IR 05000206/1987010
| ML13323B284 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 07/23/1987 |
| From: | Andrew Hon, Huey F, Johnson P, Tatum J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML13323B282 | List: |
| References | |
| 50-206-87-10, 50-361-87-09, 50-361-87-9, 50-362-87-10, NUDOCS 8708100418 | |
| Download: ML13323B284 (22) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION V
Report No.50-206/87-10, 50-361/87-09, 50-362/87-10 Docket No, 50-361, 50-362 License No DPR-13, NPF-10, NPF-15 Licensee:
Southern California Edison Company P. 0. Box 800, 2244 Walnut Grove Avenue Rosemead, California 92770 Facility Name:
San Onofre Units 1, 2 and 3 Inspection at:
San Onofre, San Clemente, California Inspection conduc rough May 23, 1987 Inspectors:
F. R. Huey, enior R Date S gned Inspector, Uni s and 3 E/ Tatum,'Resident Inspector Date Signed AL./
, Rpsident Inspector Date Signed Approved By:
-2-3 7 P. hnson, Chief Date Signed Reactd Projects Section 3 Inspection Summary Inspection on April 4 through May 23, 1987 (Report Nos. 50-206/87-10, 50-361/87-09, 50-362/87-10)
Areas Inspected:
Routine resident inspection of Units 1, 2 and 3 Operations Program including the following areas:
operational safety verification, evaluation of plant trips and events, monthly surveillance activities, monthly maintenance activities, independent inspection, licensee events report review, and follow-up of previously identified items. Inspection procedures 30703, 36700, 37701, 61702, 61705, 61706, 61707, 61708, 61709, 61710, 61726,.62700, 62703, 71707, 71710, 72700, 86700, 92700 and 92701 were covere Results: Of the areas examined, two apparent violations were identified:
(1) Failure to provide adequate procedures for performing maintenance on
.safety-related equipment, and (2) Failure to comply with procedures for performing maintenance on safety-related equipmen PDR ADOCK 05000206
DETAILS 1. Persons Contacted Southern California Edison Company
- H. Ray, Vice President, Site Manager
- W.' Moody, Deputy Site Manager
- H. Morgan, Station Manager
- M. Wharton, Deputy Station Manager
- D. Schone, Quality Assurance Manager D. Stonecipher, Quality Control Manager
- R. Krieger, Operations Manager
- D. Shull, Maintenance Manager
- J. Reilly, Technical Manager P. Knapp, Health Physics Manager
- W. Zintl, Compliance Manager D. Peacor, Emergency Preparedness Manager P. Eller, Security Manager W. Marsh, Operations Superintendent, Units 2/3 J. Reeder, Operations Superintendent, Unit 1 V. Fisher, Assistant Operations Superintendent, Units 2/3 R. Joyce, Maintenance Manager, Units 2/3
- L. Cash, Maintenance Manager, Unit 1 1T. Mackey, Compliance Supervisor C. Couser, Compliance Engineer San Diego Gas & Electric Company R. Erickson, San Diego Gas and Electric
- Denotes those attending the exit meeting on May 22, 1987.
The inspectors also contacted other licensee employees during the course of the inspection, including operations shift superintendents, control room supervisors, control room operators, QA and QC engineers, compliance engineers, maintenance craftsmen, and health physics engineers and technician. Operational Safety Verification The inspectors performed several plant tours and verified the operability of selected emergency systems, reviewed the Tag Out log and verified proper return to service of affected components. Particular attention was given to housekeeping, examination for potential fire hazards, fluid leaks, excessive vibration, and verification that maintenance requests had been initiated for equipment in need of maintenanc a. Preparations for Mid Loop Operations (Unit 1)
The licensee planned to drain the reactor coolant system to the middle of the reactor coolant system hot leg during the Unit 1 mid
cycle outage in order to support maintenance on the reactor coolant pump seal packages. Considering the recent loss of residual heat removal (RHR) capability at another facility during a similar evolution and previous problems experienced on Unit 2, the inspector reviewed licensee actions to preclude recurrence of similar problems during Unit 1 mid loop operations. The inspector review covered the following areas:
(1) Onsite Review Committee Evaluation of Planned Efforts The inspector attended the Onsite Review Committee (OSRC)
meeting initiated by the licensee to review the planned actions for control of mid loop operations. During this meeting, the licensee described the several equipment design and administrative control features that were being implemented to ensure trouble-free mid loop operation. One of the key features of this effort involved the installation of redundant level indicators on the reactor coolant hot legs. These indicators included a narrow range instrument on the loop C hot leg that is independent of pressurizer venting and the reactor vessel head area (which has been a common problem for other level monitoring systems). This temporary indicator provided a narrow range readout in the control room and included a low level alarm. The inspector-had the following comments relative to the licensee's proposed actions:
(a) The licensee should determine the time period that is available from the point at which RHR circulation is inadvertently lost until the onset of fuel overheatin Specific measures should be established to ensure that this time period provides sufficient margin to allow for orderly establishment of containment integrity. Licensee review of this question indicated that core uncovering could occur as little one hour following a loss of RH On this basis, the licensee committed to install the containment equipment hatch during reactor coolant system water level manipulations and during the majority of the mid loop operating perio (b) The licensee should consider additional administrative controls to ensure proper alignment of key water level monitoring system valves and to prevent inadvertent reactor coolant system drainage during protracted mid loop operations. The licensee agreed to implement additional tagging and training to address this concer (c) The licensee should ensure that temporary level instrumentation is installed as safety related equipment, utilizing appropriate quality controls. The licensee agree (2) Procedures for Plant Draining and Loss of RHR
The inspector reviewed the licensee procedures for draining.to mid loop and response to inadvertent loss of RHR. No deficiencies were note (3) Operator Training The inspector attended operator training sessions associated with planned mid loop operations and noted no discrepancie (4) Level Instrument Calibration and Installation The inspector observed the calibration and installation of the temporary mid loop level monitoring instrumentation. The inspector noted that the temporary narrow range instrument, being installed on the loop C hot leg, was not properly mounted, in that the instrument was.not located below the level of the hot leg. The licensee took action to properly locate the instrument and noted that this problem would have been detected and corrected as a function of supervisory closeout of the maintenance order and post-maintenance testing. The inspector agreed that the licensee would likely have found the problem; however, the inspector noted that the maintenance order for installation of the instrument was inadequate and that additional attention by cognizant engineering and quality assurance personnel appeared to be warranted to preclude recurrence of similar problems. The licensee agreed to provide additional attention to this are The inspector noted that the tygon vent hose associated with the loop B temporary standpipe was kinked at the top of the standpipe and required additional support to preclude possible closure. The licensee committed to correct this discrepanc (5) Initial Drain to Mid Loop The inspector observed draining operations. The equipment, procedures and personnel performed very wel b. Control Room Shift Schedule (Unit 1)
The inspector reviewed the licensee's schedule for rotation of operating shift crews. The licensee's control room staff consists of five crews of licensed and non-licensed operators. Each crew works eight hours per shift for a period of seven days and rotates from day shift to evening shift and then to midnight shift with two to four days off between each seven day period. The nominal operation schedule is covered by four crews, while the fifth crew is on training. There is a half hour turnover at the end of each shift, not included in the eight hour shift, which is covered as routine overtime. A review of recent operations schedules indicated that overtime usage did not appear to be excessive. Furthermore, routine control room observation during various hours did not identify any evidence of inattentiveness or fatigue by the shift operating staf c. Seashell Damage to Circulating Water Piping (Unit 2)
Reactor power was decreased to 75% on May 12, 1987, due to a saltwater leak that developed in circulating water pump 2P-116 36" discharge piping to the turbine plant cooling water syste Evidently, the rubber liner inside the carbon steel piping was damaged over some-period of time due to seashells and barnacle The carbon steel piping corroded and a leak developed when the piping was exposed to the saltwater. Unit load was reduced to 75%
to enable P-116 to be isolated to stop the leak and make repair Maintenance was completed and the unit was returned to 100% power on May 14, 198 d. Overspeed Trip of Auxiliary Feedwater Pump 3P-140 (Unit 3)
While conducting In-Service Inspection (ISI) of trip throttle valve 3HV-4716, on May 3,,1987, steam driven auxiliary feedwater pump 3P140 tripped on overspeed. As a result of vibration problems with check valves MU-003 and MU-005, discussed previously in paragraph 5b of Inspection Report 50-362/86-19 and paragraph 5c of Inspection Report 50-362/86-23, steam isolation valve 3HV-8200 associated with steam generator E-089 was caution tagged in the closed positio This valve receives an automatic open signal upon receipt of an Emergency Feedwater Actuation Signal (EFAS). When 3HV-8200 was opened to conduct ISI testing of 3HV-4716, a water slug entered the turbine and caused 3P-140 to trip on overspeed. The licensee subsequently determined that steam trap 3F-209 which drains the steam lead upstream of 3HV-8200 was not working. The licensee visually inspected all snubbers in the applicable steam lines for damage and found them to be in satisfactory condition. The licensee demonstrated that 3P-140 was operable during a subsequent tes Currently, the licensee is maintaining 3HV-8200 in the open position to facilitate draining of the steam leads, pending repair of the steam tra Improper Bypass of Plant Safety Function On May 9, 1987, during exercise of control element assemblies (CEA's) to satisfy Technical Specification requirements, CEA #80 moved only 2 steps and a motion failure alarm was received. CEA #80 is assigned to subgroup #20 and is one of the six subgroups that make up shutdown bank B. The licensee placed subgroup #20 on the hold bus to facilitate troubleshooting, and CEA #82 (part of this subgroup) dropped into the core and caused core protection calculator (CPC) channel C to trip on local power density (LPD)/departure from nucleate boiling ratio (DNBR).
Since only one CEA of the subgroup had dropped, the control room supervisor (CRS)
did not consider the trip signal on CPC channel C to be valid and considered the channel to be inoperable. As allowed by the annunciator response procedure S023-5-2.11 for a failed channel, the CRS placed the trip in bypass. Subsequently, the licensee determined that a failure had occurred in the automatic CEDM timing modules (ACTM's) associated with CEA's 80 and 82. After the ACTM's were replaced, CEA 82 was withdrawn to the proper configuration and
the bypass was removed from CPC channel C. The inspector questioned the bypass of CPC channel C during this event since the CPC appeared to be functioning as designed. The inspector reviewed the following concerns with the licensee:
(1) Safety Significance The licensee stated that the control element assembly calculators (CEAC's) were designed to provide protection for asymetric CEA configurations that occur within a given subgroup. For other asymetric configurations that might develop which are not restricted to a single subgroup, the CEAC's do not provide protection and CEA position would not necessarily cause the CPC's to generate -a reactor tri Multiple CEA's that are associated with only one CPC channel could fall into the core, for example, and not cause a reactor trip. Review of CEAC and CPC design with the licensee indicated that the CEAC's provide an automatic protective function only for multiple dropped CEA's within a given subgroup. However, other combinations of dropped CEA's may cause a reactor trip if the dropped CEA's are associated with different CPC channels. The licensee considers that since the plant protection system is not designed to provide automatic protection for rod misalignments involving different subgroups, there was no safety significance to operator bypass of what was considered to be a spurious trip of CPC channel C. This item remains unresolved pending further review (50-362/87-10-01).
(2) Administrative Control The inspector noted the following concerns associated with the administrative controls implemented by the licensee in conjunction with the bypass of CPC channel C:
(a) The reactor trip signal provided by CPC channel C appears to have been a proper response of the channel to a valid rod misalignment indication. The licensee procedures in place at the time of this event do not appear to provide sufficient guidance to warrant bypassing of a safety function under these circumstance (b) The Control Room Supervisor bypassed the safety function without obtaining additional review or concurrence from the shift superintendent or other higher level of cognizant plant supervision. Considering the above noted weakness of plant procedures regarding bypass of this safety function, it appears that additional supervisory attention was.warrante The licensee agreed with the above concerns and committed to revise applicable procedures and reinforce these concerns with cognizant personne. Evaluation of Plant Trips and Events There were no plant trips or significant events during this inspection perio. Monthly Surveillance Activities a. Unit 1 (1) Dedicated Safe Shutdown System Operation Test, S01-10-7 The inspector observed the testing of the dedicated safe shutdown diesel generator and the dedicated auxiliary feedwater pump G-10-W. No deficiencies were note (2) Functional Test of the Safety Injection System, S01-12.9-10 The inspector observed the functional testing of safety injection system switchover from the main feedwater mode to the safety injection mode of operation (in particular, the opening of valves HV-851A and B under actual RCS operating conditions).
The automatic notification system to the California State Emergency Service Office was inadvertently returned to service after it was placed in test mode per the test procedur Consequently, the Emergency Service Office received the automatic notification upon actuation of the safety injection syste The licensee was unable to determine how the notification system was returned to service prior to the completion of the test. During this test, all systems appeared to have functioned properl (3) Steam Driven Auxiliary Feedwater Operability Test, S01-12.3-26 The surveillance was performed to demonstrate operability of the steam driven auxiliary feedwater-pump G-10 after it was returned from maintenance. Two significant deficiencies were observed - overspeed trip and failure of the steam bypass valve SV-3200 which is used for system warm-up before operatio The licensee attributed the overspeed trip problem to the water accumulation in the piping due to steam condensation during the maintenance. The licensee has experienced this problem on several occasions. The licensee blew down the piping of G-10 to clear any condensation and lowered the steam inlet pressure to allow smoother operation of the governor valv The licensee attributed the SV-3200 deficiency to binding of the valve and adopted an interim operating scheme of locking the valve open to allow the turbine to rotate at lower speed on the bypassed steam. The licensee evaluated and determined that there was no adverse effect to allow continued low speed
rotation of G-10 such as adequate lubrication and vibration due to the critical speed. Furthermore, instruments were added to continuously monitor the pump bearing temperature and vibratio The above temporary changes were reviewed by the licensee On-Site Review Committee. The surveillance test was then successfully conducted and repeated to demonstrate the operability and reliability of the system. The licensee plans to correct these deficiencies during the upcoming mid-cycle outag b. Unit 2 The inspector observed the following surveillances during this report period:
S023-XXV-Surveillance Requirement Containment Purge Isolation System Train A Loops ZZZZZZ 7804-1 and ZZZZZZ 7856-1 Channel Functional Test (31 Day Interval)
S023-3-Safety Injection Monthly Tests While reviewing procedure S023-XXV-4.6 to verify that all sign-offs were being made properly, the inspector observed that the signature verifications associated with calibration of the iodine monitoring channel (7804.A1) were not completed. Instead, the procedure was annotated at these steps to indicate that the iodine channel was being alternately controlled. The iodine channel was inoperable and was not being calibrated, but the maintenance order (#87041986000)
did not specify that the calibration procedure should be used in this manner. The inspector reviewed administrative procedure S0123-VI-1.0.3 titled, "Methods of Handling Invalid Steps/Sections,"
and verified that this method of dealing with procedures was allowed. In such instances, alternately controlled (A/C) may be annotated in the procedure if the intent of the procedure is not altered. Steps of the procedure that are A/C must be reviewed and approved by the Control Room Supervisor or Shift Superintenden c. Unit 3 The inspector observed the following surveillances on Unit 3 during this report period:
S023-3-3.29 Determination of Reactor Shutdown Margin S023-II-1.1.5 Reactor Plant Protection System Logic Matrix Functional Test (31 Day Interval)
As a follow-up to the recent Unit 3 refueling outage, the inspector also reviewed data from the startup testing program. The inspector reviewed data associated with power distribution limits, nuclear instrument calibration, thermal power evaluation, reactor shutdown
margin, temperature coefficient of reactivity, doppler coefficient of reactivity and rod worth. No anomalies or deficiencies were identifie. Monthly Maintenance Activities a. Electric Driven Feedwater Pump-Discharge Valve Test (Unit 1)
The inspector observed part of the activity under maintenance order MO 86031445000 to inspect and test the motor operated discharge valve S1-AFW-MOV-1202. Motor-operated valve analysis and testing (MOVATS) was conducted under this MO. The work appeared to have been properly performe b. North Saltwater Cooling Pump S1-SWC-G-13A Repair (Unit 1)
The inspector observed the maintenance activity under MO 8704286 to adjust pump shaft packing in order to reduce excessive leakage. No deficiencies were observe c. Component Cooling Water (CCW) Pump Outage (Unit 2)
The inspector observed portions of the maintenance outage on CCW pump 2PO24, to replace one of the pump bearings. Maintenance was performed in.accordance with procedure S023-I-8.148, "Pump-Goulds Model 3415 Bearing Replacement and Overhaul."
The inspector observed that a dial indicator was left on the pump casing which had a calibration expiration date of December 30, 1986. The number on the dial indicator was M1-3350. The inspector reviewed the maintenance order and verified that the dial indicator was not listed as the dial indicator used to verify run out measurement The licensee could not determine why the dial indicator was improperly located on the pump casing. Additional discussion regarding the control of measuring and test equipment (M&TE) is included in paragraph 9.b of this repor d. Saltwater Cooling (SWC) Pump Outage (Unit 2)
The licensee removed SWC pump 2P112 from service to do minor preventive and corrective maintenance. The inspector observed motor bearing oil replacement and verified that the proper oil was use This activity was conducted in accordance with procedure S023-1-8.12, "Lubrication of Electric Motor Bearings -
Motors Equipped with Fill Plugs and Sight Glasses."
e. Atmospheric Dump Valve (ADV) Maintenance (Unit 3)
The licensee recently experienced several failures of the atmospheric dump valve threaded rods which secure the valve body and bonnet/muffler assembly together. The inspector observed maintenance to replace the threaded rods on ADV 3HV-8421. In addition, a Belville washer was added to reduce the fatigue loading on the threaded rods. The threaded rods were failing due to fatigue
during recent actuations of the ADV's. Since the licensee does not have Technical Specification operability requirements associated with the ADV's, outage duration for each ADV was administratively limited to 7 days with only one valve out of service at a tim. Engineered Safety Feature Walkdown 1E DC Distribution and Vital AC Bus System (Unit 1)
The inspector verified the line up of the IE 125V.DC distribution and the vital 120 V AC bus. Minor housekeeping deficiencies observed were promptly corrected by the license.
Independent Inspection Pulsation Dampener Effects on Charging System Operability Several events have occurred at Palo Verde Nuclear Generating Station (PVNGS) which indicate a potential failure mode of the charging pumps due to leaking pulsation dampeners. On February 18, July 12, and July 18, 1986, PVNGS experienced charging pump failures due to gas bindin Nitrogen escaped from leaky pulsation dampeners, or nitrogen was charged directly into the system through a ruptured pulsation dampener and subsequently caused gas binding of the charging pump Since the San Onofre charging system is similar to PVNGS, the inspector requested the licensee to perform an engineering evaluation to address this failure mechanism. This is an open item (50-361/87-09-01).
8. Review of Licensee Event Reports a. Through direct observations, discussion with licensee personnel, or review of the records, the following Licensee Event Reports (LERs)
were closed:
Unit 1 86-009 Inadequate Establishment of Compensatory Fire Watch 87-004 Entry into Technical Specification 3. Unit 2 87-003 Fuel Handling Isolation System (FHIS) Spurious Actuations87-005 Containment Purge Isolation System (CPIS)
Spurious Actuation Unit 3 86-16 Fuel Handling Isolation System (FHIS) Spurious Actuations
87-02 Containment Purge Isolation System (CPIS)
Spurious Actuation b. The following LERs remain open pending additional licensee action to address the concerns noted below:
Unit 1 1-86-11 Failure of Main Feedwater Pump This LER addressed the failure of the impeller shaft on the Unit 1 west main feedwater pump. The LER describes extensive evaluations performed by the licensee to determine the cause of the shaft failure, concluding that the failure was the result of stress induced cracking caused by improper assembly of a thrust bearing nut. Licensee maintenance procedures were determined to be deficient relative to the manner in which this nut should be installed. Subsequent inspector discussions with the licensee determined that prior to the event, the pump manufacturer had provided the licensee with a bulletin which described proper procedures for installing this nut. The LER did not describe why these procedures did not get incorporated into applicable licensee procedures or corrective actions to ensure that similar problems do not recu Ground on Vital DC Bus This LER addressed an entry into technical specification 3.0.3 as the result of troubleshooting of a ground on DC bus 2. The LER identified that the cause of the ground was determined to be the result of moisture in a control circuit junction box for a solenoid valve which controls the rate of closure of feedwater isolation valve HV-854A. The LER did not address any action to determine the cause or correction of the moisture proble Trip on Loss of Generator Field This LER addressed a reactor trip resulting from a maintenance error that was complicated by numerous unrelated equipment malfunction The LER did not adequately address root cause or corrective action for several of these equipment malfunctions. For example:
Two control rod bottom lights failed to illuminate following the trip, requiring operators to perform an emergency plant boratio The licensee determined that the cause of the failure was the result of inadequate calibration of the rod bottom light indication circuitry. However, the LER did not identify any actions to ensure that future calibrations are performed properl Steam generator block valve MOV-21 failed to properly close when required. The licensee determined that the cause of valve malfunction involved misalignment of a packing gland follower, which resulted in valve stem binding during closure. The LER did not address any action to determine the cause of the misalignment or
address the adequacy of post maintenance testing to detect this type of deficienc Unit 2 2-86-27 Trip due to Failed CEA Indicator This LER addressed the failure of a reed switch position transmitter for CEA 34, which resulted in a reactor trip. The licensee concluded that the cause of the transmitter failure was the result of a loose solder joint. The LER stated that the deficiency was an isolated event and no corrective actions were considered necessar The licensee provided no description of the extent to which this maintenance deficiency was evaluated to substantiate the conclusion that it was an isolated case warranting no corrective.actio Trip During Power Supply Transfer This LER addressed a reactor plant trip that resulted from improper transfer of a turbine plant non-interruptible power suppl Following this trip, several plant components which were safety related or important to safety did not function properly. The licensee did not establish the cause of the malfunctions and the LER did not provide any basis for considering the malfunctions as isolated instances requiring no further corrective actions. The licensee revised this LER to resolve the above concerns; however, the revised LER is still considered inadequate. For example: the LER identified that the steam bypass control system malfunctioned during the event as the result of a failed integrated circuit. The licensee stated that an equipment history review indicated no previous failures; however, the LER did not describe any effort to determine the cause of the specific integrated circuit failure ( heat, moisture, improper assembly, etc.); the LER identified that plant protective system loss of load circuitry is believed to have malfunctioned as the result of hydraulic oil contamination, however, the LER did not address any action to pursue confirmation or correction of this proble Trip on Low Steam Generator Level This LER addressed a reactor trip involving malfunction of 2 of 4 low water level trip channels for steam generator E-089. The licensee identified that the cause of the malfunction involved a restriction in the instrument sensing lines. The LER states that the licensee backflushed the affected sensing lines, however, the LER did not address any action to evaluate or correct possible restriction in the non-affected steam generator level sensing lines prior to Unit 2 restart or for operating Unit Unit 3 3-87-04 Missed Steam Blowdown Sample
This LER addressed the inadvertent failure to take a required steam generator blowdown activity sample as the result of a misalignment of sample valves on the effluent radiation monitor. The LER identified the cause of the valve misalignment as an inadequate procedure, because the procedure did not include a specific verification signature step for notification of chemistry prior to isolation of the effluent monitor. Since the precautions and limitations section of the procedure clearly required chemistry notification, it does not appear appropriate to focus corrective action on procedure revision. The LER did not address the adequacy of operations supervision control of changes to plant condition Licensee procedures provide that the shift operations supervisor is responsible for understanding and implementing the precautions and limitations associated with any plant condition changes and it would appear that additional emphasis on the importance of procedure compliance by plant operators is warranted. In this regard, it is noted that previous events have revealed similar deficiencies in the proper control of plant condition changes (e.g. LER 2-86-29 and LER 2-85-58).
9. Follow-Up of Previously Identified Items a. (Closed).Open Item (50-206/86-37-01) Further Review of Licensee's Decision to Start up with RPS Subject to Single Failure Summary It was identified that the failure of a pressure transmitter (PT-459) in the density compensation circuit of the steam flow instrument could result in the failure of all three steam/feedwater flow mismatch trips in the RPS. The licensee's review identified that the high pressurizer level reactor trip at 70% would have tripped the plant for the design based accidents without taking credit for the steam/feedwater flow mismatch trip. However, the review also identified that the pressurizer would go solid and cause primary safety valves to lift and pass water instead of steam. The licensee took interim compensatory measures to eliminate dependency on steam/feedwater flow mismatch trip and reduced the setpoint of the high pressurizer level trip from 70% to 50%.
Status The licensee proposed an amendment to the Technical Specifications for the above change on November 2, 1986. The NRR staff reviewed and approved this proposal by Amendment No. 97 to the operating license. The licensee plans to modify this circuitry to correct this deficiency during a subsequent outage. This item is close (Closed) Unresolved Item (50-206/87-06-01), Source Range Channel Calibration During a previous inspection, the inspector reviewed documentation related to maintenance and calibration of source range nuclear
instrument channel N-1201. The documentation recorded in the "work done" section of maintenance order (MO) #87011045002 indicated that Instrument and Test Procedure 501-II-1.6.3 (TCN #1-2) titled,
"Source Range Channel N-1201 Calibration," had not been completed in its entirety, and that the procedure was in need of revisio During this report period, the inspector conducted a detailed review of this maintenance activity which included personnel interviews and review of the maintenance orders and procedures associated with this activit Sequence of Events Source range channel N-1201 neutron level meter was indicating 50 to 100 cps when the reactor was at 92% power and high voltage to the detector was turned off. MO 87011045000 was initiated on January 15, 1987, to correct this problem. The discriminator circuit was calibrated under this MO but did not correct the problem. MO 87011045001 was issued on January 16, 1987, to allow additional work to be done. Under this MO, the neutron level meter was replaced and a calibration of the source range channel was performed. Upon completion of the calibration, the neutron level meter was still counting 50 to 100 cps and MO 87011045002 was issued to do additional work. Under this MO, another calibration of the source range channel was performed. During the performance of this calibration, the technicians identified that paragraph 6.3.12 and 6.3.13 of procedure S01-11-1.6.3 (Rev. 1) could not be completed as written. Paragraph 6.3.12 was a calibration of the rod stop annunciator set point and paragraph 6.3.13 was a verification of this adjustmen These paragraphs could not be completed because the rod stop annunciator was disabled when circuit board J-205 was removed earlier in the procedure. TCN 1-2 was issued to the procedure to address this problem and the calibration was subsequently completed. Upon completion of this calibration, the neutron level meter appeared to be working properl Inspection Results In reviewing the maintenance orders and procedures used to control this maintenance activity and as a result of interview of I&C technicians, the inspector identified several areas of concer (1) Procedure Adequacy The licensee is required to establish, implement and maintain procedures for activities affecting quality. This requirement is specified by the following documents:
o 10 CFR 50, Appendix B, Criteria V and XII o
Paragraph 6.8.1 of the Unit 1 Technical Specifications (which references ANSI N18.7-1976 and Regulatory Guide 1.33)
Chapters 1C, 5A and 5C of the licensee's Topical Quality Assurance Manual (TQAM)
10 CFR 50, Appendix B, Criterion V, as implemented by Chapter IC of the TQAM requires the use of procedures for quality-affecting activities; and also requires that procedures include appropriate acceptance criteria. Contrary to this requirement, calibration procedure S01-II-1.6.3 did not include acceptance criteria for the data recorded by paragraphs 6.2.19 and 6.3.14 of the procedure (a desired reading or value was indicated, but allowed tolerance was not specified). These data were required as part of the calibration of the startup rate meters and neutron level meters associated with source range nuclear instrument channel NIS-1201. The licensee stated that a review of the Unit 1 maintenance procedures was recently completed, and the need to include acceptance criteria was recognized. As a result of this review, the licensee plans to include acceptance criteria prior to using the procedures for future application CFR 50, Appendix B, Criterion XII, as implemented by Chapter 5C of the TQAM, requires measuring and test equipment (M&TE)
used in quality-affecting activities to be controlled and calibrated. Contrary to this requirement, a ramp generator was called out by procedure S01-II-1.6.3 for use in calibrating the source range startup rate circuit, but the procedure did not identify the ramp generator as M&TE. As a result, the ramp generator was not calibrated and the output of the ramp generator was not monitored by calibrated M&T Startup rate indication from the source range channel is used by the control operators during reactor startup evolutions. Procedure SO1-II-1.6.6, titled "Intermediate Range Channel N-1204 Calibration," also called out the use of this ramp generator in a similar fashion. In addition to providing startup rate indication, the intermediate range channel also provides a reactor trip function at 5 DPM startup rate. The licensee has checked the output from the ramp generator with calibrated M&TE and has verified that the ramp generator output was in tolerance. The licensee stated that the vendor's technical manual only required a regulated voltage to be supplied to the ramp generator and did not require the output of the ramp generator to be monitored. Since the ramp generator consists of a synchronous motor turning a potentiometer, the licensee believes that monitoring the input voltage to the potentiometer is all that is necessary to ensure proper output. In addition, the licensee believed that the check that is done using the internal rate test circuit in the source range drawer would provide sufficient verification that the ramp generator was functioning properly. The inspector questioned the licensee's contention that the check performed using the source range channel internal rate test circuit provides verification that the ramp generator is working properly, since the licensee only performed a one point calibration check using the test circuit
and operability over the entire range of indication was not evaluate Based on the inspector's observations, it appears that the licensee has not satisfied the regulatory requirements as they relate to procedural adequacy. This is an apparent violation (50-206/87-10-01).
In addition to above noted specific examples of procedure inadequacy, the inspector addressed several general concerns associated with the direction in which the licensee appears to be headed relative to the amount of detail that is included in corrective maintenance orders (MOs), especially for MOs involving instrumentation and control (I&C) equipment. The licensee confirmed the inspector's.observation that many of the more recent I&C MOs are boiler plate "trouble shoot, repair and test" type MOs, with little, if any, procedural guidance (which had been typical of earlier MOs). The licensee indicated that an increasing volume of MOs dictates this more flexible approach to MO preparation and he emphasized his belief that this approach is within the scope of current regulatory requirements. The inspector stated that although this may be the case, the current requirements of the licensee quality assurance program appear to be more restrictive than that being implemented with the current MO format. In this regard, the inspector discussed the following specific observations with the licensee:
C Maintenance Orders 87011045000, 87011045001 and 87011045002 included a generic note which allowed steps of the work plan to be completed out of sequence, without regard as to the applicability of the generic note to the specific work plan step o Maintenance Orders 87011045000, 87011045001 and 87011045002 included a generic step which stated,
"Inspect, test rework..." with very little additional guidance given. Although Regulatory Guide 1.33 states that "skills normally possessed by qualified maintenance personnel may not require detailed step-by-step delineation in a procedure," this should not be interpreted to mean that a procedure is not required. As specified by Chapter 5A of the licensee's TQAM, certain elements such as prerequisites, precautions, limitations and acceptance criteria should be included as appropriate in each maintenance order. In addition, the main body of the maintenance order should include that amount of detail which is commensurate with the skill of the craft doing the wor o Maintenance Orders 87011045000, 87011045001 and 87011045002 gave direction to do rework before troubleshooting was completed, and before the scope of work and retest requirements could be define o Maintenance Orders 87011045000 and 87011045002 allowed the I&C technician and his foreman to determine if retest was necessary following rewor The inspector requested that the licensee specifically address the above concern in his response to the notice of violation on procedure adequac (2) Procedure Compliance As noted above, the Federal Code, Unit Technical Specification and the licensee's TQAM require the use of procedures for accomplishing quality affecting activitie The licensee has implemented this-requirement for maintenance activities in procedure 50123-1-1.1, "Organization and Responsibilities of the Maintenance Section."
This procedure requires activities to be accomplished in verbatim compliance with approved procedures (paragraph 6.2.3.5), and requires procedures to be revised if additional actions are required (other than minor corrective maintenance) beyond those allowed by written work procedures (paragraph 6.2.3.5.3). Maintenance Procedure S0123-I-1.7, "Maintenance Order Preparation, Use and Scheduling," requires work to be done in verbatim compliance with approved procedures and documented instructions contained in the work packages (paragraphs 6.12.11 and 6.12.12).
Administrative Procedure S0123-VI-1.0.3, "Methods of Handling Invalid Steps/Sections," states that "N/A" shall not be used to indicate invalid procedural steps unless specifically allowed by the maintenance or surveillance procedure being used (paragraph 6.1.2). For the case where a portion of a maintenance or surveillance procedure is not applicable due to special circumstances or conditions, the procedure must be corrected by a temporary change notice (TCN) or the work plan section of the maintenance order must specify how the procedure should be used (paragraph 6.2).
(a) As part of the maintenance activity that was conducted on January 17, 1987 on source range channel N-1201, step 5 of MO 87011045001 required a calibration to be performed in accordance with Instrument and Test Procedure S01-II-1. o Section 6.3 of the procedure performed calibration of the rate amplifier, and steps 6.3.10 through 6.3.13 stated the following requirements:
6.3.10 Adjust the power supply voltage to the ramp generator to 0.505 (0.504 to 0.506) VD.3.11 Place the ramp generator controls in the UP and ON position.3.12 S.U.R. meter should indicate 2.0 DPM. Adjust R203 on chassis so that the "Rod Stop" annunciator initiates at (1.8 to 2.2) DP.3.13 Verify that the reactor plant N annunciator window No. 51 annunciates at 2.0 DP Although steps 6.3.12 and 6.3.13 were signed off, it was discovered on January 20, 1987 while working under MO 87011045002 that the rod stop annunciator could not be tested as the procedure required while the unit was operating at power. During a previous step (6.3.2), circuit board J-205 was removed from the source range drawer to defeat the high voltage cut-off from the intermediate range channe The rod stop annunciator relay is located on circuit board J-205 and, with the circuit board removed, the rod stop annunciator can not be checked. Contrary to the requirements, steps 6.3.12 and 6.3.13 of the procedure were not properly adhered to and the procedural deficiency was not discovered until a subsequent calibration of the source range channe The licensee stated that the procedural noncompliance was the result of inattention to detail rather than willful disregard on the part of the technician Steps 6.5.7 and 6.5.8 of the procedure S01-II-1. stated the following requirements:
6. Calibrate NYV 2201 per 501-II-1.51 6. Calibrate NYI 2201 per S01-II-1.53 Contrary to the requirements, these steps were marked
"N/A" by direction from the I&C foreman because the foreman didn't believe that these instruments (Foxboro EMF Converters) were affected by the maintenance activity on source range channel N-120 The licensee stated that, although the Foxboro converter calibrations were not required, the foreman failed to comply with the administrative requirements for use of procedures. The licensee committed to provide an explanation of why the Foxboro Converters did not require calibration as a result of the maintenance activit Steps 6.1.15 and section 6.2 of procedure SO1-II-1.6.3 specified the use of a pulse counter during calibration of the discriminator circuit and pulse log integrator on source range channel N-120 Contrary to the requirements, a pulse counter was not used during the calibration that was performed under MO 87011045001. The technician stated that the oscilloscope (also required by the procedure) was used in place of the pulse counte (b) Maintenance Procedure 50123-1-1.7, titled "Maintenance Order Preparation, Use and Scheduling," requires that measuring and test equipment (M&TE) used during maintenance activities be.recorded on applicable MO's (paragraphs 6.12.7 and 6.12.19.5). Instrument and Test Procedure S0123-II-1.0 titled, "Calibration and Control of Measuring and Test Equipment," states the following definition for M&TE (paragraph 6.1.1):
"M&TE includes all devices or systems used to calibrate, measure, gauge, test, inspect, or control in order to acquire research, development, test or operational data specifications. M&TE does not include:
Permanently installed plant instrumentation Equipment used for preliminary checks where data obtained will not be used to determine acceptability or.verify conformance to established criteria Items for which normal commercial practices provide adequate accuracy, such as rulers, tape measures, levels, and feeler gauges Dosimetry devices, radiation survey instruments, and associated Health Physics equipment."
Step 6 of MO 87011045000 specified calibration of the source range channel N-1201 discriminator circuit in accordance with step 6.1.15 of procedure S01-II-1.6.3, which stated:
6.1.15 Connect the pulse generator, pulse counter and oscilloscope to input connector J20.1 Set the pulse generator for a positive pulse with an amplitude of 1.0 volt P-P and a pulse width of 0.2 use.2 Set the pulse generator for a frequency output of 1x103 PP.3 Transfer the oscilloscope from the pulse generator to collector-of transistor Q204 (junction of R229 and C206) under chassi.4 Observing the oscilloscope, adjust R-229 for a peak outpu The procedure also identified the pulse generator, pulse counter and oscilloscope as M&TE (paragraph 3.2).
Contrary to the requirements, the technician did not record this equipment.on the MO. The technician felt it was not necessary to record the M&TE used because additional work and final calibration of source range channel N-1201 were planne Based on the inspector's observations, it appears that the licensee has not complied with the regulatory requirements as they relate to procedural compliance. This is an apparent violation (50-206/87-10-02). (Closed) Unresolved Item (50-361/82-30-08), Five-Finger CEA Movement with Polar Crane This item was unresolved pending review of CEA movement inside the core. It was not clear if rod movement inside the core should be allowed during the refueling outage prior to going into Mode Paragraph 3.9.1 of the Technical Specifications for Units 2 and 3, dated November 15, 1982, requires the reactor to be maintained in Mode 6 whenever fuel is in the reactor and the reactor vessel head closure bolts are not fully tensioned. For other modes of operation, paragraphs 3.1.1.1, 3.1.1.2, 3.1.2.1, 3.1.3.5 and 3.1. of the Units 2 and 3 Technical Specifications are applicable'to control rod configuration. The movement of control rods appears to be well addressed by the Technical Specifications for Units 2 and This item is close (Closed) Open Item (50-361/86-08-02), M&TE Authorized User's List Additional followup action associated with the licensee's program for control and use of M&TE will be done as discussed in paragraph 9(e) of this report. This item is close (Open) Open Item (50-361/86-19-03), Use of Uncalibrated Instruments The inspector observed additional examples of poor control of M&TE which indicated the need for program enhancement. These additional examples are discussed in paragraph 9(b) of this report. The inspector questioned whether the licensee's program effectively addresses the use and control of M&TE such that the craft understand and comply with the station policies, only authorized users have access to the equipment, and M&TE is turned in for calibration as required. This item remains ope (Open) Unresolved Item (50-361/86-34-03), Fire Boundary Isolation Currently, there are two aspects of this issue that remain unresolve (1) Administrative Control of Fire Door Installation -
The licensee has changed procedure S0123-XIII-24 to provide instructions for issuing separate FBRRR's for each impairment associated with fire barrier work. The licensee has also provided instructions to include Technical specification fire doors in surveillance procedure S0123-XIII-50 prior to closing the applicable FBRRR's for new installations. The licensee stated that the programmatic problem had already been corrected before this issue was identified by the NRC inspector, when the requirements for closing the FBRRR were changed to require the QC inspector to use a copy of the FBRRR to do the close out inspection. Previously, the QC inspector just used a computer generated form to inspect against. The licensee believes that this particular example was an isolated case due to personnel error because the QC inspector failed to recognize that the FBRRR's were still required to control the fire doors. It does not appear to the NRC inspector that this was an isolated case due strictly to the error of one individua Three QC inspectors were involved in closing out the FBRRR's associated with these fire doors, and none of them recognized the need to maintain control of the fire doors. Even if the fire doors had been operable at the time of the QC inspection, there was no requirement to ensure that the fire doors were added to surveillance procedure S0123-XIII-50.prior to FBRRR close ou A.programmatic deficiency did exist, and this deficiency was corrected by the licensee's recent revisions to procedure S0123-XIII-24, previously discusse (2) Installation of Coordinating Devices - The licensee's TQAM requires design changes in the area of fire protection to comply with "appropriate codes, quality standards and regulatory requirements..."
NFPA-80, Section 3, requires the use of coordinating devices for double doors that have a latch bolt or astragal that could keep the doors from closing full The licensee stated that he is currently requesting an interpretation of this code requirement. The inspector requested the licensee to provide the basis for excluding the requirements of NFPA-80 prior to requesting the code interpretatio Currently, the licensee's proposed revision to the fire protection program is being reviewed by NRR. As part of this review, the fire doors in question will be evaluated to determine if they are required for Technical Specification fire barriers. This item remains unresolved pending additional revie.
Exit Meeting On May 22, 1987, an exit meeting was conducted with the licensee representatives identified in Paragraph 1. The inspectors summarized the inspection scope and findings as described in this report.