Information Notice 1991-50, a Review of Water Hammer Events After 1985
UNITED STATES
NUCLEAR REGULATORY COMMISSION
OFFICE OF NUCLEAR REACTOR REGULATION
WASHINGTON, D.C. 20555 August 20, 1991 NRC INFORMATION NOTICE NO. 91-50: A REVIEW OF WATER HAMMER EVENTS AFTER 1985
Addressees
All holders of operating licenses or construction permits for nuclear power
reactors.
Purpose
This information notice is'intended to alert addressees to a U.S. Nuclear
Regulatory Commission (NRC) evaluation of water hammer events between
January 1986 'And March 1990. It is expected that recipients will review the
information for applicability to their facilities and consider actions, as
appropriate, to avoid similar problems. However, suggestions contained in this
information notice do not constitute NRC requirements; therefore, no specific
action or written response is required.
Background:
The NRC originally addressed water hammer in Unresolved Safety Issue (USI) A-1, reviewing 148 reported events from 1969 to 1980. The NRC considered this USI
resolved with the issuance of "Evaluation of Water Hammer Occurrence in Nuclear
Power Plants," NUREG-0927, Revision 1, in March 1984. 'The NRC concluded that
cost-benefit considerations did not support new requirements'to reduce the
number of water hammer events. However, the'NRC included guidelines on mea- sures to prevent-and reduce water hammer.
After the-event at the San Onofre Nuclear Generating Station, Unit 1, in
November 1985, the NRC reassessed the occurrence of water hammer, reviewing
40 events from 1981 to 1985. In the reassessment, the NRC confirmed the
original conclusions that new or additional requirements to reduce the number
of water hammer events-were not cost-effective. The frequency of water hammer
events had decreased significantly since the'initial review. The NRC identi- fied no new causal mechanisms for water hammer.
Description of Circumstances
'.
The NRC evaluated'water hammer events that have occurred since January 1, 1986.
The staff searched NRC -databases from January 1986'through March 1990 and found
about a dozen reports of water hammer events or events related to the water
hammer phenomenon. In February 1991, the staff documented its findings in "A
Review of Water Hammer Events After 1985," AEOD/E91-01. A copy of this
097
August 20, 1991 report is available in the NRC Public Document Room, 2120 L Street N.W.,
Washington, D.C. The staff reviewed each of these reports to identify new
physical phenomena, common mode aspects, and ways to prevent situations that
could result in water hammer. The following events at Dresden Units 2 and 3, South Texas Unit 1, Trojan, and Susquehanna Unit 2 exhibit characteristics not
emphasized in previous studies and offer lessons beyond implementing the
guidance in NUREG-0927, Revision 1. In addition, a recent event at Big Rock
Point 1 involved damage to a gate valve. Such damage has not been previously
identified in a nuclear power plant. -
Big Rock Point 1: On May 28, 1991, while the reactor was operating at 97X of
full power, thl licensee was performing a routine surveillance test of the
emergency core spray (ECS) injection valves. After successfully testing both
injection valves in the primary ECS system and the upstream injection valve in
the backup ECS system, a signal to open the downstream injection valve was
generated. A few seconds after the valve started to open, a reactor operator
at the valve heard a water hammer and observed movement of the 4-inch piping
that continued for several seconds. The water hammer bent one pipe hanger, partially pulled a bolt for another from the wall, and misaligned or damaged
switches attached to the valve operators.
The backup ECS system is intended to deliver water from the fire suppression
system at 150 psi to the reactor vessel after it has been depressurized follow- ing a loss of coolant accident. Fire water would be delivered to a nozzle
located within the reactor vessel. The elevation of this nozzle is slightly
higher than the elevation of the nozzles for the piping which connects the
reactor vessel to the steam drum. The length of backup ECS piping from where
it penetrates the head of the reactor vessel to the nearest injection valve is
approximately 60 feet. This piping is routed horizontally and vertically
upwards. An 18-foot section of horizontal piping has a rise in excess of
4 inches in the downstream direction and thus acts as a water trap. The
-upstream side of the injection valve nearest to the reactor vessel connects to
a short pipe spool, a check valve, another short pipe spool, and the upstream
injection valve. A short length of 1-inch pipe connects to the bottom of the
upstream spool and terminates at a blind flange with an eighth-inch hole. The
pipe serves to demonstrate that the check valve is not leaking.
The backup ECS piping normally contains noncondensible gases and saturated
steam and water at 1350 psi. The relative concentrations of these constituents
depend on the temperature distribution in the piping, the length of time that
the reactor has been at power, and the number of surveillance tests that have
been performed since the last startup. On May 28, 1991, conditions in the pipe
led to acceleration of a slug of water that struck the gate of the downstream
injection valve as it was opening during the surveillance test. The impact was
great enough to leave imprints of the valve seats on both sides of the gate and
to cause some cracking of the gate. Leakage of the valve prior to the event
and consequent steam cutting of the upstream side of the gate and seat. may have
contributed to the event. The licensee's corrective actions included changing
the slope of the horizontal section of piping, so that it will drain back to
the reactor, and repairing the valves, valve operators, and pipe hangers.
August 20, 1991 Dresden'Unit 2:. A series of events occurred in the high pressure coolant
injection THPCI) system at Dresden Units 2 and 3 over several months. They are
discussed in 'order of occurrence to enhance the understanding of changes.in
system'valve positions. This' event is also'discussed, but in less detail, in
NRC Information Notice No. 89-80,'"Potential for Water Hammer, Thermal Strati- fication, and Steam Binding in High-Pressure-Coolant I.njection Piping,"
December 1, 1989. On October'31 1989, while the plant was operating at'100
percent full power, the licensee declared an unusual event and began an orderly
shutdown because time had expired for the limiting condition of operation (LCO)
with the HPCI system inoperable. During the 5 months before taking this
action, the licensee had.observed high temperatures in the piping at the HPCI
pump discharge.and between two motor-operated valves (MOVs)*(Points A and
B on Figure 1 showing the normal.configuration) near the interface between the
HPCI system and the feedwater'system. During this time, the licensee concluded
that feedwater was -leaking back through.feedwater isolation check valve No. 7 and thehnormally closed IPCI.injection MOV No.-8, found deficiencies in about
one-half'of the pipe supportst(16/34), and concluded that steam voids could
form.: On October 23, the licensee declared the HPCI system inoperable. To
correct the.problem temporarily, the licensee realigned the HPCI system valves
to open MOV No. 8 and close MOV No. 9 to serve as the normally closed HFCI
injection valve. In a later inspection, the licensee found a bent stem and
erosion of the.disc and the seat in MOV No. 8. In the realignment, the nor- mally closed MOV;No. 10.becomes subject.to feedwater pressure. If MOV No. 10
is not fully closed', theh the open MOV No. 15 in the HPCI test return line to
the condensate storage tank (CST) allows a conditi'on conducive to water hammer
when check valve No.' 7 is'leakin'g. This alignment permits. hot pressurized
feedwater to flow in.a cold low pressure test system (LER 50-237/89-29-01),
Dresden Unit 3:! On October 31, 1989, while the plant was operating at
100 percent tull power, the licensee declared the HPCI system inoperable, having found conditions similar to.those-at Unit 2 described above: similarly
elevated temperatures., deficiencies in about one-half of the pipe supports
(21/40), and valves.that'could'be leaking. The licensee found the discharge
piping in the steam tunnel to be insulated, contrary to'the original con- struction documentation. Initially, the licensee revised the alignment of the
HPCI system as it had at Unit 2, to open MOV No. 8 and close MOV No. 9. The
licensee later determined that feedwater was leaking back through MOV No. 10.
Accordingly, the licensee closed MOV No. 15 to return the HPCI system to
operable status.,-"In a later inspection', the licensee identified damage in the
seating surfaces tin MOVs No. B'and 10 and check.valve No..7 to confirm feed- water back leakage. Closure of MOV No. 15 offers protection from a potential
water hammer condition thatcould develop if MOV No. 10 does not fully close
when check valve No..7'!is,1eaking (also LER 50-237/89-29-01).
Dresden Unit 2: On March 19, 1990, while the plant was operating at 96 percent
full power, the licensee was conducting HPCI system surveillance. Before
testing, the'valve alignment corresponded to that described above for the
short-term correction-to the October 23, 1989 event; i.e.,.MOV No. 8 was open
and MOV No. 9 was closed. To conduct certain tests,.the licensee temporarily
closed MOV No.'8 to isolate the HPCI system from the feedwater system, even
though both MOV No. 8`and chepk valve.No. 7 were still leaking. After complet- ing the routine surveillance tests, including a test of MOV No. 10, the
August 20, 1991 licensee began a quarterly valve timing test of the
HPCI pump discharge valve
MOY No. 9. The licensee heard banging noises and observed
pipe movement. The licensee terminated the timing test, HPCI pump discharge
to the pretest configuration, and monitored the noises restored system valves
and movement
ceased about one and a half hours later (also LER 50-237/89-29-01). until they
Subsequent valve manipulation and HPCI pump discharge
ment led the licensee to conclude that the root cause pipe temperature measure- feedwater that had leaked back through the HPCI test of the event was
licensee postulated that this valve did not fully close return MOY No. 10. The
required manipulations. This valve did not have a after one of the
the stroke after initiation, and the limit switch wasseal-in feature to complete
switch in the open direction until the valve was 25 set to bypass the torque
percent
limit switch also controlled illumination of the "valve open. This same
light in the control room. Consequently, the "valve closed" indication
illuminated over the part of the valve stroke for which closed" light would be
was bypassed. Thus, a control room operator who removed the open torque switch
the light indicated the valve was closed would leave a closure signal when
25 percent open. Accordingly, the licensee revised the valve approximately
to maintain the closure signal for 30 seconds after the appropriate procedures
illuminates. the "valve closed" light
In addition, the licensee revised the valve alignment
protect against backleakage through MOY No. 10 by closing of the HPCI system to
MOY No. 15.
South Texas Unit 1: On November 5, 1987, before the
criticality, the licensee, Houston Lighting & Power, plant attained initial
the auxiliary feedwater (AFW) system inoperable when declared the A train of
vent line in the pump discharge piping was severed a one-inch double valve
failure occurred three days later in a double valve completely. A second
instrument
D pump discharge line. In making the initial assessment, tap in the
attributed the cause as water hammer resulting from the licensee
system. The licensee continued to note vibrations improper venting of the
in the AFW system. During
later testing, the licensee found that pressure pulsed
valves were in highly throttled positions. The resulting when the flow control
hydraulic and structural resonances was sufficient combination of both
to
licensee made design changes to eliminate this problem cause the damage. The
an: On May 12, 1987, while the plant was in a
licensee, the Portland General Electric Company, wasrefueling outage, the
transferring water from
the pressurized A accumulator (583 psig) to the depressurized
prepare for maintenance on the A accumulator. This D accumulator to
cussed from a different perspective in NRC Information event has also been dis- Hammer and Possible Piping Damage Caused by Misapplication Notice No. 88-13, "Water
Metal Diaphragm Globe Valves," April 18, 1988. The of Kerotest Packless
nozzle-to-pipe weld in the
A accumulator one-inch fill line ruptured, spilling
water. The licensee repaired the line, satisfactorily 2000 gallons of borated
again aligned the system for the transfer. The licenseehydrotested it, and
system for operations, but no controls were on the had not released the
had been released. This time, differential pressure system because the clearance
was
the transfer was started, the licensee heard loud noises, about 650 psig. When
tion, checked the arrangement of the valves and restarted stopped the opera- the transfer. After
August 20, 1991 one more cycle of this sequence of events, the nozzle-to-pipe weld in the
A accumulator fill line ruptured again.
The licensee performed metallurgical analysis of the accumulator nozzle welds
after each failure and found that the ruptures resulted from low cycle, high
stress fatigue cracking. This cracking resulted from excessive flow back
through the packless diaphragm globe valve in the A accumulator fill line.
This backflow imposed a high differential pressure across the valve, causing
the valve disc to vibrate. The licensee concluded that operator error and
insufficient procedures had-contributed to this failure. The operators had
failed to follow procedures and to determine the causes of the loud noises
before proceeding., The licensee had a procedure for transferring water through
- the sample lines but not through the fill lines.
The licensee developed a model for dynamic analysis and found that the backflow
through the fill line resulted in theload on the nozzle-to-pipe weld being far
greater than the pipe's failure threshold. During a backflow test using a
similar packless globe valve, the licensee found that the pipe would fail at a
flow of about 70 gpm. The licensee revisecI operating procedures to prohibit
water transfer between the accumulators antI developed an operation improvement
plan (LER 344/87-013-01). _ -
Susquehanna Unit 2: On October 12, 1986, while the plant was shut down, a
water hammer occurred. This event is discussed in more detail in NRC Informa- tion Notice No. 87-10, "Potential for Water Hammer During Restart of Residual
Heat Removal Pumps," February 11, 1987. The licensee, the Pennsylvania Power
and-Light Company, had established a temporary-pathway from the B recirculation
loop to the-condenser for control of reactor water level while the residual
heat removal (RHR) system was in service. With the D RHR pump running, the
licensee started the B RHR pump and then stopped the D RHR pump. However, at
approximately the same time, the outboard isolation valve in the letdown line
from the B recirculation loop to the suction of the B RHR pump closed automati- cally, tripping the pump. To compensate for the resulting loss of shutdown
cooling, the licensee established alternate cooling using the control rod drive
cooling system and the reactor water cleanup system. The licensee reset the
logic and reopened the valve to the B RHR pump suction without filling and
venting the system. The system had partially drained to the condenser through
the temporary pathway and a water hammer resulted when the suction valve was
opened. To prevent water hammer from occurring in the future, the licensee
reviewed this event and two previous similar events and revised procedures for
reestablishing RHR service (LER 388/86-015-01).
Other Plants: Other water hammer events are discussed in the following re- ports. These events resulted from causes similar to those discussed in the USI
assessment and reassessment.
PLANT SYSTEM REPORT
Palisades Accumulator Injection NRC Inspection Report 255/90-14 Oconee 3 Main Steam LER 50-287/89-02 Waterford 3 Steam Generator Blowdown LER 50-382/89-15 ANO 2 Steam Supply to AFW LER 50-368/88-23 Indian Point 3 Feedwater LER 50-286/88-02 Oyster Creek Isolation Condenser LER 50-219/88-21 Shearon Harris 1 Steam Generator Blowdown LER 50-400/87-29-01
August 20, 1991 Discussion:
These water hammer events occurred at both boiling water reactor (BWR)
pressurized water reactor (PWR) plants. In BWRs, the events occurred and
RHR (shutdown cooling mode), isolation condenser, and HPCI systems. in the
In PWRs, the events occurred in the feedwater, main steam, auxiliary feedwater
steam generator blowdown, and accumulator systems. These systems have (AFW),
associated with water hammer in previous studies. been
Some aspects differ between these events, such as the location of the
hammer. For example, the accumulator fill lines and injection lines water
and the
AFW vent lines were not previously recognized as typical sites of water
However, the physical phenomena involve the previously identified mechanismshammer.
formation of steam voids and fluid transfer between high and low pressure of
systems. The licensees have cited a number of causes for these events, ing improper filling and venting, the overly rapid stroking of valves, includ- of guidance about system configuration, accumulating water at low points, a lack
depressurizing a system to cause local flashing, and bypassing steam
Such causes were addressed in NUREG-0927, Revision 1. traps.
These events illustrate the complex nature of water hammer events and
namic interactions. The events at Dresden Units 2 and 3 point out the hydrody- that is necessary in altering system alignment during operation or to care
testing. Such alignments can increase the susceptibility to water hammer.perform
Details of component operability and control features may easily
when the immediate goal is to find a means to continue operation. be overlooked
This information notice requires no specific action or written response.
you have any questions about the information in this notice, please If
of the technical contacts listed below or the appropriate NRR project contact one
manager.
ares E. Rossi, Director
Division of Operational Events Assessment
Office of Nuclear Reactor Regulation
Technical Contacts: Earl J. Brown, AEOD
(301) 492-4491 C. Vernon Hodge, NRR
(301) 492-1861 Attachments:
1. Figure 1. High Pressure Coolant Injection System Normal
Valve Configuration
2.' List of Recently Issued NRC Information Notices
Attachment I
August 20, 1991. FEEDWATER
UNE
I
CST Condensate
Storage Tank
Figure 1
High Pressure Coolant Injection System Normal
Valve Configuration
Attachment 2 IN 91-50
August 20, 1991 LIST OF RECENTLY ISSUED
NRC INFORMATION NOTICES
Information I Date of
Notice No. Subject Issuance Issued to
91-49 Enforcement of Safety 08/15/91 All Nuclear Regulatory Com- Requirements for Radiog- mission (NRC) licensees
raphers authorized to use sealed
sources for industrial
radiography.
91-48 False Certificates of Con- 08/09/91 All holders of OLs or CPs
formance Provided by West- for nuclear power reactors.
inghouse Electric Supply
Company for Refurbished Com- mercial-Grade Circuit
Breakers
91-47 Failure of Thermo-Lag 08/06/91 All holders of OLs or CPs
Fire Barrier Material to for nuclear power reactors.
Pass Fire Endurance Test
89-56, Questionable Certification 07/19/91 All holders of OLs or CPs
Supp. 2 of Material Supplied to for nuclear power reactors.
the Defense Department by
Nuclear Suppliers
91-46 Degradation of Emergency 07/18/91 All holders of OLs or CPs
Diesel Generator Fuel Oil for nuclear power reactors.
Delivery Systems
91-45 Possible Malfunction of 07/05/91 All holders of OLs or CPs
Westinghouse ARD, BFD, and for nuclear power reactors.
NBFD Relays, and A200 DC
and DPC 250 Magnetic Con- tactors
91-44 Improper Coptrol of 07/08/91 All nuclear fuel facilities.
Chemicals in Nuclear Fuel
Fabrication
91-43 Recent Incidents Involving 07/05/91 All holders of OLs or CPs
Rapid Increases in Primary- for pressurized-water
to-Secondary Leak Rate reactors (PWRs).
OL = Operating License
CP = Construction Permit
August 20, 1991 Discussion:
These water hammer events occurred at both boiling water reactor (BWR) and
pressurized water reactor (PWR) plants. In BWRs, the events occurred in the
RHR (shutdown cooling mode), isolation condenser, and HPCI systems. In PWRs, the events occurred in the feedwater, main steam, auxiliary feedwater (AFW),
steam generator blowdown, and accumulator systems. These systems have been
associated with water hammer in previous studies.
Some aspects differ between these events, such as the location of the water
hammer. For example, the accumulator fill lines and injection lines and the
AFW vent lines were not previously recognized as typical sites of water hammer.
However, the physical phenomena involve the previously identified mechanisms of
formation of steam voids and fluid transfer between high and low pressure
systems. The licensees have cited a number of causes for these events, includ- ing improper filling and venting, the overly rapid stroking of valves, a lack
of guidance about system configuration, accumulating water at low points, depressurizing a system to cause local flashing, and bypassing steam traps.
Such causes were addressed in NUREG-0927, Revision 1.
These events illustrate the complex nature of water hammer events and hydrody- namic interactions. The events at Dresden Units 2 and 3 point out the care
that is necessary in altering system alignment during operation or to perform
testing. Such alignments can increase the susceptibility to water hammer.
Details of component operability and control features may easily be overlooked
when the immediate goal is to find a means to continue operation.
This information notice requires no specific action or written response. If
you have any questions about the information in this notice, please contact one
of the technical contacts listed below or the appropriate NRR project manager.
Original Signid by
Charles E. Rossi
Charles E. Rossi, Director
Division of Operational Events Assessment
Office of Nuclear Reactor Regulation
Technical Contacts: Earl J. Brown, AEOD
(301) 492-4491 C. Vernon Hodge, NRR
(301) 492-1861 Attachments:
1. Figure 1. High Pressure Coolant Injection System Normal
Valve Configuration
2. List of Recently Issued NRC Information Notices
- SEE PREVIOUS CONCURRENCES D
Dl~RE~N~g4tS/OGCB:DOEA:NRR
CZE! '> CHBerlinger
08//_191 07/12/91
- OGCB:DOEA:NRR*ROAB:DSP:AEOD *C/ROAB:DSP:AEOD *D/DSF:AEOD *RPB:ADM
CVHodge EBrown JERosenthal TMNovak TechEd
05/13/91 06/24/91 06/26/91 06/26/91 05/13/91 DOCUMENT NAME: IN 91-50
IN 91-XX
.- July xx, 1991
-- K> \_- Discussion:
These water hammer events occurred at both boiling water reactor (BWR) and
pressurized water reactor (PWR) plants. In BWRs, the events occurred in the
RHR (shutdown cooling mode), isolation condenser, and HPCI systems. In PWRs, the events occurred in the feedwater, main steam, auxiliary feedwater (AFW),
steam generator blowdown, and accumulator systems. These systems have been
associated with water hammer in previous studies.
Some aspects differ between these events, such as the location of the water
hammer. For example, the accumulator fill lines and injection lines and the
AFW vent lines were not previously recognized as typical sites of water hammer.
However, the physical phenomena involve the previously identified mechanisms of
formation of steam voids and fluid trdnsfer between high and low pressure
systems. The licensees have cited a number of causes for these events, includ- ing improper filling and venting, the overly rapid stroking of valves, a lack
of guidance about system configuration, accumulating water at low points, depressurizing a system to cause local flashing, and bypassing steam traps.
Such causes were addressed in NUREG-0927, Revision 1.
However, these events exhibit the following new characteristics:
(1) Hydrodynamic interactions of systems or trains that can produce water
hammer
(2) System realignments involving changing the position of MOVs that can
introduce complex issues concerning component operability and water
hammer
(3) The energization of RHR pumps in BWR plants that has resulted in a
number of isolation valve closures followed by water hammer and a
loss of shutdown cooling
This information notice requires no specific action or written response. If
you have any questions about the information in this notice, please contact one
of the technical contacts listed below or the appropriate NRR project manager.
Charles E. Rossi, Director
Division of Operational Events Assessment
Office of Nuclear Reactor Regulation
Technical Contacts: Earl J. Brown, AEOD
(301) 492-4491 C. Vernon Hodge, NRR
(301) 492-1861 Attachments:
1. Figure 1. High Pressure Coolant Injection System Normal
Valve Configuration
2. List of Recently Issued NRC Information Notices
- SEE PREVIOUS CONCURRENCES D/DOEA:NRIR C/O - NRR
Document Name: WATHAM 0503 CERossi CHBerlinger
07/ /91 07/f~491
- OGCB:DOEA:NRR*ROAB:DSP:AEOD *C/ROAB:DSP:AEOD *D/DSP:AEOD *RPB:ADM
CVHodge EBrown JERosenthal TMNovak TechEd
05/13/91 06/24/91 06/26/91 06/26/91 05/13/91
IN 91-XX
June xx, 1991 Discussion:
These water hammer events occurred at both boiling water reactor (BWR) and
pressurized water reactor (PWR) plants. In BWRs, the events occurred in the
RHR (shutdown cooling mode), isolation condenser, and HPCI systems. In PWRs, the events occurred in the feedwater, main steam, auxiliary feedwater (AFW),
steam generator blowdown, and accumulator systems. These systems have been
associated with water hammer in previous studies.
Some aspects differ between these events, such as the location of the water
hammer. For example, the accumulator fill lines and injection lines and the
AFW vent lines were not previously recognized as typical sites of water hammer.
However, the physical phenomena involve the previously identified mechanisms of
formation of steam voids and fluid transfer between high and low pressure
systems. The licensees have cited a number of causes for these events, includ- ing improper filling and venting, the overly rapid stroking of valves, a lack
of guidance about system configuration, accumulating water at low points, depressurizing a system to cause local flashing, and bypassing steam traps.
Such causes were addressed in NUREG-0927, Revision 1.
However, these events exhibit the following new characteristics:
(1) Hydrodynamic interactions of systems or trains that can produce water
hammer
(2) System realignments involving changing the position of MOVs that can
introduce complex issues concerning component operability and water
hammer
(3) The energization of RHR pumps in BWR plants that has resulted in a
number of isolation valve closures followed by water hammer and a
loss of shutdown cooling
This information notice requires no specific action or written response. If
you have any questions about the information in this notice, please contact one
of the technical contacts listed below or the appropriate NRR project manager.
Charles E. Rossi, Director
Division of Operational Events Assessment
Office of Nuclear Reactor Regulation
Technical Contacts: Earl J. Brown, AEOD
(301) 492-4491 C. Vernon Hodge, NRR
(301) 492-1861 Attachments:
1. Figure 1. High Pressure Coolant Injection System Normal
Valve Configuration
2. List of Recently Issued NRC Information Notices
- SEE PREVIOUS CONCURRENCES D/DOEA:NRR C/OGCB:DOEA:NRR
Document Name: WATHAM 0503 9 CERossi CHBerlinger
~06/ /9,1 06/ /91
- OGCB:DOEA:NRR ROAB:DSP:AEOD C/R1PAB:DSP:AE0D D/D0 EOD *RPB:ADM
CVHodge EBrown JERosenthal /u~I vak TechEd
05/13/91 06/ /91 06 2&91 6/a(/91 05/13/91
1 , - I _
4
04; 4 IDlvs'Uion of Operational Events Assessment
Office of Nuclear Reactor Regulation
Technical Contacts: Earl J. Brown, AEOD
(301) 492-4491 C. Vernon Hodge, NRR
(301) 492-1861 Attachments:
1. Figure 1. High Pressure Coolant Injection System Normal
Valve Configuration
29 'lit ~f-44efcrz.nc
3. List of Recently Issued NRC Information Notices
Document Name: WATHAM 0503 D/DOEA:NRR C/OGCB:DOEA:NRR
'CERossi CHBerlinger
it 05/ /91 05/ /91 OGCB:DOEA:NRR ROAB:DSP:AEOD C/RIE SP:AEOD D/DSP:AEOD RPB:ADM
CVHodge EBrown £ JER senthal TMNovak TechEd Jma A
05/13/91 95bt/91 0O6 W91 05/ /91 05/13 /91 Kzq/