Halliburton Artificial Lift - ESP

© 2011 HALLIBURTON. ALL RIGHTS RESERVED.

DJ Fakelman – Account Representative Denver, CO.

© 2011 HALLIBURTON. ALL RIGHTS RESERVED.

Presentation Overview

§  Halliburton  Ar-ficial  Li1  §  Divide  County  case  study  §  Mountrail  County  case  study  §  Advantages  to  using  ESP’s  in  the  Bakken/Three  Forks  §  Addressing  the  Program  Bullet  Points  §  Conclusion      

Halliburton Artificial Lift

2008   2012  §  Global  Ar-ficial  Li1  formed  in  2008  §  2009  -­‐  Service  centers  opened  in  Texas  and  Oklahoma  §  2010  -­‐  New  Manufacturing  facility  opened  in  Oklahoma  City  §  2011-­‐  Service  centers  opened  in  Casper,  WY  and  Minot,  ND  §  2012  –  Halliburton  Energy  Services  acquires  Global  §  2013  –  Forma-on  of  new  PSL,  Halliburton  Ar-ficial  Li1  

Tomlinson  3-­‐2HN  §  U-lizing  a  Halliburton  ESP  unit  

beginning  October  of  2012  §  300th  Day  Oil  Produc-on  –  63,276  BO  §  Lower  intake  pressure,  lower  fluid  level    

© 2011 HALLIBURTON. ALL RIGHTS RESERVED. 4

Divide County Case Study: SM Energy

Tomlinson  3-­‐1HS  §  U-lizing  a  Rotoflex™  unit  beginning  

March  of  2012  §  300th  Day  Oil  Produc-on  –  57,765  BO    §  Higher  intake  pressure,  higher  fluid  level    

v  Both  wells  were  completed  using  the  same  techniques  v  ESP  has  significantly  increased  produc-on  over  the  last  11  months  

v  Opportunity  has  been  created  for  con-nued  u-liza-on  of  Halliburton  ESP’s  in  this  area    

 

© 2011 HALLIBURTON. ALL RIGHTS RESERVED. 5

Mountrail County Case Study: Slawson Exploration Cannonball  Federal  2-­‐27-­‐34H  

§  Compe-tor  ESP  installed  in  April  2012  §  ESP  pulled  in  November  2012  §  GLR  ranging  from  500-­‐800  §  Gas  locking  issues  between  700-­‐1000psi  

PIP  §  NPT  caused  by  excessive  down  -me  §  Produced  104,332  BO  during  run  life  of  

ESP    

Cannonball  Federal  3-­‐27-­‐34H  §  Halliburton  ESP  installed  in  March  2012  §  ESP  pulled  in  April  2013  §  GLR  ranging  from  500-­‐800  §  No  gas  locking,  PIP  consistently  

between  400-­‐500psi  §  No  NPT  caused  by  excessive  down  -me  §  Produced  244,823  BO  during  run  life  of  

ESP  

 v  Both  wells  were  completed  using  the  same  techniques  v  Halliburton  ESP  not  only  had  longer  run  life  but  produced  68,070  BO  more  in  same  -me  

period  (  8  months  )  as  compe-tor  unit    v  Opportunity  has  been  created  for  con-nued  u-liza-on  of  Halliburton  ESP’s  in  this  area    

 

§  Crea-on  of  “second”  decline  curve  –  Achieve  rates  reached  during  flow  back  

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Advantages to Using ESP’s in the Bakken / Three Forks

§  Pump  wells  down  to  lower  PIP’s  and  fluid  levels  –  Maximize  the  amount  of  hydrocarbon  produc-on    

§  Large  opera-ng  range      –  Less  interven-ons  and  NPT  to  accommodate  well  decline    

§  Ability  to  gather  and  trend  large  amounts  of  data  –   Down  hole  sensor  is  u-lized  alongside  monitoring  program  

§  No  problems  caused  by  rod  wear,  rod  stretch,  rod  pounding,  or  tubing  wear  –  Deeper  PSD’s  and  rod  pounding  caused  by  gas  interference  are  common  problems  

§  Minimal  maintenance  required  and  small  footprint  –  Less  for  field  hands  to  worry  about,  weather  has  ligle  effect  on  opera-on  

§  Today’s  technology  allows  the  use  of  ESP’s  in  high  GLR,  high  BHT  condi-ons  

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Addressing the Program Bullet Points §  Evaluating whether aggressive preliminary ESP production raises the decline curve enough

to justify initial outlay –  In  our  experience  the  answer  is  yes.    The  pump  must  be  properly  designed  for  the  applica-on  

and  coopera-on  between  the  service  company  and  the  operator  is  key.  

§  Deciphering the lowest production rate at which ESPs can run without failing to determine the point at which it can't be used

–  There  are  ESP’s  that  can  pump  volumes  as  low  as  75bpd.    The  ques-on  is  when  is  an  ESP  no  longer  the  economical  solu-on.  The  answer  to  that  is  situa-on  and  operator  specific.  

§  Assessing the failure rate of ESPs being used in the Bakken to define the total run life that can be expected

–  The  run  life  of  an  ESP  is  as  much  determined  by  the  environment  in  which  it  is  operated  in  as  it  is  by  the  design  and  manufacturing  of  the  unit.  

–  Failure  rates  can  be  directly  correlated  to  how  the  well  bore  is  treated  and  what  is  put  into  place  to  protect  the  ESP  prior  to  installa-on.    

§  Examining the effectiveness of using ESPs for moving additional fluid to clean the well up before running rod pump  

–  ESP’s  should  not  be  considered  the  vacuum  cleaner  that  is  run  in  order  to  clean  the  well  up  for  other  forms  of  li1.  

–  If  designed  properly,  an  ESP  can  be  the  preferred  method  of  ar-ficial  li1  for  a  large  por-on  of  the  life  of  the  well.