IR 05000272/1981014
| ML18086A825 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 07/13/1981 |
| From: | Bettenhausen L, Greenman E, Hill W, Norrholm L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18086A824 | List: |
| References | |
| 50-272-81-14, 50-311-81-13, NUDOCS 8108030240 | |
| Download: ML18086A825 (22) | |
Text
Plz12-810611 050311-810602 72-810623 050311-810603
- ... 050311-810604 050311-810605 050311-810609 050311-810611 050311-810617 050311-810616 050311-810623 050311-810624 050311-810625 050311-810626 050311-810627 050311-810629 Report No Docket No License No Licensee:
U. S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT 50-272/81-14 50-311/81-13 50-272 50-311 DPR-70 DPR-75
REGION I
Public Service Electric and Gas Company 80 Park Plaza Newark, New Jersey 07101 Facility Name: __
s_a_l em __
Nu_c_l_e_ar_G_e_ne_r_a_t_in~g._* *_st_a"-t_i_on_* _-_un_i_t_s_l_a_n_d_2 __
Inspection At: __
H_an_c_o_c_ks_B_r_id_.g_e __,_N_e_w_* _Je_r_s_.ey ___________ _
ne 30, 1981 Inspectors:
- J. N rrholm, Senior Resident Inspector
?{:' JYJ. ?MJ W. M. Hil 1, Jr::Resident Reactor Inspector
. -:? e-= 27--& ;&;t,,c-=
'tali.* Bettenhausen, Ph.D, Reactor Inspector, EIB Approved By:
Ccl.tJ/l~
E. G. Greenman, Chief, Reactor Projects Section N Projects Branch No. 2, DRPI 2A, JUL 9 1981 date JUL 9 1981 date 7/Jo/g; date JUL 13* J9iJ date Inspection Summary:
Inspections on June 1 - June 30; 1981. (Combined *Report Numbers* 50.;.272/81-14 and
.-
50-311/81-13}
.
~
Unit 1 Areas Inspected: Routine inspections by the resident and region-based inspectors of plant operations including tours of the facility; confonnance with Technical Specifications and operating parameters; log and record review; review of licensee events; IE Bulletins and Circulars; and followup on previous inspection items. The inspection involved 57 inspector-hours by the resident and region-based NRC inspector Results:
No items of noncompliance were identifie Unit 2 Areas Inspected: Routine inspections by the resident and region-based inspectors of plant startup testing including tours of the facility; conformance with license requirements and Technical Specifications; IE Bulletins and Circulars; followup on licensee events; and, followup on previous inspection items. The inspection involved 123 inspector-hours by the resident and region-based NRC inspector Results:
No items of noncompliance were identifie ~j~
PDR ADOCK 05000PDR Q
1-
DETAILS 1. Persons.Contacted J. Driscoll, Chief Engineer L. Fry, Station Operating Engineer J. Gallagher, Assistant Maintenance Engineer S. LaBruna, Maintenance Engineer H. Midura, Manager - Salem Generating Station L. Miller, Station Performance Engineer F. Schnarr, Reactor Engineer R. Silverio, Assistant to the Manager J. Stillman, Station QA Engineer R. Swetnam, Radiation Protection Engineer The inspector also interviewed and talked with other licensee personnel during the course of the inspections including management, clerical, maintenance, operations, performance and quality assurance personne. Status of Previous Inspection Items (Closed) Follow Item (272/80-23-06)
Review of maintenance documentation relative to repairs of No. 13 Steam Generator nozzle. The in-spector reviewed the completed package for Work Order No. 935687, including records of NOE conducted following repai Two in-clusions in the final RT were found code acceptabl The package has undergone review by the contractor, the AN! inspector, the
!SI coordinator. The inspector identified no unacceptable con-ditions with regard to the documentatio (Closedl Follow Item (272/80-01-06) Diesel generator "over crank" trip protection. The inspector confirmed that DCR's l-SC-341 and 2-SC-342 were completed on all six diesels. The modification changed the set point for the "over crank" trip to 500 rpm which is within the range of the sensing switch. The inspector had no further questions on this ite (Closedl Follow Item (272/80-21-02) Evaluation of lightning ground desig Following a lightning strike to the south penetration area, an evaluation was completed on August 1, 1980 which concluded that preventive measures should include the addition of grounding masts on the penetration areas to reduce the probability of a strike to those structures. Design changes 1-EC-908 and 2-EC-909 have been completed for both units. These changes add two masts on the penetration areas. * The inspector had no further questions on this ite *
SITE
- e
(Closed) Unresolved Item (311/80-17-02) Supplemental report and evaluation of spurious SEC operatio By letter dated February 19, 1981, the licensee forwarded supplemental LER 80-19/03X-1 for Unit The licensee describes a test program undertaken during the period July 28 - September 3, 1980 to detect transients in the syste No transients or spurious operation were identified* during this perior The inspector noted that a subsequent event on May 20, 1981 led to a conclusion that the SEC is sensitive to power supply voltage fluctuations. The licensee's evaluation and corrective action to mitigate this sensitivity will be reviewed by the in-spector when completed (Unresolved Item 272/81-12-07 refers).
(Closed)
Open Item (311/79-18-01) Procedure for shutdown outside the control roo As documented in this report, SUP 82.5 was conducted during this inspection period and was witnessed by the inspectors. All applicable modifications to the test procedure were made prior to conduct of the test. The inspector had no further question. Shift Logs and Operating Records The* inspector reviewed the f o 11 owing p 1 ant procedures to determine *the licensee established requirements in this area in preparation for a review of selected logs and record AP-5, Operating Practices, Revision 10, May 21, 1980; AP-6, Operational Incidents, Revision 6, February 22, 1979; AP-13, Control of Lifted Leads and Jumpers, Revision 4, February 11, 1980; Operations Directive Manual; and, AP-15, Safety Tagging Program, Revision 1, November 21, 198 b. Shift logs and operating records were reviewed to verify that:
Control room log sheet entries are filled out and initialled; Auxiliary log sheets are filled out and initialled; Log entries involving abnormal conditions provide sufficient detail to corrmunicate equipment status, lockout status, correction and restoration; Log book reviews are being conducted by the staff; Operating orders do not conflict with Technical Specification requirements;
Incident reports detail no violation of Technical Specification
.LCO or reporting requirement; and, Logs and records were maintained in accordance with Technical Specifications and the procedures in 3.a abov c. The review included examination of the following plant shift logs and operating records and discussions with licensee personnel:
Log No. 1 - Control Room Daily Log, June 1-30, 1981 Log No. 6 - Primary Plant Log, June 1-30, 1981 Log No. 7 - Secondary Plant Log, June 1-30, 1981 Log No. 8 - Unavailable Equipment Status Log, June 1-30, 1981 Night Orders, June 1, 1981 - June 29, 1981 Lifted Lead and Jumper Log - All active Tagging Requests - All active (Unit 2)
Nonconfonnance Reports for May 1981 Incident Reports 81 - 112, 134-138, 140, 141, 145, 146, 149-162, 164, 166-169, 173-178, 180, 187, 188, 191, 192 The inspector had no questions relative to logs reviewed during this inspection perio. Plant Tour a. During the course of the inspections, the inspector made observations and conducted multiple tours of plant areas, including the following; (1) Control Room (daily)
(2) Relay Rooms (3) Auxiliary Building (4) Vital Switchgear* Rooms (5)
Tu~bine Building (6)
Yard Areas 0) Radwaste Building
.
..
(8}
Penetration Areas (9}
Control Point (10}
Site Perimeter
(11) *Fuel Handling Building (12} Containment (13}
Guard House b. The following determinations were made:
Monitoring instrumentation: The inspector verified that selected instruments were functional and demonstrated parameters within Technical Specification limit Valve positions. The inspector verified that selected valves were in the position or condition required by Technical Specifications for the applicable plant mode. This verification included exam-ination of control board indication and field observation of valve positions (Charging/Safety Injection, Auxiliary Feedwater, and Containment Spray Systems).
Radiation Controls. The inspector verified by observation that control point procedures and posting requirements were being followe Plant housekeeping conditions. The inspectors observed that several areas of the plant were still in need of housekeeping. This item was identified during the previous inspection period and acknowledged oy plant management at that tim Increased effort in this area has oeen noted by the inspectors out further improvements are neede This item will receive continuing attention by the inspector Fluid leak No fluid leaks were observed which had not been identi-fied by station personnel and for which corrective action had not been initiated, as necessar Piping vibratio No excessive piping vibrations were observed and no adverse-conditions were note Selected pipe hangers and seismic restraints were observed and no adverse conditions were note Equipment tagging. The inspector selected plant components for which valid tagging requests were in effect and verified that the tags were in place and the equipment in the condition specified *
By frequent observation through the inspection, the inspector verified that control room manning requirements of 10 CFR 50.54-(k) and the Technical Specifications were being me In addition, the inspector observed shift turnovers to verify that continuity of system status was maintained. The inspector periodically questioned shift personnel relative to plant conditions and their knowledge of emergency procedure Release On a sampling basis, the inspector verified that appro-priate documentation, sampling, authorization, and monitoring instrumentation were provided for effluent releases. The inspector noted that a containment pressure relief, CP-07-81, was perfonned on June 30, 1981 while the containment monitor (lRllA} was in alar The inspector confinned that appropriate sampling before the release and monitoring during the release were perfonned and the activity was within pennissible limits. A subsequent inspection was performed to identify the cause for the alann condition, and a leak (inside containment) was discovered on the pressurizer spray valve. The activity levels inside containment returned to normal following isolation of the leaking valv Fire protection. The inspector verified that selected fire exting-uishers were accessible and inspected on schedule, that fire alann stations were inspected on schedule, that fire alarm stations were unobstructed and that cardox systems were operabl Technical Specifications. Through log review and direct observa-tions during tours, the inspector verified compliance with Technical Specifications including Limiting Conditions for Operation (LCO's).
The following parameters were sampled frequently:
RWST level, BAST level and temperature, containment temperature, boration flow path, shutdown margin, offsite powe In addition, the inspector conducted periodic visual checks of protective instrumentation and inspection of electrical switchboards to confirm availability of safeguards equipmen Security. During the* course of these inspections, observations relative to protected and vital area security were made, including access controls, boundary integrity, search, escort, and badgin At the organizing union's initiative, the security guards remaining on strike tenninated their action effective 6:00 p.m. on June 25 *
All pickets were remove No unacceptable conditions were note The following acceptance criteria were used for the above items:
Technical Specifications Operation Directives Manual Inspector Judgement e. The inspector had no further questions relative to tours made during this inspectio *
7 Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted by the licensee pursuant to Technical Specifications 6.9.l and 6.9.2 were reviewed by the inspecto This review included the following considerations:
The report included the information required to be reported by NRC requirements; Test results and/or supporting information were consistent with design predictions and performance specifications; Planned corrective action was adequate for resolution of identified problems; and, Determination whether any information in the report should be classified as an abnormal occurrenc Within the scope of the above, the following periodic reports were reviewed by the inspector:
Unit 1 Monthly Operating Report - May 1981 Unit 2 Monthly Operating Report - May 1981 No unacceptable conditions were identifie.
IE Bulletin and Circular Followup The IE Bulletins discussed below were reviewed to determine that:
Licensee management forwarded copies of the response to the bulletin to appropriate onsite management representatives *
. Information discussed in the licensee's reply was supported by facility records or by visual examination of the facilit Corrective action taken was effected as described in the reply *
The licensee's reply was prompt and within the time period -re.,quired in the bulletin *
The reviews included discussions with licensee personnel and observation and-review of items discussed in the details belo By correspondence dated March 12, 1981, the licensee responded for both units to IE Bulletin 81-01, Surveillance of Mechanical Snubber All INC snubbers were inspected on both units within the time con-straints of the Bulletin. The only failures were found on the RHR pumps, on both units, and were attributed to in-service vibratio These snubbers were replaced. By May 29, 1981, the INC snubbers in this application on both units were replaced with mechanical struts in accordance with design changes 1-EC-841A and 2-EC-115 In addition, the remaining (PSA) snubbers were inspected with no in-service failures foun These results were previously discussed in NRC Combined Inspection Report 50-272/81-04 and 50-311/81-0 The RHR snubber failures were the subject of LER 50-272/81-17 and 81-2 The inspector further noted that Unit 2 Technical Specifications include section 4.7.9, detailing surveillance requirements for mechanical as well as hydraulic snubbers. The listing of mechanical snubbers is required to be submitted within the first four months of power operatio In a letter from NRC, dated November 20, 1980, the licensee was requested to provide an amendment application for Unit 1 within 120 days, to include the model Technical Specifications for mechanical snubber inspections. At the conclusion of this in-spection, the request had not been submitted fer Unit 1. This item is unresolved (272/81-14-01).
By correspondence dated May 6, 1981, the licensee responded for both units to IE Bulletin 81-02, Failure of Gate Type Valves to Close Against Differential Pressur None of the valves identified in the Bulletin are used at Salem. Salem PORV's are Velan valves with Limitorque operators. The inspector had no further questions on this ite By correspondence dated May 22, 1981, the licensee responded for both units to IE Bulletin 81-03, Flow Blockage of Cooling Water To Safety System Components By Corbicula Sp. (Asiatic Clam) and, Mytilus Sp. (Mussel). The licensee states that these species have not been observed in on-going benthic monitoring or in the radiological monitoring program. Additionally, environmental conditions in Delaware Bay appear to preclude establishment of permanent popula-tions of these species. The licensee further outlines the periodic condenser inspection program and sampling program which should provide adequate warning in the event fouling species appear. The inspector had no further questions on this item *
ay correspondence dated February 26, Maren 26, July 1 and July 31,
.1980, the licensee responded for both units to IE Bulletin 79-27, Loss of Non-Class 1-E Instrumentation and Control Power System Bus During Operation. The July 1, 1980 letter also provided the response called for by the Confinnatory Order on this subject dated April 4, 1980. The licensee's response provided a detailed listing of specific instrumentation, source of power, effects of failure, and, in some cases, proposed design change In tne July 31, 1980 letter, the licensee states that the design changes considered will oe implemente One modification to this position involved auxiliary feedwater jnstru-mentatio In view of NRC acceptance of this instrumentation as safety grade, no modification to power source is considered necessar The inspector has previously confirmed that operating infonnation relative to instrument bus failures has 6een provided in the control rooms (NRC Inspection Report 50-272/81-09 and 50-311/81-10). The following design changes have 15een initiated to accomplish the
- changes 1 "isted in the Bulletin response; 1-EC-1128, 2-EC-1129, l-EC-1130, 2-EC-1131, 1-EC-1204, 2~EC-1250. 1-EC-674, 2-EC-677, 1-EC-1132, 2-EC-1133, 1-EC-1134, 2-EC-1135, and 1-SC-342. The schedule for implementation is the next refueling outage on each unit. Completion will be confirmed by the inspector (272/81-14-02, 311/81-13-01). Further technical review of the Bulletin response by NRC is continuing. The inspector had no further questions on imple-mentation of committed actions at. this tim For the IE Circulars listed below 5 the inspector verified that the Circular was received by the licensee management, that a review for applicability was performed, and that if the circular were applicable to the facility, appropriate corrective actions were taken or were scheduled to be take,
--
80-23 Potential Defects in Beloit Power Systems Emergency Generators Salem generators are manufactured by Electrical Machinery Manufacturing Company and the c'oncerns identified in the Circular were evaluated as not applicabl Design Problems Involving Indicating Pushbutton Switches Manufactured by Honeywell Incorporated.
These switches are not used at the Salem sit No action was required by the license Inoperable Seismic Monitoring Instrumentstion The licensee's evaluation, based on satisfactory periodic surveillances and apparent lack of problems,concludes that current testing programs are adequate *
81-06 Potential Deficiency Affecting Certain Foxboro 10 to 50 Milliampere Transmitters The licensee uses 4 to 20 milliampere transmitters and concludes that the problem discussed in the Circular is not applicable to Sale The inspector had no further questions relative to Bulletins and Circulars reviewe. Operating Events a. Unit 1 (1)
On June 11, at 11':00 p.m., a service water 1 eak was discovered in containmen Investigation identified the source of the leak as an open vent valve on the service water header to No. 12 Containment Fan Coil Unit. The leak was detected by the sump level monitoring syste The sump: did not overflow. The cause of the 1 eak was failure to shut a vent valve prior to restoring the service water lineup. The leak was reported in accordance with IE Bulletin 80~2 Corrective action to prevent recurrence will be addressed in a written report *
(2) During this turbine outage, the licensee elected to open and inspect two steam generators due to an intennittent series of impacts on the Metal Impact Monitoring Systems (MIMS} recorded during operatio Photomapping of the tube sheets confinned that all tube plugs were in their proper locations. With vessel level at the nozzle mid-plane, an additional attempt to search the loops with a video camera was mad During the TV scan of No. 11 hot leg, the camera float became stuck approximately six feet into the loo Initial attempts to free the float and camera were unsuccessfu The camera float, which was stuck near the 14-inch RHR suction in No. 11 hot leg, was removed on June 10 during a temporary shutdown of RHR flo Upon removal, the fol lowing parts were not accounted for; a five-inch by one-inch stainless steel tube containing lenses and a lens positioning motor, a three-inch plastic extension tube, a three-inch length of 3/8-inch tubing, a short length of nylon line, and a piece of the float material. It is believed that RHR flow (nominally 3000 gpm) into the suction piping pulled these parts into the RHR syste The licensee prepared a safety evaluation to demonstrate that with the remaining camera parts located in either the Reactor Coolant System or the RHR System, continued operation of the unit could be performed safely. The evaluation was submitted to NRC for review *
(3)
Following the review of the safety evaluation, NRC pennitted the licensee to heatup unit On June 18, at 6:24 a.m., the unit entered Mode 4. Continued examination located most of the parts in the RHR Heat Exchanger inlet and some in the bypass valv These parts were recovered on June 19. The following parts were not recovered; nylon line, tape, non-metalic camera parts, and the 3 inch piece of 3/8 tubing. During heat-up and subsequent start-up, a monitoring program including valve cycling, pump testing, and increased noise monitoring was conducted as recommended by the NRC safety evaluation. The results of this effort indicated no unusual conditions and were discussed with the NRC resident inspector prior to critical operations. The Metal Impact Monitor-ing System (MIMS) provided no abnormal indications. Criticality was achieved at 9:45 a.m *. on June 2 Equipment problems with the individual rod position indicating system required shutdown prior to power operation On June 22, at 4:14 a.m., criticality was achieve The unit was synchronized with the grid at 1:48 a.m. and reached 50 per cent power by 10:00 p.m. on June 22. *
Due to high vibration on No. 7 main turbine bearing, power reduction was initiated at midnight to balance the turbin When the unit was taken off line at 2:25 a.m. on June 23, a turbine trip occurre Probable cause of the trip was overspeed. Since reactor power was still just above 10 %, the turbine trio resulted in automatic reactor trip. The reactor was again critical at 4:58 a.m. Following turbine balancing, the unit was synchronized to the grid at 2:54 p.m. on June 2 Intermittent MIMS alarms on steam generator channels con-tinued, particularly during power increases. During subsequent operation at 98 % rated thermal power, turbine vibration readings were normal and no Metal Impact Monitoring System (MIMS) alarms were received. Evaluation of the previous alanns by the licensee and vendor identified the impacts as operational in nature tvalves, expansion, etc.) and not characteristic of loose parts. Operation of unit 1 remained at 98 % power for the remaining portion of the inspection perio b. Unit 2 (1} At 5:00 a.m. on May 30, No. 21 Aux Feed Pump (AFP) became inoperable when bearing failure resulted in shaft damage. A subsequent reactor trip at 5:34 a.m. due to low level in No. 24 Steam Generator precluded further startup testing beeause of the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Technical Specification Action Statemen AFP 21 was replaced. Criticality was achieved at 5:49 a.m. on June 2 *
(2) Startup testing at the 10 % power plateau continued with several problems identified. The following trips were experienced; June 2 11:41 Reactor/turbine trip from 8 % power due to spurious unblock of source range NI channe June 2 2:09 June 2 6:06 June 2 7:57 Reactor trip from the intermediate range (1-ElLamps} due to source range channel power supply failure. The power supply was replace Reactor/turbine trip due to high-high level in No. 21 Steam Generato Reactor trip from low power while trouble-shooting inability to block source range channel N 3 (3) Following repair of the source range channel, the reactor was again critical at 8:36 p.m. on June The turbine was synchronized with the grid at 2:49 a.m. on June 3 and stabilized at 110 MWE (10 %
power).
Problems were experienced in attempting automatic steam generator level control. At 4:40 a.m. a turbine/reactor trip occurred due to high-high level in No. 22 Steam Generator. Safety Injection was also initiated, but no "first out" alann indicated. Since steam line isolation also occurred, it is believed that the initiating signal was high steam line flow (to the steam dump) coincident with low Tav All systems functioned nonnally on the trip and SI. The high head pumps injected for approximately five minutes. The SI was reset when termination criteria was confinned. Pressurizer level was 70 % on terminatio (4) During the Safety Injection on June 3, service water isolation valve 2 SW 26, which supplies the turbine building, failed to close. The valve was tested from the SEC output and declared operable prior to re-start. Subsequent review confinned that this occurrence was attributable to the loss of power described belo During the Safety Injection on June 3, start of No. 24 Containment Fan Coil Unit resulted in a trip of the feeder breaker to 18 230-Vol t Vital Bus. Subsequent investigation revealed that the thermal overload setting on the breaker had not been raised to a value con~
sistent with Unit 1. The result could be tripping of the feeder breaker under accident loading conditions without loss of offsite powe The overload settings were modified as intended. A 14-day report was submitted *
(5) Fol lowing an inves*tigation of feedwater and steam dump control circuits, the reactor was again critical at 3:33 a.m. on June **While maintaining feedwater control in manual at less than 10 %
- power, a reactor trip on low-low level in the No. 24 Steam Gen-erator occurred at 4:49 The reactor was again critical at 6:32 a.m. and startup testing at 10 % turbine power continue The-generator was synchronized to the grid at 9:27 a.m. on June
. At 9:32 a.m., a turbine trip/reactor trip was initiated by
. high level in No. 22 Steam Generator while level was being main-tained at 40 % in manua The level "swell" during power increase occurred too rapidly for operator/system response. The reactor remained in Mode 3 during evaluation. A problem in the feedwater regulating valve positioners was identified and corrected. The reactor* was critical again at 5:31 p.m. and the unit was on-line at 1:51 a.m., June 5. At 2:00 a.m., a turbine trip/reactor trip occurred due to high level in No. 23 Steam Generator while shifting to automatic control. Subsequent investigation identified a dif-ference in "null" voltages for manual and automatic control causing
- excessive valve opening when shifting to automatic. Time to return to manual and regain control was insufficient to prevent the high level trip *. Following repairs, the reactor was critical at 3:15 a.m. and synchronized at 4:43 At 5:50 a.m. the unit was at 110 MWE for an eight-hour run *
Further testing at 10 % power plateau was delayed by inconsistent and high results in turbine mechanical overspeed test (6)
At approximately 8:00 p.m. on June 9, containment sump level, humidity and airborne activity indicated a leak in containmen Subsequent investigation identified a broken weld on a letdown line vent valve. The leak was fsolated and repaired. The plant was in Mode 3 at the time of this occurrence. It was estimated that 3000 gallons of water leaked to the containment sum The plant had tripped from approximately 10 % power at 12:57 p.m. on June 9 due to low-low level in No. 22 Steam Generator while bringing the turbine up to speed. Restart was delayed due to the leak described abov The failed eves vent piping was repaired by installing a short schedule 80 pipe stem and ca The reactor was critical at 8:39 on June 10 and the unit synchronized with the grid at 1:55 a.m. on June 11. The plant tripped from less than 10 % power at 9:11 on June 11 due to high-high level in No. 22 Stearn Generator while unloading the turbine in preparation for mechanical overspeed trip Return to criticality was achieved at 9:54 a.m. and a series of successful overspeed tests conducte (7} During testing, anomalous and inconsistently low readings on steam flow channels were observed. Despite calib?ations and functional checks, the indicators did not provide normal indication at 20 %
steam flow. This problem may also explain continued difficulty experienced with automatic feedwater control. At 5:00 p.m. on June 11, the licensee elected to cooldown in order to implement a proposed design change to the steam flow sensing piping routing to associated condensing pots. The reactor was shutdown at 5:40 and was in cold shutdown at 5:49 a.m. on June 1 *
(81 Visual *inspection of No. 23 Auxiliary Feedwater Pump steam supply check valves on June 17 identified the following:
the valve discs had separated from the operating ann; the operating ann pivot hole
- had elongated; and the disc mounting hardware (stud, washer, and nut} were missing. Repairs and an inspection of the turbine were mad Inspection of Unit 1 identified an identical condition on both check valves. All missing parts have been recovered from the system. The valves are Velan 6-inch swing checKs, name plate data, 11Fig No. B 14-2114B-2TS.
Failure of these valves to seat in the event of an upstream steam line break could result in simultaneous blowdown of two steam generators. The licensee will submit an LER describing corrective actions and interim measures to assure operability *. Generic aspec.ts are. being evaluated by NR (9) At 1:55 p.m. on June 16, with the plant in Mode 5, spurious un-blocking of two pressurizer low pressure instrument channels re-sulted in initiation of safety injection. All three diesels and the second RHR pump. started. Other components were not available in this mode. After approximately two minutes, the SI was rese In accordance with Technical Specifications, SI is not reportable in Mode 5. Several components in the SSPS, suspected of causing the unblocking, were replace (10} Following modification to steam flow sensing lines, the unit wa heated to Mode 3 at 12:35 p.m. on June 2 The plant was critical at 7:37 p.m. on June 22 and synchronized to the grid at 11:41 At 3:00 a.m. on June 23 the loss of offsite power test from 10 %
power w~s conducted without incident. The test was witnessed by the inspector (lll At 11:33 a.m. on June 23, a containment service water leak w~s detected by containment sump level monitoring. The leak, estimated as less than 1000 gallons, did not overflow the sump and was stopped by isolating No. 21 Containment Fan Coil Unit. The source was a failed cap on a motor cooler drain. The cap was repaired and the unit returned to service prior to startu The reactor was critical at 6:35 p.m. and the unit synchronized at 10:39 p.m. on June 2 At 2:44 a.m. on June 24, Startup Procedure (SUPl 82.5, Shutdown Outside the Control Room, was initiated by tripping the reactor at the trip oreakers. The plant was success-fully controlled in hot standby from the hot shutdown panel and several aspects of the remote cooldown procedure were demonstrate The test was witnessed by the inspectors_ *
(12} The reactor was critical at 11:33 a.m. and the unit synchronized to the grid at 4:23 p.m. on June 2 At 4:33 p.m., low suction pressure resulted in loss of No. 21 Feedwater Pump and a consequent reactor trip on low steam generator level. The reactor was again critical at 6:44 p.m. At 7:06 p.m., apparent premature operation of steam generator *safety valve 21 MS 15, with Tave at approximately 5510F, resulted in low level in No. 21 Steam Generator causing another trip from low power. Criticality was again achieved at 8:18 p.m. and the unit synchronized at 9:36 p.m. on June 2 (13) The plant tripped from29 % power at 11:41 a.m. on June 25 due (141 to high level in No. 22 Steam Generator and the resulting turbine trip. All steam generator level control was in automatic with the exception of No. 2 An operator trainee controlling water level could not respond quickly enough to a change in feedwater flow caused by placing an additional condensate pump on the lin Restart was delayed to resolve a series of calibration problems with individual rod position indication. The reactor was critical at 5:00 a.m. on June 26. At 6:16 a.m., the reactor tripped from 2 % power due to low level in No. 24 Steam Generator while warming steam lines witn level control in manua The reactor was again critical at 7:18 On June 27 at 4:06 a.m., a reactor trip - turbine trip resulted from a low-low level in No. 22 Steam Generato An operator error caused loss of No. 22 Main Feed Pump wliich resulted in a low-low level in the steam aenerator. Several minutes later, at 4:08 a.m.,
a safety injection lSIJ occurred from a liigli steam flow (loops 21 and 231 coincident witfi low Tave. Subsequent investigation deter-
.. mined tFiat steam flow was affected oy rapid startup of No. 23 Auxiliary Feed Pump [steam driven} and severe hunting of tne governor immediately after startup. An interim solution included manually cycling.* * the governor valve periodically and after each us Long tenn corrective action is being evaluated by the licensee and will be reviewed by the inspector (311/81-13-02).
On June 29 at 6:35 a.m., a turbine trip-reactor trip occurred when loss of No. 21 Main Feed Pump caused a low level in No. 24 Steam Generator. The feed pump tripped on low suction pressure due to a clogged condensate strainer. Cleaning of condensate strainers had been required continuously since startup several"hours earlie It was noted that high steam flow (spiking) was not experienced *
after the trip. Subsequent startup was delayed while investigating and correcting a problem with pressure control in the volume control tank (VCTl. Repair of the VCT relief valve (2 CV 24:Qwas required *
r-
(15}
The reactor was critical at 4:33 a.m. on June 30,.following repairs to valve 2 CV 241. While in Mode 2, the main steam line bypass valves (21-24 MS 18) were tested to confirm closure time on main steam isolation signal. Two valves did not go shut and Technical Specification 3.6.3, Action b., requiring isolation within four hours was.. completed, however, closure of valve 24 MS 18 within 10 seconds could not be demonstrated. The licensee elected to fail the valve shut and isolate the pneumatic suppl On the premise that the valve was in its required post-isolation condition.{s'hut}, the l icense.e* considered it operable a*nd resumed power ascension to Mode 1. Technical Specifications are not explicit in pennitting mode change under these conditions. It was noted, however, that mode change with a main steam isolation valve secured in the closed position is pennitted. The licensee stated that a license change request will be submitted to modify'
the Technical Specifications for containment isolation valves, to permit continued operation if the valve is secured in its closed position. This item is unresolved pending NRR review of this request (311/81-13-03).
At the end of the report period, the unit was operating at 30 % power with all steam generator level control in automatic. The inspector had no further questions on operating event. Full Power License Conditions (Unit 2)
On January 14, 1981, April 28, 1981, and May 19, 1981, the NRC staff, in-cluding the Senior Resident Inspector, briefed the Commission on the status of Salem Unit 2 and the proposed licensing action to authorize operation in excess of 5 % rated thermal powe The full power license for Salem Unit 2 was issued on May 20, 1981 and contains several conditions to be met prior to July 1, 1981. The inspector reviewed a number of these items to determine status of implementation. The following comments apply to the areas reviewed (Numbers refer to paragraph references in the full power license):
-- 2.C. (lO)(g)
2.C.(24)(a)
Local operations during perfonnance of SUP 8 SUP 82.5 was conducted on June 24, 1981 and was witnessed by the inspectors. The following evolutions were con-ducted as part of the startup test procedure; local start of diesel generator using alternate control power source, local operation of 4 KV breaker, local start of con-tainment fan coil unit, local operation of a motor operated and an air operated valve, local control of chargin No unacceptable conditions were identifie Shift Manning. Regularly scheduled eight-hour shifts were established for licensed operators on June 3, 198 Non-routine use of overtime has been required due to vacation schedules and is governed by the guidelines of Action Item I.A.1.3 (NUREG 0737). *
-- 2.C.(25}(f}
Auxiliary Feedwater Initiation and Indicatio By letter dated June 12, 1981, NRC has accepted the Salem design of the auxiliary feedwater control and indication system as meeting safety grade requirements. This license condition is therefore met. A similar acceptance of the Unit 1 system is documented in correspondence dated June 16, 198.C.(25)(ii}
Containment Isolation Dependability-High radiation signal. The original Salem design for both units employs the feature of containment ventilation isolation on-high radiation (Reference NRC Inspec-tion Report 50-272/79-15}.
-- 2.C.(25)(h)(ii) Additional Accident Monitoring Instrumentation-Containment water level. The licensee has in-stalled, in both units, two redundant level instru-ments which measure level from the bottom of the containment sump (elevation 70'4~") to a height of approximately 86'. The required recording instruments were not installed with the indicator At the conclusion of the inspection period, re-corders for Unit 2 were operable but had not been permanently mounted in panel 2RP Efforts to complete the work were underway on July 1. The licensee asserts the following correlation between level and volume in containment: elevation 83'1" -
400,000 gallons; elevation 84'0" - 500,000 gallon Accordingly, the license requirement to measure 600,000 gallons appears to be me Detailed cal-culations to confirm this fact were not available during this inspection. Verification of the volume calculations and proper mounting of the recorders remain unresolved (311/81-13-04).
-- 2.C.(25}(g)(i)
Containment Isolation Dependability - Containment setpoint pressur By letter dated April 23, 1981, the licensee identifies the minimum setpoint pressure as 4.0 psig for containment isolation. Design changes have been completed on both units to establish this setpoin By letter dated June 16, 1981, a request for amendment of the Unit 1 Technical Specifications to reflect the new value was submitte Unit 2 Technical Specifications currently reflect the 4.0 psig setpoin The inspector had no further questions relative to license conditions reviewed during this period *
- 18 Power Ascension Procedure Review Test Procedures SUP 82.5, Shutdown from Outside the Control Room, and SUP 82.6,. Loss of Offsite Power, were reviewed using the following guidelines:
FSAR, Technical Specifications and license provisions incorporated as applicable; Procedure reviews and approvals performed in accordance with licensee's administrative controls; Test objectives clearly stated; Prerequisites and initial conditions identify required plant conditions; Acceptance criteria incorporated; The procedure includes references to appropriate material; Appropriate precautions included; Provision 1s made to ensure details of the test are recorded; The procedure is consistent with the test description in the FSAR SUP.82.5, Shutdown from Outside the Control Room, was originally approved March 6, 1979.* The test procedure was extensively revised to incorporate demonstrations of local control of equipment as specified in license condition The modified test procedure was approved as Change No. 1 on June 2, 198 The procedure requires:
Manual reactor trip outside control room; Maintenance of hot standby plant conditions from hot shutdown panel for one hour; Local operation of a fan coil unit, a service water pump, a motor-operated valve, a pneumatic-operated valve controlling charging and a diesel generator; Data collection to support the test objectives; and Restoration of the plant to nonnal operatio *
- The test procedure incorporates Emergency Instructions for Reactor Trip and Shutdown from Outside the Control Room as *well as procedures for emergency equipment operation. The procedure contains provisions for adequate manning of the Control Room during the test, for reestablishment of control room control in the event of malfunction or abnonnal conditions, for crew assign-ments to perform manual functions using a minimum shift crew and for conmuni-cation SUP 82.6 Loss of Offsite Power, was initially approved March 6, 1979, then extensively revised to incorporate revised Emergency Instructions and reissued as Change No. 2, approved June 2, 1981. The test procedure a.nd its incorporated Emergency Instruction contain acceptance criteria appropriate to loss of offsite power and maintaining plant in hot standby for at least 30 minute The test procedure contains provision to restore off-site power in event of problems during the test. The initial conditions call for steady state plant operations greater than 10 % rated thennal power with the pre-scribed electrical lineup. The test is initiated by opening the generator output breakers and the feeder breakers to the Unit 2 Station Power Trans-former The test procedure provides for restoration of the plant to normal operating conditions using facility procedure The inspector had no further question.
Inspector Witness of Power Ascension Testing Unit 2 startup tests described below were witnessed in whole or in part as they were perfonned, including backshifts and weekend Inspection criteria included the following:
Appropriate test and operating procedures available, in use and adhered to; Crew composition meets test and Technical Specification(s)
requirements; Test prerequisites met on a sampling basis; Technical Specifications and license.conditions met; Special test equipment properly calibrated and in service as required by procedure; Crew actions coordinated and timely; Evaluation performed as prescribed, with corrective action initiated where warranted; Data and test perfonnance documented as prescribed in test procedure for final analysis; Preliminary test results reviewed independently by inspecto *
B. Turbine Overspeed Trip Test (SUP 81.3}
The inspector witnessed overspeed trip tests on the turbine generato Initial trip tests on June 5 and June 8 were unsuccessful in that the mechanical overspeed trip point was inconsistent and higher than accep-table. The mechanical overspeed trip mechanism was extensively reworked to remove galling and improve mechanical clearances. A series of success-ful overspeed trips were completed on June 11; the average trip speed was 1839 rpm (average of 3 tests}. Loss of Offsite Power Test (SUP 82.6}
The inspector reviewed the completed surveillance procedure SP(O} 4.3.2. (a},. ESF - MANUAL SAFETY INJECTION, Revision lj approved March 11, 1981 and completed April 8, 1981. This surveillance procedure tests diesel generator* blackout loading sequence, automatic loading on initiation of safety injection, 24-hour endurance runs of each diesel generator and various protective features for the diesel generators. With the exception of some loads which were out of service at the time of test (24 Fan Coil Unit on 28 Vital Bus, 22 Charging Pump on 2C Vital Bus} and were later retested satisfactorily, the test was satisfactor SUP 82.6 was initiated at 2:58 a.m. on June 23, 1981 from 10 % generator power (110 MWE) and witnessed by the inspector. The plant tripped on loss of power; diesel generators started and connected safeguard blackout loads. Emergency oil pumps and auxiliary feed pumps functioned properl Inspector obser-vation and trend data review showed that the plant was maintained in a stable hot standby condition for more than 30 minute Inspection criteria previously set forth were applied. The inspector independently reviewed the sequence of events log, computer trend data and plant recorders for this transient test. As* a result of the tests, minor procedure and equip-ment deficiencies were noted and will be tracked through the startup test exception/deficiency mechanis The inspector had no further question Shutdown from Outside the Control Room Test (SUP 82.5)
The inspector reviewed the prerequisite preoperational test procedure SUP 50.15, Control Room Inaccessibility, for completenes SUP 50.15 was re-leased for test November 4, 1978, completed prior to January 20, 1979, and the test results reviewed and approved by the Preoperational Review Committee on March 8, 1979. The test was completed as required by test procedure with exceptions and deficiencies identified and resolve SUP 82.5 was initiated at 2:44 a.m., June 24, 1981. The inspector wit-nessed the control room evacuation, establishment of control from the hot*
shutdown panel, control of the transition to hot standby, maintenance of fiat standby conditions for one hour and remote local operation of a fan coil unit, a service water pump, a service water valve and a diesel generator using procedures developed as a result of fire hazards analysi The inspector ooserved effects of local control of charging from the control roo The inspector independently reviewed the sequence of events log, computer trend data, data logged by test engineers and test engineer*s narrative lo The inspector had no further question.
'.
11. Surveillance The reactor coolant system pressure isolation (check} valves were required to be leak checked to determine satisfactory operation. The test was imposed on unit 1 by Order dated April 20, 1981 and issuance of the Full Power License with Technical Specifications for unit 2. The results of the tests were satisfactory and presented in detail in NRC Inspection Reports 50-272/80-32 (Unit 1) and 50-311/81-11 (Unit 2). The inspector reviewed the surveillance procedures for Unit 1, SP(O) 4.4.6.3, and Unit 2, SP(O) 4.4.7.2.2 and concluded that the procedures were technically adequate to measure the valve leak rates and determine valve acceptability. The inspector noted three items which were discussed with the licensee. For unit 1, the leak rates were measured prior to issuance of the Order requiring the test. The acceptance criterion specified in the procedure was not the same as specified in the Order; however, the test results were within the criteria specified in the Orde The licensee stated that the leak rate limits imposed by the Order would be included in the surveillance procedur The inspector noted that not all throttle valves were included in the pretest valve lineup or the prerequisite section of the test procedures. If the valves were shut, they would have affected the measured flow rate. Based on a discussion with licensee personnel it may be necessary to shut a throttle valve to measure the leak rate of a single valve or reseat a check valve. Adequate control of the throttle valves will be examined in the review of the 1 icensee response to._ previous inspection item 272/81-01-0 The licensee could not produce data to indicate calibration of the installed flow measuring devices. The inspector expressed his concern that the flow indicators should be checked to provide assurance that the previous data was accurate, and the instruments should be calibrated periodically or prior to subsequent tests. The.1 i censee* concurred._with the. inspe.ctor*. This item*
is unresolved (272/81-14-05) pending calibration of these instrument. Fire Protection The licensee, as documented in Supplement 4 of the Safety Evaluation Report, NUREG 0517, stated that fire dampers will be provided on all supply and exhaust openings in the ventilation-ducts. Following installation,.an opera-tional test, "Damper Operation and Limit Switch Test Procedure," Sa 1 em Generating Station, Specification 70-6499, was perfonned to demonstrate satisfactory damper and alann operation. A contractor performed the tests and the licensee provided Quality Assurance inspectors to certify satisfactory operation. The inspector identified 106 dampers which had position alarms on the annunciator cabinets in the control room The inspector examined the QA records for the operational tests. The operational test records for 93 dampers were examined by the inspector and evaluated as acceptabl Data for the remaining 13 dampers was not available at the conclusion of the report perio *
The remaining dampers are identified as follows:
1 CAF 206 207 202 203 205 1 ABF 604 2.ABF 226 2 ABF 60 CAF 206
'
207 202 203 205 The test result will be examined when it becomes available. This item is unresolved (311/81-14-03) pending review of the test dat The inspector noted that the Technical Specification Surveillance 4.7.11 for* fire dampers only requires a periodic visual inspection to detennine operability. The inspector acknowledged that a visual inspection may
- identify obvious problems with dampers but the visual checks did not demonstrate operation of the damper in a manner similar to the operating test procedure referenced abov The licensee stated that the need for periodic operational tests was being evaluated. Periodic testing of fire dampers is unresolved {311/81-14-04) pending review of the licensee's evaluatio. Unresolved Items Areas for which more information is required to detennine acceptability are considered unresolved. Unresolved items are contained in Paragraphs 6, 7, 8, 11 and 12 of this repor. Exit Interview At periodic intervals during the course of this inspection, meetings were held with senior facility management to discuss inspection scope and findings *