IR 05000293/1985031

Safety Insp Rept 50-293/85-31 on 851105-1206.No Violations Noted.Errors Found in Operating Procedure & Valve Checklist for Loop B of LPCI Mode of RHR Sys.Instrumentation Problem Re Drift in Steam Flow Switches Addressed

ML20137B240
Person / Time
Site:	Pilgrim
Issue date:	01/03/1986
From:	Mcbride M, Meyer G, Neyer G, Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20137B216	List: IR 05000293/1985031 ML20137B211
References
50-293-85-31, NUDOCS 8601150194
Download: ML20137B240 (15)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report N /85-31 Docket N License N DPR-35 Category C Licensee: Boston Edison Company 800 Boylston Street Boston, Massachusetts 02199

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Facility: Pilgrim Nuclear Power Station Location: Plymouth, Massachusetts Dates: N emb Inspector: M h..i.!er5,1985-December McBri 4, Senior Resident Inspector h$ 6,1985 Date

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. Meyer(/ Project Engineer MsDate-Approved: . [. Add / /85 L. Tripp,f fhief, Reactor Projects ' Date Section No. 3A, Projects Branch No. 3

Inspection Summary: Inspection on November 5, 1985 - December 6, 1985 i (Report No. 50-293/85-31)

Areas Inspected: Routine unannounced safety inspection of plant operations in-cluding: Followup of previous inspection findings, operational safety verification and ESF walkdown, followup of non-routine reports, surveillance activities, and maintenance activities. The inspection involved 105.5 inspection-hours by one senior resident inspector and a project enginee Results: No violations were identified. However, numerous errsrs were fe.:nd in the operating procedure and the valve checklist for the B loop of the LPCI mode of the RHR system (Section 4.b(8)). This indicates that on going efforts to organize checklists and assure that valves are properly tagged need to be accelerated to aid in detecting and correcting such errors. A significant instrumentation problem involving drift in high steam ficw switches for the main steam lines is discussed in Section 6.b and remains unresolved pending final determination and correction of the root caus B601150194 e60106 r PDR ADOCK 05000293 G PDR L

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TABLE OF CONTENTS Page Persons Contacted ........................................ 1 Plant Status ............................................. 1 Followup on Previous Inspection Findings ................. 1 Operational Safety Verification and ESF Walkdown . . . . . . . . . 1 Scope and Acceptance Cri teria . . . . . . . . . . . . . . . . . . . . . . . I Findings ............................................ 2

! Followup on Nonroutine Reports ........................... 7 Surveillance. Testing ..................................... 8 Scope ............................................... 8 Findings ............................................ 8 Maintenance and Modification Activities .................. 10 Scope ............................................... 10 Findings ............................................ 10 Management Meetings ...................................... 11 Attachment A - Surveillance and Maintenance Items

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Attachment 8 - Set Point Drift in Main Steam Line Flow Switches

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DETAILS Person: Contacted Within this report period, interviews and discussions were conducted with members of the licensee and contractor staff and management to obtain in-formation pertinent to the subjects being inspecte . Plant Status The reactor operated at power throughout the report perio . Followup on Previous Inspection Findings

.(0 pen) Follow Item (85-28-03). Review licensee evaluation of the failure of valve MO-1001-36A to open on November 4, 1985. The licensee determined that the failure was caused by a loose wire connection on a terminal strip. The terminal strip screw was subsequently tightene Hold down bolts for the motor operator were also found loose and were subsequently tightened. The root cause for the loose terminal block screws and operator hold down bolts had not been determined by the end of this inspection. This item will remain open pending the completion of licensee revie . Operational Safety Verification and ESF Walkdown Scope and Acceptance Criteria <

The inspector observed control room operations, reviewed selected logs and records, and held discussions with control room operator The inspector reviewed the operability of safety-related and radiation monitoring systems. Tours of the reactor building, turbine building, station yard, switchgear rooms, diesel generator rooms, battery rooms, and control room were conducte Observations included a review of equipment condition, security, housekeeping, radiological controls, and equipment control (tagging).

The inspector verified the operability of a selected Engineered Safety Feature (EiF) system by performing a walkdown of accessible portions of the sistem. As found valve positions were compared to station drawings. General housekeeping was also reviewed during the walkdow These reviews were pt.cformed in order to verify conformance with the facility Technical Specifications and the licensee's procedure ,

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b. Findings (1) On November 5, 1985, the normally open scram discharge volume drain valve CV 302-22A, was unexpectedly closed by a half scran signal during a routine surveillance test, 8.M.1- The valve should only close on a full scram signal. The licensee subsequently determined that a solenoid valve controlling air flow to the drain valve was defectiv On November 8, the defective solenoid valve was replaced. A plant shut down was initiated during the replacement and an ENS notification made. During the replacement work, the scram discharge volume drain valve was closed and a half scram trip was maintaine The inspector reviewed the maintenance request for the repair, MR 85-641, post work testing, and discussed the ongoing repair with licensed personnel on duty. No problems were identifie (2) On November 10, 1985, the "B" train of the control room high efficiency air filtration system did not properly operate during a routine functional test. This system is manually initiated during an accident and filters the control room atmosphere to maintain habitability. During the functional test, 8.C.6, the control switch for fan VSF-103-B started the system, but the system shutdown when the switch was release The "A" train was tested and functioned normall The switch contacts were cleaned and the test repeate No subsequent problems were observed. The inspector had no further question (3) Cn November 17, 1985, the "S" train of the post accident containment hydrogen analyzer o;d not properly operate during a functional test. The instrument meter did not go upscale when the function switch was placed in the " span" mode during the test. The licensee cycled valves controlling the flow of calibration gas to the unit and repeated the functional tes No further problems were observed. The licensee subsequently verified the calibration of the hydrogen monitors with procedure 7.10.7 on December 3, 198 The licensee believes that a sticking flow valve caused the test problem. This incident is isolated. The inspector had no further question (4) On November 21, 1985, the inspector questioned the adequacy of testing of two time delay relays in the core spray pump start logic. The relays 14A-K12 A and B, were shown on drawing MIK-4-11 as being set to 0.33 see time delay. However, an NRC l

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inspection team, inspection No. 50-293/85-30, had not found evidence that the relay was calibrated. The team noted that a sequencing load test for the diesel generators had been conducted near the end of the 1984 outage, which demonstrated that the core spray pumps started in less that one second following the receipt of initiation signals. 'This test did not however, calibrate the time delay rela The licensee indicated that the relays were originally installed to allow the core spray pumps to be loaded onto the emergency busses after the residual heat removal (RHR) pumps during a loss of offsite power. However, the sequence was changed prior to plant licensing to require the core spray pumps to load first. This change eliminated the need for the core spray time delay rela However, in 1977, a core spray pump motor breaker tripped open during a routine load sequencing tast. The licensee concluded that the trip occurred because the test, 8.M.3-1, simultaneously inserted an ECCS initiation signal and a loss of offsite power signal into the core spray pump start logic. The ECCS initia-tion signal apparently caused the core spray pump motor breaker to start to close prior to the breaker logic receiving the loss of offsite power signal. When the safety bus undervoltage trip was received, the breaker went trip free with the breaker closing springs only partially charged. At that time, the core spray pump motor breakers did not automatically recharg Instead, the breaker springs had to be manually recharged if they tripped fre Between 1977 and 1982, the licensee prevented the trip free action by requiring the time delay relay to retard the ECCS initiation signal in the core spray start logic by 0.33 se In 1982, the breakers were modified to auton.atically recharge and reclose following a trip free action. Following the breaker modifications, the time delay became less important as the breakers would automatically recharge and reclose if they tripped free during the tes The licensee stated that the trip free condition would not be encountered during an actual loss of offsite power. The trip free condition, which could delay the breakers reciosing while the closing springs were recharged, would only be encountered if the breaker was tripped while it was in the act of closing. If a LOCA occurred before a loss of offsite power, the core spray pump motor breaker would first close and recharge the closing springs. The breaker would subsequently trip open on the power loss, but be available to immediately reclose on the safety bus when power was restore If a loss of offsite power occurred first, the breaker would not try to close until bus power was re-store '

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The design basis LOCA in the FSAR requires that the LOCA and loss of offsite power occur at the same time. This accident would generate a loss of offsite power logic signal first followed by the ECCS actuation logic signals. Since the two signals would not occur simultaneously, the time delay relays in the core spray pump start logic would not be needed to prevent the pump motor breakers from tripping fre The licensee concluded that the chance of the ECCS and loss of offsite power logic signals occurring simultaneously during a LOCA was remote. Therefore, the exact time delay for the core spray relays is not important, as long as the relays do not delay too long and run the core spray pump start sequence into the RHR pump start. The inspector agree The licensee verifies that the core spray time delay relays pick up quickly ("zero time") during semiannual surveillance functional tests 8.M.2-2.10.1-4 and -5. However, the test should relate the pick up time directly to the technical specification time limit of one second (technical specification table 3.2.B). At the exit interview, the licensee agreed to review the functional test wordin The inspector had no further question (5) On November 24, 1985, a small leak was detected at a socket weld on a one-inch drain line in the "A" loop of the core spray system. The drain line was located downstream from the 1400-4A valve on the recirculation line to the torus. The leak was visually detected during a routine core spray pump operability chec The weld was promptly ground out and repaired. The inspector reviewed the maintenance request (MR 85-661) and discussed the repair with maintenance personnel. At the exit meeting, the licensee indicated that an engineering review of line vibration would be conducted to attempt to determine a root cause for the weld failure. The weld had net previously failed. The inspector had no further questions at this tim (6) On November 25, 1985, the set points on eleven of sixteen high steam flow switches for the main steam lines were found to have drifted hig These switches are used to sense a main steam line break and activate the primary containment isolation system. The subsequent licensee evaluation is discussed in section 6 of this repor n p'

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h (7) On December 1,1985, the licensee initiated hourly fire patrols L to compensate for missed fire barrier surveillance tests. The i

barriers are required to be inspected once per operating cycle (eighteen months) by the technical specifications. Some L barriers were inspected early during the 1984 outage and are L currently due to be reinspected. The licensee indicated that-

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.some barriers could not be inspected while the plant was operating, due to personnel radiation exposure consideration In these cases, the itcensee stated that fire patrols would be used as compensating actions. Accessible barriers have been

, inspected. The adequacy of licensee actions was reviewed

! further during a subsequent NRC specialist inspection, No.

, 50-293/85-37; no problems were noted. The inspector had no fur-L ther questions.

I l~ (8)' On December 3, 1985, the inspector reviewed environmental l qualification records at the licensee's corporate engineering

! offices. On November 25, 1985, the NRC denied licensee extension l request for environmental qualification of equipmertt. Five items l were. included in the request. Only one item needed further testing; the other items required extra time to complete the

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l-l documentation of test results. The licensee initially estimated that two weeks (past the EQ deadline) would be required to com-plete the testing and ten weeks would be required for the docu-mentation. The EQ deadline was November 30, 1985.

,. After being informed of the Commission's decision on the l~ extension request, the licensee requested that a vendor l- laboratory reschedule the remaining EQ test and expedite the j completion of documentation and the review of the other tests.

L -These efforts required extensive coordinatien between the licen- see and the vendor testing laboratory over a holiday weekend.

! The . inspector conducted a preliminary review of the

documentation packages for four of the five items and found I that the packages were complete and had received appropriate licensee review.

L The inspector noted that the EQ thermal aging test on control l switches had been terminated an hour early (compared to the test l- specification). The licensee indicated that the discrepancy was not critical and would be documented. A subsequent NRC team in-spection, No. 50-293/85-35, also reviewed this item. The inspec-tor had no further questions regarding EQ documentatio During this review, the inspector questioned the completeness of action on an unrelated EQ matter. The licensee determined that electrical terminal blocks associated with reactor head vent valves (220-46 and 47) were not environmentally qualified.

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The terminal blocks could not be modified while the reactor was in operation. The licensee identified a possible failure mode for

! the unqualified terminal blocks which could cause them to inadver-tently energize the head vent valves, causing the valves to open while the reactor was pressurized. If this occurred, the reactor vessel would be vented to the drywell sump. To preclude this occurrence, the Engineering Department instructed the Operations Department to deenergize the head vent valves by pulling a fuse in a control room panel. The licensee pulled the fuses and tagged the valve control switches. An engineering memo, NED 85-1220, indicated that the fuses could be reinserted during

" start up and shut down." The inspector questioned the completeness of this instruction, considering that startups and shutdowns can extend for several weeks with the reactor pressurized. The licensee subsequently revised the memo to instruct operators to keep the fuse out and the valves deener-gized while reactor coolant temperatures are above 212 degrees Fahrenheit. The inspector had no further questions about this

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instruction (9) The inspector reviewed the valve lineup of the B loop of the LPCI mode of the Residual Heat Removal (RHR) system. The inspector utilized procedure 2.2.19, Revision 23, and P&ID

drawing M-241, sheets 1 & 2, revisions E14 and E9, respectively. The review included verification of valve positions in the NW and NE reactor building quadrants, the torus room and the B valve roo The inspector found all valves properly aligned. However, the

! operating procedure and the valve checklist used to align the l system were found to contain numerous errors, and the l licensee's efforts to tag the valves remained incomplet Section VII.A, Standby Status, of operating procedure 2.2.19 improperly listed outboard LPCI injection valve 288 as open and inboard LPCI injection valve 29B as closed. This lineup reversed the status as observed on control panel 903 and as listed in the valve checklist and the P&ID. This error was

! corrected by SR0 change 85-178 dated December 5, 1985, to l

procedure 2.2.19. The inspector marked up a copy of the valve checklist to indicate the status of tagging and to show checklist errors. The marked up copy was given to the Chief Operating Enginee Of the greater than one hundred valves reviewed, the inspector found that slightly more than half of the valves did not have tags, six valves had the wrong tags, and four valves were

tagged but not listed in the checklist. On the valve checklist

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the inspector found the following errors:

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4 valves were not shown on the drawing and were not found in the listed locatio valves had the wrong numbe valves had the wrong locatio valves were duplicated on different page valves had the wrong descriptio In addition, the inspector reviewed the last completed valve checklist, performed in December, 1984, on an earlier revision of the checklist. The inspector found that some of the above checklist errors had resulted from " corrections" made via the procedure change process following the last checklist completio In discussions with the Chief Operating Engineer, the inspector noted that the checklist is not organized by valve location or any other method and that since the checklist is 29 pages long, the lack of organization on the checklist appears to have abetted the checklist errors (e.g. , duplications, wrong numbers,etc.). The Chief Operating Engineer stated that efforts to organize checklists have been underway for over a year but have made little progress due to lack of adequate clerical suppor At the inspection exit meeting, the inspector identified the checklist's lack of organization by valve location and the lack of valve tags on all system valves as the root causes of the above checklist errors. Plant management stated that ongoing efforts to organize checklists and to tag valves would be accelerated to aid in correcting checklist errors. The inspector stated that the accuracy of valve checklists would be reviewed during periodic system walkdown . Followup on Nonroutine Reports Licensee Event Reports (LERs) submitted to NRC:RI were reviewed to verify that the details were clearly reported, including accuracy of the description of cause and adequacy of corrective action. The inspector determined whether further information was required from the licensee, whether generic implications were indicated, and whether the event

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warranted onsite followup. The following LERs were reviewed.

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LER N Event Date.- Report Date Subject 78-002/01X 1/20/78 11/12/85 Station Switchyard (Update) Shielding Mast Failure 85-28 10/10/85 11/12/85 Inadequate Surveillance Procedure 85-29 10/18/85 11/15/85 HPCI Inverter Inoperable The inspector had no further questions concerning the LER . Surveillance Testing Scope The inspector reviewed the licensee's actions associated with surveillance testing in order to verify that the testing was performed in accordance with approved station procedures and the facility Technical Specification A list of the items reviewed is included in Attachment "A" to this repor Findings (1) On November 25, 1985, the set points in eleven of sixteen high steam flow switches for the main steam line were found to have drifted high. The switches sense differential pressure across flow restrictors in the steam lines and are normally set between 118 and 123 psid (no adjust band). One of the switches drifted between the top of the no adjust band and a Watch Engineer's notification Ifmit (W.E. limit was 125.9 psid). The ten remaining switches drif ted above the W.E. limit. Two of the ten switches drifted above 140 psid. The licensee promptly notif!ed the NRC via the ENS telephone line, t. hat ten of the switches may have exceeded the technical specification limit of 140% steam flow. The correlation between sensed differential pressure and steam flow was not known at the station at that time. The next day, November 26, the licensee notified the NRC that five switches had actually exceeded the technical specifi-cation flow limit (equivalent to 127.2 psid sensed pressure).

The minimum number of operable high steam flow sensors (two per steam line) required by TS Table 3.2.A were still availabl I

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The switches, Barton Model 288A, were installed between December 1984 and September 1985 as part of environmental qualification upgrades to plant equipment. The 288A switches employ snap acting micro switches and replaced previous Barton switches that had internal mercury switches. The licensee indicated

that snap acting Barton switches had been used for several l years in other steam' flow sensing applications in emergency core cooling systems and had no history of drif Attachment 2 shows the testing history of the five switches that drifted above the technical specification limit on November 25. The licensee decreased the surveillance test interval from quarterly to weekly and retested the switches on December 2, 1985. All switches except the 2M switch were stable. The 2M switch had drifted low on December 2 and was also low on December 3 and 4. The licensee subsequently determined that binding of a roller assembly of an unused low-flow micro switch inside the 2M switch housing was causing the switch to react sluggishly. The licensee adjusted the roller assembly and lowered the set point for the low-flow switch on December 4. No subsequent drift was observed in this switc At the end of the inspection period, the licensee planned to adjust the low flow micro switches on the remaining steam line switches, to minimize further drift. At the exit meeting, the licensee indicated that the root cause of the drift problem had not been determined, but was likely related to the installation method. The EQ modifications required that the new switches be disassembled for installation. Tolerances in the reassembled switch linkages apparently were not adequately controlled. The

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adequacy of licensee control over these modifications is unee-solved, pending completion of the licensee root cause analysis (85-31-01).

(2) The inspector reviewed the surveillance testing of LPCI pamp and valve operability under test procedures 8.5.2.1, 8.5.2.2, and 8.5.2.3 during the months of October and November by reviewing the completed test records. The inspector noted that due to environmental qualification modifications to emergency core cooling systems, the LPCI system was surveillance tested frequently (e.g., during the 5 week period from October 11 to November 14, the RHR pumps were tested 14 times and the motor operated valves (MOVs) were tested as many as 18 times). The inspector found the test records demonstrated that the equipment met all acceptance criteri V ..

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The inspector reviewed the surveillance test procedures to ,

verify that the testing sequence was adequate and that technical specification requirements were met. .The inspector found the procedures to be acceptable with the exception of -

confusion concerning the testing of check valve Specifically, paragraph VIII.A.4 of procedure 8.5.2.2 and paragraph V.A.3 of its appendix A describe testing of check valves M0-1001-102, -103, and -10 However, none of these .

valves are check valves. Accordingly, the intent of the 'N procedure regarding these valves in unclear. The licensee stated at the exit meeting that the procedure was being reviewed and would be suitably modified (85-31-03).

(3) On December 4, 1985, the inspector observed portions of '

surveillance test 8.M.3-9, " Liquid Radwaste Effluent Discharge Radiation Monitor." The technicians. performing the test followed the surveillance procedure clo:ely, with the exception of an independent verification step. ' This step, No.17 in attachment A to the procedure, required that an alarm 1 annunciator be verified to be cleared ~at the end of the tes One technician checked that the alarm cleared and signed step 17; a second technician then signed the procedure without ,

checking that the alarm cleared. The second technician promptly indicated that he should have checked the alarm when questioned by the inspector. At the exit meeting, the licensee indicated that the technician had been further counseled. The inspector had no further questions at this tim . Maintenance and Modification Activities Scope

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The inspector reviewed the licensee's actions associated with main- .

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tenance and modification activities in order to verify that they were'

conducted in accordance with station procedures and the facility Technical Specifications. The inspector verified for selected items that the activity was properly authorized and that appropriate radiological controls, equipment tagging, and fire protection were being implemente A list of the items reviewed is included in Attachment "A" to this report.

j Findings On December 4, 1985, the inspector discussed recent residual heat re-l

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moval (RHR) pump wear ring problems at Peach Bottom Unit 3 with Pilgrim Station maintenance personnel. Pump impellor wear rings in Bingham single stage centrifugal pumps were recently found damaged at Peach' s Bottom when the pumps were disassembled for maintenance. Similar

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-(although not identical) pumps are installed in the Pilgrim RHR system. Failure of the wear rings can significantly degrade pump performance. Pilgrim personnel indicated that the wear rings in the Pilgrim pumps may have been made of a different material than the failed Peach Bottom rings. At the exit meeting, the licensee (Boston Edison) indicated that the implications at the Peach Bottom wear ring failures for Pilgrim were under review. The wear rings in the Pilgrim Pumps have never been inspected. No signs of degraded pump performance have been detected. The licensee's evaluation will

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be reviewed during a future inspection (85-31-02).

8. Management Meetings

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During the inspection, licensee management was periodically notified of the preliminary findings by the resident inspectors. A summary was also provided at the conclusion of the inspection and prior to report issuance. No written material was provided to the licensee during this inspection other than the marked up valve check list described in section four of this repor .

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ATTACHMENT A TO INSPECTION REPORT 50-293/85-31 The following surveillance and maintenance items were reviewed during the report perio *

Portions of the following tests were reviewed:

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Calibration of Comsip H2-02 analyzers on December 3, 198 Surveillance testing procedures of the core spray pump start logic, including test 8.M.3- Surveillance testing procedure for LPCI pump flow rate test and MOV timing, no. 8.5. Main steam line high steam flow sensor set point calibration testing data for 198 Radwaste discharge radiation monitor functional test on December 4, 198 Scram discharge volume drain valve functional test procedure, no. 8. Portions of the following maintenance and modification activities were reviewed:

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Environmental qualification modification records for selected items were reviewe MR 85-641, scram discharge volume drain valve goes closed on a half scram signa MR 85-645, control room air filtration system (high efficiency) is not workin MR 85-661, leak in a one-inch drain line downstream of MO 1400-4 MR 85-638, MO 1001-36 won't open on signal from control roo MR 85-653, the "B" hydrogen monitor did not perform as expected during test 8.M.3-1 Maintenance and modification activities on the main steam line high flow switches during 1985 were reviewe l

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ATTACHMENT B TO INSPECTION REPORT 50-293/85-31 Set Point Drift in Main Steam Line Flow Switches *

Date As-Found As-Left Switch Tested Set Point Set Point Comment 261-2A 12/4/84 --

12 Post Installation 12/19/84 121 No Adjustment 3/7/85 122 No Adjustment 8/30/85 110 120 11/25/85 128 12 /2/85 12 No Adjustment 12/6/85 121 No Adjustment 12/8/85 122 No Adjustment 261-2D 4/26/85 --

11 Post Installation 5/30/85 118 No Adjustment 8/30/85 109 119 11/25/85 128 120 12/2/85 12 No Adjustment 12/6/85 12 No Adjustment 12/8/85 12 No Adjustment 261-2E 3/29/85 --

12 Post Installation 5/30/85 112 121 8/30/85 109 119 11/25/85 148 12 /2/85 122 No Adjustment 12/6/85 126 119 12/8/85 118 120 261-2M 5/17/85 --

121 Post Installation 5/30/85 120 No Adjustment 8/30/85 111 121 11-25-85 143 121 12/2/85 110 119 12/3/85 105 122 12/4/85 108 121 **

12/5/85 122 No Adjustment 12/6/85 122 No Adjustment 12/8/85 123 No Adjustment 261-2N 5/3/85 --

12 Post Installation 5/30/85 121 No Adjustment 8/30/85 114 119 11/25/85 131 119 12/2/85 12 No Adjustment 12/8/85 118 No Adjustment

• No adjustment band 118.0 to 123.0 psi ** Low flow set point lowered and linkage adjusted.