IR 05000354/1988020
| ML20206D795 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 10/24/1988 |
| From: | Cummins J, Haughney C, Norrholm L Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20206D793 | List: |
| References | |
| 50-354-88-200, NUDOCS 8811170275 | |
| Download: ML20206D795 (38) | |
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f U.S. NUCLEAR REGULATORY COMMISSION OFFICE Of NUCLEAR REACTOR REGULATION Division of Reactor Inspection and Safeguards - _
Report No.: 50-354/88-200 Docket No.: 50-354 Licensee: Public. Service Electric and Gas Company P.O. sox 236 Hancocks Bridge,, NJ 08038
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Inspection At: Hope Creek Nuclear Generating Station Hancocks Bridge, New Jersey Inspection Conducted: Septe ber 6 through September 16, 1988 Team Leader: kano e 4%%Ww mes E. Cumins, Team Leader
/b/d Datd 5 gne
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nior Operation Engineer, NRR Accompanying Personnel Glenn W. F. eyer Senior Resident Inspector, Region I
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David K. Allsopp, Resident Inspector, Region I Consultants: Donald A. Beckman, Prisuta-Beckman Associates, In Cary Bethke, Comex, Corp.
. Mark W. Parrish, EG&G Ideho In Michael Mecherikoff, EG&G Idaho, In Other NRC Personnel Attending the Exit Meeting:
James E. Konklin, Chief Team Integration Section, RS!B, 0x!S, NRR
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Paul D. Swetland. *,hief Reactor Project Section, Region I g N., . /b!/d/SS Reviewedby[:
, ry . L e #, ve M. 'ii Date Signed Tei "
t.I and Development S . L :
Approved by:
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> acial Inspecty Bran, a S,
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G8111702 ADOCv .>500 54 PPR *
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TABLE OF CONTENTS PAGE INSPECTION SCOPE ..................................... 7..:..... 1 BACKGROUND ..................................................... 2 DETAILED INSPECTION FINDINGS ................................... 3 Program and Procedure Review .............. .................... 3 3. Comparison of Emergency Operating Procedures. Owners'
Group Emergency Procedure Guidelines, cnd Plant-Specific Technical Guidelines ......................................... 3 3. R e v i ew o f W ri te r ' s Gu i de . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 3.1. Comparison of Revision 2 of Writer's Guide with NUREG-0899 ..... 8 3.1. Jomparison of Revision 2 of Writer's Guide with Emergency Ope ra ti ng Procedu re s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 3. Verification and Validation Program ............................ 11 3. E0P Calculations .................... .......................... 14 3. Ongoing Evaluation of E0Ps ..................................... 17 3. Quality Assurance of Plant-Specific Technical Guidelines ....... 17 3. C o n ta i nme n t Ve n t i n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 3. Postaccident Reactor Building Habitability and Reentry ......... 19 Plant Walkdowns of E0Ps ........................................ 20 E0P Evaluation Using the Plant-Specific Simulator .............. 28 3. Simulator Scenario #1 .......................................... 28 3. Simulator Scenario #2 .......................................... 29 3. Simulator Scenario #3 .......................................... 30 3. Simulator Scenario f4 .......................................... 31 3. G e n e r a l C ome n t s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 E0P Training ................................................... 32 3. Initial Licensed Operator T.aining ............................. 32 3. Eq u i pme n t O pe ra t o r T ra i n i n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 3. L i c en s e d Ope ra t o r Re t ra i n i n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 3. Instrument Technician Training ................................. 33 3. Chemist Training ............................................... 33 3. Training on E0P Revisions ...................................... 34 4.0 Exit Meeting / Persons Contacted ...................................... 35 ATTACHMENT A PERSONNEL CONTACTED - EXIT MEETING ATTENDEES ATTACHMENT B DOCUMENTS REVIEWED ATTACH"ENT C ABBREVIATIONS AND ACRONYMS
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1.0 INSPECTION 500PE The inspection was performed to verify ^ hat the Hope Creek Nuclear Generating Station emergency operating procedures (EOPs) were technically accurate; that their specified actions could be physically carried out in the plant using existing equipment, instrumentation, and controls; and that the plant staff could correctly perform the procedures. The team also reviewed the licensee's provisions for containment venting. The inspection was conducted in accordance with the guidance in Temporary Instruction (TI) 2515/92 "Emergency Operating Procedures Team Inspections."
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2.0 BACKGROUND Following the Three Mlle Island (TMI) accident, the Office of Nuclear Reactor Regulation developed the "TMI Action Plan" (NUREG-0660 and NUREG-0737). Item I.C.1 of this plan r luired licensees of operating plants to reanalyze tran-sients and accidents snd to upg n de Emergency Operating Procedures (EOPs).
In addition, Jtem I.C.9 of the plan required the NRC staff to develop a long term plan that integrated and expanded efforts for the writing, reviewing and monitoring of plant procedures. NUREG-0899, "Guidelines for the Preparation of Emergency Q erating Procedures," reoresents the NRC staff's long term program 1or upgrading E0Ps, and describes the use of a Procedures Generation Package (PGP) to prepare E0P The licensees formed four vendor owners' groups corresponding to the four najor reactor types in the United States: Westinghouse, General Electric (GE),
Babcock and Wilcox, and Combustion Engineerirg. Working with the vendor company and the NRC, these owners' groups developed generic procedures that set forth the desired accident mitigation strategy. For GE plants, the generic guidelines Are referred to as Emergency Procedure Guidelines (EPGs). These EPGs were to be used by licensees in developing their PGPs. Generic Letter 82-33 "Supplement 1 to NUREG-0737 - Requirements for Emergency Response Capability," required each licensee to submit to NRC a PGF that included: Plant-Specific Technical Guidelines (PSTGs) with justification for safety-significant deviations from the EPGs; A Plant-Specific Writer's Guide (WG); A description of the program to be used for the verification and validation of the E0Ps; and A de;cription of the training program for the upgraded E0P Plant-specific E0Ps were to have been developed that would provide the operator with directions to mitigate the consequences of a broad range of accident and multiple equipment failure For various reasons, there were long de'ays in achieving NkC approval of many of the PGP Nevertheless, the licensees have all implemented tneir E0Ps. To determine ^he success of this implementation, the NRC is perfonning a series of inspections to examine the final product of the program: the E0Ps. A representative sample of each of the four vendor types was selected for review by four inspection teams from Regions 1. II, 111, and I An addit.onal 13 facilities, facluding Hope Creek, having General Electric Mark I containments, ware selected for E0P review. These inspections are being conducted by the Office of Nuclear Redctor Regulation and include a detailed review of the containment venting provisions of the E0P _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ - _ _ _ . .__ _ _ _ ____ ___ . . _ _ _ _ _ . _ _ _ _ _ - _ _ _ _ . _ _ _ _ _ _ _ _ _ _ .
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3.0 DETAILED INSPECTION FINDINGS The following sections present the scope and findings af each aspect of the
team's Hope Creek inspection. Attachment C to this report provides a consoli-dated list of the relevant acronyms and abbreviations used in this discussion.
3.1 Program and Procedure Review
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The team evaluated the licensee's program and its end product, the E0Ps, with i respect to the requirements of NUREG-0737, "Requirement for Emergency Response !
Capability," Supplement 1 and the guidelines provided in NUREG-0899, "Guidelines for the Preparation of Emergency Operating Procedures."
In ge:1eral, the Hope Cret.. emergency operating procedures (EOPs) used a j flowchart format for the operator action ste ,s and contingencies. There was no '
equivalent text-only procedure. The text procedures relating to each of the EOFs included only guidance, purpose, and precautions and were not necessarily :
used during event response l Documents reviewed during the inspectica are listed in Attachment ,
The following sections present the findings of the tear.'s program and procedure l review:
3.1.1 Comparison of Erwrgency Operating Procedures Emergency Procedure "
Guidelines, and Plant S;,ecific Technical Guidelines The teamthe (EPGs), reviewed and compared plant spectiic the owner's technical guidelines PSTG group
, and (ct.er theency procedure guidelines emergency operating procedures (EOPs), and identified the following discrepancies between ;
the document , The Hope Creek Conversion Document consisted of a comparison of the PSTG with the EPAs and a couparison of the PSTG with the equivalent E0P flow I diagram segments. The document was intenced to identify the discrepancies between the EPGs and the implemented procedures, and to provide the i justification for these deviation l
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The conversion do u w t was generally out of date and incomplet Similarly, the PSTL hsd not been maintained as a basis document used to ;
prepare E0P revisions. The licensee, acknowledged that priority had been l given to maintaining the E0Ps as the'"lead" document for revisions and ,
that the conversion document and PSTGs had not been maintained, although I this approach wa. contrary to the principles of NUREG-0899 and the !
licensee's PGP. A revision to the PSTGs, issued July 27, 1988, correc+,ed i
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a nutober of discrepancies, but the team identified the additional disc.e- i pancies discussed belo . The flow diagram sequence for a reactor building fire, provided in h OP-EO.ZZ-10?. "Containment Control & Drywell Pressure Control " Revision !
1, steps RD/T-12 through Rb/T-17 was not reflected in the PSTG or the l
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convers%n document. The flow diagram logic indicated a serial l
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a relationship in which response to a fire would 'ollow response to a leak, although the EPGs required a parallel response. No justification for this deviattors was provided in the conversion document.
' The EPG s*.ep SC/L-3 required emergency reactor pressure vessel (RPV)
depressurization if a primary system discharged into more than one reactor ,
building area such that maximum safe operating floor water levels were exceeded. OP-EO.ZZ-103 flow chart steps RB/L-8 through RB/L-11 required only normal depressurization and were not addressed in the conversion documen ,
, The sequence presented by OP-EO.ZZ-201, "Level Restoration," Revision .teps LR-1 and LR-2, reversed that of the PSTG and conversion document, ;
steps C1-1 and Cl-2. This reversal resulted in E0P actions being taken, in step LR-1, to align systems for injection prior to consideration, in ,
step LR-2, of the conditions that may require entry into any of three :
, other contingency procedures. This configuration could delay more '
significant required actions, OP-E0.ZZ-204, "Spray Cooling," Revision 0, step SPC-1, required concurrent performance of OP-E0.ZZ-202, "Emergency Depressurization, Revision 1, as ;
the first step in initiation of spray cooling. The EP",, PSTG, and conver- :
sion document, step C4-1, simply stated "open all ADS valves." The :
step SPC-1 transfer to OP-E0 ZZ-202 required the operator to perform a ,
number of steps (verification of boron injection status, termination and i i prevention of injection, suppression pool level verification, and others)
prior to opening automatic depressurization system (AN) valves. This !
sequence appeared to be unnecessary, and could result in delay of required ;
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actions. No justification was provided, EPG and PSTG Contingency 5. "Alternate Shutdown Cooling," steps C5-3 i through C5-6, provided instructions for opening safety relief valves l
- (SRVs), raising the water level in the reactor pressure vessel (RPV) to ;
I establish a flow path through the open SRVs, and then using a low-pressure coolant injection (LPCI) or core spray (CS) pump to provide alternato l
- shutdown cooling flow. OP-EO.ZZ-205, "Alternate Shutdown Cooling,"
Revision 0, steps A$C-3 through ASC-7, corresponded to the above steps, !
! except that step A3C-5 required termination and prevention of all injec-
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tion into the RPV except from the control rod drive (CRD) system. No ,
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equivalent of step ASC-5 was included in the EPG or PSTG. The step was included in the PSTG to-Flow-Diagram conversion document; however, no ;
justification for the step was provided, r The EPG and PSTG step C6-2,1 included a retainment step requiring transfer j
- to E0P-1 (OP-EO.ZZ-101, "Reactor Pressure Vessel Control " Revision 1),
step RC/P-4, and to Contingency 7 (OP-EO.ZZ-207, "Reactor Level / Power
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Control," Revision 1) if RPV flooding was not required. OP-EO.ZZ-206, j
"Reactor Flooding " Revision 0, step RF-6, the equivalent step, referenced
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OP-E0.ZZ-207, but on.itted the transfer to OP-EO.ZZ-101. No je Nication ;
i for the deviat:-.. was provided ia the conversion document. The unsee ;
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s':ated that the omission was acceptable in that OP-EO.ZZ-207 rea ts in .
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eventual transfer to E0P-1 at the end of the procedure. However, the steps were not equivalent, and no justification for the deviation was <
documente '
h. The EPGs for E0P-1 (OP-E0.ZZ-101) included a retainment step.following RC/P-2 which directed a return to step RC/D-2 if the reactor was not shutdown while executing subsequent steps. This retention step provided for continuing RPV pressure control via turbine bypass valves. The i equivalent E0P-1 flowchart step, RC/P-10, did not include logic or in tructions equivalent to the EPG retention step. No justification for the deviation was provided in the conversion documen . EPG secondary containment control guidelines required definition of a
"maximum safe operating (araa) radiation level" as a point at which E0P response actions were escalated to include manually scraming the reactor i and either normal or emergency depressurization. OP-E0.ZZ-103, "Reactor Building Control " steps RB/R-5 through RB/R-8, defined this level as an
"estimated dose for required area entry greater than 25 Rem."
The licensee expleined that the value nad t,een chosen prior to full operability of all reactor building area radiation monitors, and had been i based on emergency plan guidelines for maximum exposures allowable for l equipment restoration or recovery. The team believed that the criterion was ambiguous in that it was not a specific dose rate, but appeared to represent an integrated dose, that is, a higher dose cate that could be ,
tolerated based on occupancy requirements of less than one hour. Further, ;
the team believed that the 25 Rem limit, even if considered to be 25 Rem .
per hour, was excessive and represented a very significant increase over the procedure entry conditions.
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Similarly, Table 2 in OP.E0.ZZ-103 used sump pump continuous run time as :
the criteria for maximum safe floor level. The run times in the precedure were based on the calculated time to reduce the water level in respective rooms from 4.5-inches to 1.0-inch. This process made the criterion
- dependent on total floor space, rather than on factors such as pipe size ,
and equipment sensitivity. Monitoring sump pump run time during an i accident, which required communications with the radwaste control room, :
would be difficult and distracting. The licensee should reevaluate this I criterion, and give consideration to replacing it with a more observable
criterio j. Step C2-1.3 of the EPGs specified that systems used for alternate reactor '
a depressurization were to be "used in order which will minimize radioactive release to the environment." This information was not included in the corresponJing PSTG step. The justification in the PSTG was that "radio- l activity release is addressed in OP-E0.Z:'-104." However, OP-EO.ZZ-104 did
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not provide guidance for use of systems to minimize radioactive release, k. Step DW/T-4 of procedure OP-EO.ZZ-102, "Containment Control." Revision 1, stated "CAN DRWL AIR COOLER INLET TEMP BE MAINTAINED BELOW 200"F". The
"YES" response resulted in continuation to step DW/T-7, thereby bypassing the requirement of step DW/T-5 to "RUNBACK RECIRC AND MANUALLY SCRAM" when ,
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drywell temperature cannot be maintained below 200'F. PSTG step DW/T-1 required that the reactor recirculation pumps he run back and the reactor shutdown when drywell temperature cannot be maintained below 200" If the operator determined initially that drywell temperature could be maintained below 200"F, no action would be taken to limit temperature - '
increase until the temperature reached 340' The licensee stated that the flowchart should have indicated that a "YES" response to DW/T-4 should result in continued monitoring of drywell temperature, and initiation of DW/T-6 actions when required by step DW/T- '
1. Step RC-2 of E0P-EO.ZZ-102, "Reactor Pressure Yessel Control " required that the mode switch be placed in shutdown. The E0P was required to be re-entered each time a new entcy condition existed. If, during a failure te scram, the mode switch was taken out of shutdown in order to reset the scram, reentry into the E0P on another entry condition would result in placing the mode switch in shutdown. This action would frustrate efforts to drain the scram discharge volume. Step RC-1 of the EPGs and PSTG indicated that "if a scram has not been initiated, initiate a scram." Neither PSTG step RC/Q-4 nor the corresponding'EOP step RC/Q-43 referenced a procedure by which borated water was to be added to the reactor vessel through the reactor water clean-up (RWCU) system. A reference to OP-EO.ZZ-304, "Boron Injection Using RWCU," should be added to each of these step ; The PSTG step RC/Q-5.5.2 did not refererce the procedure used to bypass l the rod sequence control system (RSCS). The corresponding E0P ste RC/Q-20, referenced OP-E0.ZZ-307, "Bypassing RSCS." This reference should be added to the PST ; Neither the PSTG step RC/Q-5.5.4 nor the corresponding E0P step RC/Q-2':
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referenced a procedure for venting the CRD hydraulic control units (HCUs).
! The licensee should develop a support procedure (300-series) to accomplish the venting, or mooify an existing system operating procedure (such as .
l OP-50.BF-002, "Individual CRD HCU Operations") to add the appropriate L references to tools and high temperature protective clothing which may be '
i required. The new procedure should be referenced in the PSTG and E0P r 1 The PSTG step SP/T-3 did not reference the procedure by which the plant 1 was to be depressurized. The corresponding step in the E0Ps did contain !
the proper reference to procedure OP-10.ZZ-004, "Shutdown from Rated Power ;
to Cold Shutdown." l 1 t The PSTG step PC/P-7 did not contain a reference to procedure l OP-EO.ZZ-318. "Containment Venting," which was referenced in the i corresponding E0P step. DW/P-1 !
i The PSTG step SP/L-2, which corresponded to E0P step SP/L-10 stated "If the combination of suppression pool level and temperature cannot maintain ;
net positive suction head (NPSH) for pumps taking a suction on the i suppressicn pool, then line up and inject from systems which take a i
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suction external to containment." Rather than referring to pool level .
and temperature, the PSTG step should refer to the parameters plotted on ,
curves $P-L-2a and SP-L-2b and described in the E0P step. The parameters :
refwrenced should be temperature, pump flow, and pressur ,
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- PSTG step 01-2, which listed alternate injection systems to Be linedup, l did not reference the 300-series support procedures by which these '
lineups were to be made. The corresponding steps in the Level ;
- Restoration E0P (OP-EO.ZZ-201) did contain the proper reference to the '
- alternate injection system lineup procedure '
l PSTG step C6 2.1 used the confusing nomenclature, "If less than 1 SRV can 1 be opened, continue in this procedure." The licensee should consider y changing this step to read "no SRVs" instead of "less than 1 SP,V." ,
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i PSTG step Cl-2 listed the alternate injection systems as: !
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! Service Water; l l Fire System; {
> Emergency Core Cooling System (ECCS) Keep-Full Systems; and t
- (4 Standby Liquid Control (SLC). ,
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The corresponding OP-EO.22-201 E0P flowchart steps, LR-4 and LR-5, listed l the alte nate injection systems as: t i
(1)CondensateTransferand l l (2) Standby Liquid Contro ;
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i In addition the E0P flowchart steps listed the standby injection systems [
as: F J) >
j (1)FireWaterand l l (2) Service Wate j
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The ECCS keep-full systems at Hope Creek consisted of jockey pumps placed !
in parallel with the systems' normal purps. These jockey pumps ran
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continuously and would provide a small source of low-pressure injection if
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! The PSTG did not include condensate transfer as an alternate injection f l system, and tiie E0P did not include ECCS jockey pumps (ECCS keep-full l l system). The PSTG and the E0P should be brought into harmony with respcet ;
- to alternate and standby injection system l
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I Pendir.g ferther NRC review, the above unjustified deviations (items 3.1. p
! through 3.1.1.u) in the E0Ps from the EPG and PSTG are an unresolved item ;
j (354/88200-01).
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3.1.2 Review of Writer's Guide 3.1.2.1 Comparison of Revision 1 of Writer's Guide with NUREG-0899 The team reviewed Revision 1 of the writer's guide (WG), and, in general, found that it complied with NUREG-0899. However, the team identified a number of discrepancies between the WG and NUREG-0899, which were discussed with the licensee as improvement items. Examples of these items are described in the following paragraphs: NUREG-0899(5.6.1) discussed the consistent use of short, comon, concrete, specific words. The WG (5.4) essentially restated this guidance,
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recomended that verbs with specific meanings be used, and provided a list H of possible action words (WG Attachment 5-Comands List). This list was not referenced in paragraph 5.4 of the WG, but was identified in the WG (step 4.4.1d) as a list of suggested verbs. The list did not contain all action words allowable in the E0Ps, and did not contain definition It did, however, contain words which appeared to be used synonymously or
, interchangeably . For example, the words COMMENCE. INITIATE, and START appeared in the Comands List and in the E0Ps, and BEGIN was used in the E0Ps. Similarly, the word VERIFY was used in the flowcharts, and the words CONFIRM and ASSURE were defined in the definition sections of the i E0Ps, although they were not used in the E0Ps. A complete list of allowable verbs with definitions should be provided to eliminate inconsistencies and ambiguity in the E0P The guidance in h0 REG-0899 (5.6.6 and 5.6.7) was inconclusive regarding the specificatic't of numerical values in the E0Ps only to the level of '
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precision readable from available instrumentation. The WG (4.4.3f) stated that values in the flowcharts shall correspond to values that the operator can obtain from plant instrumentation.
! The E0Ps did not always observe the WG convention concerning the required '
level of precision. The justification given by the licensee was that the operators were very familiar with certain velues that exceed the accuracy to which instrumentation can be read (for inscance, certain set points),
and expressing plant conditions in the E0PS 1,1 tenns of these familiar ,
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values was considered helpful to the operators. The WG did not discuss
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this exception to its general rule concerning the required level of precision, nor did it list the values which were exempt from the general ,
rul To help define for the procedure writer the objectives and constraints in
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the development of E0Ps, NUREG-0899 (5.8.2 and 5.8.3) recew. ended a discussion of control room staffing. This requirement would ensure that the E0Pa minimize staff conflicts, avoid duplication of actions, and allow the control room supervisor to keep up with staff actions and plant ccnditions. In addition, NUREG-0899 (5.8.2 and 5.8.3) required a discus-sion of the anticipated manner of use of the E0Ps in the control roo The WG did not address these issues, nor did it address the physical form of the E0Ps and their anticipated mode of storage, accessibility, handling, and us ,
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3.1. Comparison of Revision 1 of Writer's Guide with E0Ps
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The inspection team performed a detailed review of the Hope Creek E0Ps for adherence to the requirements of the Writer's Guide (WG) and established human
, factors principles. Series 100 and 200 E0Ps covered the basic emergency procedures and the contingency procedures as defined in the EPGs.- Sections 1 through 4 in each ; rocedure consisted of Purpose, References, Definitions, and Responsibilities; 'iection 5 consisted of the action steps (flowchart).
The flowcharts, ia general, were found to be in good compliance with the WG, and, in fact,1:e some instances, went beyond the requirements of the WG (for example, the use of color-for-color coding and emphasis).
The preparation and format of the E0P support procedures (Series 300 E0Ps) were not controlled by the WG, but by Attachment 2 of OP-AP.ZZ-001(Q), "Preparation and Approval of Operations Departinent Procedures," and were written in system operating procedures (SOP) format (WG 3.2). In the plant walkdowns the proce-dures were found to be clear and the format was appropriate and helpful to the operator .1.3 Verification and Validation Program The team reviewed the verification and validation (V&V) progran established by
the licensee to support the implementation of and revisions to the E0Ps. The l program was modeled after the Institute of Nuclear Power Operations guidelines l (INP0-83-004, March 1983, and INP0-83-006, July 1983) for LOP verification and validation. The team found that the Hope Creek V&V progrem, titled "Work Plan i For E0P Verification and Validatica At Hope Creek Generating Station," met the intent and requirements of both the INPO guidelines and the V&V section of NUREG-0899.
! The team reviewed the results of the initial V&V conducted in 1985, and found j the review process to be adequate. The team reviewed the procedure with particular attention to how it has been applied since the E0Ps were first
! 1mplenented in 1985. The most recent revision (Revision 0) to the Hope Creek l V8V program was dated July 1985 and became part of the Final Safety Analysis i Report (FSAR), Appendix 13L, on April 11, 1988.
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! As background for the comments which follow, excerpts from the V&V program l described in the FSAR are provided below.
l Section 2.2 of the V&V program read,!"When a step, subsection, or i attachment to an approved procedure is changed, verification steps will be
! performed as necessary to ensure: (a) * hat procedure changes accurately
! reflect technical source data; (b) that the plant-specific technical
) guidelines are maintained up-to-date; and (c) that all procedure changes l are written in accordance with the Writer's Guide."
, Section 2.7 of the V&V program read "A partial Technicci verification l should be done when revisions are suggested for a limited portion of the
, procedure:
{ - Setpoint chat.ge for instrumentation i
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- Addition er removal of an alarm
- Addition or removal of a control, controller, displal-
- Changes in a table, graph or attachment."
c. Section 4.2 of the V8V program read "... validation will be performed when existing, approved procedures are revised, depending on the nature of *
the revision. A revised procedure must be validated when: .
- The revision arises from a plant equipment change (hardware or software) that alters the functions or response characteristics of a system or subsystem, or alters interrelationships between systems or subsystem The revision arises from a change in equipment characteristics that alters the functions or response characteristics of a system nr subsystem, or alters interrelationships between systems or subsystem .
- The revision arises frem a change in plant equipnient that could affect radioactive release control or that raises an environmental -
question not oreviously addresse The revision changes cues for operator actions or the expected results of operator action The revision changes the sequence of operator actions on one or mere branches of the procedure."
Given this background, the team identified the following pesblems concerning the V&V program:
(1) The V&Y program did not require the V&V process to be applied to the E0P support (300-series) procedures (such as, Bypasses Alternate ,
Injection Methods, Alternate Make-up, Containment Venting). This exclusion of the 300 series procedures was approved in the Hope Creek NRC Safety Evaluation Report (SER) (NUREG-1048, April 1986). These ,
precedures are an integral pa.*t of completing many of the 100- and :
200-series E0Ps. The licensee's safety review group and the 10CFR 50.59 review process at Hops Creck included the 300-series procedures as part of the E0Ps. Problems with the procedures, which are detailed in this report, indicate that the licensee should recensider i the exclusion of the 300-series procedures and subject these '
procedures to the V&V proces F (2) No V&V process had been applied to any revision of any of the 100 ,
200 , or 300-series procedures since the original review which was perfo'ued in the spring and sunmer of 1985. Nearly all of the EOFs i have undergone a revision since that time. Pending further NRC review, this failure to perform V8V of the revised 100- and 200-series '
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E0Ps is an open item (354/88200-02).
(3) The procedures listed below have undergone revisions during the past year, and are examples of procedures that appear to require a partial V&Y review (acco.' ding to the intent of the V&V program).
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Proced .ae Reason for Change t
OP-EO.ZZ-101 Change in the downscale setpoint of the averege power range monitor (APRM)
OP-EO.ZZ-203 Change in a level instrument scale . _
OP-EO.ZZ-30? Added steps to remove scram discharge volume (SDV)ventanddrainvalvefuses -
OP-EO.ZZ-304 Major re-write that changed many steps OP-EO.ZZ-309 Added steps to open bottom condensate storage tank (CST) suction ,
OP-EO.ZZ-310 Major re-write that changed many steps
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The reasons listed for the above revisions are examples and do not ,
reflect all of the changes which were mede to the subject procedure :
The sections of this report that concern E0P walkdowns and PSTG-to-EOP comparison provide numerous examples of the types of E0P wording errors and problems which could possibly have been avoided through the applica-tion of a V&Y review of procedure revisions, in completing the V&V portion of the inspection, the team noted the following additional examples of E0P errors:
(4) In procedure OP-EO.ZZ-302, "De-ener Revision 1,steoswereaddedtopulgizationofScramSolenoids,"
. the fuses on the SUV vent and drain valve solenoids. This action would ensure that the SDV was .
isolated prior to pulling the scram solenoid valve fuses. The !
section of the procedure titled "Purpose" was r.ot revised to reflect l the new scope of the procedur .
(5) In proaedure OP-EO.ZZ-309, "Alternate Injection Using Conensate Transfer " Revision 5. steps were added to open valve 1-AP-V015 to I allow the Condensate Transfer pumps to take a suction on the bottom of the CST (rather than at the FCCS standpipe levei). In step b.1.10, an error was mai.e ia referring to the repetitive steps which ;
must be performed to cot,tinue injection to u intain the reactor :
pressure vessel (RPV) level. The procedure mistakenly referred to steps 5.1.6 and 5.1.8 when it should "nave referred to steps 5.1.7 and I 5.1.9. Similarly, in step 5.2.9, the proccure incorrectly directed i the operator to repeat steps 5.2.5 and 5.2.7, rather than steps 5. and 5. ;
The Hope Creek E0P revisions were reviewed by a Station Qualified Reviewer (SQR), as mandated by section 6.5.3 of the station Technical Specification Final approval of the procedures was the responsibility of the Operations Manager. Although all recent revisiens have been subjected to an SQR review in accordance with Static- Administrative procedure SA-AP.ZZ-032(Q), "Review and Approval of Station Procedures and Procedure Revision," Revision 6. none of the reviews checked by the team have been assessed as requiring a safety evaluation or involving a significant safety issue (SSI). As previously stated, none of the recent revisions to the E0Ps have been subjected to a partial V&Y process as would seem appropriate based on the wording of the FSAR docketed V&V progra *
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In sumary, the relatively numerous errors in the E0Ps identified by the team indicated a need for Hope Creek to greatly improve its attention to detail in performing E0P reviews. It appeared to the team that one or more of the following methods could be used to improve the review process: (1) Upgradi..g to SQRs the importance of their the qualifications responsibility and of SQRs and attention stressing (2) Returning E0P review responsibility to detai to the Plant Operations Review Committee (PORC), (3) Imprcving the qualifica-tions and attention to d6; ail required of Safety Review Group personnel, and (4) Increasing the level of peer support for the E0P Coordinato .1.4 E0P Calculations The EPGs, Appendix C, provided calculation procedures for the various analyses and limits required to develoo ahd implement the E0Ps. Under the General Electric (GE) Quality Assurance Program the licensee had contracted GE to perform the calculations and to assemble EPG, Appendix C, Table Cl-T4, "Plant Data Table" (the tabulation of plant-specific input parameters for the detailed calculations). In it's initial transmittal of the calculations (GE Letter, J.S. Post to S.L. Mischke, PSE&G October 30,1984) GE stated that all calculations except numbers 6, 8, 9, 19, 21 and 25 had been performed 13 accordance with EPG revision 3 and subject to GE verification processe The letter stated further that calculations 6, 8, 9, 19, 21, and 25 had been performed using EPG revision 3A and calculation number 4 had been perfonned using a preliminary procedure from Bechte The team reviewed a sample of the procedures, completed calculations, and related correspondence, and performed confinnatory calculations. The specific documents reviewed by the team were:
- EPG, Appendix C, Table Cl-T4, " Plant Data Table"
- Calculation 3.0, Heat Capacity Temperature Limit (HCTL), original calculation dated October 23, 1984, and res sed calculation dated August 31, 1988
- Calculation 4.0, Suppression Pool Load Limit
- Calculation 12.0, Pressure Suppression Pressure
- Calculation 15.0, Heat Capacity Level Limit
- Calculation 20.0, Minimum and Maximum Alternate Sh.,tdown Cooling Pressures and Minimum Number of SRVs Required for Alternite Shutdown Cooling
- GE Transmittal of Appendix C Results, October 30, 1984
- GE Transmittal, Resolution of Coments to Hopt Creek Appendix C Data and Calculations, February 4, 1985
- PSE&G Letter MEC-88-04J5, incorrect specific heat values (C g , Cp ) used in calculation 3.0 (HCTL), dated July 12, 1988
- GE Letter G-KT-8-310, correction of specific heat errors in HCTL calculation, dated July 29, 1988
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PSE&G Letter MEC-88-0026, incorrect shutdown cooling interlock (PSDC}
setpoint used for calculation 3,0 (HCTL), dated August 23, 1988
- GE Letter G-KT-8-149, corrected HtlTL calculation, dated September 6, 198 As previously stated, the calculations were performed under t.he GE quality assurance and calculation verification programs. Correspondence and discussion with the licensee staff established that initial (1984-85) licensee desk-top review com:nts on the final calculations had been resolved and that additional errors had recently been identified by tne licensee and resolved by G _
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'o The team, however, identified the following errors, questicnable calculation practices, and quality assurance program deficiencies in the calculations and the licensee's associated administration, The licensee has established procedures for configuration management and design control. The Standards and Assurance Supervisor and the' Senior Staff Engineer responsible for the calculations provided the team with procedures Package," DE-WB.ZZ-001(Q),
Revision "Engineering)
0, and DE-AP.ZZ-001(Q Work
, "Design BasisBook for Revision
/ Input," Standard Change 0, which appeared to include reasonable control provisions. However, the calculations reviewed by the team had not formally been subjected to the requirements of these procedures. Moreover, the procedures were not subject to formal document control or records management and storage provisions, Although the initial licensee review connents (GE lettor, February 4, 1988, above) appeared to be detailed, the team found the following additional discrepancies in the original calculations which shnuld have been identified and correcte (1) Calculation 4.0 was identified as preliminary by the Gi transmittal, and final BWROG and licensee approval and acceptance of this calcula- '
tion was not evident. The licensee stated, however, that the calculation had been approved by the BWROG and NRC in a final form ,
equivalent to the preliminary version use !
(2) The team's review of calculation 20.0 found that an incorrect steam table value had apparently been used for the specific volume (v ) of water at 308.26'F. It appeared that the specific volume had, f instead, been determined for a pressure of 308.26 psia, resulting in a value approximately eight-percent higher than the correct valu The erroneous value was then used to calculate V , the volume of reactorcoolantflowrequiredforcorecooling,fesultingin
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propagetion of a corresponding eight-percent (conservative) error through the remainder of the calculation. This error adversely ;
affected the calculated minimum SRV differential pressure and the minimum number of SRVs required for alternate shutdown cooling, j Although this appeared te have negligible effect on the final calculation, the errors were sufficiently fundamental that they
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should have been identified during licensee revie I (3) Calculation 12.0 used 25.53 feet as the elevaticn of the suppression ;
chamber pressure instrument tap (E-SCPI), although the value shown in :
Table Cl-T4 was located at elevation 24.98 fee !
k Again, the net effect on the calculation's final result was I negligible, but there was no evidence of error identification or !
recalculation tu verify the cffect. This calculation was further !
affected by a revised velue of T-SRV the heat capacity temperature !
limit (HCTL) at the RPV pressure corresponding to the lowest SRV i setroint, resulting from the 1988 revisions to calculation ,
(discussedbelow). Additional examples of observed documentation errors included incomplete data blanks for calculation steps ;
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12.4.1.8, .9, and .10, 12.4.2.6 and 12.4.3, and omission of a plot of Figure C12-2, "Suppression Chamber Volume vs. Suppression Pool Water Level " used in step 12.4.1.9. Similar examples of incomplete i data blanks and curve plots were identified in calculation 15.0, i steps 15.5.2, 15.5.3, 15.5.4, 15.5.5, 15.5.6, and Curve C15-2. The [
validity of the calculations was not affected since the' data (or equivrient)wereavailableeitherelsewhereintherespective '
, calculation or ir. another calculatio (4) In July 1988, the licensee discovered that an incorrect value of 135 !
psig had been used in the HCTL calculation for P-SDC, the shutdown i
- cooling interlock pressur This error was identified to GE j (August 23, 1988 PSE&G.lette7) and a revised HCTL calculation and !
l curves were issued by GE on September 6, 1988. The team identified several problems resulting from this calculatio }
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First, portions of the calculation package provided by GE were !
illegible, caking both licensee and team review difficul !
r Second, the original HCTL calculation outputs were used as inputs to '
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other calculations includinv those for heat capacity level limit (HCLL) and prenure suppression pressure. The interaction between the HCTL and other calculations nad not been identified by either GE '
l or the licrasee. The team performed a confinnatory calculation for HCLL using ccrrected values for M-BD(SRV), mass transfer from the
, RPV to the suppression pool durin;; a blowdown, and delta-T(SRV),
change in suppression pool water temeprature during a blowdown, frem the revised HCTL calculatiuns, and found a significant but conserva-tive crror in the final HCLL. Calculation 11.0 was similarly
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affected and the team reyaested that the licensee determine the impact of the revised input data and any other occurrences, r
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.j Additionall) , the calculation uses P-SRV, RPV dete pressure l J corresponding to the lowest SRV setpoint, as an input value of 1108 i l psig in both the original and revised calculatio Since performing :
I the original calculation, the licensee has installed a "low-low set" ;
' feature on the SRVs which will automatically reduce the satpoint for ;
certain plant conditions. The variable setpoint and expected t l setpoint tolerances were apparently not considered in the revised I j calculation; the licensee was reviewing this matter at the I
, conclusion of the inspection.
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j Although the calculation discrepancies discusscd abuve were not individually
safety significant, the team was concerned that the rate of their occurrence in
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the relatively small review sample sad the informality ot' the licensee controls
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made the integrity of the unreviewed calculations questionable. Pending further NRC review, the above calculation discrepancies (items 3.1.4.b(1)
, through 3.1.4.b(4) are an unresolved itera (354/88200 03).
3.1.5 Ongoing Evaluation of E0Ps
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Section 6.2.3 of NUREG-0899, "Guidelines for the Preparation of Emergency 1 Operating Proceduras," recommends that licensees establish a program for the ongoing evaluation of the E0Ps. For this feedback, the licensee relied on the-14-
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plant procedure SA-AP.ZZ-001-1, "Preparation of Station Procedures and Procedure Revisions." The procedure required L review of E0Ps every two years. The team felt that the licensee was not fully utilizing other opportunities for identifying and correcting errors in the E0Ps. The team conducted a review of plant and training department procedures and interviewed
- several personnel concerning feedback on E0Ps. Based on these procedure
- reviews and personnel interviews, the team concluded that
- (1)althoughfeed-back did occur, it did not occua consistently; (?) efforts were duplicated by the instructor and the crew for feedback items that were raised during training i sessions; and (3) the originator of feedback on the E0Ps did not receive a j response as to the actions that would be or had been taken.
l 3.1.6 Quality Assurance of Plant-Specific Technical Guidelines q NUREG-0899, Section 4.4, "Quality Asturance " states that the plant-specific technical guidelines should be subject to examination under the plant's overall q Quality Assurance (0A) program and that review and control of the guidelines should be included in the QA program.
I The existing PSTGs and associated appendices, calculations, and conversion documents were not controlled under the licensee's QA program, although th?
E0Ps and associated procedures were. The licensee had not implemented proce-dural controls for the preparation, review, and approval of these documents.
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For example, none of the PSTG revisions or the conversion documents were controlled under site administrative procedures. Similarly, the calculations discussed in section 3.1.4 of this report had been prepared by General Electric
and had been informally reviewed by the licensee's engineering personnel; j
however, the calculations had not been subject to t&e licensee's fonnal
- configuration management programs, i
! The E0P develo> ment process had not been subject to routine QA audit or
! surveillance, )ut had been audited and reviewed during May - June, 1988, by the
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Hope Creek Safety Review Group. The team reviewed this audit report and found
- it to be generally comprehensive and effective in identifying procedure and l program problems. Many of the findings were similar to those found by this 1 team, and corrective action was in progress.
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Although application of the licensees' QA program to the development and maintenance of the E0Ps had been minimal, the team found the E0Ps generally acceptable and able to be performed in the field. The initial PSTGs had been reviewed and found acceptable by the NRC as part of the plant licensing process (NUREG-1048, Supplement 5. "Safety Evaluation Relating to the Operrtion of Hope Creek Generating Station," Section 13.5.2.3.1, April 1986). Nonetheless, the number of specific procedure, calculation, and related discrepancies identified de ing this inspection indicated a clear need to implement more rigorous qua..ty assurance measures for the E0P progra .1.7 Containment Venting The team reviewed the provisions in OP-EO ZZ-102, "Containment Control and Drpell Pressure Control." Revision 1, and OP-E0.ZZ-318. "Containment Venting "
Revision O. In conducting this review, te team evaluated the confonnance of the provisions to the EPGs, acceptability Jf the engineering bases for the-15-
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procedt.res, and the ability of the operators to implement the procedures during walkthrounh scenario OP-E0.ZZ-102 required venting the containment in accordance with OP-E0.ZZ-318 and consistent with the criteria of the EPGs. The procedures provided for venting the containment at 65 psig through seven sequenced vent paths beginning .
with small bore (2-inch) piping and progressing to 24-inch and 26-inch vent piths. The procedures also provided for initial venting through the suppres-sten pool, to take advantage of fission product screbbing. The capability of the flowpath valves to operate under accident differential pressures had teen evaluated by the licensee and found ade Containment pressure effects on automatic depressurization system (ADS)quate. valve operation had also been accommodated and the venting scheme had previously been reviewed by the NR The flow pa*.hs involving low pressure ductworir included ductwork blowout panels desigr;ed to relieve duct pressure at 1 psig. Three of the four blowout panels discharged to the torus compartment. The venting scheme was designed to fail the blowout panels and permit the containment pre-purge and cleanup system (CPCS) and the filtration, recirculation and ventilation system (FRVS) to process the vented accident products. The torus compartment was itself equipped with a 1.5 psig blowout panel which would relieve excess building pressure to the outside atmosphere. This arrangement had been analyzed as part of FSAR Change Notice 86-62 for a design basis loss-of-coolant accident (LOCA)
coinciJent with the opening of the cor.tainment isolaticn valves for a purge and exhaust operation. In that scenario, the panels were designed to protect the ductwork and building against reactor cooltot blowdown pressures until the containment isol tion valves automatically closed (approximately five seconds). t The flow path analysis did not address the E0P containment venting scenerio, but appeared to envelop the E0P parameters with one possible exception. The app 6 rent exception was that the rupture ranel at the 26-inch drwyell vent valve HV-4950, discharged to the 132-fo t elevation of the reactor building, rather then to the torus compartment. T' is portion of the reactor building did not appear to be protected from ove'. pressurization. The licensee was evaluating the team's questions at the conclusion of the inspection. Pending furthar NRC review, the licensee's evaluation of the potential everpressurization of the 132-foot elevation of the reactor building is an open item (354/88200-0<).
One notable feature considered advantageous by the team was the use of a i
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6-inch, high pressure pipe vent flowpath normally used to pressurize containment during integrated leak rate tests. Although the team observed several problems (described below) with the detailed steps of OP-EO.ZZ-318, i
"Containment Venting," Revision 0, the availability of a medium size, high integrity vent path was considered advantageous. The team identified the following problems with this flowpath procedure (steps 5.1.8 through 5.1.13),
o The procedure required rotation of a spectacle flange upstream from valve '
GP-V129 inside the reactor building at elevation 102-feet. The flange was located 15- to 20-feet above the floor with no direct access and no i
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cedicated ladder or scaffold. The equiprunt and tools required were not listed in section 4.0, "Equipment Required " of the procedure. The i licensee believed that sufficient isolation of the line was available i through closed valves and was considering either removing the flange or permanently rotating it to the "open" positio ,
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o Minor difficulty was encountered in locating valve GS-V058 in step 5.1.9; i a procedure location hint may be warrante l o The outdoor discharge for the vent path included several vent and drain valves with plugged tail pieces. The vent valve upstream from valve ,
GPV-129 wat, unlabeled and ite tailpiece had an open air-hose twist-lock 1 fitting installed. Similarly, the vent tailpiece for valve GPV-135 was !
uncappe l The team also observed the following general concerns regarding procedure OP-E0.ZZ-318:
o Thn step numbering and paragraph indentation hierarchy in the procedure !
was generally in accordance with OP-AP.ZZ-001(Q), "Preparation and Approval of Operations Department Procedures," Revision 1, applied to i normal operating procedures. Pswever, no major subject headings were i provided for the seven major ;1w path sequences in the procedure, making i differentiation of venting sequences difficul l
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o Step 5.1.24 referred the operator to step 5.1.6 if containment pressure i was not decreasing after the prior vent path alignment. The corract !
continuation step should have been 5.1.2 o Step 5.1.29 was intended to begin the seventh vent path alignment if the !
first six wera ineffective. The continuation instructions preceding this l step were omitted from step 5.1.26 or 5.1.2 [
3.1.8 Post-accident Reactor Building Habitability and Reentry The E0PG required entry into the reactor building during and after an accident i to perform local operations as discussed in the OP-EO.ZZ-300 series E0P support ;
. procedures. NUREG-0737, "Clarification of TM! Action Plan Requirements " Item ;
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11.B.2. "Design Review of Plant Shielding and Environmental Qualification of
) Equipment for Spaces / Systems Which May Be Used in Post Accident Operations," !
! required that each licensee provide access to plant areas adequate to permit an ;
i L operator to aid in the mitigation of or recovery from an accident. This item i required the licensee to identify plant areas to which such access was required i and to analyze the adequacy cf radiation protectwn based on specific source i tems. The licensee's evaluation was included in FSAR section 1.10.2, "TMI At tion Plan Requirements for Applicants for an OL " and section 12.3.2.2.6,
"Post Accident Shielding Design and Access Review." FSAR figures 12.3-30
! through 12.3-57A, "Post Accident Shielding Design Review Radiation Zones,"
provided projected dose rate information, incluJing areas with rates greater than 5000 Rem / hour. Section 12.3.2.2.6 and Tablo 12.3-3 identified seven areas as "vital" to accident operations and eight areas as "useful." The FSAR did
, not, however, include many of the areas requiring access for the E0Ps, and stated that reactor building reentry was not required to support emergercy
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operations.
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The licensee stated that the above considerations had neither been reviewed nor applied to the symptom-based E0Ps for either general access requirements or specific E0P operational requirement .2 Plant Walkdowns of E0Ps l-17-
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In order to assure that the E0Ps could be accomplished successfully, the team perfonned walkdown evaluations of all E0Ps and supplemental procedures refere%ed in the EGPs. The team verified that E0P instrument and control designations were consistent with the installed equipment and that indicators, annunciators, and controls referenced by the E0Ps were available to the opera-tors. The team also verified that the controlled set of E0Ps in the control room was easily accessible to the operators, and that activities which might be required outside of the control room during an accident could physically be accomplished. All of the E0P and 300-series support procedures were walked-down in the plan During the plant walkdowr" the team identified the following discrepancies: OP-E0.ZZ-100, "Scram," Revision 2, step S-7, directed the operator to control the level between +12.5 and +54 inches using one of several injection systems. If reactor core isolation cooling (RCIC) was used, the nearest instrument which could be used to monitor the ievel was ebout ten feet away from the RCIC panel and at an oblique angle. If not already done, the licensee should evaluate this situation as a potential human engineering deficiency, The team noted the following problems with OP-E0.ZZ-101, "Reactor Pressure Y-*sel (RPV) Control:"
(1) The control rod insertion sequence document in use at the time of this inspection erroneously listed the first three rods in the sequence as 0 to 48 (notch out) rather than the proper 48 to O (notch in).
(2) Step RC/Q-23 directed the operator to vent the hydraulic control units (HCUs) for rods wLich were not inserted, but did not not reference a procedure by which the HCU venting was to be accomplishe The licensee should either reference the applicable operating proce-dure (OP-SO.CF-002, "Individual CRD HCU Operation") or develop a new procedure for this ste The licensee should also ensure that all of the hoses, tools, and protective clothing (such as insulated gloves)
are staged for this procedure in the same manner that kits are staged for 300-series E0P support procedure (3) Caution 8, which appears on the flowchart for OP-EO.ZZ-101,
"Reactor / Pressure Vessel (RPV) Control." did not refer to graphs SP-L-2a and SP-L-2b which were located on the flow chart for OP-E0.ZZ-102, "Containment Control." Due to this omission the operator was required to (1) realize that the graphs existed and (2) refer to another flowchart in order to comply with this caution, The team noteo the following problems with OP-EO.ZZ-201, "Level Restoration:"
(1) This E0P flowchart did not include E0P Caution 6 which stated "If drywell temperature exceeds 135 degrees F, use only channels A and B of the wide, narrow and upset RPV water level instruments." Since the intent of this E0P was to recover level, it referred to many-18-
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level indications and should, therefore, include the caution concerning use of level instruments at elevated drywell temperature (2) Step LR-7 of the flowchart stateo "!F LEVEL DROPS TO - 129 IN THEN PREVENT ADS USING ADS TIMER ACT BYP SWITCH." The label on the key lock switch to be positioned stated "ADS ACTUATION TIMER."- In this and other walkthroughs, the operators were somewhat confused as to whether procedure steps were directing them to reset the ADS timers (with switches labeled LOGIC B/F INIT and LOGIC D/H INIT), as in step RC/L-9, or to defeat the entire ADS actuation circuit (with switches labeled ADS ACTUATION TIMER), or to reset the high drywell pressure seal-in logic (with switches labeled HI DRYWELL PR LOGIC). To clarify the intent, the wording in this E0P step and others referring to the ADS system should be changed to match the labeling of the control board switches. The licensee should also consider conducting a special operator training session on this family of switches, and improving the labeling of the switches so that the labels better indicate the function of each set of switches, The team noted the following problems with OP-EO.ZZ-301, "Bypassing MSIV Isolation Interlocks," Revision (1) The labels above the relays (addressed by steps 5.1.4.1 throtgh 5.1.4.4) were extremely small and were somewhat obstructed by wiring in the panels. The equipment operator (EO) perfoming the walkthrough had difficulty locating the proper relays to be jampere The team member had similtr difficulty readinc the labels and finding the proper relays. In ad.fition to poor legibility, some labtis had numbers which were only One letter or digit different from t'iose of similar relays in the pr.nels (for example, Relays B21H-K12A and B21H-K212A). Because of this deficiency, the EO (and the team members) temporarily mistook relay K12A for K212A. The E0P-related relays in these parels were also not as easily differentiated from other relays since they were in other panels where only E0P-related components had banana plugs installed. Obviously, the '31ay designators cannot be changed. However, the E0P-related relays cr.J1d be highlighted through the use of color coding, a small '. dan, largs r labels, or some other means to aid in their locatio (2) The labeling *oblem described above for steps 5.1.4.1 ti. cough 5.1.4.4 also ,) plied to steps 5.2.3.1 through 5.2. In OP-EO.ZZ-302, "De-energization of Scram Solenoids," fuses F-30 C71A-F17A and F-29 C71A-F17B, which were to be removed in steps 5.1.2 and 5.1.3, were somewhat difficult to locate. The labels on the melamine fuse covers were easily read, but finding a specific fuse required a visual search of many fuses that appeared identical. The fact that the fuse numbers on a given terminal strip were not arranged in numerical order contributed tn the difficulty of locating a specific fuse. The E0P-related fuses could be highlighted tnrough the use of color coding, larger labels, a small sign, or other distinguishing means, OP-EO.ZZ-304, "BORON INJECTION USIFG RWCU," Draft Revision 1, was used to drain borated water from the the Standby Liquid Control (SLC) tank to the-19-
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Reactor Water Cleanup (RWCU) resin pre-coat mixing tank for transfer to the RWCU demineralizers and subsequent injection into the reactor vesse The procedure was walked-down with both an Equipment Operator (EO) and a Shift Chemistry Technician. The SLC portions of the procedure were accomplished by the E0, and the RWCU portions (such as operation of the precoat systera) were accomplished by the chemist, it sh W be noted that the procedure used was a draft revision which the licensee had produced to correct deficiencies identified by its safety review group. Tti licensee stated that the draft represented an improvement over the approsed procedure, and requested that the team use it for the walkdown. The team noted the following problems and recomendations for improvement of the procedure:
(1) Step 3.4, "Precautions and Limitations," stated, "The steps in this procedure refer to the "A" demineralizer, "B" demineralizer is referred to in parentheses." This wording convention was not, however, adhered to in the body of the procedure. Rather than using references to the "B" demineralizer such as "FRCS-il74A (FRCS-39748),"
the procedure used wording such as "FRCS-3974 e B' and "BG-HV-3932A or BG-HV39328." In addition to this discrepan ), the procedure was internally inconsistent in that it sometimes wiote the entire valve or control designator for "B" components and swetimes used an "or B" statement. In a procedure of this complexity. it is imperative that steps referring to alternative trains of comp;nents be clear and consistent. The licensee should revise this procedure and check other procedures for similar occu..;.::: vi this proble (2) The labeling in Local Panel 10C601 (for leads B-TB-213-1 and others),
referred to in steps 5.2.5.1. through 5.2.5.4, was small and difficult to rea (3) The teminal board labeling for TB-162 and 1B-172 in Local Panel 10C6602 was small and difficult to read. The TB-162 label was partially hidden behind a wire bundl (4) Note 5.3, which preceded the RWCU portion of the line-up procedure, stated, "Chemistry personnel should perform this section, if available." The team detemined that EOs were not trained to perfom the RWCU portions of this procedur1 and that chemistry personnel were trained on the RWCU system, but not specifically on this procedur The licensee should provide chemistry personnel with specific '
training on the procedure and should consider training EOs in all steps of the procedure since current shift staffing had only one chtnist on the 1600 - 2400 and 0000 - 0800 shift (5) Neither valve 1-BH-V044, SLC Pump BP208 Suction Drain Valve, nor valve 1-BH-V017, SLC Pump AP208 Suction Drain Valve, had the large, easily-readable labels found on most other E0P-related manual valves in the plant. These valycs had the standard small metal tags, which all valves bad, but lacf ad the large yellow labels found on other E0P valve (6) Leveral pipe fittings and pieces of tygon tubing were required to be connected together by the E0 when accomplishing the procedure. The-20-
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following modifications to staged materials and procedures would enhance the speed and reliability of assembling the connection from the SLC to the RWCU pre-coct tank, o The 1-inch to 1/2-inch reducer, used to connect the tubing to the SLC drain fitting, should be connected in advance-to the associated pipe nipple and tubing, o The tygon tubing arrangement which was staged consisted of five fifty-foot pieces that had to be connected together with a total of ten pipe nipples and screw-type hose climps. The hose should remain in sections to facilitate running it through the path between the SLC and RWCU, but the connection process could be quickened by t; sing quick disconnect fittings instead of the hose clamp and nipple arrangemen o The procedure did not explicitly direct the E0 to connect a pipe niople "L" assembly at the point where the tubing must be drop,ned dor.: over the edge of a floor through an open bay to the floor below. Failure to install this "L" would cause the tubing to collapse when filled with water. Similarly, the procedure did not direct the E0 to install the ball valve arrangement at the end of the tubing. Failure to install this ball valve would make it impossible for the chemist at the RWCU pre-coat tank to control tank filling paproximately three fill and sluice routines required per demineralizer fill cycle).
(7) Although the boron ion exchange capacity of the RWCU demineralizers was very low, the licensee should consider isolating the '.Nminerali-zer that will not be used for boron injection, prior to filling the other demineralizer with boron and beginning the injection proces (8) In Note 5.3.2, "Changing Timers," the step to change the status of the #55-19 Stepping Switch Programmer to "inactive" should contain a short description of the progranner's location and the method to be used to deactivate it. The particular sequencer used in the RWCU demineralizer panel required that the tabbed ring on the sequencer rotor be pushed down (rather than a tab removed or pushed down). The
- 55-19 ring could be located more easily, if it were color coded or marked in some way to indicate that it was part of this E0P procedur (9) To streamline the procedure, the timer settingt specified in steps 5.3.2.15c and 5.3.2.15.d could be moved to Note 5.3.2, where the other timers were reset.
t (10) The two preceding coments concerning Note 5.3.2, "Changing Timers,"
refer to a "Note" which should not normally contain procedural steps (such as phy;ically changing control positions). These procedural steps should be deleted from the note and rewritten as procedure action step (11) In step 5.3.2.1d, "Operation of valves from Panel 10C205," valves BG-HV-3930A and BG HV-39308 (air supplies to demineralizers) do not-21-
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need to be opened, since the demineralizers in this procedure were gravity-drained rather than air-lcaded. The opening of these valves should be removed frcen the procedur (12) Note 5.3.2.3a contained a typographical error in referring.to Instrument rack 00C077 (should be 00C075). -
(13) Steps 5.3.2.10a, 5.3.2.10b, and 5.3.2.10c (second demineralizer drain steps) should be eliminated from the procedure, since the "Fill and ,
Wash" and "Re-wash" ti ners were set to zero, thereby eliminating the opening of the valves which were closed by these step ,
(14) Step 5.3.2.19freferredtothe"Pre-coatOutletValves(WAandWB)".
These valves serve the described function of providing an outlet path from the domineralizers during precoat, but were labeled "Backwash Inlet" on the control sanel. The valves also serve this described '
purpose during the backwash cycle. The procedure could be clarified by re-wording it to read "Backwash Inlet (Pre-coat Outlet)" so that the procedure was consistent with panel labeling while still describing the dual function of the valve j (15) flote 5.3.2.20 could contain wording to inform the chemist or E0 that the next cycle (group of procedural steps) in the procedure would require approximately three repetitiont to fill th demineralizer with borated wate (16) Step 5.3.2.24 stated,"TimeouttheStepTimer." To eliminate r
ambiguity,(the statement
"Time out by manually should setting thebe rewritten timer using to zero)." words Most such as chemists probably understand the existing wording, but E0s may misinterpret this ste (17) The Attachment I restoration section of the procedure did not contain i a step to re-install the pipe cap on valve 1-BH-V018 tailpip g. OP-EO.ZZ-308, "Alternate Injection using Service Water," Revision 1. Step 2.3, required manual opening of valves EA-HV-2203 and EA-HV-1204, Station :
Service Water (SSW) to Reactor Auxiliary Cooling System (RACS) Heat ,
Exchanger (HX)SupplyHeader. These valves we.*e located about 10 feet l above floor level and would require a ladder for the E0 to operate the valves. No ledder was staged in the are l h. OP-E0.ZZ-309, "Alternate injection Using Condensate Transfer," did not contain any precautions concerning the fact that the nuclear shift '
supervisor had to select one cf the several possible line-ups available l (through core spray and residt.al heat removal) and had to direct the E0 as ;
to which loop of the selectert system was to be used in a specific line-u ;
The procedure should include a provision for annotating the valves t positioned for the selectad system and loop. This comment also applies to
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other 300-series E0P-support procedures with multiple paths, when the .
procedures were characterized by a general lack of provisions for i maintaining the status of abnormal line-ups initiated and complete ~22-
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. E0.ZZ-311. "Bypassing P. imary Containment Instrument Gas Isolation Interlocks," Devision 2, outlines the steps necessary to override the-129-inen reactor level isolation of the primary containment instrument gas (PCIG) system and to return the 1E header to service (SRVs only). This procedure also outlines the steps necessary to bypass the -129-inch reactor level isolation of the PCIG non-1E header isolation valve and to allow PCIG to be supplied to the inboard main steam isolation valves ( MS I V s ', , The welkdown of this procedure produced the following connent (1) Steps 5.2.1 and 5.2.3 directed the removal of relays from cabinets in the control equipment roon at elevation 102. The relays to be removed were highlighted with small typed signs to aid the operator in finding them. The licensee should consider using this beneficial means of identifying components within instrumentation and control
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(ItC) cabinets on other components which must t": jumpered and removed in the other 300-series procedures. See other corrents in this report concerning the difficulty enccuntered in finding components in other cabinets and panel (2) Steps 5.2.2 and 5.2.4 required the jumpering of terminals within cabinets in the Control Equipment Room. ~ m cirections in the procedure referred to terminal locations with statements such as "bay 4. front, second group of terminal blocks from the top." The E0 had difficulty finding the proper terminals using these location descriptions. The licensee should consider changing the descriptive word "group" to "baseplate" since there were several groups of terminals or,a given baseplate and the existing descriptions actually refer to baseplate location. Alternatively, the licensee could highlight the proper tenninals with color, a snall !Un, ir other means, rather than trying to describe the locatica verbo. OP-EO.ZZ-315. "Suppression Chamber (SC) Makeup from HPCI," Revision 1, step 5.1.2, required verification of the positior 9f the manual condensate valves AP-V009 and AP-V010. The valves were located in the condensate storage tank (CST) enclosure, but the operator could aot recall whether the valves were located in a pit outside the enclosura or inside it. A location hint provided in the procedure appeared warrante Additionally, the CST enclosure was outdoors and was in a contamintted area which, at the time of inspection, contained about 1-1/2 feet of
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I standing water. The procedure did not note this factor and no provisiuns were made for pre-staging anticontamination clothing. The absence of such clothing would require diversion of a dispatched operator to the radio-logical control area (RCA) catrol point to obtain protective gea Also, no provisions were made for periodic pumping or disposal o' ',he standing water which further complicated access to the valves. >. signifi-l cant delay in performance could occur.
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Similarly, condensate manual valve AP-V027 was operated if core spray loop
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A was to be used for suppression pool makeup. Access to the valve, located in a contaminated area atop the torus, was dangerous due to the absence of gratings, low lighting levels, and potentially extreme post-accident radiation le,els. While safety belts were ptt-staged, they were not dedicated and controlled by section 4.0, "Equipment Required," in
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the procedure, and no anticontamination clothing was staged locally. Use of this makeup path was considered by the operators as an absolute last rewr '
k. OP-EO.ZZ-316. "Suppression Pool Level Reduction Using HPCI," Revision 2, sections 4.0 and 5.1.4, required that key (172 be used to open auxiliary relay room panel 10C620, Bay A, for jumper and lifted lead installatio Two different keys were on key tag #172, and neither worked when initially tried (with reasonable force) in the panel lock Similarly. OP-EO.ZZ-317. "Suppression Pool Level Reduction Using RCIC."
Revision 1, required access to auxiliary relay room panels 10C620 and 100621 for installation of jum>ers and lifted lead Section 4.0 of the procedure indicated only that (ey #173 would b'. required for panel 10C621; ;
the requirement of key f172 for pane'i 10C620 was not indicated Again, :
two keys were on key tag #173, and neither worked when initially tried in the panel locks.
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Further, although licensee policy was to maintain the relay panels in a locked state, 10C620 and 10C621 were both found unlocked. The licensee
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subsequently advised that the panels were relocked, that the locks were t
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four keys were verified to be correct and were made to work in the lock ,
The ,;.ocedures were revhed to identify the needed keys more specificall :
, 1. OP-E0.ZZ-317 required replacement of relay E51-K37 with a dummy relay module. The procedure did not include provisions for safekeeping and accountability of the removed relay. The relay was required to estrblish suction valve interlocks for the RCIC system which were reinstated upon completion of the proccdure. The operator was uncertain whether the relay should be left on the iloor of the cabinet, taker to the control room, provided to the in5 * *nt and control department, or otherwise controlled. The l' we was considering provisions for control of the relay.
s m. OP-EO.ZZ-317, Attachment 1 Revision 1, provided restoration instructions ,
for the RCIC system. Prior revisions of the procedure used lifted leads t
- to bypass interlocks whereas the current revision used a dumy relay *
i module. Steps 6.1.7 and 6.1.10 of Attachment 1 erroneously provided for
restoration of the lifted leads and omitted instructions for the dumy relay. The licensee corrected the procedure during the inspection.
n. During walkthrough of activities in the auxiliary relay room, operators
frequently had difficulty locating specific panels and bays. Although the '
door: of panel bays requiring emergency procedure access were labeled with
the procedure numier, the number and similarity of cabinets complicated i
orientation in the room and caused delays in step performance. The ,
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licensee pianned to incorporate a relay room floor plan illustration in the procedure {
o. OP-E0.ZZ-319. "Restoring Instrurrent Air in ar Emergency," Revision 0, step 5.1.3, required leads to be lif ted in euxiliary relay panel 1AC567 which contained several identical but unlabeled terminal board arrays. The licensee's numbering system in the procecure identified the cabinet, ; i-24-
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teminal baseplate, terminal boerd, and teminal but the equipment in the panel had no corresponding identification labels. While the operator occurately identified the leads to be lifted, the identification required close reading of the procedure and several attempts. Similarly, step 5.1.6 required operation of hand-cranks on the first and second stage '
cylinder valves of the emergency instrument air compressor, but neither the stages nor the valves were labeled. The licensee stated that it was considering more conspicuous identification method The procedure also required local, manual operatial of motor-operated valves EA-HV-2203 and EA-HV-2436. The valves required simultaneous operation of a hand clutch and a handwheel located 10 to 12 feet above floor level, accessible only by climbing on structural steel or other piping. No ladders were dedicated or called-out by the procedure for these operations, Emergency lighting in the plant spaces had been surveyed by the licensee as part of the 10 CFR 50, Appendix R fire protection program, but had not been reviewed with respect to the E0Ps. A number of areas observed by the team were considered to have marginal or deficient emergency lighting, as des (ribed belo No emergency lights were provided in the vicinity of auxiliary relay cabinet 10C62 Only two or three small emergency spot lights were provided in the core spray pump rooms to support the operations required by OP-EO.ZZ-315. The licensee advised that the lighting levels provided were based on transit through the rooms, not the conduct of operations within the room Little or no emergency lighting was provided at the motor control center cubicles and RACS valves EA-HV-2203 and EA-HV-2446 operated as part of OP-E0.ZZ-31 .3 E0P Evaluation Using the Plant-Specific Simulator To ensure tnat the Hope Creek E0Ps could be correctly implemented, the team developed four accident scenarios that were conducted on the Hope Creek simulator using licensed operators. The scenarios were designed to determine whether the E0Ps clearly outlined the actions req 11 red of operators during an energency and provided them with sufficient guidance to enable them to perform the recuired actions. The scenarios exercised parallel E0P paths and contingency procedures. Hence, the scenarios demonstrated whether (1) the E0Ps caused unnecessary duplication of operator actions, (2) transitions from different E0P paths and contingency procedures could be made satisfactorily, and (3) all the operator actions could be performed concurrently when require The scenarios were designed to exercise the maximum number of E0P decision paths and contingency procedures in the available simulator time. The events contained malfunctions beyond the design basis of the plant but within the i scope of the E0P . _
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Four scenarios were conducted with a normal shift complement consisting of a senior nuclear shift supervisor (SRO), two nuclear shift supervisors (SRO), and two nuclear control operators (RO). The shift technical adviser position was filled by one of the nuclear shift supervisor . Simulator Scenario il - -
The scenario was designed to exercise the following E0Ps:
- OP-EO.ZZ-101, Reactor Pressure Yessel (RPV) Control;
- OP-E0.ZZ-102, Containment Control and Drywell Pressure Control; and
- OP-EO.ZZ-202. Emergency Depressurizatio The scenario was initiated from 100-percent power with a loss of all primary cond+nsate pumps. The high pressure coolant injection (HPCI) system was inoperable, and the reactor core isolation cooling system failed to start. A small coolant piping break in the drpell caused the RPV level to decrease and containment parameters to increase. The scenario was tenninated when the crew completely filled the vessel and stabilized primary containment parameter The inspection team made the following observations during performance of this scenario, The nuclear control operator (NCO) was unable to spray the drywell as a result of failure to satisfy the interlock which required that the low-pressure coolan', injection (LPCI) system injection valve be closed and overridden before the drywell spray valve could be opened, The crew failed to control the level between 12.5 inches and 54 inches, as is rquired by step RC/L-3, when low pressure systems injected. As a result, the vessel wr.s completely filled and allowed to flow through the open ADS valve .3.2 Simu'ator Scenario #2 The scenario was designed to exercise the following E0Ps:
- OP.EO.ZZ-101, Reactor / Pressure Vessel (RPV) Control;
- OP-EO ZZ-102, Containment Control;
- ,0P-E0.ZZ-202. Emergency Depressurization; and
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OP-F0 ZZ-207. Level / Power Contro The scenario was initiated with a turbine trip from 80-percent power. A failure of control rods was inserted prior to the turbine trip, causing an anticipated transient without scram (ATWS) condition. The crew tripped the recirculation Wmps thereby reducing power to 35-percer.t. Since the power remained greater than the 25-percent capacity of the bypass, SRVs opened to reduce reactor pressure. The opening of the SRVs resulted in a swell in reactor level which caused a high-level trip of the reactor feed pumps. The combined loss of reactor feed pumps and a reactor water level shrink from the closure of the SRVs caused the water level to decrease to the low water level setpoint for isolation of the main steam isolation valves (MSIVs). The scenario was terminated when the water level was stabilized and power control procedures j
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The inspection team made the following observations during performance of this scenerio: The crew failed to terininate injection from reactor core Lolation cooling (RCIC) and failed to prevent injection from core spray as required by step E0- The crew failed to bypass the rod worth minimizer (RWM) and to defeat the rod sequence control system (RSCS) as required by RC/Q-20, Step LP-9 of Level / Power Control stated "Lower RPV water level by tenninating and preventing all injection...." Training ocrsonnel stated that the crews did not tenninate injection to the RPV but reduced the flow to the RPY in order to lower RPV level in a controlled manner. The licensee should consider rewording this step to indicate that the intent of this step is to reduce flow in a controlled manner and riot to terminate i .3.3 Simulator Scenario #3 This scenario was designed to exercise the following E0Ps:
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- OP-EO.ZZ-101, Reactor /PressureYessel(RPV) Control;
- OP-EO.ZZ-102, Containment Control;
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- OP-EO ZZ-202 Emergency Depressurization;
- OP-EO.ZZ-206, Reactor Flooding;
- CP-EO ZZ-207, Level / Power Control; i - OP-EO.ZZ-307 Bypassing RSCS;
- OP-EO.ZZ-311, Bypassing Primary Containment Instrument Gas 1 Iso ation Interlocks; j
- OP-EO.ZZ-318, Containment Venting; and
- OP-E0.ZZ-319, Restoring Instrument Air in an Emergenc This scenario was initiated from 100-per.ent pWer with a small break loss-of-coolant accident (LOCA) a;Sror.1 mating 5 percent of the design basis accident leakage rate. The scenario (1so simuli.ted a failure of one half of the control rods to insert. A break in the downcomer above the level of the
- suppression pool was inserted prior to the LOCA. Drywell pressu e increased to i a pressure requiring emergency depressurization, RPV flooding, and containment venting. The scenario was terminated af ter the crew commenced venting the
- containment and a drywell pressure decrease was observe The inspection team made the following observations during performance of the scenario- The crew entered OP-E0.ZZ-207, "Level / Power Control." although suppression pool temperature was only 80"F and was not increasing. Taking this action t wasted time and confused the NSS as to the required actions contarning injection to the vessel. Step RC/Q-38 stated "Before Suppression Chamber water temperature reaches 110"F or when RRCS actuates SLC...then continue I
at Step RC/Q-39." This path continues on to Level Power Control. This i step is a deviation from the EPG which stated, "if the reactor cannot be i shutdown before the suppression pool temperature reaches 110"F, BORON l
INJECTION IS REQUIRED...." The use of "Before" does not indicate that
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this action should not be taken unless suppression pool temperature was going to exceed 110'F. The team realized that the operator should retain flexibility for injecting borcn by the standby liquid control system (SBLC) and for entry into the Level / Power Control if suppression pool
, temperature is increasing, but these actions should not be performed unless exceeding a suppression pool temperature of 110*F appears israinent. ,
- The crew failed to proceed to step LP-15 of Level / Power Control t. hen Emergency Depressurization was required. Step LP-10, which is a retainment step, indicated that this action should be take Emergency Depressuriza-tion was required because drywell pressure could not be maintained below the Pressure Suppression Limit of Graph DW-P-1, step DW/P-1 The crew failed to exit Level / Power Control and enter OP-E0.ZZ-20?,
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Emergency Depressurization, as required by step LP-1, a retainment sta This action was required when suppression chamber pressure could not be
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maintained below 57.2 psig. Failure to exit Level / Power Control resulted 1 in failure to inject at the maximum rate required by step RF-7. This inaction resulted in the level being below the top of active fuel without the pressure being above that specified by table RF-P- The crew implemented step DW/P-14 as required. This resulted in securing the drywell cooler fans in anticipation of spraying the drywell. The subsequent step of DW/P-14 required that the operator verify that
suppression chamber pressure and temperature is below the Drywell Spray
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Initiation Pressure Limit of Graph DW-P-1. Since the crew failed to satisfy this curve, they were unable unable to spray the drywell and prematurely secured drywell cooler fans. The flowchart layout deviated J from both the EPG and PSTG requirements. The licensee should consider j rearranging the flowchart to verify the conditions of step DW/P-15 prior to performance of step DW/P-14 l Once the crew made the decision to inject boron through the SBLC system, l
they failed to carry out the actions of step RC/Q a3, injection of boron
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using reactor cleanup, when the SBLC syFtem failed to inject.
i The crew used the shift technical adviser to perform OP-EO.ZZ-318, Containment Venting.
i The crew failed to terminate injection from the condensate system, as required by step ED-5, prior to opening the ADS valves, i
3.3.4 Simulator Scenario f4 l
This scenario was designed to exercise the following E0Ps:
- OP-EO ZZ-101, Reactor / Vessel Pressure (RPV) Control;
- OP-E0.ZZ-102, Containment Control;
- OP-EO.ZZ-201, level Restoration ;
- OP-EO.ZZ-309, Alternate Injection using Condensate Transfer;
- OP-EO.ZZ-310, Alternate Injection using Fire Main; and
- OP-E0.ZZ-308, Alternate Injection using Service Wate _
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The event was initiated from 100-percent power with the A residual heat removal !
(RHR) pump and HPCI out of service. A failure of 125 Y OC Class IE Bus 100420 i was simulated, and the crew completed actions for this failure. A simultaneous '
loss of all grid power, a loss of 4.16 KV class 1E Bus 10A404, and a failure of !
the C diesel to start were simulated. These failures resulted in the only l sources of injection being the A core spray pump and a control rod drive (CRD) !
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pump. A relief valve stuck open when it opened to control pressure. The crew !
i was able to start ai.J load the C Diesel Generator locally, but the C RHR pump !
i failec to start. The C core spray pump started. The remaining CRD pump was !
i later tripped. When pressure decreased to approximately 500 psig, the i
! stuck-open relief valve closed. The crew reduced pressure in order to allow i Core Spray to inject. The scenario was teminated when the level was restored I to the normal ban I i
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I The inspection team made the following observations during perfomance of the
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' The crew did not comply with Caution 15. "Open SRVs in a sequence which ,
I will distribLte heat uniformly throughout the suppression chamber, if *
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possible." Two adjacent SRVs were opened simultaneously. Also. SRVS were j opened in the same area as the stuck-open relief valv '
l A member of the crew acknowledged alams indicating that the only system i
. that was injecting to the core, a CRD pump, had tripped, but did not !
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3.3.5 General Comments All 300-series E0Ps (Bypasses Alternate Injection, etc.) contained a common r
- precaution in step 3.1 whic.h stated "The Nuclear Shift Supervisor shall log the i i
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starting and corrpletion times of this procedure." During the simulator walkthroughs, the inspection team requested that the shift personnel complete ,
4 all of their logs in the same manner that they would during actual control room t
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I A review of logs completed during the conduct of the four scenarios in the {
} simulator shawed that the start and stop times of 300-series procedures were i not being logged. The team understood that a limited amount of time was :
I available to the operators to complete logs during a transient. Because of l i this limitation, the team reconnended that the licensee evaluate the methods !
j for tracking the completion of emergency line ups and bypasses, like those in l
. the 300-series E0Ps which have been successfully implemented at other utilitie !
{ The most viable means of tracking abnormal line-ups of plant systems seems to
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be the use of a checklist posted on a desk or on the control boards. This approach would allow the operators to maintain a record of plant status using a i simple check mark rather than making 6 time-consuming log entry. This method !
was the same approach that was used at Hope Creek for place-keeping in the E0P l flowcharts, j 3.4 E0P Training g The inspection team reviewed the adequacy of training with respect to the E0P !
f Items reviewed included classroom training lesson plans (tor both the equipment
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operator and the licensed operator), simulator scenarios for licensed operater:, an en-the-job training program for the equipment operators, training on a recent E0P revision, and training on E0P for the instrumentation technicians. A team member also observed a licensed operator E0P classroom training sessio ..
3.4.1 Initial Licensed Operator Training Personnel preparing to take the NRC licensed operator (RO) and senior operator (SRO) examinations were trained in both the classroom and simulator. The classroom training addressed E0P performance and their basis. The simulator training consisted of task-oriented training and scenarios from the requalification program. The team concluded that initial E0P training for licenced operators was adequat .4.2 Equipment Operator Training The equipment operator training program consisted of classroom presentations and on-the-job training. Equipment operators were trained on all E0P tasks that they would be required to execute except RC/Q-23, venting of the control rod drive hydraulic control units. The training for Equipment Operators to perform step RC/Q-23 was completed through training on a similar task of OP-SO.BF-002, "Individual CRD HCU Operation." The training on this task did not emphasize the high pressure and high temperatures that would be encountered during performance of RC/Q-23. With this exception, the team concluded that E0P trait.ing for equipment operators was adequat .4.3 Licensed Operator Retraining The E0P training within the licensed operator requalification program consisted of classroom presentation and simulator training. The classroom training covered E0P steps and their basis. The classroom training alternated annually between self-study and instructor-presentation of the E0P training materia E0P training in the simulator was integrated with training on normal and abnormal tasks. The inspection tedm made the following observations: Simulator training on OP-EO.ZZ-103, "Reactor Building Control," was limited because the simulator could not simulate problems in the reactor building, Simulator training scenarios should identify areas of discussion on items that require operator judgment. Examples include: RC/Q-28, "How long to allow the scram discharge volume (SDV) to drain," Caution 15. "sequence for opening SRVs," and RC/Q-31 "are full manual or individual rod scrams desired."
The team concluded that E0P retraining for licensed operators was adequat . Instrumentation Technician Training Shift instrumentation technicians received classroom and laboratory training on tasks that they would be expteted to perform during implementation of the E0P The team concluded that E0P training for instrumentation technicians was adequat . _ _ _ _ __
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e 3.4.5 Chemist Training Section 3.4 of NUREG-0899, "Guidelines for the Preparation of Emergency Operating Procedures," required that licensees train personnel other than operators on E0Ps or familiarire them with the E0Ps as necessary.. Performance of OP-EO.ZZ-304, "Boron Injection using RWCV " required assistance from the chemists. It was determined that plant chemists had not been trained in the performance of this procedure. One chemist interviewed was not familiar with operation of the demineralizer panel timer and sequence .4.6 Training on E0P Revisions Training on minor revisions to the E0Ps was conducted through pre-shift briefings or lectures in the requalification program. Training on major revisions was cor. ducted through the use of classroom training and walkthroughs in the simulator or control room. Training on revisions was conducted as specified by a generic lesson plan for procedure changes, The team concluded that training on E0P revisions was adequate, but expected that detailed training combined with a feedback program would help eliminate some of the procedural errors noted during this inspection (such as the performance of incorrect steps in OP-EO.ZZ-309).
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4.0 EXIT MEETING / PERSONS CONTACTED ,
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On September 16, 1988, the team and other NRC representatives met with licensee personnel to discuss the scope and findings of the inspection. Persons i contacted by the team and attendees at the exit meeting held on September 16, 1988 are identified in Attachment A. Mr. J.E. Konklin, Chief Team Integration Section, NRR and Mr. P.D. Swetland, Chief, Reactor Projects, Region I, represented NRC management at the exit meeting. During the inspection the team also contact 1d other members of the licensee's staff to discuss issues and ongoing act.vitie n
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. . ATTACHPENT A PERSONS CONTACTED ,
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EXIT MEETING ATTENDEES . _ :
NAME TITLE Persons contacted:
- S. LaBruna Vice President - Nuclear Operations
- G. Connor General Manager - Nuclear Services
- J. Nichols Technical Manager - Hope Creek
- R. Drewnowski Nuclear Mechanical Engineering Manager
- C Vondra Operations Manager - Hope Creek M. Adzima Shift Chemistry Technician
- R. Beckwith Station Licensing Engineer J. DeDomenico Nuclear Shif t Supervisor E. Dodge Equipment Operator
- R. Donges Licensing Engineer J. Eaton Senior Nuclear Shif t Supervisor A. Garrison Principal Training Supervisor, Chemistry
- A. Giardino Manager - Station Quality Assurance W. Gott Principal Training Sapervisor, Operator Training R. Havens Training Instructor
- M. Headrick On-Site System Review Engineer R. Hunton Equipment Operator J. Joullian Training Instructor D. Kabachinski Training Instructor
- D LaMastra Nuclear Mechanical Engineer
- G. Mecchi Principal Training Supervisor, Simulator B. Meyer Principal Training Supervisor for Controls S. Miller Nuclear Control Operator R. Myers Nuclear Shift Supervisor
- M. Rogers Emergency Operating Procedures Coordinator
- F. Thomson Principal Engineer - Nuclear Licensing
- Denotes those present at the exit meeting on September 16, 1988.
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. 1 ATTACHMENT B D0r*T T- REVIEWE3 NUMBER TITLE REVISION
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OP-E0.ZZ-099 POST SCRAM RESTORATICA 2 ;
OP-EO.ZZ-100 SCRAM 2 ;
OP-EO ZZ-101 REACTOR PRESSURE VESSEL (RPV) CONTROL 1 i OP-EO.ZZ-102 CONTAINMENT CONTROL AND DRYWELL PRESSURE CONTROL 1 ;
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OP-E0.ZZ-103 SECONDARY CONTAINMENT CONTROL 1 OP-E0.ZZ-104 RADIOACTIVE RELEASE 2 OP-EO.ZZ-201 LEVEL RESTORATION 1 OP-EO.ZZ-202 EMERGENCY BLOWDOWN 1 OP-EO ZZ-203 STEAM COOLING 2 OP-EO.ZZ-204 SPRAY COOLING 0 OP-EO.Z1-205 ALTERNATE SHUTDOWN COOLING 0
3P-EO.ZZ-206 RPV FLOODING 0 OP-EO.ZZ-207 REACTOR LEVEL / POWER CONTROL 1 OP-E0 ZZ-301 BYPASSING MSIV ISOLATION INTERLOCKS 2 [
OP-EO.ZZ-302 DE-ENERGIZATION OF SCRAM $0LEN0105 1 l
, OP-EO.ZZ-303 INDIVICUAL CONTROL ROD SCRAMS 1 OP-EO.ZZ-304 B0RON INJECTION USING RWCU 0 OP-EO.ZZ-306 MANUAL ISOLATION VENT OF SCRAM AIR HEADER 1 OP-EO.ZZ-307 BYPASSING RSCS 0 OP-EO.ZZ-308 ALTERNATE INJECTION USING SERVICE WATER 1 OP-EO.ZZ-309 ALTERNATE INJECTION USING COND TRANSFER 1 OP-EO.ZZ-310 ALTERNATE INJECTION USING FIRE MAIN 2 OP-EO.ZZ-311 BYPASSING PRI CONTAINMENT INST GAS ISLN INTERLOCKS 2 t
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OP-EO.ZZ-312 SUPP CHAMBER MAKE UP FROM HPCI 1 OP-EO.ZZ-313 SUPP CHAMBER MAKE UP FROM RCIC 1 i OP-EO.ZZ-314 SUPP CHAMBER MAKE UP FROM SERVICE WATER 1 :
OP-EO.ZZ-315 SUPP CHAMBER MAKE UP FROM CORE SPRAY I I OP-EO.ZZ-316 $UPP CHAMBER LEVEL REDUCTION USING HPCI 2 :
OP-EO.ZZ-317 $UPP CHAMBER LEVEL REDUCTION USING RCIC 1 i OP-EO.ZZ-318 CONTAINMENT VENTING 0 !
OP-EO ZZ-319 RESTORING INSTRUMENT AIR IN AN EMERGENCY 0 E-1
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ATTACHMENT C ABBREVIATIONS AND ACRONYMS
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ADS Automatic Depressurization System APRM Aterage Power Range Monitor ASC Alternate Shutdown Cooling ATWS Anticipated Transient Without Scram BWROG Boiling Water Reactor Owners Group CRD Control Rod Drive
- ' CS Core Spray DCRDR Detailed Control Room Design Review EO Equipment Operator E0P Emergency Operating Procedure EPGs Emergency Procedure Guidelines FSAR Final Safety Analysis Report GE General Electric HCU Hydraulic Control Unit HPCI High Pressure Coolant Injection INPO Institute of Nuclear Power Operations
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LPCI Low Pressure Coolant Injection MSIV Main Steam Isolation Valve NPS4 Net Positive Suction Head PGP Procedure Generation Package PSE&G Public Service Electric and Gas PSTG P! ant-Specific Technical Guidelines QA Quality Assurance RACS Reactor Auxiliary Cooling System RCIC Reactor Core Isolation Cooling RRR Residual Heat Removal RPY Reactor Pressure Vessel
! RSCS Rod Sequence Control System RWCU Reactor hater Clean-up SDV Scram Discharge Volume SLC Standby Liquid Control SPDS Safety Parameter Display System SQR Station Qualified Reviewer SRV Saicty Relief Valve SSW Station Service Water I
STA Shift Technical Advisor TAF Top of Active Fuel V1V Verification and Validation i
WG Writer's Guide C-1
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E0P Control Section Designations RC/L Neactor Pressure Vessel / Level RC/P Reactor Pressure Vessel / Pressure RC/Q Reactor Pressure Yessel/ Power ' *
DW/T Drywell/ Temperature DW/P Drywell/ Pressure SP/1 Suppression Pool / Temperature SP/L Suppression Pool / Level RS/L Reactor Building / Level RB/R Reactol Building / Radiation RB/T Reactor Building / Temperature RR Radioactivity Release Control LR Level Recovery ED Emergency Depressurization STC Steam Cooling SPC Spray Cooling ASC Alternate Shutdown Cooling LP Level / Power Control RF Reactor Flooding PSR Post Scram Recovery S Scram
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