IR 05000354/1987008
| ML20215K170 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 04/29/1987 |
| From: | Norrholm L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20215K149 | List: |
| References | |
| 50-354-87-08, 50-354-87-8, NUDOCS 8705110102 | |
| Download: ML20215K170 (19) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
050354-870106 050354-870108 Report No.
50-354/87-08 050354-870112-050354-870113 -
Docket 50-354 050354-870205i 050354-870211i License NPF-57 050354-870213-050354-870218'
Licensee:
Public Service Electric and Gas Company 050354-870224'
050354-870224l Facility:
Hope Creek Generating Station 050354-870319 Conducted:
March 10, 1987 -kpril13,1987 Inspectors:
R. W. Borchardt, Senior Resident Inspector D. K. Allsopp, Resident Inspector K. A. Manoly, Lead Reactor Engineer R. J Spmers, Project Engineer p
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Nim-tz, Sr. Radiation Specialist
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Approved:
k U
'f 37 37 L4 rc6olm, Chief, Projects Section 2B
/ Dat(e Inspection Summary:
Inspection on March 10, 1987 - April 13, 1987 (Inspection Report Number 50-354/87-08)
Areas Inspected: Routine onsite resident inspection of the following areas:
followup on outstanding inspection items, operational safety verification, surveillance testing, maintenance activities, radiological occurrence report system, high radiation area access control, measuring and test equipment, vehicle access control, emergency drill observation, strike contingency plans, control of transient equipment, and licensee event report followup. This inspection involved 229 hours0.00265 days <br />0.0636 hours <br />3.786376e-4 weeks <br />8.71345e-5 months <br /> by the inspectors.
Results: As discussed in paragraph 3 of this report, the inspector identified a violation of Technical Specifications (TS), in that the main steam line radiation high-high trip setpoints were set non-conservatively high and outside the allowable limits of TS. The main steam line radiation detectors are provided to detect a gross failure of the fuel cladding and, when tripped, provide an input to the reactor protection system.
If the RPS logic were satisfied, the reactor would scram and the main steam isolation valves close to limit the release of fission product activity to the environment. A number of factors appear to have contributed to this situation, including a failure to incorporate power ascension test results into setpoint calculations and an inadequate review of setpoint change request / authorization documents.
8705110102 870509 PDR ADOCK 05000354 G
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Paragraph:6 of this report also documents concerns that the. radiological
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occurrence report program is not totally effective in the thorough review and resolution of radiological occurrences.
Further NRC review will be
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Details 1.
Persons Contacted Within this report period, interviews and discussions were conducted with Mr. R. Salvesen and members of the licensee management and staff and various contractor personnel as necessary to support inspection activity.
2.
Followuo on Outstanding Inspection Items and Bulletins
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(Closed) IE Compliance Bulletin 86-01, " Minimum Flow Logic Problems That Could Disable RHR Pumps" (TI 2515/82)
The inspector reviewed the licensee's response to the subject bulletin. The response, dated June 11, 1986, was found to be timely and accurate. The licensee determined that due to the redundancy and physical and electrical separation inherent in the Hope Creek design of the RHR system, no credible, single failure problem exists. The inspector reviewed the licensee's FSAR, RHR system P&ID, and RHR system valve control logic diagrams to verify the licensee's position. The Hope Creek design utilizes 4 separate and distinct channels of RHR, including 4 pumps, flowpaths, minimum-flow valves and minimum flow valve controls using independent instruments. The only common portion is a common minimum-flow line discharge to the suppression pool (SP) for each of two trains of RHR (either A and C or B and D). This common leg is downstream of the two respective minimum-flow valves and has a single, manual isolation valve prior to penetrating the SP. This manual valve is a normally locked open valve. Therefore, even the misalignment of a single manual valve would only adversely affect the minimum-flow protection for two of four RHR pumps. The inspector had.no further questions.
(Closed) Unresolved Item (85-58-01); This item was related to the identification of two cases of closely spaced rigid supports on the Safety Auxiliary Cooling System (SACS)
piping from the discharge side of heat exchanger IA2E-201.
A concern was raised regarding the installation of snubbers in proximity to other snubbers, rigid restraints, or anchors. This could lead to the inoperability of these snubbers if the dead band in a snubber were larger than the pipe translation between the two successive supports. The concern was also applicable to rigid supports installed in proximity to other rigid supports or anchors.
The licensee response to the unresolved item involved the performance of a proximate pipe support review. The review involved the identification of all large bore (2 1/2" 0.D.
and larger) pipe supports which are located in proximity to b
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other supports and anchors.
Evaluation of proximate supports was based on establishing proximity distance criteria for supports adjacent to other supports, structural anchors (including equipment nozzles), and rotary equipment nozzles. The proximity criteria were three (3), five (5) and ten (10) pipe diameters (D)
respectively. The criteria were based on simplified beam models subjected to a bending moment equivalent to pipe stress of 12,000 psi and deflections limited to 1/16" for rigid supports and 0.04" for snubber dead bands. The licensee response indicated that small bore piping supports were excluded from the evaluation since their design was generally based on a conservative simplified dynamic analysis approach.
The approach used for design, specified a minimum design span between supports of 4'-0" for 1/2" diameter piping and 4'-6" for 3/4" to 2" diameter piping.
These spans exceeded the proximity criteria lengths of 3D and 50.
Evaluation of large piping supports for proximity resulted in the identification of the following conditions that did not meet the established. proximity criteria:
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23 rigid supports adjacent to rigid supports
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32 rigid supports adjacent to anchors / equipment nozzles 14 rigid supports adjacent to rotary equipment
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5 rigid supports adjacent to snubbers
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10 snubbers adjacent to snubbers
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23 snubbers adjacent to anchors / equipment nozzles
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17 snubbers adjacent to rotary equipment In addition to the above, other conditions outside the established criteria were identified during the licensee's review, but were excluded from further evaluation.
Proximate supports excluded from evaluation included rigid restraints consisting of sway struts with lost motion equal to approximately 0.01" and pipe supports located between two or more elbows.
The evaluation of all proximity violations identified above involved the use of several methods for the qualification of the affected piping systems.
These included:
Comparison of dead weight displacement of box-frame
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vertical supports against their design seismic inertia
loads.
Supports were considered acceptable when their weight loads were equal to or greater than their design seismic inertia loads.
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Determination of modified proximity lengths based on actual measured snubber's lost motions.
Proximate snubbers were considered acceptable when their spacing exceeded the modified proximity lengths derived abov,
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3 Reanalysis of piping systems associated with the
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remaining supports which were not qualified using the above methods. The seismic reanalysis was performed with the.
proximate restraints deleted from the computer model.
For proximate locations where computed deflections were greater than the required movement to activate these proximate restraints, the supports were considered active during a seismic event.
For those cases where the computed piping deflections were less than the required movements to activate these supports, the reanalysis results (piping stress and support reaction loads) were re-evaluated for code compliance and support structure acceptability.
The licensee's evaluation of this concern states that all identified conditions not meeting the established criteria located on large bore piping, including those identified in the NRC inspection, were acceptable. Therefore, piping system stresses and support loads were within the design criteria limits.
The licensee's evaluation was considered sufficient to resolve the identified NRC concern. This unresolved item is therefore closed.
(Closed) Inspector Follow Item (86-51-02); Declaration of Emergency Classifications.
(Closed) Inspector Follow Item (86-51-03); Shift Supervisor's Narrative Log Deficiencies.
(Closed)
Inspector Follow Item (86-51-04); Command and Control of Operational Support Center Teams.
The above items are closed based upon the observation of the licensee's emergency exercise drill on March 26, 1987 as documented in paragraph 10 of this report.
(Closed)
Inspector Follow Item (85-52-23); NRC to review operation of the licensee's computer controlled radiation work permit (RWP) system. This area was reviewed during inspection 86-59 resulting in one iolation being issued relative to
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use of this system. The inspector has completed the review of the RWP system and considers this item closed.
(Closed) Violation (87-01-01); This violation involved a personnel error by radiation protection personnel _which resulted in two missed grab samples of the drywell atmosphere. The inspector reviewed the licensee's response to this violation dated April 3,1987, and verified through independent inspection the implementation of licensee's corrective actions. The inspector will monitor radiation protection sampling activities in the future to verify the effectiveness of Technical Specification training.
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3.
Operational Safety Verification 3.1 Inspection Activities On a daily basis throughout the report period, inspections were conducted to verify that the facility was operated safely and in conformance with regulatory requirements.
The licensee's management control system was evaluated by direct observation of activities, tours of the facility, interviews and discussions with licensee personnel, independent verification of safety system status and limiting conditions for operation, and review of facility records. These inspection activities were conducted in accordance with NRC inspection procedure 71707.
3.2 Inspection Findings and Significant Plant Events The unit entered this report period at approximately 92% power as limited by the transmission network stability curves generated after the damage to the Keeney 500KV transmission lines. The unit remained at the maximum allowable power levels throughout this report period except for short power reductions in order to perform maintenance or surveillance activities.
With the Hope Creek - Keeney 500KV transmission line out of service, the Hope Creek generator operating guide requires that both Hope Creek and the Salem units be operated at reduced power. However, in order to operate at a level closer to the designed generation rate, the licensee installed a modification (Trip-A-Unit) to the Salem Unit-1 generator protection circuitry.
Grid and generator stability is provided by this modification which will automatically trip the Salem Unit-1 generator should the Salem - Deans transmission line be lost.
The NRC held meetings with the licensee to discuss this modification and its impact on the operation of Salem and Hope Creek units.
In addition, the NRC reviewed safety evaluation S-C-E500-NSE-0675-R-1 " Justification for operation of all three units at Artificial Island at increased power during the Hope Creek - Keeney line outage". As documented in a March 30, 1987 letter to the NRC the licensee will observe the following megawatt restrictions during the Keeney line outage:
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Hope Condition Salem 1 Salem 2 Creek Trip-A-Unit Available 1162 1000 1000 Trip-A-Unit Unavailable 790 790 750 One Transmission Line Out 650 650 650 Of Service i
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Additionally, with one unit out of service, the remaining units may be operated at maximum capacity with the trip-a-unit scheme disabled.
Also, the trip-a-unit scheme will be disabled and power reduced accordingly under any of the following conditions:
Severe thunderstorm and/or lightning activity within 50
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miles of Salem.
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Severe icing conditions.
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Winds in excess of 50 mph as measured at either Camden or Deans switching stations or at Artificial Island.
Whenever forest fires are reported in the vicinity of the
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Salem / Deans right-of-way.
Required maintenance work.
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On April 10, 1987, while the plant was operating at 100% power, the inspector performed a comparison of the main steam line (MSL)
radiation monitors' reading to the instruments' high-high rad trip setpoint. The inspector found that the readings and setpoints for the 4 channels were as follows:
Channel Reading (MREM /HR)
High-High Trip Setpoint (MREM /HR)
610A 30.1 118 610B 28.5 118 610C 23.5 118 610D 32.2 118 Technical Specification 2.2.1 states that the reactor protection system MSL radiation high-high trip se. point be established at less than, or equal to, 3.0 times full power background and that the maximum allowable value be less than, or equal to, 3.6 times full power background.
If the logical assumption is made that the April 10 readings were representative of normal 100 percent power background, it can be seen that the high-high trip setpoints in effect were in violation of the allowable value Technical Specification requirements.
Actual High-High Trip Maximum Allowable Value (3.6 Channel Setpoint Times Full power Background)
610A 118 108.36 6108 118 102.6 610C 118 84.6 6100 118 115.92
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The inspector requested the licensee's full power background calculation to evaluate if there was a reasonable explanation for the apparent dis-crepancies.
Further review by both the inspector and the licensee determined that the trip Jetpoints for all-4 channels were in excess of the TS allowed value and that this condition had existed since November 17, 1986, when the new NUMAC MSL radiation monitor drawers were placed in service. The licensee was informed that this was an apparent violation of Technical Specifications.
(354/87-08-01)
Although. additional review remains to be performed, a contributing factor to this violation appears to be the level of review this setpoint change. received. 14 Deficiency Report had been written to ensure that correct setpoints were established once full power had been achieved.
It also appears that the full power data obtained during the power ascension program was not adequately utilized in establishing those setpoints.
In response to the inspector's concern, the licensee utilized historical information to calculate a new full power background level for each of the 4 channels and reset the high-high trip setpoint accordingly on April 13.
The background levels were consistent with those observed by the inspector. The inspector will continue the review of this issue and the licensee's corrective actions during the next inspection period as part of the violation followup.
4.
Surveillance Testing During this inspection period the inspector performed detailed technical procedure reviews, witnessed in progress surveillance testing, and reviewed completed surveillance packages. The inspector verified that the surveillance tests were performed in accordance with Technical Specifications, licensee approved procedures, and NRC regulations. These inspection activities were conducted in accordance with NRC inspection procedure 61726.
The following surveillance tests were reviewed, with portions witnessed by the inspector:
- IC-FT.SK-050 Functional Test of Reactor Water Cleanup Isolation (Division 1 Channel A)
- IC-FT.SE-013 APRM Functional Calibration Test No violations were identified.
5.
Maintenance Activities
- 5.1 Inspection Activity During this inspection period the inspector observed selected maintenance activities on safety related equipment to ascertain
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that these activities were conducted in accordance with approved procedures, Technical Specifications, and appropriate industry codes and standards. -These inspections were conducted in accordance with NRC inspection procedure 62703.
5.2 Inspection Findings Portions of the following activities were observed by the inspector:
Work Order Procedure Description 87-01-22-070-5 MD-PM.ZZ-004 18 Month preventative maintenance on Core Spray Valve IBE-HV-F031B 87-02-26-125-1 MD-ST.ZZ-007 480 V Electrical breaker preventative maintenance 87-03-30-031-5 MD-PM.FD-001 Troubleshooting and repair of HPCI mechanical overspeed trip assembly During. performance of reactor building log OP-DL.ZZ-014 on March 30, an equipment operator found that the High Pressure Coolant Injection (HPCI) system mechanical overspeed trip mechanism did not have the required freedom of movement. This condition may have prevented the HPCI turbine from automatically tripping on an overspeed condition. Although HPCI was still capable of performing its safety related function, it was declared inoperable and repairs were commenced.
A res tew of industry documentation found that inoperable HPCI overspeed mechanisms had been previously identified at other BWR sites and was the subject of General Electric Rapid Information -
Communication Services Information Letter (RICSIL) 004 dated May 23, 1986 and Services Information Letter (SIL) 392 supplement I dated February 10, 1987.
In fact, the HPCI overspeed mechanism check was incorporated into the reactor building logs in response to RICSIL-004.
Initial investigations by GE and Terry Corporation (turbine manufacturer) suggest that the cause of the overspeed mechanism binding is a lubricant attack on the polyetherurethane part in the mechanism. The polyetherurethane tappet head assembly of the trip mechanism is located in a housing where it is exposed to lubricating oil and oil vapor. After exposure to aromatic hydrocarbons, the tappet head assembly may swell and restrict the tappet freedom of movement. Depending upon the position of the tappet assembly when stuck, the HPCI turbine could either have no overspeed protection or the turbine could be in a
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" permanently" tripped condition. The mechanism was found in the no o/erspeed protection condition at Hope Creek.
After removal of the overspeed mechanism from the HPCI turbine, the licensee elected to make an onsite modification to the tappets in accordance with.SIL 392. The SIL recommends that licensees either replace the tappet assembly with the vendor modified design or machine the existing tappets from a diameter of 0.744 - 0.746 inch to 0.738 - 0.740 inch. After machining the tappet to a diameter of 0.740 inch the overspeed mechanism was reinstalled, and freedom of movement was verified.
HPCI was declared operable on March 31.
No violations were identified.
6.
Radiological Occurrence Report Program 6.1 Inspection Activity The inspector reviewed the adequacy, implementation and effectiveness of the Radiological Occurrence Report (ROR)
program. The review was with respect to criteria contained in procedure RP-AP.ZZ-111(Q), Radiological Occurrence.
The evaluation of the licensee's performance was based on review of the ROR log, discussion with personnel, and review of documentation.
6.2 Findings The inspector's review in this area indicated that the ROR program was not effective and did not provide management with adequate assurance that radiological problems have been adequately resolved. This conclusion is based upon the following:
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The inspector requested 3 RORs for review, (87-28, 87-29, and 87-34). The licensee was unable to locate any of the RORs.
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There were a total of 56 log entries contained in the ROR log for the period January 1,1987 through March 16, 1987.
Of this total, 33 were indicated as RORs. Of the 33, 57%
(19 RORs) were not closed out.
No indication could be found that the issues associated with these RORs were adequately resolved.
The inspector did not find any evidence that RORs were
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being reviewed for trends and that appropriate actions were taken as necessar.
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The licensee was aware of the problems with the ROR
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program.
However, as of March 16, 1987 it was unclear as to how the problems were to be resolved.
The individual who had been tasked with correcting the problems recently resigned.
Based on the above review, the inspector concluded that the ROR process was not totally effective as a tool to identify problems and initiate appropriate corrective actions. This is considered a significant weakness in the licensee's oversight of the Radiation Protection _ Program. This area will be reviewed during a subsequent inspection.
(354/87-08-02)
7.
High Radiation Access Controls 7.1 Inspection Activity The inspector reviewed the adequacy, implementation and effectiveness of the licensee's High Radiation Area Access Control Program. The review was with respect to criteria contained in applicable licensee procedures and Technical Specifications.
7.2 Findings On March 13, 1987, an I&C technician withdrew an activated traversing incore probe (TIP) into the TIP room via the drive switch on control room panel 10-C607. This was contrary to a sign posted on the TIP panel which stated:
"TIP room entry in-progress - do not move TIPS". When the technician noticed the sign, he notified appropriate personnel and a review was initiated. The review indicated:
the entry into the TIP room had not been made,
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personnel did not receive any unplanned exposures, and
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the sign was not readily visible on the control panel because it was black with white lettering and had been placed on a black panel.
The licensee was in the process of initiating corrective actions. As initial corrective actions, licensee representatives indicated an individual would be stationed at the TIP panel in the control room to prevent personnel from moving the TIPS when anyone is in the TIP room. The inspector also understands that the station procedures will be modified to require removal of TIP drive power before a TIP room entry is made.
The licensee's actions on this unresolved matter will be reviewed during a subsequent inspection.
(354/87-08-03)
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10 8.
Measuring and Test Equipment i
8.1 Inspection Activity An inspection of the control of measuring and test equipment (M&TE)
was conducted to determine conformance with regulatory requirements, license commitments, and industry standards. The inspector reviewed the Quality Assurance Program, FSAR commitments, and administrative procedures relative to control of M&TE and conducted interviews with selected individuals. The inspector performed an extensive sampling inspection of calibration status of M&TE awaiting use by Instrumen-tation and Controls (I&C), Project Installation Department (PID),
Maintenance, and Radiation Protection Department.
8.2 Inspection Findings I&C M&TE Issue Room The I&C M&TE issue room had received a thorough QA surveillance just prior to the NRC inspection and no discrepancies were discovered that had not been previously QA identified.
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The PID M&TE storage and issue room does not meet the requirements of level
"B" storage as stated in ANSI /ASME N45.2.2.6.1.2.(2), in that uniform heating and temperature control could not be verified as no hydrothermograph recorder was in operation. The issue room does not meet the requirements of SA-AP.ZZ-031(Q) zone 4 requirements in that eating, drinking, and smoking were not prohibited. There was at least one occurrence of the return of M&TE to the issue room exceeding the 7 day issue limit specified in SA-AP.ZZ-022(Q). Pressure gage HC-ZNM-436 had a calibration sticker which indicated the pressure gage had exceeded its calibration cycle. A review of calibration records determined that the calibration. sticker had an inaccurate calibration due date and the pressure gage was within its calibration cycle.
Maintenance M&TE Issue Room i
The Maintenance M&TE issue room had received a thorough QA surveillance prior to the NRC inspection and no discrepancies were identified.
Radiation Protection M&TE Issue Room Non-conforming M&TE was not segregated from calibrated M&TE as required by SA-AP.ZZ-022(Q). The inspector determined that PNR-4 (Serial No. 4415) was past its calibration due date of February 18, 1987. The Radiation Protection M&TE storage and
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issue room does not meet the requirements of level "B" storage as stated in ANSI /ASME N45.2.2.6.1.2.(2), in that uniform heating and temperature control could not be verified as no hydrothermograph recorder was in operation.
PID and Radiation Protection M&TE issue room discrepancies have been identified to the licensee QA organization. The inspector considers this matter unresolved pending further review of the licensee's program for these two departments (354/87-08-04).
9.
Security - Access Control of Vehicles The inspector conducted an inspection to verify that the licensee controls access of all vehicles to the protected and vital-areas in accordance with the physical security plan and regulatory requirements.
Vehicle inspections and required vehicle escorting was observed by the inspector to be satisfactory. The vehicle authorization list was reviewed and discussions were held with selected security personnel.
No violations were identified.
10. Emergency Preparedness Exercise Drill 10.1 Inspection Activity A team of three inspectors observed the March 26, 1987 Emergency Preparedness Exercise Drill and participated in the post drill critiques. Areas observed by the inspectors included the cont rol room, operational support center (OSC), technical support center (TSC), control point, and the performance of in plant teams.
'10.2 Exercise Observations The exercise scenario included the following events with the licensee's responses observed by the inspectors:
Fire in a relay room panel resulting in the loss of all
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overhead annunciators Loss of Feedwater
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Reactor Scram Failure of the High Pressure Coolant Injection System
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Degradation of Reactor Core Isolation Cooling System
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Use of Post Accident Sampling System
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Release of radioactive material to the environment
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In plant radiological monitoring
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Dispatch of teams from the OSC
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Use of the Event Classification Guide (ECG) and Emerger.cy
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Operating Procedures (EOP)
Development of Protective Action Recommendations
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Injured man in the radiological control area
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The inspectors noted that the licensee's activation and augmentation of the emergency organization, activation of the emergency response facilities, and use of the facilities were generally censistent with their emergency response plan and implementing procedures. Based upon the licensee's performance during this pract :e drill, the inspectors have the following comments:
Command and control by the Senior Nuclear Shift Supervisor
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was adequate and he displayed a good understanding of event classifications.
Communications in general, and especially with the TSC and OSC, could use improvement in order to improve utilization of personnel and prioritization of corrective measures.
Command and control in the Technical Support Center was
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good, however a lack of effective communication with the control room and OSC hampered some attempts at technical problem resolution.
Command and control of the OSC and the teams dispatched
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from the OSC was significantly improved over previous emergency drills.
No violations were identified.
11.
Licensee Plans For Coping With Strikes The inspector conducted an inspection of the Hope Creek contingency plan for strike situations that would be implemented in the event of a strike by plant operators, electricians and mechanics. This plan provides the organization and assignments to accomplish the transition from bargaining unit operation of the plant to management operation. The contingency plan was inspected to ensure that an adequate number of qualified and proficient personnel are available to perform both licensed and non-licensed duties, plant security will be mair.tained, and the contingency plan is consistent with regulatory requirements. The inspector determined that an adequate number of personnel are available to perform all plant functions for an extended period of time, however a problem with the control room shift rotation schedule was noted. As written, the contingency plan
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calls for each of two shifts of. control room operators to work in excess of-72 hours over a 7 day period.
Technical Specification 6.2.2.e states', in part, that an individual should not be permitted to work more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any 7 day period, excluding shift turnover time. This situation was brought to the licensee's attention and the inspector has been informed that the shift rotation schedule will be modified in order to conform with the T.S. working hour limits. All other aspects of the strike contingency plan were found to be acceptable. The inspector will followup on the licensee changes to the contingency plan in a future inspection.
(354/87-08-05)
No violations were identified.
12. Storage of Transient Equipment in Safety Related Areas (Region TI:
87-03)
The inspector reviewed the licensee's internal response to NRC IE Information Notice 80-21 " Anchorage and Support of Safety Related Electrical Equipment'. This response did not address ancillary concerns pertaining to storage of equipment in or near seismic category 1, safety related areas and equipment.
However, the licensee has implemented various administrative procedures that control such activities.
These procedures are of'a sufficient level of detail to preclude an adverse impact on safety related equipment by transient equipment. During tours of the facility, it was apparent that good housekeeping practices are now being implemented.
However, during the procedural review, and subsequently through field verification, the inspector identified a weakness in the station scaffolding program (Procedure SA-AP.ZZ-023(Q)).
This weakness is that the procedure was developed only on the oasis of withstanding a safe shutdown earthquake from power operations.- The procedure then serves as a format for compliance with a standing safety evaluation for scaffold erection. Although this approach provides sufficient guidance for erecting scaffold, etc., it does not provide sufficient oversight for implementation nor does it require sufficient review by qualified personnel to determine if a potential hazard exists to safety related or important to safety equipment required for all modes of operation. This weakness was evident through field review of scaffolding. The inspector identified scaffold that could have adversely affected the following Class IE conduit:
12BRXP26 (scaffold 87-050); 12XREN01 (scaffold 87-052) and, 12WRXN01 (scaffold 87-054). The scaffold was erected for, and approved by, the supervisor in charge of work related to BISCO seals in the plant.
Station QA reviewed the subject scaffold, in addition to other scaffold in the plant, and identified a number of deficiencies similar to those identified by the inspector.
The scaffold was immediately removed. Although the procedure provides the necessary guidance, implementation is not reviewed to determine if a condition adverse to safety exists.
This matter is considered unresolved pending licensee review of the scaffolding procedure.
(354/87-08-06)
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14 13.
Licensee Event Report Followup The licensee. submitted the following event reports during the inspection period. All of the reports were reviewed for accuracy and timely submission. The asterisked reports received additional followup by the inspector for corrective action implementation.
LER 87-001 Inadvertent Omission of Containment Atmosphere Grab
Sample Collection and Analysis LER 87-002 Inadvertent Control Room Ventilation System Isolation Resulting in CREF Actuation - ESF Actuation LER 87-003 Reactor Water Cleanup System Isolation Caused by Inadvertent Grounding of Test Equipment Due to Lack of Accessibility Inside Panels
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-* LER 87-004 Reactor Water Cleanup System Isolation Due to Spurious Signal Induced by Temperature Monitoring Modules LER 87-013 Loss of _ Reactor Protection System Bus "B" Due to
De-Energization of Motor Control Center LER 87-014 Forced Reactor Shutdown Due to Unidentified Leakage Greater Than 5 gpm and Subsequent Manual Scram Due to RSCS Rod Block When Shutting Down LER 87-015 Auto-Isolation of the Control Room Ventilation System Caused by Spurious Signal From Radiation Monitoring System LER 87-016 Automatic Start of Filtration, Recirculation, and Ventilation System Due to Unknown Causes LER 87-017 Reactor Scram During Performance of a Surveillance
Procedure on Reactor Water Level Instrumentation LER 87-018 Unanticipated Failure of MSIV to Close on Signal -
Blocked Port of Solenoid Valve Operator Special Filtration, Recirculation, and Ventilation Report System (FRVS) Post Accident Radiation Monitor Inoperable 87-002'
for More Than 72 Hours
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LER 87-001 describes a failure to collect and analyze grab samples from the containment atmosphere every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as required by Technical Specifications whenever the drywell leak detection noble gas monitor is out of service. Contrary to this requirement, samples were not taken for two days during the out of service period due to
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personnel error. Although this Technical Specification violation was licensee identifieJ, it was cited as a violation in Inspection Report 50-354/87-01 due to the. recurrent nature of this type of problem.
Additional details of this event are discussed in section 3.2 of NRC Inspection Report 50-354/87-01.
LER 87-004 discusses a reactor water cleanup (RWCU) system isolation which occurred when the " read / set" switch on a Riley tempmatic 86 temperature module was placed in the " read" position.
This action induced a spurious nuclear steam supply system channel
"A" isolation signal to the RWCU system which tripped both RWCU pumps and shut the RWCU inboard containment isolation valve HV-F001. This RWCU isolation was identical to the isolation reported in LER 86-051-00.
Prior to both isolations, Hope Creek had completed modifications to the module circuit board as recommended by General Electric Field Deviation Disposition Request dated February 7,1985 for Limerick which experienced similar RWCU isolations.
Hope Creek has decided to replace the temperature modules with a newer design which the manufacturer states eliminates spurious trip problem associated with the older modules. Hope Creek has also taken steps to minimize use of the " read / set" switch until the new temperature modules are installed.
LER 87-013 describes the loss of reactor protection system (RPS) Bus
"B" normal power when the motor control center (MCC) supplying power to the RPS motor generator set was de energized. The loss of RPS Bus
"B" initiated an engineered safety feature actuation (reactor water cleanup isolation) as well as other trip and trouble indications.
The MCC was de-energized when simultaneous breaker trips at the MCC and unit substation supplying the MCC resulted from plugging in a defective (partially grounded) piece of equipment into a lower tiered distribution panel. Corrective action included personnel training to verify portable electrical equipment is in proper working order prior to use.
LER 87-017 describes a reactor scram which occurred during the performance of an I&C surveillance procedure on reactor vessel level channel C32-K624C (narrow range, level 8). The technician performing the procedure placed the ohm meter leads across the wrong contacts which resulted in a level 8 turbine trip and scrammed the reactor.
The licensee's corrective actions included color coding and labeling of spade jacks on relay terminals which could, if shorted, cause a turbine trip.
The licensee has initiated a program to add precautions to all surveillance procedures with a high potential for initiating a full scram.
LER 87-018 details the events which resulted in the "A" inboard main steam isolation valve (MSIV) being declared inoperable after it failed to close from either the manual control switch or when the fused power supply was de-energized. The failure of the "A" MSIV to operate is currently attributed to a blocked vent path in the No. 1
solenoid in the pneumatic valve operator.
The root cause of the
j
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failed solenoid is still under investigation and' will be reviewe'd and tracked by the resident inspectors as open item 354/87-08-07.
Details of this event are discussed in section 3.2 of NRC Inspection Report 50-354/87-05.
14. SALP Management Meeting On April 7, 1987, a Systematic Assessment of Licensee Performance (SALP) management meeting was held betw"en the NRC and PSE&G at the licensee's administrative building on Artificial Island. A list of attendees is provided as enclosure I to this report.
15. Exit Interview The inspectors met with Mr. J.. Nichols and other licensee personnel periodically and at the end of the inspection report to summarize the scope and findings of their inspection activities.
Based on. Region I-review and discussions with the licensee, it was determined that this report does not contain information subject to 10 CFR 2 restriction f.:
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Enclosure 1 Hope Creek SALP Management Meeting List of Attendees Name Organization
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W. F. Kane NRC R. M. Gallo NRC L. J. Norrholm NRC R. W. Borchardt NRC D. K. Allsopp NRC D. H. Wagner NRC E. J. Ferland PSE&G C. A. McNeill PSE&G R. S. Salvesen PSE&G S. E. Miltenberger PSE&G A. K. Thompson-PSE&G B. A. Burricelli PSE&G R. W. Beckwith PSE&G J. N. Leech PSE&G U. J. Polizzi PSE&G B. A. Preston PSE&G C. P. Johnson PSE&G J. R. Lovell PSE&G G. C. Connor PSE&G R. F. Drewnowski PSE&G P. M. Krishna PSE&G-H. D. Hanson PSE&G E. A. Liden PSE&G B. H. Simons PSE&G E. L. Morris PSE&G D. M. Scott State of N.J.
D. J. Zannoni State of N.J.