjustment of Reactor Protection System for Cycle 7 Protective Functions

, The inspector observed two different crews on two consecutive shifts

! adjust the powea to flow to flux imbalanca reactor trip signal l instrumentation. The work was requested by a job ticket which referenced the technical manual, as well as a Temporary Change Notice (TCN) to SP 1303-4.1. The Instrument and Control technicians on both shifts appeared to have little preparation for the adjustment and required supervisory guidance to complete it. Although the job

ticket referenced the technical manual procedure, it did not clearly state which sections of the procedure pertained to the work. One crew omitted performance of the first sections of the procedure until the inspector pointed out that the first section was required for any adjustments to the module involved. This error was indicative of poor pre-planning and job ticket preparation. On both shifts, the Instrument and Control (IsC) technicians performing the work recognized that they did not fully unoerstand the procedure and

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sought assistance from supervisory personnel. The operating crew provided no overview of the work, and were unaware that the I&C technicians were having problems or that the technicians involved had never performed this procedure before.

. The inspector identified an aspect of this procedure that makes it particularly cumbersome and difficult in that the technician must perf s as many as nire hand calculations to derive the correct i

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adjustments. No worksheet was provided in the job ticket to perform and document these calculations. Consequently, the calculations were made on scratch paper and discarded af ter the work was compl:t- This problem was discussed with cognizant licensee personnel and an appropriate worksheet was developed and provided to the technicians for use during adjustment of the remaining RPS channel An additional potential procedure and/or hardware problem was observed by the inspector in that specified voltage tolerances in some cases app.ared to be too small for the achievable adjustment tolerances. For example, there are some cases where the specified tolerance band is 1 1.0 millivolt, but where the slightest movement of the potentiometer appeared to change the voltage by several millivolts. This problem was discussed with the cognizant member 'c the Plant Material Assessment Group, who acknowledged the prob' and stated that a number of procedure changes and potentiometer replacements were under consideratio The licensee representatives acknowledged the inspector's statement

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that these weaknesses needed to be improve .4 Review of Control Room Technical Specifications Amendment Nos. 142, 143, and 144 to the TMI-1 Technical Specifications (TS) were issued in July, 1988 by the NRC in support of cycle 7 operations. Amendment No. 142 provided new safety

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settings and operating curves as a result of the refuelin Amendment No. 143 raised the authorized maximum core thermal power

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level from 2535 Mwt to 2568 Mwt. Amendment No. 144 incorporated action statement > and surveillances for post-accident monitoring instrumentation installed in accordance with Regulatory Guide (RG) 1.9 As of August 10, 1988 Amendment No. 144 had not been entered in the control room copy of the TS, although an advanced copy of the amendment was clipped to the cover of the binder. A subsequent check confirmed that the amendment had been properly entered prior to plant startu Interviews with selected licensee personnel indicated

general familiarity with the contents of these amendments.

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6.5 Changes to Plant Surveillance Procedures Amendment No. 142 to the Technical Specifications, which was issued

! by the NRC on July 18, 1988, authorized elimination of the variable low pressure reactor trip function. The licensee implemented this action by a combination of a job ticket to readjust the instrument

. trip setpoints and a "pen and ink" change to the RPS monthly

! surveillance procedure (SP 1303-4.1). Although the change had received proper reviews and approvals, the inspector questior ' t ,e

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use of a pen and ink change for this purpose because the ame m sc .

j was available nearly one month before the procedure was actuf ;r l

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needed, and ample time was available to process a permanent change to the procedure. "Pen and ink" changes increase the potential for technician error. This was discussed with the author of the procedure change who acknowledged the commen .6 Scheduling of Plant Surveillance Procedure Performance  ;

During the intpection period, it was difficult to ascertain when various surveillances were scheduled to be performed. Most of the key surveillances in support of reactor startup did not appear on the weekly work schedule as being scheduled for any particular shif Generally, shift supervisors were not aware that a particular survetllance was to be performed on his shift until the technician arrived in the control room to start the work. This .nlaced an additional burden on shift supervisory personnel, since they did not '

have the opportunity to review the procedure and reconcile actual plant conditions with required surveillance conditions in advanc This practice increased stress on the licensed operators at a ti!e ,

l when plant activities are already at a high leve :

The licensee plant scheduling staff acknowledged the inspector's statement that performance in this area should be improve .7 Conclusion l The inspector's observations and review of the above plant surveillances

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indicated the licensee had a competent staff and workable procedures

that were properly implemented. However, the program weaknesses addressed above merit management review and action.

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7,0 Licensee's Actions on Previous NRC Concerns

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(Closed) Unresolved Item 86-17-09: Incorporate ASCO valve parts into the shelf life program.

l The licensee has evaluated 191 ASCO valves and repair kits held in the

storeroom for application of the shelf life program. The program now requires that valve. with expired shelf life for internal parts be conditionally issued with replacement kits for these parts. Quality l Control assures the kits are installed prior to the valves being used in the plan This item is close .0 U:. resolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items or violations.

' Un esolved items are discussed in paragraphs 3.2.1.B and 4.3.

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1 9.0 Management Meetings Licensee management was informed of the scope and purpose of the inspection at the entrance interview on August 8, 1988. The findings of

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the inspection were discussed with licensee representatives during the course of the inspection and pr64ented to licensee management at the August 19, 1988 exit interview (see Attachment B for attendees).

At no time during this inspection was written material concerning inspection findings provided to the licensee. The licensee did not indicate that any proprietary information was involved within the scope of this inspectio t

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ATTACHMENT A

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DOCUMENTS REVIEWED 1.1 Procedures Administrative Procedures AP-1001H, Rev. 4, 3/28/88, Drawing Utilization AP-1001C, Rev. 7, 5/23/88, Drawing Distribution Control AP-1043, Rev. 13, 2/26/88, Control of Plant Modifications AP-1047 Rev. 4, 2/8/88, Startup and Test Manual EMP-017, Rev. 4-00, 3/2/87, Project Ready-For-Service and Completion Reporting SP-004, Rev. 3-00, 12/21/87, Test Closeout i

1000-PLN-7200.01, Rev. 1-00, Operational Quality Assurance Plan MCF Job Order No. A25A-G1534, ICS/NNI Auto / Fan / Hand Power Changeout and Cable Routing 1000-ADM-3272.01, Rev. 1 GpVN Inservice Inspection Program Requirements and Responsibilities 6150-ADM-3272.01, Rev. 1 Special Processes and Programs, Inservice Inspection Program Development and Implementation 6150-ADM-3272.02, Rev. O TMI Inservice Inspection Schedules 6150-ADM-3272.03, Rev. O Recording and Distribution of Nondestructive

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Examination Data for Inservice Inspection 6150-ADM-3272.04, Rev. 0 Oyster Creek and THI Inservice Inspection Plans anc Schedules (Supersedes 6150-ADM-3272.02)

6150-ADM-3272.05, Rev. 1 Evaluation of Recordable Indications, Rev. 1 9800-ADM-3272.03, Rev. 0 QA Organization for the GPUN Inservice Inspection /NDE Services Program Operational procedures EP 1202-40, Rev. 12, 8/12/87 Total Loss of ICS/HNI Power i

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2 Attachment A

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EP 1202-40, Rev. 13, 8/12/88 Loss of ICS Hand and Auto Power EP 1202-41, Rev. 11, 9/4/87 Total or Partial Loss of ICS/NNI Hand Power EP 1202-42, Rev. 13, 9/4/87 Total or Partial loss of ICS/NN! Auto Power EP 1202-42, Rev. 14, 8/12/88 Total or Partial Loss of ICS/NNI Auto Power 1107-3, Rev. 3, Operating Proccdure - Diesel Generator TP-358, Wev. O, Neutron Flux Monitoring System 1.2 Engineering Documents TP 300/0.1, Power Rewire for ICS/NNI Modules TP 349/2, Functional Testing of the SASS Units TP 349/3, Functional Testing of the ABT TP 349/4, Functional Testing of MS-V-4A/B & MS-V-3A-F TP 349/5, Functional Testing of ICS Control Loops on Loss of Power at Cold Shutdown TP 349/6, ICS "HAND", "AUT0", "FAN" Power Change TP 349/7, Functional Testing of ICS Control Loops on Loss of Power at Hot Shutdown GPUN DWG 10-620-18-1024, Rev 1, 6/25/88, NNI/ICS System Elec. Connectio Diagram, NNI/ICS Reliability Enhancement Hodification GPUN DWG 10-620-18-1057, Rev. O, 3/31/88, NNI/tCS System Ele Connection Diagram Bailey DWC 08032724 Rev. H, 9/23/87, Analog Schematic Integrated Master Control T1-IS-41249-004, Installation Specification, Neut.ron Flux Monitoring System Rev. O N1-YE-11 and YE-12, Rey, 0, System component Evaluation Worksheet for Neutron Monitoring System Instrumentation T1-IS-412491-003, Installation Specification for Instrument Loop Upgrade Modifications, Rev. O

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3 Attachment A

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TP 400/0.1/0.2, Rev. O Intermediate Cooling Isolation Valve IC-V-3/4 Control Circuit Tes Rewiring of Remote Shutdown Transfer Switch Panel

"B" MM-412244-007, Pev. O, TI MM-412244-007 Rev. O T1-IS-412534-001, Rev. 2, 6/24/88, ICS/NNI Auto / Fan / Hand Power Changesut and Cable Routing to Support the ICS/NNI Enhanced Reliability Modification T1-IS-412534-002, Rev. O,1/6/88, ICS/NNI Auto / Fan / Hand Power thangeout and Cable Routing to Support the ICS/NNI Enhanced Reliability Modification SP-1101-41-003, Rev. 1, 8/14/87, TMI Specification for Installation of Electrical Equipment SP-9000-26-002, Rev. O, 11/4/87, Installation of Labels SE-412534-001, t /22/88, Safety / Environment Determination and 50.59 Review of ICL , nhanced Reliability Modificatio .3 Modification O iptions/ Packages F00-T1-621 A, Rev. $. '4 / , '~o, .C3 Enhanced Reliability, Div II M0 MDD-T1-621 B, Rev 1,1/26,'88, ICS/NNI Auto / Fan / Hand Power Change out and Cable Routing to Support the ICS/NNI Enchanged Reliability Modificatio A25G-30244, Repowering Remote Shutdown Transfer Switch Panel "B".

A25H-30244, Remote Shutdown Panel Rewire, IC-V-3 and IC-V-4 A258-30431 Regulatory Guide 1.97 Loop Upgrade and Neutron Flux Monitoring System Modification 1.4 QA Reports PIR 13416, 5/31/88 ICS/NNI Auto / Fan / Hand Power Changeout and Cable Rerouting for Enhanced Reliability PIR 23201, 7/1/88, Internal Wiring Inspection of ICS/NNI Control Cabinet Modification PIR 23206, 7/1/88 Internal Wiring Inspection of ICS/NNI Control Cabinet Modifiction P!R 23291, 7/21/88 Internal Wiring Inspection of ICS/NN! Control Wiring QA 7R Restart Validation Checklist QDR #GLD-015-88, 4/12/88, Plant Ccnftguration Control List Deficiencies

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Quality Deficiency Report (QDR), No. HRH-039-88, regarding QC verification and plant schedul TMI-88-01, TMI continuing Engineering and Design Services (Gilbert / Commonwealth) dated April 20-21, 1988 1.5 Design Change Notices / Field Questionaires Field / Change Requests DCN-C055187, 6/30/88, Notice of Problem Conditions in DTSG Pressure Loops A&E l

FQ-C058146, Rev. 1 3/29/88, Test Requirements of MDD-T1-621A, Div. II, Re FCR-C05E191, 6/22/88, Multiple Design Corrections and Modifications to ICS/NNI Construction Drawings FCR-C055406, 7/8/88, Rewire of OTSG Pressure Control Circuit l FCR-C055407, 7/21/88, Multiple Design Corrections & Modifications to ICS/NNI Construction Drawings FCR-C055183, 5/20/88, Multiple Design Corrections & P.odifications to ICS/NNI Construction Drawings FCR-C055402, 7/1/88, Multiple Design Corrections & Modifications to ICS/NNI Construction Drawings l FCR-C058154, 4/26/88, Correction of Specified ICS Module Location FCR-C055403, 7/11/88, Multiple Design Corrections & Modifications to ICS/NNI Construction Drawings FCR-C055409, 7/21/88, Multiple Design Corrections & Modifications to ICS/NNI construction Drawings FCR-C056622, 4/26/88, MDD-T1-621B, Fan Power Breaker Assignment FCR-C057637, 4/28/88, Deletion of ICS/NNI "At Power" Testing 1.6 References / Requirements / Source Documents GPU Nuclear Corporation Letter from Hukill to Stolz (NRC) dated June 5, 1986 Neutron Flux Monitor Instruction Manual No. 106, Rev. 2 (Gamma Metrices)

System Design Description SDD-TI-772, Rev.1, TMI Nuc1 car Generating Station Electrical Cable and Raceway Routing

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1EEE-383-1974, Standard for Type Test of Class 1 E Electric Cables, Field Spices and Connections for Nuclear Power Generating Statio USNRC Regulatory Guide 1.97, Rev. 3 Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident TOR-860, Rev. O, Pipe Erosion / Corrosion Inspection-6R Refueling and Maintenance Outage SP-1101-12-110, Rev. 1, 7R Pipe Wall Tanning Inspection 1.7 Maintenance Work Reviewed Task N System (s) Description C1 990 Main Steam Weld Seat Ring Repair Seat C1 990 Main Steam Internal Machining CS 274 Main Steam Weld Seat Ring / Repair Seat CIC 600 Auxiliary Steam Check Valve Leaks Through CN 808 Feedwater Inspect tubine governor control oil system CP 539 Main Steam Test Equipment Tool Calibration CP 866 Nuclear Services Checknate Test CP 866 Decay Heat Checkmate Test CP 855 Nuclear Services Checkmate Test CS 899 Condensate Repair A/B Section of Condensor Split Seams CS 292 Main Steam Pin Main Steam Hangers CS 292 Ma.o Steam Unpin Main Steam Hangers CL 456 Main Steam MOVATS TEST USING MOC SYS CP 553 Electrical Cal, of Electrical Equi CS 634 Air Handling Bearing Replace /Balince CL 002 Electrical 1A Aux Transformer Oil Leak CS 110 Feedwater VALVE OPERATOR TESTING PA 970 Electrical IL RP BKR IC Inspection PA J81 Reactor Coolant Vibration System Calibration PA H59 Electrical IB RP MCC Breaker Test PA C65 Reactor Coolant Motor Inspection PA 731 Security Security System Camera Ins PA K22 Chemistry PM Chemistry Lab Equipment V1 506 Electrical A Station Battery Test V1 506 Electrical B Station Battery Test V1 523 Reactor Protection RPS Purp/Fiux Operator CRC? Power Monitor CS 429 Reactor Coolant Reconnect Tubing Down Steam of Valve RC-V-1037

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PA G27 Reactor Coolant Tank Inspection PA C65 Reactor Coolant Motor Inspection Support V1 R93 Reactor Coolant Remove / Replace Code Safety Valve CS 743 Nuclear Services Paint Pipe in Rx Bld CS 646 Nuclear Services Paint Pipe in Aux. Bld l Fire Extinguisher Inspection

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PA U44 Fire Services for 2nd week PA 580 Main Steam Safety Inspection /Main CP 560 Fire Services Fire Poor Repair CR 841 Makeup & Purification Repack CT 085 Turbine Replace.TD-V-3A (Drain Valve)

CN 158 Turbine Investigate and repair TD-V-3A (Drain Valve)

CT 131 Chem Addition Repair CA-V-13 (Limitorque)

will not operate electrically (Valve)

CS 742 Nuclear Service Prepare and paint Nuclear Service piping in areas of Intermediate Building CN 583 Hydrogen Recombiner Replace flow transmitters on Hydrogen Recombiner HR-R-01 at backup CP 769 Reactor Coolant Inspect #2 and #3 seals on RC-P-1C (Pump "C").

Repair if needed CS 028 Reactor Coolant Inspect #1, 2 and 3 seals on RC-P-10 (Pump "D"). Repair it needed CP 736 Makeup Overhaul MU-P-1B (Pump "18")

CT 031 Makeup Replace outboard seal 0-ring. Adjust inboard seal (Pump "1B")

PA 144 ALL Determine percent of PM Back-log in Preventative Maint-tenance program  ;

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PERSONS CONTACTED GPU Nuclear Corporation S. Barkofski, Control System Engineer (Gilbert / Commonwealth)

R. Barley, Manager, Plant Engineering T. Basso, Plant Engineer

• G. Broughton, Operations and Maintenanca (0&M) Director, TMI-1 A. Feinberg, Manager, Training

• J. Fornicola, Manager, Operations Quality Assurance

• J. Frew, Manager, Material, Construction and Facilities (MC&F)

E. Fuhrer, Manager, Chemistry

• G. Gurican, Senior Licensing Engineer C. Hartman, Manager, Plant Engineering

• T. Hawkins, Startup and Test Manager J. Herman, Quality Assurance Auditor

• H. Hukill, Director, Three Mile Island, Unit 1

• C, Incorvati, Manager Quality Assurance Auditing G. Jaffa Human Factors Engineer R. Knight, Licensing Engineer R. McGoey, Licensing Engineer E. Lawrence, MC&F Plant Engineer G. Navratti, Inservice Inspection Specialist V. Orland, I&C Plant Engineer G. Oswald, Quality Assurance NDE Supervisor S. Otto, Licensing Engineer R. Prabhakar, Manager, Quality Control M. Ross, Manager, Plant Operations C. Shorts, Manager, Technical Functions D. Shovlin, Plant Material Director H. Shipman, TMI Operations R. Summers, Plant Engineering J. Sullivan, Licensing Manager G. Tullidge, Startup and Test Engineer J. Yost, Senior Engineer (Gilbert / Commonwealth

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United States Nuclear Regulatory Commission (USNRC)

• R. Conte, Senior Resident Inspector, TMI-l C. Cowgill, Chief Project Inspector, THI-1

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• R. Gallo, Chief, Operations Branch, DRS

"D. Johnson, Resident Inspector, THI-1

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• T, Moslak, Resident Inspector, THI-1

• Denotes those attending the exit meeting The inspector also contacted other administrative and technical personnel during the inspection.

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