IR 05000277/1993028

Insp Repts 50-277/93-28 & 50-278/93-28 on 931115-19.No Violations Noted.Major Areas Inspected:Licensee Main Steam Safety Valve & Safety/Relief Valve Related Activities

ML20059D678
Person / Time
Site:	Peach Bottom
Issue date:	12/20/1993
From:	Eapen P, Gregg H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20059D671	List: IR 05000277/1993028 ML20059D668
References
50-277-93-28, 50-278-93-28, NUDOCS 9401100037
Download: ML20059D678 (10)

Text

l

.

.

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

DOCKET / REPORT NOS. 50-277/93-28 50-278/93-28 LICENSE NOS.

DPR-44 DPR-56 LICENSEE:

Philadelphia Electric Company P. O. Box 195 Wayne, Pennsylvania 19087-0195 FACILITY NAME:

Peach Bottom Atomic Power Station, Units 2 and 3 INSPECTION AT:

Delta, Pennsylvania INSPECTION DATES:

November 15 - 19, 1993 INSPECTOR:

-

.

, LL-4A, --

lW 2.o 9 3 Harold Gregg, Sr. Reactor Efgi6eer

/ Date'

Systems Section EB, DRS G.

K - (d.

<a A a192 APPROVED BY:

Plackeel K. Eapen, Chief /

Ijate

'

Systems Section EB. DRS i

9401100037 931222 PDR ADOCK 05000277 O

PDR

,

.

.

i

!

l l

Areas inspected: An announced inspection was conducted of the licensee's main steam safety valve and safety / relief valve related activities.

Results: The program was implemented in compliance with applicable technical specifications, ASME Code, and regulatory requirements. Periodic testing and refurbishment

'

of the valves was effectively implemented and assures reliable operation of these safety significant components.

l l

I I

.

i

.

i

i

.

.

DETAILS 1.0 SAFETY RELIEF VALVE AND SAFETY VALVE INSPECTION

l Yais inspection was performed as a regional initiative because.of the safety significance of safety / relief valves (SRVs) and spring safety valves (SVs), several recent NRC Information i

Notices about these valves, and the NRC study on SRV and SV reliability problems.

1.1 Objectives This inspection was performed to review the licensee's activities related to the reactor coolant system main steam SRVs and SVs. These components perform a significant safety function

!

of providing reactor vessel and coolant piping system overpressure protection. In addition,

.

'

five of the SRVs also perform automatic depressurization of the reactor vessel to permit injection of core spray in the event of a small break LOCA.

The inspector reviewed SRV and SV plant specific requirements; licensee's adherence to i

Technical Specifications (TS) and ASME Code requirements; Final Safety Analysis Report (FSAR) commitments; adequacy of testing and results evaluations; knowledge and response j

to industry, vendor, and NRC information; and reporting of events.

i 2.0 VALVE TYPES

!

t The inspector verified that eleven target rock model 67, three stage, 6" x 10" flanged SRVs (five of the SRVs also perform an automatic depressurization system (ADS) function), and

,

two Dresser Industries, Model 6-3707-RA-RT21-X0S114, "R" orifice (16.00 sq. inches), two

!

adjusting ring, exposed spring, 6" x 10" flanged SVs were installed at each of the units. The

!

licensee maintains storeroom spares of six SRVs and two SVs.

!

3.0 TS AND AEME CODE REQUIREMENTS, AND ISAR COMMITMENTS 3.1 TS Requirements

.,

The licensee's TS required the following set pressures:

'

4 SRVs 1105 psig (

11 psi)

4 SRVs 1115 psig (i 11 psi)

i 3 SRVs 1125 psig (

11 psi)

!

2 SVs 1230 psig (

12 psi).

'

.

s TS requires the following surveillances:

e At least five SRVs and one SV checked or replaced every 24 months and all valves to be tested every two cycles.

i i

'

.

.

I

• At least one SRV to be disassembled and inspected every 24 months.

Integrity of SRV bellows to be continuously monitored, switches calibrated once per

operating cycle, and accumulators and air piping to be inspected once per operating cycle using leak test fluid.

Manual opening of each SRV when reactor pressure is ;t 100 psig once per operating

cycle and verification that SRVs open by observing turbine bypass valve closure or load reduction or change in measured steam flow, depending on operating configuration.

The in:;pec:ct determined that the plant's operating pressure (985 psig) provides sufficient simmer margin to prevent SRV and SV leakage. The inspector also determined that the required surveillances were performed through a specific surveillance procedure. Where there are different TS and ASME Code requirements such as setpoints, the procedure data sheet listing includes both.

3.2 ASAIE Code Requirements The licensee's current Inservice Testing of valves program adopted the use of ASME OM-1 (1981) and was accepted by NRC. This standard requires all SRVs and SVs of each type and manufacturer to be tested within five years and defines time periods during the five years when testing should be performed. The set pressure acceptance criteria of OM-1 requires the valves not to exceed the stamped set pressure by 3% or greater. Valves exceeding this criteria are considered failed and require additional valves to be tested. (It was known by the inspector and the licensee that the latest OM-1 standard now have a i 3% criteria.)

The inspector concluded that the licensee's testing of SRVs and SVs was in accordance to ASME Code requirements.

3.3 FSAR Description The FSAR defines the safety objectives of the pressure relief system, design aspects of the system (including ADS), and pressure relief valves that are in the system. The installation, location, and overpressure operation of the SRVs and SVs are also narrated in the FSAR.

The SRVs actuate automatically when set pressure is reached or can be remote manual

, _ _ _ _ - _ _ _ _ _ _ _ _ _ _

_ - _ - - _ - - _

.

o

i operated when system pressure is > 100 psig. The SRVs discharge to the suppression whereas the SVs discharge directly into the drywell. Specific details of how the SRVs operate and cross section schematic diagrams of an open and closed SRV are also in the FSAR.

The FSAR narrated details effectively describe the as-installed configuration of the SRVs and SVs. However, the diagrams depicting SRVs opened and closed were inaccurate in portraying the pilot stage abutment gap and steam location inside the valve. The licensee has initiated action to address the FSAR discrepancy found by the inspector.

)

Conclusions

'

The inspector concluded that TS, FSAR, and ASME Code adherence for SVs and SRVs are being affectively met.

4.0 EVALUATION OF SRV AND SV TESTING The inspector determined that testing of SRVs and SVs was performed offsite at a testing.

laboratory. Recent testing reviewed by the inspector was performed at Westinghouse-Western Service Center and Wylie Laboratories. The inspector also determined that the entire SRV was sent to the laboratory for the test and that each SRV and SV sent for test was -

also reworked by the manufacturer's representative after the as-found testing.

Each of the Peach Bottom units are on a 24-month operating cycle, and a minimum of five or six SRVs and one SV are tested each cycle, and all valves within two cycles. Failures to meet the OM-1 set pressure acceptance criteria required additional valves to be tested and an LER was written when TS set pressure was exceeded.

The set pressure testing of SRVs and SVs included as-found and as-left tests. The first SRV and SV test actuation was the recorded as-found set pressure. Two subsequent activations were performed for repeatability determination purposes. (For SRVs', a manual actuation is performed prior to the three automatic actuations).

The as-left testing required three consecutive within tolerance actuations and the last was the recorded as-left set pressure. (For SRVs, a manual actuation is performed prior to the --

automatic actuations). The licensee requires the laboratories to set SVs at i 1% and SRVs at +0/-l%. The inspector determined the more stringent +0/-l% setting of SRVs is basedf

,

on specific correspondence between the plant and manufacturer. and takes into account slight pressure increases of the bonnet internal volume when in operation.

Seat leakage testing was also performed with valves in as-found and as-left condition..

t

.

_. _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _______ ______ _ ___ _ ________ -

.

.

The inspector noted that the licensce's purchase order provides basic testing requirements, such as set point tolerance and number of as-found and as-left tests. The licensee also reviews and modifies the test laboratory test procedure, where needed, to adhere to the plant's imposed requirements such as +0/-1% settings of SRVs and three consecutive within tolerance as-left actuations.

Conclusions The SRV and SV testing meets TS and OM-1 requirements and was effective. More stringent than TS or OM-1 setpoints are used in the setting of SRVs. The licensee was aware of vendor related issues concerning SRVs and SVs.

5.0 SRV AND SV TEST RESULTS The inspector evaluated the last two tests performed for each unit. The inspector's summary of the as-found setpoints are shown in the tabulation below.

Unit 3 (Oct.1993)

Unit 2 (Oct.1992)

Valves As-Found Valves As-Found Tested Results Tested Results 1 SV

+3%

1 SV-4.2 %

6 SRVs (4) within i1 %

5 SRVs (3) within i1%

(1) +1.3%

(1) -2.1 %

(1) +1.6%

(1) +2.1%

Unit 3 (Oct.1991)

Unit 2 (March 1991)

1 SV within 11%

(1) SV within i1 %

5 SRVs (4) within 1%

(6) SRVs (3) within i1%

(1) +2%

(1) -2.7%

(1) -1.1 %

(1) +2.3%

Conclusions The inspector concluded that the deviations from nominal as-found setpoint wen minimal and can be partially attributed to rework of each tested valve. The minimal as-found setpoint deviations of the SRVs demonstrated excellent reliability (22 of 22 SRVs within 3%) and could, in part, be attributed to the rework of each tested valve, and also that these valves are the three stage model SRVs.

_ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ -

i

.

I

6.0 SV RING SETTINGS The inspector reviewed the method used to adjust SV ring settings because several recent NRC Information Notices described findings of improperly set rings. Adjusting ring

'

positions are important and enable an SV to perform proper opening, full lift capacity, and reclosure. The inspector evaluated the valve manufacturer's (Dresser Industries) disassembly inspection refurbishment, and reassembly report for SV Serial No. B-1095, performed in October 1992. Determinations made by the inspector were that vendor ring position gages (serial numbers identified in the report) were used to set the valve. The inspector also verified that the use of gages was confirmed by vendor testing, and was appropriate.

{lonclusion SV adjustments are made by vendor representatives, and settings are properly performed.

7.0 IMPLEMENTATION OF TS AND OM-1 REQUIREMENTS The inspector reviewed licensee's surveillance procedures and observed the control room panels to verify that SRV and SV TS surveillance requirements were met.

e The OM-1 and TS 4.6.D.1 and 4.6.D.2 requirements for numbers of valves to be tested and frequency of testing was performed by Procedure ST-M-01G-450.

The TS 4.6.D.3 requirement for continuous monitoring of the SRV bellows was

performed by control room indication and audible signal. (There were control room panel lights for each SRV that display if a pressure sensing switch actuates and there was a common audible signal for all SRVs).

• The TS 4.6.D.3 switch calibrations at required frequencies are performed by Procedure SI 2P-71-EICO. A minor discrepancy of not identifying TS 4.6.D.3 on this procedure was identified by the inspector and the licensee prepared an action item to address this issue.

The required accumulator and air piping inspections required are performed by

Procedure ST-M-016-220.

The TS requirement 4.6.D.4 for manual operation of all SRVs at 2100 psig are e

performed by Procedure ST-0-01G-440.

Conclusions The inspector concluded that the TS and ASME OM-1 requirements were met and the licensee's performance in meeting the requirements was effective.

-

.__ -_ __

_

-

e

8.0 REVIEW OF ANNUAL REPORT OF SRV CIIALLENGES i

The inspector reviewed the licensee's TS 6.9.1.c and TMI Action Plan Item II.K.1 required annual reporting for the primary coolant SRV and SV challenges (in response to high reactor pressure).

The inspector determined that the licensee had: 0 challenges in 1991, three challenges of SRVs in 1992, and 0 challenges thus far in 1993.

The three challenges in 1992 were:

1.

(LER 2-92-12). A thunder and lightning storm caused Unit 2 startup feed and main generator breaker trips and a reactor scram. Six SRVs lifted, two cycled two times

,

and four cycled one time each.

2.

(LER 2-92-15). Maintenance activities initiated a reactor scram following a main

>

generator lock out and three SRVs lifted momentarily.

3.

(LER 3-92-08). Slight jarring of an instrument rack during a half isolation investigation caused a sensitive pressure switch actuation for low steam line pressure e

and a group one reactor scram. Three SRVs lifted at approximately 1105 psig, one cycled three times, and two cycled one time each.

For the LER 3-92-08 event, the inspector independently reviewed pressure / time computer-generated charts and assessed valve opening points and blowdown. The inspector determined

'

that a pressure of 1102 psig was reached when SRVs 71C and 71E (set pressure 1105 11)

opened. SRV 71C closed at approximately 1060 psig, and 71E closed at approximately 1043 psig. Pressure increased again, and SRV 71F (also set 1105 psig i 11) opened. The i

operators then went to manual control per the EOPs. The inspector determined the reclosure blowdown to be 4% for SRV 71C, and 5.6% for SRV 71E. This blowdown was considered i

very acceptable by the inspector. The inspector also noted that the three valves that opened were on the same header as would be somewhat expected.

As an additional matter of interest, the inspector determined that the last inadvertent early opening of an SRV occurred in 1982.

Conclusions Annual reporting of SRV and SV challenges was in accordance with the technical specification requirement I

_

9.0 SITE ORGANIZATION RESPONSIBILITY FOR SRV AND SV PERFORMANCE The inspector determined that plant engineering has prime responsibility for assuring proper

,

SRV and SV performance, and there was an effective interface with maintenance support personnel. The inspector found the plant engineering persons involved with SRVs and SVs (main steam system engineer, component engineer, and IST engineer) to be relatively new in l

their positions. Further review by the inspector determined that prior engineering lead SRV

,

and SV expertise was onsite in other positions and are called on when needed.

Conclusions The engineering personnel assigned to SRV and SV responsibilities were found technically competent and they are obtaining the required expertise from their predecessors.

10.0 EXIT MEETING The inspector met with the licensee's representatives at the conclusion of the inspection to summarize the findings of this inspection on November 19, 1993. Attendees at the exit meeting are listed in Attachment 1. The licensee acknowledged the inspector's findings and provided comments and clarifications, as appropriate.

.

I

__-

-_

_-

-

e ATTACHMENT 1 Persons Contacted Philadelphia Electric Comnany J. Armstrong Senior Manager, Plant Engineering J. Baddick Maintenance Technical Support

M. Baker Component Engineer

D. Foss Regulatory Engineer R. Gambone Manager, NSSS

• E. Guarino Plant Engineer, NSSS D. Miller Vice President, Peach Bottom Atomic Power Station

• J. Mitman Manager, Component Engineering T. Niessen Director, Site Engineering R. Porrino Maintenance Foreman G. Sawka Main Steam System Manager

• R. Smith Regulatory / Experience Assessment Engineer -

• D. Turek Plant Engineer, NSSS

• A. Wasong Manager, Experience Assessment.

Atlantic Electric Comoany

• H. Abendroth Site Representative U.S. Nuclear Regulatory Commission

• R. IArson Resident Inspector W. Schmidt Senior Resident Inspector j

-

• Denotes those who attended the exit meeting on November 19, 1993.

_ _ _ _ _ - _ - _ - - _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _