Realizing  Reliability  Benefits  of  Distribu5on  Automa5on:  

Early  Impacts  &  Lessons  Learned  Joseph  M.  LoPorto,  PE  

Manager,  T&D  Automa9on    February  20,  2014  

American Recovery and Reinvestment Act of 2009 •  Smart Grid Investment Grant Program •  Smart Grid Demonstration Program

For further information go to www.smartgrid.gov.

The information in this presentation is based on the results of a DOE funded project under:

or the

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Acknowledgement  "This material is based upon work supported by the Department of Energy under Award Numbers: DE-OE000300, DE-OE0000301, DE-OE0000204” Disclaimer: "This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof."

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4 PEPCO HOLDINGS, INC. All rights reserved.

Presenta5on  topics  •  PHI  Quick  Facts    •  Automa5on  Technologies  •  ASR  Overview  and  Demonstra5on  •  Es5mated  Impacts  On  Reliability    •  Learnings  from  ASR  pilot  project  and  ini5al  SGIG  projects.  

•  ASR  commissioning  5meline  •  Summary  of  Benefits  •  Q&A    

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Pepco Holdings, Inc. Quick Facts •  Incorporated in 2002 •  Service territory:

8,340 square miles •  Customers served (~2M)

–  Atlantic City Electric: •  545,000 – electric

–  Delmarva Power: •  503,000 – electric •  125,000 – natural gas

–  Pepco: •  793,000 – electric

•  Total Population Served: 5.6 million

•  Regulated transmission and distribution is PHI’s core business

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Distribu5on  Automa5on  (DA)  Project  Types  

•  Automa9c  Sec9onalizing  &  Restora9on  (ASR)  Schemes    –  DA  ASR  entails  the  installa5on  of  certain  devices  that  are  intended  to  work  together  to  iden5fy  

distribu5on  feeder  faults,  automa5cally  isolate  iden5fied  faulted  area,  and  reroute  electricity  supply  to  segments  of  the  outage  feeder  un-­‐impacted  by  the  fault.    This  will  to  reduce  the  number  and  length  of  electric  system  outages,  resul5ng  in  increased  reliability  and  customer  sa5sfac5on.  

•  Dissolved  Gas  Analysis  (DGA)  monitors  on  substa9on  transformers    –  This  on-­‐line  system  will  con5nuously  monitor  eight  cri5cal  fault  gases  and  other  transformer  

insula5ng  oil  key  parameters  for  a  5mely  assessment  of  transformer  condi5ons  to  schedule  maintenance  and  help  prevent  failures.  

•  URD  Fault  Detectors  System  –FDS  (Pepco  MD)  –  This  system  will  iden5fy  the  loca5on  of  faulted  URD  transformers  by  conveying  a  signal  back  to  

the  control  center  in  order  to  reduce  5me  spent  by  crews  in  loca5ng  faults.  •  Network  Transformer  Protector  Remote  Monitoring  System  -­‐  RMS  (Pepco  DC)  

–  This  system  will  provide  real  5me  remote  control/monitoring  capability  as  well  as  power  quality  informa5on  such  as  phase  currents,  transformer  loading,  power  factor,  etc.  to  network  transformers  through  implementa5on  of  two  way  communica5on  and  installa5on  of  intelligent  sensors  for  an  enhanced  reliability  of  the  network  system.  

•  Capacitor  Bank  Automa9on    –  This  project  will    add  feeder  capacitors  that  have  supervisory  controlled  capability  and  

visibility.  This  will  allow  remote  control  of  feeder  reac5ve  power  (VAr)  and  resolu5on  of  high/low  voltage  issues.      

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ASR  Overview  –  Building  Blocks  •  Smart  Relay/Smart  Meter:  A  substa5on  feeder  terminal  device  that  measures  

opera5on  aWributes  of  a  feeder  and  is  used  for  coordina5ng  feeder  protec5on  at  the  substa5on.  

•  Distributed  Remote  Terminal  Unit  (DRTU):  A  substa5on  system  which  cons5tutes  of  a  CPU,  ethernet  switches,  circuit  breaker  controllers,  and  a  data  concentrator,  all  which  work  together  to  provide  the  electronic  link  to  the  control  center,  and  breaker  status  to  the  ASR  Control  System.  

•  ASR  Control  System  -­‐    Substa5on  computer  and  control  program  that  monitors  the  status  of  the  field  devices  and  coordinates  their  opening  and  closing  to  isolate  the  fault  and  restore  service  to  un-­‐impacted  feeder  sec5ons.  

•   Automa9c  Circuit  Recloser  (ACR):  A  feeder  line  protec5ve  device  which  opens/closes  when  it  detects  fault  current  or  through  remote/local  command  to  isolate  a  feeder  sec5on.  This  device  can  reclose  mul5ple  5mes  to  ride  through  temporary  faults.  

•  SF6  Switch:  A  feeder  line  switch  which  opens/closes  either  through  remote  or  local  command  to  isolate  a  sec5on  of  feeder  circuit.  This  is  not  used  as  a  protec5ve  device.  

•  Electronic  Controllers  –  Each  device  above  has  an  electronic  controller  that  allows  seYng  of  opera5on  commands,  local  opera5on  of  the  device,    and  with  added  communica5on,  remote  opera5on  of  the  device.  

•  Remote  Radio:  equips  each  field  device  controller    with  remote  control  capabili5es  through  the  wireless  mesh  network.  

•  Repeaters-­‐Relays.  Radio  Masters.    Access  Points:  Cons5tute  the  wireless  mesh  network  which  transmits    field  data  to  the  intended  des5na5on  in  the  data  network,  and  back  again.  

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PHI’s  ASR  System  •  Protects  customers  from  sustained  outages  caused  by  feeder  lock-­‐outs  

•  Segments  feeders  into  2,  3,  or  4  sec5ons  using  closed  remote  controlled  SF6  switches  or  Automa5c  Circuit  Reclosers  (ACR’s)  in  the  field  

•  For  an  fault  in  any  one  sec5on,  ASR  opens  closed  switches  to  isolate  the  sec5on  

•  ASR  restores  the  other  sec5ons  by  reclosing  the  feeder  breaker  and/or  closing  open  5e  switches  to  other  feeders    

•  Generally  ASR  operates  in  less  than  a  minute  

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ASR  System  -­‐  Demonstra5on  

Substation

Fault Occurs on Feeder 001

Feeder 001 Locks out

1008 Customers out

ASR verifies switch status and fault location

Open Switch

Open Switch

Close Switch

270 Customers out

Total Time: 51 Seconds

Close Breaker

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 Outage  impact  reduc5ons  (Pilot  ASR  scheme)  

•  4  fdr  scheme  •  6,800    CI  Saved  •  1.2    Million  CMI  Saved  •  181    min  ave  dura5on  of  saves  •  20-­‐50%  rel    Impr  possible  

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 Outage  impact  reduc5ons  (DOE  Scheme  1)  

•  16  fdr  scheme  •  10,500  CI  Saved  •  1.4  Million  CMI  Saved  •  136  min  ave  dura5on  of  saves  •  20-­‐50%  rel    Impr  possible  

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Some  reasons  for  non-­‐opera5ons  

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•  As  designed:    maintenance/repair  work,  downed  conductor,  system  operator  discre5on.  

•  Addressable:    equipment  failures,  telecom  failures,  false  fault  targets,  process  issues.

Learnings/Recommenda5ons  -­‐1  

•  Iden5fica5on  of  resources    up  front  is  key  to  comple5ng  the  work  on  5me.    Include  all  skill  sets:  planning/PM,  engineering,  construc5on,    tes5ng/  EMS  integra5on,  and  maintenance.  

•  Lab  modeling/tes5ng  is  essen5al  to  reduce  implementa5on  errors  – Validate  interoperability  and  network  connec5ons  – Adjust  for  un-­‐modeled  aspects  (e.g.,  tree  foliage)    per  experience  with  completed  projects.  

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Learnings/Recommenda5ons  -­‐  2  

•  New  class  of  assets  will  not  follow  tradi5onal  asset  lives.  (e.g.,  15  years  Vs.  30  years)  

•  Incorporate  cyber  protec5on  from  the  beginning  of  the  project:  – Apply  access  control,  firewalls,  encryp5on,  etc  – Work  with  vendors  to  develop  applica5on  level  encryp5on  for  distribu5on  equipment.  

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Learnings/Recommenda5ons-­‐  3  •  Smart  devices  are  subject  to  more  frequent  firmware  upgrades/revisions  –  Can  occur  during  project  implementa5on  –  Prepare  for  the  increasing  numbers  by  moving  towards  remote  “over  the  air”  upgrade  capabili5es.  

•  Con5nued  maintenance  is  cri5cal  –  can’t  just  set  it  and  forget  it!  –  BaWery  failure  most  common  maintenance  issue;  add  dual  power  

sources  to  the  controls.  Develop    baWery  replacement  program.  –  Communica5on  system  needs  to  stay  con5nuous;  NOC  plays  a  key  

role.  –  DA  models  need    to  stay  up  to  date;    iden5fy  and  train  stake  holders.  –  Add  adequate  funding  for  maintaining  equipment  and  systems    

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ASR  Commissioning  Timeline:  

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2014  &  Beyond  

2012  2013  

Install substation and feeder smart devices , and telecom infrastructure

2011  2010  

MD: ASR 1 commissioned DC: ASR 2 commissioned ACE: ASR 3 Commissioned

Initiate DOE SGIG Distribution Automation

MD: ASR 4 Commissioned DC: ASR 5 Commissioned MD: ASR 6 Commissioned ACE: ASR 7 Commissioned MD: ASR 8 Commissioned MD: ASR 9 Commissioned DC: ASR 10 Commissioned

DA continues with additional ASR schemes & other reliability improvement technologies.

•  SGIG project for 113 feeders has been completed •  ASR for an additional 12 feeders in DPL service area also completed. •  Together with 6 other ASR feeders, PHI now has 131feeders (utilizing 475

field devices) completed.

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Summary  of  DA/ASR  Expected  Benefits  

•  Distribu5on  Automa5on  will  help  PHI  achieve  its  smart  grid  vision.  

•  It  will  result  in  key  benefits  to  customers  and  the  company:  –  Improved  feeder  and  system  reliability    à        increased  customer  sa5sfac5on    

–  Increased  visibility,  control,  and  op5miza5on  of  the  distribu5on  system.  

–  Opera5onal  savings  from  reduced  field  trips  and  restora5on  5mes.    

–  Increased  knowledge  of  transformer  health  resul5ng  in  beWer  maintenance  and  asset  end  of  life  control.  

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Your  ques5ons/comments  18