IR 05000352/1987005

Insp Rept 50-352/87-05 on 870127-0318.Violation Noted: Failure to Maintain as-built Drawings in Technical Support Ctr.Unresolved Item Initiated That Addressed Effectiveness of QA Plan Re Review/Approval of Drawings

ML20206P481
Person / Time
Site:	Limerick
Issue date:	04/15/1987
From:	Eugene Kelly, Kenny T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20206P446	List: IR 05000352/1987005 ML20206P441 ML20206P458
References
50-352-87-05, 50-352-87-5, NUDOCS 8704210193
Download: ML20206P481 (16)

Text

.

.

U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report No. 50-352/87-05 Docket No. 50-352 License No. NPF-39 Licensee: Philadelphia Electric Company 2301 Market Street Philadelphia, PA 19101 Facility: Limerick Generating Station, Unit 1 Inspection Period: Jan ary 27 - March 18, 1987 Inspectors: f 87 e . lly, Senior Resident Inspector Daye / . Kucharski, Resident Inspector L. Scholl, Reactor Engineer T. Lu , R actor Engineer Approved by: / '

/ E7 T

nyActingChief,ProjectsSec.2A Date /

Summary: Routine daytime and backshift inspections (263 hours0.00304 days <br />0.0731 hours <br />4.348545e-4 weeks <br />1.000715e-4 months <br />) of Unit 1 by the resident inspectors and Region I reactor engineers consisting of:

followup on outstanding items; walkdown of the D12 diesel generator; plant tours including fire protection measures; maintenance and surveillance ,

observations; and review of LERs and periodic report The inspection covered Limitorque DC motor operators that were potentially deficient, a ground detected on the main generator, and the shutdown and subsequent startup at the beginning of the inspection period caused by high unidentified drywell leakage. Also assessed were a large number of P&ID drawing errors created during a CADD conversion process in July,198 A violation was identified for failure to maintain as-built drawings in the TSC. An unresolved item was initiated that addressed the effectiveness of the Limerick Quality Assurance Plan regarding review / approval of drawings for Unit PDR ADOCK 05000352 G PDR ,

___ _ _ _ _ - _ _ _ _ _ .

.

DETAILS 1.0 Principals Contacted Philadelphia Electric Company J. Corcoran, Engineer in Charge, Field QA J. Doering, Superintendent of Operations J. Franz, Station Manager G. Hunger, Nuclear Safety Section Head J. Spencer, Superintendent Services D. Helwig, Engineer-in-Charge, Mechanical Engineering R. Alejnikov, Modifications Coordinator 2.0 Followup on Unresolved Items 2.1 (Closed) Violation 86-43-01; Emergency Service Water Discharge Valves The inspector reviewed a modification to the manual discharge valve operators to provide position indicatio Quarterly ESW test procedures were revised to eliminate throttling of the pump discharge valves. An outline for licensed and non-licensed operator training was written, to be included in the next requalification cycle detailing the process to be.followed when performing STs, including Independent Verification of Restoration (IV0R),

NLOCT-0230, "ST Guide Lines". Finally, the training program was updated to include proper methods for verifying the position of manual locked valves, NLOCT-0260. This item is therefore close .2 (Closed) Violation 86-17-01; Drywell Chilled Water Isolation Valves The inspector reviewed revisions to Administration Procedure A-26 which provides controls for the performance of work using Maintenance Request Forms (MRF's). Appendix 1 to the procedure has been revised to clarify the meaning of the MRF Section 1 box titled

" Tech Spec /LC0", which ensures that primary containment isolation valves are " flagged" when they are taken out of service for maintenance. The Nuclear Training Section has also proposed additional review for containment isolation boundaries, design bases, license conditions and Operator Aids. A memorandum was issued to shift personnel discussing the blocking error that occurred, and the need to consider Technical Specifications when approving MRF's. Finally, primary containment isolation valves have been identified as such and entered into the CHAMPS and Permit Manager data bases so that they will automatically appear on MRF's and blocking permits. This item is therefore close _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .

_______

.

. 2.3 (0 pen) Deviation 86-17-02; Chilled Water Valve Shunt Trip Coils The inspector reviewed Temporary Circuit Alteration (TCA) 0737 disabling the subject shunt trip coils by disconnecting their terminal blocks at the motor control centers (MCC). The licensee plans to remove the shunt trip coils for the eight valves affected, and incorporate automatic isolation capability during the first refueling outage, under modification MDCP-106. This item remains open until the modification is implemente .0 Review of Plant Operations 3.1 Summary of Events A controlled shutdown of Unit I was performed on January 27 to repair three valves found to contribute to high unidentified drywell leakage. After repairs were made, the plant started up on January 30 and remained in operation throughout the reporting perio On February 18 a licensed amendment was received allowing operation at increased core flow and reduced feedwater heating. Reactor Engineers raised the Minimum Critical Power Ratio (MCPR) limit to 1.24 and the Rod Block Monitor clamp was increased to 106%. The

-

recirculation pump M-G set mechanical and electrical stops were raised to 106.5% and 106% respectively. This was performed to allow achievement of full rated power within the constraints of new 105%

core flow limi On February 24th, a field ground developed on the main generator and reactor power was reduced to 25% of rated to remove the turbine /

generator from service. The reactor remained in OPCON 1 during this time. Trouble shooting revealed that the problem was in the ground detection circuitry and the generator was returned to service on February 25. On February 27, the 6th stage of feedwater heating was removed from service to maximize power operations (resulting in a 43 degree feedwater temperature drop) until the refueling outage schedule to begin in May, 198 .2 Operational Safety Verification 3. Control Room Activities The inspectors toured the control room daily to verify proper manning, access control, adherence to approved procedures, and compliance with Technical Specification The inspectors reviewed shift superintendent, control room supervisor, and operator logs covering the entire inspection perio .-

.

Instrumentation and recorder traces were observed, and the status of control room annunciators was reviewed. Nuclear instrument panels and other reactor protective systems were examined. Effluent monitors were reviewed for indi-cations of abnormal releases; none were evident. Panel indications for onsite/offsite emergency power sources were verified for automatic operabilit Sampling reviews were made of equipment trouble tags (ETT's), shift night orders, and the temporary circuit alteration (TCA) and LC0 tracking logs. The inspectors also observed shift turnovers during the period. Opera-tions activities were observed for conformance with Administrative Procedure A-7; no unacceptable conditions were note . Security and Radiolerical Controls During entry to and egress from the Unit 1 Protected Area and Vital Island, the inspector observed access control, security boundary integrity, search activities, escorting and badging in accordance with Security Plan implementing procedures and guard force instruction The inspectors also observed the availability of radiation monitoring equipment, including portal monitors and por-table friskers. No unacceptable conditions were foun . Cold Weather Preparations The inspector reviewed the licensee's program to prepare the plant for cold weather operation. This program is described in General Plant Procedure GP-7, Cold Weather Preparation and Operations. The program consists of valve and switch check off lists which align: HVAC systems in critical areas; heat tracing for critical components; and, circulating and service water systems to operate in their winter modes. The program was completed except for the certification of position indication for four valves located in the Pipe Tunnel on the 14th of Novembe The Pipe Tunnel is a high radiation area during reactor operation, and the licensee decided not to send personnel into the area until plant shutdown. Proper valve positions were verified in January, 1987. No unacceptable conditions were identifie .3 Station Tours The inspectors toured accessible areas of the plant throughout the inspection period, including: the Unit I reactor and turbine-auxiliary enclosures; the main control and auxiliary equipment rooms;

.

5 attery, emergency switchgear and cable spreading rooms; and, the lant site perimeter. During these tours, observations were made of equipment condition, fire hazards, fire protection, adhererce to-procedures, radiological controls and conditions, housekeeping, security, tagging of equipment, ongoing maintenance and surveillance, and the availability of redundant equipment. No unacceptable conditions were identifie .4 System Walkdowns 3. Engineered Safeguards Features Verification The inspector performed a detailed walkdown of portions of the 1B diesel generator and auxiliary systems in order to independently verify system operability. The walkdown included of the following:

--

Review of emergency diesel generator Technical Specifications, FSAR, System Operating Procedures and P&ID's

--

Inspection of diesel generator IB equipment condition

--

System check-off list S92.1 and operating procedures consistent with plant drawings

--

Valves, breakers, and switches properly aligned, including appropriate locking devices

---

Instrumentation properly valved-in and operable

--

Satisfactory status of control room indicators and controls Within the scope of the inspection, no unacceptable conditions were note . PRA-Based System Inspection The inspector performed selected system walkdowns utilizing methods prescribed in a study prepared for the NRC by Brookhaven National Laboratory using the Limerick Proba-bilistic Risk Assessment (PRA). The study, entitled PRA-Based System Inspection Plan dated May 1986, provides inspection guidance by prioritizing plant safety systems with respect to their importance to risk. The study incorporates abbreviated system checklists which contain components that are considered to have a high risk factor as determined in the PRA.

l

_ _ _ - _ _ _ _ _ _ _ _ _ _

.

'

The inspector verified the proper configuration of the following AC/DC electrical power system components on several occasions during the inspection period:

--

power available to the four 4 kV AC buses

--

power available to the four 440V AC buses

--

power available to the four 125/250V DC buses

--

all diesel generator alarms cleared

--

power available from 220 kV and 550 kV offsite sources

--

diesel Local / Remote selector switch in Remote ~

--

ventilation fan switches in auto / standby

--

governor oil level (sight glass) satisfactory

--

air receiver tank pressure at 225-250 psig

--

fuel oil day tank level satisfactory

--

ESW discharge valve 11-1005 throttled open and locked

--

closed output breakers at each battery charger (six

,

total), and supply breakers closed as follows:

Div 1 From MCC 10B211ZA to IBCA1 From MCC 10B211ZA to 1BCA2 Div II From MCC 108212ZB to 1BCB1 ,

From MCC 10B212ZB to IBCB2 l l

No unacceptable conditions were note .0 Onsite Followup of Events The inspector performed onsite followup of the following events that occurred during the inspection period. The events were evaluated for i

proper notification to the NRC, reactor safety significance, licensee efforts to identify cause and propose effective corrective action, and verification of proper system design response.

l 4.1 Shutdown for High Drywell Leakage Unit I was manually scrammed from 27% power on January 27, 1987 following a controlled shutdown due to increased drywell leakag Unidentified floor drain leakage had been gradually trending upward at a rate of about 0.5 gpm per month over the previous two month Leakage increased from 2.5 gpm on January 23 to 4.7 gpm on January 26 when the decision to shut down was made prior to reaching the Technical Specification limit of 5 gp The licensee had unsuccessfully attempted to reduce the leakage by electrically backseating seven valves on January 26. A drywell entry was made on January 27 to identify the source of the leakag Three valves were identified as the sources of the leakage: a 24-inch feedwater check (1F010A) valve external gasket; and,12-inch

- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

l

..

'

manual RHR shutdown cooling return (1F0608) valve packing. A j smaller packing leak was found on a 2-inch motor operated reactor ,

vessel head vent valve (IF005). l The licensee replaced flexitallic gaskets on the shaft bearing side covers of both feedwater line inboard check valves; a leakage problem previously experienced during the June 1986 outage. Packing replacements were also completed on the loop A and B RHR shutdown cooling return valves; manual valves with internally spring-loaded

' live' Teflon packin .2 Main Generator / Exciter Ground Faults A load reduction was begun at 1:00 a.m. on February 25 from 97.7%

power due to ground indications on the main generator and exciter field windings. The grounds were discovered via alarms received on

February 24. The main turbine was manually tripped at 6:28 a.m. and reactor power was maintained at approximately 25% using the turbine bypass valves. Licensee field engineers performed megger checks of the main generator and exciter field with the generator at rest, no grounds were detected. Megger checks of the exciter also failed to identify the cause of the ground alarms. The generator was then gradually brought to rated speed while field engineers monitored meggers connected to the main generator and exciter field wirding These checks also failed to detect any grounds. The decision was then made to return the unit to service while monitoring the ground detection relays for any recurrence of the grounds. Full power operation was reached on February 26 with no indication of grounds on

'

the main generator or exciter field Licensee engineers suspect tht a surge in the ground detection circuit may have been the cause of the ground detection relay actuatio .3 Limitorque DC Motor Lead Insulation NRC Information Notice No. 87-08, Degraded Motor Leads in Limitorque i DC Motor Operators, addressed potential motor failure due to faulty j insulation. The licensee identified 23 potentially affected l Limitorque operators; 22 spares stored in the Warehouse and one motor l that was installed at another facility. Nomex-Kapton insulated leads l were found to be susceptible to insulation degradation and had caused l short circuit failures in Unit 1 in the Auxiliary Equipment Room

cooling coil valve TVC-90-0448. The inspector observed the

disassembly and inspection of the DC motor for TVC-90-0448. The

motor lead insulation ws in good condition although being of the

'

questionable Nomex-Kapton design. The motor was replaced under MRF 87-1654 and satisfactorily tested on March 4, 198 No violations were identifie . _ ._ . . - - , . _

r

.-

..

5.0 Licensee Reports 5.1 In-Office Review of Licensee Event Reports The inspector reviewed Unit 1 LERs submitted to the NRC Region I off. ice to verify that details of the event were clearly reported, including accurate description of cause and the adequacy of corrective action. The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted on-site followup. The following LERs were reviewed:

LER Number Report Date Subject 87-001 2/4/87 Secondary Containment Isolation due to (note b) Loss of Auxiliary Steam 87-002 2/20/87 Actuation of HPCI Isolation Valve (note a) due to Personnel Error 87-003 2/23/87 Control Room Chlorine Isolation and (note b) Emergency Fresh Air System Actuation 87-004 2/24/87 Primary Containment Sampling System (Group VI C) Isolation 87-005 3/2/87 Postulated Loss of HPCI and RCIC (note a) Systems Due to Channel Separation Violations Notes: Addressed in Detail 5.2 of this report Previously addressed in Inspection Report 86-27 5.2 Onsite Followup of Licensee Event Reports For those LERs selected for onsite followup as noted in Section 5.1, the inspector verified the reporting requirements of 10 CFR 50.73 and technical specifications had been met, that appropriate correc-tive action had been taken, that the event was reviewed by the licensee, and that continued operation of the facility was conducted in accordance with technical specification limit . LER No.87-002; Actuation of HPCI Isolation Valve On January 21, 1987 the HPCI outboard steam supply isolation valve closed upon receipt of a Division II

isolation signal during the performance of surveillance

!

ST-2-55-611-1, HPCI Room Temperature Channel Functional i Test. The cause was determined to be personnel error.

l

. - . _ . _ . , _ _ , , _ . .

.

a.-

.

An Instrument and Control technician, prematurely connected.a volt-ohmeter to normally open relay contact This shorted the relay contacts of the isolation logic through the meter, causing the closure of the HPCI cutboard isolation valve. The technician did not correctly follow procedural steps; correct performance of the ST would have placed the HPCI supply line outboard valve test switch in its bypass position and the isolation would not have occurred. The isolation was reset and the HPCI system was returned to service within 5 minute The inspector reviewed the licensee's corrective action, involving counseling the technicians involved in the importance of performing procedures in correct sequenc The license also re-emphasize the topic at an "All Hands" meeting. The inspector had no further questions, and identified no violation . LER No.87-005; Postulated Loss of ECCS Systems On January 30, 1987, during a comparison of the Unit 2 Plant Monitoring System (PMS) to the existing Unit 1 Emergency Response Facility Data System (ERFDS) it was determined that two temporary cables were incorrectly routed. The cables were originally intended to collect data during Unit I startup, and provided steam supply line high differential pressure isolation signals for the HPCI and RCIC system The cables were not connected to the proper channelized multiplexers, and were routed together with the cables for their redundant channels as well as connected to the same channelized multiplexe The HPCI steam line high differential pressure isolation signal, designated as safeguard channel D, was found routed through channel B raceway and connected to the channel B multiplexer. The RCIC had a similar problem with the high isolation signal, designated as a channel C signal, routed through A raceway and connected to the A multiplexe The inspescor reviewed the licensee's evaluation of the possible adverse consequences from this event. The licensee concluded that the consequence of the incorrect wiring configuration would have been a ground of one of the incorrectly routed cables along with the ground of one of its redundant channel cables. This would result in the loss of either systems steam line high differential pressure isolation signal. If this occurred, other sensors for both systems would be available to detect the event and isolate the steam supply lines such as:

.

.

.

--

High and differential temperature Equipment Room temperature

--

High Pipe Routing Area Temperature

--

Low steam supply pressur The licensee removed the two temporary ERFDS cables. The inspector had no further question .3 Review of Periodic and Special Reports Periodic or special reports submitted by the licensee were reviewed by the inspector. The reports were reviewed to determine that the report included the required information, that test results and/or supporting information were consistent with design predictions and performance specifications, and whether any information in the report should be classified as an abnormal occurrenc The following reports were reviewed:

--

Monthly operating reports for January and February 1987

--

Radiation Protection Manager's Conference, dated January 30, '

1987

--

1986 Annual Report of all Challenges to Safety Relief Valves -

Report No. 2, dated February 25, 1987 These reports were found acceptable and the inspectors had no further question .0 Surveillance Activities 6.1 Test Observations The inspector observed the performance of and/or reviewed the results of the following tests:

--

ST-6-092-311-1, D11 Diesel Generator Operability Test Run

--

ST-6-020-813-1, D13 Diesel Generator Fuel Oil Analysis

--

ST-6-001-760-1, Main Turbine Stop and CIV Valve Exercise Test

--

ST-6-076-250-1, SGTS and RERS Flow Test

--

CH-508, Determination for Particulate Contamination in Diesel Fuels The tests were observed to determine that surveillance procedures conformed to technical specification requirements; proper admini-strative controls and tagouts were obtained prior to testing; testing was performed by qualified personnel in accordance with approved

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ - _

.. . . . .

.

.

orocedures and calibrated instrumentation; test data and results were accurate and in accordance with technical specifications; and equipment was properly returned to service following testin No unacceptable conditions were note .2 Inspection of New Fuel On February 2,1987, the inspector observed the unpacking, inspection and transfer of new fuel bundles by QA, QC and maintenance personne The inspector noted that the following sequence of activities occurred. The packing box lid was removed; then, the box (with two i fuel bundles) was transferred to an upright position. Each fuel bundle was frisked prior to removing it from the packing carton and '

prior to removal of the plastic protective covering. A visual inspection of the lower tie plates and nose pieces was performed by QC inspectors and the bundles were transferred to stands for a detailed inspectio The detailed standup inspection consisted of visual and dimensional checks. Packing material was removed from between the fuel rods, and a sample of the packing material were frisked. Outer dimensions and clearances were measured on each bundle, along with the clearances between fuel rods. Visual inspection for obstructions between the rods and each spacer was performed, and fuel channels were visually inspected for irregularities. When bundle inspection was complete, the fuel channels were lowered onto the bundles and the bundles were transferred to the spent fuel poo No unacceptable conditions were note .3 Independent Verification of Restoration (IV0R)

On February 20, 1987 the inspector met with licensee representatives to discuss their effort in providing information and instructions for station personnel to follow when independently verifying the position of components as required during plant activitie The licensee has upgraded their administrative procedures A-41, Procedure for Control of Plant Equipment; A-42, Procedure for Control of Temporary Circuit Alterations (TCA); and, A-47, Preparation of Surveillance Test Procedures, to better describe independent verification. Auxiliary Operator training includes a t method for determining the position of valves which will aid in the performance of IVOR. Also included in the training program are the following:

--

LOR 86/1-B, Surveillance Test Guidelines

--

NLOCT 0260, Local Valve Position Indications

--

NLOCT 0230, Surveillance Test Guidelines

_ _ _ _ - _ _ _ _ _ _ _

.

.

The training guides include step-by-step methods for the required administrative procedure (A-47) that list the types of equipment that require independent verificatio Finally Chapter 6 of the Limerick Operations manual, " Guidance for Operations" includes a section on IV0R's and double verification. The inspector had no further question .0 Computer Aided Drafting and Design Conversion Errors 7.1 Background Computer aided drafting and design (CADD) was initiated for the Limerick Unit 1 and Unit 2 P& ids in February 1986. New drawings were issued on July 18-24, 1986, and drawings were distributed onsite in August 1986. Category 1 drawing locations in the TSC and control room were updated with the CADD conversion drawings on August 8, 198 During the period of September through November 1986, the Unit 2 Startup Test Group began to identify drawing errors as part of the preparation of flushing procedures for Unit 2 testing. The drawing errors were noted on " speed" memos from the Startup Test Group, and the number of.the errors accumulated to the point that, in early December 1986, PECO Engineering began an investigation of drawing At the end of December 1986, the licensee's mechanical engineering department had determined that a large number of inaccuracies existe On January 9, 1987 a meeting was held to discuss the issue and to involve the Limerick Independent Safety Engineering Group (ISEG).

The ISEG was requested to review the operational significance of the drawing errors as well as the reportability to the NR In parallel with this effort, a " red-line" process was begun in accordance with Limerick Administrative Procedure A6, and completed by January 19, 1987. The red-line process corrected as-built drawings in the five Category 1 drawing stick locations; i.e., control room, Blocking Coordinator's office, TSC, EOF and the Station Library. By February 12, the ISEG evaluation of the significance of the errors had been completed. A sample of 51 P&ID sheets (or 28% of all sheets) was reviewed for errors; the results of the ISEG review are described in Detail The NRC resident inspectors became aware of the drawing inaccuracies in early February 1987 and on March 3, 1987 a potential 10 CFR 50.55e report was made for Unit 2 via telephone call to NRC Region Subsequently, a meeting was held at the licensee's Corporate Offices on March 6th to discuss the errors, followed by an onsite meeting held on March 13th with NRC personnel. At the March 13 meeting, the licensee made verbal notification to the NRC of their intent to report under 10 CFR Part 21 for Unit so

.

7.2 Chronology Date Comment 2/25/86 Bechtel procedure for CADD conversions developed 5/2/86 Unitized _CADD P&ID's developed; hand-drawn P&ID's

"frczen" 7/18-24/86 CADD revisions issued 8/8/86 CADD revisions hung on control room Category I sticks Sept-Dec 86 Speed memos originated with Unit 2 startup flush procedure development identify errors (17 in September; 325 by December)

,

12/8-26/86 Unit 1 potential impact identified; reviews initiated 1/11/87 Corrected " yellow-line" P&ID's provided to site Modification Group 1/19/87 " Red-Line" process for Category 1 drawings completed 1/21/87 PECO QA Audit Findings issued 2/12/87 ISEG evaluation of operational impact completed 2/20-24/87 Corrected CADD prints issued 3/3/87 Potential 50.55(e) verbal report (for Unit 2)

3/6/87 Meeting between PECO engineering representatives and NRC senior resident inspector at Corporate Office 3/11-13/87 Limerick Unit 1 PORC meetings to discuss drawings 3/12/87 NRB meeting to discuss ~P&ID errors 3/13/87 Meeting with NRC onsite; verbal Part 21 notification

'

3/16/87 Part 21 report issued for Unit 1 7.3 Category 1 Drawings The inspectors reviewed Category 1 drawings in the main control room and Technical Support Center (TSC) during the period. Control room prints were found to accurately incorporate the request for drawing f changes (RDCs) which had been prepared to identify the errors on various P&ID sheets.

I

<

t-

,

On March 6, 1987 while reviewing the as-built drawings in the Technical Support Center, the resident inspector identified numerous prints which had not been updated to the latest as-built " red-line" revisions. This was an apparent violation of administrative proce-dure A-6, Control and Distribution Drawings. (50-352/87-05-01)

The inspectors also contacted Emergency Preparedness personnel and inquired as to the status of as-built drawings in the Emergency Operations Facility (EOF). The inspectors determined that versions of drawings in the EOF may have been more up to date than those on control room sticks. One instance was identified for P&ID M-12, RHR Service Water Systems, where the red-line version in the EOF was more recent than the red-line versions existing in the TSC and the control room. A meeting was held onsite with the outage planning engineer and the modification coordination group on March 12, 1987 to discuss the as-built process. The drawing problems and their distribution was discussed with licensee station personnel responsible for the red-line process, the modification coordinator group, and the discrepancy with the EOF drawings was explained to the inspecto .4 Impact on Unit 1 Prior to the July 1986 CADD conversion, there were a total of approximately 90 Unit I and Unit 2 P& ids. The CADD conversion

, process was for " unitization" of Unit 1 and Unit 2 P& ids; i.e.,

separation of Unit 1 and common systems from Unit 2 systems on different drawing sheets. The conversion process resulted in a total of approximately 300 drawing sheets or an increase of more than three-fold. Following the discovery of errors on the drawings, a total of 184 Unit 1 and common P&ID CADD-converted sheets were found to have errors.

i The Limerick ISEG sampled 51 of the total 184 sheets affected by the drawing errors. The ISEG sample identified and characterized the errors found on the drawings. While many of the errors involved coordinates, notes, and typographical titles, a percentage involved incorrect valve numbers (24% of the samples), instrument tags missing or incorrect (6%), and piping /line discrepancies (29%). The total number of errors on the 184 Unit 1 and common sheets was later determined by Bechtel Engineering to be 113 The ISEG assessment of the impact of these errors on Unit 1 operation involved a review of 590 procedures and 29 blocking and tagging sequences potentially affected by the drawing errors which had either been revised or initiated during the period of July 1986 to February 1987. ISEG engineers identified two instances (for the 590 procedures) involving a translation of the drawing errors into the documents. The procedures were not non-safety related, involved cooling tower and offgas systems, and had no impact on plant opera-tions. The operational impact conclusion was based on discussions

.

y

...

t

.

-15

.

with plant operators,-review of plant records, and. independent assessment by the ISEG group. The.ISEG also looked at 29 blocking and tagging sequences created or revised during the period in-

_ question and-found no instances where drawing errors had been translated into the sequence The. licensee's engineering department also undertook a review of all modifications designed or reviewed after July 1986 to present and identified a total of 105 potentially affected modifications. Of the: total number, 49 modifications were already implemented and 29 were in progress. Of the 78 working modifications, 31 modifications were safety-related and none were found to incorporate any of the errors'from the P& ids issued in Jul Although not completed as of the end of this period, the licensee is also reviewing the Quality Assurance Documents (QADs) which form the basis for Q-listed items and systems at Limerick. The drawing errors were also translated to the newly issued QADs. The effect of these QAD errors on procurement activities has been preliminarily assessed to be minimal although QA/QC organizations are still assessing the significance. Procurement at the current operational stageaof Unit 1 is normally accomplished through previously ,

existing purchase orders; therefore, the QADs have no direct effect-

_

for procurement of Q-listed _ items at the sub-component-level. The effect of QAD errors on procurement will be assessed in later inspection The Limerick PORC met on March _11 and again on March 13 and identi-fied an additional concern that is currently being investigate The concern-involved incorrect piping line. designations and line numbers in the P& ids on welding performed as part of modification *

The licensee was investigating this aspect at the end of the inspection period. A 10 CFR Part 21 report was issued to the NRC on March 16, 1987. This report identifies drawing inconsistencies and their potential for construction and operations erro .5 Conclusions

'

The resident inspectors reviewed control room prints, reviewed RDCs to correct the errors, discussed the ISEG's review of the operational significance of_the drawing errors, and the cause of the drawing errors with licensee's Engineering representatives. The inspectors concluded that, while the number of errors were large, no apparent operational significance or impact has been experienced during the 6-month period of August 1986 through January 1987 when the errors existed undetecte The inspectors also concluded that the undetected errors reflect the fact that P& ids are infrequently used by plant operators since operating procedures, surveillance tests, blocking sequences, and

- - _ _

F P

.

.

other operational activities had already been developed (prior to July 1986). The effect of inaccuracies and errors in p& ids is more a concern for modifications, although that work uses a P&ID as a

^

governing document, detail designed engineering goes further than P&IO. Further, there are many checks in place in the design change process that enable uncovering drawing errors over a period of time, such as system walkdowns and installation discrepancie Of more concern are accurate sets of as-built prints in the Technical Support Center and, to a lesser extent, the Emergency Operations Facility since these are the locations where Engineering and manage-

.

ment personnel would make post-accident decisions that may not be reflected in pre-established blocking sequences and operating pro-cedure Unresolved as of the close of this inspection was the effectiveness of the licensee's Quality Assurance Program for Unit 1 operation regarding engineering services and design activities. Specifically, the process whereby Bechtel conversion of P& ids to CADD drawings incorporated over 1100 errors that went undetected, and where

_

Engineering review and approval of the revised drawings was not formally undertaken, creates the question regarding program effec-tiveness. .This issue is unresolved pending further inspectio (50-352/87-05-02)

8.0 Exit Meeting The NRC resident inspector discussed the issues in this report throughout the inspection period, and summarized the findings at an exit meeting held with the Station Manager, Mr. John Franz on March 18. At the meeting, the licensee's representatives indicated that the items discussed in this report did not involve proprietary informatio s (