IR 05000293/1999005
| ML20217E167 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 10/08/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20217E162 | List: |
| References | |
| 50-293-99-05, NUDOCS 9910190094 | |
| Download: ML20217E167 (31) | |
Text
,
U.S. NUCLE:AR REGULATORY COMMISSION L*
REGION I
.
License No.:
DPR-35 '
' Report No.:
99-05 Docket No.:
50-293 Licensee:
Entergy Nuclear, Inc.
~ Pilgrim Nuclear Power Station
'
600 Rocky Hill Road Plymouth, MA 02360 Facility:
_ Pilgrim Nuclear Power Station inspection Period:
July 26,' 1999, through September 5,1999 Inspectors:
R. Laura, Senior Resident inspector R. Arrighi, Resident inspecr A. Lohmeier, Senior Reactoc Engineer, DRS E. H. Gray, Group Leader, DRS R. S. Bhatia, Reactor Engineer, DRS Approved by:
S. Coffin, Acting Chief Projects Branch 5 Division of Reactor Projects l
l
'
9910190094 991008
["I PDR ADOCK 0S000293
-
G PDR
.
EXECUTIVE SUMMARY
,
Pilgrim Nuclear Power Station NRC Inspection Report 50-293/99 05 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers resident inspection for the period of July 26,1999, through September 5,1999; in addition, it includes the rest >!!s of an announced inspection by three regional engineering specialists.
Operations -
Operators responded effectively by using proper command-and-control and procedure
.-
usage in response to a turbine trip and resultant automatic reactor scram. (Section C2.1)
i The post trip review completed by operation support personnel focused on proper
.
,
equipment and system response. Plant equipment operated as expected. (Section O2.1)
Operators missed an opportunity to notify engineering to investigate and resolve the
.
moisture separator drain tank high level alarm and correct the condition prior to the reactor scram. (Section O2.1)
Maintenance Good pre-job briefs and procedure adherence were observed during maintenance and j
.
surveillance activities. (Section M1.1)
Equipment unavailability was being tracked properly during maintenance and
.
surveillance activities in accordance with the maintenance rule. (Section M1.1)
While a subsequent evaluation found this condition to be acceptable, the NRC concluded
-
that the licensec was slow to correct a degraded condition for a partially clogged, safety-related, salt service water system instrument line. (Section M2.1)
Several lower level equipment deficiencies were identified by the NRC during plant tours
.
which were either missed by the plant staff or not entered into the work control process for correction. These deficiencies represented a slight decline in problem identification of equipment deficiencies. (Section M2.2)
A review of work activities scheduled for the week of August 22,1999, revealed that the
.
licensee was properly imp!amenting their procedural requirements and considering the overall risk impact to th9 plant. Maintenance activities were properly managed to ensure the plant wasn't placed in a condition of significant risk. Proper controls were in place to
'
assess risk associated with the removal of equipment from service during power operation. (Section M3.1)
)
il
'
l j
, ;
Executive Summary (cont'd)
r.
'
Enaineerina I
.
.The cause of the reactor scram was attributed to instrument drift and improper calibration
..-
l of the moisture separator controllers. Contributing to this was a lack of integrated I
enginec ring analysis to support a modification that replaced the moisture separator drain
. and dump valves during the last refueling outage. (Section O2.1)
i
..
The follow-up inspection of the open items resulting from the NRC Architect Engineer team inspection 50-293/98-203 revealed that the licensee had addressed the significant i
issues. Fourteen of eighteen open items were closed Decause appropriate corrective actions were performed or scheduled. Two of these issues are classified as seventy level IV violations and are being treated as non-cited violations, consistent with Appendix C of the NRC Enforcement Policy. These violations involve: (1) failure to assure that
design bases are correctly translated into specifications and (2) failure to assure control j
design input in calculations and technical specification surveillances. These violations
{
are in the licensee's corrective action program as Regulatory Commitment 98.2096.01
/
and Problem Report 98.9536, respectively. (Section E8)
The licensee's corrective actions to address the inadequate diesel fuel supply were
.
adequate. Dedicated equipment is available to transfer fuel from the station blackout diesel to the emergency diesel generator storage tanks and procedural guidance is available to allow calculation of fuel consumption at various diesel loads. (Section E8.19) '
Plant Suooort
)
The NRC identified a problem with the boundary / posting of a high radiation area near the
.
west scram discharge instrument volume. This most likely resulted from human error by not re-establishing the boundary prnperly when exiting the area. 'Ihe interim corrective actions were judged to be good to prevent recurrence in the short tarm. This severity
'
- level IV violation is being treated as a non-cited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Problem Report 99.2032. (Section R1.1)
i
.
iii i
i
- t TABLE OF CONTEi4TS
.
EXECUTIVE SUM MARY.........................
.... ii
.......
....
Sum m ary of Plant Status................................................
.1 1. O P E RATI ON S...........................................
............. 1
.O1 Conduct of 0perations........................................ 1 01.1 General Com ments..................................... 1
'02 Operational Status of Facilities and Equipment..
...............1
...
,
O2.1 '(Closed) LER 50-293/99-08; Automatic Reactor Scram Due to Automatic
'
.
' Turbine Trip...........................
............ 1
'
II. MAINTENANCE..........................................
..
..........
M1 Conduct of Maintenance...................................... 3 M1.1 General Maintenance and Surveillance...................... 3 M2 Maintenance and Material Condition of Faclli6es and Equipment.........
M2.1 Partially Clogged SSW System Header Pressure Switch Sensing Line. 4 M2.2. Degraded Equipment Problem identification.........
..........6 M3 Maintenance Procedures and Documentation............
.7 j
........
M3.1 Risk Assessment Process............................... 7 111. E NG I N E E RI N G..................................................
.8 E8 Miscellaneous Engineering Issues................................ 8 E8.1 (Closed) Inspection Follow-up item (IFI) 50-293/98-203-01: Instrument Uncertainty Control and Application (E1.2.1.2.b)............... 8 E8.2 (Closed) IFl 50-293/98-203-02: Control of LOCA Analysis inputs and Updated Final Safety Analysis Report (UFSAR) Update (E1.2.1.2.c).
E8.3 (Open) URI 50-293/98-203-03: Reconciliation of Emergency Operating Procedure (EOP) Actions and UFSAR Assumptions Associated With Containment Flooding (E1.2.12.d).............................. 9 E8.4 (Closed) IFl 50-293/98-203-04 : Review of Licensee's Calculation and Review Method for Generic Letter (GL) 96-06 (E1.2.1.2.e and E1.2.4.2.d)
..................................................... 10 E8.5 (Open) IFl 50-293/98-203-05: Review of Revised EDG Loading Calculations (E1.2.2.1.a).................................... 10 E8.6 (Open) IFl 50-293/98-203-06: Review of Electrical Backfeed Analysis ( E 1.2. 2. 2.1.d)............................................ 10 E8.7 (Closed) IFl 50-293/98-203-07: Review of Electrical Penetration Protection (E1.2.2.2.1.d).................................. 11
' E8.8 (Closed) IFl 50-293/98-203-08 and LER 50-293/99-07: Review of Plant Modification to Resolve Degraded Bus Voltage Concerns (E1.2.2.2.1.f)
.................................................... 11 E8.9 (Closed) IFl 50-293/98-203-09: Review of Technical Specifications (TS)
' and Testing of New 480 VAC Relays (E1.2.2.2.1.f)..............
-iv
r
-
(..
.
.
i.
I.
-Table of Contents (cont'd)
l
,
E8.10 (Closed) IFl 50-293/98-203-10: Review of New Battery Sizing Calculations (E.1.2.2.2.2.a)
.............................13 l
E8.11 (Closed) IFl 50-293/98-203-11: Verification of Postulated Fault Current and Replacement Buses with Low Fault Current Ratings (E1.2.2.2.2.b)
l.
..................................................... 13 L
E8.12 (Closed) IFl 50-293/98-203-12: Follow-up Review of DC System and
!
Battery Terminal Voltage Calculations (E1.2.2.2.2.c)...........
E8.13 (Clased) URI 50-293/98-203-13: Adequacy of Design Controls Associated i'
With Controlling Changes With Calculation Comment Sheets and -
- Acceptability of TS Surveillance Test (E1.2.2.2.2.d, E.2.2.2.2.e, and
.
l E 1. 2. 3. 2. b)............................................... 14 E8.14 (Closed) URI 50-293/98-203-14: Adequacy of Design Controls Associated with ECCS Room Potential Flooding (E1.2.4.2.a)........
......
!
E8.15 (Closed) IFl 50-293/98-203-15: Review of Reactor Building Closed i
Cooling Water (RBCCW) Inservice inspection (ISI) Boundary
'
( E 1. 2.4. 2. b)............................................. 1 6 E8.16 (Closed) IFl 50-293/98-203-16: Vulnerability of RBCCW system to damage from a high energy line break (HELB) (E1.2.4.2.c)......
l E8.17 (Open) IFl 50-293/98-203-17: Review of Over-pressere Protection for Heat Exchangers in the RBCCW System (E1.2.4.2.e)...........
3 E8.18 ' (Closed) IFl 50-293/98-203-18: Design Control for Replacement Parts
~ (E 1.4. 2. b)............................................. 18
!
E8.19 EDG Fuel Oil Supply
.....................................19-IV. PLANT SUPPORT..................................................... 20
'R1 Radiological Protection and Chemistry (RP&C) Controls.............. 20 R1.1 High Radiation Area Boundary Problem...
.................20 H
V. MANAGEMENT MEETINGS...............................
............. 21 X1 Exit Meeting Summary........................................... 21 X3 Management Meeting Summary................................... 21 i
ATTACHMENTS
!
.
..
l
?" nhment 1 -Inspection Procedures Used Attachment 2 - ltems Opened,- Closed, and Updated Attachment 3 - List of Acronyms Used
i v
tr l
l m
e.1 REPORT DETAILS i
i
_ Summary of Plant Status
)
- Pilgrim Nuclear Power Station (PNPS) began this period operating at 100% reactor power.
Operators briefly lowered reactor power on July 29,1999, in response to a loss of feed water i
heating in the third point heater. On August 5,1999, a turbine trip and automatic reactor scram
.
occurred due to a high water level in the "A" moisture separator drain tank. After corrective
.
maintenance was completed, operators started up the plant on August 7,1999, and attained full power on August 10,1999.. The details of this event are discussed below in Section O2.1 of this report. The unit operated at or near 100% reactor power during the remainder of this inspection period.
l. OPERATIONS
~ 01 Conduct of Operations'-
01.1 General Comments (71707)
I Using inspection procedure 71707, the inspector conducted frequent reviews of ongoing
)
plant operations. The inspector observed proper control room staffing, effective pre-i evolutionary briefings, and expected plant response for the plant configuration and plant
' activities in progress. Any anomalies identified during NRC tours of the plant were reported to the nuclear watch engineer (NWE) for evaluation and corrective action, if needed. Shift tumover briefings led by the NWE were informative and provided a good synopsis of recently completed and upcoming activities. The inspector noted that operators performed well during plant restart following the automatic scram on August 5,
.1999. The unit was retumed to 100% power with no significant problems.
.
-02-Operational Status of Facilities and Equipment i
O2.1L - (Closed) LER 50-293/99-08: Automatic Reactor Scram Due to Automatic Turbine Trip'
a.
Insoection Scooe (71707. 93702)L The inspector reviewed integrated crew and equipment performance following an automatic reactor scram that occurred on August 5,1999, due to an equipment problem.
The inspector was in the control room immediately following the scram and directly observed operator immediate actions to stabiliza plant conditions. The post-trip review report and the related licensee event report ( LER) 99-08 were also reviewed.
b.-'
Observations and Findinos At 9:45la.m. reactor operators received a main turbine trip and anticipatory reactor scram. Operators stabilized plant conditions in accordance with procedure 2.1.6,
' Topical headings such as 01, M8, etc., are used in accordance with the NRC standardized reactor inspection report outline.
IndMdual reports are not expected to address all outline topics.
i
p
.
.
. Reactor Scram," and emergency operating procedures. The inspector observed
"
effective command-and-control by the nuclear operating supervisor (NOS). The NOS frequently briefed the operating crew on plant status and actions to be taken to place the plant in a stable condition. All equipment operated as expected during the transient with the exception of the "C" source range detector which could not be driven into the core.
Investigation into the cause revealed that a fuse in the drive circuitry had blown. The fuse was replaced, and the detector was inserted into the core.
Just prior to the reactor scram, the moisture separator " DRAIN TANK A LEVEL Hi" alarm annunciated in the control room. Operators initiated action in accordance with the alarm l
response procedure and checked the position of the moisture separator drain tank dump and level control valves. The dump valve indicated mid-position, and the level control valve was full open. The operators notified Instrument and Control (l&C) technicians to investigate the cause of the alarm. The NOS briefed the operating crew on potential
down power / scram actions due to the unstable moisture separator level condition. The rate of level rise in the moisture separator drain tank was not known or indicated in the control room. The l&C technicians had just left the control room to troubleshoot the problem with the moisture separator high level condition when the reactor scrammed.
Following the reactor scram, the licensee identified that the "A" moisture separator
controller had drifted snd that the controller had been improperly calibrated. This limited the ability of the dump valve to fully open. Problem report (PR) 99.9448 was wriiten to document the condition and determine the root cause. The licensee's investigation revealed an error in the calibration procedure.
. The licensee had previously revised the procedure used to calibrate pneumatic controllers prior to the refueling outage to enhance the calibration instructions.
Discussions with the licensee revealed that the vendor manual did not provide the
necessary guidance for making field adjustments to the Fisher pneumatic controller,
'
Prior to restad of the reactor on August 7, all eight Fisher pneumatic moisture separator controllers were replaced with like components and properly re-calibrated. The licensee indicated that there are no other Fisher controllers located in the plant.
The inspector notes the moisture separator and feedwater heating system has been
!
operating erratically since startup of the reactor in July 1999 from the refueling outage.
During the outage, the licensee implemented a plant design change (PDC) to replace the moisture separator and feedwater dump valves and control valves to address valve leakage and improve valve performance. The licensee was aware of the erratic response of the feedwater heating system. They had developed a temporary procedure (TP) and had contacted the vendor to assist in troubleshooting the cause. However, prior to implementing the TP, the plant tripped.
The inspector determined that the moisture separator instrument drift and the inadequate procedure guidance used to calibrate the moisture separator and feedwater heater controllers led to the. turbine trip / reactor scram. Contributing to the cause was the PDC, which replaced the moisture separator drain tank valves but did not fully evaluate the l
overall effect of the change on the associated controllers and the calibration procedure.
!
e
.
The moisture separator and feedwater heater level control systems are non safety-related components and outside the scope of 10 CFR 50 Appendix B, Quality Assurance Criteria. As a result, no violations of NRC requirements were identified. LER 50-293/99-08 is closed.
On August 5,1999, at approximately 4:30 a.m., five hours prior to the reactor scram, the previous operating crew had received the moisture separator drain tank high level alarm on three separate occasions within a half hour time frame. On each occasion, the alarm had come in and cleared immediately. The operating crew initiated a problem report for the alarming condition. Later, during the 7:30 morning production meeting, this problem report was reviewed by the maintenance department, at which time a plan was developed to investigate the cause of the alarms. Before the investigation could begin, the alarm occurred again, followed by the turbine trip and reactor scram. The NRC found the response of the operators to the earlier alarm conditions to not be sensitive to the possible consequences of malfunction of this equipment.
c.
Conclusions Operators responded effectively by using proper command-and-control and procedure usage in response to a turbine trip and resultant automatic reactor scram. The post trip review completed by operation support personnel focused on proper equipment and system response. Plant equipment operated as expected.
The cause of the reactor scram was attributed to instrument drift and improper calibration of the moisture separator controllers. Contributing to this was a lack ofintegrated engineering analysis to support a modification that replaced the moisture separator drain and dump valves during the last refueling outage.
Operators missed an opportunity to notify engineering to investigate and resolve the moisture separator drain tank high level alarm and correct the condition prior to the reactor scram.
II. MAINTENANCE M1 Conduct of Maintenance M1.1 General Maintenance and Surveillance a.
1.nsoection Scope (61726/62707)
The inspector observed portions of selected maintenance and surveillance activities to verify that the applicable procedures were used and technical specifications requirements were satisfied. The licensee's actions for monitoring the effectiveness of maintenance were also reviewed against the requirements of 10 CFR 50.65 "The Maintenanca Rule."
-
--
g H
!:l.:.-
L
.
!
b.
' Observations and Findinas
.
The inspector observed all or portions of the following activities:
!
. Surveillance Procedure (SP) 8.M.2-2.5.6. "HPCI Condensate Storaae Tank I,ege_L-Functional Test" l
The inspector observed the performance of SP 8.M.2-2.5.6. Good procedure adherence
. was displayed by the maintenance craft. Operators properly declared the high pressure i
coolant injection (HPCI) system inoperable during the performance of the surveillance and system unavailability was tracked in accordance with the maintenance rule.
Temoorary Procedure (TP)98-034. " Performance Evaluation of Feedwater Heat System Valves" The inspector attended the pre-job brief and monitored the performance of procedure TP 98-034. The procedure obtains operational data which would be used to adjust eighteen -
new feedwater heater system dump and control valves installed during refueling outage (RFO) 12. The detailed brief included a discussion of recent problems with hook-up of
)
test equipment. Good procedure adherence was displayed during the performance of the TP.-
,
Maintenance Reauest (MR) 19901865 Re-balance the "E" Salt Service Water (SSW)
Pump l
- The inspector monitored the performance of the maintenance activity for re-balancing the
"E" SSW pump. In-service test data revealed that the pump vibration had increased and had just entered the alert range. Pump performance improved followirs re-balancing.
l No significant problems were observed during the work activity.
c.
Conclusions The inspector observed good pre-job briefs and procedure adherence during maintenance and surveillance activities.
The licensee properly tracked equipment unavailability during maintenance and j
surveillance activities in accordance with the maintenance rule.
M2 Maintenance and Material Condition of Facilities and Equipment i
i M2.1. Partially Cloaoed SSW System Header Pressure Switch Sensina Line a.
Insoection Scoos.
l The inspector review d the potential significance of.and planned corrective maintenance for a partially clogged sensing line for pressure switch PS-3829A located in the "B" train SSW discharge header. There are two pressure switches for redundancy purposes in i
l
m
.
.
both the "A" and "B" SSW train discharge headers. PS-3829A is safe'priated and provides for automatic start of the "D" and "E" SSW pumps during ceh accident conditions, as well as for the swing "C" SSW pump if it is aligned to the *B' train, l&C technicians identified this deficiency en June 4,1999, during RFO 12 while venting the sensing line. The l&C technicians generated PR 99.9308 to document, evaluate and correct this deficiency.
l.
- b.-
Observations and Findinas On August 17,1999, the inspector reviewed the work control status of MR 19901186 that was issued to perfc m the corrective maintenance on PS-3829A. This MR was coded as l
a priority level 3 (relatively low priority) and was in the initial stages of work control i
planning (status P) with no work package developed. The licensee informed the
'
inspector that this work was not scheduled until the first quarter of calendar year 2000, at least six months after the problem was identified. The inspector determined that the partially clogged safety-related SSW system sensing line received little attention and was handled as a low priority by work control.
The inspector interviewed the l&C technicians who initially identified the partially clogged
. sensing line. At that time the line was vented, water did not flow from the line for about 1
!
minute with the SSW discharge header pressure at approximately 35 psig. Then water
!
began to slowly trickle from the line, but at a rate significantly less than the three other SSW discharge header sensing lines. The I&C technicians promptly issued PR 99.9308 l
to document this deficiency. The inspector determined that the l&C technicians performed very well by identifying the problem and entering it into the licensee's corrective action process.
The inspector reviewed how the licensee processed PR 99.9308 and discovered that no detailed operability evaluation had been performed. The licensee considered the SSW system operable based on the redundant pressure switch in the same header which has its own sensing line.. Initially, PS-3829A was declared inoperable during RFO12 and a limiting condition for operation (LCO) entry was made against the SSW system. But later, just prior to performing an emergency diesel generator (EDG) load shed test,
. operations personnel cleared the LCO entry based on the availability of the redundant pressure switch and the fact that some water dribbled out of the degraded sensing line.
The inspector expressed concem about the uncertainty involved with the degradation of the partially clogged sensing line. The licensee hypothesized that the disc in the root
'
valve for the sensing line had become dislodged and was blocking flow, or that there was (
debris or some type of fouling in the sensing line. The inspector also expressed concem l
about the potential for a common mode failure of the four sensing lines and the importance of the pressure switches which allow the system to perform its intended I
design basis functions. As a result of the inspector's concems, the licensee initiated a i
. detailed operability evaluation that concluded that the SSW system was degraded but operable. The engineering staff strongly recommended that the line blockage be cleared as soon as possible. Additionally, a compensatory measure was established to vent the degraded sensing line once per month to monitor the condition of the line and to ensure
,
F
!
-
i
!
- l the line was not completely blocked. The inspectorjudged that this operability evaluation was of good quality.
l Later during this period, the licensee attempted to repair the partially blocked SSW system sensing line but was unable to close the Joot valve and establish a work boundary. The licensee decided not to secure the "B" train SSW discharge header while
i the plant was in operation due to the increased risk significance of that plant configuration. At the end of this period, the licensee was evaluating other options such as the use of a freeze seal to isolate the degraded sensing line. The degraded sensing line will remain as an inspector follow item (IFl 50-293/99-05-01) pendir:g the reso!ution and identification of the full problem scope.
c.
Conclusions A partially clogged, safety-related SSW system sensing line identified during RFO 12, which ended in July 1999, had not been corrected nor scheduled for repair until calendar year 2000. An operability evaluation had not been performed until questioned by the inspector, and subsequent repairs during this period were unsuccessful due to a stuck root valve. While a subsequent evaluation found this condition to be acceptable, the NRC concluded that the licensee was slow to correct the degraded condition.
M2.2 Dearaded Eouloment Problem identification (62707)
j a,
inspection Scope The inspector toured the reactor building, EDG rooms and screen;.ouse to assess whether or not plant staff identified equipment deficiencies and entered them into the work control and/or corrective action system.
b.
Observations and Findinas The licensee staff identified many deficiencies and correctly entered them into the work control and/or corrective action system. However,.he inspectors found several lower level degraded equipment conditions that were eithe not known by the licensee staff or not entered into the work control system for correction. The inspectors identified the following problems:
packing leakage from core spray system valve 1400-2 broken HPCI system electrical conduit for valve CV-90618.
- significant air leak in C-89 ventilation panel for the "A" EDG room.
+
HPCI system test return line check valve hinge pin leakage.
t
-
l broken clamps on the recirculation motor-generator set scoop tube box covers.
- n I
.
I
,-
debris located under the HPCI system turbine and used anti-contamination
-
clothing laying on the floor in back of the west scrum discharge instrument volume.
i in each case, the inspector notified the NWE or system engineer of the deficiency. The licensee promptly corrected or entered the problem into the work control system for corrective action. None of these deficiencies resulted in an immediate operability problem. The inspector had no further questions or concerns. The operations department manager subsequently briefed operations personnel on the importance of identification of equipment deficiencies at an early stage.
c.
Conclusions Several lower level equipment deficiencies were identified by the NRC during plant tours that were either rnissed by the plant staff or not entered into the work control process for correction. These deficiencies represented a slight decline in problem identification of equipment deficiencies.
M3 Maintenance Procedures and Documentation M3.1 Risk Assessment Process a.
Inspection Scope. (62707)
The inspector reviewed the scheduled on-line maintenance activities for the week of August 22,1999, with regards to its impact on overall plant risk. The inspector also verified that the licensee followed the guidelines contained in PNPS procedure 1.5.22,
" Risk Awessment Process."
~ b.
Obsefvations and Findinos The licensee plans work activities for the various systems / components based on a rotating 13-week maintenance cycle. The licensee evaluates the risk associated with equipment being out-of-service using probabilistic risk assessment. In addition, as part of the schedule development, a risk assessment team performs a final review of the scheduled work activities during the week prior to the work week implementation. The team is comprised of a representative from operations (senior reactor operator),
integrated scheduling and maintenance.
The team reviews the schedule to assess existing plant conditions (equipment tagged
{
out of service and degraded equipment conditions) and external factors such as the j
weather. The team specifies any restrictions and compensatory measures for items that
,
pose an increase in risk. Once completed, an equipment out-of-service (EOOS) risk profile is generated. The work week manager then develops a risk assessment profile
{
(i.e., planned schedule, existing equipment status, EOOS profile and compensatory
l measures sheets) that is reviewed and approved by plant management. Once
)
o
.
.
approved, the profile is given to the control room and maintenance departments prior to work week commencement.
The inspector reviewed the list of work activities scheduled for the week and did not
'
identify a major risk to the plant. The inspector noted that a copy of the risk package is
. maintained in the control room so that it is available for review. Discussion with the NWE revealed that he was aware of the risk significant maintenance activities scheduled to be worked and understood the risk assessment process.
c.
.Qonclusions A review of work activities scheduled for the week of August 22,1999 revealed that the licensee was properly implementing their procedural requirements and considering the overall risk impact to the plant. Maintenance activities were r operly managed to ensure the plant wasn't placed in a condition of significant risk. Prcper controls were in place to assess risk associated with the removal of equipment from service during power operation.
111. ENGINEERING E8 Miscelleneous Engineering issues E8,1 (Closed) Inspection Fellow-up it
- l) 50-293/98-203-01: Instrument Uncertainty Control and Acolication (E1.2.1.21 The NRC A/E team found that PNPS did not have a clear documented basis for i
instrument uncertainties in the residual heat removal (RHR) pump surveillance test acceptance criteria and in the loss of coolant accident (LOCA) analyses. This is a
_ generic issue for boiling water reactor (BWR) plants of the same vintage as PNPS. At the time of the inspection, the licensee discussed plans to establish and document the q
basis for instrument uncertainties and how this information v' dd be applied to the
- analyses and operation at PNPS.
l
- The licensee found that instrument uncertainty was not a:
, sed for many instrument
,
loops, and that there was no philosophy for instrument unca tainties to ensure consistent determinations in calculations for the varying analyses and plant operations. The Design Basis improvement (DBI) Group at PNPS developed a formal position on the requirements for instn *Mt uncertainty ca!culations and reflected this in topical design basis document TDBD-113, " Topical Design Basis Document for Instrument Uncertainty."
During this inspection, the NRC reviewed TDBD-113 and found that it clearly documented the bcses for the licensing and design requirements in Section 2.0 of the report, including Section 2.3.4, " Pump Testing for IST." Test acceptance was based on
"as-read" indications from instruments meeting the requirements of ASME Section XI, Subsection lWP, and/or ASME/ ANSI Standards, as delineated in the PNPS inservice
L
~
l
\\
'
!
j.
L
!
-
l-testing (IST) program. In accordance with the ASME Code requirements, reference test conditions were established when a pump was known tc be operating acceptably, and
)
then trended such that degradation from predetermined limits would result in declaring
'
l.
the pump inoperable and require corrective action. The NRC reviewed the in-service inspection pump test data sheet (RHR Pumps P-203A/B/C/D) and found that the pump performance met the required flow / head test values. The NRC also found that the test l
equipmer t calibration data was satisfactorily recorded and reviewed.
<
The NRC found that Section 2.3.5 of TDBD-113, " Appendix K LOCA Analysis," provided a LOCA evaluation model developed in accordance with 10 CFR 50.46 requirements
,
!
and was sufficiently conservative to account for instrument uncertainty. Because the
!
licensee has developed a formal position on instrument uncertainty, met the ASME Code accuracy, range, and general requirements for pump testing, and provided a position on instrument uncertainty related to LOCA analysis, IFl 50-293/98-203-01,a closed.
!'
ES.2 (Closed) IFl 50-293/98-203-02: Control of LOCA Analysis Inouts and Updated Final
_Sp_fety Analysis Report (UFSAR) Update (E1.2.1.2.c)
l The NRC A/E team identified two concerns related to Safety Evaluation (SE) 2989, in which the licensee evaluated the impact of increasing overall injection delay time from
l 49.7 to 54.6 seconds for the desigr. basis LOCA analysis input. The increased swing
bus time was evaluated as acceptable, but no UFSAR changes were identified to reflect changes in ths LOCA analysis. The team concluded that the UFSAR should have been revised to reflect the impact on the low pressure coolant injection (LPCI) time delay, and that documentation of calculations should be provided with independent verification.
l The licensee performed timing calculations of power emergency buses to verify the total time required for the EDG to power the 4.16 kV emergency buses, and the 480V bus B2 to power the swing bus B6 for a postulated design basis accident (DBA) LOCA l
coincident with a degraded voltage condition and a postulated DBA LOCA coincident with a loss of offsite power (LOOP) event.
i l
During this inspection, the NRC reviewed calculations in PS-230 Rev 1, confirmatory test l
results of power bus timing, and independent verification of the calculations. The NRC found the calculations and confirming test results acceptable, and the results were reflected in UFSAR Section 6.5. IFl 50-293/98-203-02 is closed.
E8.3 (Ooen) URI 50-293/98-203-03: Reconcifistion of Emeroency Ooeratino Procedure (EOP) Actions and UFSAR Assumptions Associated With Containment Floodino (E1.2.12.d)
The NRC A/E team four:.d an apparent lack of reconciliation of EOP actions and UFSAR
,
assumptions regarding the use of containment flooding and venting as DBA LOCA
!
mitigation strategies. Differences in required assumptions in the UFSAR and other design basis information remained to be reconciled.
!
L
f
10
+
(.
The plant specific EOP for vessel flooding was part of the licensee implementation of industry-endorsed Severe Accident Guidelines (SAG). The flooding concern impacted the SAG and was discussed at BWR Owners Group (BWROG) meetings in early 1999.
The licensee is still evaluating this concern and will continue to pursue this issue with the BWROG. Resolution of this issue is scheduled for completion before the end of the 1999. Pending resolution and any needed corrective actions, UR? 50-293/98-203-03 remains open.
E8.4 (Closed) IFl 50-293/98-203-04 : Review of Licensee's Calculation and Review Method l
for Generic Letter (GL) 96-06 (E1.2.1.2.e and E12.4.2.d)
NRC GL 96-06, " Assurance of Equipment Operability and Containment Integrity During Design-Basis Accident Conditions," addressed the potential for over-pressurization of isolated water-filled piping sections in containment. The licensee identified six drywell penetrations that were subject to thermal pressurization, including an RHR shutdown cooling suction line that had 5 feet of piping in the containment exposed to elevated temperature during a postulated DBA. The A/E team identified two concerns with the licensee's supporting calculation that required additional NRC review of the licensee's analysis to ensure pipe stress limits are not exceeded.
During the current inspection, the NRC reviewed a revised analysis and found that the calculated stress was within ASME Code faulted stress limits. We noted that although the licensee previously had performed several calculations that contained input discrepancies, these were corrected and the isolated water-filled containment piping sections under accident heating conditions were verified to be within ASME Section lli i
!
Code faulted stress limits. IFl 50-293/98-203-04 is closed.
'
E8.5 (Open) IFl 50-293/98-203-05: Review of Revised EDG Loadina Calculations (E1.2.2.1.a)
The NRC A/E team identified two programmatic concems with the control of EDG Ioading calculations. The calculation procedure did not require.a mandatory calculation revision when information changed.- Also, there were no procedural controls in place to maintain a running total of loads added to the EDG nor criteria for when the calculation should be revised.
Pilgrim is conducting transient analyses for EDG loading under accident and turbine trip conditions. Additional program controls are being addressed through a calculation enhancement program and controls for calculation prioritization and configuration management will be developed as part of the DBI program. Pending completion of these corrective actions, IFl 50-293/98-203-05 remains open.
E8.6 - (Ooen) IFl 50-293/98-203-06: Review of Electrical Backfeed Analysis (E1.2.2.2.1.d)
l I
The NRC A/E team noted the absence of supporting analysis for acceptab% voltages l-under back feed of the electrical distribution system through the main and,,xiliary transformers. The licensee plans to complete formal load flow / voltage drop by the end of f
L
.
,
the third quarter of 1999. Pending completion of the analysis, IFl 50-293/98-203-06 will remain open.
E8.7 ' (Close@ IFl 50-293/98-203-07: Review of Electrical Penetration Protection (E1.2.2.2.1.d)
.
The NRC A/E team identified that the electrical penetrations at PNPS were not designed to withstand a fault current assuming a single failure of the protective device. The team's concern was that if the breaker fails to open during a fault, the containment pressure integrity could be lost. The team also noted that the existing design with one protective device was consistent with the licensing basis. However, the licensee's design bases required the electrical system to meet the redundancy, independence and single failure criteria as defined in IEEE 308-1969, " Class 1E Electric Systems for Nuclear Power Generating Stations."
In response to the team's concern, the licensee committed to increase the surveillance frequency of safety-related and nonsafety-related breakers from the existing six and eight years intervals to four year intervals, in addition, they also committed to upgrade the penetration circuit protection for nonsafety-related circuits.
During this inspection, the NRC verified that the licensee had adequately revised the master surveillance tracking program to reflect the above surveillance interval changes.
The inspectors reviewed the last surveillance conducted on several breakers and identified no concems regarding the testing interval. The inspectors also confirmed that the licensee engineering staff had initiated a formal request to upgrade the nonsafety-related penetration protection devices. The completion of this task is scheduled for the end of September 1999. IFl 50-293/98-203-07 is closeci.
E8.8 (Closed) IFl 50-293/98-203-08 and LER 50-293/99-07: Review of Phnt Modification to Resolve Dearaded Bus Voltaoe Concems (E1.2.2.2.1.f)
During the NRC A/E team inspection, the team noted that timing of the degraded bus relays to support the operation of 4160 volt buses from EDGs was not consistent with the i
accident analysis. Specifically, the core spray (CS) pump breakers could potentially trip during sequencing. Also, the licensee discovered that during a degraded voltage condition coincident with a LOCA, the EDG would not oe available to support the accident loads in the required timo assumed in the LOCA analysis.
As documented in NRC Inspection Report 50-293/98-06, a non-cited violation was issued for inadequate implementation of the 4.16 kV degraded voltage protection logic
,
'
that was described in Licensee Event Reports (LER) 50-293/98-014 and 98-015. The peak clad temperature analysis indicated a 15' F increase (to 1836* F), which was within the design basis temperature of 2200* F. The licensee's lona term corrective actions d
were scheduled to be implemented during the April 1999 refueling outage.
During this inspection, the NRC noted that the licensee had implemented s plant modification (PDC 99-05) that reduced the time to restore power for injection from the original 21 seconds to approximately 15.45 seconds. This time was selected based
p
.
L
.
upon the licensee's evaluation of the limiting LOCA analyses. The licensee had determined that the most limiting case of LOCA analysis was the design basis loss of
- coolant accident (DBLOCA) with a loss of off-site power (LOOP) and a single failure of the LPCI injection valvec This case bounded the case involving LOCA with degraded
.
voltage. The NRC found this analysis and modification (corrective action) to be reasonable. However, subsequent to implementing this modification, the licensee discovered a potential failure mode that could result in bus B6 remaining de-energized following a LOCA coincident with degraded grid voltage. As a result, LER 99-007 was issued. The inspectors reviewed engineering evalration (EE)99-065 that determined
.
that the existing guidance contained in PNPS procedures 2.4.14.4 and 2.1.5 was
,
sufficient to ensure that safety-related components would operate during a degraded voltage condition. The inspectors reviewed the procedures and verified that steps taken
to mitigate this condition were adequate.
i The licensee attributed the cause of these discrepancies to personnel error during the j
development of the modification. The licensee determined that all possible scenancs i
were not considered during the design process. The pre-charge time required for closing springs in bus B6 transfer breakers52-102,601, and 602 was not considered.
Furthermore, a legend on the electrical drawings indicating breaker operation design and pre-charging time was deleted, along with a lack of a complete design basis document for the 480V and 4.16kV distribution system.
l The failure to assure that applicable design bases were correctly translated into i
specifications, drawings, procedures, and instructions, specifically in PDC 99-05, for a safety-related equipment is a violation of 10 CFR 50, Appendix B, Criterion lil, " Design
- Control." This severity level N violation of NRC requirements is being treated as a non-
.
'
cited violation (NCV) in accordance with Appendix C to the NRC Enforcement Policy (NCV 50-293/99-06-02). This condition was promptly captured by the licensee in their corrective action reporting system (Regulatory Commitment (RC) 98.2096.01). The licensee immediately performed an operability evaluation and provided appropriate
!
administrative controls. The licensee's short term actions were comprehensive and long i
term planned corrective actions were being tracked as part of their corrective action program. Based on the corrective actions to address the original issue, IFl 50-293/98-203-08 and LER 50-293/99-07 are closed.
E8.9. (Closed) IFl 50-293/98-203-09: Review of Technical Soecifications (TS) and Testina of New 480 VAC Relavs (E1.2.2.2.1.f)
During the review of a safety evaluation, the NRC A/E team determined that the licensee did not discuss the effect of the installation and testing of the new relavs on the TS. The
- team was concemed that the 10 CFR 50.59 safety evaluation procedure, P83E5,
,
" Safety Review," Revision 12, did not contain the requirement to review for TS impact.
'
!
in their response to this concern, the licensec stated that they review PDCs and changes to the UFSAR for TS impact. The TS review in this case for the 480 VAC relays was L
done against the four criterion contained in 10 CFR 50.36, " Technical Specification."
This review found that this instrumentation did not qualify for inclusion in the TS.
..
Y
'
,
To address the instances where safety evaluations performed for reasons other than for modifications or UFSAR update may require TS impact review, the licensee revised the above procedure and added additional clarifications to address this concern. The inspectors reviewed the updated safety review procedure and found it adequate. IFl 50-293/98-203-09 is closed.
J E8.10 (Closed) IFl 50-293/98-203-10: Review of New Battery Sizina Calculations (E.1.2.2.2.2.a)
During the review of upgraded battery system calculations, the NRC-A/E team identified i
several discrepancies in the input data of the DC battery sizing analysis. After accounting for the outstanding load discrepancies, the licensee determined that the station battery margin was in accordance with IEEE 485. This issue remained open
_ pending resolution of the discrepancies in revised calculations.
!
The inspectors noted that the licensee had updated all battery sizing calculations
(redundant 125 VDC batteries (PS-233B &C) and 250 VDC battery (PS-283D)). The ine.pectors found that battery sizing calculations were performed in accordance with the requirements of IEEE 485. Review of the revised input data used the worst case sizing analysis (PS-233A). Discrepancies documented in NRC inspection report 50-293/98-203 were appropriately included in the calculations to determine each battery's margin.
The inspectors' review of the above calculations indicated that each battery had sufficient margin (approximately 18% in the 'A' and 5% in the 'B' 125 VDC batteries, and 30% in 250 VDC battery). IFl 50-293/98-203-10 is closed.
E8.11 (Closed) IFl 50-293/98-203-11: Verification of Postulated Fault Current and Reolacement Snes with Low Fault Current Ratinas (E1.2.2.2.2.b)
The NRC A/E team found that the licensee had no DC system calculation to show -
available fault currents for the new batteries installed in 1993 and 1994, in accordance with PDC 93-28. In addition, the engineering evaluation performed (EE 96-083) in i
response to PR 91.2241 also predicted higher DC fault currents due to the lack of current-limiting capability of the fuses in the main battery leads and possibly five buses i
(D4, D5, D10, D16, and D17), in the DC distribution system for the three station batteries. This issue was left open pending the licensee's verification of postulated fault currents and replacement of buses or fuses with appropriate fault ratings.
The inspectors verified that the licensee developed a DC system short circuit calculation (PS-227). To improve the coordination of the DC system, the licensee also performed
,
Leoordination study, PS-31-5. As a result of these analyses, PDC 98-26 was prepared to increase the ratings of four of the DC buses (D4, D10, D16, and D17). In addition, the licensee also replaced the existing main in-line fuses of all DC batteries. Several other
.
DC fuses in-series with breakers in distribution panels were replaced to achieve an optimized coordination of the DC distribution system. The inspectors verified that the assumptions made and the load input data in the above analyses were appropriate. The
- inspectors performed a walk-down of the DC system and verified that the new equipment
i
.
<
,
in the above DC buses and newly installed fuses in selected panels were consistent with the required design rating. IFl 50-293/98-203-11 is closed.
E8.12 (Closed) IFl 50-293/98-203-12: Follow-uo Review of DC System and Batterv Terminal Voltaae Calculations (51.2.2.2.2.c)
The NRC A/E team questioned whether DC end devices had sufficient voltage under postulated worst-case battery discharge voltage condition. The licensee's existing calculation had calculated the available voltage up to the distribution panel level only, as opposed to the DC end device. In addition, the expected minimum battery terminal voltage during the battery discharge cycle was not determined through analysis. The team also noted that the licensee made previous design changes to improve system performance by replacing feeder cables to DC distribution panels and motor control centers and replacing the DC motor operated valve operators. In response, the licensee stated that the DC system and battery terminal voltages were being re-verified as part of the calculation enhancement program.
As discussed above in section E8.10, the licensee revised and upgraded the DC system calculations. The inspectors reviewed the DC system end device calculation results and noted that all required end devices had sufficient voltage to perform their intended design functions under the worst case battery discharge cycle. However, some devices were found to have less than adequate voltage prior to one minute at the end of an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> discharge cycle. The licensee performed further re-evaluation considering the actual required function of the device in the load discharge cycle, and found that all required devices were acceptable during normal and abnormal plant conditions because they were required to be operated in earlier time sequence, when the available terminal voltage was higher and acceptable. The inspectors' review of the calculations indicated that each battery terminal voltage at the end of the discharge cycle would be 112.42 at the "A" and 107.21 at the "B" 125 VDC redundant batteries and 227.68 Volt at the 250 VDC battery terminal. Based on the above review and adequate corrective action taken by the licensee, IFl 50-293/98-203-12 is closed.
E8.13 (Closed) URI 50-293/98-203-13: Adeauacy of Deslan Controls Associated With Controllina Chanaes With Calculation Comment Sheets and Acceptability of TS Surveillance Test (E1.2.2.2.2.d. E.2.2.2.2.e. and E1.2.3.2.b)
The NRC A/E team found five instances in which PDCs did not properly indicate the need to revise affected documents. The team determined that the licensee had no formal procedure for tracking and controlling DC loads other than by revision of the appropriate DC calculations, or by calculation comment sheets outstanding againct the same calculations. Also, the NRC noted that the licensee had not established calculation revision criteria, such as a periodic time limit, the number of outstanding calculation comment sheets, or a set value of DC load changes in kW. As a result, a service test performed on 'B' battery did not envelop the loading profile of record. At the time of inspection, the licensee wrote PR 98.9536 to document the team's concern and to evaluate battery operability. These issues were treated as an unresolved item, pending PNPS resolution, NRC review of the licensee's corrective actions to address the
. adequacy of the TS battery surveillance test, and resolution of design control weaknesses found from the team inspection.
To address the weaknesses in the programmatic areas, the inspectors noted that PNPS l-revised the design calculation procedure, NE3.05. For significant changes made in
!-
calculation comment sheets (CCS), the procedure now requires that the effects of each L
calculation be independently reviewed, and the CCS should include the calculation l
- number, its revision number, and a sequential number. The CCS assigned to each
!
calculation will be indexed as an associated record of the parent calculation in the record l
. management system. The inspectors verified that all discrepancies noted in the NRC-
. A/E inspection report regarding modification changes affecting the DC system
.
calculations were appropriately resolved in the revised calculations. During review of the
'
training records and discussions with the engineering personnel, the inspectors determined that the engineering ctaff was trained to recognize weaknesses of design control and was aware of the revised procedure.
l To address the issue with the service test performed on "B" battery that did not envelop the loading profile as specified in calculation PS47H, Revision 01, the licensee re-evaluated the DC loads in' the calculation. The licensee determined that the "B" Turbine Building Component Cooling Water (TBCCW) (P110) load was assumed to be operating (closing) at the same time the emergency core cooling system (ECCS) load breakers were closing. However, during a LOOP with LOCA scenario, the TBCCW "B" breaker would be tripped via the load shed logic or loss of voltage relay. The licensee detcrmined that when the power at the emergency bus A6 is restored, breaker B206 will i
close and the P-110B pump will start in 36 to 44 seconds but only if the "A" pump fails to start. The closing of this breaker does not commence until 40 seconds which is beyond the ECCS pump breaker sequencing time (20 seconds including the spring charge time).
i In addition, three tie-bus breakers (B102,601 and 605) on circuit D6-14, had been tripped prior to initiation of EDG and ECCS breaker closing circuits. As a result, the revised loading in the initial profile peak was reduced to 425.7A, which was found lower than the test value of 427A. Based on the review of the revised load data in the i
calculation and other applicable documents, the inspectors' determined that the licensee i
had adequately satisfied the TS requirements.
The failure to ensure control of design input in calculations and TS surveillance for a i
safety-related equipment is a violation of 10 CFR 50, Appendix B, Criterion Ill, " Design Control." This severity level IV violation of NRC requirements is being treated as a non-cited violation (NCV) in accordance with Appendix C to the NRC Enforcement Policy (NCV 50-293/99-06-03). This condition was promptly captured by the licensee in their corrective action reporting system (PR98.9536). The licensee upgraded the applicable procedures, and provided adequate training to staff personnel to establish measures to preclude recurrence. In addition, the revised calculation verified that the battery "B"
!
surveillance test satisfied the TS requirements. The inspectors determined that the licensee's corrective actions were prompt and comprehensive. URI 50-293/98-203-13 is closed.'
l
r
.
.
E8.14 (Closed) URI 50-293/98-203-14: Adeauacy of Desian Controls Associated with ECCS Room Potential Floodina (E1.2.4.2.a)-
The NRC A/E team expressed concem for potential common mode flooding of the torus room and the four safety-related ECCS equipment room quadrants as identified in inspection & Enforcement Circular No. 78-06, " Potential Common Mode Flooding of ECCS Equipment Rooms at BWR Facilities." The team questioned whether the licensee considered all sources of leakage and flooding to assure that multiple ECCS equipment rooms are not impacted by a single quad room flooding event.
Licensee engineers previously walked down the quadrants, the torus, and the HPCI turbine rooms. With the exception of the reactor core isolation cooling (RCIC) turbine drip tray connection, the as-found drain piping system would preclude multiple system flooding upon flooding a single quadrant. Addressing this exception would preclude a single failure affecting all quadrants. Other than the drip tray concern, three quadrants were found to require only minor physical maintenance or modification.
During the current inspection, the NRC reviewed the radwaste collection system piping and instrument diagram (P&lD), M232, and the condition of the floor (chemical) drains and equipment drains in the ECCS torus and quad rooms. Photographs of the drain conditions were sampled and direct observations of the drain conditions were made in the HPCI and RCIC rooms. From these reviews, observations, and an interview with the responsible engineer, the inspectors concluded that the floor drains are normally valved shut in the HPCI room before reaching the collection sump. Additionally, the equipment drains are hard piped to their respective collection points such that back flooding through the floor and equipment drains from one room to any of the other four ECCS rooms is prevented by design and the equipment configuration. Hardware problems noted by the NRC A/E team were found to have been corrected. Two new issues, as
'
documented in problem report PR 99.2088.00, were identified during the walkdown.
These are the need to correct designations on P&lD M232, and the absence of guidance in procedure PNPS 2.5.2.71 to preclude the opening of more than one of the quad / torus room drain lines at the same time. The A/E findings have been addressed adequately, and the new items have been documented properly in a problem report for resolution and action. No violations of NRC requirements were identified. URI 50-293/98-203-14 is closed.
E8.'15 (Closed) IFl 50-293/98-203-15i Review of Reactor Buildina Closed Coolina Water
'
(RBCCW) inservice Inspection (ISI) Boundarv (E1.2.4.2.b)
j The NRC A/E team reviewed classifications sf various piping systems and was unable to
'
determine the basis used for an ISI boundary change from Class 3 to Class 0 at the.
normally open RBCCW non-essential loop isolation valves. This non-essential portion of
- the RBCCW system requires operator action to prevent a loss of Inventory on pipe
.. failure. it did not appear that a failure in the non-classified system could be isolated in time to prevent loss of RBCCW loop inventory.
,
_I
,
.
The licensee initiated PR 98.9531 to determine appropriate classification of the ISI boundary change by using guidance from the UFSAR Specification M-300 Rev. E40,
"P; ping," ANSI 52.1, " Nuclear Safety Criteria for the Design of Stationary Boiling Water Reactor Plants," and Regulatory Guide 1.26, " Quality Group Classifications and Standards for Reactor Plants." The licensee concluded that, although ASME safety classifications will not be applied, the PNPS Class 1 - Pressure Boundary Only designation requires a level of inspection generally consistent with ASME Section XI Class 3. methods and criteria for non-essential portions of the RBCCW system. Also, the
.
licensee established an Augmented Inspection Program (AIP) for the RBCCW non-essential piping and components. This program will be administered as part of the Quality Assurance AIP for non-essential piping and components and appropriate revisions will be made to inspection specifications, quality assurance criteria, and drawings to the new requirements.
The licensee considered all alternatives to preclude loss of RBCCW loop inventory in PR 98.9531. Engineering evaluation EE 98-0081 found that the RBCCW was and remains operable. This was based on current ASME Class 3 visual ISI examinations and in-service monitoring performed by operations for non-essential components that support normal operation.
Based on the completion of pipe reclassification, implementation of an augmented inspection program, and a determination of the RBCCW system operability, IFl 50-293/98-203-15 closed.
E8.16 (Closed) IFl 50-293/98-203-16: Vulnerability of RBCCW system to damaae from a hiah i
gnerav line breaP (HELB) (E1.2.4.2.c)
NRC Information Notice (IN) 89-55, " Degradation of Containment Isolation Capability by a High Energy Line Break (HELB)," (6/89), addressed the HELB problem of piping failure i
causing pipe whip in a closed system inside the containment. The licensee found that i
RBCCW pipe would not be damaged by pipe whip and only limited parts of the RBCCW would be exposed to jet impingement effects. The NRC-A/E inspection team found that PNPS did not evaluate the effects of losing inventory before the failure could be isolated.
Loss of inventory could result in system loop loss of function or create a vent path from
. the primary containment through the surge tank vent into the reactor building. The team noted that there was no analysis of record to address this issue. PNPS evaluated the issue during the inspection in EE 98-0082 revision 1 and found that the event path was
well'within capability of the stand-by gas treatment system and the small radiological consequences would have no significant impact on environmental release.
j i
' This item was evaluated by the licensee via problem report PR 98.9532.00, and aspects of the issue were documented in the PNPS SE 3255, dated June 1,1999. The inspectors reviewed both the problem report and the PNPS SE, and discussed the i%m with the responsible engineering manager. The SE provided the results of an evaluation i
of the probability of a HELB causing pressure boundary failure of the RBCCW system, the safety significance of the issue, the applicability of NRC IN 89-55 and NRC GL 96-06 i
to the issue, the relation of the issue to the plant design basis, proposed changes to the l
C
c.
,
UFSAR and a 50.59 evalua, tion of the UFSAR change. With the evaluation of the vulnerability of the RBCCW system to damage from a HELB complete, and a proposed clarification to the design basis for this issue ready for UFSAR revision, IFl 50-293/98-203-16 is closed, l
E8.17 (Ooen) IFl 50-293/98-203-17: Review of Over-oressure Protection for Heat Exchanaers in the RBCCW System (E1.2.4.2.e)
The NRC A/E team found that during maintenance there was an opportunity for over-pressurization of the RBCCW heat exchangers because of the lack of pressure relief valves. ASME Section Vill Division I (1968 Edition), paragraphs UG-125 through UG-
'136, require pressure relief devices pressures lifting at over 10 percent of the working
'
pressure. These heat exchangers were classified as meeting UW-2 for hazardous materials (potentially radioactive). Bechtel Specification M-11, " Cooling Water and Fuel Pool Cooling Heat Exchangers," Revision 1, required relief valves. The licensee stated that when the RBCCW and SSW systems are in normal lineups there is no potential for over-pressure. However, during maintenance, over-pressurization could occur in the absence of isolation or venting during isolation.
The licensee contacted the heat exchanger manufacturer, who indicated that they took exception to Purchase Specification M11 to provide shell/ tube side relief valves and valve flanged connections. Licensee discussions with the ASME Code authorized inspector found no concern with the existing installation. In the absence of documentation, low probability of over-pressurization, and acceptance by the Code inspector, the licensee believes that omission of the safety relief valves was a conscious decision at the time. However, a procedure change is being considered for venting the heat exchangers during isolation for maintenance.
To date, resolution of the possibility of over-pressurization during maintenance has not been completed. Pending resolution of the issue by providing a documented basis for
the absence of pressure relief valves on the heat exchangers, providing an approved venting procedure, or providing a modification to render the design consistent with ASME j
Code requirements, IFl 50-293/98-203-17 remains open.
E8.18 (Closed) IFl 50-293/98-203-18: Desian Control for Reolacement Parts 'E1.4.2.b>
The NRC A/E team questioned the qualification of replacement flexible steel RBCCW hoses on RHR pump area cooling coils with in-kind hoses under the Commercial Grade item (CGI) process without evaluating the hose degradation potential from radiation under post-accident conditions. The team indicated to the licensee that elements of design control require measures be established for the selection and review of the
.
suitability of materials, parts, and equipment that are essential to the safety-related functions of the structures, systems, and components.
In response to the team's concern, the licensee initiated PR 98.2647 to review the CGI procedures to include evaluation of radiological effects as necessary. The licensee evaluated procedure.4.05 " Evaluation of Commercial Grade items," and found that i
i
,
]
t i
y
.
.
Section 5.2.2.2 requires verification that " critical characteristics for acceptance shall meet or exceed the acceptance requirements specified for procurement of the original item."
The licensee's cognizant engineer shall use the original information to identify critical characteristics and acceptance requirements. Although radiation is not mentioned in the l-
' procedure for non-EQ items, it would be evaluated if the original purchase information
!
addressed it.. Radiation was not addressed as a critical characteristic. The licensee further confirmed, through assessment of the radiation environment, that the in-kind replacement of the original hose was suitable for the application and the conditions.
In review of this issue, the NRC found that the in-kind replacement of the original hose i
was determined by the licensee to be suitable for the calculated worst case total l
integrated dose (TID) values in the reactor building. An evaluation procedure for commercial grade items adequately provides for evaluating radiological effects on replacement items when required in the originai specification. IFl 50-293/98-203-18 is closed.
E8.19 EDG Fuel Oil Suoolv a.
Inspection Scope (92903)
i The inspector reviewed the interim corrective actions taken to address the inadequate fuel supply for the EDGs.
j b.
Observations and Findinos J
On September 28,1998, the licensee identified that the TS minimum fuel requirement of 19,800 gallons for each EDG is insufficient to support the electrical loads specified in the UFSAR (reference LER 50-293/98-21). To address this condition, the licensee submitted a TS amendment to the NRC to allow crediting the station blackout (SBO)
diesel fuel oil supply. Other actions include revising procedure 2.2.8, " Standby AC Power System (Diesel Generators)," to include steps to transfer diesel oil from the SBO diesel storage tanks to the EDG storage tanks, and requiring technical support center personnel to determine the need for fuel transfer within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of an initiating event
.. (EDG fuel management strategy).
The inspector reviewed procedure 2.2.8, and verified that fuel utilization curves were implemented to calculate the diesel fuel consumption at various EDG loads and that r.,teps were added to the procedure to transfer fuel from the SBO to the EDG storage tanks. The inspector also verified that the licensee has dedicated equipment and hoses to allow the transfer of the diesel fuel oil from the SBO to the EDG storage tanks.
c.
Conclusions The licensee's corrective actions to address the inadequate diesel fuel supply were adequate. Dedicated equipment is available to transfer fuel from the SBO diesel to the EDG storage tanks and procedural guidance is available to allow calculation of fuel consumption at various diesel loads.
l a
l
,
.
.
IV. PLANT SUPPORT i
i R1 Radiological Protection and Chemistry (RP&C) Controls j
..
..
,
_
)
R1.1 : Hiah Radiation Area Boundary Problem (71750)
~.
Inspection Scggg i
a i
Tours of the radiologically controlled area (RCA)_were made to assess the condition and
adherence to radiological postings. This included radiation areas, high radiation areas
and contaminated area postings and boundaries.
I l
b.
JObservations and Findinas l
On August 12,.1999, during an inspection of the reactor building, the inspector identified a disconnected high radiation area (HRA) boundary located in back of the west scr m discharge instrument volume tank. No workers were observed in this area. The
- inspector re-established the HRA boundary and reported this deficiency to radiation protection technicians at the red line area. The inspector determined that this was a
'
procedural violation of procedure 1.3.114, " Conduct of Radiological Operations," step 5.1.2[3](e). This procedure requires the HRA barricade and posting be re-established after entering / exiting the HRA.'
The licensee generated PR 99.2032 to document, evaluate and correct this condition.
PR 99.2032 was coded as a significant condition adverse to quality because the condition required heightened management attention. A root cause analysis was assigned which was not completed at the end of this inspection period. The acting radiological control manager implemented several interim corrective actions. First, a plant wide inspection was done to ensure no other radiological boundariee were down.
No other problems were found during this inspection. Also, a radiological survey was performed in the subject area which found no radiation levels greater than 100 millirern/ hour.- Hence, the subject area was over-posted as a conservative measure.
Subsequently, the health physics staff reposted the area as a radiation area. Lastly, a
. review of recent site worker radiation exposures found no higher levels of unplanned radiation exposures. The inspector determined that the licensee took good interim corrective actions to prevent recurrence.
' The radiation protection manager stated that another HRA barrier problem occurred
,
during RFO 12.- However, that event resulted from a radiation protection technician error who forgot to install the barricade when setting up the boundary. Therefore, the corrective actions for that event would not have necessarily prevented the event this
. period.' The manager stated that both events did result from human error and a broader action was initiated by senior site managers to improve human performance. This
,
I severity level IV violation cf procedure 1.3.114 is being treated as a non-cited violation,
,
consistent with Appendix C of the NRC Enforcement Policy..This is in the licensee's corrective action program as PR 99.2032. (NCV 50-293/99-05-04)
h
.
l
.
c.
Conclusions l
The NRC identified a problem with the boundary / posting of a high radiation area near the west scram discharge instnJment volume. This most likely resulted from human error by not re-establishing the boundary properly when exiting the area. The interim corrective j
actions were judged to be good to prevent recurrence in the short term. This severity level IV violation is being treated as a non-cited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as problem report (PR) 99.2032.
V. MANAGEMENT MEETINGS X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at j
the conclusion of the inspection on September 24,1999. The licensee acknowledged the findings presented. The licensee did not identify any materials examined during the
- inspection to be considered proprietary.
X3 Management Mew:ng Summary On August 31,1999, the NRC held a public meeting with the licensee to discuss the results from the last plant performance review (PPR). Messrs. J. Wiggins, W. Lanning and C. Anderson form NRC Region I participated in the meeting in addition to the NRC resident inspectors assigned at Pilgrim. The public meeting was held at the John Carver inn located in Plymouth, MA. A few members of the local media and one representative from the Commonwealth of Massachusetts attended the meeting.
I
\\
p i
.
l.
ATTACHMENT 1:
L*
INSPECTION PROCEDURES USED
!
'
IP 37550:
. Engineering (-
IP 37551:
Onsite Engineering
IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP 61726:
. Surveillance Observation
'
IP 62707:
Maintenance Observation IP 71707:
Plant Operations IP 71750:
Plant Support Activities IP 82301:
Evaluation of Exercises for Power Reactors IP 92700:
Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor Facilities i
IP 92901:
Follow-up - Operations
)
IP 92902:
Follow-up - Maintenance IP 92903:
. Follow-up Engineering IP 92904:
Follow-up - Plant Support IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors
'
- .
j
!
l
!..
,
'
>
..
. ATTACHMENT 2:
.
ITEMS OPENED, CLOSED, AND UPDATED Qoened IFl '50-293/99-05-01 Degraded SSW sensing line Closed IFl 50-293/98-203-01 Instrument Uncertainty Control and App!! cation (50-293/98-203 paragraph E1.2.1.2.b) -
IFl 50-293/98-203-02 Control of LOCA Analysis inputs and UFSAR Update
.
.
(50-293/98-203 paragraph E1.2.1.2.c)
IFl 50-293/98-203-04 Review of Licensee's GL 96-06 Calculation and Review Method
.
(50-293/98-203 paragraph E1.2.1.2.e and E1.2.4.2.d)
IFl 50-293/98-203-07 Review of Electrical Penetration Protection (50-293/98-203 paragraph E1.2.2.2.1.e) _
- . IFl 50-293/98-203-08 Review of Plant Modification to Resolve Degraded Bus Voltage
,
Concems (50-293/98-203 paragraph E1.2.2.2.1.f)
'
IFl 50-293/98-203-09 Review of TS and Testing of New 480 VAC Relays (50-293/98-203 paragraph E1.2.2.2.1.f)
' IFl 50-293/98-203-10 Review of New Battery Sizing Calculations (50-293/98-203 paragraph E.1.2.2.2.2.a)
IFl 50-293/98-203-11 Verification of Postulated Fault Current and Replacement Buses with Low Fault Current Ratings (50-293/98-203 paragraph
,
E1.2.2.2.2.b)
.
IFl 50-293/98-203-12 Follow-up Review of DC System and Battery Terminal Voltage
.
Calculations (50-293/98-203 paragraph E1.2.2.2.2.c)
.IFl 50-293/98-203-15 '
Review of RBCCW ISI Boundary (50-293/98-203 paragraph I
E1.2.4.2.b) _
.
,
IFl 50-293/98-203-16
. Vulnerability of RBCCW System to Damage From a HELB (50-i 293/98-203 paragraph E1.2.4.2.c)
)
H IFl 50-293/98-203-18 Design Control for Replacement Parts (50-293/98-203 paragraph
.i E1.4.2.b)
j LER 50-293/99-08 -
- Automatic Reactor Scram Due to Automatic Turbine Tnp
NCV 50-293/99-05-02 '
Failure to assure that design bases are correctly translated into specifications.
'
? NCV 50-293/99-05-03 -
- Failure to assure control design input in calculations and TS
.sumeillances -
NCV 50-293/99-05-04 :
High Radiation Area boundary problem URI 50-293/98-203-13
- Adequacy of Design Controls Associated With Control!ing
' Changes With Calculation Comment Sheets and Acceptability of TS Sumeillance Test (50-293/98-203 paragraph E1.2.2.2.2.d,.
E.2.2.2.2.e, and E1.2.3.2b)
.
- ,.
( URI 50-293/98-203-14.
Adequacy of Design Controls Associated With ECCS Room
^
Potential Flooding (50-293/98-203 paragraph E1.2.4.2.a)
~.
k
.
i l
\\
-
Attachment 2 (cont'd)
,
Discussed (Remaining Open)
i
- IFl 50-293/98-203-05 Review of Revised EDG Loading Calculations (50-293/98-203
,
'
pcragraph E1.2.2.1.a)
IFl 50-293/98-203-06 Review of Electrical Backfeed Analysis (50-293/98-203 paragraph E1.2.2.2.1.d)
)
IFl 50-293/98-203-17 -
Review of Over pressure Protection for Heat Exchangers in the
'
URI 50-293/98-203-03_
RBCCW System (50-293/98-203 paragraph E1.2.4.2.e)
.
'
Reconciliation of EOP Actions and USFAR Assumptions Associated With Containment Flooding (50-293/98-203 paragraph E1.2.12.d)
l i
l
-
,
I
'
,
ATTACHMENT 3:
LIST OF ACRONYMS USED A
Amperes Al Authorized inspector AIP Augmented Inspestion Program
,
A/E Architect Engineering ANSI American Nuclear Standards Institute ASME-American Society of Mechanical Engineers BWR Boiling Water Reactor BWROG Boiling Water Reactor Owners Group CCS Calculation Comment Sheet CGl..
Commercial Grade item CS Core Spray
- DBA Design Basis Accident DBI Design Basis Improvement DC Direct Current EOP-Emergency Operating Procedures
,
ECCS Em3rge acy Core Cooling System
>
EDG Emergency Diesel Generator EE Engineering Evaluation EOOS Equipment Out of Service
,
F Fahrenheit FSAR Final Safety Analysis Report GL-Generic Letter HELB High Energy Line Break HPCI H:gh Pressure Coolant injection HRA High Radiation Area IEEE Institute of Electrical and Electronics Engineers l&C Instrument and Control
- IFl inspection Follow Item
'
ISI In-Service inspection IST In-Service Testing kA Kilo Amperes i
kV Kilo Volt kW Kilo Watt LCO Limiting Conditlon for Operations LER Licensee Event Report LOCA Loss of Cooling Accident LOOP Loss of Offsite Power LPCI Low Pressure Coolant injection MCC Motor Control Center MOV Motor Operated Valve MR Maintenance Request MSTP Master Surveillance Tracking Procedure NLV Non-cited Violation NRC United States Nuclear Regulatory Commission NWE Nuclear Watch Engineer P&lD Piping and Instrument Diagram
F
)
,
'
(- :
e p'
-
s
,
'
Attachment 3 (cont'd) -
~2 y
..
j'
PDC Plant Design Change :
.
PNPS?
Pilgrim Nuclear Power Station PPR-Plant Performance Review:
PR.
Problem Report QA
.
. Quality Assurance l
RBCCW-
' Reactor Building Closed Cooling Water p
.RCA-Radiological Controlled Area
!
RCIC.
Reactor Core Isolation Cooling RFO.
' Refueling Outage RHR Residual Heat Removal
. SAG Severe Accident Guidelines.
SBO Station Blackout '
SE Safety Evaluation SGTS-Stand-by Gas Treatment System
,
SSW -
Salt Service Water -
, TBCCW -
Turbine Building Component Cooling Water
,
1TDBD, Topical Design Basis Document TID TotalIntegrated Dose -
{
TP:
Temporary Procedure.
]
' TS-Technical Specifications
_
UFSAR:
Updated Final Safety Analysis Report URI:
Unresolved item USQ Unresolved Safety Question I
.' V.
Volts VAC.;
Volts Altem_ ating Current i
VDC Volts Direct Current r.
.-l
'
s ls l-
.l l
!
I
!'
l n
,
.
r