ML20234E778
| ML20234E778 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 06/30/1987 |
| From: | Butcher R, Dance H, Will Smith NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20234E765 | List: |
| References | |
| 50-416-87-14, NUDOCS 8707070680 | |
| Download: ML20234E778 (12) | |
See also: IR 05000416/1987014
Text
{{#Wiki_filter:UMITED SVATES [pm Riog 'e,^ . NUCLEAR REGULATORY COMMISSION
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REGION H I
0 ' 101 MARIETTA STREET, N.W. {{ - E ATLANTA, GEORGI A 30323 %w ]
, l Report No.: 50-416/87-14 Licensee: System Energy Resources, Inc. Jackson, MS 39205 Docket No.: 50-416 License No.. NPF-29
s Facility Name: Grand Gulf Nuclear Station Inspection Conducted: May 16 through June 19, 1987 [/l M / 3# I7 Inspect s: f+ R. C. Butcher, Senior Resident Inspector Date Signed I y C d > 30lU b- W.'F. Smith, Resident Inspector Date Signed j Approved by: b d** - b d//7 I H. C. Dance,'Section Chief D4te S'igned Division of Reactor Projects SUMMARY Scope: This routine inspection was conducted by the resident inspectors at the site in the areas 3of Licensee Action on Previous Enforcement Matters, Operational Safety Verification, Maintenance Observation, Surveillance Obser- vation, ESF System Walkdown, Reportable Occurrences, Operating Resctor Events, and Inspector Followup and Unresolved Items. Results: One violation was identified: Failure to provide an adequate procedure for surveillance testing of the Standby Liquid Control System. l l l I i I l . 8707070680 B{go 416 ADOCK O PDR j PDR G j i I
r - , . '! REPORT DETAILS ' 1. Licensee Employees Contacted
- J. E. Cross, GGNS Site Director
- C. R. Hutchinson, GGNS General Manager
R. F. Rogers, Manager, Unit 1 Projects
- A. S. McCurdy, Manager, Plant Operations
- J. D. Bailey, Compliance Coordinator
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- M. J. Wright, Manager, Plant Support
- L. F. Daughtery, Compliance Superintendent
D. G. Cupstid, Start-up Supervisor R. H. McAnulty, Electrical Superintendent J. P. Dimmette, Manager, Plant Maintenance W. P. Harris, Compliance Coordinator
- J. L. Robertson, Licensing Superintendent
L. G. Temple, I&C Superintendent J. H. Mueller, Mechanical Superintendent L. B. Moulder, Operations Superintendent' ! J. V. Parrish, Chemistry / Radiation Control Superintendent
- S.
M. Feith, Director, QA
- R. V. Moomaw, Technical Assistant to Manager, Maintenance
- R. T. Halbach, Administrative Assistant to General Manager
- S. F. Tanner, Manager, Nuclear Site QA
Other licensee employees contacted included technicians, o'perators, security force members, and office personnel.
- Attended exit interview
~ 2. Exit Interview (30703) j The inspection scope and findings were summarized on June 19, 1987, with those persons indicated in paragraph 1 above. The licensee did not 1 identify as proprietary any of the materials provided to or reviewed by the inspectors during this inspection. The licensee had no comment on the following inspection findings: 416/87-14-01, Inspector Followup Item: Correction of deficiencies found during the Standby Gas Treatment System walkdown inspection (paragraph 7). 416/87-14-02, Inspector Followup Item: Inspection and/or replacement of General Electric HFA relays in safety related systems (paragraph 9). i 416/87-14-03, Violation: Failure to provide and implement an adequate procedure for the surveillance testing of the Standby Liquid Control System (paragraph 10). l i i i u
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. 2 1 3. Licensee Action on Previous Enforcement Matters (92702) (Closed) Violation 416/87-10-04. Failure to identify and document a condition adverse to quality in accordance with Administrative Procedure 01-S-03-2, Quality Deficiency Reports. The primary cause of this . viola- tion was failure of Quality Assurance (QA) personnel to recognize that a deficiency existed when an improperly assembled relief valve in the Standby Liquid Control System began to leak profusely when pump suction head was applied downstream of the relief. The inspectors verified documentation of corrective actions taken, i.e., to train all QA inspec- tion and audit personnel, and to ensure all GGNS employees are aware of their responsibility to document any nonconformance at the time it is , identified. The actions taken appear to be adequate. No further action I is required. 4. Operational Safety Verification (71707, 71709 and 71881) The inspectors kept themselves informed on a daily basis of the overall plant status and any significant safety matters related to plant opera- tions. Daily discussions were held with plant management and various members of the plant operating staff. The inspectors made frequent visits to the control room such that it was visited at least daily when an inspector was on site. Observations included instrument readings, setpoints and recordings, status of operating systems,, tags and clearances on equipment controls and switches, annunciator alarms, adherence to limiting conditions for operation, temporary alterations in effect, daily journals and data sheet entries, control room manning, and access controls. This inspection activity included numerous informal discussions with operators and their supervisors. Weekly, when the inspectors were onsite, selected Engineered Safety Feature (ESF) systems were confirmed operable. The confirmation is made by verifying the following: Accessible valve flow path alignment, power supply breaker and fuse status, major component leakage, lubrication, cooling and general condition, and instrumentation. General plant tours were conducted on at least a biweekly basis. Portions of the control building, turbine building, auxiliary building and outside areas were visited. Observations included safety related tagout verifica- tions, shift turnover, sampling program, housekeeping and general plant conditions, fire protection equipment, control of activities in progress, problem identification systems, and containment isolation. At least monthly, the licensee's onsite emergency response facilities were toured to determine facility readiness. Monthly, the inspectors reviewed at least one Radiation Work Permit (RWP), observed health physics management involvement and awareness of significant plant activities, and observed plant radiation controls. At least quarterly the inspectors reviewed the licensee's program to limit personnel radiation )
r . . 3 exposure As Low As Reasonably Achievable (ALARA). Monthly, the inspectors verified licensee compliance with physical security manning and access control requirements. At least quarterly the inspectors verified the adequacy of physical security detection and assessment aids. The following comments were noted: Piping and Instrument Drawing (P&ID) M-1083A, Reactor Core Isolation Cooling (RCIC) System, identifies the RCIC injection shutoff valve as E51F013A. It should be E51F013-A. The RCIC pump suction from the suppression pool valve is identified as E51F031A. It should be E51F031-A. P&ID M-1100A, Containment Cooling System, zone G2 shows an air operated butterfly valve upstream of valve M41F037, with no identifying number, nor is the position specified. Correction of these deficiencies shall be tracked under Inspector Followup Item 416/87-14-01 which is discussed in paragraph 7 of this report under ! other P&ID deficiencies. No violations or deviations were identified. 5. Maintenance Observation (62703) During the report period, the inspectors observed portions of the main- l tenance activities listed below. The observations included a review l of the Maintenance Work Orders (MW0s) and other related documents for j ' adequacy, adherence to procedure, proper tagouts, adherence to technical specifications, radiological controls, observation of all .or part of the actual work and/or retesting in progress, specified retest requirements, and adherence to the appropriate quality controls. ! MWO 171307, Recirculation valve runback relay card rework (Incident Report 87-3-7). . MWO 172538, Investigation of increasing level indication on Reactor vessel level instruments supplied by condensing pot D004A. MWO M72688, Chemical cleaning of ESF switchgear room cooler T46-B002A. ! MWO ME1495, Periodic inspection of containment personnel airlock at the 119 foot elevation accordance with Maintenance Procedure 07-S-14-264, Revision 1. MWO 172880, Investigate cause of Division 3 diesel generator tachometer - failure. , MWO M72879, Damping of Standby Liquid Control System pressure gauge 1C41-R003. No violations or deviations were identified. , i , - -_.-- __ _ ___.___ _
e ~ q < l . 4 1 6. Surveillance Observation (61726) The inspectors observed the performance of portions of the surveillance listed below. The observation included a review of the procedure for technical adequacy, conformance to technical specifications, verification of test instrument calibration, observation of all or part of the actual surveillance, removal from service and return to service of the system or components affected, and review of the data for acceptability based upon the acceptance criteria. 06-RE-1J11-V-0001, Revision 30, Power Distribution Limits Verification. 06-IC-1821-M-1004, Revision 24, Reactor Vessel Water Level (PCIS) Level 2 and 1 Functional Test. 06-RE-1C51-0-0001, Revision 25, Local Power Range Monitor (LPRM) Calibra- tion (APRM Channels A,E,C and G). During performance of the calibration, the inspector noted that step 5.4.12 of the procedure required adjustment of the appropriate LPRM gain control to achieve 8.000 DC volts on the i digital volt meter, and no tolerance was specified. Licensee personnel j conducting the test accepted from 7.990 to 8.010, which was not allowed by 1 the procedure. The Reactor Engineer at the scene explained that plus or d minus 10 millivolts was acceptable, and that he would initiate a change to the procedure to provide for the tolerance. The inspectors have witnessed other surveillance where a similar circumstance existed and the technicians spent inordinate amounts of time adjusting potentiometers to exact values when a reasonable tolerance would have achieved satisfactory results and perhaps reduce the time safety related equipment is bypassed out of service for calibration. The licensee is in the process of correcting procedures to facilitate verbatim compliance, and the problem above is i typical to many procedures. The inspectors will continue to monitor surveillance. 06-0P-1C41-M-0001, Revision 26, Standby Liquid Control System (SLCS) ) Operability. See paragraph 10, Inspector Followup Item 416/87-10-05 l for comments. No violations or deviations were identified. 7. Engineered Safety Features System Walkdown (71710) A complete walkdown was conducted on the accessible portions of the Standby Gas Treatment System (SGTS). The walkdown consisted of an inspection and verification, where possible, of the required system valve , alignment, including valve power available and valve locking where required, ' instrumentation valved in and functioning; electrical and instrumentation I cabinets free from debris, loose materials, jumpers, evidence of rodents, ' and system free from other degrading conditions. The system was found to be in a satisfactory condition and appeared ready to perform its safety l function if called upon. The inspectors noted several minor discrepancies as discussed below: l - _ _ _ _ _ - _ _ _ _ . _
. 5 a. Treatment System UnitPiping and Instrument D a 1, grams (P& ids) M-1102A & B accurately represent contain example the as-built several errors , Standby Gas dampers,T48-F015 and F016M-11028 shows the south condition and thus do ducts to the north stai of the connected to 6 inch ductsstairwell registe For not 166 foot elevation.rwell, corridors, and ele and isolation shows the SGTSdirectly to the 16 inch The , in parallel with south stairwell duct is a vator duct shaft at the reducingactually located at 139 fA equipment room on adjacent stairwell.ctually connected to the 119 foot elevation wheelev located on the 139 footfitting on the eet. M-11028 shows M-11028 fans an 8 inch to 14 inch is and dampers T48-F021 and F02 elevation. they are 2 in theM-1102A shows the rec n it is actually located on the 208 f building. actually oot elevation of the auxilienclo u ating b. SGTS filter train diffe identified as to functioand R003B are not labeledren a ry as to instrument number s PDI-R002A, R002B, S n c. n, The eight inch ducts in t However, they are , auxiliary building elevatis alled to draw down the f upstream of water operated dampers T48-F019on 208 feet have ma are not labeled, and are are they controlled by th and F020ampers installed the position of not identified on the ap liThe dampers The li the dampers. 501. shut. e The inspector p cable P&ID nor was promptly notifiedThey appeared to be full verified open.censee could not determine fuel handl If they were operation. ing area y op as designed during anshut, the SGTS would not dthe so that The the rest ofinstalled for the purp licensee could be explained not normally shownthe auxiliary buildinnf balancing that the ose manual damper procedural controls toon the P&ID. g and n wa s The licensee committedthat balancing dam position when verifying ensure the dampers s are d. operability of Motor are in the to implement F025A and F026B respectioperated butterfly valve the system. as-balanced as F025-A and F026-B s T48-F025 and F026 are l b vely versus power and on the P&ID they are id . This ,s Inspection Report i supply labeling problem whi h another example a eled T48- in paragraph 4 of this 416/86 4- 1. of the entified c Another similar problemwas discussed in previous Correction report. of the Followup Item 416/87-14 0above deficiencies was identified graph 4 will be tracked with The P&ID shall -1 No violations or deviati this item. deficienciesbe tracked under Inspect identified in para r o ons were identified.
. . 5 , i a. Piping and Instrument Diagrams (P& ids) M-1102A & B, Standby Gas Q Treatment System Unit 1, contain several errors .and thus do not I accurately represent 'the as-built condition of the system. For i example, M--1102B shows the south stairwell registers and isolation dampers T48-F015 and F016 connected to 6 inch ducts, in parallel with ducts to the north stairwell, corridors, and elevator shaft at the 166 foot elevation. The south stairwell duct is actually connected directly to the 16 inch duct adjacent to the stairwell. M-11028 ) shows the SGTS A equipment room on elevation 119 feet when it is ' actually located at 139 feet. M-1102B shows an 8 inch to 14 inch reducing fitting on the 119 foot elevation when it is actually located on the 139 foot elevation. M-1102A shaws the recirculating fans and dampers T48-F021 and F022 in the enclosure building when they are actually located on the 208 foot elevation of the auxiliary building. b. SGTS filter train differential pressure instruments PDI-R002A, R002B, and R003B are not labeled as to instrument number. However, they are identified as to function. j c. The eight inch ducts installed to draw down the fuel handling area of auxiliary building elevation 208 feet have manual dampers installed upstream of water operated dampers T48-F019 and F020. The dampers are not labeled, and are not identified on the applicable P&lD nor are they controlled by the 501. The inspector could not determine the position of the dampers. They appeared to be fully open or fully shut. The licensee was promptly notified so that they ' could be verified open. If they were shut, the SGTS would not draw down the fuel handling area as designed during an event calling for SGTS operation. The licensee explained that the manual damper -was installed for the purpose of balancing the fuel handling area with the rest of the auxiliary building and that balancing dampers are not normally shown on the P&ID. The licensee committed to implement procedural controls to ensure the dampers are in the as-balanced position when verifying operability of the system. d. Motor operated butterfly valves T48-F025 and F026 are labeled T48- F025A and F026B respectively, and on the p&ID they are identified as F025-A and F026-B. This is another example of the safety train versus power supply labeling problem which was discussed in previous Inspection Report 416/86-41. Another similar problem was identified in paragraph 4 of this report. Correction of the above deficiencies shall be tracked under Inspector Followup Item 416/87-14-01. The p&ID deficiencies identified in para- graph 4 will be tracked with this item. No violations or deviations were identified. _ _ _ _ _ _ _
. . 6 8. Reportable Occurrences (90712 & 92700) The below listed event reports were reviewed to determine if the informa- tion provided met the NRC reporting requirements. The determination included adequacy of event description and corrective action taken or planned, existence of potential generic problems and the relative safety significance of each event. Additional inplant reviews and discussions with plant personnel as appropriate were conducted for the reports indicated by an asterisk. The event reports were reviewed using the guidance of the general policy and procedure for NRC enforcement actions, regarding licensee identified violations. The following License Event Reports (LERs) are closed. LER No. Event Date Event
- 86-019
December 15, 1984 Fire rated penetrations not properly sealed.
- 86-038
October 22, 1986 Secondary containment isolation during surveillance testing.
- 87-006
May 1, 1987 Inadvertent Reactor Core Isolation Cooling System isolation due to personnel error.
- 87-007
May 1, 1987 Inservice testing of Standby Liquid Control (SLC) System check valves inadequate due to procedural error. No violations or deviations were icantified. 9. Operating Reactor Events (93702) The inspectors reviewed activities associated with the below listed reactor events. The review included determination of cause, safety significance, performance of personnel and systems, and corrective action. The inspectors examined instrument recordings, computer printouts, opera- tions journal entries, scram reports and had discussions with operations, maintenance and engineering support personnel as appropriate. At 2:20 p.m., on May 27, 1987, an inadvertent downshift of both recircu- lation pumps to the Low Frequency Motor Generator (LFMG) power supply occurred. The plant was operating at approximately 100% thermal puwer and 97% core flow. After the downshift the operators stabilized the plant at approximately 42% thermal power and 35% core flow. Technicians were working MWO 171307 which affects only the recirculation control valve runback circuitry. Although recirculation pump ant 1-cav1tation circuitry (which could cause a recirculation pump downshift) is located in the same panel as the recirculation valve runback circuitry, and did alarm during the event, nothing indicated what actually caused the event. The licensee _ _ - _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ - _ _
i l . 7 investigated to determine the cause of the pump downshift but nothing l specific was identified. After troubleshooting and verifying operability ( of the circuitry, the plant was taken back up to 100% thermal power. The I flow control valves and recirculation pumps functioned as designed. The inspectors reviewed the licensee's administrative controls to deter- ) mine compliance to Technical Specification (TS) 6.2.3, Independent Safety i Engineering Group (ISEG) requirements. Nuclear Plant Engineering (NPE) procedure 01-701, Onsite and Offsite Document Review, directs documenta- tion of evaluations performed by the Operational Analysis Section (OAS) acting as the ISEG referred to in TSs. The offsite and onsite documents subject to review are listed and the review process is defined. Also, the criteria for evaluation and analysis is defined. In report 0A 86-011, Assessment of the ISEG Function at G3NS, dated July 21, 1986, the licensee examined the requirements for the ISEG in NUREG-0737, Item I.B.1.2, and in the TSs. The report concluded that MP&L (now SERI) was satisfying all the requirements but certain improvements should be made. The inspectors concur with the conclusions and recommendations in the report. Although the recommendations have not been implemented at this time, the licensee stated they intend to implement the recommendations as manpower and budget constraints permit. The OAS submits a monthly summary of plant operating experience to management (Vice President, Nuclear Engineering and Support, and Vice President, Nuclear Operations). The inspectors reviewed report 1 0A-87-011 which covered operational events for the period of April 1,1987 l through April 30, 1987. Included as an attachment was report 0A-87-010, l l ISEG Review of the SSW and HPCS Systems, i In paragraph 9 of NRC Inspection Report 416/87-12, the inspectors reported , a problem the licensee was having with the reactor vessel water level l instruments. On May 11, 1987, the licensee told the inspectors that a l channel check revealed a 4 inch level differential between certain reactor vessel water level instruments. This was the licensee's limit for i initiating an investigation. The condition was corrected by refilling ! the A reactor vessel water level reference leg. Within a few days the condition reappeared. Troubleshooting was conducted by isolating the various detectors on the A reference leg and walking down the system to find leaks. Two minor packing leaks were found, one of which was on the A reference leg. The leakage was stopped by backseating the valves. The various detectors were isolated to determine if detector or equalizer valve leakage existed which would cause reference leg draining in excess of the makeup provided by the condensing pot. There was no indication of such leakage. The 1.censee is currently monitoring the levels for any changes. One theory is that non-condensable gas may have collected in the condensing pot thus reducing the effective condensing surface area. The licensee is exploring other possibilities with the assistance of General Electric. The resident inspectors will conduct routine followups and report any further developments. On May 20, 1987, while working on a Design Change Package (DCP) to upgrade some non-safety related Bailey Model 711 Recorders, Nuclear Plant Engineering (NPE) personnel discovered that the field mounting configura- tion of certain Bailey Model 711 Recorders was not consistent with the _ _ _ _ - - -
- _ _ _ _ _ _ - _ - _ , . 8 seismic qualification test configuration. Systems affected were Reactor Vessel, Area Radiation Monitoring, Residual Heat Removal, Suppression Pool Makeup, Combustible Gas Control, Containment and Drywell Instruments, Standby Service Water, Standby Gas Treatment System, and Control Room l HVAC. Most of the recorders are mounted in the Control Room. The test configuration differed from the installed configuration at GGNS in that a supplemental restraining device was installed during the test to prevent the recorders from drifting out of the shelf mounting assembly. Although- the restraining device was not installed at GGNS, the' licensee determined by analysis that the device would not be needed because the qualification test was conducted at excitation levels significantly higher than the GGNS design basis Safe Shutdown Earthquake (SSE). The test ranged between 10 and 15 gravities compared with the GGNS required level of 2 gravities. , Thus NPE concluded that the as-mounted recorders would remain functional ! following a seismic event. General Electric agreed with this determination. The licensee also sent the same recorders to Wyle Laboratories to confirm the qualification to GGNS requirements. The results were satisfactory, i The generic implications of this issue are being reviewed by the licensee i pursuant to 10 CFR 21. l At 12:10 p.m., on May 29, 1987, a momentary loss of voltage was experienced on the 115 kV Port Gibscn power feed. At the time, the Division 3 (High Pressure Core Spray) ESF bus was being fed by transformer 12 which in turn was connected to the 115 kV feeder. The momentary loss was sensed by the Division 3 ESF bus resulting in an automatic start of the Division 3 Diesel Generator (DG). The DG started satisfactorily and all associated equipment functioned properly. One of the inspectors was in the control q room at the time and witnessed the event. Orerator actions appeared- 1 appropriate and procedures were referred to and followed. The NRC d Operations Center was notified at 2:07 p.m., in accordance with 10 CFR 50.72. On May 29, 1987, the A train Standby Service Water (SSW) pump inadvertently , started with no apparent automatic initiation signal present. The reactor ! was at 83% thermal power. Plant operation was not affected. Technicians ) were working Maintenance Work Order E72626 to troubleshoot and correct a l problem where the SSW A pump and the Residual Heat Removal (RHR) A pump ! room fan coil unit would not shut down after running and then securing the ] RHR A pump. The technicians found the linkage for auxiliary switch AG in the RHR A pump control breaker disconnected. This prevented the SSW A - pump and RHR A pump room fan coil unit from turning off when RHR A was secured. The technicians replaced the linkage and when the RHR A pump l control breaker was racked back in the SSW A pump inadvertently started. ! The technicians then adjusted the linkage, checked the auxiliary switch j . contacts, and restored the system to normal operation.
On June 2,1987, the Region I Morning Report stated that Boston Edison i Company (Pilgrim Plant) has deterinined that a significant percentage of General Electric (GE) type HFA auxiliary relays installed in safety related applications at Pilgrim are susceptible to mechanical binding of the armature. The report referred to a GE Service Advice Letter (SAL) -__ _
_ , k 1 . 9 1 188.1 which identified this potential problem on November 14, 1986. The inspectors followed up to see if SERI had knowledge of the SAL and if actions had been (or were being) taken to determine if the problem exists at GGNS, and if so, what was done to eliminate the problem. The licensee did have the SAL and had determined that in the two failure cases reported, the applications called for AC powered, continuously energized HFA relays. Their investigation revealed eight similar applications at GGNS, and all are in the Reactor Protection System in the turbine control valve fast closure and turbine stop valve closure circuits. The licensee ' is p,reparing MW0s to perform the prescribed relay tests. Due to the
sensitivity of the system applications and thus the potential for an inadvertent reactor trip, the work orders were scheduled for the next . shutdown. The inspectors will follow up and report the results of the ' relay tests and any corrective actions taken. This shall be Inspector Followup Item 416/87-14-02. On June 14,1987 the 0400 to 0500 hourly fire watch patrol failed to meet the requirement of TS 3.7.7.a action statement on each 'of five auxiliary ) building fire doors, in that the hourly patrol was performed from one to l five minutes late. The apparent cause was failure of one individual to attend to his responsibilities in a timely manner. The licensee identified the incident on Incident Report 87-6-1, dated June 15, 1987 and took prompt and adeguate corrective action including disciplinary, action against the individual. The inspectors evaluated the significance of the event and licensee actions taken, and concluded that the five criteria listed in Section V. A. of 10 CFR Part 2, Appendix C (1986), General Statement of Policy and Procedure for NRC Enforcement Actions, have been met, thus a notice of violation will not be issued. 10. Inspector Followup and Unresolved Items (92701) (Closed) Inspector Followup Item 416/87-12-02. By letter dated May 15, 1987(AECM-87/0098), the licensee stated that qualification testing of the 1 subjectwirewascompletedonMay 12, 1987, anc the test results indicated ' that the wire would withstand its normal and accident environment and would continue to perform its function Post-LOCA in the hydrogen analyzers for a minimum service life of five years. Also, the licensee is conducting further environmental qualification testing of the wire to l further extend the qualified life of the wire. (Closed) Inspector Followup Item 416/87-10-06. .he licensee replaced the remote start pushbutton for the Standby Diesel Generator 12 under Maintenance Work Order E71618. The removed pushbutton .was operated repeatedly while monitoring the normally open contacts with a volt-ohm meter and no intermittent actions of the contacts were identified. No conclusive evidence of failure of this switch could be determined. No further action is necessary. 1 (Closed) Inspector Followup Item 416/86-32-06. The inspectors reviewed the closed Design Change Implementation Package for Design Change Packages 81/5003, 85/3064 and 85/3098. These packages covered the installation of
" . 10 electrical isolation switches between the' control room and the Division 1 I I remote shutdown panel, which was required by License Condition 2.C.(22). All work appears to have been satisfactorily completed, the appropriate retests were implemented, and the applicable documents and procedures updated. (Closed) Inspector Followup Item 416/87-10-05. The licensee changed SLCS surveillance procedure 06-0P-1C41-M-0001 to provide better control over s the quarterly surveillance test, and submitted the revised procedure to i the inspectors for review prior to the next scheduled test. The l inspectors noted that the changes did not appear adequate, and suggested that the licensee reconsider using the revised procedure as written. The l licensee implemented additional minor changes and then the test was l attempted on June 10, 1987, with one of the inspectors present. The test i was unsuccessful, due to both procedural and test equipment inadequacies. Examples of some of the problems were as follows: Paragraph 2.3 of the procedure cautions the operator to never permit the SLC pumps to pump against a shutoff head, but paragraph 5.2.19 directs the operator to stop the pump and close the only open path, drain valve 1C41-F025. Due to the potential of shutting F025 before the pump coasts down to a full stop, the operator felt compelled to open another path, F016, which was not provided for in the procedure. Paragraph 3.3 specifies Heise test pressure gauges, and paragraph 5.5.5 installs one of the pressure gauges at the SLC pump discharge test block. The gauge was so sensitive to the violent pressure oscillations generated by the SLC pump, the snubber had to be adjusted so tight the gauge did not reflect actual pressure. This resulted in two lifts of relief valve F029A, which is prohibited by the procedure in two caution notes. This is an exemple of inadequate test equipment specified by the procedure. The individual who monitored and snubbed the discharge pressure test gauge was not in control of the individuals operating the throttled valves as directed by paragraph 5.2.4.6, nor should he be. Paragraph 5.2.7 NOTE requires the operator to verify no in-leakage to i the test tank. This is not possible in the current system configuration because there is an orifice bypass around F014 that continuously and slowly fills the test tank when F031 is open. If there are any delays during the test (there was a delay on June 10 1987 and another delay on June 16,1987), the tank will overflow (and it did overflow both times). This is not addressed in the procedure. Proper sequencing would have prevented the overflow. Paragraphs 5.2.9 and 5.2.10 required the operator to open F017 and F201 respectively. These valves would already be open when the second pump is tested per 5.2.24. If a detailed procedure directs the operator to open a valve, he should expect to find it shut and vice versa. Correct wording would be "open or check open". This was , _-_ - _ - _ - _ - . - - - - . _ - . - _ - _ _ . - - - . _ _ _ _ - - _ _ . _ - - _ - - - _ _ - _ - _ _ _ _ - _ _ ._ . . _ _ _ . _ - . - _ _ . _ - _ . _ ___ -. J
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, 4 11 done by TCN to paragraph 5.2.27, which is a similar circumstance, but ! not to all paragraphs where it would have been appropriate. The above problems and other similar examples were discussed with the licensee. Technical Specification 6.8.1.c requires that wri,tten proce- dures shall be established, implemented and maintained covering surveil- lance and test activities of safety related equipment. Contrary to this ) requirement, the licensee failed to provide and implement an adequate procedure for the surveillance testing of SLCS, as evidenced by the deficiencies identified in surveillance procedure 06-0P-1C41-M-0001. This shall be violation 416/87-14-03. The licensee subsequently made more changes to the procedure, verified ! that the relief valves were lifting at the correct pressure, and deter- mined that the check valves downstream of the pumps were not obstructed. 1 On June 15, 1987, SLC A was successfully tested and on June 16, 1987, SLC i B was successfully tested. As of the end of this inspection period the inspectors noted that the surveillance procedure still needed minor improvements. The licensee was informed of this and committed to ensure that this and all other safety related procedures are written to facilitate formal, ste,p-by-step implementation. The licensee was requested to address this in the response to violation 416/87-14-03 above. } ) l l l I l l I i , < f L-- - --- _ _ _ - - - - - - - - - - - - - - - - - - - - - - -_ - -_-----..-- -- ._ - ----- --------------- _--- ---- - J }}