IR 05000416/1987035

Insp Rept 50-416/87-35 on 871114-1218.Violation Noted.Major Areas Inspected:Operational Safety Verification,Maint Observation,Surveillance Observation,Operating Reactor Events & Fastener Testing for Bulletin 87-002

ML20195J331
Person / Time
Site:	Grand Gulf
Issue date:	01/19/1988
From:	Butcher R, Dance H, Mathis J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20195J315	List: IR 05000416/1987035 IR 07100114/2012018 ML20195J310
References
50-416-87-35, IEB-87-002, IEB-87-2, NUDOCS 8801270237
Download: ML20195J331 (16)

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[ "g REGION 11 g j 101 MARIETTA STREET, *'- 2 ATLANTA. GEORGI A 30323

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Report No.: 50-416/87-35 Licensee: System Energy Resources, In Jackson, MS 39205 Dochet No.: 50-416 License No.: NPF-29 Facility Name: Grand Gulf Nuclear Station Inspection Cond ted: November 14 thru December 18, 1987 Inspect rs: s .

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& AUw R.B. Bt/tcher, Senior Resident Inspector

. Mathis Resident Inspector i/n er Det Signed Approved by:

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b" C. Dance, Section Chief, Division of I I'l k Date 5'igned ReactorProjects SUMMARY Scope: This routine inspection was conducted by the resident inspectors at the site in the areas of Licensee Action on Previous Enforcement Matters, Operational Safety Verification, Maintenance Observation, Surveillance Observation, Operating Reactor Events, Inspector Followup and Unresolved Items, Refuelir,g Activities, Compliance with the ATWS Rule, Fastener Ter, ting for Bulletin 87-02, and Design Changes and Modification Results: One violation was identified- Failure to follow procedures and failure to have adequate procedures for performing mainteriance repair, replacement and modification wor ADOCK 880 16 DR y

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REPORT DETAILS Licensee Employees Contacted J.E. Cross, GGNS Site Director

! *C.R. Hutchinson, GGNS General Manager R.F. Rogers, Manager, Special Projects

• A.S. McCurdy, Manager, Plant Operations J.D. Bailey, Compliance Coordinator M.J. Wright, Manager, Plant Support

• L.F. Daughtery, Compliance Superintendent

• 0.G. Cupstid, Start-up Supervisor R.H. McAnuity, 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, Quality Programs

• J.C. Roberts, Manager, Plant Modification and Construction Other licensee employees contacted included technicians, operators, security force members, and office personne * Attended exit interview Exit Interview (30703)

The inspection scope and findings were summarized on December 18, 1987, with those persons indicated in paragraph 1 above. The licensee did not 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:

416/87-35 01, Violatio Four examples of failure to follow procedures and failure to have adequata proi adures for performing maintenance repair, replacement and modification wor (Paragraph 7).

461/87-35-02, Inspector Followup Ite Final determination of the significance of cracks found on Division 1 Diesel Generator turbocharger manifol (Paragraph 7). Licensee Action on Previous Enforcement Matters (92702)

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(Closed) Escalated Enforcement Action (EA) 84-23-1, EA 84-23-2, EA 84-23-3 and EA 84-23-4. By letter dated June 3,1985, the NRC notified the licensee (Mississippi Power and Light Company at that time) that escalated enforcement action was being taken in response to Regional inspection and Office of Investigations finding On October 23, 1987, the NRC announced that the proposed $500,000 fine had been mitigated to $200,000 in a settlement agreement with the licensee. No further actions are require . Operational Safety, Radiological Protection and Physical Security Verification (71707, 71709 and 71881)

The inspectors kept themselves informed on a daily basis af the overall plant status and any significant safety matters related to plant operation Daily discussions were held with plant management and various members of the plant operating staf The inspectors made frequent visits to the control room such that it was visited at least daily when an inspector was on sit 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 supervisor Weekly, when the inspectors were onsite, selected Engineered Safety Feature (ESF) systems were confirmed operabl 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 instrumentatio General plant tours were conducted on at least a biweekly basis. Portions of the control building, turbine building, auxiliary building and outside areas were visite Observations included safety related tagout verifications, shift turnover, sampling program, housekeeping and general plant conditions, fire protection equipment, control of activities in progress, problem identification systems, and containment isolation. The licensee's onsite emergency response facilities were toured to determine facility readines 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 control The inspectors verified licensee compliance with physical security manning and access control requirements. Periodically the inspectors verified the adequacy of physical security detection and assessment aid No violations or deviations were identifie l i

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3 Maintenance Observation (62703)

During the report period, the inspectors observed portions of the maintenance activities listed belo The observations included a review of the Maintenance Work Orders (MW0s) and other related documents for 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 control MWO M75812, Chemical Clean Cooler ESF Switchgear Room MWO M76067, Disassemble and Prepare SLC Pumps for Hydro, Perform Hydro and Reassemble Pump SERI is in the process of upgrading the design pressure of.a part of the Standby Liquid Control (SLC) system (from the pump discharge to the explosive valves, inclusive) from 1400 psig at 150 *F to 1500 psig at 150 * Design Change Package (DCP) 85/4053 addresses ATWS modifications to SLC that are ongoing during refueling outage 2. The upgrading of design pressure will allow increasing the system relief valve set points, thus providing additional margin between the system operating / test pressures and the relief valve set pressures. As a part of the upgrade of the SLC (C41-C001A/B) pumps design pressure, a hydrostatic test of the pump casing and discharge in accordance with ASME Section III was performed and witnessed by the inspectors on December 17, 1987 for SLC pump A. Maintenance Work Plan (MWP) 87/1171 was written to initiate the hydrostatic test of the pumps. Change Notice 87-0288 provided the instructions and requirements for the necessary hydrostatic test. The acceptance criteria for the hydrostatic leakage test for each pump is that there shall te no leakage allowed. Both pumps successfully passed the hydrostatic tes No violations or deviations were identifie . Surveillance Observation (61726)

The inspectors observed the performance of portions of the surveillances 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 surveillances, removal from service and return to service of the system or components affected, and review of the data for acceptability based upon the acceptance criteri EL-1L21-0-0001, Revision 25, Battery 1A3,183, and 1C3 Performance Discharge Tes P-1P81-R-0001, Revision 25, HPCS Diesel Generator 18 Month Functional Tes __ _ _ . _ . __ --

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06-IC-1E12-R-1011, Revision 24, Interface Valve Pressure Calibratio S-53-833-29, Revision.16, Non Calibrated Jet Pump Flo IC-1821-R-0006, Revision 23, Main Steam Line Low Pressure Calibratio No violations or deviations were identifie . 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 actio The inspectors examined instrument recordings, computer printouts, operations journal entries, scram reports and had discussions with operations, maintenance and engineering support personnel as appropriat During this inspection period of the second refueling outage there appears to have been an increase in the number of events. The safety significance is minimal since the unit has been shutdown for a refueling outage since November 7, 1987 but the inspectors did express their concern to the plant manager that the failure to prevent similar incidents could be a precursor to more serious events, especially during plant operation. Plant management expressed their concern also and pointed out controls that are being incorporated to prevent recurrences and noted the improvement over the previous refueling outage. The inspector noted that these comments of concern are an early warning and concurs that there has been an improvement over the previous refueling outage control At 3:00 p.m. on November 14, 1987, the licensee identified that Limiting Condition for Operation (LCO) 87-1163 for condensing pot (B21-00048)

snubber B21-G146C04 had exceeded the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed by the action statement in TS 3. LC0 87-1163 was written at 8:15 a.m. on November 11, 1987. While performing a shift LC0 review at 3:00 p.m. on November 14, 1987 it was discovered that the snubber could affect not only Division 2 ECCS actuation instrumentation which was out of service) but also isolation system actuation instrumentation (TS 3.3.2-1) and accident monitoring instrumentation (TS 3.3.7.5) required to be operabl The licensee immediately performed the TS action statements and wrote LCOs 87-1195 and 87-119 A review of the work package for snubber B21G146C04 revealed the snubber had not been removed until November 12, 1987. Licensee personnel involved in the snubber removal started work on the day shift and signed statements that they removed snubber B21G146C04 between the hours of 8:00 a.m. and 10:00 a.m. on November 12, 1987. The same snubber was reinstalled and accepted by Quality Assurance before 6:00 a.m. on November 15, 198 Based on the actual removal and installation times being within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, this event became non-reportable. The licensee reviewed his existing snubber controls and initiated the following controls:

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- All existing snubbers that had been previously released for work were reviewed for attached system operabilit Each snubber package submitted for work must clearly identify: What system the snubber is attached to, and Exactly where in the system the snubber is physically locate Prior to being taken to the control room for authorization to start work (ATS) signature each snubber package will: Be reviewed by a non-shift SR0 for system effec Have an LC0 generated and placed in the snubber packag LCOs will be separated into two distinctive groups:

(Normal LCOs and LCOs initiated only for tracking purposes) Tracking LCOs (for snubbers on inoperable systems) Tracking LCOs will be distinctively identified by bold lettering at the top of the form, Tracking LCOs will be maintained in a separate noteboo LC0 index sheet will indicate which LCOs are tracking LCO Active 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LCOs (for snubbers on operable systems). A memo will be placed in the package for snubbers to be released on operable systems stating that a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LC0 starts when ATS is signed on the MW For MNCRs written on snubbers released on operable systems, the shift will evaluate them as making the identified snubber inoperable and indicate that an engineering evaluation must be performed on the component attached within 72 hrs, of when the LC0 was initiate At approximately Reactor Operator (2:30 a.m. on November 17, the refueling floor SeniorSRO), who the polar crane operator moving a reactor vessel head stud tensioner toward the upper containment fuel storage pool which contained fuel assemblies. By the time the SR0 could get off the refuel platform and get the crane operators attention the tensioner was over the corner of the new fuel portion of the fuel pool. The SR0 directed the movement of the stud tensioner around the opposite direction of containment such that it did not pass over critical areas. TS 3.9.7 states that loads in excess of 1140 pounds shall be prohibited from travel over fuel assemblies in the

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spent fuel or upper containment fuel storage pool racks. The licensee had the crane load placed in a safe location and red tagged the polar crane such that the shift superintendent would have to authorize tag removal in order to use the crane. The licensee's management review board and plant safety review committee developed an action plan that included adding a management representative on the refuel floor to review overall activities that the refuel floor SR0 may not be aware of. The supervisor for crane operations will personally oversee all crane equipment movements. Failure to prohibit loads in excess of 1140 pounds from travel over the contain-ment fuel storage pool racks is a violation of TS 3.9.7. The inspectors review of this event indicated that it meets the five criteria of licensee identified violations listed in Section V.G. of 10 CFR Part 2, Appendix C, for NRC enforcement actions and no violation will be issue At 2:53 a.m. on November 19, while Instrumentation and Controls (18C)

personnel were performing a surveillance (06-IC-1821-R-0038) on the reactor vessel steam dome pressure (Channel C) time response test, the control room observed that shutdown cooling suction valve E12-F009 closed, isolating Residual Heat Removal (RHR) shutdown cooling. The reactor was shutdown in Mode 5 and reactor coolant temperature was 100 F at the time of the event. Upon investigation a fuse was found blown. The fuse was replaced and RHR shutdown cooling was restored at 4:00 a.m. with no apparent temperature increase noted at the recirculation loop temperatur Recirculation pump A was in operation during this even On November 19, at approximately 6:00 a.m. during fuel movement from the reactor vessel core to the spent fuel pool, while attempting to lift fuel bundle LJS047 the load limit trip of 1200 pounds on the main hoist was reached without fuel assembly movemen Incident Report 87-11-14 was written in conjunction with MNCR 0382-87 to provide an evaluation and disposition for dislodging the stuck fuel bundle. The inspectors followed the licensee's activities for dislodging the stuck bundle. See paragraph 10 for more details on the stuck fuel bundl On December 9, the licensee notified the resident inspectors, Region II and NRC headquarters of indications of cracks found in the exhaust manifold inlet housing for the turbochargers on the Division 1 diesel generator. The diesel generators are Transamerica Delaval diesels with Elliot turbochargers. On December 10, 1987, a telecon with the licensee, Region II and NRC headquLrters personnel was conducted in order for the licensee to inform the NRC of their findings and planned actions. A similar discrepancy had been identified at another plant. A followup telecon was conducted on December 17,1987, in order for the licensee to present their metal'urgical findinas from the Division 1 Diesel Generator manifold. The indications appear to be from casting techniques and the Division 1 manifold was examined to determine if the resulting cracks are a safety issue or if they pose no functional problem. The licensee's position is that the cracks were formed during the casting process and examinations show that the cracks have not grown during operation. The final report is due to be completed on December 23, 1987, and will be I

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given to the resident inspector to be forwarded to Region II for final evaluation. The final determination of the acceptability of the cracks found on the Division 1 manifold will be tracked as Inspector Followup Item 416/87-35-0 The following events were reviewed using the guidance of the general policy and procedure for NRC enforcement actions and due to the previous similar violation issued during the first refueling outage (416/86-37-01),

a violation will be issued against failure to follow procedures or failure to establish adequate procedures:

On November 30, 1987, at 2:16 p.m., the licensee re-energized electrical bus 16AB and RHR shutdown cooling suction valve E12-F009 went shut isolating shutdown cooling. Bus 16AB, Division 2 ESF bus, had been de-energized for maintenance activities and valve E12-F009 was in the open position with power removed. Inverter 1Y88 was de-energized which sealed in a high reactor vessel pressure (135 psig) isolation signa Prior to energizing bus 16AB the breaker to valve E12-F009 was closed such that when bus 16AB was energized it received control power but the isolation logic still sensed an abnormal condition causing valve E12-F009 to isolate. The procedure failed to recognize that valve E12-F009 would isolate resulting in the loss of shutdown coolin At 5:00 p.m. , on November 27, 1987, the licensee identified that a 3/4 inch sensing pipe for the A channel narrow and wide range containment pressure post accident monitors was cappe The B channel instrumentation pipe was open but a 3/4 to 1/4 inch reducer was installe These modifications would have made the A channel containment pressure monitors inoperable. A deficiency tag had been written on August 28, 1987 for both the A and B channel 3/4 inch pipes stating that a pipe cap should be installe Maintenance Work Order (MW0) M74520 for the A channel (penetration 103D) and MWO M74513 for the B channel (penetration 1040)

were written on August 28, 1987 to add 3/4 inch pipe cap An Instrumentation and Controls (I&C) representative reviewed the request and had the MW0s cancelled on October 1, and October 2, respectively, due to the realization that the penetration pipes should not be capped. Sometime subsequent to that date, the A channel 3/4 inch pipe was capped. Incident Report 87-11-20 was written to document this discrepancy. The licensee was operating in Mode 1 until November 7, when the unit was shutdown for the present refueling outage. TS Table 3.3.7.5-1, Accident Monitoring Instrumentation, item 10 requires two channels each of the wide and narrow range containment pressure in operational condition 1, 2 and The minimum number of operable channels is one with the action statement that if the number of operable accident monitoring instrumentation channels is less than the required number of channels, restore the inoperable channels to operable status within 7 days or be in at least hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cold shutdown within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The licensee's investigation indicated that the pipe cap installation was accomplished during Local Leak Rate Testing (LLRT) activities on November 11. The LLRT procedure 06-ME-1M61-V-0001, step 5.9, implies that pipe caps be replaced

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to secure all test connection LLRT personnel have had the replacement of pipe caps emphasized during trainin It appears the pipe cap was not installed during operational conditions 1, 2 or 3, but was installed by LLRT personnel without proper documentatio On December 8, 1987, at 3:40 a.m., while restoring from procedura 06-0P-1E12-R-0022, RHR Containment Spray Initiation Logic System Functional Test, an operator perfonned step 5.2.33 prior to completing the restoration in step 5.2.3 This allowed Division 2 Load Shedding and Sequencing (LSS) to actuate causing several ESF actuations. All systems were restored to normal lineu Incident Report 87-12-7 was written to document this event. Step 5.2.32 has a caution at the end that states, RHR B/RHR C initiate logic must be reset before removing the ECCS test switch. Otherwise an inadvertent Division 2 LOCA initiation will occu Step 5.2.33 states to remove the ECCS test switch. Personnel failed to follow the procedure as writte On December 12, 1987, at 4:50 p.m., while performing Modification Special Test Instruction (MSTI) 1C11-87-001-05, testing the Alternate Rod Injection (ARI) for Recirculation Pump Trip (RPT) system logic, a scram signal was received due to a high-high scram discharge volume level signal. The reactor was in cold shutdown (refueling mode) with all control rods in an abnormal system operating configuration was being utilized to provide a trip signal from ARI/RPT to reactor recirculation pump motors breakers Z52-1103C and Z52-12205 ARI channel 2 was placed in the test mode causing instrument air bypass valve C11-F1648 to ope Channel 2 was then tripped which opened the exhaust port on instrument air supply valve C11-F160. Channel 2 was then returned to the normal mode without resetting the trip signals so breakers 252-1103C and 252-1205C would tri This caused -he instrument air bypass valve F164B to close with the supply valve F160 in the exhaust position which isolatej the instrument air supply from the scram pilot valve air headers. The scram pilot valve air header pressure bled down causing the scram valves to drift open, putting water into the scram discharge volume. The normal system operating procedure during Channel 2 testing is to reset the ATWS ARI/RPT trip signal prior to returning the system to normal configuration which prevents the above problem from occurrin TS 6.8.1 requires that the applicable procedures recommended in Appendix A of Regulatory Guide (RG) 1.33, Revision 2, February 1976 be established, implemented and maintained. RG 1.33 requires procedures for performing maintenance repair, replacement and modification work. Contrary to TS 6.8.1, the licensee in the four events described above failed to follow procedures or failed to provide adequate procedures. This is a violation 416/87-35-01.

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9 Inspector Followup and Unresolved Items (92701)

(Closed) Inspector Followup Item 416/85-45-05. The licensee has reviewed their allowable leak rate program and have not determined that a change will be made. Since the present allowable leakage is in the conservative direction the inspector had no further questions. This item is close . Refueling Activities (60710)

The refueling outage for cycle two officially started on November 7, 1987, as previously reported in Inspection Report 416/87-29. The movement of new fuel into the containment spent fuel pool was completed at 4:30 p.m.,

on November 13, and the first fuel bundle was off loaded from the reactor vessel core at 9:45 a.m. on November 1 Fuel shuffle was performed in accordance with procedure 09-S-02-300, Revision 8, Special Nuclear Mct1 rial (SNM) Movement Centrol. The procedure provided the technical guidelines for planning and tracking the movement of SNM. On November 19, during the core shuffle for cycle 2, an attempt to remove a peripheral fuel assembly (LJS047 at core location 01-32) failed. The main hoist load limit trip at 1200 pounds was received without fuel assembly movement. An inspection of the fuel assembly upper grid location revealed that the assembly was about one inch lower than the surrounding assemblie The adjacent assemblies were removed from locations 34-01 and 30-01 for inspection of fuel assembly LJSO47 by remote underwater video. The licensee discovered that the fuel bundle nose piece was not positioned in the peripheral support casting, but instead, wedged beside the support casting. Several attempts were made to dislodge the assembly with the fuel grapple, with each attempt failing due to load limit trips at 1200 pounds. TS 3.9.6.1 specifies a 1250 pound load limit on the refueling platform main hoist, however, the licensee's procedure

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restricts the load limit to 1200 pounds. The proposed disposition from MNCR-382-87 to dislodge the stuck bundle (LJS047) required review and SERI discretionary enforcement letter dated November by(AECM-87/0230)

21, 1987 the Nuclear Regulatory to NRC (Commission. Region II) requ a one-time enforcement discretion on GGNS TS 3.9.6.1 and surveillance requirements 4.9.6.1.a.3 and 4.9.6.2.4. to allow the licensee to use methods successfully utilized at two foreign BWR-6 facilities for similar situ 6tions. The general approach to dislodge the stuck assembly is described in MNCR-382-87 Disposition Instructions. The plan for removing the stuck fuel assembly involved applying a force of up to 2,000 pounds to the upper tie plate handle of the stuck assembly. The licensee's evalJation concluded that all fuel design criteria were satisfied and no fuel bundle failures were anticipated to occu Furthermore, the licensee concluded +. hat there is no significant increase in the probability or consequences of a previously evaluated accident described in chapter 15 of the FSA _ _

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On November 23, 1987, NRC Region II Office called SERI regarding enforcement discretion transmitted to the NRC by letter AECM-87/0230, on November 21, 198 The NRC granted the enforcement discretion waiver (DEW-001). effective on November 23, 198 On November 24, 1987, under special instructions to MNCR 0382-87, fuel assembly LJS047 was removed via the following method:

Using the polar crane as an attachment point, a manually operated chainfall and a dynamometer (load indicator) was installed in series with the general purpose grapple. The grapple was attached to the fuel assembly bail handle and load was gradually increase At approximately 1535 pounds, fuel assembly LJSO47 broke free and was reseated in the support casting. Later bundle LJS047 was placed in the spent fuel pool in accordance with SNM tracking shee On November 25, and November 26, 1987, fuel assembly LJS047 and the following reactor internals were inspected for damage:

Peripheral fuel support fillet weld

Peripheral fuel support casting

Area around the fuel support casting, and Top guide The above listed inspections were performed by GE personnel, witnessed by SERI and the resident inspectors, and showed no evidence of assembly or reactor internal damage. The inspectors reviewed Procedure 09-S-02-108, Core Verification, to assure that appropriate measures were incorporated

. in the procedure to ensure similar misalignment of the peripheral assemblies does not occur again. In addition, the inspectors verified that commitments described in SERI discretionary enforcement letter (AECM 87/0230) were performe The inspectors have followed the activities for chemical cleaning of the Standby Service Water (SSW) system, Division 1 and Division 3, which utilize basin A primaril The siphon line between basin A and B was plugge Procedure 04-1-01-P41-1-TEMP 8. Revision 0 with TCN 1 was used to provide directions for SSW loop A and C chemical cleaning. The inspectors verified the SSW basin water level was maintained above elevation 84'-6", total flow was maintained greater than 3700 gallons per minute and the discharge pressure was maintained below 150 psig. The cooling tower fans were secured and the following components were valved in:

A Control Room Air Conditioning A ESF Electrical Switchgear Room Cooler A Diesel Generator Jacket Water Cooler

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A Drywell Purge Compressor Cooler A Fuel Pool Cooling Heat Exchanger A RHR Heat Exchanger HPCS Diesel Generator Jacket Water Cooler HPCS Room Cooler SSW Pump A Motor Bearing 011 Cooler Fuel Pool Cooling and Cleanup Pump Room Cooler RHR A Pump Seal Cooler RHR A Room Cooler LPCS Room Cooler RCIC Room Cooler

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(a TANNIN Solution adjusted with approximately and a minimum 2560 gallons 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> iron conditioning of NALC0 run was started. The inspectors observed a pH of approximately 5.7 during this run. Then sulfuric acid was added to bring the pH to between 2.5 and Then a NALC0 solution was added along with an iron dispersant. pH was to be maintained between 2.5 and 2.8. After circulating for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> the solution in the A basin was drained to the Unit 2 cooling tower basi Region II inspectors were on site the week of December 14, 1987, to review the licensee's chemical cleaning and water treatment programs and their findings are in Inspection Report 416/87-3 . Compliance With the ATWS Rule, 10 CFR 50.62 (25020)

The inspection requirements of TI 2500/20 were addressed previously in Inspection Report 416/87-29. During this inspection period the inspectors followed the installation of DCPs 87/4005, 85/4053 and 87/300 The inspectors verified the following items for DCP 87/300 Panel 1H13-P680 in the control room was modified to add the ARI/RPT legend plate, associated switches and indicating lights as detailed in the drawing Electrical connector / bracket assembly was mounted correctl Verified jumper from jack 1833A-J338 and J344 were removed and new jumper from jack 1C11C-J001 to the ARI control status panel (P-680)

was installe Wiring connected to a switch in the ARI/RPT panel (272A717P016K008, 16 gauge, grey color and 27297917P020X008, 20 gauge, grey color) was verified to be environmentally qualified wirin A welder working in the control room on hanger 18-525A-3696, conduit support, was verified to be qualified per welding procedure M-P1-A LH-S, Revision 5. The inspector verified that the welding amperes and voltages being used met the requirements of the welding procedure. The ampmeter used to check the welding machine amperage

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(No. 0883) and voltage (voltmeter No. A292) were calibrated on September 17, 1987 and November 18, 1987, respectively and had a 6 months calibration period requiremen Housekeeping and fire protection controls were being observed!

Official copies of the required work packages were available and being followed during installation wor The inspectors verified the following for DCP 87/4005, ATWS-ARI Solenoid Valve Installation. DCP 87/4005 was required to be worked concurrently with DCP 87/300 The solenoid valves were installed as shown on the P&ID and were properly identifie Housekeeping and fire protection controls were being observed Official copies of the required work packages were available and being followed during installation wor The . inspectors verified the following items for DCP 85/4053, SLC System Design Changes to Comply With 10 CFR 50.6 The inspector verified that the welder working on support N C41-PI-R003 was qualified to welding procedure M-P1-A-LA-S, Revision . The welding rods used were E-7018, 3/32 inch No. 79211. The inspector reviewed the welding rod material certificatio The inspector verified the weld for valve C41-F220 was made by a qualified welder using the applicable procedure, M-P8-T-ag, Revision 4. The inspector verified the correct amperage and voltage being used for the weld was as called out in the welding procedure. The ampmeter (No. 0883) and voltmeter (No. A292) were within calibration date The latest drawing revisions were being used, the licensee was following the drawings and equipment identification was maintaine . Fastener Testing to Determine Conformance with Applicable Material Specifications (25026)

This inspection was conducted per Temporary Instruction 5200/26 to ensure fasteners selected in response to NRC Bulletin 87-02 are representative of installed fasteners and that suspect fasteners are selected for testin Ten non-safety-related studs, bolts and/or capscrews; ten non-safety-related nuts, ten safety-related studs, bolts and/or capscrews and ten safety-related nuts were to be selected from stock for testing. From .'

interviews with licensee personnel the following proportion of use of fasteners was determined:

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Bolts, Studs and/or Capscrews Safety-Related Material & Grade  % Use A-193- B7 72 A-193- 88 Negligible A-193- 816 0 A-449 Negligible A-325- 1 23 A-325- 2 0 A-325- 3 0 A-354 0 A-490 0 A-320- L7M 0 (Less than 1/2 inch size)

Non-Safety-Related SAE J429 -5 78 SAE J429 -8 10 A-7207 Negligible A-325 - 1 12 Nuts Safety Related A-194 - 2H 95 A-325 5 (not procured to this specificatio Nuts come with A-325, grade 1 bolts.)

Non-Safety-Related A-563 0 SAE J995 5 78 A-325 22 Based on the above figures, the following fastener sampling was agreed to:

Safety-Related Material & Grade Type and Size (inches) Head Markings A-193 87 4 Bolts, 1/2 X 2 1/4 87 CU L7 7 3 Studs, 1/2 X 3 1/4 B7 C A-325 1 3 Bolts, 1 X 3 1/4 UNY C A325 A-194 2H 7 Nuts, 3/4 A 2H 2 Nuts, 1 C 2H CD 1 Nut, 1 A ._

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Non-Safety-Related Material & Grade Type and Size (inches) Head Markings SAE J429 5 3 Bolts, 1/2 X 2 FM 3 hash marks SAE J429 8 3 Bolts, 3/4 X 2 3/4 Triangle 6 hash marks A-325 1 4 Bolts, 5/8 X 3 1/2 V SAE J995 5 6 Nuts, 1/2 None A-325 4 Nuts, 5/8 BS. 3 hash marks The inspectors verified each fastener was put in a separate zh lock bag with identifying dat The selection was based in part on the test laboratory (Wyle laboratories) requirements in that the fasteners had to be 1/2 inch diameter or larger, a minimum length of 3 X diameter up to 4 1/2 inches long. The licensee has specified the same test program for safety and non-safety-related fasteners. The tests shall evaluate the ultimate tensile strength, hardness and chemical prop-ties as required by the fastener's specification, grade and class. Information regarding each fastener's specifications, grade and class with methods for testing is to be furnished to Wyle laboratories by the license . Design, Design Changes, and Modification (37700)

The inspectors reviewed Design Change Package (DCP) Number 85/4007,which provides the design change necessary to install a Condenser Tube Cleaning System (CTCS) on the Circulating Water (CW) system, which provides an on line cleaning method for the condenser tubes. The 10 CFR 50.59 evaluation associated with DCP 85/4007 was reviewed to verify that the written basis upon which the determination was made is technically correct and that the questions necessary to determine whether the design change constitutes an unreviewed safety question pursuant to 10 CFR 50.59 have been considered by the licensee in the safety evaluatio The following Maintenance Work Packages (MWPs) associated with DCP 85/4007 were reviewed to determine if MWPs included:

Identification of Specifications, guides and codes governing the wor Identification of inspections required by codes or standard Acceptance tests which stipulate acceptance values or performance requirement QA/QC requirement MWP 87/1088 Prefabrication MWP 87/1087 Chemical Flushing

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15 MWP 87/1196 Piping & Precleaning of Condenser MWP 87/1201 Electrical The purpose of the Condenser Tube Cleaning system is to continuously remove the corrosion deoosits from the condenser tube inner walls in order te maintain the thermal efficiency of the low pressure turbines and to reduce the possibility of pitting under deposits. In addition, the Condenser Tube Cleaning system is designed to remove small amounts of-existing deposits from the entire length of the tubes in order to periodically restore the design cleanliness level of the condenser tube Procedures for operation and maintenance of the Condenser Tube Cleaning '

system will be provided by Taprogge Field Engineering during Condenser Tube Cleaning system commissioning. The inspectors will review the system operating procedures when they become availabl ;

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